Eversource 2008 Annual Report Download - page 40

However, due to the significance of the non-observable
capacity prices associated with modeling the fair values of
these contracts, their initial fair values were not recorded
in CL&P’s financial statements pursuant to EITF Issue
No. 02-3, “Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts
Involved in Energy Trading and Risk Management
Activities.” This guidance applies to initial fair values only,
and not to subsequent changes in value. Subsequent
changes in the values of these contracts were substantial,
primarily due to reductions in the expected market prices
of capacity. The value of CfDs at December 31, 2008
included approximately $100 million of initial gains and
losses, previously deferred due to the use of significant
unobservable inputs in the valuation that were recorded
upon adoption of SFAS No. 157 on January1, 2008. The
changes in CfD values since inception were recorded
as a regulatory asset as the costs of the contracts are
recoverable from CL&P’s customers. Significant judgment
was involved in estimating the fair values of the contracts,
including projections of capacity prices and reflecting
the probabilities of cash flows considering the risks and
uncertainties associated with the contracts.
Our regulated companies, particularly CL&P and PSNH,
have entered into agreements that are derivatives and do
not meet the normal purchases and sales exception. These
contracts are marked to market and included in derivative
assets and liabilities on the accompanying consolidated
balance sheets. The oset to these derivatives are
generally recorded as regulatory assets or liabilities as
these amounts are recoverable from or refunded to our
customers as they are incurred. The measurement of many
of these contracts is extremely complex, as contracts are
long-dated and many of the variables, such as discount
rates, future energy and energy-related product prices,
and the risk associated with projects that have not been
completed, require significant management judgment.
For further information, see Note 1E, “Summary of
Significant Accounting Policies - Derivative Accounting,”
and Note 3, “Derivative Instruments,” to the consolidated
financial statements.
Revenue Recognition: The determination of energy sales
to individual customers is based on the reading of meters,
which occurs on a systematic basis throughout the month.
Billed revenues are based on these meter readings and
the bulk of recorded revenues is based on actual billings.
At the end of each month, amounts of energy delivered
to customers since the date of the last meter reading are
estimated, and an estimated amount of unbilled revenues
is also recorded.
Unbilled revenues represent an estimate of electricity or
gas delivered to customers for which the customers have
not yet been billed. Unbilled revenues are included in
revenue on the statement of income and are assets on the
balance sheet that are reclassified to accounts receivable
in the following month as customers are billed. Such
estimates are subject to adjustment when actual meter
readings become available, when changes in estimating
methodology occur and under other circumstances. There
were no changes in estimating methodology in 2008.
The regulated companies estimate unbilled revenues
monthly using the daily load cycle (DLC) method. The
DLC method allocates billed sales to the current calendar
month based on the daily load for each billing cycle. 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, such as energy demands, weather and changes in
the composition of customer classes that can significantly
impact the amount of revenues recorded. Estimating
the impact of these factors is complex and requires our
judgment. The estimate of unbilled revenues is important
to our consolidated financial statements, as adjustments
to that estimate could significantly impact operating
revenues and earnings.
For further information, see Note 1D, “Summary of
Significant Accounting Policies - Revenues,” to the
consolidated financial statements and “Transmission Rate
Matters and FERC Regulatory Issues” to this Management’s
Discussion and Analysis.
Regulatory Accounting: The accounting policies of the
regulated companies conform to GAAP applicable to rate-
regulated enterprises and historically reflect the eects
of the rate-making process in accordance with SFAS
No. 71, “Accounting for the Eects of Certain Types of
Regulation.”
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, we
record regulatory assets before approval for recovery has
been received from the applicable regulatory commission.
We must use judgment to conclude that costs deferred
as regulatory assets are probable of future recovery. We
base our conclusion on certain factors, including but not
limited to changes in the regulatory environment, recent
rate orders issued by the applicable regulatory agencies
and the status of any potential new legislation. Regulatory
liabilities represent revenues received from customers to
fund expected costs that have not yet been incurred or
probable future refunds to customers.
We use our best judgment when recording regulatory
assets and liabilities; however, regulatory commissions can
reach dierent conclusions about the recovery of costs,
and those conclusions could have a material impact on our
consolidated financial statements. We believe it is probable
that the regulated companies will recover the regulatory
assets that have been recorded. If we determined that we
could no longer apply SFAS No. 71 to our operations, or
if we could not conclude that it is probable that revenues
or costs would be recovered or reflected in future rates,
the revenues or costs would be charged to income in the
period in which they were incurred. If we determine that a
regulatory asset is no longer probable of recovery in rates,
then SFAS No. 71 requires that we record the charge in
earnings at that time.
For further information, see Note 1G, “Summary of
Significant Accounting Policies - Regulatory Accounting,”
to the consolidated financial statements.
Presentation: In accordance with GAAP, our consolidated
financial statements include all subsidiaries over which
control is maintained and would include any variable
interest entities (VIEs) for which we are the primary
beneficiary as defined in FIN 46(R), “Consolidation of
Variable Interest Entities.” Determining whether we are
the primary beneficiary of a VIE is complex and subjective,
and requires our judgment. There are a variety of facts
and circumstances and a number of variables taken into
consideration to determine whether we are considered
the primary beneficiary of a VIE. We need to determine
whether the entity is a VIE and whether our interest in
the entity is a variable interest. For each VIE in which we
have determined we hold a variable interest, we perform a
qualitative analysis that considers the nature of the VIE’s
risks and determine the variability created by these risks
that the VIE is designed to create and pass along to its
interest holders. We evaluate the degree to which the VIE
is designed to pass along risks to NU or its subsidiaries.
In addition, when considered necessary to identify the
primary beneficiary of the VIE, we perform modeling of
the potential results of the VIE under various scenarios
to quantify the degree to which it passes variability to
parties that hold variable interests, including NU or one
of its subsidiaries. If the majority of the variability were
determined to be passed along to us, then we would be
required to consolidate that VIE. A change in facts and
circumstances or a change in accounting guidance could
require us to reconsider whether or not we are the primary
beneficiary of the VIE.
The Energy Independence Act required the DPUC to
consider the impact on distribution companies of entering
into long-term contracts for capacity and contracts to
purchase renewable energy products from new generating
plants. We reviewed each contract to determine the
appropriate accounting treatment based on the terms of
the contracts, which included variable and fixed pricing
elements. In 2007, CL&P entered into a 15-year agreement
beginning in 2010 to purchase energy, capacity and
39