October 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
19 Loan Guarantee Applications for
New Plants Received by DOE
Nineteen applications from 17
electric power companies for federal loan guarantees to support the construction
of 14 nuclear power plants have been received by the U.S. Department of
Energy (DOE) in response to its June 30, 2008 solicitation. The applications
reflect the intentions of those companies to build 21 new reactors, with
some applications covering two reactors at the same site. All five reactor
designs that have been certified, or are currently under review for possible
certification, by the Nuclear Regulatory Commission (NRC) are represented
in the applications. DOE also has received applications from two companies
for federal loan guarantees to support two different Front-End Nuclear
Facility Projects. DOE and the U.S. nuclear industry became partners to
share the cost of programs to improve the design and licensing processes
of the first new nuclear power plants to be constructed in the U.S. in
over 20 years. If all projects are constructed, they would add 28,800
megawatts of clean, emissions-free, base load electric generating capacity.
(CCH Nuclear Regulation Reports, No. 1402, October 14,
2008)
Policy Statement on Regulation of Advanced
Reactors Issued
A policy statement on the regulation
of advanced reactors has been issued by the Nuclear Regulatory Commission.
The Commission's primary goal is to adequately protect the environment
and public health and safety and ensure the common defense and security.
With regard to advanced reactors, the Commission expects, as a minimum,
at least the same degree of protection that is required for the current
generation light-water reactors (LWRs). Furthermore, the Commission expects
that advanced reactors will provide enhanced margins of safety and/or
use simplified, inherent, passive, or other innovative means to accomplish
their safety and security functions. The Commission also expects that
the safety features of these advanced reactor designs will be complemented
by the operational program for Emergency Planning (EP). This EP operational
program, in turn, must be demonstrated by inspections, tests, analyses,
and acceptance criteria to ensure effective implementation of established
measures. The Commission expects that advanced reactor designs will comply
with the Commission's safety goal policy statement and the policy statement
on conversion to the metric measurement system as well. (CCH Nuclear
Regulation Reports, No. 1403, October 28, 2008)
Electric Utilities
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, FERC Statutes and Regulations ¶31,265], has
been largely affirmed by the agency. Order No. 708 authorized a public
utility, without prior Commission authorization, to dispose of less than
10 percent of its voting securities to various types of public utility
holding companies, only if, after the disposition, the holding company
and any associate company would own, in the aggregate, less than 10 percent
of the outstanding voting interests of that public utility. FERC, however,
in Order 704-A, has granted rehearing on the question of expanding authorization
to non-holding companies. The Commission determined that the distinction
between holding and non-holding companies was not determinative as to
whether a particular transaction was consistent with the public interest,
particularly if the in the aggregate 10 percent limitation was in place
to ensure that there was no likely opportunity for a transfer of control
of a public utility. Expanding blanket authorization to include non-holding
companies would encourage investment without causing harm to competition
or captive customers. According, the Commission will extend blanket authorization
to ``any person’’ but will require additional reporting for
non-holding companies. Specifically, the Commission will authorize a public
utility to transfer its outstanding voting securities to any person other
than a holding company if, after the transfer, such person and any of
its associate or affiliate companies will own less than 10 percent of
the outstanding voting interests of such public utility. (FERC
Statutes and Regulations ¶31,273
(ip
access users))
New Cross-Subsidization Safeguards
Clarified
A number of the Commission’s
(FERC) cross-subsidization restrictions on affiliate transactions [Order
No 707, 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. The Commission will
also address, on a case-by-case basis, issues regarding transactions between
affiliated franchised public utilities or between franchised public utilities
that include intermediate transactions with centralized service companies.
FERC will consider whether pricing or other restrictions need to be imposed
on these transactions. (FERC Statutes and Regulations
¶31,272
(ip
access users))
Incentive ROE Adder Does Apply to Cost
Overruns
FERC ruled that return on equity (ROE) incentive
adders, previously approved for transmission projects in ISO New England
Inc.’s Regional Transmission Expansion Plan (RTEP), did apply to
cost overruns on those projects. New England Conference of Public Utilities
Commissioners, Inc. (NECPUC) filed a complaint alleging that it was unjust
and unreasonable for the ROE incentives authorized in Opinion No. 489
(117 FERC ¶61,129) to apply to project costs in excess of those estimated
at the time the Commission granted the incentive. NECPUC argued that the
costs of many of the eligible projects had increased, some by as much
as 100 percent. NECPUC claimed that the cost increases represented a significant
change in the core circumstances that led the Commission to find a sufficient
link between the cost of the ROE incentive and its benefits. NECPUC argued
that the cost overruns would wipe out the incentive’s assumed benefits,
removing the basis for granting the incentive in the first place.The Commission
found that the cost increases NECPUC had identified did not change the
circumstances underlying their decision to authorize the ROE incentive
and did not render the cost of the incentive unjust and reasonable. NECPUC’s
attempt to restrict the application of the ROE incentive to the originally
estimated costs should have been raised in the opinion proceeding, the
Commission noted. The Commission explained that it did not authorize the
ROE incentive after a cost-benefit analysis that generated roughly equal
results, such that any increase in the cost of the incentive would tip
the scale against its benefits. Instead, the Commission relied on an evidentiary
record that focused on the broadest contours of the RTEP process, which
the Commission found trustworthy because its independence and objectivity
placed the necessity and region-wide benefits of RTEP-approved projects
beyond dispute. Finally, the Commission noted that the incentive applied
only to costs that were prudently incurred and it had an established procedure
for ensuring that only prudently incurred costs were recovered. (New
England Conference of Public Utilities Commissioners, Inc. v Bangor Hydro-Electric
Co., 124 FERC ¶61,291)
PJM’s OATT Revisions Found Reasonable
by ALJ
The open access transmission tariff (OATT) revisions
and assignments of cost responsibility to merchant transmission facilities
(MTFs) proposed by PJM Interconnection L.L.C. have generally been found
just, reasonable, and not unduly discriminatory by a FERC Administrative
Law Judge (ALJ). PJM is a regional transmission organization and as such
directs and coordinates the reliable and efficient operation of transmission
systems within its region by means of its OATT. MTFs are transmission
facilities that are added to or interconnected with the PJM system. MTFs
and their transmission customers seek to purchase energy in one region
and resell it at a profit in another region where generation costs are
higher. PJM is also responsible for the implementation of its regional
transmission expansion plan (RTEP). The ALJ generally upheld PJM’s
proposal when it allocates RTEP costs to MTFs and zones in a comparable
manner, in this case using a distribution factor (DFAX) methodology which
accurately measures an MTF’s benefits and allocates it costs that
are properly proportionate to those benefits. According to the ALJ, however,
certain adjustments to PJM’s OATT are necessary in order allocate
RTEP costs in a comparable manner. Therefore, PJM will have to develop
a mechanism for both reliability upgrades and economic upgrades. If PJM
allocates the cost of an upgrade to an MTF based on its planned firm transmission
withdrawal rights (FTWRs), the constructing transmission owner (TO) shall
enter RTEP charges allocated to the MTF into the TO’s allowance
for funds used during construction (AFUDC) account, and PJM cannot collect
revenues for the upgrade from the MTF until it goes into service. If the
MTF receives fewer FTWRs than the number specified in the interconnection
service agreement (ISA), PJM must base its collections on the actual number
of FWTRs awarded. PJM may collect typical electricity consumptions (TECs)
from the MTF based on more than its actual FTWRs only to the extent that
PJM or the TO can demonstrate that the MTF is responsible for receiving
fewer FTWRs than are specified in the ISA. (PJM Interconnection, L.L.C.,
124 FERC ¶63,022)
Hydroelectric Utilities
Hydro Proposal Would Substantially
Alter Existing Hydro License
Substantial evidence supported
a Federal Energy Regulatory Commission's (FERC) order concluding that
a hydroelectric project owner's license would be substantially altered
under the Federal Power Act (FPA) by a rural electric cooperative's proposed
hydroelectric project, the U.S. Court of Appeals for the Ninth Circuit
held. Under the FPA, a proposed project cannot substantially alter an
existing license. Fall River Rural Electric Cooperative, Inc. (Fall River)
argued that because its proposal would not substantially or materially
alter the configuration, mode of operations, or power generation of the
hydroelectric project licensed to Pennsylvania Power and Light Montana,
LLC (PPL), FERC's orders (dismissing Fall River’s license application,
request to hold the proceeding in abeyance, and request for rehearing)
were not supported by substantial evidence. The court said, however, that
each of FERC's factual findings with respect to Fall River's proposed
physical alterations and operational interferences with PPL's license
were supported by substantial evidence. Collectively, the alterations
would fundamentally change the physical characteristics and operation
of PPL's facilities, the court held. The court also ruled that FERC's
orders were consistent with Commission precedents and with its issuance
of a preliminary permit to Fall River. (Fall River Rural Electric
Coop., Inc. v. FERC, 9th Cir., CCH Utilities Law Reporter
¶14,714)
Hydro Project Does Not Burden Indian
Tribe’s Religious Practices
A decision by the Federal Energy
Regulatory Commission (FERC) to relicense a hydroelectric project did
not substantially burden an Indian tribe's free exercise of religion,
the U.S. Court of Appeals for the Ninth Circuit held. The Snoqualmie Indian
Tribe had argued that Snoqualmie Falls, where the hydroelectric power
plant was located, was a sacred site to them, and that the operation of
the plant by Puget Sound Energy interfered with their right to practice
their religion. The Religious Freedom Restoration Act (RFRA) provides
that the government shall not substantially burden a person's free exercise
of religion unless the government demonstrates that the application of
the burden to the person is in furtherance of a compelling governmental
interest and is the least restrictive means of furthering that interest.
The tribe's argument that the dam interfered with their ability to practice
their religion was irrelevant, the Ninth Circuit said, because there was
no evidence that the project forced them to choose between either practicing
their religion and receiving a government benefit, or between exercising
their religion and facing civil or criminal sanction. Therefore, relicensing
the project did not impose a substantial burden upon their ability to
practice their religion. In addition, while FERC is normally required
to engage in government-to-government consultation with federally-recognized
Indian tribes regarding identification of historic properties and consideration
of adverse effects, in this case FERC was not required to consult with
the Snoqualmie tribe because the tribe achieved federal recognition more
than two years after finalization of the key documents. (Snoqualmie
Indian Tribe v. FERC, 9th Cir., CCH Utilities Law Reporter
¶14,716)
Oil & Gas
Credits Approved for Relinquishing
Leases Offshore Florida
Certain leases located offshore
of Florida within certain OCS planning areas are eligible for a bonus
or royalty credit if relinquished, under a final rule issued by the Minerals
Management Service. There are 79 leases that are eligible for the credit.
Each lease is eligible for a credit equal to the original bonus paid plus
the cumulative rental paid on the lease since its issuance, which is worth
about $60 million in total for all 79 leases. MMS will not credit any
exploration costs or interest costs in calculating the credit. To obtain
the credit, parties holding title must apply within two years from the
effective date of the final rule. Multiple owners of a lease will receive
a percentage share of the credit based upon their percentage share in
total ownership interest at the time the request is submitted to MMS.
A bonus or royalty credit can be applied to a successful bid for a new
lease or for royalties reported due on Form MMS 2014. The credits may
be redeemed only in lieu of a monetary payment owed, and not for any royalty-in-kind
deliveries. The credits have no expiration date, but after five years,
unused credits may be applied, at MMS discretion, to the credit holder's
obligations to MMS. Credits are transferable. The rule became effective
October 14. (CCH Energy Management ¶9538)
Eligibility for Deepwater Royalty Relief
Expanded
The rules governing royalty
relief for deepwater oil and gas leases on the Outer Continental Shelf
(OCS) have been amended by the Minerals Management Service to make more
leases eligible for royalty relief. The Deep Water Royalty Relief Act
required the Department of Interior to suspend royalties for certain volumes
of production on all leases in more than 200 meters of water in certain
parts of the Gulf of Mexico issued in the first five years following enactment.
In its interim final rule implementing the law, MMS provided that leases
issued under this law assigned to a field with a current lease that produced
before the enactment date of the law, November 28, 1995, were not eligible
for section 304 royalty relief, and when there was more than one section
304 lease in a field, the leases shared the royalty suspension volume
(RSV). However, these two restrictions were found to be inconsistent with
the statute by the U.S. Court of Appeals for the Fifth Circuit, in the
2004 case of Santa Fe Snyder Corp., et al. v. Norton. The final rule removes
these restrictions. The changes are expected to cost the federal government
an estimated $3.1 billion to $10.3 billion between 2000 and 2034, depending
on whether the courts permit MMS to condition royalty relief on price
thresholds. (CCH Energy Management ¶9540)