Progress Energy 2004 Annual Report Download - page 78

by April 30, 2004. Approximately $5 million was originally
returned in March 2003 related to 2002 revenue sharing.
However, in February 2003, the parties to the Agreement
filed a motion seeking an order from the FPSC to enforce
the Agreement. In this motion, the parties disputed PEF’s
calculation of retail revenue subject to refund and
contended that the refund should be approximately
$23 million. In July 2003, the FPSC ruled that PEF must
provide an additional $18 million to its retail customers
related to the 2002 revenue sharing calculation. PEF
recorded this refund in the second quarter of 2003 as a
charge against electric operating revenue and refunded
this amount by October 2003.
The Agreement also provides that beginning with the
in-service date of PEF’s Hines Unit 2 and continuing
through December 2005, PEF will be allowed to recover
through the fuel cost recovery clause a return on average
investment and depreciation expense for Hines Unit 2, to
the extent such costs do not exceed the unit’s cumulative
fuel savings over the recovery period. Hines Unit 2 is a
516 MW combined-cycle unit that was placed in service
in December 2003. PEF recovered $36 million through this
clause related to Hines Unit 2.
In addition, PEF suspended retail accruals on its reserves
for nuclear decommissioning and fossil dismantlement
through December 2005. Additionally, for each calendar
year during the term of the Agreement, PEF will record a
$63 million depreciation expense reduction and may, at
its option, record up to an equal annual amount as an
offsetting accelerated depreciation expense. No
accelerated depreciation expense was recorded during
2004 and 2003. In addition, PEF is authorized, at its
discretion, to accelerate the amortization of certain
regulatory assets over the term of the Agreement.
Under the terms of the Agreement, PEF agreed to continue
the implementation of its four-year Commitment to
Excellence Reliability Plan and expected to achieve a 20%
improvement in its annual System Average Interruption
Duration Index by no later than 2004. If this improvement
level was not achieved for calendar years 2004 or 2005,
PEF would have provided a refund of $3 million for each
year the level is not achieved to 10% of its total retail
customers served by its worst performing distribution
feeder lines. PEF achieved this improvement level in 2004.
In January 2005, in anticipation of the expiration of its
Stipulation and Settlement approved by the FPSC in 2002
to conclude PEF’s then-pending rate case, PEF notified
the FPSC that it intends to request an increase in its base
rates, effective January 1, 2006. In its notice, PEF
requested the FPSC to approve calendar year 2006 as the
projected test period for setting new base rates. The
request for increased base rates is based on the fact that
PEF has faced significant cost increases over the past
decade and expects its operational costs to continue to
increase. These costs include the costs associated with
completion of the Hines Unit 3 generation facility,
extraordinary hurricane damage costs including capital
costs which are not expected to be directly recoverable,
the need to replenish the depleted storm reserve and the
expected infrastructure investment necessary to meet
high customer expectations, coupled with the demands
placed on PEF as a result of its strong customer growth.
On February 7, 2005, the FPSC acknowledged receipt of
PEF’s notice and authorized minimum filing requirements
and testimony to be filed May 1, 2005.
D. Regional Transmission Organizations and
Standard Market Design
In 2000, the FERC issued Order No. 2000 regarding regional
transmission organizations (RTOs). This Order set minimum
characteristics and functions that RTOs must meet,
including independent transmission service. In July 2002,
the FERC issued its Notice of Proposed Rulemaking in
Docket No. RM01-12-000, Remedying Undue Discrimination
through Open Access Transmission Service and Standard
Electricity Market Design (SMD NOPR). If adopted as
proposed, the rules set forth in the SMD NOPR would have
materially altered the manner in which transmission and
generation services are provided and paid for. In April 2003,
the FERC released a White Paper on the Wholesale Market
Platform. The White Paper provided an overview of what
the FERC intended to include in a final rule in the SMD
NOPR docket. The White Paper retained the fundamental
and most protested aspects of SMD NOPR, including
mandatory RTOs and the FERC’s assertion of jurisdiction
over certain aspects of retail service. The FERC has not yet
issued a final rule on SMD NOPR. The Company cannot
predict the outcome of these matters or the effect that they
may have on the GridSouth and GridFlorida proceedings
currently ongoing before the FERC. By order issued
December 22, 2004, the FERC terminated a portion of the
proceedings regarding GridSouth. The GridSouth
Companies asked the FERC for further clarification as to the
portions of the GridSouth docket it intended to address. On
March 2, 2005, the FERC affirmed that it only intended to
close the mediation portion of the GridSouth docket. It is
unknown what impact the future proceedings will have on
the Company’s earnings, revenues or prices.
The FPSC ruled in December 2001 that the formation of
GridFlorida by the three major investor-owned utilities in
Florida, including PEF, was prudent but ordered changes in
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Notes to Consolidated Financial Statements