PART I
OUR
BUSINESS
Overview
We are a
public utility holding company whose indirect wholly owned subsidiaries
include:
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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 Corp. 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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Our
reportable business segments are Electric Transmission & Distribution,
Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate
Pipelines, Field Services and Other Operations. From time to time, we consider
the acquisition or the disposition of assets or businesses.
Our
principal executive offices are located at 1111 Louisiana, Houston, Texas 77002
(telephone number: 713-207-1111).
We make
available free of charge on our Internet website our annual report on
Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as
reasonably practicable after we electronically file such reports with, or
furnish them to, the Securities and Exchange Commission (SEC). Additionally, we
make available free of charge on our Internet website:
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our
Code of Ethics for our Chief Executive Officer and Senior Financial
Officers;
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our
Ethics and Compliance Code;
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our
Corporate Governance Guidelines;
and
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the
charters of our audit, compensation, finance and governance committees of
the Board of Directors.
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Any
shareholder who so requests may obtain a printed copy of any of these documents
from us. Changes in or waivers of our Code of Ethics for our Chief Executive
Officer and Senior Financial Officers and waivers of our Ethics and Compliance
Code for directors or executive officers will be posted on our Internet website
within five business days of such change or waiver and maintained for at least
12 months or reported on Item 5.05 of Form 8-K. Our website
address is
www.centerpointenergy.com.
Except to the extent explicitly stated herein, documents and information
on our website are not incorporated by reference herein.
Electric
Transmission & Distribution
In 1999,
the Texas legislature adopted the Texas Electric Choice Plan (Texas electric
restructuring law) that led to the restructuring of certain integrated electric
utilities operating within Texas. Pursuant to that legislation, integrated
electric utilities operating within the Electric Reliability Council of Texas,
Inc. (ERCOT) were required to unbundle their integrated operations into separate
retail sales, power generation and transmission and distribution companies. The
legislation also required that the prices for wholesale generation and retail
electric sales be unregulated, but services by companies providing transmission
and distribution service, such as CenterPoint Houston, would
continue
to be regulated by the Public Utility Commission of Texas (Texas Utility
Commission). The legislation provided for a transition period to move to the new
market structure and provided a true-up mechanism for the formerly integrated
electric utilities to recover stranded and certain other costs resulting from
the transition to competition. Those costs are recoverable after approval by the
Texas Utility Commission either through the issuance of securitization bonds or
through the implementation of a competition transition charge (CTC) as a rider
to the utility’s tariff.
CenterPoint
Houston is the only business of CenterPoint Energy that continues to engage in
electric utility operations. It is a transmission and distribution electric
utility that operates wholly within the state of Texas. Neither CenterPoint
Houston nor any other subsidiary of CenterPoint Energy makes sales of electric
energy at retail or wholesale, or owns or operates any electric generating
facilities.
Electric
Transmission
On behalf
of retail electric providers (REPs), CenterPoint Houston delivers electricity
from power plants to substations, from one substation to another and to retail
electric customers taking power at or above 69 kilovolts (kV) in locations
throughout CenterPoint Houston’s certificated service territory. CenterPoint
Houston provides transmission services under tariffs approved by the Texas
Utility Commission.
Electric
Distribution
In ERCOT,
end users purchase their electricity directly from certificated REPs.
CenterPoint Houston delivers electricity for REPs in its certificated service
area by carrying lower-voltage power from the substation to the retail electric
customer. CenterPoint Houston’s distribution network receives electricity from
the transmission grid through power distribution substations and delivers
electricity to end users through distribution feeders. CenterPoint Houston’s
operations include construction and maintenance of electric transmission and
distribution facilities, metering services, outage response services and call
center operations. CenterPoint Houston provides distribution services under
tariffs approved by the Texas Utility Commission. Texas Utility Commission rules
and market protocols govern the commercial operations of distribution companies
and other market participants. Rates for these existing services are established
pursuant to rate proceedings conducted before municipalities that have original
jurisdiction and the Texas Utility Commission.
ERCOT
Market Framework
CenterPoint
Houston is a member of ERCOT. ERCOT serves as the regional reliability
coordinating council for member electric power systems in Texas. ERCOT
membership is open to consumer groups, investor and municipally-owned electric
utilities, rural electric cooperatives, independent generators, power marketers
and REPs. The ERCOT market includes most of the State of Texas, other than a
portion of the panhandle, portions of the eastern part of the state bordering
Louisiana and the area in and around El Paso. The ERCOT market represents
approximately 85% of the demand for power in Texas and is one of the nation’s
largest power markets. The ERCOT market includes an aggregate net generating
capacity of approximately 73,000 megawatts (MW). There are only limited direct
current interconnections between the ERCOT market and other power markets in the
United States and Mexico.
The ERCOT
market operates under the reliability standards set by the North American
Electric Reliability Council (NERC) and approved by the Federal Energy
Regulatory Commission (FERC). These reliability standards are administered by
the Texas Regional Entity (TRE), a functionally independent division of ERCOT.
The Texas Utility Commission has primary jurisdiction over the ERCOT market to
ensure the adequacy and reliability of electricity supply across the state’s
main interconnected power transmission grid. The ERCOT independent system
operator (ERCOT ISO) is responsible for operating the bulk electric power supply
system in the ERCOT market. Its responsibilities include ensuring that
electricity production and delivery are accurately accounted for among the
generation resources and wholesale buyers and sellers. Unlike certain other
regional power markets, the ERCOT market is not a centrally dispatched power
pool, and the ERCOT ISO does not procure energy on behalf of its members other
than to maintain the reliable operations of the transmission system. Members who
sell and purchase power are responsible for contracting sales and purchases of
power bilaterally. The ERCOT ISO also serves as agent for procuring ancillary
services for those members who elect not to provide their own ancillary
services.
CenterPoint
Houston’s electric transmission business, along with those of other owners of
transmission facilities in Texas, supports the operation of the ERCOT ISO. The
transmission business has planning, design, construction, operation and
maintenance responsibility for the portion of the transmission grid and for the
load-serving substations it owns, primarily within its certificated area.
CenterPoint Houston participates with the ERCOT ISO and other ERCOT utilities to
plan, design, obtain regulatory approval for and construct new transmission
lines necessary to increase bulk power transfer capability and to remove
existing constraints on the ERCOT transmission grid.
Recovery
of True-Up Balance
The Texas
electric restructuring law substantially amended the regulatory structure
governing electric utilities in order to allow retail competition for electric
customers beginning in January 2002. The Texas electric restructuring law
required the Texas Utility Commission to conduct a “true-up” proceeding to
determine CenterPoint Houston’s stranded costs and certain other costs resulting
from the transition to a competitive retail electric market and to provide for
its recovery of those costs.
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 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 REPs;
and
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affirmed
the True-Up Order in all other
respects.
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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 the
second quarter of 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 we 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, we 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, we 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 our 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, we anticipate that we 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. We
believe 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, we 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 us 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 our
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. We 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 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. 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 our or CenterPoint Houston’s financial
condition, results of operations or cash flows.
During
the years ended December 31, 2006, 2007 and 2008, CenterPoint Houston
recognized approximately $55 million, $42 million and $5 million,
respectively, in operating income from the CTC. Additionally, during the years
ended December 31, 2006, 2007 and 2008, CenterPoint Houston recognized
approximately $13 million, $14 million and $13 million,
respectively, of the allowed equity return not previously recognized. As of
December 31, 2008, we have not recognized an allowed equity return of
$207 million on CenterPoint Houston’s true-up balance because such return
will be recognized as it is recovered in rates.
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.
Hurricane
Ike
CenterPoint
Houston’s electric delivery system suffered substantial damage as a result of
Hurricane Ike, which struck the upper Texas coast early Saturday,
September 13, 2008.
The
strong Category 2 storm initially left more than 90% of CenterPoint Houston’s
more than 2 million metered customers without power, the largest outage in
CenterPoint Houston’s 130-year history. Most of the widespread power outages
were due to power lines damaged by downed trees and debris blown by Hurricane
Ike’s winds. In addition, on Galveston Island and along the coastal areas of the
Gulf of Mexico and Galveston Bay, the storm surge and flooding from rains
accompanying the storm caused significant damage or destruction of houses and
businesses served by CenterPoint Houston.
CenterPoint
Houston estimates that total costs to restore the electric delivery facilities
damaged as a result of Hurricane Ike will be in the range of $600 million
to $650 million. 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.
In
addition to storm restoration costs, CenterPoint Houston lost approximately
$17 million in revenue through December 31, 2008. Within the first 18
days after the storm, CenterPoint Houston had restored power to all customers
capable of receiving it.
CenterPoint
Houston has deferred the uninsured storm restoration costs as management
believes it is probable that such costs will be recovered through the regulatory
process. As a result, storm restoration costs did not affect our or CenterPoint
Houston’s reported net income for 2008. As of December 31, 2008,
CenterPoint Houston recorded an increase of $145 million in construction
work in progress and $435 million in regulatory assets for restoration
costs incurred through December 31, 2008. Approximately $73 million of
these costs are based on estimates and are included in accounts payable as of
December 31, 2008. Additional restoration costs will continue to be
incurred in 2009.
Assuming
necessary enabling legislation is enacted by the Texas Legislature in the
session that began in January 2009, CenterPoint Houston expects to seek a
financing order from the Texas Utility Commission to obtain recovery of its
storm restoration costs through the issuance of non-recourse securitization
bonds similar to the storm recovery bonds issued by another Texas utility
following the hurricanes that affected that utility’s service territories in
2005. Assuming those bonds are issued, CenterPoint Houston will recover the
amount of storm restoration costs determined by the Texas Utility Commission to
have been prudently incurred out of the bond proceeds, with the bonds being
repaid over time through a charge imposed on customers. Alternatively, if
securitization is not available, recovery of those costs would be sought through
traditional regulatory mechanisms. Under its 2006 rate case settlement,
CenterPoint Houston is entitled to seek an adjustment to rates in this
situation, even though in most instances its rates are frozen until
2010.
Customers
CenterPoint
Houston serves nearly all of the Houston/Galveston metropolitan area.
CenterPoint Houston’s customers consist of 79 REPs, which sell electricity to
over 2 million metered customers in CenterPoint Houston’s certificated
service area, and municipalities, electric cooperatives and other distribution
companies located outside CenterPoint Houston’s certificated service area. Each
REP is licensed by, and must meet minimal creditworthiness criteria established
by, the Texas Utility Commission. Two of the REPs in CenterPoint Houston’s
service area are subsidiaries of RRI. Sales to subsidiaries of RRI represented
approximately 56%, 51% and 48% of CenterPoint Houston’s transmission and
distribution revenues in 2006, 2007 and 2008, respectively. CenterPoint
Houston’s billed receivables balance from REPs as of December 31, 2008 was
$141 million. Approximately 46% of this amount was owed by subsidiaries of
RRI. CenterPoint Houston does not have long-term contracts with any of its
customers. It operates on a continuous billing cycle, with meter readings being
conducted and invoices being distributed to REPs each business day.
Advanced
Metering System and Distribution Automation (Intelligent Grid)
In
December 2008, CenterPoint Houston received approval from the Texas Utility
Commission to deploy an advanced metering system (AMS) across its service
territory over the next five years. CenterPoint Houston plans to begin
installing advanced meters in March 2009. This innovative technology should
encourage greater energy conservation by giving Houston-area electric consumers
the ability to better monitor and manage their electric use and its cost in near
real time. CenterPoint Houston will recover the cost for the AMS through a
monthly surcharge to all REPs over 12 years. The surcharge for each residential
consumer for the first 24 months, beginning in February 2009, will be $3.24 per
month; thereafter, the surcharge is scheduled to be reduced to $3.05 per month.
These amounts are subject to upward or downward adjustment in future proceedings
to reflect actual costs incurred and to address required changes in scope.
CenterPoint Houston projects capital expenditures of approximately
$640 million for the installation of the advanced meters and corresponding
communication and data management systems over the five-year deployment
period.
CenterPoint
Houston is also pursuing possible deployment of an electric distribution grid
automation strategy that involves the implementation of an “Intelligent Grid”
which would make use of CenterPoint Houston’s facilities to provide on-demand
data and information about the status of facilities on its system. Although this
technology is still in the developmental stage, CenterPoint Houston believes it
has the potential to provide a significant improvement in grid planning,
operations and maintenance of the CenterPoint Houston distribution system. These
improvements would be expected to contribute to fewer and shorter outages,
better customer service, improved operations costs, improved security and more
effective use of our workforce. Texas Utility Commission approval and
appropriate rate treatment would be sought in connection with any actual
deployment of this technology.
Competition
There are
no other electric transmission and distribution utilities in CenterPoint
Houston’s service area. In order for another provider of transmission and
distribution services to provide such services in CenterPoint Houston’s
territory, it would be required to obtain a certificate of convenience and
necessity from the Texas Utility Commission and, depending on the location of
the facilities, may also be required to obtain franchises from one or more
municipalities. We know of no other party intending to enter this business in
CenterPoint Houston’s service area at this time.
Seasonality
A
significant portion of CenterPoint Houston’s revenues is derived from rates that
it collects from each REP based on the amount of electricity it delivers on
behalf of such REP. Thus, CenterPoint Houston’s revenues and results of
operations are subject to seasonality, weather conditions and other changes in
electricity usage, with revenues being higher during the warmer
months.
Properties
All of
CenterPoint Houston’s properties are located in Texas. Its properties consist
primarily of high voltage electric transmission lines and poles, distribution
lines, substations, service wires and meters. Most of CenterPoint
Houston’s
transmission and distribution lines have been constructed over lands of others
pursuant to easements or along public highways and streets as permitted by
law.
All real
and tangible properties of CenterPoint Houston, subject to certain exclusions,
are currently subject to:
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the
lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1,
1944, as supplemented; and
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the
lien of a General Mortgage (the General Mortgage) dated October 10,
2002, as supplemented, which is junior to the lien of the
Mortgage.
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As of
December 31, 2008, CenterPoint Houston had outstanding approximately
$2.6 billion aggregate principal amount of general mortgage bonds under the
General Mortgage, including approximately $527 million held in trust to
secure pollution control bonds for which CenterPoint Energy is obligated,
$600 million securing borrowings under a credit facility which was
unutilized and approximately $229 million held in trust to secure pollution
control bonds for which CenterPoint Houston is obligated. Additionally,
CenterPoint Houston had outstanding approximately $253 million aggregate
principal amount of first mortgage bonds under the Mortgage, including
approximately $151 million held in trust to secure certain pollution
control bonds for which CenterPoint Energy is obligated. CenterPoint Houston may
issue additional general mortgage bonds on the basis of retired bonds, 70% of
property additions or cash deposited with the trustee. Approximately
$1.8 billion of additional first mortgage bonds and general mortgage bonds
in the aggregate could be issued on the basis of retired bonds and 70% of
property additions as of December 31, 2008. However, CenterPoint Houston
has contractually agreed that it will not issue additional first mortgage bonds,
subject to certain exceptions. In January 2009, CenterPoint Houston issued
$500 million aggregate principal amount of general mortgage bonds in a
public offering.
Electric Lines —
Overhead.
As of December 31, 2008, CenterPoint Houston
owned 27,603 pole miles of overhead distribution lines and 3,727 circuit miles
of overhead transmission lines, including 423 circuit miles operated at 69,000
volts, 2,088 circuit miles operated at 138,000 volts and 1,216 circuit miles
operated at 345,000 volts.
Electric Lines —
Underground.
As of December 31, 2008, CenterPoint Houston
owned 19,690 circuit miles of underground distribution lines and 26 circuit
miles of underground transmission lines, including 2 circuit miles operated at
69,000 volts and 24 circuit miles operated at 138,000 volts.
Substations.
As of December 31, 2008, CenterPoint Houston
owned 229 major substation sites having a total installed rated transformer
capacity of 51,400 megavolt amperes.
Service
Centers.
CenterPoint Houston operates 14 regional service
centers located on a total of 291 acres of land. These service centers
consist of office buildings, warehouses and repair facilities that are used in
the business of transmitting and distributing electricity.
Franchises
CenterPoint
Houston holds non-exclusive franchises from the incorporated municipalities in
its service territory. In exchange for the payment of fees, these franchises
give CenterPoint Houston the right to use the streets and public rights-of way
of these municipalities to construct, operate and maintain its transmission and
distribution system and to use that system to conduct its electric delivery
business and for other purposes that the franchises permit. The terms of the
franchises, with various expiration dates, typically range from 30 to
50 years.
Natural
Gas Distribution
CERC
Corp.’s natural gas distribution business (Gas Operations) engages in regulated
intrastate natural gas sales to, and natural gas transportation for,
approximately 3.2 million residential, commercial and industrial customers
in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. The largest
metropolitan areas served in each state by Gas Operations are Houston, Texas;
Minneapolis, Minnesota; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi,
Mississippi; and Lawton, Oklahoma. In 2008, approximately 43% of Gas Operations’
total throughput was to residential customers and approximately 57% was to
commercial and industrial customers.
Gas
Operations also provides unregulated services consisting of heating, ventilating
and air conditioning (HVAC) equipment and appliance repair, and sales of HVAC,
hearth and water heating equipment in Minnesota.
The
demand for intrastate natural gas sales to, and natural gas transportation for,
residential, commercial and industrial customers is seasonal. In 2008,
approximately 71% of the total throughput of Gas Operations’ business occurred
in the first and fourth quarters. These patterns reflect the higher demand for
natural gas for heating purposes during those periods.
Gas
Operations also suffered some damage to its system in Houston, Texas and in
other portions of its service territory across Texas and Louisiana as a result
of Hurricane Ike. As of December 31, 2008, Gas Operations has deferred
approximately $4 million of costs related to Hurricane Ike for recovery as
part of future natural gas distribution rate proceedings.
Supply and
Transportation.
In 2008, Gas Operations purchased virtually
all of its natural gas supply pursuant to contracts with remaining terms varying
from a few months to four years. Major suppliers in 2008 included BP Canada
Energy Marketing Corp. (13.4% of supply volumes), Tenaska Marketing Ventures
(11.5%), Oneok Energy Marketing (10.2%), Coral Energy Resources (6.6%) and
Cargill, Inc. (5.8%). Numerous other suppliers provided the remaining 52.5% of
Gas Operations’ natural gas supply requirements. Gas Operations transports its
natural gas supplies through various intrastate and interstate pipelines,
including those owned by our other subsidiaries, under contracts with remaining
terms, including extensions, varying from one to fifteen years. Gas Operations
anticipates that these gas supply and transportation contracts will be renewed
or replaced prior to their expiration.
We
actively engage in commodity price stabilization pursuant to annual gas supply
plans presented to and/or filed with each of our state regulatory authorities.
These price stabilization activities include use of storage gas, contractually
establishing fixed prices with our physical gas suppliers and utilizing
financial derivative instruments to achieve a variety of pricing structures
(e.g., fixed price, costless collars and caps). Our gas supply plans generally
call for 25-50% of winter supplies to be hedged in some fashion.
Generally,
the regulations of the states in which Gas Operations operates allow it to pass
through changes in the cost of natural gas, including gains and losses on
financial derivatives associated with the index-priced physical supply, to its
customers under purchased gas adjustment provisions in its tariffs. Depending
upon the jurisdiction, the purchased gas adjustment factors are updated
periodically, ranging from monthly to semi-annually, using estimated gas costs.
The changes in the cost of gas billed to customers are subject to review by the
applicable regulatory bodies.
Gas
Operations uses various third-party storage services or owned natural gas
storage facilities to meet peak-day requirements and to manage the daily changes
in demand due to changes in weather and may also supplement contracted supplies
and storage from time to time with stored liquefied natural gas and propane-air
plant production.
Gas
Operations owns and operates an underground natural gas storage facility with a
capacity of 7.0 billion cubic feet (Bcf). It has a working capacity of 2.0
Bcf available for use during a normal heating season and a maximum daily
withdrawal rate of 50 million cubic feet (MMcf). It also owns nine
propane-air plants with a total production rate of 200 MMcf per day and
on-site storage facilities for 12 million gallons of propane (1.0 Bcf
natural gas equivalent). It owns liquefied natural gas plant facilities with a
12 million-gallon liquefied natural gas storage tank (1.0 Bcf natural
gas equivalent) and a production rate of 72 MMcf per day.
On an
ongoing basis, Gas Operations enters into contracts to provide sufficient
supplies and pipeline capacity to meet its customer requirements. However, it is
possible for limited service disruptions to occur from time to time due to
weather conditions, transportation constraints and other events. As a result of
these factors, supplies of natural gas may become unavailable from time to time,
or prices may increase rapidly in response to temporary supply constraints or
other factors.
Assets
As of
December 31, 2008, Gas Operations owned approximately 70,000 linear miles
of natural gas distribution mains, varying in size from one-half inch to
24 inches in diameter. Generally, in each of the cities, towns and
rural
areas
served by Gas Operations, it owns the underground gas mains and service lines,
metering and regulating equipment located on customers’ premises and the
district regulating equipment necessary for pressure maintenance. With a few
exceptions, the measuring stations at which Gas Operations receives gas are
owned, operated and maintained by others, and its distribution facilities begin
at the outlet of the measuring equipment. These facilities, including odorizing
equipment, are usually located on the land owned by
suppliers.
Competition
Gas
Operations competes primarily with alternate energy sources such as electricity
and other fuel sources. In some areas, intrastate pipelines, other gas
distributors and marketers also compete directly for gas sales to end-users. In
addition, as a result of federal regulations affecting interstate pipelines,
natural gas marketers operating on these pipelines may be able to bypass Gas
Operations’ facilities and market and sell and/or transport natural gas directly
to commercial and industrial customers.
Competitive
Natural Gas Sales and Services
CERC
offers variable and fixed-priced physical natural gas supplies primarily to
commercial and industrial customers and electric and gas utilities through
CenterPoint Energy Services, Inc. (CES) and its subsidiary, CenterPoint Energy
Intrastate Pipelines, LLC (CEIP).
In 2008,
CES marketed approximately 528 Bcf of natural gas, transportation and
related energy services to approximately 9,700 customers (including
approximately 9 Bcf to affiliates). CES customers vary in size from small
commercial customers to large utility companies in the central and eastern
regions of the United States, and are served from offices located in Arkansas,
Illinois, Indiana, Louisiana, Minnesota, Missouri, Pennsylvania, Texas and
Wisconsin. The business has three operational functions: wholesale, retail and
intrastate pipelines, which are further described below.
Wholesale
Operations.
CES offers a portfolio of physical delivery
services and financial products designed to meet wholesale customers’ supply and
price risk management needs. These customers are served directly through
interconnects with various inter- and intra-state pipeline companies, and
include gas utilities, large industrial customers and electric generation
customers.
Retail
Operations.
CES offers a variety of natural gas management
services to smaller commercial and industrial customers, municipalities,
educational institutions and hospitals, whose facilities are located downstream
of natural gas distribution utility city gate stations. These services include
load forecasting, supply acquisition, daily swing volume management, invoice
consolidation, storage asset management, firm and interruptible transportation
administration and forward price management. CES manages transportation
contracts and energy supply for retail customers in sixteen states.
Intrastate Pipeline
Operations.
CEIP primarily provides transportation services to
shippers and end-users and contracts out approximately 2.3 Bcf of storage at its
Pierce Junction facility in Texas.
CES
currently transports natural gas on over 32 interstate and intrastate pipelines
within states located throughout the central and eastern United States. CES
maintains a portfolio of natural gas supply contracts and firm transportation
and storage agreements to meet the natural gas requirements of its customers.
CES aggregates supply from various producing regions and offers contracts to buy
natural gas with terms ranging from one month to over five years. In addition,
CES actively participates in the spot natural gas markets in an effort to
balance daily and monthly purchases and sales obligations. Natural gas supply
and transportation capabilities are leveraged through contracts for ancillary
services including physical storage and other balancing
arrangements.
As
described above, CES offers its customers a variety of load following services.
In providing these services, CES uses its customers’ purchase commitments to
forecast and arrange its own supply purchases, storage and
transportation
services to serve customers’ natural gas requirements. As a result of the
variance between this forecast activity and the actual monthly activity, CES
will either have too much supply or too little supply relative to its customers’
purchase commitments. These supply imbalances arise each month as customers’
natural gas requirements are scheduled and corresponding natural gas supplies
are nominated by CES for delivery to those
customers.
CES’ processes and risk control environment are designed to measure and value
imbalances on a real-time basis to ensure that CES’ exposure to commodity price
risk is kept to a minimum. The value assigned to these imbalances is calculated
daily and is known as the aggregate Value at Risk (VaR). In 2008, CES’ VaR
averaged $1.5 million with a high of $2.8 million.
The
CenterPoint Energy risk control policy, governed by our Risk Oversight
Committee, defines authorized and prohibited trading instruments and trading
limits. CES is a physical marketer of natural gas and uses a variety of tools,
including pipeline and storage capacity, financial instruments and physical
commodity purchase contracts to support its sales. The CES business optimizes
its use of these various tools to minimize its supply costs and does not engage
in proprietary or speculative commodity trading. The VaR limits within which CES
operates are consistent with its operational objective of matching its aggregate
sales obligations (including the swing associated with load following services)
with its supply portfolio in a manner that minimizes its total cost of
supply.
Assets
CEIP owns
and operates approximately 227 miles of intrastate pipeline in Louisiana
and Texas and holds storage facilities of approximately 2.3 Bcf in Texas
under long-term leases. In addition, CES leases transportation capacity of
approximately 1.1 Bcf per day on various inter- and intrastate pipelines
and approximately 8.8 Bcf of storage to service its customer
base.
Competition
CES
competes with regional and national wholesale and retail gas marketers including
the marketing divisions of natural gas producers and utilities. In addition, CES
competes with intrastate pipelines for customers and services in its market
areas.
Interstate
Pipelines
CERC’s
pipelines business operates interstate natural gas pipelines with gas
transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri,
Oklahoma and Texas. CERC’s interstate pipeline operations are primarily
conducted by two wholly owned subsidiaries that provide gas transportation and
storage services primarily to industrial customers and local distribution
companies:
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CenterPoint
Energy Gas Transmission Company (CEGT) is an interstate pipeline that
provides natural gas transportation, natural gas storage and pipeline
services to customers principally in Arkansas, Louisiana, Oklahoma and
Texas; and
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CenterPoint
Energy-Mississippi River Transmission Corporation (MRT) is an interstate
pipeline that provides natural gas transportation, natural gas storage and
pipeline services to customers principally in Arkansas and
Missouri.
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The rates
charged by CEGT and MRT for interstate transportation and storage services are
regulated by the FERC. Our interstate pipelines business operations may be
affected by changes in the demand for natural gas, the available supply and
relative price of natural gas in the Mid-continent and Gulf Coast natural gas
supply regions and general economic conditions.
In 2008,
approximately 15% of CEGT and MRT’s total operating revenue was attributable to
services provided to Gas Operations, an affiliate, and approximately 7% was
attributable to services provided to Laclede Gas Company (Laclede), an
unaffiliated distribution company, that provides natural gas utility service to
the greater St. Louis metropolitan area in Illinois and Missouri. Services to
Gas Operations and Laclede are provided under several long-term firm storage and
transportation agreements. Effective April 1, 2008, MRT signed a 5-year
extension of its firm transportation and storage contracts with Laclede.
Agreements for firm transportation, “no notice” transportation
service
and storage services in certain of Gas Operations’ service areas (Arkansas,
Louisiana, Oklahoma and Texas) will expire in 2012.
Carthage to
Perryville.
In April 2008, CEGT completed the Phase III
expansion of the Carthage to Perryville pipeline. This expansion included
additional compression and authorization from the Pipeline and Hazardous
Materials Safety Administration (PHMSA) to operate the line at higher pressures.
The Carthage to Perryville pipeline can now operate at up to 1.5 Bcf per day.
CEGT filed with FERC on December 5, 2008 to increase the Carthage to Perryville
capacity to approximately 1.9 Bcf per day. The expansion includes a new
compressor unit at two of CEGT’s existing stations and is currently projected to
be placed in service in the second quarter of 2010.
Southeast Supply
Header.
The Southeast Supply Header (SESH) pipeline project, a
joint venture between CEGT and Spectra Energy Corp., was placed into commercial
service on September 6, 2008. This new 270-mile pipeline, which extends from the
Perryville Hub, near Perryville, Louisiana, to an interconnection with the Gulf
Stream Natural Gas System near Mobile, Alabama, has a maximum design capacity of
approximately one Bcf per day. The pipeline represents a new source of natural
gas supply for the Southeast United States and offers greater supply diversity
to this region. Our share of SESH’s net construction costs is approximately
$625 million.
Assets
Our
interstate pipelines business currently owns and operates approximately 8,000
miles of natural gas transmission lines primarily located in Arkansas, Illinois,
Louisiana, Missouri, Oklahoma and Texas. We also own and operate six natural gas
storage fields with a combined daily deliverability of approximately
1.2 Bcf and a combined working gas capacity of approximately 59 Bcf. We
also own a 10% interest in the Bistineau storage facility located in Bienville
Parish, Louisiana, with the remaining interest owned and operated by Gulf South
Pipeline Company, LP. Our storage capacity in the Bistineau facility is
8 Bcf of working gas with 100 MMcf per day of deliverability. Most
storage operations are in north Louisiana and Oklahoma.
Competition
Our
interstate pipelines business competes with other interstate and intrastate
pipelines in the transportation and storage of natural gas. The principal
elements of competition among pipelines are rates, terms of service, and
flexibility and reliability of service. Our interstate pipelines business
competes indirectly with other forms of energy, including electricity, coal and
fuel oils. The primary competitive factor is price. Changes in the availability
of energy and pipeline capacity, the level of business activity, conservation
and governmental regulations, the capability to convert to alternative fuels,
and other factors, including weather, affect the demand for natural gas in areas
we serve and the level of competition for transportation and storage
services.
Field
Services
CERC’s
field services business operates gas gathering, treating, and processing
facilities and also provides operating and technical services and remote data
monitoring and communication services.
CERC’s
field services operations are conducted by a wholly owned subsidiary,
CenterPoint Energy Field Services, Inc. (CEFS). CEFS provides natural gas
gathering and processing services for certain natural gas fields in the
Mid-continent region of the United States that interconnect with CEGT’s and
MRT’s pipelines, as well as other interstate and intrastate pipelines. CEFS
gathers approximately 1.3 Bcf per day of natural gas and, either directly or
through its 50% interest in a joint venture, processes in excess of
240 MMcf per day of natural gas along its gathering system. CEFS, through
its ServiceStar operating division, provides remote data monitoring and
communications services to affiliates and third parties.
Our field
services business operations may be affected by changes in the demand for
natural gas and natural gas liquids (NGLs), the available supply and relative
price of natural gas and NGLs in the Mid-continent and Gulf Coast natural gas
supply regions and general economic conditions.
Assets
Our field
services business owns and operates approximately 3,600 miles of gathering
pipelines and processing plants that collect, treat and process natural gas from
approximately 150 separate systems located in major producing fields in
Arkansas, Louisiana, Oklahoma and Texas.
Competition
Our field
services business competes with other companies in the natural gas gathering,
treating, and processing business. The principal elements of competition are
rates, terms of service and reliability of services. Our field services business
competes indirectly with other forms of energy, including electricity, coal and
fuel oils. The primary competitive factor is price. Changes in the availability
of energy and pipeline capacity, the level of business activity, conservation
and governmental regulations, the capability to convert to alternative fuels,
and other factors, including weather, affect the demand for natural gas in areas
we serve and the level of competition for gathering, treating, and processing
services. In addition, competition among forms of energy is impacted by
commodity pricing levels and influences the level of drilling activity and
demand for our gathering operations.
Other
Operations
Our Other
Operations business segment includes office buildings and other real estate used
in our business operations and other corporate operations that support all of
our business operations.
Financial
Information About Segments
For
financial information about our segments, see Note 14 to our consolidated
financial statements, which note is incorporated herein by
reference.
REGULATION
We are
subject to regulation by various federal, state and local governmental agencies,
including the regulations described below.
Federal
Energy Regulatory Commission
The FERC
has jurisdiction under the Natural Gas Act and the Natural Gas Policy Act of
1978, as amended, to regulate the transportation of natural gas in interstate
commerce and natural gas sales for resale in intrastate commerce that are not
first sales. The FERC regulates, among other things, the construction of
pipeline and related facilities used in the transportation and storage of
natural gas in interstate commerce, including the extension, expansion or
abandonment of these facilities. The rates charged by interstate pipelines for
interstate transportation and storage services are also regulated by the FERC.
The Energy Policy Act of 2005 (Energy Act) expanded the FERC’s authority to
prohibit market manipulation in connection with FERC-regulated transactions and
gave the FERC additional authority to impose significant civil and criminal
penalties for statutory violations and violations of the FERC’s rules or orders
and also expanded criminal penalties for such violations. Our competitive
natural gas sales and services subsidiary markets natural gas in interstate
commerce pursuant to blanket authority granted by the FERC.
Our
natural gas pipeline subsidiaries may periodically file applications with the
FERC for changes in their generally available maximum rates and charges designed
to allow them to recover their costs of providing service to customers (to the
extent allowed by prevailing market conditions), including a reasonable rate of
return. These rates are normally allowed to become effective after a suspension
period and, in some cases, are subject to refund under applicable law until such
time as the FERC issues an order on the allowable level of rates.
CenterPoint
Houston is not a “public utility” under the Federal Power Act and, therefore, is
not generally regulated by the FERC, although certain of its transactions are
subject to limited FERC jurisdiction. The Energy Act conferred new jurisdiction
and responsibilities on the FERC with respect to ensuring the reliability of
electric transmission service, including transmission facilities owned by
CenterPoint Houston and other utilities within ERCOT. Under this authority, the
FERC has designated the NERC as the Electric Reliability Organization (ERO) to
promulgate
standards, under FERC oversight, for all owners, operators and users of the bulk
power system (Electric Entities). The ERO and the FERC have authority to impose
fines and other sanctions on Electric Entities that fail to comply with the
standards. The FERC has approved the delegation by the NERC of authority for
reliability in ERCOT to the TRE. CenterPoint Houston does not anticipate that
the reliability standards proposed by the NERC and approved by the FERC will
have a material adverse impact on its operations. To the extent that CenterPoint
Houston
is required to make additional expenditures to comply with these standards, it
is anticipated that CenterPoint Houston will seek to recover those costs through
the transmission charges that are imposed on all distribution service providers
within ERCOT for electric transmission provided.
Under the
Public Utility Holding Company Act of 2005 (PUHCA 2005), the FERC has authority
to require holding companies and their subsidiaries to maintain certain books
and records and make them available for review by the FERC and state regulatory
authorities in certain circumstances. In December 2005, the FERC issued
rules implementing PUHCA 2005. Pursuant to those rules, in June 2006, we filed
with the FERC the required notification of our status as a public utility
holding company. In October 2006, the FERC adopted additional rules regarding
maintenance of books and records by utility holding companies and additional
reporting and accounting requirements for centralized service companies that
make allocations to public utilities regulated by the FERC under the Federal
Power Act. Although we provide services to our subsidiaries through a service
company, our service company is not subject to the FERC’s service company
rules.
State
and Local Regulation
Electric
Transmission & Distribution
CenterPoint
Houston conducts its operations pursuant to a certificate of convenience and
necessity issued by the Texas Utility Commission that covers its present service
area and facilities. The Texas Utility Commission and those municipalities that
have retained original jurisdiction have the authority to set the rates and
terms of service provided by CenterPoint Houston under cost of service rate
regulation. CenterPoint Houston holds non-exclusive franchises from the
incorporated municipalities in its service territory. In exchange for payment of
fees, these franchises give CenterPoint Houston the right to use the streets and
public rights-of-way of these municipalities to construct, operate and maintain
its transmission and distribution system and to use that system to conduct its
electric delivery business and for other purposes that the franchises permit.
The terms of the franchises, with various expiration dates, typically range from
30 to 50 years.
CenterPoint
Houston’s distribution rates charged to REPs for residential customers are based
on amounts of energy delivered, whereas distribution rates for a majority of
commercial and industrial customers are based on peak demand. All REPs in
CenterPoint Houston’s service area pay the same rates and other charges for the
same transmission and distribution services. Transmission rates charged to other
distribution companies are based on amounts of energy transmitted under “postage
stamp” rates that do not vary with the distance the energy is being transmitted.
All distribution companies in ERCOT pay CenterPoint Houston the same rates and
other charges for transmission services. This regulated delivery charge includes
the transmission and distribution rate (which includes municipal franchise
fees), a system benefit fund fee imposed by the Texas electric restructuring
law, a nuclear decommissioning charge associated with decommissioning the South
Texas nuclear generating facility and transition charges associated with
securitization of regulatory assets and securitization of stranded
costs.
Recovery of True-Up
Balance.
For a discussion of CenterPoint Houston’s true-up
proceedings, see “— Our Business — Electric Transmission & Distribution —
Recovery of True-Up Balance” above.
CenterPoint Houston Interim
Transmission Costs of Service Update.
In September 2008,
CenterPoint Houston filed an application with the Texas Utility Commission
requesting an interim update to its wholesale transmission rate. The filing
resulted in a revenue requirement increase of $22.5 million over rates then
in effect. Approximately 74% will be paid by distribution companies other than
CenterPoint Houston. The remaining 26% represents CenterPoint Houston’s share.
That amount cannot be included in rates until 2010 under the terms of the rate
freeze implemented in the settlement of CenterPoint Houston’s 2006 rate
proceeding described below. In November 2008, the Texas Utility Commission
approved CenterPoint Houston’s request. The interim rates became effective for
service on and after November 5, 2008.
CenterPoint Houston Rate
Agreement
. CenterPoint Houston’s transmission and distribution
rates are subject to the terms of a Settlement Agreement effective in October
2006. The Settlement Agreement provides that until June 30, 2010
CenterPoint Houston will not seek to increase its base rates and the other
parties will not petition to decrease those rates. The rate freeze is subject to
adjustment for certain limited matters, including the results of the appeals of
the True-Up Order, the implementation of charges associated with
securitizations, the impact of severe
weather
such as hurricanes and certain other force majeure events. CenterPoint Houston
must make a new base rate filing not later than June 30, 2010, based on a test
year ended December 31, 2009, unless the staff of the Texas Utility
Commission and certain cities notify it that such a filing is
unnecessary.
Natural
Gas Distribution
In almost
all communities in which Gas Operations provides natural gas distribution
services, it operates under franchises, certificates or licenses obtained from
state and local authorities. The original terms of the franchises, with various
expiration dates, typically range from 10 to 30 years, although franchises
in Arkansas are perpetual. Gas Operations expects to be able to renew expiring
franchises. In most cases, franchises to provide natural gas utility services
are not exclusive.
Substantially
all of Gas Operations is subject to cost-of-service regulation by the relevant
state public utility commissions and, in Texas, by the Railroad Commission of
Texas (Railroad Commission) and those municipalities Gas Operations serves that
have retained original jurisdiction.
In March
2008, Gas Operations filed a request to change its rates with the 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 have filed second motions for rehearing on this order.
However, in December 2008, Gas Operations implemented the approved rates
for the nine TCUC cities and the environs, subject to refund. The impact of the
Railroad Commission’s order on rehearing on the settled rates is still under
review, and how rates will be conformed among all cities in the Texas Coast
service territory is unknown at this time. A final decision from the Railroad
Commission regarding the second motions for rehearing is expected no later than
March 2009.
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 our
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. The MPUC is allowed ten months to issue a final
decision; however, an extension of time can occur in certain
circumstances.
Department
of Transportation
In
December 2006, Congress enacted the Pipeline Inspection, Protection,
Enforcement and Safety Act of 2006 (2006 Act), which reauthorized the programs
adopted under the Pipeline Safety Improvement Act of 2002 (2002 Act). These
programs included several requirements related to ensuring pipeline safety, and
a requirement to assess the integrity of pipeline transmission facilities in
areas of high population concentration. Under the legislation, remediation
activities are to be performed over a 10-year period. Our pipeline subsidiaries
are on schedule to comply with the timeframe mandated for completion of
integrity assessment and remediation.
Pursuant
to the 2002 Act, and then the 2006 Act, the Pipeline and Hazardous Materials
Safety Administration (PHMSA) of the U.S. Department of Transportation (DOT) has
adopted a number of rules concerning, among other things, distinguishing between
gathering lines and transmission facilities, requiring certain design and
construction features in new and replaced lines to reduce corrosion and
requiring pipeline operators to amend existing written operations and
maintenance procedures and operator qualification programs.
We
anticipate that compliance with these regulations and performance of the
remediation activities by CERC’s interstate and intrastate pipelines, and
natural gas distribution companies will require increases in both capital
expenditures and operating costs. The level of expenditures will depend upon
several factors, including age, location and operating pressures of the
facilities. Based on our interpretation of the rules written to date and
preliminary technical reviews, we believe compliance will require annual
expenditures (capital and operating costs combined) of approximately $17 to
24 million during the initial 10-year period.
ENVIRONMENTAL
MATTERS
Our
operations are subject to stringent and complex laws and regulations pertaining
to health, safety and the environment. As an owner or operator of natural gas
pipelines, gas gathering and processing systems, and electric transmission and
distribution systems, we must comply with these laws and regulations at the
federal, state and local levels. These laws and regulations can restrict or
impact our business activities in many ways, such as:
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restricting
the way we can handle or dispose of
wastes;
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limiting
or prohibiting construction activities in sensitive areas such as
wetlands, coastal regions, or areas inhabited by endangered
species;
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requiring
remedial action to mitigate pollution conditions caused by our operations,
or attributable to former operations;
and
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enjoining
the operations of facilities deemed in non-compliance with permits issued
pursuant to such environmental laws and
regulations.
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In order
to comply with these requirements, we may need to spend substantial amounts and
devote other resources from time to time to:
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construct
or acquire new equipment;
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acquire
permits for facility operations;
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modify
or replace existing and proposed equipment;
and
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clean
up or decommission waste disposal areas, fuel storage and management
facilities and other locations and
facilities.
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Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial actions, and the
issuance of orders enjoining future operations. Certain environmental statutes
impose strict, joint and several liability for costs required to clean up and
restore sites where hazardous substances have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste products into the
environment.
The trend
in environmental regulation is to place more restrictions and limitations on
activities that may affect the environment, and thus there can be no assurance
as to the amount or timing of future expenditures for environmental compliance
or remediation, and actual future expenditures may be different from the amounts
we currently anticipate. We try to anticipate future regulatory requirements
that might be imposed and plan accordingly to remain in compliance with changing
environmental laws and regulations and to minimize the costs of such
compliance.
Based on
current regulatory requirements and interpretations, we do not believe that
compliance with federal, state or local environmental laws and regulations will
have a material adverse effect on our business, financial position, results of
operations or cash flows. In addition, we believe that our current environmental
remediation activities will not materially interrupt or diminish our operational
ability. We cannot assure you, however, that future events, such as changes in
existing laws, the promulgation of new laws, or the development or discovery of
new facts or conditions will not cause us to incur significant costs. The
following is a discussion of all material environmental and safety laws and
regulations that relate to our operations. We believe that we are in substantial
compliance with all of these environmental laws and regulations.
Global
Climate Change
In recent years, there has been
increasing public debate regarding the potential impact on global climate change
by various “greenhouse gases” such as carbon dioxide, a byproduct of burning
fossil fuels, and methane, the principal component of the natural gas that we
transport and deliver to customers. Legislation to regulate emissions of
greenhouse gases has been introduced in Congress, and there has been a
wide-ranging policy debate, both nationally and internationally, regarding the
impact of these gases and possible means for their regulation. Some of the
proposals would require industries such as the utility industry to meet
stringent new standards requiring substantial reductions in carbon emissions.
Those reductions could be costly and difficult to implement. Some proposals
would provide for credits to those who reduce emissions below certain levels and
would allow those credits to be traded and/or sold to others. While there is
growing consensus that some form of global climate change program will be
adopted, it is too early to determine when, and in what form, a regulatory
scheme regarding greenhouse gas emissions will be adopted or what specific
impacts a new regulatory scheme might have on us and our subsidiaries. However,
as a distributor and transporter of natural gas and consumer of natural gas in
its pipeline and gathering businesses, CERC’s revenues, operating costs and
capital requirements could be adversely affected as a result of any regulatory
scheme that would reduce consumption of natural gas if ultimately adopted. Our
electric transmission and distribution business, unlike most electric utilities,
does not generate electricity and thus is not directly exposed to the risk of
high capital costs and regulatory uncertainties that face electric utilities
that are in the business of generating electricity. Nevertheless, CenterPoint
Houston’s revenues could be adversely affected to the extent any resulting
regulatory scheme has the effect of reducing consumption of electricity by
ultimate consumers within its service territory
.
Air
Emissions
Our
operations are subject to the federal Clean Air Act and comparable state laws
and regulations. These laws and regulations regulate emissions of air pollutants
from various industrial sources, including our processing plants and compressor
stations, and also impose various monitoring and reporting requirements. Such
laws and regulations may require that we obtain pre-approval for the
construction or modification of certain projects or facilities expected to
produce air emissions or result in the increase of existing air emissions,
obtain and strictly comply with air permits containing various emissions and
operational limitations, or utilize specific emission control technologies
to
limit
emissions. Our failure to comply with these requirements could subject us to
monetary penalties, injunctions, conditions or restrictions on operations, and
potentially criminal enforcement actions. We may be required to incur certain
capital expenditures in the future for air pollution control equipment in
connection with obtaining and maintaining operating permits and approvals for
air emissions. We believe, however, that our operations will not be materially
adversely affected by such requirements, and the requirements are not expected
to be any more burdensome to us than to other similarly situated
companies.
Water
Discharges
Our
operations are subject to the Federal Water Pollution Control Act of 1972, as
amended, also known as the Clean Water Act, and analogous state laws and
regulations. These laws and regulations impose detailed requirements and strict
controls regarding the discharge of pollutants into waters of the United States.
The unpermitted discharge of pollutants, including discharges resulting from a
spill or leak incident, is prohibited. The Clean Water Act and regulations
implemented thereunder also prohibit discharges of dredged and fill material in
wetlands and other waters of the United States unless authorized by an
appropriately issued permit. Any unpermitted release of petroleum or other
pollutants from our pipelines or facilities could result in fines or penalties
as well as significant remedial obligations.
Hazardous
Waste
Our
operations generate wastes, including some hazardous wastes, that are subject to
the federal Resource Conservation and Recovery Act (RCRA), and comparable state
laws, which impose detailed requirements for the handling, storage, treatment
and disposal of hazardous and solid waste. RCRA currently exempts many natural
gas gathering and field processing wastes from classification as hazardous
waste. Specifically, RCRA excludes from the definition of hazardous waste waters
produced and other wastes associated with the exploration, development, or
production of crude oil and natural gas. However, these oil and gas exploration
and production wastes are still regulated under state law and the less stringent
non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes
such as paint wastes, waste solvents, laboratory wastes, and waste compressor
oils may be regulated as hazardous waste. The transportation of natural gas in
pipelines may also generate some hazardous wastes that would be subject to RCRA
or comparable state law requirements.
Liability
for Remediation
The
Comprehensive Environmental Response, Compensation and Liability Act of 1980, as
amended (CERCLA), also known as “Superfund,” and comparable state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons responsible for the release of hazardous substances
into the environment. Such classes of persons include the current and past
owners or operators of sites where a hazardous substance was released and
companies that disposed or arranged for the disposal of hazardous substances at
offsite locations such as landfills. Although petroleum, as well as natural gas,
is excluded from CERCLA’s definition of a “hazardous substance,” in the course
of our ordinary operations we generate wastes that may fall within the
definition of a “hazardous substance.” CERCLA authorizes the United States
Environmental Protection Agency (EPA) and, in some cases, third parties to take
action in response to threats to the public health or the environment and to
seek to recover from the responsible classes of persons the costs they incur.
Under CERCLA, we could be subject to joint and several liability for the costs
of cleaning up and restoring sites where hazardous substances have been
released, for damages to natural resources, and for the costs of certain health
studies.
Liability
for Preexisting Conditions
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
December 31, 2008, 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 (PRPs), 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 December 31,
2008, 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 EPA 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. CERC 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
CERCLA, and applicable state statutes, and is vigorously contesting the suit and
its designation as a PRP.
Mercury
Contamination.
Our 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. We have found this type
of contamination at some sites in the past, and we have 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 our experience and that of
others in the natural gas industry to date and on the current regulations
regarding remediation of these sites, we believe that the costs of any
remediation of these sites will not be material to our financial condition,
results of operations or cash flows.
Asbestos.
Some
facilities owned by us contain or have contained asbestos insulation and other
asbestos-containing materials. We or our 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 us, but most existing claims relate to
facilities previously owned by our subsidiaries. We anticipate that additional
claims like those received may be asserted in the future. In 2004, we sold our
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 us and our 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 we
have agreed to continue to defend such claims to the extent they are covered by
insurance maintained by us, subject to reimbursement of the costs of such
defense from the purchaser. Although their ultimate outcome cannot be predicted
at this time, we intend to continue vigorously contesting claims that we do not
consider to have merit and do not expect, based on our experience to date, these
matters, either individually or in the aggregate, to have a material adverse
effect on our 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. We 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
us or CERC.
Other
Environmental.
From time to time we have received notices from
regulatory authorities or others regarding our status as a PRP in connection
with sites found to require remediation due to the presence of
environmental
contaminants.
In addition, we have 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, we do not expect, based on our experience to date, these
matters, either individually or in the aggregate, to have a material adverse
effect on our financial condition, results of operations or cash
flows.
EMPLOYEES
As of
December 31, 2008, we had 8,801 full-time employees. The following
table sets forth the number of our employees by business segment:
|
Business
Segment
|
|
Number
|
|
|
Number
Represented
by
Unions or
Other
Collective
Bargaining
Groups
|
|
|
Electric
Transmission & Distribution
|
|
|
2,858
|
|
|
|
1,236
|
|
|
Natural
Gas Distribution
|
|
|
3,652
|
|
|
|
1,405
|
|
|
Competitive
Natural Gas Sales and Services
|
|
|
122
|
|
|
|
—
|
|
|
Interstate
Pipelines
|
|
|
654
|
|
|
|
—
|
|
|
Field
Services
|
|
|
215
|
|
|
|
—
|
|
|
Other
Operations
|
|
|
1,300
|
|
|
|
—
|
|
|
Total
|
|
|
8,801
|
|
|
|
2,641
|
|
As of
December 31, 2008, approximately 30% of our employees are subject to
collective bargaining agreements. One of the collective bargaining agreements
covering approximately 5% of our employees, Gas Workers Union Local No. 340, is
scheduled to expire in 2009. We have a good relationship with this bargaining
unit and expect to negotiate a new agreement in 2009.
EXECUTIVE
OFFICERS
(as
of February 25, 2009)
|
Name
|
|
Age
|
|
Title
|
|
David
M. McClanahan
|
|
59
|
|
President
and Chief Executive Officer and Director
|
|
Scott
E. Rozzell
|
|
59
|
|
Executive
Vice President, General Counsel and Corporate Secretary
|
|
Gary
L. Whitlock
|
|
59
|
|
Executive
Vice President and Chief Financial Officer
|
|
C.
Gregory Harper
|
|
44
|
|
Senior
Vice President and Group President, CenterPoint Energy Pipelines and Field
Services
|
|
Thomas
R. Standish
|
|
59
|
|
Senior
Vice President and Group President — Regulated
Operations
|
David M. McClanahan
has been
President and Chief Executive Officer and a director of CenterPoint Energy since
September 2002. He served as Vice Chairman of Reliant Energy, Incorporated
(Reliant Energy) from October 2000 to September 2002 and as President and Chief
Operating Officer of Reliant Energy’s Delivery Group from April 1999 to
September 2002. He previously served as Chairman of the Board of Directors of
ERCOT, Chairman of the Board of the University of St. Thomas in Houston and the
Chairman of the Board of the American Gas Association. He currently serves on
the boards of the Edison Electric Institute and the American Gas
Association.
Scott E. Rozzell
has served as
Executive Vice President, General Counsel and Corporate Secretary of CenterPoint
Energy since September 2002. He served as Executive Vice President and General
Counsel of the Delivery Group of Reliant Energy from March 2001 to September
2002. Before joining Reliant Energy in 2001, Mr. Rozzell was a senior partner in
the law firm of Baker Botts L.L.P. He currently serves on the Board of Directors
of the Association of Electric Companies of Texas.
Gary L. Whitlock
has served as
Executive Vice President and Chief Financial Officer of CenterPoint Energy since
September 2002. He served as Executive Vice President and Chief Financial
Officer of the Delivery Group of Reliant Energy from July 2001 to September
2002. Mr. Whitlock served as the Vice President, Finance and Chief Financial
Officer of Dow AgroSciences, a subsidiary of The Dow Chemical Company, from 1998
to 2001.
C. Gregory Harper
has served
as Senior Vice President and Group President of CenterPoint Energy Pipelines and
Field Services since December 2008. Before joining CenterPoint Energy in
2008, Mr. Harper served as President, Chief Executive Officer and as a Director
of Spectra Energy Partners, LP from March 2007 to December 2008. From
January 2007 to March 2007, Mr. Harper was Group Vice President of Spectra
Energy Corp., and he was Group Vice President of Duke Energy from January 2004
to December 2006. Mr. Harper served as Senior Vice President of Energy
Marketing for Duke Energy North America from January 2003 until January 2004 and
Vice President of Business Development for Duke Energy Gas Transmission and Vice
President of East Tennessee Natural Gas, LLC from March 2002 until January 2003.
He currently serves on the Board of Directors of the Interstate Natural Gas
Association of America.
Thomas R. Standish
has served
as Senior Vice President and Group President-Regulated Operations of CenterPoint
Energy since August 2005, having previously served as Senior Vice President and
Group President and Chief Operating Officer of CenterPoint Houston from June
2004 to August 2005 and as President and Chief Operating Officer of CenterPoint
Houston from August 2002 to June 2004. He served as President and Chief
Operating Officer for both electricity and natural gas for Reliant Energy’s
Houston area from 1999 to August 2002.
We are a
holding company that conducts all of our business operations through
subsidiaries, primarily CenterPoint Houston and CERC. The following, along with
any additional legal proceedings identified or incorporated by reference in
Item 3 of this report, summarizes the principal risk factors associated
with the businesses conducted by each of these subsidiaries:
Risk
Factors Affecting Our Electric Transmission & Distribution
Business
CenterPoint
Houston may not be successful in ultimately recovering the full value of
its true-up
components, which could result in the elimination of certain tax
benefits and
could have an adverse impact on CenterPoint Houston’s results of
operations,
financial condition and cash flows.
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 restructuring law. In December 2004, the
Texas Utility Commission issued its 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 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:
|
|
•
|
reversed
the Texas Utility Commission’s ruling that had denied recovery of a
portion of the capacity auction true-up
amounts;
|
|
|
•
|
reversed
the Texas Utility Commission’s ruling that precluded CenterPoint Houston
from recovering the interest component of the EMCs paid to
REPs; and
|
|
|
•
|
affirmed
the True-Up Order in all other
respects.
|
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:
|
|
•
|
reversed
the district court’s judgment to the extent it restored the capacity
auction true-up amounts;
|
|
|
•
|
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
RRI;
|
|
|
•
|
ordered
that the tax normalization issue described below be remanded to the Texas
Utility Commission as requested by the Texas Utility
Commission; and
|
|
|
•
|
affirmed
the district court’s judgment in all other
respects.
|
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 the
second quarter of 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 we 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, we 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, we 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 our 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, we anticipate that we 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. We
believe that the Texas Utility Commission based its order on proposed
regulations issued by the 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 ADITC and 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, we received a 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 us 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 our
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. We 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.
CenterPoint
Houston must seek recovery of significant restoration costs arising from
Hurricane
Ike.
CenterPoint
Houston’s electric delivery system suffered substantial damage as a result of
Hurricane Ike, which struck the upper Texas coast on September 13, 2008.
CenterPoint Houston estimates that total costs to restore the electric delivery
facilities damaged as a result of Hurricane Ike will be in the range of
$600 million to $650 million.
CenterPoint
Houston believes it is entitled to recover prudently incurred storm costs in
accordance with applicable regulatory and legal principles. The Texas
Legislature currently is considering passage of legislation that
would (i) authorize the Texas Utility Commission to determine the amount of
storm restoration costs that CenterPoint Houston would be entitled to recover
and (ii) permit the Texas Utility Commission to issue a financing order
that would allow CenterPoint Houston to recover the amount of storm restoration
costs determined in such a proceeding through issuance of dedicated
securitization bonds, which would be repaid over time through a charge imposed
on REPs. In proceedings to determine and seek recovery of storm restoration
costs under the proposed legislation, CenterPoint Houston would be required to
prove to the Texas Utility Commission’s satisfaction its prudently incurred
costs as well as to demonstrate the cost benefit from using securitization to
recover those costs instead of alternative means. Alternatively, CenterPoint
Houston has the right to seek recovery of these costs under traditional rate
making principles. CenterPoint Houston’s failure to recover costs incurred as a
result of Hurricane Ike could adversely affect its liquidity, results of
operations and financial condition. For more information about CenterPoint
Houston’s recovery from Hurricane Ike, please read “Business — Electric
Transmission & Distribution — Hurricane Ike” in Item 1 of
this report.
CenterPoint
Houston’s receivables are concentrated in a small number of retail
electric
providers, and any delay or default in payment could adversely affect
CenterPoint
Houston’s cash flows, financial condition and results of
operations.
CenterPoint
Houston’s receivables from the distribution of electricity are collected from
REPs that supply the electricity CenterPoint Houston distributes to their
customers. As of December 31, 2008, CenterPoint Houston did business with
79 REPs. Adverse economic conditions, structural problems in the market served
by ERCOT or financial difficulties of one or more REPs could impair the ability
of these REPs to pay for CenterPoint Houston’s services or could cause them to
delay such payments. In 2008, seven REPs selling power within CenterPoint
Houston’s service territory ceased to operate, and their customers were
transferred to the provider of last resort or to other REPs. CenterPoint Houston
depends on these REPs to remit payments on a timely basis. Applicable regulatory
provisions require that customers be shifted to a provider of last resort if a
REP cannot make timely payments. Applicable Texas Utility Commission regulations
significantly limit the extent to which CenterPoint Houston can demand credit
protection from REPs for payments not made prior to the shift to the provider of
last resort. However,
the Texas
Utility Commission is currently considering proposed revisions to those
regulations that, as currently proposed, would (i) increase the credit
protections that could be required from REPs, and (ii) allow utilities to defer
the loss of payments for recovery in a future rate case. Whether such
revised regulations will ultimately be adopted and their terms cannot now be
determined. RRI, through its subsidiaries, is CenterPoint Houston’s largest
customer. Approximately 46% of CenterPoint Houston’s $141 million in billed
receivables from REPs at December 31, 2008 was owed by subsidiaries of RRI.
Any delay or default in payment by REPs such as RRI could adversely affect
CenterPoint Houston’s cash flows, financial condition and results of operations.
RRI’s unsecured debt ratings are currently below investment grade. If RRI were
unable to meet its obligations, it could consider, among various options,
restructuring under the bankruptcy laws, in which event RRI’s subsidiaries might
seek to avoid honoring their obligations and claims might be made by creditors
involving payments CenterPoint Houston has received from RRI’s
subsidiaries.
Rate regulation
of CenterPoint Houston’s business may delay or deny CenterPoint
Houston’s ability
to earn a reasonable return and fully recover its costs.
CenterPoint
Houston’s rates are regulated by certain municipalities and the Texas Utility
Commission based on an analysis of its invested capital and its expenses in a
test year. Thus, the rates that CenterPoint Houston is allowed to charge may not
match its expenses at any given time. The regulatory process by which rates are
determined may not always result in rates that will produce full recovery of
CenterPoint Houston’s costs and enable CenterPoint Houston to earn a reasonable
return on its invested capital.
In this
regard, pursuant to the Stipulation and Settlement Agreement approved by the
Texas Utility Commission in September 2006, until June 30, 2010
CenterPoint Houston is limited in its ability to request retail rate relief. For
more information on the Stipulation and Settlement Agreement, please read
“Business — Regulation — State and Local Regulation — Electric
Transmission & Distribution — CenterPoint Houston Rate Agreement”
in Item 1 of this report.
Disruptions at
power generation facilities owned by third parties could interrupt
CenterPoint
Houston’s sales of transmission and distribution services.
CenterPoint
Houston transmits and distributes to customers of REPs electric power that the
REPs obtain from power generation facilities owned by third parties. CenterPoint
Houston does not own or operate any power generation facilities. If power
generation is disrupted or if power generation capacity is inadequate,
CenterPoint Houston’s sales of transmission and distribution services may be
diminished or interrupted, and its results of operations, financial condition
and cash flows could be adversely affected.
CenterPoint
Houston’s revenues and results of operations are seasonal.
A
significant portion of CenterPoint Houston’s revenues is derived from rates that
it collects from each REP based on the amount of electricity it delivers on
behalf of such REP. Thus, CenterPoint Houston’s revenues and results of
operations are subject to seasonality, weather conditions and other changes in
electricity usage, with revenues being higher during the warmer
months.
Risk Factors Affecting Our Natural
Gas Distribution, Competitive Natural Gas Sales
and Services, Interstate Pipelines
and Field Services Businesses
Rate regulation
of CERC’s business may delay or deny CERC’s ability to earn a
reasonable return
and fully recover its costs.
CERC’s
rates for Gas Operations are regulated by certain municipalities and state
commissions, and for its interstate pipelines by the FERC, based on an analysis
of its invested capital and its expenses in a test year. Thus, the rates that
CERC is allowed to charge may not match its expenses at any given time. The
regulatory process in which rates are determined may not always result in rates
that will produce full recovery of CERC’s costs and enable CERC to earn a
reasonable return on its invested capital.
CERC’s businesses
must compete with alternate energy sources, which could result in
CERC marketing
less natural gas, and its interstate pipelines and field services
businesses must
compete directly with others in the transportation, storage,
gathering,
treating and processing of natural gas, which could lead to lower prices
and reduced
volumes, either of which could have an adverse impact on CERC’s results
of
operations, financial condition and cash flows.
CERC
competes primarily with alternate energy sources such as electricity and other
fuel sources. In some areas, intrastate pipelines, other natural gas
distributors and marketers also compete directly with CERC for natural gas sales
to end-users. In addition, as a result of federal regulatory changes affecting
interstate pipelines, natural gas marketers operating on these pipelines may be
able to bypass CERC’s facilities and market, sell and/or transport natural gas
directly to commercial and industrial customers. Any reduction in the amount of
natural gas marketed, sold or transported by CERC as a result of competition may
have an adverse impact on CERC’s results of operations, financial condition and
cash flows.
CERC’s
two interstate pipelines and its gathering systems compete with other interstate
and intrastate pipelines and gathering systems in the transportation and storage
of natural gas. The principal elements of competition are rates, terms of
service, and flexibility and reliability of service. They also compete
indirectly with other forms of energy, including electricity, coal and fuel
oils. The primary competitive factor is price. The actions of CERC’s competitors
could lead to lower prices, which may have an adverse impact on CERC’s results
of operations, financial condition and cash flows. Additionally, any reduction
in the volume of natural gas transported or stored may have an adverse impact on
CERC’s results of operations, financial condition and cash flows.
CERC’s natural
gas distribution and competitive natural gas sales and services
businesses are
subject to fluctuations in natural gas prices, which could
affect the
ability of CERC’s suppliers and customers to meet their obligations or
otherwise
adversely affect CERC’s liquidity and results of operations.
CERC is
subject to risk associated with increases in the price of natural gas. Increases
in natural gas prices might affect CERC’s ability to collect balances due from
its customers and, for Gas Operations, could create the potential for
uncollectible accounts expense to exceed the recoverable levels built into
CERC’s tariff rates. In addition, a sustained period of high natural gas prices
could (i) apply downward demand pressure on natural gas consumption in the
areas in which CERC operates thereby resulting in decreased sales volumes and
revenues and (ii) increase the risk that CERC’s suppliers or customers fail
or are unable to meet their obligations. Additionally, increasing natural gas
prices could create the need for CERC to provide collateral in order to purchase
natural gas.
A decline in
CERC’s credit rating could result in CERC’s having to provide collateral
in order to
purchase gas.
If CERC’s
credit rating were to decline, it might be required to post cash collateral in
order to purchase natural gas. If a credit rating downgrade and the resultant
cash collateral requirement were to occur at a time when CERC was experiencing
significant working capital requirements or otherwise lacked liquidity, CERC’s
results of operations, financial condition and cash flows could be adversely
affected.
The revenues and
results of operations of CERC’s interstate pipelines and field
services
businesses are subject to fluctuations in the supply and price of natural
gas.
CERC’s
interstate pipelines and field services businesses largely rely on natural gas
sourced in the various supply basins located in the Mid-continent region of the
United States. The level of drilling and production activity in these regions is
dependent on economic and business factors beyond our control. The primary
factor affecting both the level of drilling activity and production volumes is
natural gas pricing. A sustained decline in natural gas prices could result in a
decrease in exploration and development activities in the regions served by our
gathering and pipeline transportation systems and our natural gas treating and
processing activities. A sustained decline could also lead producers to shut in
production from their existing wells. Other factors that impact production
decisions include the level of production costs relative to other available
production, producers’ access to needed capital and the cost of that capital,
the ability of producers to obtain necessary drilling and other governmental
permits, access to drilling rigs and regulatory changes. Because of these
factors, even if new natural gas reserves are discovered in areas served by our
assets, producers may choose not to develop those reserves or to shut in
production from
existing
reserves. To the extent the availability of this supply is substantially
reduced, it could have an adverse effect on CERC’s results of operations,
financial condition and cash flows.
CERC’s
revenues from these businesses are also affected by the prices of natural gas
and natural gas liquids (NGL). NGL prices generally fluctuate on a basis that
correlates to fluctuations in crude oil prices. In the past, the prices of
natural gas and crude oil have been extremely volatile, and we expect this
volatility to continue. The markets and prices for natural gas, NGLs and crude
oil depend upon factors beyond our control. These factors include supply of and
demand for these commodities, which fluctuate with changes in market and
economic conditions and other factors.
CERC’s
revenues and results of operations are seasonal.
A
substantial portion of CERC’s revenues is derived from natural gas sales and
transportation. Thus, CERC’s revenues and results of operations are subject to
seasonality, weather conditions and other changes in natural gas usage, with
revenues being higher during the winter months.
The actual cost
of pipelines under construction and related compression facilities
may be
significantly higher than CERC had planned.
Subsidiaries
of CERC Corp. have been recently involved in significant pipeline construction
projects and, depending on available opportunities, may, from time to time, be
involved in additional significant pipeline construction projects in the future.
The construction of new pipelines and related compression facilities requires
the expenditure of significant amounts of capital, which may exceed CERC’s
estimates. These projects may not be completed at the planned cost, on schedule
or at all. The construction of new pipeline or compression facilities is subject
to construction cost overruns due to labor costs, costs of equipment and
materials such as steel and nickel, labor shortages or delays, weather delays,
inflation or other factors, which could be material. In addition, the
construction of these facilities is typically subject to the receipt of
approvals and permits from various regulatory agencies. Those agencies may not
approve the projects in a timely manner or may impose restrictions or conditions
on the projects that could potentially prevent a project from proceeding,
lengthen its expected completion schedule and/or increase its anticipated cost.
As a result, there is the risk that the new facilities may not be able to
achieve CERC’s expected investment return, which could adversely affect CERC’s
financial condition, results of operations or cash flows.
The states in
which CERC provides regulated local gas distribution may, either
through
legislation or rules, adopt restrictions similar to or broader than those
under the
Public Utility Holding Company Act of 1935 regarding organization,
financing and
affiliate transactions that could have significant adverse impacts on
CERC’s
ability to operate.
The
Public Utility Holding Company Act of 1935, to which we and our subsidiaries
were subject prior to its repeal in the Energy Act, provided a comprehensive
regulatory structure governing the organization, capital structure, intracompany
relationships and lines of business that could be pursued by registered holding
companies and their member companies. Following repeal of that Act, some states
in which CERC does business have sought to expand their own regulatory
frameworks to give their regulatory authorities increased jurisdiction and
scrutiny over similar aspects of the utilities that operate in their states.
Some of these frameworks attempt to regulate
financing
activities, acquisitions and divestitures, and arrangements between the
utilities and their affiliates, and to restrict the level of non-utility
businesses that can be conducted within the holding company structure.
Additionally they may impose record keeping, record access, employee training
and reporting requirements related to affiliate transactions and reporting in
the event of certain downgrading of the utility’s bond rating.
These
regulatory frameworks could have adverse effects on CERC’s ability to operate
its utility operations, to finance its business and to provide cost-effective
utility service. In addition, if more than one state adopts restrictions over
similar activities, it may be difficult for CERC and us to comply with competing
regulatory requirements.
Risk
Factors Associated with Our Consolidated Financial Condition
If we are unable
to arrange future financings on acceptable terms, our ability to
refinance
existing indebtedness could be limited.
As of
December 31, 2008, we had $10.7 billion of outstanding indebtedness on
a consolidated basis, which includes $2.6 billion of non-recourse
transition bonds. As of December 31, 2008, approximately $953 million
principal amount of this debt is required to be paid through 2011. This amount
excludes principal repayments of approximately $669 million on transition
bonds, for which a dedicated revenue stream exists. Our future financing
activities may be significantly affected by, among other things:
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the
resolution of the true-up components, including, in particular, the
results of appeals to the courts regarding rulings obtained to
date;
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CenterPoint
Houston’s recovery of costs arising from Hurricane
Ike;
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general
economic and capital market
conditions;
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credit
availability from financial institutions and other
lenders;
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investor
confidence in us and the markets in which we
operate;
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maintenance
of acceptable credit ratings;
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market
expectations regarding our future earnings and cash
flows;
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market
perceptions of our ability to access capital markets on reasonable
terms;
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our
exposure to RRI in connection with its indemnification obligations arising
in connection with its separation from
us; and
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provisions
of relevant tax and securities
laws.
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As of
December 31, 2008, CenterPoint Houston had outstanding approximately
$2.6 billion aggregate principal amount of general mortgage bonds,
including approximately $527 million held in trust to secure pollution
control bonds for which we are obligated, $600 million securing borrowings
under a credit facility which was unutilized and approximately $229 million
held in trust to secure pollution control bonds for which CenterPoint Houston is
obligated. Additionally, CenterPoint Houston had outstanding approximately
$253 million aggregate principal amount of first mortgage bonds, including
approximately $151 million held in trust to secure certain pollution
control bonds for which we are obligated. CenterPoint Houston may issue
additional general mortgage bonds on the basis of retired bonds, 70% of property
additions or cash deposited with the trustee. Approximately $1.8 billion of
additional first mortgage bonds and general mortgage bonds in the aggregate
could be issued on the basis of retired bonds and 70% of property additions as
of December 31, 2008. However, CenterPoint Houston has contractually agreed
that it will not issue additional first mortgage bonds, subject to certain
exceptions. In January 2009, CenterPoint Houston issued $500 million
aggregate principal amount of general mortgage bonds in a public
offering.
Our
current credit ratings are discussed in “Management’s Discussion and Analysis of
Financial Condition and Results of Operations of CenterPoint Energy, Inc. and
Subsidiaries — Liquidity and Capital Resources — Future Sources
and Uses of Cash — Impact on Liquidity of a Downgrade in Credit Ratings” in
Item 7 of this report. These credit ratings may not remain in effect for
any given period of time and one or more of these ratings may be lowered or
withdrawn entirely by a rating agency. We note that these credit ratings are not
recommendations to buy, sell or hold our securities. Each rating should be
evaluated independently of any other rating. Any future reduction or withdrawal
of one or more of our credit ratings could have a material adverse impact on our
ability to access capital on acceptable terms.
As a holding
company with no operations of our own, we will depend on distributions
from our
subsidiaries to meet our payment obligations, and provisions of
applicable
law or
contractual restrictions could limit the amount of those
distributions.
We derive
all our operating income from, and hold all our assets through, our
subsidiaries. As a result, we will depend on distributions from our subsidiaries
in order to meet our payment obligations. In general, these subsidiaries are
separate and distinct legal entities and have no obligation to provide us with
funds for our payment obligations, whether by dividends, distributions, loans or
otherwise. In addition, provisions of applicable law, such as those limiting the
legal sources of dividends, limit our subsidiaries’ ability to make payments or
other distributions to us, and our subsidiaries could agree to contractual
restrictions on their ability to make distributions.
Our right
to receive any assets of any subsidiary, and therefore the right of our
creditors to participate in those assets, will be effectively subordinated to
the claims of that subsidiary’s creditors, including trade creditors. In
addition, even if we were a creditor of any subsidiary, our rights as a creditor
would be subordinated to any security interest in the assets of that subsidiary
and any indebtedness of the subsidiary senior to that held by us.
The use of
derivative contracts by us and our subsidiaries in the normal course of
business
could result in financial losses that could negatively impact our results
of
operations and
those of our subsidiaries.
We and
our subsidiaries use derivative instruments, such as swaps, options, futures and
forwards, to manage our commodity, weather and financial market risks. We and
our subsidiaries could recognize financial losses as a result of volatility in
the market values of these contracts, or should a counterparty fail to perform.
In the absence of actively quoted market prices and pricing information from
external sources, the valuation of these financial instruments can involve
management’s judgment or use of estimates. As a result, changes in the
underlying assumptions or use of alternative valuation methods could affect the
reported fair value of these contracts.
Risks
Common to Our Businesses and Other Risks
We are subject to
operational and financial risks and liabilities arising from
environmental
laws and regulations.
Our
operations are subject to stringent and complex laws and regulations pertaining
to health, safety and the environment as described in “Business
— Environmental Matters” in Item 1 of this Form 10-K. As an owner
or operator of natural gas pipelines and distribution systems, gas gathering and
processing systems, and electric transmission and distribution systems, we must
comply with these laws and regulations at the federal, state and local levels.
These laws and regulations can restrict or impact our business activities in
many ways, such as:
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restricting
the way we can handle or dispose of
wastes;
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limiting
or prohibiting construction activities in sensitive areas such as
wetlands, coastal regions, or areas inhabited by endangered
species;
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requiring
remedial action to mitigate pollution conditions caused by our operations,
or attributable to former
operations; and
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enjoining
the operations of facilities deemed in non-compliance with permits issued
pursuant to such environmental laws and
regulations.
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In order
to comply with these requirements, we may need to spend substantial amounts and
devote other resources from time to time to:
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construct
or acquire new equipment;
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acquire
permits for facility operations;
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modify
or replace existing and proposed
equipment; and
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clean
up or decommission waste disposal areas, fuel storage and management
facilities and other locations and
facilities.
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Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial actions, and the
issuance of orders enjoining future operations. Certain environmental statutes
impose strict, joint and several liability for costs required to clean up and
restore sites where hazardous substances have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste products into the
environment.
Our insurance
coverage may not be sufficient. Insufficient insurance coverage and
increased
insurance costs could adversely impact our results of operations,
financial
condition and
cash flows.
We
currently have general liability and property insurance in place to cover
certain of our facilities in amounts that we consider appropriate. Such policies
are subject to certain limits and deductibles and do not include business
interruption coverage. Insurance coverage may not be available in the future at
current costs or on commercially reasonable terms, and the insurance proceeds
received for any loss of, or any damage to, any of our facilities may not be
sufficient to restore the loss or damage without negative impact on our results
of operations, financial condition and cash flows.
In common
with other companies in its line of business that serve coastal regions,
CenterPoint Houston does not have insurance covering its transmission and
distribution system because CenterPoint Houston believes it to be cost
prohibitive. CenterPoint Houston may not be able to recover the costs incurred
in restoring its transmission and distribution properties following Hurricane
Ike, or any such costs sustained in the future, through a change in its
regulated rates, and any such recovery may not be timely granted. Therefore,
CenterPoint Houston may not be able to restore any loss of, or damage to, any of
its transmission and distribution properties without negative impact on its
results of operations, financial condition and cash flows.
We, CenterPoint
Houston and CERC could incur liabilities associated with businesses
and assets that
we have transferred to others.
Under
some circumstances, we, CenterPoint Houston and CERC could incur liabilities
associated with assets and businesses we, CenterPoint Houston and CERC no longer
own. These assets and businesses were previously owned by Reliant Energy,
Incorporated (Reliant Energy), a predecessor of CenterPoint Houston, directly or
through subsidiaries and include:
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merchant
energy, energy trading and REP businesses transferred to RRI or its
subsidiaries in connection with the organization and capitalization of RRI
prior to its initial public offering in
2001; and
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Texas
electric generating facilities transferred to Texas Genco Holdings, Inc.
(Texas Genco) in 2004 and early
2005.
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In
connection with the organization and capitalization of RRI, RRI and its
subsidiaries assumed liabilities associated with various assets and businesses
Reliant Energy transferred to them. RRI also agreed to indemnify, and
cause the
applicable transferee subsidiaries to indemnify, us and our subsidiaries,
including CenterPoint Houston and CERC, with respect to liabilities associated
with the transferred assets and businesses. These indemnity provisions were
intended to place sole financial responsibility on RRI and its subsidiaries for
all liabilities associated with the current and historical businesses and
operations of RRI, regardless of the time those liabilities arose. If RRI were
unable to satisfy a liability that has been so assumed in circumstances in which
Reliant Energy and its subsidiaries were not released from the liability in
connection with the transfer, we, CenterPoint Houston or CERC could be
responsible for satisfying the liability.
Prior to
the distribution of our ownership in RRI to our 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, we, 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 revised 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 December 31, 2008. RRI
continues to meet its obligations under the contracts, and on the basis of
market conditions, we 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, we would retain our exposure to the counterparty under the
guaranty.
RRI’s
unsecured debt ratings are currently below investment grade. If RRI were unable
to meet its obligations, it would need to consider, among various options,
restructuring under the bankruptcy laws, in which event RRI might not honor its
indemnification obligations and claims by RRI’s creditors might be made against
us as its former owner.
Reliant
Energy and RRI are named as defendants in a number of lawsuits arising out of
energy sales in California and other markets and financial reporting matters.
Although these matters relate to the business and operations of RRI, claims
against Reliant Energy have been made on grounds that include the effect of
RRI’s financial results on Reliant Energy’s historical financial statements and
liability of Reliant Energy as a controlling shareholder of RRI. We, CenterPoint
Houston or CERC could incur liability if claims in one or more of these lawsuits
were successfully asserted against us, CenterPoint Houston or CERC and
indemnification from RRI were determined to be unavailable or if RRI were unable
to satisfy indemnification obligations owed with respect to those
claims.
In
connection with the organization and capitalization of Texas Genco, Texas Genco
assumed liabilities associated with the electric generation assets Reliant
Energy transferred to it. Texas Genco also agreed to indemnify, and cause the
applicable transferee subsidiaries to indemnify, us and our subsidiaries,
including CenterPoint Houston, with respect to liabilities associated with the
transferred assets and businesses. In many cases the liabilities assumed were
obligations of CenterPoint Houston and CenterPoint Houston was not released by
third parties from these liabilities. The indemnity provisions were intended
generally to place sole financial responsibility on Texas Genco and its
subsidiaries for all liabilities associated with the current and historical
businesses and operations of Texas Genco, regardless of the time those
liabilities arose. In connection with the sale of Texas Genco’s fossil
generation assets (coal, lignite and gas-fired plants) to NRG Texas LP
(previously named Texas Genco LLC), the separation agreement we entered
into with Texas Genco in connection with the organization and capitalization of
Texas Genco was amended to provide that all of Texas Genco’s rights and
obligations under the separation agreement relating to its fossil generation
assets, including Texas Genco’s obligation to indemnify us with respect to
liabilities associated with the fossil generation assets and related business,
were assigned to and assumed by NRG Texas LP. In addition, under the amended
separation agreement, Texas Genco is no longer liable for, and we have assumed
and agreed to indemnify NRG
Texas LP
against, liabilities that Texas Genco originally assumed in connection with its
organization to the extent, and only to the extent, that such liabilities are
covered by certain
insurance
policies or other similar agreements held by us. If Texas Genco or NRG Texas LP
were unable to satisfy a liability that had been so assumed or indemnified
against, and provided Reliant Energy had not been released from the liability in
connection with the transfer, CenterPoint Houston could be responsible for
satisfying the liability.
We or our
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. Most claimants in such litigation have been workers who participated
in construction of various industrial facilities, including power plants. Some
of the claimants have worked at locations owned by us, but most existing claims
relate to facilities previously owned by us or our subsidiaries but currently
owned by NRG Texas LP. We anticipate that additional claims like those received
may be asserted in the future. Under the terms of the arrangements regarding
separation of the generating business from us 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 we have agreed to
continue to defend such claims to the extent they are covered by insurance
maintained by us, subject to reimbursement of the costs of such defense by NRG
Texas LP.
The global
financial crisis may have impacts on our business, liquidity and financial
condition
that we currently
cannot predict.
The
continued credit crisis and related turmoil in the global financial system may
have an impact on our business, liquidity and our financial condition. Our
ability to access the capital markets may be severely restricted at a time when
we would like, or need, to access those markets, which could have an impact on
our liquidity and flexibility to react to changing economic and business
conditions. In addition, the cost of debt financing and the proceeds of equity
financing may be materially adversely impacted by these market conditions. With
respect to our existing debt arrangements, Lehman Brothers Bank, FSB, which had
an approximately four percent participation in our credit facility and each of
the then-existing credit facilities of our subsidiaries, stopped funding its
commitments following the bankruptcy filing of its parent in September 2008 and
was subsequently terminated as a lender in our facility and the facility of
CenterPoint Houston. Defaults of other lenders should they occur could adversely
affect our liquidity. Capital market turmoil was also reflected in significant
reductions in equity market valuations in 2008, which significantly reduced the
value of assets of our pension plan. These reductions are expected to result in
increased non-cash pension expense in 2009, which will impact 2009 results of
operations.
In
addition to the credit and financial market issues, the national and local
recessionary conditions may impact our business in a variety of ways. These
include, among other things, reduced customer usage, increased customer default
rates and wide swings in commodity prices.
Not
applicable.
Item 2.
Properties
Character
of Ownership
We own or
lease our principal properties in fee, including our corporate office space and
various real property. Most of our electric lines and gas mains are located,
pursuant to easements and other rights, on public roads or on land owned by
others.
Electric
Transmission & Distribution
For
information regarding the properties of our Electric Transmission &
Distribution business segment, please read “Business — Our Business —
Electric Transmission & Distribution — Properties” in Item 1
of this report, which information is incorporated herein by
reference.
Natural
Gas Distribution
For
information regarding the properties of our Natural Gas Distribution business
segment, please read “Business — Our Business — Natural Gas
Distribution — Assets” in Item 1 of this report, which information is
incorporated herein by reference.
Competitive
Natural Gas Sales and Services
For
information regarding the properties of our Competitive Natural Gas Sales and
Services business segment, please read “Business — Our Business —
Competitive Natural Gas Sales and Services — Assets” in Item 1 of this
report, which information is incorporated herein by reference.
Interstate
Pipelines
For
information regarding the properties of our Interstate Pipelines business
segment, please read “Business — Our Business — Interstate
Pipelines — Assets” in Item 1 of this report, which information is
incorporated herein by reference.
Field
Services
For
information regarding the properties of our Field Services business segment,
please read “Business — Our Business — Field Services — Assets”
in Item 1 of this report, which information is incorporated herein by
reference.
Other
Operations
For
information regarding the properties of our Other Operations business segment,
please read “Business — Our Business — Other Operations” in
Item 1 of this report, which information is incorporated herein by
reference.
For a
discussion of material legal and regulatory proceedings affecting us, please
read “Business — Regulation” and “Business — Environmental Matters” in
Item 1 of this report and Notes 3 and 10(d) to our consolidated
financial statements, which information is incorporated herein by
reference.
Item 4.
Submission of Matters to a Vote of
Security Holders
There
were no matters submitted to the vote of our security holders during the fourth
quarter of 2008.