NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(1) Background
and Basis of Presentation
General.
Included
in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy, Inc.
are the condensed consolidated interim financial statements and notes (Interim
Condensed Financial Statements) of CenterPoint Energy, Inc. and its subsidiaries
(collectively, CenterPoint Energy, or the Company). The Interim Condensed
Financial Statements are unaudited, omit certain financial statement disclosures
and should be read with the Annual Report on Form 10-K of CenterPoint
Energy for the year ended December 31, 2008 (CenterPoint Energy Form
10-K).
Background.
CenterPoint
Energy, Inc. is a public utility holding company. The Company’s operating
subsidiaries own and operate electric transmission and distribution facilities,
natural gas distribution facilities, interstate pipelines and natural gas
gathering, processing and treating facilities. As of March 31, 2009, the
Company’s indirect wholly owned subsidiaries included:
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CenterPoint
Energy Houston Electric, LLC (CenterPoint Houston), which engages in the
electric transmission and distribution business in a 5,000-square mile
area of the Texas Gulf Coast that includes
Houston; and
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CenterPoint
Energy Resources Corp. (CERC Corp., and, together with its subsidiaries,
CERC), which owns and operates natural gas distribution systems in six
states. Subsidiaries of CERC own interstate natural gas pipelines and gas
gathering systems and provide various ancillary services. A wholly owned
subsidiary of CERC Corp. offers variable and fixed-price physical natural
gas supplies primarily to commercial and industrial customers and electric
and gas utilities.
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Basis of
Presentation.
The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities, disclosure of contingent assets and liabilities at the date of the
financial statements, and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those
estimates.
The
Company’s Interim Condensed Financial Statements reflect all normal recurring
adjustments that are, in the opinion of management, necessary to present fairly
the financial position, results of operations and cash flows for the respective
periods. Amounts reported in the Company’s Condensed Statements of
Consolidated Income are not necessarily indicative of amounts expected for a
full-year period due to the effects of, among other things, (a) seasonal
fluctuations in demand for energy and energy services, (b) changes in energy
commodity prices, (c) timing of maintenance and other expenditures and (d)
acquisitions and dispositions of businesses, assets and other
interests.
For a
description of the Company’s reportable business segments, reference is made to
Note 14.
(2) New
Accounting Pronouncements
In
December 2007, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standard (SFAS) No. 141 (Revised 2007),
“
Business Combinations”
(SFAS No. 141R)
.
SFAS
No. 141R will significantly change the accounting for business combinations.
Under SFAS No. 141R, an acquiring entity will be required to recognize all the
assets acquired and liabilities assumed in a transaction at the acquisition date
fair value with limited exceptions. SFAS No. 141R also includes a substantial
number of new disclosure requirements and applies prospectively to business
combinations for which the acquisition date is on or after the beginning of the
first annual reporting period beginning on or after December 15, 2008. As the
provisions of SFAS No. 141R are applied prospectively, the impact to the Company
cannot be determined until applicable transactions occur.
In
December 2007, the FASB issued SFAS No. 160,
“
Noncontrolling Interests in
Consolidated Financial Statements ─ an Amendment of ARB No. 51” (SFAS No. 160).
SFAS No. 160 establishes new accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. This accounting standard is effective for fiscal years and interim
periods within those fiscal years, beginning on or after
December
15, 2008. The Company’s adoption of SFAS No. 160 as of January 1, 2009 did not
have a material impact on its financial position, results of operations or cash
flows.
Effective
January 1, 2009, the Company adopted SFAS No. 161,
“
Disclosures about Derivative
Instruments and Hedging Activities ─ an amendment of FASB Statement
No. 133” (SFAS No. 161). SFAS No. 161 amends SFAS No.
133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No.
133) which requires enhanced disclosures of derivative instruments and hedging
activities such as the fair value of derivative instruments and presentation of
their gains or losses in tabular format, as well as disclosures regarding credit
risks and strategies and objectives for using derivative
instruments. These disclosures are included as part of the Company’s
Derivatives Instruments footnote (see Note 5).
In May
2008, the FASB issued FASB Staff Position (FSP) No. APB 14-1 “Accounting for
Convertible Debt Instruments That May Be Settled in Cash Upon Conversion
(Including Partial Cash Settlement),” which changed the accounting treatment for
convertible securities that the issuer may settle fully or partially in cash.
Under the final FSP, cash settled convertible securities are separated into
their debt and equity components. The value assigned to the debt component is
the estimated fair value, as of the issuance date, of a similar debt instrument
without the conversion feature, and the difference between the proceeds for the
convertible debt and the amount reflected as a debt liability is recorded as
additional paid-in capital. As a result, the debt is recorded at a discount
reflecting its below market coupon interest rate. The debt is then subsequently
accreted to its par value over its expected life, with the rate of interest that
reflects the market rate at issuance being reflected on the income statement.
The Company adopted the FSP effective January 1, 2009, which required
retrospective application to all periods presented. The Company currently has no
convertible debt that is within the scope of this FSP, but did during prior
periods presented. Accordingly, the implementation of the FSP had a
non-cash effect on net income for prior periods and the consolidated balance
sheets when the Company had contingently convertible debt outstanding. The
effect on net income for the three months ended March 31, 2008 was a
decrease in net income of $1 million, or $0.01 per basic share. There was
no impact on diluted earnings per share. Upon adoption of this FSP, the effect
on the balance sheet as of January 1, 2009 was a credit to Additional
Paid-In-Capital of $23 million, with an offsetting debit to retained
earnings of $23 million.
In
December 2008, the FASB issued FASB Staff Position No. FAS 132(R)-1, “Employers’
Disclosures about Postretirement Benefit Plan Assets” (FSP 132(R)-1), which
amends SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other
Postretirement Benefits.” FSP 132(R)-1 expands the disclosures about
employers’ plan assets to include more detailed disclosures about the employers’
investment strategies, major categories of plan assets, concentrations of risk
within plan assets and valuation techniques used to measure the fair value of
plan assets. FSP 132(R)-1 is effective for fiscal years ending after December
15, 2009. The Company expects that the adoption of FSP 132(R)-1 will not have a
material impact on its financial position, results of operations or cash
flows.
In April
2009, the FASB issued FASB Staff Position No. FAS 107-1 and APB 28-1, “Interim
Disclosures about Fair Value of Financial Instruments” (FSP 107-1), which amends
SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” (SFAS No.
107) and APB 28-1, “Interim Financial Reporting.” FSP 107-1 expands the fair
value disclosures required for all financial instruments within the scope of
SFAS No. 107 to interim periods. FSP 107-1 also requires entities to disclose in
interim periods the methods and significant assumptions used to estimate the
fair value of financial instruments. FSP 107-1 is effective for interim
reporting periods ending after June 15, 2009. The Company expects that the
adoption of FSP 107-1 will not have a material impact on its financial position,
results of operations or cash flows.
(3) Employee
Benefit Plans
The
Company’s net periodic cost includes the following components relating to
pension and postretirement benefits:
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Three
Months Ended March 31,
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2008
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2009
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Pension
Benefits
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Postretirement
Benefits
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Pension
Benefits
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Postretirement
Benefits
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(in
millions)
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Service
cost
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$
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8
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$
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—
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$
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6
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$
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—
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Interest
cost
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25
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7
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28
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7
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Expected
return on plan assets
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(37
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)
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(3
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)
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(24
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)
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(2
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)
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Amortization
of prior service cost
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(2
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)
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1
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1
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1
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Amortization
of net loss
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6
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—
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17
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—
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Amortization
of transition obligation
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—
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2
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—
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2
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Net
periodic cost
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$
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—
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$
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7
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$
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28
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$
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8
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The
Company expects to contribute approximately $22 million to its pension
plans in 2009, of which $2 million had been contributed as of March 31,
2009 and $13 million was funded on April 14, 2009.
The
Company expects to contribute approximately $18 million to its
postretirement benefits plan in 2009, of which $6 million had been
contributed as of March 31, 2009.
(4) Regulatory
Matters
CenterPoint
Houston’s electric delivery system suffered substantial damage as a result of
Hurricane Ike, which struck the upper Texas coast in
September 2008.
As is
common with electric utilities serving coastal regions, the poles, towers,
wires, street lights and pole mounted equipment that comprise CenterPoint
Houston’s transmission and distribution system are not covered by property
insurance, but office buildings and warehouses and their contents and
substations are covered by insurance that provides for a maximum deductible of
$10 million. Current estimates are that total losses to property covered by
this insurance were approximately $17 million.
CenterPoint
Houston deferred the uninsured system restoration costs as management believes
it is probable that such costs will be recovered through the regulatory process.
As a result, system restoration costs did not affect the Company’s or
CenterPoint Houston’s reported net income for 2008 or the first quarter of 2009.
As of March 31, 2009, CenterPoint Houston had balances of $161 million in
construction work in progress and $437 million in regulatory assets related
to restoration costs incurred through March 31, 2009. In April 2009,
CenterPoint Houston filed with the Public Utility Commission of Texas (Texas
Utility Commission) an application for review and approval for recovery of
approximately $608 million in system restoration costs identified as of the
end of February 2009, plus $2 million in regulatory expenses,
$13 million in certain debt issuance costs, and $55 million in
carrying costs, pursuant to the legislation described
below. CenterPoint Houston expects to incur additional costs,
currently estimated at $12 million, related to Hurricane Ike, principally
related to the reconstruction of certain substations on Galveston Island, and
will seek to recover those costs through the regulatory process at a later
date.
In April
2009, the Texas Legislature enacted legislation that authorizes the Texas
Utility Commission to conduct proceedings to determine the amount of system
restoration costs and related costs associated with hurricanes or other major
storms that utilities are entitled to recover through charges to
customers. The legislation authorizes the Texas Utility Commission to
issue a financing order that would permit a utility like CenterPoint Houston to
recover the distribution portion of those costs and related carrying costs
through the issuance of non-recourse system restoration bonds similar to the
securitization bonds issued previously. The legislation also allows
such a utility to recover, or defer for future recovery, the transmission
portion of its system restoration costs through the existing mechanisms
established to recover transmission level costs. The legislation
requires the Texas Utility Commission to make its determination of recoverable
system restoration costs within 150 days of the filing of a utility’s
application and to rule on a utility’s application for a financing order for the
issuance of system restoration bonds
within 90
days of the filing of that application. The time periods for the
Texas Utility Commission to act on the two applications can run concurrently,
but the Texas Utility Commission can delay issuing a financing order until it
has ruled on the amount of recoverable system restoration
costs. Alternatively, if securitization is not the least-cost option
for rate payers, the legislation authorizes the Texas Utility Commission to
allow a utility to recover those costs through a customer surcharge
mechanism.
In the
application it filed in April 2009, CenterPoint Houston seeks approval for
recovery of a total of approximately $678 million, which includes the
$608 million in system restoration costs described above plus related
regulatory expenses, certain debt issuance costs, and carrying costs calculated
through August 2009. CenterPoint Houston also plans to apply for a financing
order which would authorize CenterPoint Houston to issue system restoration
bonds to recover the portion of the $678 million related to distribution
service, or approximately $657 million. Assuming those bonds are
issued, CenterPoint Houston will recover the distribution portion of system
restoration costs out of the bond proceeds, with the bonds being repaid over
time through a charge imposed on customers. CenterPoint Houston will
also seek to recover the remaining approximately $21 million related to
transmission service through the existing annual transmission cost of service
tariff. Although the Company and CenterPoint Houston believe the
storm restoration costs CenterPoint Houston is seeking authorization to recover
and the amounts it will seek authorization to securitize are in accordance with
applicable regulatory requirements, as in any regulatory proceeding, there can
be no assurance that the Texas Utility Commission will authorize recovery or
securitization of the full amounts requested by CenterPoint
Houston.
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(b)
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Recovery
of True-Up Balance
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In March
2004, CenterPoint Houston filed its true-up application with the Texas Utility
Commission, requesting recovery of $3.7 billion, excluding interest, as
allowed under the Texas Electric Choice Plan (Texas electric restructuring law).
In December 2004, the Texas Utility Commission issued its final order (True-Up
Order) allowing CenterPoint Houston to recover a true-up balance of
approximately $2.3 billion, which included interest through August 31,
2004, and provided for adjustment of the amount to be recovered to include
interest on the balance until recovery, along with the principal portion of
additional excess mitigation credits (EMCs) returned to customers after
August 31, 2004 and certain other adjustments.
CenterPoint
Houston and other parties filed appeals of the True-Up Order to a district court
in Travis County, Texas. In August 2005, that court issued its judgment on the
various appeals. In its judgment, the district court:
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reversed
the Texas Utility Commission’s ruling that had denied recovery of a
portion of the capacity auction true-up
amounts;
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reversed
the Texas Utility Commission’s ruling that precluded CenterPoint Houston
from recovering the interest component of the EMCs paid to retail electric
providers (REPs); and
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affirmed
the True-Up Order in all other
respects.
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The
district court’s decision would have had the effect of restoring approximately
$650 million, plus interest, of the $1.7 billion the Texas Utility
Commission had disallowed from CenterPoint Houston’s initial
request.
CenterPoint
Houston and other parties appealed the district court’s judgment to the Texas
Third Court of Appeals, which issued its decision in December 2007. In its
decision, the court of appeals:
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reversed
the district court’s judgment to the extent it restored the capacity
auction true-up amounts;
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reversed
the district court’s judgment to the extent it upheld the Texas Utility
Commission’s decision to allow CenterPoint Houston to recover EMCs paid to
Reliant Energy, Inc. (RRI);
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ordered
that the tax normalization issue described below be remanded to the Texas
Utility Commission as requested by the Texas Utility Commission;
and
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affirmed
the district court’s judgment in all other
respects.
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In April
2008, the court of appeals denied all motions for rehearing and reissued
substantially the same opinion as it had rendered in December 2007.
In June
2008, CenterPoint Houston petitioned the Texas Supreme Court for review of the
court of appeals decision. In its petition, CenterPoint Houston seeks reversal
of the parts of the court of appeals decision that (i) denied recovery of EMCs
paid to RRI, (ii) denied recovery of the capacity auction true up amounts
allowed by the district court, (iii) affirmed the Texas Utility Commission’s
rulings that denied recovery of approximately $378 million related to
depreciation and (iv) affirmed the Texas Utility Commission’s refusal to permit
CenterPoint Houston to utilize the partial stock valuation methodology for
determining the market value of its former generation assets. Two other
petitions for review were filed with the Texas Supreme Court by other parties to
the appeal. In those petitions parties contend that (i) the Texas Utility
Commission was without authority to fashion the methodology it used for valuing
the former generation assets after it had determined that CenterPoint Houston
could not use the partial stock valuation method, (ii) in fashioning the method
it used for valuing the former generating assets, the Texas Utility Commission
deprived parties of their due process rights and an opportunity to be heard,
(iii) the net book value of the generating assets should have been adjusted
downward due to the impact of a purchase option that had been granted to RRI,
(iv) CenterPoint Houston should not have been permitted to recover construction
work in progress balances without proving those amounts in the manner required
by law and (v) the Texas Utility Commission was without authority to award
interest on the capacity auction true up award.
Review by
the Texas Supreme Court of the court of appeals decision is at the discretion of
the court. In November 2008, the Texas Supreme Court requested the parties
to the Petitions for Review to submit briefs on the merits of the
issues raised. Briefing at the Texas Supreme Court should be completed in
May 2009. Although the Texas Supreme Court has not indicated
whether it will grant review of the lower court’s decision, its
request for full briefing on the merits allowed the parties to more fully
explain their positions. There is no prescribed time in which the Texas
Supreme Court must determine whether to grant review or, if review is granted,
for a decision by that court. Although the Company and CenterPoint Houston
believe that CenterPoint Houston’s true-up request is consistent with applicable
statutes and regulations and, accordingly, that it is reasonably possible that
it will be successful in its appeal to the Texas Supreme Court, the Company can
provide no assurance as to the ultimate court rulings on the issues to be
considered in the appeal or with respect to the ultimate decision by the Texas
Utility Commission on the tax normalization issue described below.
To
reflect the impact of the True-Up Order, in 2004 and 2005, the Company recorded
a net after-tax extraordinary loss of $947 million. No amounts related to
the district court’s judgment or the decision of the court of appeals have been
recorded in the Company’s consolidated financial statements. However, if the
court of appeals decision is not reversed or modified as a result of further
review by the Texas Supreme Court, the Company anticipates that it would be
required to record an additional loss to reflect the court of appeals decision.
The amount of that loss would depend on several factors, including ultimate
resolution of the tax normalization issue described below and the calculation of
interest on any amounts CenterPoint Houston ultimately is authorized to recover
or is required to refund beyond the amounts recorded based on the True-up Order,
but could range from $170 million to $385 million (pre-tax) plus
interest subsequent to December 31, 2008.
In the
True-Up Order, the Texas Utility Commission reduced CenterPoint Houston’s
stranded cost recovery by approximately $146 million, which was included in
the extraordinary loss discussed above, for the present value of certain
deferred tax benefits associated with its former electric generation assets. The
Company believes that the Texas Utility Commission based its order on proposed
regulations issued by the Internal Revenue Service (IRS) in March 2003 that
would have allowed utilities owning assets that were deregulated before
March 4, 2003 to make a retroactive election to pass the benefits of
Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal
Income Taxes (EDFIT) back to customers. However, the IRS subsequently withdrew
those proposed normalization regulations and in March 2008 adopted final
regulations that would not permit utilities like CenterPoint Houston to pass the
tax benefits back to customers without creating normalization violations. In
addition, the Company received a Private Letter Ruling (PLR) from the IRS in
August 2007, prior to adoption of the final regulations that confirmed that the
Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost
recovery by $146 million for ADITC and EDFIT would cause normalization
violations with respect to the ADITC and EDFIT.
If the
Texas Utility Commission’s order relating to the ADITC reduction is not reversed
or otherwise modified on remand so as to eliminate the normalization violation,
the IRS could require the Company to pay an amount equal to
CenterPoint
Houston’s unamortized ADITC balance as of the date that the normalization
violation is deemed to have occurred. In addition, the IRS could deny
CenterPoint Houston the ability to elect accelerated tax depreciation benefits
beginning in the taxable year that the normalization violation is deemed to have
occurred. Such treatment, if required by the IRS, could have a material adverse
impact on the Company’s results of operations, financial condition and cash
flows in addition to any potential loss resulting from final resolution of the
True-Up Order. In its opinion, the court of appeals ordered that this issue be
remanded to the Texas Utility Commission, as that commission requested. No
party, in the petitions for review or briefs filed with the Texas Supreme Court,
has challenged that order by the court of appeals, though the Texas Supreme
Court, if it grants review, will have authority to consider all aspects of the
rulings above, not just those challenged specifically by the appellants. The
Company and CenterPoint Houston will continue to pursue a favorable resolution
of this issue through the appellate or administrative process. Although the
Texas Utility Commission has not previously required a company subject to its
jurisdiction to take action that would result in a normalization violation, no
prediction can be made as to the ultimate action the Texas Utility Commission
may take on this issue on remand.
The Texas
electric restructuring law allowed the amounts awarded to CenterPoint Houston in
the Texas Utility Commission’s True-Up Order to be recovered either through
securitization or through implementation of a competition transition charge
(CTC) or both. Pursuant to a financing order issued by the Texas Utility
Commission in March 2005 and affirmed by a Travis County district court, in
December 2005 a subsidiary of CenterPoint Houston issued $1.85 billion in
transition bonds with interest rates ranging from 4.84% to 5.30% and final
maturity dates ranging from February 2011 to August 2020. Through issuance of
the transition bonds, CenterPoint Houston recovered approximately
$1.7 billion of the true-up balance determined in the True-Up Order plus
interest through the date on which the bonds were issued.
In July
2005, CenterPoint Houston received an order from the Texas Utility Commission
allowing it to implement a CTC designed to collect the remaining
$596 million from the True-Up Order over 14 years plus interest at an
annual rate of 11.075% (CTC Order). The CTC Order authorized CenterPoint Houston
to impose a charge on REPs to recover the portion of the true-up balance not
recovered through a financing order. The CTC Order also allowed CenterPoint
Houston to collect approximately $24 million of rate case expenses over
three years without a return through a separate tariff rider (Rider RCE).
CenterPoint Houston implemented the CTC and Rider RCE effective
September 13, 2005 and began recovering approximately $620 million.
The return on the CTC portion of the true-up balance was included in CenterPoint
Houston’s tariff-based revenues beginning September 13, 2005. Effective
August 1, 2006, the interest rate on the unrecovered balance of the CTC was
reduced from 11.075% to 8.06% pursuant to a revised rule adopted by the Texas
Utility Commission in June 2006. Recovery of rate case expenses under Rider RCE
was completed in September 2008.
Certain
parties appealed the CTC Order to a district court in Travis County. In May
2006, the district court issued a judgment reversing the CTC Order in three
respects. First, the court ruled that the Texas Utility Commission had
improperly relied on provisions of its rule dealing with the interest rate
applicable to CTC amounts. The district court reached that conclusion based on
its belief that the Texas Supreme Court had previously invalidated that entire
section of the rule. The 11.075% interest rate in question was applicable from
the implementation of the CTC Order on September 13, 2005 until
August 1, 2006, the effective date of the implementation of a new CTC in
compliance with the revised rule discussed above. Second, the district court
reversed the Texas Utility Commission’s ruling that allows CenterPoint Houston
to recover through the Rider RCE the costs (approximately $5 million) for a
panel appointed by the Texas Utility Commission in connection with the valuation
of electric generation assets. Finally, the district court accepted the
contention of one party that the CTC should not be allocated to retail customers
that have switched to new on-site generation. The Texas Utility Commission and
CenterPoint Houston appealed the district court’s judgment to the Texas
Third Court of Appeals, and in July 2008, the court of appeals reversed the
district court’s judgment in all respects and affirmed the Texas Utility
Commission’s order. Two of the appellants have requested further review from the
Texas Supreme Court. In March 2009, the Texas Supreme Court requested
that the parties file briefs on the merits in their appeals. Briefing
at the Texas Supreme Court should be completed in May 2009. Review by
the Texas Supreme Court is discretionary with that court, and there is no
deadline for its action on appeals. The ultimate outcome of this
matter cannot be predicted at this time. However, the Company does not expect
the disposition of this matter to have a material adverse effect on the
Company’s or CenterPoint Houston’s financial condition, results of operations or
cash flows.
During
the 2007 legislative session, the Texas legislature amended statutes prescribing
the types of true-up balances that can be securitized by utilities and
authorized the issuance of transition bonds to recover the balance
of
the CTC.
In June 2007, CenterPoint Houston filed a request with the Texas Utility
Commission for a financing order that would allow the securitization of the
remaining balance of the CTC, adjusted to refund certain unspent environmental
retrofit costs and to recover the amount of the final fuel reconciliation
settlement. CenterPoint Houston reached substantial agreement with other parties
to this proceeding, and a financing order was approved by the Texas Utility
Commission in September 2007. In February 2008, pursuant to the financing order,
a new special purpose subsidiary of CenterPoint Houston issued approximately
$488 million of transition bonds in two tranches with interest rates of
4.192% and 5.234% and final maturity dates of February 2020 and February 2023,
respectively. Contemporaneously with the issuance of those bonds, the CTC was
terminated and a transition charge was implemented.
During
the three months ended March 31, 2008 and 2009, CenterPoint Houston
recognized approximately $5 million and $-0-, respectively, in operating
income from the CTC. Additionally, during each of the three months ended
March 31, 2008 and 2009, CenterPoint Houston recognized approximately
$2 million of the allowed equity return not previously recognized. As of
March 31, 2009, the Company had not recognized an allowed equity return of
$205 million on CenterPoint Houston’s true-up balance because such return
will be recognized as it is recovered in rates.
Texas.
In March 2008, the
natural gas distribution businesses of CERC (Gas Operations) filed a request to
change its rates with the Railroad Commission of Texas (Railroad Commission) and
the 47 cities in its Texas Coast service territory, an area consisting of
approximately 230,000 customers in cities and communities on the outskirts of
Houston. The request sought to establish uniform rates, charges and terms and
conditions of service for the cities and environs of the Texas Coast service
territory. Of the 47 cities, 23 either affirmatively approved or allowed the
filed rates to go into effect by operation of law. Nine other cities were
represented by the Texas Coast Utilities Coalition (TCUC) and 15 cities were
represented by the Gulf Coast Coalition of Cities (GCCC). In July 2008, Gas
Operations reached a settlement agreement with the GCCC. That settlement
agreement, if implemented across the entire Texas Coast service territory, would
allow Gas Operations a $3.4 million annual increase in revenues. The TCUC
cities denied the rate change request and Gas Operations appealed the denial of
rates to the Railroad Commission. The Railroad Commission issued an order in
October 2008, which, if implemented across the entire Texas Coast service
territory, would result in an annual revenue increase of $3.7 million. Both
the Railroad Commission order and the settlement provide for an annual rate
adjustment mechanism to reflect changes in operating expenses and revenues as
well as changes in capital investment and associated changes in revenue-related
taxes. In December 2008, the Railroad Commission issued an order on
rehearing. Parties filed second motions for rehearing on this
order. In December 2008, Gas Operations implemented the approved
rates for the nine TCUC cities and the environs. In February 2009,
the Railroad Commission denied the second motions on rehearing reaffirming its
original decision. Cities with settled rates have the opportunity to
adopt the rates established by the Railroad Commission or retain the rates
agreed to in their settlements. In March 2009, TCUC and the State of
Texas appealed the Railroad Commission’s decision to the 353
rd
Judicial District Court, Travis County, Texas. The Company and CERC
do not expect the outcome of this litigation to have a material adverse impact
on the financial condition, results of operations or cash flows of either the
Company or CERC.
Minnesota.
In November 2006,
the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas
Operations for a waiver of MPUC rules in order to allow Gas Operations to
recover approximately $21 million in unrecovered purchased gas costs
related to periods prior to July 1, 2004. Those unrecovered gas costs were
identified as a result of revisions to previously approved calculations of
unrecovered purchased gas costs. Following that denial, Gas Operations recorded
a $21 million adjustment to reduce pre-tax earnings in the fourth quarter
of 2006 and reduced the regulatory asset related to these costs by an equal
amount. In March 2007, following the MPUC’s denial of reconsideration of its
ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of
the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been
arbitrary and capricious in denying Gas Operations a waiver. The court ordered
the case remanded to the MPUC for reconsideration under the same principles the
MPUC had applied in previously granted waiver requests. The MPUC sought further
review of the court of appeals decision from the Minnesota Supreme Court, and in
July 2008, the Minnesota Supreme Court agreed to review the
decision. In January 2009, the Minnesota Supreme Court heard oral
arguments. While there is
no
deadline for a decision, a decision is expected by the end of the third quarter
of 2009. While no prediction can be made as to the ultimate outcome, this matter
will have no negative impact on the Company’s financial condition, results of
operations or cash flows.
In
November 2008, Gas Operations filed a request with the MPUC to increase its
rates for utility distribution service. If approved by the MPUC, the
proposed new rates would result in an overall increase in annual revenue of
$59.8 million. The proposed increase would allow Gas Operations to
recover increased operating costs, including higher bad debt and collection
expenses, the cost of improved customer service and inflationary increases in
other expenses. It also would allow recovery of increased costs
related to conservation improvement programs and provide a return for the
additional capital invested to serve its customers. In addition, Gas
Operations is seeking an adjustment mechanism that would annually adjust rates
to reflect changes in use per customer. In December 2008, the MPUC
accepted the case and approved an interim rate increase of $51.2 million,
which became effective on January 2, 2009, subject to refund. CERC and the
Company do not expect an order from the MPUC until early 2010.
(5) Derivative
Instruments
The
Company is exposed to various market risks. These risks arise from transactions
entered into in the normal course of business. The Company utilizes
derivative instruments such as physical forward contracts, swaps and options to
mitigate the impact of changes in commodity prices, weather and interest rates
on its operating results and cash flows. Such contracts are recognized in the
Company’s Condensed Consolidated Balance Sheets at their fair value unless the
Company elects the normal purchase and sales exemption for qualified physical
transactions. A derivative contract may be designated as a normal purchase or
sale if the intent is to physically receive or deliver the product for use or
sale in the normal course of business. If derivative contracts are designated as
a cash flow hedge according to SFAS No. 133, the effective portions of the
changes in their fair values are reflected initially as a separate component of
shareholders’ equity and subsequently recognized in income at the same time the
hedged items impact earnings. The ineffective portions of changes in fair values
of derivatives designated as hedges are immediately recognized in income.
Changes in other derivatives not designated as normal or as a cash flow hedge
are recognized in income as they occur. The Company does not enter into or hold
derivative instruments for trading purposes.
The
Company has a Risk Oversight Committee composed of corporate and business
segment officers that oversees all commodity price, weather and credit risk
activities, including the Company’s marketing, risk management services and
hedging activities. The committee’s duties are to establish the Company’s
commodity risk policies, allocate risk capital within limits established by the
Company’s board of directors, approve use of new products and commodities,
monitor positions and ensure compliance with the Company’s risk management
policies and procedures and limits established by the Company’s board of
directors.
The
Company’s policies prohibit the use of leveraged financial instruments. A
leveraged financial instrument, for this purpose, is a transaction involving a
derivative whose financial impact will be based on an amount other than the
notional amount or volume of the instrument.
|
(a)
|
Non-Trading
Activities
|
Derivative Instruments.
The
Company enters into certain derivative instruments to manage physical commodity
price risks that do not qualify or are not designated as cash flow or fair value
hedges under SFAS No. 133. The Company utilizes these financial
instruments to manage physical commodity price risks and does not engage in
proprietary or speculative commodity trading. During the three months ended
March 31, 2008, the Company decreased natural gas revenues from unrealized net
losses of $20 million and increased natural gas expense from unrealized net
losses of $2 million, resulting in a net unrealized loss of
$22 million. During the three months ended March 31, 2009, the Company
increased revenues from unrealized net gains of $3 million and increased
natural gas expense from unrealized net losses of $22 million, resulting in
a net unrealized loss of $19 million.
In prior
years, the Company entered into certain derivative instruments that were
designated as cash flow hedges under SFAS No. 133. The objective of
these derivative instruments was to hedge the price risk associated with natural
gas purchases and sales to reduce cash flow variability related to meeting the
Company’s wholesale and retail customer obligations. In 2007, the Company
discontinued designating these instruments as cash flow hedges under SFAS No.
133. As of March 31, 2009, there are no remaining amounts deferred in
other comprehensive income related to these instruments that had previously been
designated as cash flow hedges.
Weather
Derivatives.
The Company has weather normalization or other
rate mechanisms that mitigate the impact of weather on its operations in
Arkansas, Louisiana, Oklahoma and a portion of Texas. The remaining
Gas
Operations
jurisdictions, Minnesota, Mississippi and most of Texas, do not have such
mechanisms. As a result, fluctuations from normal weather may have a
significant positive or negative effect on the results of these
operations.
In 2007,
the Company entered into heating-degree day swaps to mitigate the effect of
fluctuations from normal weather on its financial position and cash flows for
the 2007/2008 winter heating season. The swaps were based on ten-year
normal weather. In July 2008, the Company entered into heating-degree day swaps
to mitigate the effect of fluctuations from normal weather on its financial
position and cash flows for the 2008-2009 winter heating season. The
swaps are based on ten-year normal weather and provide for a maximum payment by
either party of $11 million. During the three months ended
March 31, 2008 and 2009, the Company recognized losses of $11 million
and $3 million, respectively, related to these swaps. Such
amounts were substantially offset by increased margin due to colder than normal
weather. These weather derivative losses are included in revenues in the
Condensed Statements of Consolidated Income.
|
(b)
|
Derivative
Fair Values and Income Statement
Impacts
|
The
following tables present information about the Company’s derivative instruments
and hedging activities. The first table provides a balance sheet
overview of the Company’s Derivative Assets and Liabilities as of March 31,
2009, while the latter table provides a breakdown of the related income
statement impact for the three months ended March 31, 2009.
|
Fair
Value of Derivative Instruments
|
|
|
|
|
March
31, 2009
|
|
|
Total
derivatives not designated as hedging
instruments
under SFAS 133
|
|
Balance
Sheet
Location
|
|
Derivative
Assets
Fair
Value (2) (3)
|
|
|
Derivative
Liabilities
Fair
Value (2) (3)
|
|
|
|
|
|
|
(in
millions)
|
|
|
Commodity
contracts (1)
|
|
Current
Assets
|
|
$
|
133
|
|
|
$
|
(14
|
)
|
|
Commodity
contracts
(1)
|
|
Other
Assets
|
|
|
24
|
|
|
|
(1
|
)
|
|
Commodity
contracts (1)
|
|
Current
Liabilities
|
|
|
12
|
|
|
|
(222
|
)
|
|
Commodity
contracts (1)
|
|
Other
Liabilities
|
|
|
1
|
|
|
|
(149
|
)
|
|
Indexed
debt securities derivative
|
|
Current
Liabilities
|
|
|
—
|
|
|
|
(111
|
)
|
|
Total
|
|
$
|
170
|
|
|
$
|
(497
|
)
|
|
(1)
|
Commodity
contracts are subject to master netting arrangements and are presented on
a net basis in the Consolidated Balance Sheet. This netting causes
derivative assets (liabilities) to be ultimately presented net in a
liability (asset) account within the Consolidated Balance
Sheet.
|
|
(2)
|
The
fair value shown for commodity contracts is comprised of derivative
volumes totaling 688 billion cubic feet (Bcf). These
volumes are disclosed in absolute terms, not net. Basis swaps
constitute 261 Bcf of the
total.
|
|
(3)
|
The
net of total non-trading derivative assets and liabilities is
$32 million as shown on the Company’s Condensed Consolidated Balance
Sheets, and is comprised of the commodity contracts derivative assets and
liabilities separately shown above offset by collateral netting of
$248 million.
|
For the
Company’s price stabilization activities of the Natural Gas Distribution
business segment, the settled costs of derivatives are ultimately recovered
through purchase gas adjustments. Accordingly, the net unrealized gains and
losses associated with interim price movements on contracts that are accounted
for as derivatives and probable of recovery through purchase gas adjustments are
recorded as net regulatory assets. For those derivatives that are not included
in purchase gas adjustments, unrealized gains and losses and settled amounts are
recognized on the Condensed Statements of Consolidated Income as revenue for
retail sales derivative contracts and as natural gas expense for natural gas
derivatives and non-retail related physical gas derivatives. Indexed debt
securities are recorded as Other Income (Expense) on the Condensed Statements of
Consolidated Income.
|
Income
Statement Impact of Derivative Activity
|
|
|
Total
derivatives not designated as hedging
instruments
under SFAS 133
|
|
Income
Statement
Location
|
|
Three
Months Ended
March
31, 2009
|
|
|
|
|
|
|
(in
millions)
|
|
|
Commodity
contracts
|
|
Gains
(Losses) in Revenue
|
|
$
|
77
|
|
|
Commodity
contracts (1)
|
|
Gains
(Losses) in Expense: Natural Gas
|
|
|
(149
|
)
|
|
Indexed
debt securities derivative
|
|
Gains
(Losses) in Other Income (Expense)
|
|
|
22
|
|
|
Total
|
|
$
|
(50
|
)
|
|
(1)
|
The Gains (Losses) in Expense:
Natural Gas contains $(78) million of costs associated with
price stabilization activities of our Natural Gas Distribution business
segment which are ultimately recovered through purchased gas
adjustments. In addition, for the period a $(91) million unrealized
loss associated with unsettled price stabilization derivatives
was recorded into the net regulatory asset
account.
|
|
(c)
|
Credit
Risk Contingent Features
|
The
Company enters into financial derivative contracts containing material adverse
change provisions. These provisions require the Company to post
additional collateral if the Standard & Poor’s Rating Services or Moody’s
Investors Service, Inc. credit rating of the Company is
downgraded. The total fair value of the derivative instruments that
contain credit risk contingent features that are in a net liability position at
March 31, 2009 is $250 million. The aggregate fair value of
assets that are already posted as collateral at March 31, 2009 is
$162 million. If all derivative contracts (in a net liability
position) containing credit risk contingent features were triggered at March 31,
2009, $88 million of additional assets would be required to be posted as
collateral.
(6) Fair
Value Measurements
Effective
January 1, 2008, the Company adopted SFAS No. 157, “Fair Value
Measurements” (SFAS No. 157), which requires additional disclosures about the
Company’s financial assets and liabilities that are measured at fair
value. Effective January 1, 2009, the Company adopted SFAS No. 157 for
nonfinancial assets and liabilities, which adoption had no impact on the
Company’s financial position, results of operations or cash
flows. Beginning in January 2008, assets and liabilities recorded at
fair value in the Consolidated Balance Sheet are categorized based upon the
level of judgment associated with the inputs used to measure their value.
Hierarchical levels, as defined in SFAS No. 157 and directly related to the
amount of subjectivity associated with the inputs to fair valuations of these
assets and liabilities, are as follows:
Level 1:
Inputs are unadjusted quoted prices in active markets for identical assets or
liabilities at the measurement date. The types of assets carried at Level 1
fair value generally are financial derivatives, investments and equity
securities listed in active markets.
Level 2:
Inputs, other than quoted prices included in Level 1, are observable for the
asset or liability, either directly or indirectly. Level 2 inputs include quoted
prices for similar instruments in active markets, and inputs other than quoted
prices that are observable for the asset or liability. Fair value assets
and liabilities that are generally included in this category are derivatives
with fair values based on inputs from actively quoted markets.
Level 3:
Inputs are unobservable for the asset or liability, and include situations where
there is little, if any, market activity for the asset or liability. In certain
cases, the inputs used to measure fair value may fall into different levels of
the fair value hierarchy. In such cases, the level in the fair value hierarchy
within which the fair value measurement in its entirety falls has been
determined based on the lowest level input that is significant to the fair value
measurement in its entirety. Unobservable inputs reflect the Company’s judgments
about the assumptions market participants would use in pricing the asset or
liability since limited market data exists. The Company develops these inputs
based on the best information available, including the Company’s own
data. The Company’s Level 3 derivative instruments primarily consist
of options that are not traded on recognized exchanges and are valued using
option pricing models.
The
following table presents information about the Company’s assets and liabilities
(including derivatives that are presented net) measured at fair value on a
recurring basis as of March 31, 2009, and indicates the fair value hierarchy of
the valuation techniques utilized by the Company to determine such fair
value.
|
|
|
Quoted
Prices in
Active
Markets
for Identical
Assets
(Level
1)
|
|
|
Significant
Other
Observable
Inputs
(Level
2)
|
|
|
Significant
Unobservable
Inputs
(Level
3)
|
|
|
Netting
Adjustments
(1)
|
|
|
Balance
as
of
March
31,
2009
|
|
|
|
|
(in
millions)
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
equities
|
|
$
|
184
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
184
|
|
|
Investments,
including money
market
funds
|
|
|
69
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
69
|
|
|
Derivative
assets
|
|
|
1
|
|
|
|
164
|
|
|
|
7
|
|
|
|
(30
|
)
|
|
|
142
|
|
|
Total
assets
|
|
$
|
254
|
|
|
$
|
164
|
|
|
$
|
7
|
|
|
$
|
(30
|
)
|
|
$
|
395
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Indexed
debt securities
derivative
|
|
$
|
—
|
|
|
$
|
111
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
111
|
|
|
Derivative
liabilities
|
|
|
41
|
|
|
|
314
|
|
|
|
33
|
|
|
|
(278
|
)
|
|
|
110
|
|
|
Total
liabilities
|
|
$
|
41
|
|
|
$
|
425
|
|
|
$
|
33
|
|
|
$
|
(278
|
)
|
|
$
|
221
|
|
|
(1)
|
Amounts
represent the impact of legally enforceable master netting agreements that
allow the Company to settle positive and negative positions and also cash
collateral of $248 million posted with the same
counterparties.
|
The
following table presents additional information about assets or liabilities,
including derivatives that are measured at fair value on a recurring basis for
which the Company has utilized Level 3 inputs to determine fair value, for the
three months ended March 31, 2009:
|
|
|
Fair
Value Measurements
Using
Significant
Unobservable
Inputs
(Level
3)
|
|
|
|
|
Derivative
assets and
liabilities,
net
|
|
|
|
|
(in
millions)
|
|
|
Beginning
liability balance as of January 1, 2009
|
|
$
|
(58
|
)
|
|
Total
gains or (losses) (unrealized and realized):
|
|
|
|
|
|
Included
in earnings
|
|
|
(3
|
)
|
|
Included
in regulatory assets
|
|
|
(17
|
)
|
|
Purchases,
sales, other settlements, net (1)
|
|
|
52
|
|
|
Ending
liability balance as of March 31, 2009
|
|
$
|
(26
|
)
|
|
The
amount of total losses for the period included in earnings attributable to
the change in unrealized gains or losses relating to assets still held at
the reporting date
|
|
$
|
(2
|
)
|
|
(1)
|
Purchases,
sales, other settlements, net includes $50 million associated
with price stabilization activities of the Company’s Natural Gas
Distribution business segment.
|
(7) Goodwill
Goodwill
by reportable business segment as of both December 31, 2008 and March 31,
2009 is as follows (in millions):
|
Natural
Gas Distribution
|
|
$
|
746
|
|
|
Interstate
Pipelines
|
|
|
579
|
|
|
Competitive
Natural Gas Sales and Services
|
|
|
335
|
|
|
Field
Services
|
|
|
25
|
|
|
Other
Operations
|
|
|
11
|
|
|
Total
|
|
$
|
1,696
|
|
(8) Comprehensive
Income
The
following table summarizes the components of total comprehensive income (net of
tax):
|
|
|
For
the Three Months Ended
March
31,
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
|
(in
millions)
|
|
|
Net
income
|
|
$
|
122
|
|
|
$
|
67
|
|
|
Other
comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
Adjustment
to pension and other postretirement plans (net of tax of $1 and
$1)
|
|
|
2
|
|
|
|
2
|
|
|
Net
deferred loss from cash flow hedges (net of tax of $5)
|
|
|
(9
|
)
|
|
|
—
|
|
|
Reclassification
of deferred gain from cash flow hedges realized in net income
(net
of tax of $2)
|
|
|
(4
|
)
|
|
|
—
|
|
|
Other
comprehensive income (loss)
|
|
|
(11
|
)
|
|
|
2
|
|
|
Comprehensive
income
|
|
$
|
111
|
|
|
$
|
69
|
|
The
following table summarizes the components of accumulated other comprehensive
loss:
|
|
|
December
31,
2008
|
|
|
March
31,
2009
|
|
|
|
|
(in
millions)
|
|
|
Adjustment
to pension and post retirement
plans
|
|
$
|
(127
|
)
|
|
$
|
(125
|
)
|
|
Net
deferred loss from cash flow hedges
|
|
|
(4
|
)
|
|
|
(4
|
)
|
|
Total
accumulated other comprehensive
loss
|
|
$
|
(131
|
)
|
|
$
|
(129
|
)
|
(9) Capital
Stock
CenterPoint
Energy has 1,020,000,000 authorized shares of capital stock, comprised of
1,000,000,000 shares of $0.01 par value common stock and
20,000,000 shares of $0.01 par value preferred stock. At
December 31, 2008, 346,088,714 shares of CenterPoint Energy common stock
were issued and 346,088,548 shares of CenterPoint Energy common stock were
outstanding. At March 31, 2009, 349,216,714 shares of
CenterPoint Energy common stock were issued and 349,216,548 shares of
CenterPoint Energy common stock were outstanding. Outstanding common
shares exclude 166 treasury shares at both December 31, 2008 and
March 31, 2009.
(10) Short-term
Borrowings and Long-term Debt
|
(a)
|
Short-term
Borrowings
|
Receivables Facility.
On
November 25, 2008, CERC replaced a receivables facility that had terminated
on October 28, 2008 with a new 364-day receivables facility. Availability
under the new facility ranges from $128 million to $375 million,
reflecting seasonal changes in receivables balances. At
December 31, 2008 and March 31, 2009 the facility size was $128 and
$375 million, respectively. As of December 31, 2008 and March 31,
2009, advances under the receivables facilities were $78 million and
$215 million, respectively.
Inventory Financing
. In
December 2008, CERC entered into an asset management agreement whereby it sold
$110 million of its natural gas in storage and agreed to repurchase an
equivalent amount of natural gas during the 2008/2009 winter heating season for
payments totaling $114 million. This transaction was accounted
for as a financing and, as of December 31, 2008 and March 31, 2009,
the Company’s financial statements reflect natural gas inventory of
$75 million and $-0-, respectively, and a financing obligation of
$75 million and $-0-, respectively, related to this
transaction.
Revolving Credit Facility.
CenterPoint Houston’s $600 million 364-day credit facility is
secured by a pledge of $600 million of general mortgage bonds issued by
CenterPoint Houston. This credit facility will terminate if bonds are issued to
securitize the distribution-related costs incurred as a result of Hurricane Ike
and if those bonds are issued prior to the November 24, 2009 expiration of
the facility. In April 2009, the Texas Legislature enacted
legislation that authorizes the Texas Utility Commission to conduct proceedings
to determine the amount of system restoration costs associated with hurricanes
or other major storms that utilities are entitled to recover. The
legislation authorizes the Texas Utility Commission to issue a financing order
that would permit a utility like CenterPoint Houston to recover the distribution
portion of those costs through the issuance of non-recourse system restoration
bonds similar to the securitization bonds issued previously. CenterPoint Houston
expects to seek regulatory approval for the issuance of such bonds during
2009.
Borrowing
costs for London Interbank Offered Rate (LIBOR)-based loans will be at a margin
of 2.25 percent above LIBOR rates, based on CenterPoint Houston’s current
ratings. In addition, CenterPoint Houston will pay lenders, based on current
ratings, a per annum commitment fee of 0.5 percent for their commitments
under the facility and a quarterly duration fee of 0.75 percent on the
average amount of outstanding borrowings during the quarter. The spread to LIBOR
and the commitment fee fluctuate based on the borrower’s credit rating. The
facility contains covenants, including a debt (excluding transition and other
securitization bonds) to total capitalization covenant. Bank fees associated
with the establishment of this credit facility aggregated approximately
$13 million. From inception through March 31, 2009, there
have been no borrowings under the credit facility.
General Mortgage Bonds
. In
January 2009, CenterPoint Houston issued $500 million aggregate principal
amount of general mortgage bonds, due in March 2014 with an interest rate of
7.00%. The proceeds from the sale of the bonds were used for general
corporate purposes, including the repayment of outstanding borrowings under its
revolving credit facility and the money pool, capital expenditures and storm
restoration costs associated with Hurricane Ike.
Revolving Credit Facilities.
The Company’s $1.2 billion credit facility has a first drawn cost of
LIBOR plus 55 basis points based on the Company’s current credit ratings. The
facility contains a debt (excluding transition and other securitization bonds)
to earnings before interest, taxes, depreciation and amortization (EBITDA)
covenant, which was modified (i) in August 2008 so that the permitted ratio of
debt to EBITDA would continue at its then-current level for the remaining term
of the facility and (ii) in November 2008 so that the permitted ratio of debt to
EBITDA would be temporarily increased until the earlier of December 31,
2009 or CenterPoint Houston’s issuance of bonds to securitize the costs incurred
as a result of Hurricane Ike, after which time the permitted ratio would revert
to the level that existed prior to the November 2008 modification.
CenterPoint
Houston’s $289 million credit facility’s first drawn cost is LIBOR plus 45
basis points based on CenterPoint Houston’s current credit ratings. The facility
contains a debt (excluding transition bonds) to total capitalization
covenant.
CERC
Corp.’s $950 million credit facility’s first drawn cost is LIBOR plus 45
basis points based on CERC Corp.’s current credit ratings. The facility contains
a debt to total capitalization covenant.
Under the
Company’s $1.2 billion credit facility, CenterPoint Houston’s
$289 million credit facility and CERC Corp’s $950 million credit
facility, an additional utilization fee of 5 basis points applies to borrowings
any time more than 50% of the facility is utilized. The spread to LIBOR and the
utilization fee fluctuate based on the borrower’s credit
rating.
As of
December 31, 2008 and March 31, 2009, the following loan balances were
outstanding under the Company’s long-term revolving credit facilities (in
millions):
|
|
|
December 31,
2008
|
|
|
March 31,
2009
|
|
|
CenterPoint
Energy $1.2 billion credit facility borrowings
|
|
$
|
264
|
|
|
$
|
234
|
|
|
CenterPoint
Houston $289 million credit facility borrowings
|
|
|
251
|
|
|
|
—
|
|
|
CERC
Corp. $950 million credit facility borrowings
|
|
|
926
|
|
|
|
501
|
|
|
Total
credit facility borrowings
|
|
$
|
1,441
|
|
|
$
|
735
|
|
In
addition, as of December 31, 2008 and March 31, 2009, the Company had
approximately $27 million and $29 million, respectively, of
outstanding letters of credit under its $1.2 billion credit facility and
CenterPoint Houston had approximately $4 million of outstanding letters of
credit under its $289 million credit facility as of both December 31,
2008 and March 31, 2009. There was no commercial paper outstanding that
would have been backstopped by the Company’s $1.2 billion credit facility
at December 31, 2008 and March 31, 2009. There was $-0- and
$19 million of commercial paper outstanding that was backstopped by CERC
Corp.’s $950 million credit facility at December 31, 2008 and March 31,
2009, respectively. The Company, CenterPoint Houston and CERC Corp.
were in compliance with all debt covenants as of March 31,
2009.
(11) Commitments
and Contingencies
|
(a)
|
Natural
Gas Supply Commitments
|
Natural
gas supply commitments include natural gas contracts related to the Company’s
Natural Gas Distribution and Competitive Natural Gas Sales and Services business
segments, which have various quantity requirements and durations, that are not
classified as non-trading derivative assets and liabilities in the Company’s
Consolidated Balance Sheets as of December 31, 2008 and March 31, 2009
as these contracts meet the SFAS No. 133 exception to be classified as “normal
purchases contracts” or do not meet the definition of a derivative. Natural gas
supply commitments also include natural gas transportation contracts that do not
meet the definition of a derivative. As of March 31, 2009, minimum payment
obligations for natural gas supply commitments are approximately
$333 million for the remaining nine months in 2009, $460 million in
2010, $396 million in 2011, $393 million in 2012, $381 million in
2013 and $930 million after 2013.
|
(b)
|
Legal,
Environmental and Other Regulatory
Matters
|
Legal
Matters
RRI
Indemnified Litigation
Gas Market Manipulation
Cases
. The Company, CenterPoint Houston or their predecessor, Reliant
Energy, Incorporated (Reliant Energy), and certain of their former subsidiaries
are named as defendants in several lawsuits described below. Under a master
separation agreement between the Company and RRI (formerly Reliant Resources,
Inc.), the Company and its subsidiaries are entitled to be indemnified by RRI
for any losses, including attorneys’ fees and other costs, arising out of these
lawsuits. Pursuant to the indemnification obligation, RRI is
defending the Company and its subsidiaries to the extent named in these
lawsuits. A large number of lawsuits were filed against numerous gas
market participants in a number of federal and western state courts in
connection with the operation of the natural gas markets in 2000-2002. The
Company’s former affiliate, RRI, was a participant in gas trading in the
California and Western markets. These lawsuits, many of which have been filed as
class actions, allege violations of state and federal antitrust laws. Plaintiffs
in these lawsuits are seeking a variety of forms of relief, including, among
others, recovery of compensatory damages (in some cases in excess of
$1 billion), a trebling of compensatory damages, full consideration damages
and attorneys’ fees. The Company and/or Reliant Energy were named in
approximately 30 of these lawsuits, which were instituted between 2003 and 2009.
Most of these cases have settled or the Company has been dismissed from them.
CenterPoint Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a
defendant or sought to be added as a defendant in two cases now pending in
federal court in Wisconsin and Nevada alleging a conspiracy to inflate Wisconsin
natural gas prices in 2000-2002. Additionally, the Company was a
defendant in a lawsuit filed in state court in Nevada that was dismissed in
2007, but the plaintiffs have asked for reconsideration of the dismissal. The
Company believes that neither it nor CES is a proper defendant in
the
remaining
cases and will continue to pursue dismissal from those cases. The
Company does not expect the ultimate outcome of these matters to have a material
impact on its financial condition, results of operations or cash
flows.
Other
Legal Matters
Natural Gas Measurement
Lawsuits.
CERC Corp. and certain of its subsidiaries are defendants in a
lawsuit filed in 1997 under the Federal False Claims Act alleging mismeasurement
of natural gas produced from federal and Indian lands. The suit seeks
undisclosed damages, along with statutory penalties, interest, costs and fees.
The complaint is part of a larger series of complaints filed against 77 natural
gas pipelines and their subsidiaries and affiliates. An earlier single action
making substantially similar allegations against the pipelines was dismissed by
the federal district court for the District of Columbia on grounds of improper
joinder and lack of jurisdiction. As a result, the various individual complaints
were filed in numerous courts throughout the country. This case has been
consolidated, together with the other similar False Claims Act cases, in the
federal district court in Cheyenne, Wyoming. In October 2006, the judge
considering this matter granted the defendants’ motion to dismiss the suit on
the ground that the court lacked subject matter jurisdiction over the claims
asserted. The plaintiff sought review of that dismissal from the Tenth Circuit
Court of Appeals, which affirmed the district court’s dismissal in March 2009.
The plaintiff has indicated that he intends to seek rehearing of the Tenth
Circuit decision.
In
addition, CERC Corp. and certain of its subsidiaries are defendants in two
mismeasurement lawsuits brought against approximately 245 pipeline companies and
their affiliates pending in state court in Stevens County, Kansas. In
one case (originally filed in May 1999 and amended four times), the plaintiffs
purport to represent a class of royalty owners who allege that the defendants
have engaged in systematic mismeasurement of the volume of natural gas for more
than 25 years. The plaintiffs amended their petition in this suit in July 2003
in response to an order from the judge denying certification of the plaintiffs’
alleged class. In the amendment the plaintiffs dismissed their claims against
certain defendants (including two CERC Corp. subsidiaries), limited the scope of
the class of plaintiffs they purport to represent and eliminated previously
asserted claims based on mismeasurement of the British thermal unit (Btu)
content of the gas. The same plaintiffs then filed a second lawsuit, again as
representatives of a putative class of royalty owners, in which they assert
their claims that the defendants have engaged in systematic mismeasurement of
the Btu content of natural gas for more than 25 years. In both lawsuits, the
plaintiffs seek compensatory damages, along with statutory penalties, treble
damages, interest, costs and fees.
CERC
believes that there has been no systematic mismeasurement of gas and that these
lawsuits are without merit. CERC and the Company do not expect the ultimate
outcome of the lawsuits to have a material impact on the financial condition,
results of operations or cash flows of either the Company or CERC.
Gas Cost Recovery Litigation.
In October 2002, a lawsuit was filed on behalf of certain CERC ratepayers
in state district court in Wharton County, Texas against the Company, CERC
Corp., Entex Gas Marketing Company (EGMC), and certain non-affiliated companies
alleging fraud, violations of the Texas Deceptive Trade Practices Act,
violations of the Texas Utilities Code, civil conspiracy and violations of the
Texas Free Enterprise and Antitrust Act with respect to rates charged to certain
consumers of natural gas in the State of Texas. The plaintiffs initially sought
certification of a class of Texas ratepayers, but subsequently dropped their
request for class certification. The plaintiffs later added as defendants
CenterPoint Energy Marketing Inc., CenterPoint Energy Pipeline Services, Inc.
(CEPS), and certain other subsidiaries of CERC, and other non-affiliated
companies. In February 2005, the case was removed to federal district court in
Houston, Texas, and in March 2005, the plaintiffs voluntarily dismissed the
case.
In
October 2004, a lawsuit was filed by certain CERC ratepayers in Texas and
Arkansas in circuit court in Miller County, Arkansas against the Company, CERC
Corp., EGMC, CenterPoint Energy Gas Transmission Company (CEGT), CenterPoint
Energy Field Services (CEFS), CEPS, Mississippi River Transmission Corp. (MRT)
and various non-affiliated companies alleging fraud, unjust enrichment and civil
conspiracy with respect to rates charged to certain consumers of natural gas in
Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Subsequently,
the plaintiffs dropped CEGT and MRT as defendants. Although the plaintiffs in
the Miller County case sought class certification, no class was certified. In
June 2007, the Arkansas Supreme Court determined that the Arkansas claims were
within the sole and exclusive jurisdiction of the Arkansas Public Service
Commission (APSC). In response to that ruling, in August 2007 the Miller County
court stayed but refused to dismiss the Arkansas claims. In February 2008, the
Arkansas Supreme Court directed the Miller County court to dismiss the entire
case for lack of jurisdiction. The Miller County court subsequently dismissed
the case in accordance with the Arkansas Supreme Court’s mandate and all
appellate deadlines have expired.
In June
2007, the Company, CERC Corp., EGMC and other defendants in the Miller County
case filed a petition in a district court in Travis County, Texas seeking a
determination that the Railroad Commission has exclusive original jurisdiction
over the Texas claims asserted in the Miller County case. In October 2007, CEFS
and CEPS joined the petition in the Travis County case. In October
2008, the district court ruled that the Railroad Commission had exclusive
original jurisdiction over the Texas claims asserted against the Company, CERC
Corp., EGMC and the other defendants in the Miller County case. In
January 2009, the court entered a final declaratory judgment ruling that the
Railroad Commission has exclusive jurisdiction over Texas claims. The
Company does not anticipate that an appeal will be filed.
In August
2007, the Arkansas plaintiff in the Miller County litigation initiated a
complaint at the APSC seeking a decision concerning the extent of the APSC’s
jurisdiction over the Miller County case and an investigation into the merits of
the allegations asserted in his complaint with respect to CERC. In February
2009, the Arkansas plaintiff notified the APSC that he would no longer pursue
his claims. That complaint remains pending at the APSC, subject to the review of
the Arkansas Attorney General, APSC Staff and the APSC. The Company and CERC do
not expect the outcome of this proceeding to have a material adverse impact on
the financial condition, results of operations or cash flows of either the
Company or CERC.
In
February 2003, a lawsuit was filed in state court in Caddo Parish, Louisiana
against CERC with respect to rates charged to a purported class of certain
consumers of natural gas and gas service in the State of Louisiana. In February
2004, another suit was filed in state court in Calcasieu Parish, Louisiana
against CERC seeking to recover alleged overcharges for gas or gas services
allegedly provided by CERC to a purported class of certain consumers of natural
gas and gas service without advance approval by the Louisiana Public Service
Commission (LPSC). At the time of the filing of each of the Caddo and Calcasieu
Parish cases, the plaintiffs in those cases filed petitions with the LPSC
relating to the same alleged rate overcharges. The Caddo and Calcasieu Parish
lawsuits were stayed pending the resolution of the petitions filed with the
LPSC. In August 2007, the LPSC issued an order approving a Stipulated Settlement
in the review initiated by the plaintiffs in the Calcasieu Parish litigation. In
the LPSC proceeding, CERC’s gas purchases were reviewed back to 1971. The review
concluded that CERC’s gas costs were “reasonable and prudent,” but CERC agreed
to credit to jurisdictional customers approximately $920,000, including
interest, related to certain off-system sales. The refund was completed in the
fourth quarter of 2008. A similar review by the LPSC related to the Caddo Parish
litigation was resolved without additional payment by CERC. In October 2008, the
courts considering the Caddo and Calcasieu Parish cases dismissed these cases
pursuant to motions to dismiss and these proceedings have been
concluded.
Storage Facility Litigation.
In February 2007, an Oklahoma district court in Coal County, Oklahoma, granted a
summary judgment against CEGT in a case, Deka Exploration, Inc. v. CenterPoint
Energy, filed by holders of oil and gas leaseholds and some mineral interest
owners in lands underlying CEGT’s Chiles Dome Storage Facility. The dispute
concerns “native gas” that may have been in the Wapanucka formation underlying
the Chiles Dome facility when that facility was constructed in 1979 by a CERC
entity that was the predecessor in interest of CEGT. The court ruled that the
plaintiffs own native gas underlying those lands, since neither CEGT nor its
predecessors had condemned those ownership interests. The court rejected CEGT’s
contention that the claim should be barred by the statute of limitations, since
the suit was filed over 25 years after the facility was constructed. The court
also rejected CEGT’s contention that the suit is an impermissible attack on the
determinations the FERC and Oklahoma Corporation Commission made regarding the
absence of native gas in the lands when the facility was constructed. The
summary judgment ruling was only on the issue of liability, though the court did
rule that CEGT has the burden of proving that any gas in the Wapanucka formation
is gas that has been injected and is not native gas. Further hearings and orders
of the court are required to specify the appropriate relief for the plaintiffs.
CEGT plans to appeal through the Oklahoma court system any judgment that imposes
liability on CEGT in this matter. The Company and CERC do not expect the outcome
of this matter to have a material impact on the financial condition, results of
operations or cash flows of either the Company or CERC.
Environmental
Matters
Manufactured Gas Plant Sites.
CERC and its predecessors operated manufactured gas plants (MGPs) in the past.
In Minnesota, CERC has completed remediation on two sites, other than ongoing
monitoring and water treatment. There are five remaining sites in CERC’s
Minnesota service territory. CERC believes that it has no liability with respect
to two of these sites.
At March
31, 2009, CERC had accrued $14 million for remediation of these Minnesota
sites and the estimated range of possible remediation costs for these sites was
$4 million to $35 million based on remediation continuing for 30 to 50
years. The cost estimates are based on studies of a site or industry average
costs for remediation of sites of similar size. The actual remediation costs
will be dependent upon the number of sites to be remediated, the participation
of other potentially responsible parties (PRP), if any, and the remediation
methods used. CERC has utilized an environmental expense tracker mechanism in
its rates in Minnesota to recover estimated costs in excess of insurance
recovery. As of March 31, 2009, CERC had collected $13 million from
insurance companies and rate payers to be used for future environmental
remediation.
In
addition to the Minnesota sites, the United States Environmental Protection
Agency and other regulators have investigated MGP sites that were owned or
operated by CERC or may have been owned by one of its former affiliates. CERC
has been named as a defendant in a lawsuit filed in the United States District
Court, District of Maine, under which contribution is sought by private parties
for the cost to remediate former MGP sites based on the previous ownership of
such sites by former affiliates of CERC or its divisions. CERC has also been
identified as a PRP by the State of Maine for a site that is the subject of the
lawsuit. In June 2006, the federal district court in Maine ruled that the
current owner of the site is responsible for site remediation but that an
additional evidentiary hearing is required to determine if other potentially
responsible parties, including CERC, would have to contribute to that
remediation. The Company is investigating details regarding the site and the
range of environmental expenditures for potential remediation. However, CERC
believes it is not liable as a former owner or operator of the site under the
Comprehensive Environmental, Response, Compensation and Liability Act of 1980,
as amended, and applicable state statutes, and is vigorously contesting the suit
and its designation as a PRP.
Mercury Contamination.
The
Company’s pipeline and distribution operations have in the past employed
elemental mercury in measuring and regulating equipment. It is possible that
small amounts of mercury may have been spilled in the course of normal
maintenance and replacement operations and that these spills may have
contaminated the immediate area with elemental mercury. The Company has found
this type of contamination at some sites in the past, and the Company has
conducted remediation at these sites. It is possible that other contaminated
sites may exist and that remediation costs may be incurred for these sites.
Although the total amount of these costs is not known at this time, based on the
Company’s experience and that of others in the natural gas industry to date and
on the current regulations regarding remediation of these sites, the Company
believes that the costs of any remediation of these sites will not be material
to the Company’s financial condition, results of operations or cash
flows.
Asbestos.
Some facilities
owned by the Company contain or have contained asbestos insulation and other
asbestos-containing materials. The Company or its subsidiaries have been named,
along with numerous others, as a defendant in lawsuits filed by a number of
individuals who claim injury due to exposure to asbestos. Some of the claimants
have worked at locations owned by the Company, but most existing claims relate
to facilities previously owned by the Company’s subsidiaries. The Company
anticipates that additional claims like those received may be asserted in the
future. In 2004, the Company sold its generating business, to which most of
these claims relate, to Texas Genco LLC, which is now known as NRG Texas LP.
Under the terms of the arrangements regarding separation of the generating
business from the Company and its sale to NRG Texas LP, ultimate financial
responsibility for uninsured losses from claims relating to the generating
business has been assumed by NRG Texas LP, but the Company has agreed to
continue to defend such claims to the extent they are covered by insurance
maintained by the Company, subject to reimbursement of the costs of such defense
from the purchaser. Although their ultimate outcome cannot be predicted at this
time, the Company intends to continue vigorously contesting claims that it does
not consider to have merit and does not expect, based on its experience to date,
these matters, either individually or in the aggregate, to have a material
adverse effect on the Company’s financial condition, results of operations or
cash flows.
Groundwater Contamination
Litigation.
Predecessor entities of CERC, along with several other
entities, are defendants in litigation,
St. Michel Plantation, LLC, et al,
v. White, et al
., pending in civil district court in Orleans Parish,
Louisiana. In the lawsuit, the plaintiffs allege that their property in
Terrebonne Parish, Louisiana suffered salt water contamination as a result of
oil and gas drilling activities conducted by the defendants. Although a
predecessor of CERC held an interest in two oil and gas leases on a portion of
the property at issue, neither it nor any other CERC entities drilled or
conducted other oil and gas operations on those leases. In January 2009,
CERC and the plaintiffs reached agreement on the terms of a settlement that, if
ultimately approved by the Louisiana Department of Natural Resources and the
court, is expected to finally resolve this litigation. The Company
and
CERC do
not expect the outcome of this litigation to have a material adverse impact on
the financial condition, results of operations or cash flows of either the
Company or CERC.
Other Environmental.
From
time to time the Company has received notices from regulatory authorities or
others regarding its status as a PRP in connection with sites found to require
remediation due to the presence of environmental contaminants. In addition, the
Company has been named from time to time as a defendant in litigation related to
such sites. Although the ultimate outcome of such matters cannot be predicted at
this time, the Company does not expect, based on its experience to date, these
matters, either individually or in the aggregate, to have a material adverse
effect on the Company’s financial condition, results of operations or cash
flows.
Other
Proceedings
The
Company is involved in other legal, environmental, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding matters arising in the ordinary course of business. Some of
these proceedings involve substantial amounts. The Company regularly analyzes
current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters. The Company does not
expect the disposition of these matters to have a material adverse effect on the
Company’s financial condition, results of operations or cash flows.
Guaranties
Prior to
the Company’s distribution of its ownership in RRI to its shareholders, CERC had
guaranteed certain contractual obligations of what became RRI’s trading
subsidiary. Under the terms of the separation agreement between the companies,
RRI agreed to extinguish all such guaranty obligations prior to separation, but
at the time of separation in September 2002, RRI had been unable to extinguish
all obligations. To secure CERC against obligations under the remaining
guaranties, RRI agreed to provide cash or letters of credit for CERC’s benefit,
and undertook to use commercially reasonable efforts to extinguish the remaining
guaranties. In December 2007, the Company, CERC and RRI amended that agreement
and CERC released the letters of credit it held as security. Under the revised
agreement RRI agreed to provide cash or new letters of credit to secure CERC
against exposure under the remaining guaranties as calculated under the new
agreement if and to the extent changes in market conditions exposed CERC to a
risk of loss on those guaranties.
The
potential exposure to CERC under the guaranties relates to payment of demand
charges related to transportation contracts. The present value of the demand
charges under these transportation contracts, which will be effective until
2018, was approximately $108 million as of March 31, 2009. RRI continues to
meet its obligations under the contracts, and, on the basis of market
conditions, the Company and CERC have not required additional security. However,
if RRI should fail to perform its obligations under the contracts or if RRI
should fail to provide adequate security in the event market conditions change
adversely, the Company would retain exposure to the counterparty under the
guaranty.
(12) Income
Taxes
During
the three months ended March 31, 2008 and 2009, the effective tax rate was 37%
and 42%, respectively. The most significant item affecting the
comparability of the effective tax rate is a $4 million increase in the
2009 income tax expense as a result of a state tax audit.
The
following table summarizes the Company’s uncertain tax positions in accordance
with FASB Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income
Taxes — an Interpretation of FASB Statement No. 109,” at December 31, 2008 and
March 31, 2009:
|
|
|
December 31,
2008
|
|
|
March
31,
2009
|
|
|
|
|
(in
millions)
|
|
|
|
|
|
|
|
Liability
for uncertain tax positions
|
|
$
|
117
|
|
|
$
|
154
|
|
|
Portion
of liability for uncertain tax positions that,
if
recognized, would reduce the effective income tax rate
|
|
|
14
|
|
|
|
15
|
|
|
Interest
accrued on uncertain tax positions
|
|
|
10
|
|
|
|
11
|
|
(13) Earnings
Per Share
The
following table reconciles numerators and denominators of the Company’s basic
and diluted earnings per share calculations:
|
|
|
Three
Months Ended March 31,
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
|
(in
millions, except share and
per
share amounts)
|
|
|
Basic
earnings per share calculation:
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
122
|
|
|
$
|
67
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares
outstanding
|
|
|
327,279,000
|
|
|
|
347,496,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per share:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
0.37
|
|
|
$
|
0.19
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
earnings per share calculation:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
122
|
|
|
$
|
67
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares
outstanding
|
|
|
327,279,000
|
|
|
|
347,496,000
|
|
|
Plus:
Incremental shares from assumed conversions:
|
|
|
|
|
|
|
|
|
|
Stock
options
(1)
|
|
|
869,000
|
|
|
|
511,000
|
|
|
Restricted
stock
|
|
|
1,127,000
|
|
|
|
1,150,000
|
|
|
3.75%
convertible senior
notes
|
|
|
10,173,000
|
|
|
|
—
|
|
|
Weighted
average shares assuming
dilution
|
|
|
339,448,000
|
|
|
|
349,157,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
earnings per share:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
0.36
|
|
|
$
|
0.19
|
|
|
(1)
|
Options
to purchase 2,848,340 and 2,662,903 shares were outstanding for the
three months ended March 31, 2008 and 2009, respectively, but were not
included in the computation of diluted earnings per share because the
options’ exercise price was greater than the average market price of the
common shares for the respective
periods.
|
Substantially all of the
3.75% contingently convertible senior notes provided for settlement of the
principal portion in cash rather than stock.
In accordance with
Emerging Issues Task Force Issue No. 04-8, “Accounting Issues related to Certain
Features of Contingently Convertible Debt and the Effect on Diluted Earnings Per
Share,” the portion of the conversion value of such notes that must be settled
in cash rather than stock is excluded from the computation of diluted earnings
per share from continuing operations. The Company included the conversion spread
in the calculation of diluted earnings per share when the average market price
of the Company’s common stock in the respective reporting period exceeded the
conversion price.
In April 2008,
the Company called its 3.75% convertible senior notes for redemption on
May 30, 2008. Substantially all of the Company’s 3.75% convertible senior
notes were submitted for conversion on or prior to the May 30, 2008 redemption
date.
(14) Reportable
Business Segments
The
Company’s
determination of reportable business segments considers the strategic operating
units under which the Company manages sales, allocates resources and assesses
performance of various products and services to wholesale or retail customers in
differing regulatory environments. The accounting policies of the business
segments are the same as those described in the summary of significant
accounting policies except that some executive benefit costs have not been
allocated to business segments. The Company uses operating income as the measure
of profit or loss for its business segments.
The
Company’s reportable business segments include the following: Electric
Transmission & Distribution, Natural Gas Distribution, Competitive Natural
Gas Sales and Services, Interstate Pipelines, Field Services and Other
Operations. The electric transmission and distribution function (CenterPoint
Houston) is reported in the Electric Transmission & Distribution business
segment. Natural Gas Distribution consists of intrastate natural gas sales to,
and natural gas transportation and distribution for, residential, commercial,
industrial and institutional customers. Competitive Natural Gas Sales and
Services represents the Company’s non-rate regulated gas sales and services
operations, which consist of three operational functions: wholesale, retail and
intrastate pipelines. The Interstate Pipelines business segment includes the
interstate natural gas pipeline operations. The Field Services business segment
includes the natural gas gathering operations. Other Operations consists
primarily of other corporate operations which support all of the Company’s
business operations.
Financial
data for business segments and products and services are as follows (in
millions):
|
|
|
For
the Three Months Ended March 31, 2008
|
|
|
|
|
|
|
|
Revenues
from
External
Customers
|
|
|
Net
Intersegment
Revenues
|
|
|
Operating
Income
|
|
|
Total
Assets
as
of December 31,
2008
|
|
|
Electric
Transmission & Distribution
|
|
$
|
409
|
(1)
|
|
$
|
—
|
|
|
$
|
91
|
|
|
$
|
8,880
|
|
|
Natural
Gas Distribution
|
|
|
1,697
|
|
|
|
3
|
|
|
|
121
|
|
|
|
4,961
|
|
|
Competitive
Natural Gas Sales and Services
|
|
|
1,109
|
|
|
|
11
|
|
|
|
6
|
|
|
|
1,315
|
|
|
Interstate
Pipelines
|
|
|
91
|
|
|
|
42
|
|
|
|
71
|
|
|
|
3,578
|
|
|
Field
Services
|
|
|
54
|
|
|
|
4
|
|
|
|
45
|
|
|
|
826
|
|
|
Other
Operations
|
|
|
3
|
|
|
|
—
|
|
|
|
2
|
|
|
|
2,185
|
(2)
|
|
Eliminations
|
|
|
—
|
|
|
|
(60
|
)
|
|
|
—
|
|
|
|
(2,069
|
)
|
|
Consolidated
|
|
$
|
3,363
|
|
|
$
|
—
|
|
|
$
|
336
|
|
|
$
|
19,676
|
|
|
|
|
For
the Three Months Ended March 31, 2009
|
|
|
|
|
|
|
|
Revenues
from
External
Customers
|
|
|
Net
Intersegment
Revenues
|
|
|
Operating
Income
|
|
|
Total
Assets
as
of March 31,
2009
|
|
|
Electric
Transmission & Distribution
|
|
$
|
412
|
(1)
|
|
$
|
—
|
|
|
$
|
70
|
|
|
$
|
8,836
|
|
|
Natural
Gas Distribution
|
|
|
1,418
|
|
|
|
3
|
|
|
|
118
|
|
|
|
4,344
|
|
|
Competitive
Natural Gas Sales and Services
|
|
|
760
|
|
|
|
5
|
|
|
|
2
|
|
|
|
1,169
|
|
|
Interstate
Pipelines
|
|
|
117
|
|
|
|
36
|
|
|
|
69
|
|
|
|
3,579
|
|
|
Field
Services
|
|
|
56
|
|
|
|
1
|
|
|
|
26
|
|
|
|
829
|
|
|
Other
Operations
|
|
|
3
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,037
|
(2)
|
|
Eliminations
|
|
|
—
|
|
|
|
(45
|
)
|
|
|
—
|
|
|
|
(1,984
|
)
|
|
Consolidated
|
|
$
|
2,766
|
|
|
$
|
—
|
|
|
$
|
285
|
|
|
$
|
18,810
|
|
|
(1)
|
Sales
to subsidiaries of RRI in each of the three months ended March 31,
2008 and 2009 represented approximately $142 million of CenterPoint
Houston’s transmission and distribution
revenues.
|
|
(2)
|
Included
in total assets of Other Operations as of December 31, 2008 and March 31,
2009 are pension related regulatory assets of $800 million and
$786 million, respectively.
|
(15) Subsequent
Event
On
April 23, 2009, the Company’s board of directors declared a regular
quarterly cash dividend of $0.19 per share of common stock payable on
June 10, 2009, to shareholders of record as of the close of business on
May 15, 2009.