Exelon 2014 Annual Report Download - page 160

Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law; which took effect June 1, 2013. Under
the new law, following a proceeding before the MDPSC and with the MDPSC’s approval of the eligible infrastructure replacement
projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure
costs incurred after June 1, 2013. The legislation includes caps on the monthly surcharges to residential and non-residential
customers, and would require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess
of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement
projects would be rolled into gas distribution rates. Irrespective of the cap, BGE is required to file a gas rate case every five years
under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29,
2014, the MDPSC issued a decision conditionally approving the first five years of BGE’s plan and surcharge. On March 26, 2014, the
Maryland PSC approved as filed BGE’s proposed 2014 project list, tariff and associated surcharge amounts, with a surcharge that
became effective April 1, 2014. On November 17, 2014, BGE filed a surcharge update including a true-up of costs estimates
included in the 2014 surcharge, along with its 2015 project list and cost estimates to be included in the 2015 surcharge. The filing
was approved with a revised surcharge effective January 1, 2015. At its December 17, 2014 weekly Administrative Meeting, the
MDPSC approved BGE’s 2015 project list and the proposed surcharge for 2015. BGE will defer the difference between the
surcharge revenues and program costs as a regulated asset or liability, which was immaterial to Exelon and BGE as of
December 31, 2014.
In February 2014, the residential consumer advocate in Maryland filed an appeal with the Baltimore City Circuit Court to the decision
issued by the MDPSC on BGE’s infrastructure replacement plan. On September 5, 2014, the Baltimore City Circuit Court affirmed
the MDPSC decision on BGE’s infrastructure replacement plan and associated surcharge. On October 10, 2014, the residential
consumer advocate noticed its appeal to the Maryland Court of Special Appeals from the judgment entered by the Baltimore City
Circuit Court, however, a procedural schedule for the matter has not yet been set.
New York Regulatory Matters
Ginna Nuclear Power Plant Reliability Support Services Agreement. Ginna Nuclear Power Plant’s (Ginna) prior period fixed-
price PPA contract with Rochester Gas & Electric Company (RG&E) expired in June 2014. In light of the expiration of the agreement,
Ginna advised the New York Public Service Commission (NYPSC) and ISO-NY that in absence of a reliability need, Ginna
management would make a recommendation, subject to approval by the CENG board, that Ginna be retired as soon as practicable.
A formal study conducted by the ISO-NY and RG&E concluded that the Ginna nuclear plant needs to remain in operation to maintain
the reliability of the transmission grid in the Rochester region through 2018 when planned transmission system upgrades are
expected to be completed. In November, in response to a petition filed by Ginna, the NYPSC directed Ginna and RG&E to negotiate
a Reliability Support Services Agreement (RSSA). On February 13, 2015, regulatory filings, including RSSA terms negotiated
between Ginna and RG&E, to support the continued operation of Ginna for reliability purposes were made with the NYPSC and with
FERC for their approval. While the RSSA is expected to be approved, in absence of such an agreement and in the event the plant
was retired before the current license term ends in 2029, Exelon’s and Generation’s results of operations could be adversely affected
by increased depreciation rates, impairment charges, severance costs, and accelerated future decommissioning costs, among other
items. However, it is not expected that such impacts would be material to Exelon’s or Generation’s results of operations.
Federal Regulatory Matters
Transmission Formula Rate. ComEd’s and BGE’s transmission rates are each established based on a FERC-approved formula.
ComEd and BGE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates
effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected
capital additions. The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior
year and actual costs incurred for that year. ComEd and BGE record regulatory assets or regulatory liabilities and corresponding
increases or decreases to operating revenues for any differences between the revenue requirement in effect and ComEd’s and
BGE’s best estimate of the revenue requirement expected to be approved by the FERC for that year’s reconciliation. As of
December 31, 2014, and 2013, ComEd had a regulatory asset associated with the transmission formula rate of $21 million and $17
million, respectively, and BGE had a net regulatory asset associated with the transmission formula rate of $1 million and a net
regulatory liability which was not material as of December 31, 2013. The regulatory asset associated with transmission true-up is
amortized to Operating revenues as the associated amounts are recovered through rates.
156