Eversource 2006 Annual Report Download - page 40

38 NU 2006 ANNUAL REPORT
The billed sales are subtracted from total calendar month sales to
estimate unbilled sales. Unbilled revenues are estimated by first
allocating sales to the respective rate classes, then applying an
average rate to the estimate of unbilled sales.
The estimate of unbilled revenues is sensitive to numerous factors that
can significantly impact the amount of revenues recorded. Estimating
the impact of these factors is complex and requires management’s
judgment. The estimate of unbilled revenues is important to NU’s
consolidated financial statements, as adjustments to that estimate
could significantly impact operating revenues and earnings.
Derivative Accounting: Most of the contracts comprising Select
Energy’s competitive wholesale marketing and generation businesses
were classified as derivatives, as were certain Utility Group contracts
for the purchase or sale of energy or energy-related products. The
application of derivative accounting rules is complex and requires
management judgment in the following respects: identification of
derivatives and embedded derivatives, designation of the normal
purchases and sales exception, identifying hedge relationships and
determining continuing qualification for hedge accounting, assessing
and measuring hedge ineffectiveness, and estimating the fair value of
derivatives. All of these judgments, depending upon their timing and
effect, can have a significant impact on earnings.
The fair value of derivatives is based upon the quantity of the contract
and the underlying market priceor fair value per unit. When quantities
are not specified in the contract, the company estimates load amounts
using amounts referenced in default provisions and other relevant
sections of the contract. The estimated load amount is updated during
the term of the contract, and updates can have a material impact on
mark-to-market amounts.
The judgment applied in the election of the normal purchases and sales
exception (and resulting accrual accounting) includes the conclusions
that it is probable at the inception of the contract and throughout its
term that it will result in physical delivery and that the quantities will
be used or sold by the business over a reasonable period in the normal
course of business. If facts and circumstances change and management
can no longer support this conclusion, then the normal exception and
accrual accounting is terminated and fair value accounting is applied.
Contracts for which the company has elected the normal exception may
be designated as a hedged item, and the derivative hedge may qualify
as a cash flow hedge with changes in fair value recorded in accumulated
other comprehensive income. If the normal exception is terminated for
the hedged item, then the cash flow hedging of the normal contract, if
any, is also terminated to the extent that the company no longer expects
to physically deliver under the contract.
For further information, see Note 5, “Derivative Instruments,” to the
consolidated financial statements.
Regulatory Accounting: The accounting policies of NU’s Utility Group
conform to accounting principles generally accepted in the United
States of America applicable to rate-regulated enterprises and historically
reflect the effects of the rate-making process in accordance with SFAS
No. 71, “Accounting for the Effects of Certain Types of Regulation.”
The transmission and distribution businesses of CL&P, PSNH and
WMECO, along with PSNH’s generation business and Yankee Gas’
distribution business, continue to be cost-of-service rate regulated.
Management believes the application of SFAS No. 71 to those businesses
continues to be appropriate. Management also believes it is probable
that NU’s Utility Group companies will recover their investments in long-
lived assets, including regulatory assets. All material net regulatory
assets, are earning an equity return, except for securitized regulatory
assets, which are not supported by equity. Amortization and deferrals
of regulatory assets are included on a net basis in amortization expense
on the accompanying consolidated statements of income/(loss). The
regulatory assets not earning an equity return will be recovered over
approximately 7 years.
During 2006, several items of a regulatory nature required management
judgment. These items included:
• The October 31, 2006 FERC decision regarding the RTO ROE and
incentives for the New England transmission owners, which required
the company’s transmission businesses to adjust the 11.5 percent
ROE being utilized for the purpose of revenue recognition. This
adjustment resulted in a negative impact to the transmission
businesses’ 2006 earnings of approximately $3 million, net of tax.
Previously, management recognized revenues utilizing its
best estimate of the RTO ROE since the RTO was activated on
February 1, 2005.
• The recording of a fixed procurement fee of 0.50 mills per KWH that
CL&P was allowed to collect from customers who purchased TSO
service through 2006. Earnings in 2005 included the recognition by
CL&P of a $5.8 million asset related toCL&P’s2004 incentive
payment. This amount was calculated based upon a methodology
approved in a draft DPUC decision. To date, the DPUC has not
issued a final decision regarding this methodology and CL&P has
not recorded any additional incentive related earnings for 2005 or
2006. Management continues to believe that the $5.8 million asset
related toCL&P’s2004 incentive payment, which was reflected in
2005 earnings, is probable of recovery.
• DPUC decisions regarding Yankee Gas PGA clause charges and
requiring an audit of $11 million in previously recovered PGA
revenues associated with unbilled sales and revenue adjustments
for the period of September 1, 2003 through August 31, 2005.
Management believes the unbilled sales and revenue adjustments
and resulting charges to customers through the PGA clause for this
period were appropriate and that the appropriateness of the PGA
charges to customers for the time period under review will be
approved by the DPUC.
• A settlement agreement filed by CYAPC, the DPUC, the OCC and
Maine state regulators which was approved by the FERC on
November 16, 2006 and disposed of pending litigation at the FERC
and the Court of Appeals, among other issues. The settlement
agreement required CYAPC to forego collection of a $10 million
regulatory asset that was written-off in 2006. NU included in 2006
earnings its 49 percent share of CYAPC’s after-tax write-off.
The application of SFAS No. 71 results in recording regulatory assets
and liabilities. Regulatory assets represent the deferral of incurred
costs that are probable of future recovery in customer rates. In some
cases, NU records regulatory assets before approval for recovery has
been received from the applicable regulatory commission. Management