DTE ENERGY CO
10-Ks and 10-Qs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
|
þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010 | ||
|
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number 1-11607
DTE ENERGY COMPANY
(Exact name of registrant as
specified in its charter)
|
Michigan
|
38-3217752 | |
|
(State or other jurisdiction
of
incorporation or organization) |
(I.R.S. Employer
Identification No.) |
|
|
One Energy Plaza, Detroit, Michigan
|
48226-1279 | |
|
(Address of principal executive
offices)
|
(Zip Code) |
313-235-4000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the
Act:
| Title of Each Class | Name of Each Exchange on Which Registered | |
|
Common Stock, without par value
|
New York Stock Exchange | |
|
7.8% Trust Preferred Securities*
|
New York Stock Exchange | |
|
7.50% Trust Originated Preferred Securities**
|
New York Stock Exchange |
| * | Issued by DTE Energy Trust I. DTE Energy fully and unconditionally guarantees the payments of all amounts due on these securities to the extent DTE Energy Trust I has funds available for payment of such distributions. | |
| ** | Issued by DTE Energy Trust II. DTE Energy fully and unconditionally guarantees the payments of all amounts due on these securities to the extent DTE Energy Trust II has funds available for payment of such distributions. |
Securities registered pursuant to Section 12(g) of the
Act: None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes
þ
No
o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes
o
No
þ
Indicate by check mark whether the registrant: (1) has
filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past
90 days. Yes
þ
No
o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or such shorter period that the registrant was
required to submit and post such
files). Yes
þ
No
o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of the registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K.
o
.
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
“large accelerated filer,” “accelerated
filer” and “smaller reporting company” in Rule
12b-2
of the
Exchange Act. (Check one):
|
Large accelerated filer
þ
|
Accelerated filer o |
Non-accelerated filer
o
(Do not check if a smaller reporting company) |
Smaller Reporting company o |
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes
o
No
þ
On June 30, 2010, the aggregate market value of the
Registrant’s voting and non-voting common equity held by
non-affiliates was approximately $7.8 billion (based on the
New York Stock Exchange closing price on such date). There were
169,443,420 shares of common stock outstanding at
January 31, 2011.
Certain information in DTE Energy Company’s definitive
Proxy Statement for its 2011 Annual Meeting of Common
Shareholders to be held May 5, 2011, which will be filed
with the Securities and Exchange Commission pursuant to
Regulation 14A, not later than 120 days after the end
of the Registrant’s fiscal year covered by this report on
Form 10-K,
is incorporated herein by reference to Part III
(Items 10, 11, 12, 13 and 14) of this
Form 10-K.
DTE
Energy Company
Annual Report on Form 10-K
Year Ended December 31, 2010
TABLE OF CONTENTS
Annual Report on Form 10-K
Year Ended December 31, 2010
TABLE OF CONTENTS
Table of Contents
DEFINITIONS
| ASC | Accounting Standards Codification | |
| ASU | Accounting Standards Update | |
| Company | DTE Energy Company and any subsidiary companies | |
| CIM | A Choice Incentive Mechanism authorized by the MPSC that allows Detroit Edison to recover or refund non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales. | |
| CTA | Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process | |
| Customer Choice | Michigan legislation giving customers the option to choose alternative suppliers for electricity and gas. | |
| Detroit Edison | The Detroit Edison Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies | |
| DTE Energy | DTE Energy Company, directly or indirectly the parent of Detroit Edison, MichCon and numerous non-utility subsidiaries | |
| EPA | United States Environmental Protection Agency | |
| FASB | Financial Accounting Standards Board | |
| FERC | Federal Energy Regulatory Commission | |
| FTRs | Financial transmission rights are financial instruments that entitle the holder to receive payments related to costs incurred for congestion on the transmission grid. | |
| GCR | A Gas Cost Recovery mechanism authorized by the MPSC that allows MichCon to recover through rates its natural gas costs. | |
| HCERA | Health Care and Education Reconciliation Act of 2010 | |
| MichCon | Michigan Consolidated Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies | |
| MISO | Midwest Independent System Operator is an Independent System Operator and the Regional Transmission Organization serving the Midwest United States and Manitoba, Canada. | |
| MDNRE | Michigan Department of Natural Resources and Environment | |
| MPSC | Michigan Public Service Commission | |
| Non-utility | An entity that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC. | |
| NRC | United States Nuclear Regulatory Commission | |
|
PPACA
|
Patient Protection and Affordable Care Act of 2010 | |
| Production tax credits | Tax credits as authorized under Sections 45K and 45 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a production tax credit can vary each year as determined by the Internal Revenue Service. |
1
Table of Contents
| Proved reserves | Estimated quantities of natural gas, natural gas liquids and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions. | |
| PSCR | A Power Supply Cost Recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power costs. | |
| RDM | A Revenue Decoupling Mechanism authorized by the MPSC that is designed to minimize the impact on revenues of changes in average customer usage of electricity and natural gas. | |
| Securitization | Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly-owned special purpose entity, The Detroit Edison Securitization Funding LLC. | |
| Subsidiaries | The direct and indirect subsidiaries of DTE Energy Company | |
| Unconventional Gas | Includes those gas and oil deposits that originated and are stored in coal bed, tight sandstone and shale formations. | |
| VIE | Variable Interest Entity | |
| Units of Measurement | ||
| Bcf | Billion cubic feet of gas | |
| Bcfe | Conversion metric of natural gas, the ratio of 6 Mcf of gas to 1 barrel of oil. | |
| kWh | Kilowatthour of electricity | |
| Mcf | Thousand cubic feet of gas | |
| MMcf | Million cubic feet of gas | |
| MW | Megawatt of electricity | |
| MWh | Megawatthour of electricity |
2
Table of Contents
Forward-Looking
Statements
Certain information presented herein includes
“forward-looking statements” within the meaning of the
Private Securities Litigation Reform Act of 1995 with respect to
the financial condition, results of operations and business of
DTE Energy. Forward-looking statements are subject to numerous
assumptions, risks and uncertainties that may cause actual
future results to be materially different from those
contemplated, projected, estimated or budgeted. Many factors may
impact forward-looking statements including, but not limited to,
the following:
| • | economic conditions resulting in changes in demand, customer conservation and increased thefts of electricity and gas; | |
| • | changes in the economic and financial viability of our customers, suppliers, and trading counterparties, and the continued ability of such parties to perform their obligations to the Company; | |
| • | economic climate and population changes in the geographic areas where we do business; | |
| • | high levels of uncollectible accounts receivable; | |
| • | access to capital markets and capital market conditions and the results of other financing efforts which can be affected by credit agency ratings; | |
| • | instability in capital markets which could impact availability of short and long-term financing; | |
| • | the timing and extent of changes in interest rates; | |
| • | the level of borrowings; | |
| • | the potential for losses on investments, including nuclear decommissioning and benefit plan assets and the related increases in future expense and contributions; | |
| • | the potential for increased costs or delays in completion of significant construction projects; | |
| • | the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers; | |
| • | environmental issues, laws, regulations, and the increasing costs of remediation and compliance, including actual and potential new federal and state requirements that include or could include carbon and more stringent emission controls, a renewable portfolio standard, energy efficiency mandates, a carbon tax or cap and trade structure and ash landfill regulations; | |
| • | nuclear regulations and operations associated with nuclear facilities; | |
| • | impact of electric and gas utility restructuring in Michigan, including legislative amendments and Customer Choice programs; | |
| • | employee relations and the impact of collective bargaining agreements; | |
| • | unplanned outages; | |
| • | changes in the cost and availability of coal and other raw materials, purchased power and natural gas; | |
| • | volatility in the short-term natural gas storage markets impacting third-party storage revenues; | |
| • | cost reduction efforts and the maximization of plant and distribution system performance; | |
| • | the effects of competition; | |
| • | the uncertainties of successful exploration of gas shale resources and challenges in estimating gas reserves with certainty; | |
| • | impact of regulation by the FERC, MPSC, NRC and other applicable governmental proceedings and regulations, including any associated impact on rate structures; | |
| • | changes in and application of federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits; |
3
Table of Contents
| • | the amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation; | |
| • | the cost of protecting assets against, or damage due to, terrorism or cyber attacks; | |
| • | the availability, cost, coverage and terms of insurance and stability of insurance providers; | |
| • | changes in and application of accounting standards and financial reporting regulations; | |
| • | changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues; and | |
| • | binding arbitration, litigation and related appeals. |
New factors emerge from time to time. We cannot predict what
factors may arise or how such factors may cause our results to
differ materially from those contained in any forward-looking
statement. Any forward-looking statements refer only as of the
date on which such statements are made. We undertake no
obligation to update any forward-looking statement to reflect
events or circumstances after the date on which such statement
is made or to reflect the occurrence of unanticipated events.
4
Table of Contents
Items 1.
and 2.
Business and Properties
General
In 1995, DTE Energy incorporated in the State of Michigan. Our
utility operations consist primarily of Detroit Edison and
MichCon. We also have four other segments that are engaged in a
variety of energy-related businesses.
Detroit Edison is a Michigan corporation organized in 1903 and
is a public utility subject to regulation by the MPSC and the
FERC. Detroit Edison is engaged in the generation, purchase,
distribution and sale of electricity to approximately
2.1 million customers in southeastern Michigan.
MichCon is a Michigan corporation organized in 1898 and is a
public utility subject to regulation by the MPSC. MichCon is
engaged in the purchase, storage, transportation, gathering,
distribution and sale of natural gas to approximately
1.2 million customers throughout Michigan and the sale of
storage and transportation capacity.
Our other segments are involved in 1) natural gas storage
and pipelines; 2) unconventional gas and oil project
development and production; 3) power and industrial
projects; and 4) energy marketing and trading operations.
Our annual reports on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K,
proxy statements, and all amendments to such reports are
available free of charge through the Investor Relations page of
our website:
www.dteenergy.com
, as soon as reasonably
practicable after they are filed with or furnished to the
Securities and Exchange Commission (SEC). Our previously filed
reports and statements are also available at the SEC’s
website:
www.sec.gov
.
The Company’s Code of Ethics and Standards of Behavior,
Board of Directors’ Mission and Guidelines, Board Committee
Charters, and Categorical Standards of Director Independence are
also posted on its website. The information on the
Company’s website is not part of this or any other report
that the Company files with, or furnishes to, the SEC.
Additionally, the public may read and copy any materials the
Company files with the SEC at the SEC’s Public Reference
Room at 100 F Street, NE, Room 1580,
Washington, D.C. 20549. The public may obtain information
on the operation of the Public Reference Room by calling the SEC
at
1-800-SEC-0330.
The SEC also maintains an Internet site that contains reports,
proxy and information statements, and other information
regarding issuers that file electronically with the SEC at
www.sec.gov
.
References in this Report to “we,” “us,”
“our,” “Company” or “DTE” are to
DTE Energy and its subsidiaries, collectively.
Corporate
Structure
Based on the following structure, we set strategic goals,
allocate resources, and evaluate performance. See Note 24
of the Notes to Consolidated Financial Statements in Item 8
of this Report for financial information by segment for the last
three years.
Electric
Utility
| • | The Company’s Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million residential, commercial and industrial customers in southeastern Michigan. |
Gas
Utility
| • | The Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transportation, gathering, distribution and sale of natural gas to approximately 1.2 million residential, commercial and industrial customers throughout Michigan and the sale of storage and transportation capacity. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers. |
5
Table of Contents
Non-Utility
Operations
| • | Gas Storage and Pipelines consists of natural gas storage and pipelines businesses. | |
| • | Unconventional Gas Production is engaged in unconventional gas and oil project development and production. | |
| • | Power and Industrial Projects is comprised of coke batteries and pulverized coal projects, reduced emission fuel and steel industry fuel-related projects, on-site energy services, renewable power generation, landfill gas recovery and coal transportation, marketing and trading. | |
| • | Energy Trading consists of energy marketing and trading operations. |
Corporate & Other
, includes various holding
company activities, holds certain non-utility debt and
energy-related
investments.
Refer to our Management’s Discussion and Analysis in
Item 7 of this Report for an in-depth analysis of each
segment’s financial results. A description of each business
unit follows.
ELECTRIC
UTILITY
Description
Our Electric Utility segment consists of Detroit Edison. Our
generating plants are regulated by numerous federal and state
governmental agencies, including, but not limited to, the MPSC,
the FERC, the NRC, the EPA and the MDNRE. Electricity is
generated from our several fossil plants, a hydroelectric pumped
storage plant and a nuclear plant, and is purchased from
electricity generators, suppliers and wholesalers. The
electricity we produce and purchase is sold to three major
classes of customers: residential, commercial and industrial,
principally throughout southeastern Michigan.
Revenue
by Service
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Residential
|
$ | 2,052 | $ | 1,820 | $ | 1,726 | ||||||
|
Commercial
|
1,629 | 1,702 | 1,753 | |||||||||
|
Industrial
|
688 | 730 | 894 | |||||||||
|
Other
|
479 | 299 | 289 | |||||||||
|
Subtotal
|
4,848 | 4,551 | 4,662 | |||||||||
|
Interconnection sales(1)
|
145 | 163 | 212 | |||||||||
|
Total Revenue
|
$ | 4,993 | $ | 4,714 | $ | 4,874 | ||||||
| (1) | Represents power that is not distributed by Detroit Edison. |
6
Table of Contents
Weather, economic factors, competition and electricity prices
affect sales levels to customers. Our peak load and highest
total system sales generally occur during the third quarter of
the year, driven by air conditioning and other cooling-related
demands. Our operations are not dependent upon a limited number
of customers, and the loss of any one or a few customers would
not have a material adverse effect on Detroit Edison.
Fuel
Supply and Purchased Power
Our power is generated from a variety of fuels and is
supplemented with purchased power. We expect to have an adequate
supply of fuel and purchased power to meet our obligation to
serve customers. Our generating capability is heavily dependent
upon the availability of coal. Coal is purchased from various
sources in different geographic areas under agreements that vary
in both pricing and terms. We expect to obtain the majority of
our coal requirements through long-term contracts, with the
balance to be obtained through short-term agreements and spot
purchases. We have long-term and short-term contracts for a
total purchase of approximately 30 million tons of
low-sulfur western coal to be delivered from 2011 through 2013
and approximately 5 million tons of Appalachian coal to be
delivered from 2011 through 2012. All of these contracts have
pricing schedules. We have approximately 98% of our 2011
expected coal requirements under contract. Given the geographic
diversity of supply, we believe we can meet our expected
generation requirements. We lease a fleet of rail cars and have
our expected western rail requirements under contract for the
next five years. All of our eastern coal rail requirements are
under contract through 2012 and approximately 50% of this
requirement is under contract in 2013. Our expected vessel
transportation requirements for delivery of purchased coal to
our generating facilities are under contract through 2014.
Detroit Edison participates in the energy market through MISO.
We offer our generation in the market on a day-ahead, real-time
and FTR basis and bid for power in the market to serve our load.
We are a net purchaser of power that supplements our generation
capability to meet customer demand during peak cycles.
In 2008, a renewable portfolio standard was established for
Michigan electric providers targeting 10% of electricity sold to
retail customers from renewable energy by 2015. Detroit Edison
has approximately 251 MW of renewable energy under contract
at December 31, 2010 representing approximately 4% of
electricity sold to retail customers. Approximately 40 MW
is in commercial operation at December 31, 2010 with an
additional 211 MW expected in commercial operation in 2011
or early 2012.
Properties
Detroit Edison owns generating plants and facilities that are
located in the State of Michigan. Substantially all of our
property is subject to the lien of a mortgage.
7
Table of Contents
Generating plants owned and in service as of December 31,
2010 are as follows:
|
Summer Net
|
||||||||||||||
|
Location by
|
Rated
|
|||||||||||||
|
Michigan
|
Capability(1) | |||||||||||||
| Plant Name | County | (MW) | (%) | Year in Service | ||||||||||
|
Fossil-fueled Steam-Electric
|
||||||||||||||
|
Belle River(2)
|
St. Clair | 1,044 | 9.5 | 1984 and 1985 | ||||||||||
|
Conners Creek
|
Wayne | 239 | 2.1 | 1951 | ||||||||||
|
Greenwood
|
St. Clair | 785 | 7.1 | 1979 | ||||||||||
|
Harbor Beach
|
Huron | 94 | 0.9 | 1968 | ||||||||||
|
Marysville
|
St. Clair | 84 | 0.8 | 1943 and 1947 | ||||||||||
|
Monroe(3)
|
Monroe | 3,027 | 27.6 | 1971, 1973 and 1974 | ||||||||||
|
River Rouge
|
Wayne | 523 | 4.8 | 1957 and 1958 | ||||||||||
|
St. Clair(4)
|
St. Clair | 1,368 | 12.5 | 1953, 1954, 1959, 1961 and 1969 | ||||||||||
|
Trenton Channel
|
Wayne | 698 | 6.4 | 1949 and 1968 | ||||||||||
| 7,862 | 71.7 | |||||||||||||
|
Oil or Gas-fueled Peaking Units
|
Various | 1,101 | 10.0 | 1966-1971, 1981 and 1999 | ||||||||||
|
Nuclear-fueled Steam-Electric Fermi 2(5)
|
Monroe | 1,087 | 9.9 | 1988 | ||||||||||
|
Hydroelectric Pumped Storage
Ludington(6) |
Mason | 917 | 8.4 | 1973 | ||||||||||
| 10,967 | 100.0 | |||||||||||||
| (1) | Summer net rated capabilities of generating plants in service are based on periodic load tests and are changed depending on operating experience, the physical condition of units, environmental control limitations and customer requirements for steam, which otherwise would be used for electric generation. | |
| (2) | The Belle River capability represents Detroit Edison’s entitlement to 81% of the capacity and energy of the plant. See Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of this Report. | |
| (3) | The Monroe power plant provided 38% of Detroit Edison’s total 2010 power generation. | |
| (4) | Excludes one oil-fueled unit (250 MW) in cold standby status. | |
| (5) | Fermi 2 has a design electrical rating (net) of 1,150 MW. | |
| (6) | Represents Detroit Edison’s 49% interest in Ludington with a total capability of 1,872 MW. See Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of this Report. |
Detroit Edison owns and operates 674 distribution substations
with a capacity of approximately 33,585,000
kilovolt-amperes
(kVA) and approximately 412,100 line transformers with a
capacity of approximately 23,849,000 kVA.
Circuit miles of electric distribution lines owned and in
service as of December 31, 2010:
| Circuit Miles | ||||||||
| Operating Voltage-Kilovolts (kV) | Overhead | Underground | ||||||
|
4.8 kV to 13.2 kV
|
28,345 | 13,916 | ||||||
|
24 kV
|
181 | 696 | ||||||
|
40 kV
|
2,278 | 381 | ||||||
|
120 kV
|
54 | 13 | ||||||
| 30,858 | 15,006 | |||||||
8
Table of Contents
There are numerous interconnections that allow the interchange
of electricity between Detroit Edison and electricity providers
external to our service area. These interconnections are
generally owned and operated by ITC Transmission, an unrelated
company, and connect to neighboring energy companies.
Regulation
Detroit Edison’s business is subject to the regulatory
jurisdiction of various agencies, including, but not limited to,
the MPSC, the FERC and the NRC. The MPSC issues orders
pertaining to rates, recovery of certain costs, including the
costs of generating facilities and regulatory assets, conditions
of service, accounting and operating-related matters. Detroit
Edison’s MPSC-approved rates charged to customers have
historically been designed to allow for the recovery of costs,
plus an authorized rate of return on our investments. The FERC
regulates Detroit Edison with respect to financing authorization
and wholesale electric activities. The NRC has regulatory
jurisdiction over all phases of the operation, construction,
licensing and decommissioning of Detroit Edison’s nuclear
plant operations. We are subject to the requirements of other
regulatory agencies with respect to safety, the environment and
health.
See Notes 4, 9, 12 and 20 of the Notes to Consolidated
Financial Statements in Item 8 of this Report.
Energy
Assistance Programs
Energy assistance programs, funded by the federal government and
the State of Michigan, remain critical to Detroit Edison’s
ability to control its uncollectible accounts receivable and
collections expenses. Detroit Edison’s uncollectible
accounts receivable expense is directly affected by the level of
government-funded assistance its qualifying customers receive.
We work continuously with the State of Michigan and others to
determine whether the share of funding allocated to our
customers is representative of the number of low-income
individuals in our service territory.
Strategy
and Competition
We strive to be the preferred supplier of electrical generation
in southeast Michigan. We can accomplish this goal by working
with our customers, communities and regulatory agencies to be a
reliable, low-cost supplier of electricity. To ensure generation
and network reliability we continue to make capital investments
in our generating plants and distribution system, which will
improve plant availability, operating efficiencies and
environmental compliance in areas that have a positive impact on
reliability with the goal of high customer satisfaction.
Our distribution operations focus on improving reliability,
restoration time and the quality of customer service. We seek to
lower our operating costs by improving operating efficiencies.
Revenues from year to year will vary due to weather conditions,
economic factors, regulatory events and other risk factors as
discussed in the “Risk Factors” in Item 1A. of
this Report. We are minimizing the impacts of changes in average
customer usage through regulatory mechanisms which decouple our
revenue levels from sales volumes.
The electric Customer Choice program in Michigan allows all of
our electric customers to purchase their electricity from
alternative electric suppliers of generation services, subject
to limits. Customers choosing to purchase power from alternative
electric suppliers represented approximately 10% of retail sales
in 2010 and 3% of retail sales in 2009 and 2008. Customers
participating in the electric Customer Choice program consist
primarily of industrial and commercial customers whose
MPSC-authorized full service rates exceed their cost of service.
MPSC rate orders and 2008 energy legislation enacted by the
State of Michigan are adjusting the pricing disparity over five
years and have placed a 10% cap on the total potential Customer
Choice related migration, mitigating some of the unfavorable
effects of electric Customer Choice on our financial
performance. In addition, we have a Choice Incentive Mechanism,
which is an over/under recovery mechanism that measures non-fuel
revenues lost or gained as a result of fluctuations in electric
Customer Choice sales. If annual electric Customer Choice sales
exceed the baseline amount from Detroit Edison’s most
recent rate case, 90 percent of its lost non-fuel revenues
associated with sales above that level may be recovered from
full service customers. If annual electric Customer Choice sales
decrease below the baseline, the Company must refund
90 percent of its increase in non-fuel revenues associated
with sales below that level to full service customers. We expect
that in 2011 customers choosing to purchase power from
alternative electric suppliers will represent approximately 10%
of retail sales.
9
Table of Contents
Competition in the regulated electric distribution business is
primarily from the
on-site
generation of industrial customers and from distributed
generation applications by industrial and commercial customers.
We do not expect significant competition for distribution to any
group of customers in the near term.
GAS
UTILITY
Description
Our Gas Utility segment consists of MichCon and Citizens.
Revenue is generated by providing the following major classes of
service: gas sales, end user transportation, intermediate
transportation, and gas storage.
Revenue
by Service
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Gas sales
|
$ | 1,281 | $ | 1,443 | $ | 1,824 | ||||||
|
End user transportation
|
185 | 144 | 143 | |||||||||
|
Intermediate transportation
|
69 | 69 | 73 | |||||||||
|
Storage and other
|
113 | 132 | 112 | |||||||||
|
Total Revenue
|
$ | 1,648 | $ | 1,788 | $ | 2,152 | ||||||
| • | Gas sales — Includes the sale and delivery of natural gas primarily to residential and small-volume commercial and industrial customers. | |
| • | End user transportation — Gas delivery service provided primarily to large-volume commercial and industrial customers. Additionally, the service is provided to residential customers, and small-volume commercial and industrial customers who have elected to participate in our Customer Choice program. End user transportation customers purchase natural gas directly from producers or brokers and utilize our pipeline network to transport the gas to their facilities or homes. | |
| • | Intermediate transportation — Gas delivery service is provided to producers, brokers and other gas companies that own the natural gas, but are not the ultimate consumers. Intermediate transportation customers utilize our gathering and high-pressure transportation system to transport the gas to storage fields, processing plants, pipeline interconnections or other locations. | |
| • | Storage and other — Includes revenues from gas storage, appliance maintenance, facility development and other energy-related services. |
Our gas sales, end user transportation and intermediate
transportation volumes, revenues and net income are impacted by
weather. Given the seasonal nature of our business, revenues and
net income are concentrated in the first and fourth quarters of
the calendar year. By the end of the first quarter, the heating
season is largely over, and we typically realize substantially
reduced revenues and earnings in the second quarter and losses
in the third quarter. We are minimizing the impacts of changes
in average customer usage through regulatory mechanisms which
decouple our revenue levels from sales volumes.
Our operations are not dependent upon a limited number of
customers, and the loss of any one or a few customers would not
have a material adverse effect on our Gas Utility segment.
Natural
Gas Supply
Our gas distribution system has a planned maximum daily send-out
capacity of 2.4 Bcf, with approximately 65% of the volume
coming from underground storage for 2010. Peak-use requirements
are met through utilization of our storage facilities, pipeline
transportation capacity, and purchased gas supplies. Because of
our geographic diversity of supply and our pipeline
transportation and storage capacity, we are able to reliably
meet our supply
10
Table of Contents
requirements. We believe natural gas supply and pipeline
capacity will be sufficiently available to meet market demands
in the foreseeable future.
We purchase natural gas supplies in the open market by
contracting with producers and marketers, and we maintain a
diversified portfolio of natural gas supply contracts. Supplier,
producing region, quantity, and available transportation
diversify our natural gas supply base. We obtain our natural gas
supply from various sources in different geographic areas (Gulf
Coast, Mid-Continent, Canada and Michigan) under agreements that
vary in both pricing and terms. Gas supply pricing is generally
tied to the New York Mercantile Exchange and published price
indices to approximate current market prices combined with MPSC
approved fixed price supplies with varying terms and volumes
through 2014.
We are directly connected to interstate pipelines, providing
access to most of the major natural gas supply producing regions
in the Gulf Coast, Mid-Continent and Canadian regions. Our
primary long-term transportation supply contracts are as follows:
|
Availability
|
Contract
|
|||||||
| (MMcf/d) | Expiration | |||||||
|
Vector Pipeline L.P.
|
50 | 2012 | ||||||
|
Great Lakes Gas Transmission L.P.
|
80 | 2013 | ||||||
|
Viking Gas Transmission Company
|
51 | 2013 | ||||||
|
ANR Pipeline Company
|
195 | 2017 | ||||||
|
Panhandle Eastern Pipeline Company
|
75 | 2029 | ||||||
Properties
We own distribution, storage and transportation properties that
are located in the State of Michigan. Our distribution system
includes approximately 19,000 miles of distribution mains,
approximately 1,036,000 service lines and approximately
1,319,000 active meters. We own approximately 2,000 miles
of transportation lines that deliver natural gas to the
distribution districts and interconnect our storage fields with
the sources of supply and the market areas.
We own properties relating to four underground natural gas
storage fields with an aggregate working gas storage capacity of
approximately 134 Bcf. These facilities are important in
providing reliable and cost-effective service to our customers.
In addition, we sell storage services to third parties. Most of
our distribution and transportation property is located on
property owned by others and used by us through easements,
permits or licenses. Substantially all of our property is
subject to the lien of a mortgage.
We own 602 miles of transportation and gathering
(non-utility) pipelines in the northern lower peninsula of
Michigan. We lease a portion of our pipeline system to the
Vector Pipeline Partnership (an affiliate) through a capital
lease arrangement. See Note 19 of the Notes to Consolidated
Financial Statements in Item 8 of the Report.
Regulation
MichCon’s business is subject to the regulatory
jurisdiction of the MPSC, which issues orders pertaining to
rates, recovery of certain costs, including the costs of
regulatory assets, conditions of service, accounting and
operating-related matters. MichCon’s MPSC-approved rates
charged to customers have historically been designed to allow
for the recovery of costs, plus an authorized rate of return on
our investments. MichCon operates natural gas storage and
transportation facilities in Michigan as intrastate facilities
regulated by the MPSC and provides intrastate storage and
transportation services pursuant to an MPSC-approved tariff.
MichCon also provides interstate storage and transportation
services in accordance with an Operating Statement on file with
the FERC. The FERC’s jurisdiction is limited and extends to
the rates, non-discriminatory requirements and terms and
conditions applicable to storage and transportation provided by
MichCon in interstate markets. FERC granted MichCon authority to
provide storage and related services in interstate commerce at
market-based rates. MichCon provides transportation services in
interstate commerce at cost-based rates approved by the MPSC and
filed with the FERC.
We are subject to the requirements of other regulatory agencies
with respect to safety, the environment and health.
See Note 12 of the Notes to the Consolidated Financial
Statements in Item 8 of this Report.
11
Table of Contents
Energy
Assistance Program
Energy assistance programs, funded by the federal government and
the State of Michigan, remain critical to MichCon’s ability
to control its uncollectible accounts receivable and collections
expenses. MichCon’s uncollectible accounts receivable
expense is directly affected by the level of government-funded
assistance its qualifying customers receive. We work
continuously with the State of Michigan and others to determine
whether the share of funding allocated to our customers is
representative of the number of low-income individuals in our
service territory.
Strategy
and Competition
Our strategy is to be the preferred provider of natural gas in
Michigan. We expect future sales volumes to decline as a result
of economic conditions, a decrease in the number of customers,
reduced natural gas usage by customers due to more efficient
furnaces and appliances, and an increased emphasis on
conservation of energy usage. We are minimizing the impacts of
changes in average customer usage through regulatory mechanisms
which decouple our revenue levels from sales volumes. We
continue to provide energy-related services that capitalize on
our expertise, capabilities and efficient systems. We continue
to focus on lowering our operating costs by improving operating
efficiencies.
Competition in the gas business primarily involves other natural
gas providers, as well as providers of alternative fuels and
energy sources. The primary focus of competition for end user
transportation is cost and reliability. Some large commercial
and industrial customers have the ability to switch to
alternative fuel sources such as coal, electricity, oil and
steam. If these customers were to choose an alternative fuel
source, they would not have a need for our end-user
transportation service. In addition, some of these customers
could bypass our pipeline system and have their gas delivered
directly from an interstate pipeline. We compete against
alternative fuel sources by providing competitive pricing and
reliable service, supported by our storage capacity.
Our extensive transportation pipeline system has enabled us to
market 400 to 500 Bcf annually for intermediate storage and
transportation services for Michigan gas producers, marketers,
distribution companies and other pipeline companies. We operate
in a central geographic location with connections to major
Midwestern interstate pipelines that extend throughout the
Midwest, eastern United States and eastern Canada.
MichCon’s storage capacity is used to store natural gas for
delivery to MichCon’s customers as well as sold to third
parties, under a variety of arrangements for periods up to three
years. Prices for storage arrangements for shorter periods are
generally higher, but more volatile than for longer periods.
Prices are influenced primarily by market conditions and natural
gas pricing.
GAS
STORAGE AND PIPELINES
Description
Gas Storage and Pipelines owns partnership interests in two
interstate transmission pipelines and two natural gas storage
fields. The pipeline and storage assets are primarily supported
by long-term, fixed-price revenue contracts. We have a
partnership interest in Vector Pipeline (Vector), an interstate
transportation pipeline, which connects Michigan to Chicago and
Ontario. We also hold partnership interests in Millennium
Pipeline Company which indirectly connects southern New York
State to Upper Midwest/Canadian supply, while providing
transportation service into the New York City markets. We have
storage assets in Michigan capable of storing up to 90 Bcf
in natural gas storage fields located in Southeast Michigan. The
Washington 10 and 28 storage facilities are high deliverability
storage fields having bi-directional interconnections with
Vector Pipeline and MichCon, providing our customers access to
the Chicago, Michigan, other Midwest and Ontario markets. Our
customers include various utilities, pipelines, and producers
and marketers.
12
Table of Contents
Properties
The Gas Storage and Pipelines business holds the following
property:
|
Property
|
||||||||
| Classification | % Owned | Description | Location | |||||
|
Pipelines
|
||||||||
|
Vector Pipeline
|
40% | 348-mile pipeline with 1,300 MMcf per day capacity | IL, IN, MI & Ontario | |||||
|
Millennium Pipeline
|
26% | 182-mile pipeline with 525 MMcf per day capacity | New York | |||||
|
Storage
|
||||||||
|
Washington 10 (includes
|
||||||||
|
Shelby 2 Storage)
|
100% | 74 Bcf of storage capacity | MI | |||||
|
Washington 28
|
50% | 16 Bcf of storage capacity | MI | |||||
The assets of these businesses are well integrated with other
DTE Energy operations. Pursuant to an operating agreement,
MichCon provides physical operations, maintenance, and technical
support for the Washington 28 and Washington 10 storage
facilities.
Regulation
The Gas Storage and Pipelines business operates natural gas
storage facilities in Michigan as intrastate facilities
regulated by the MPSC and provides intrastate storage and
related services pursuant to an MPSC-approved tariff. We also
provide interstate services in accordance with an Operating
Statement on file with the FERC. Vector and Millennium Pipelines
provide interstate transportation services in accordance with
their FERC-approved tariffs.
Strategy
and Competition
Our Gas Storage and Pipelines business expects to continue its
steady growth plan by expanding existing assets and developing
new assets that are typically supported with long-term customer
commitments. The Gas Storage and Pipelines business focuses on
asset development opportunities in the
Midwest-to-Northeast
region to supply natural gas to meet growing demand. We expect
much of the growth in the demand for natural gas in the
U.S. to occur within the Mid-Atlantic and New England
regions. We forecast these regions will require incremental
pipeline and gas storage infrastructure necessary to deliver gas
volumes to meet growing demand. Vector is an interstate pipeline
that is filling a large portion of that need, and is
complemented by our Michigan storage facilities. Due to the
proximity of the Millennium Pipeline to the Marcellus shale in
Southern New York/Northern Pennsylvania, we anticipate that the
Millennium Pipeline may have opportunities to expand in the
future.
UNCONVENTIONAL
GAS PRODUCTION
Description
Our Unconventional Gas Production business is engaged in natural
gas and oil exploration, development and production primarily
within the Barnett shale in north Texas. Our acreage covers an
area that produces high Btu gas which provides a significant
contribution to revenues from the value of natural gas liquids
extracted from the gas stream. During this period of low natural
gas prices, these natural gas liquids, with prices correlated to
crude oil prices, have provided a significant increase to our
realized wellhead price. Our drilling efforts this year have and
will continue to target liquids rich gas and oil producing
locations. Total capital investment of $26 million and
production of 5 Bcfe remained consistent with 2009. We
executed on leasing opportunities to optimize our existing
portfolio by acquiring acreage at attractive prices in 2010,
bringing our total net acreage position to 70,246 acres,
net of impairments and expirations.
13
Table of Contents
Properties
and Other
The following information pertains to our interests in the
Barnett shale as of December 31:
| 2010 | 2009 | 2008 | ||||||||||
|
Producing Wells(1)(2)(3)
|
194 | 174 | 162 | |||||||||
|
Developed Lease Acreage(1)(3)(4)
|
15,928 | 14,968 | 14,248 | |||||||||
|
Undeveloped Lease Acreage(1)(3)(5)
|
54,318 | 48,399 | 46,187 | |||||||||
|
Production Volume (Bcfe)
|
4.8 | 5.0 | 5.0 | |||||||||
|
Proved Reserves (Bcfe)(6)
|
201 | 234 | 167 | |||||||||
|
Capital Expenditures (in millions)(3)
|
$ | 26 | $ | 26 | $ | 100 | ||||||
|
Future Undiscounted Cash Flows (in millions)(7)
|
$ | 478 | $ | 392 | $ | 324 | ||||||
|
Average Gas Price, excluding hedge contracts (per Mcf)
|
$ | 5.99 | $ | 4.34 | $ | 8.69 | ||||||
|
Average Oil Price, excluding hedge contracts (per Barrel)
|
$ | 76.41 | $ | 58.47 | $ | 90.27 | ||||||
| (1) | Excludes the interest of others. | |
| (2) | Producing wells are the number of wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. | |
| (3) | Excludes sold and impaired properties. | |
| (4) | Developed lease acreage is the number of acres that are allocated or assignable to productive wells or wells capable of production. | |
| (5) | Undeveloped lease acreage is the number of acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves. | |
| (6) | The decrease in proved reserves in 2010 is primarily due to removal of reserves that exceeded the five-year development limit for the Proved Undeveloped classification, and other revisions to estimates. The increases in proved reserves in 2009 are primarily due to a definitional change in the disclosure rule issued by the SEC and technological improvements. | |
| (7) | Represents the standardized measure of undiscounted future net cash flows utilizing extensive estimates. The estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves and do not include the impact of hedge contracts. |
Strategy
and Competition
Outlook —
In the longer-term, we plan to
continue to develop our holdings in the western portion of the
Barnett shale and to seek opportunities for additional
monetization of select properties when conditions are
appropriate. Our strategy for 2011 is to maintain our focus on
reducing operating expenses and optimizing production volume.
Given the current outlook of low natural gas prices, drilling
efforts will continue to target liquids rich gas and oil
production. During 2011, we expect total capital investment of
$25 million to drill approximately 20 new wells and
continue to acquire select acreage and achieve production of
approximately 6 Bcfe of natural gas, compared with
5 Bcfe in 2010.
We manage and operate our properties to maximize returns on
investment and increase earnings. We expect to continue
acquiring additional acreage at attractive prices providing
opportunities to create value at low cost. We will target
properties with liquids rich gas and oil potential and our
drilling efforts will continue to be focused on these areas. Due
to increased activity in other shale plays throughout the
country, the availability of service providers has decreased
somewhat. However, we do not expect this to have a significant
impact on our drilling plans or operations, since most oilfield
services have been secured for the next 12 months.
From time to time, we may use financial derivative contracts to
manage a portion of our exposure to changes in the price of
natural gas and oil on our forecasted sales volume. At
December 31, 2010, we had no long-term fixed
14
Table of Contents
price contracts relating to natural gas and had the following
financial contracts in place with our Energy Trading affiliate
related to our projected oil production:
| 2011 | ||||
|
Oil Volume (in MBbl)
|
72 | |||
|
Price (in Bbl)
|
$ | 93.28 | ||
POWER AND
INDUSTRIAL PROJECTS
Description
Power and Industrial Projects is comprised primarily of projects
that deliver energy products and services to industrial,
commercial and institutional customers; provide coal
transportation and marketing; and sell electricity from
biomass-fired energy projects. This business segment provides
services using project assets usually located on or near the
customers’ premises in the steel, automotive, pulp and
paper, airport and other industries as follows:
Steel, Steel Industry Fuel, and Petroleum
Coke:
We produce metallurgical coke from two coke
batteries with a capacity of 1.4 million tons per year. We
have an investment in a third coke battery with a capacity of
1.2 million tons per year. We are investors in steel
industry fuel entities which sell steel industry fuel at three
coke battery sites. Steel industry fuels facilities recycle tar
decanter sludge, a byproduct of the coking process. Tax credits
were generated in 2009 and 2010. The ability to generate tax
credits from the steel industry fuel process expired at
December 31, 2010. We also provide pulverized coal and
petroleum coke to the steel, pulp and paper, and other
industries.
Onsite Energy:
We provide power generation,
steam production, chilled water production, wastewater treatment
and compressed air supply to industrial customers. This business
segment provides utility-type services using project assets
usually located on or near the customers’ premises in the
automotive, airport and other industries.
Wholesale Power and Renewables:
We own and
operate three biomass-fired electric generating plants with a
capacity of 133 MWs. We own two coal-fired power plants
currently undergoing conversions to biomass with expected
in-service dates of the fourth quarter of 2011 and the first
quarter of 2013. We own one gas-fired peaking electric
generating plant. The electric output is sold under long term
power purchase agreements. We also develop landfill gas recovery
systems that capture the gas and provide local utilities,
industry and consumers with an opportunity to use a competitive,
renewable source of energy, in addition to providing
environmental benefits by reducing greenhouse gas emissions.
Reduced Emission Fuel:
We deliver reduced
emission fuel to utilities with coal-fired electric generation
power plants. We own and operate five facilities that process
raw coal into reduced emission fuel resulting in reductions in
Nitrogen Oxide (NO) and Mercury (Hg) emissions. We began
generating production tax credits from these facilities
beginning in 2009 which will continue through 2019 upon
achieving certain criteria, including entering into transactions
with unrelated equity partners or third-party customers for the
reduced emission fuel. We continue to optimize these facilities
by seeking investors for facilities operating at Detroit Edison
sites, and intend to relocate other facilities to alternative
sites which may provide increased production and emission
reduction opportunities in 2011 and future years. In January
2011, the Company entered into an agreement to sell a membership
interest in one of these reduced emission fuel facilities that
is located at a Detroit Edison site.
Coal Services:
The business provides coal
transportation and related services including fuel to our
customers with significant energy requirements which include
electric utilities, merchant power producers, integrated steel
mills and large industrial companies. We specialize in
minimizing fuel costs and maximizing reliability of supply for
those energy-intensive customers. We own and operate a coal
transloading terminal which provides storage and blending for
our customers. We also engage in coal marketing which includes
the marketing and trading of physical coal and coal financial
instruments, and forward contracts for the purchase and sale of
emission allowances.
15
Table of Contents
Properties
and Other
The following are significant properties operated by the Power
and Industrial projects segment:
| Facility | Location | Service Type | ||
|
Steel
|
||||
|
Pulverized Coal Operations
|
MI & MD | Pulverized Coal | ||
|
Coke Production
|
MI, PA & IN | Metallurgical Coke Supply/Steel Industry Fuels | ||
|
Other Investment in Coke Production and Petroleum Coke
|
IN & MS | Metallurgical Coke Supply/Steel Industry Fuels, and Pulverized Petroleum Coke | ||
|
On-Site
Energy
|
||||
|
Automotive
|
Various sites in | Electric Distribution, Chilled | ||
|
MI, IN, OH,
NY & PA |
Water, Waste Water, Steam, Cooling Tower Water, Reverse Osmosis Water, Compressed Air, Mist and Dust Collectors, | |||
| Steam and Chilled Water | ||||
|
Airports
|
MI & PA | Electricity, Hot and Chilled Water | ||
|
Wholesale Power & Renewables
|
||||
|
Pulp and Paper
|
AL | Electric Generation and Steam | ||
|
Power Generation
|
MI | Electric Peaking | ||
|
Renewables
|
CA & WI | Electric Generation | ||
|
Landfill Gas Recovery
|
Various U.S. Sites | Electric generation | ||
|
Other Industries
|
||||
|
Reduced Emission Fuel
|
MI | Reduced Emission Fuel Supply | ||
|
Coal Terminaling
|
IL | Coal Terminal and Blending |
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Production Tax Credits Generated (Allocated to DTE Energy)
|
||||||||||||
|
Coke Battery(1)
|
$ | — | $ | 5 | $ | 5 | ||||||
|
Steel Industry Fuels(2)
|
29 | 4 | — | |||||||||
|
Power Generation
|
2 | 2 | 2 | |||||||||
|
Landfill Gas Recovery
|
1 | 1 | — | |||||||||
|
Reduced Emission Fuel
|
1 | — | — | |||||||||
| (1) | Tax laws enabling production tax credits related to two coke battery facilities expired on December 31, 2009. | |
| (2) | IRS regulations enabling the steel industry fuel tax credits expired on December 31, 2010. |
Regulation
Certain electric generating facilities within Power and
Industrial Projects have market-based rate authority from the
FERC to sell power. The facilities are subject to FERC reporting
requirements and market behavior rules. Certain Power and
Industrial projects are also subject to the applicable laws,
rules and regulations related to the Commodity Futures Trading
Commission, U.S. Department of Homeland Security and
Department of Energy.
16
Table of Contents
Strategy
and Competition
Power and Industrial Projects will continue leveraging its
energy-related operating experience and project management
capability to develop and grow our steel; renewable power;
on-site
energy; coal marketing, storage and blending; landfill gas
recovery; and reduced emission fuel businesses. We also will
continue to pursue opportunities to provide asset management and
operations services to third parties. There are limited
competitors for our existing disparate businesses who provide
similar products and services.
We anticipate building around our core strengths in the markets
where we operate. In determining the markets in which to
compete, we examine closely the regulatory and competitive
environment, new and pending legislation, the number of
competitors and our ability to achieve sustainable margins. We
plan to maximize the effectiveness of our inter-related
businesses as we expand. As we pursue growth opportunities, our
first priority will be to achieve value-added returns.
We intend to focus on the following areas for growth:
| • | Monetizing and relocating our reduced emission fuel facilities; | |
| • | Acquiring and developing landfill gas recovery facilities, renewable energy projects, and other energy projects which may qualify for tax credits; and | |
| • | Providing operating services to owners of industrial and power plants. |
Our Coal Transportation and Marketing business will continue to
leverage its existing business in 2011. Trends such as railroad
and mining consolidation and the lack of certainty in developing
new mines could have an impact on how we compete in the future.
Effective January 1, 2011, our existing long-term rail
transportation contract, at rates significantly below the
current market, expired and we anticipate a decrease in
transportation-related revenue of approximately
$130 million as a result. We will continue to work with
suppliers and the railroads to promote secure and competitive
access to coal to meet the energy requirements of our customers.
ENERGY
TRADING
Description
Energy Trading focuses on physical and financial power and gas
marketing and trading, structured transactions, enhancement of
returns from DTE Energy’s asset portfolio, optimization of
contracted natural gas pipeline transportation and storage, and
power transmission and generating capacity positions. Energy
Trading also provides natural gas, power and ancillary services
to various utilities which may include the management of
associated storage and transportation contracts on the
customers’ behalf. Our customer base is predominantly
utilities, local distribution companies, pipelines, and other
marketing and trading companies. We enter into derivative
financial instruments as part of our marketing and hedging
activities. These financial instruments are generally accounted
for under the
mark-to-market
method, which results in the recognition in earnings of
unrealized gains and losses from changes in the fair value of
the derivatives. We utilize forwards, futures, swaps and option
contracts to mitigate risk associated with our marketing and
trading activity as well as for proprietary trading within
defined risk guidelines. Energy Trading also provides commodity
risk management services to the other businesses within DTE
Energy.
Significant portions of the Energy Trading portfolio are
economically hedged. Most financial instruments and physical
power and gas contracts are deemed derivatives; whereas, gas
inventory, power transmission, pipeline transportation and
certain storage assets are not derivatives. As a result, this
segment may experience earnings volatility as derivatives are
marked-to-market
without revaluing the underlying non-derivative contracts and
assets. The segment’s strategy is to economically manage
the price risk of these underlying non-derivative contracts and
assets with futures, forwards, swaps and options. This results
in gains and losses that are recognized in different interim and
annual accounting periods.
Regulation
Energy Trading has market-based rate authority from the FERC to
sell power and blanket authority from the FERC to sell natural
gas at market prices. Energy Trading is subject to FERC
reporting requirements and market
17
Table of Contents
behavior rules. Energy Trading is also subject to the applicable
laws, rules and regulations related to the Commodity Futures
Trading Commission, U.S. Department of Homeland Security
and Department of Energy.
Strategy
and Competition
Our strategy for the energy trading business is to deliver
value-added services to our customers. We seek to manage this
business in a manner consistent with and complementary to the
growth of our other business segments. We focus on physical
marketing and the optimization of our portfolio of energy
assets. We compete with electric and gas marketers, financial
institutions, traders, utilities and other energy providers. The
trading business is dependent upon the availability of capital
and an investment grade credit rating. The Company believes it
has ample available capital capacity to support Energy Trading
activities. We monitor our use of capital closely to ensure that
our commitments do not exceed capacity. A material credit
restriction would negatively impact our financial performance.
Competitors with greater access to capital or at a lower cost
may have a competitive advantage. We have risk management and
credit processes to monitor and mitigate risk.
CORPORATE &
OTHER
Description
Corporate & Other includes various holding company
activities and holds certain non-utility debt and energy-related
investments.
ENVIRONMENTAL
MATTERS
We are subject to extensive environmental regulation. Additional
costs may result as the effects of various substances on the
environment are studied and governmental regulations are
developed and implemented. Actual costs to comply could vary
substantially. We expect to continue recovering environmental
costs related to utility operations through rates charged to our
customers. The following table summarizes our estimated
significant future environmental expenditures based upon current
regulations:
| Electric | Gas | Non-Utility | Total | |||||||||||||
| (In millions) | ||||||||||||||||
|
Air
|
$ | 2,100 | $ | — | $ | — | $ | 2,100 | ||||||||
|
Water
|
55 | — | 13 | 68 | ||||||||||||
|
MGP sites
|
4 | 36 | — | 40 | ||||||||||||
|
Other sites
|
21 | 1 | — | 22 | ||||||||||||
|
Estimated total future expenditures through 2020
|
$ | 2,180 | $ | 37 | $ | 13 | $ | 2,230 | ||||||||
|
Estimated 2011 expenditures
|
$ | 239 | $ | 11 | $ | 3 | $ | 253 | ||||||||
|
Estimated 2012 expenditures
|
$ | 276 | $ | 7 | $ | 7 | $ | 290 | ||||||||
Air —
Detroit Edison is subject to the EPA
ozone transport and acid rain regulations that limit power plant
emissions of sulfur dioxide and nitrogen oxides. Since 2005, the
EPA and the State of Michigan have issued additional emission
reduction regulations relating to ozone, fine particulate,
regional haze and mercury air pollution. The new rules will lead
to additional controls on fossil-fueled power plants to reduce
nitrogen oxide, sulfur dioxide and mercury emissions. Further,
additional rulemakings are expected over the next few years
which could require additional controls for sulfur dioxide,
nitrogen oxides and hazardous air pollutants. It is not possible
to quantify the impact of those expected rulemakings at this
time.
In July 2009, DTE Energy received a Notice of Violation/Finding
of Violation (NOV/FOV) from the EPA alleging, among other
things, that five Detroit Edison power plants violated New
Source Performance standards, Prevention of Significant
Deterioration requirements, and operating permit requirements
under the Clean Air Act. An additional NOV/FOV was received in
June 2010 related to a recent project and outage at Unit 2 of
the Monroe Power Plant.
18
Table of Contents
On August 5, 2010, the United States Department of Justice,
at the request of the EPA, brought a civil suit in the
U.S. District Court for the Eastern District of Michigan
against DTE Energy and Detroit Edison, related to the
June 2010 NOV/FOV and the outage work performed at Unit 2
of the Monroe Power Plant, but not relating to the July 2009
NOV/FOV. Among other relief, the EPA requested the court to
require Detroit Edison to install and operate the best available
control technology at Unit 2 of the Monroe Power Plant. Further,
the EPA requested the court to issue a preliminary injunction to
require Detroit Edison to (i) begin the process of
obtaining the necessary permits for the Monroe Unit 2
modification and (ii) offset the pollution from Monroe Unit
2 through emissions reductions from Detroit Edison’s fleet
of coal-fired power plants until the new control equipment is
operating. In January 2011, the EPA’s motion for
preliminary injunction was denied and the liability phase of the
civil suit has been scheduled for trial in May 2011.
DTE Energy and Detroit Edison believe that the plants identified
by the EPA, including Unit 2 of the Monroe Power Plant, have
complied with all applicable federal environmental regulations.
Depending upon the outcome of discussions with the EPA regarding
the NOV/FOV and the result of the civil action, the Company
could also be required to install additional pollution control
equipment at some or all of the power plants in question,
implement early retirement of facilities where control equipment
is not economical, engage in supplemental environmental
programs,
and/or
pay
fines. The Company cannot predict the financial impact or
outcome of this matter, or the timing of its resolution.
Water
— In response to an EPA regulation,
Detroit Edison is required to examine alternatives for reducing
the environmental impacts of the cooling water intake structures
at several of its facilities. Based on the results of completed
studies and expected future studies, Detroit Edison may be
required to install additional control technologies to reduce
the impacts of the water intakes. Initially, it was estimated
that Detroit Edison could incur up to approximately
$55 million in additional capital expenditures over the
four to six years subsequent to 2008 to comply with these
requirements. However, a January 2007 circuit court decision
remanded back to the EPA several provisions of the federal
regulation that has resulted in a delay in compliance dates. The
decision also raised the possibility that Detroit Edison may
have to install cooling towers at some facilities at a cost
substantially greater than was initially estimated for other
mitigative technologies. In 2008, the Supreme Court agreed to
review the remanded cost-benefit analysis provision of the rule
and in April 2009 upheld the EPA’s use of this provision in
determining best technology available for reducing environmental
impacts. Concurrently, the EPA continues to develop a revised
rule, a draft of which is expected to be published in the first
quarter of 2011, with a final rule scheduled for mid-2012. The
EPA has also issued an information collection request to begin a
review of steam electric effluent guidelines. It is not possible
at this time to quantify the impacts of these developing
requirements.
Manufactured Gas Plant (MGP) and Other Sites —
Prior to the construction of major interstate natural gas
pipelines, gas for heating and other uses was manufactured
locally from processes involving coal, coke or oil. The
facilities, which produced gas, have been designated as MGP
sites. Gas Utility owns, or previously owned, fifteen such
former MGP sites. Detroit Edison owns, or previously owned,
three former MGP sites. In addition to the MGP sites, we are
also in the process of cleaning up other sites where
contamination is present as a result of historical and ongoing
utility operations. These other sites include an engineered ash
storage facility, electrical distribution substations, gas
pipelines, and underground and aboveground storage tank
locations. Cleanup activities associated with these sites will
be conducted over the next several years.
Any significant change in assumptions, such as remediation
techniques, nature and extent of contamination and regulatory
requirements, could impact the estimate of remedial action costs
for the sites and affect the Company’s financial position
and cash flows. The Company anticipates the cost amortization
methodology approved by the MPSC for MichCon, which allows
MichCon to amortize the MGP costs over a ten-year period
beginning with the year subsequent to the year the MGP costs
were incurred, and the cost deferral and rate recovery mechanism
for Citizens Fuel Gas approved by the City of Adrian, will
prevent environmental costs from having a material adverse
impact on the Company’s results of operations.
Landfill
— Detroit Edison owns and operates a
permitted engineered ash storage facility at the Monroe Power
Plant to dispose of fly ash from the coal fired power plant.
Detroit Edison performed an engineering analysis in 2009 and
identified the need for embankment side slope repairs and
reconstruction.
19
Table of Contents
The EPA has published proposed rules to regulate coal ash under
the authority of the Resources Conservation and Recovery Act
(RCRA). The proposed rule published on June 21, 2010
contains two primary regulatory options to regulate coal ash
residue. The EPA is currently considering either, to designate
coal ash as a “Hazardous Waste” as defined by RCRA or
to regulate coal ash as non-hazardous waste under RCRA. However,
agencies and legislatures have urged the EPA to regulate coal
ash as a non-hazardous waste. If the EPA were to designate coal
ash as a hazardous waste, the agency could apply some, or all,
of the disposal and reuse standards that have been applied to
other existing hazardous wastes. Some of the regulatory actions
currently being contemplated could have a significant impact on
our operations and financial position and the rates we charge
our customers. It is not possible to quantify the impact of
those expected rulemakings at this time.
Non-Utility
The Company’s non-utility affiliates are subject to a
number of environmental laws and regulations dealing with the
protection of the environment from various pollutants.
The Michigan coke battery facility received and responded to
information requests from the EPA that resulted in the issuance
of a Notice of Violation in June of 2007 alleging potential
maximum achievable control technologies and new source review
violations. The EPA is in the process of reviewing the
Company’s position of demonstrated compliance and has not
initiated escalated enforcement. At this time, the Company
cannot predict the impact of this issue. Furthermore, the
Michigan coke battery facility is the subject of an
investigation by the MDNRE concerning visible emissions readings
that resulted from the Company self reporting to the MDNRE
questionable activities by an employee of a contractor hired by
the Company to perform the visible emissions readings. At this
time, the Company cannot predict the impact of this
investigation.
The Company is also in the process of settling historical air
and water violations at its coke battery facility located in
Pennsylvania. At this time, the Company cannot predict the
impact of this settlement. The Company received two notices of
violation from the Pennsylvania Department of Environmental
Protection in 2010 alleging violations of the permit for the
Pennsylvania coke battery facility in connection with coal pile
storm water runoff. The Company has implemented best management
practices to address this issue and is currently seeking a
permit from the Pennsylvania Department of Environmental
Protection to upgrade its wastewater treatment technology to a
biological treatment facility. The Company’s non-utility
affiliates are substantially in compliance with all
environmental requirements, other than as noted above.
Global
Climate Change
Climate regulation
and/or
legislation is being proposed and discussed within the
U.S. Congress and the EPA. Despite passage of a greenhouse
gas cap and trade bill by the U.S. House in June 2009, the
Senate has been unable to pass a similar climate bill. A
greenhouse gas cap and trade program is not expected to be
included in energy or climate bills to be considered by the
112th Congress. Meanwhile, the EPA is beginning to implement
regulatory actions under the Clean Air Act to address emission
of greenhouse gases. The EPA regulation of greenhouse gases
(GHGs) begins in 2011 requiring the best available control
technology (BACT) for major sources or modifications to existing
major sources that cause significant increases in GHG emissions.
The impact of this rule is uncertain until BACT is better
defined by the permitting agencies. Pending or future
legislation or other regulatory actions could have a material
impact on our operations and financial position and the rates we
charge our customers. Impacts include expenditures for
environmental equipment beyond what is currently planned,
financing costs related to additional capital expenditures, the
purchase of emission offsets from market sources and the
retirement of facilities where control equipment is not
economical. We would seek to recover these incremental costs
through increased rates charged to our utility customers.
Increased costs for energy produced from traditional sources
could also increase the economic viability of energy produced
from renewable
and/or
nuclear sources and energy efficiency initiatives and the
development of market-based trading of carbon offsets providing
business opportunities for our utility and non-utility segments.
It is not possible to quantify these impacts on DTE Energy or
its customers at this time.
See Notes 12 and 20 of the Notes to Consolidated Financial
Statements in Item 8 of this Report and Management’s
Discussion and Analysis in Item 7 of this Report.
20
Table of Contents
EMPLOYEES
We had approximately 9,800 employees as of
December 31, 2010, of which approximately 5,000 were
represented by unions. There are several bargaining units for
the Company’s represented employees. In the 2010 third
quarter, a new three-year agreement was ratified covering
approximately 3,800 represented employees. The majority of the
remaining represented employees are under contracts that expire
in June 2011 and August 2012.
| Item 1A. | Risk Factors |
There are various risks associated with the operations of DTE
Energy’s utility and non-utility businesses. To provide a
framework to understand the operating environment of DTE Energy,
we are providing a brief explanation of the more significant
risks associated with our businesses. Although we have tried to
identify and discuss key risk factors, others could emerge in
the future. Each of the following risks could affect our
performance.
Regional and national economic conditions can have an
unfavorable impact on us.
Our utility and
non-utility businesses follow the economic cycles of the
customers we serve. Our utilities and certain non-utility
businesses provide services to the domestic automotive and steel
industries which have undergone considerable financial distress,
exacerbating the decline in regional economic conditions. Should
national or regional economic conditions further decline,
reduced volumes of electricity and gas, and demand for energy
services we supply, collections of accounts receivable and
potentially higher levels of lost or stolen gas could result in
decreased earnings and cash flow.
We are exposed to credit risk of counterparties with whom we
do business.
Adverse economic conditions
affecting, or financial difficulties of, counterparties with
whom we do business could impair the ability of these
counterparties to pay for our services or fulfill their
contractual obligations, or cause them to delay such payments or
obligations. We depend on these counterparties to remit payments
on a timely basis. Any delay or default in payment could
adversely affect our cash flows, financial position, or results
of operations.
We are subject to rate regulation.
Electric
and gas rates for our utilities are set by the MPSC and the FERC
and cannot be changed without regulatory authorization. We may
be negatively impacted by new regulations or interpretations by
the MPSC, the FERC or other regulatory bodies. Our ability to
recover costs may be impacted by the time lag between the
incurrence of costs and the recovery of the costs in
customers’ rates. Our regulators also may decide to
disallow recovery of certain costs in customers’ rates if
they determine that those costs do not meet the standards for
recovery under our governing laws and regulations. The State of
Michigan elected a new governor and legislature in November 2010
and we cannot predict whether the resulting changes in political
conditions will affect the regulations or interpretations
affecting our utilities. New legislation, regulations or
interpretations could change how our business operates, impact
our ability to recover costs through rate increases or require
us to incur additional expenses.
We may be required to refund amounts we collect under
self-implemented rates.
Michigan law allows our
utilities to self-implement base rate changes six months after a
rate filing, subject to certain limitations. However, if the
final rate case order provides for lower rates than we have
self-implemented, we must refund the difference, with interest.
We have self-implemented rates in the past and have been ordered
to make refunds to customers. Our financial performance may be
negatively affected if the MPSC sets lower rates in future rate
cases than those we have self-implemented, thereby requiring us
to issue refunds. We cannot predict what rates an MPSC order
will adopt in future rate cases.
Michigan’s electric Customer Choice program could
negatively impact our financial performance.
The
electric Customer Choice program, as originally contemplated in
Michigan, anticipated an eventual transition to a totally
deregulated and competitive environment where customers would be
charged market-based rates for their electricity. The State of
Michigan currently experiences a hybrid market, where the MPSC
continues to regulate electric rates for our customers, while
alternative electric suppliers charge market-based rates. In
addition, such regulated electric rates for certain groups of
our customers exceed the cost of service to those customers. Due
to distorted pricing mechanisms during the initial
implementation period of electric Customer Choice, many
commercial customers chose alternative electric suppliers. MPSC
rate orders and 2008 energy legislation enacted by the State of
Michigan are phasing out the pricing disparity over five years
and have placed a cap on the total
21
Table of Contents
potential Customer Choice related migration. However, even with
the electric Customer Choice-related relief received in recent
Detroit Edison rate orders and the legislated 10 percent
cap on participation in the electric Customer Choice program,
there continues to be financial risk associated with the
electric Customer Choice program. Electric Customer Choice
migration is sensitive to market price and full service electric
price changes.
Environmental laws and liability may be
costly.
We are subject to numerous environmental
regulations. These regulations govern air emissions, water
quality, wastewater discharge and disposal of solid and
hazardous waste. Compliance with these regulations can
significantly increase capital spending, operating expenses and
plant down times. These laws and regulations require us to seek
a variety of environmental licenses, permits, inspections and
other regulatory approvals. We could be required to install
expensive pollution control measures or limit or cease
activities based on these regulations. Additionally, we may
become a responsible party for environmental cleanup at sites
identified by a regulatory body. We cannot predict with
certainty the amount and timing of future expenditures related
to environmental matters because of the difficulty of estimating
clean up costs. There is also uncertainty in quantifying
liabilities under environmental laws that impose joint and
several liability on potentially responsible parties.
We may also incur liabilities as a result of potential future
requirements to address climate change issues. Proposals for
voluntary initiatives and mandatory controls are being discussed
both in the United States and worldwide to reduce greenhouse
gases such as carbon dioxide, a by-product of burning fossil
fuels. If increased regulation of greenhouse gas emissions are
implemented, the operations of our fossil-fuel generation assets
and our unconventional gas production assets may be
significantly impacted. Since there can be no assurances that
environmental costs may be recovered through the regulatory
process, our financial performance may be negatively impacted as
a result of environmental matters.
Adverse changes in our credit ratings may negatively affect
us.
Regional and national economic
condition
s
, increased scrutiny of the energy industry and
regulatory changes, as well as changes in our economic
performance, could result in credit agencies reexamining our
credit rating. While credit ratings reflect the opinions of the
credit agencies issuing such ratings and may not necessarily
reflect actual performance, a downgrade in our credit rating
below investment grade could restrict or discontinue our ability
to access capital markets and could result in an increase in our
borrowing costs, a reduced level of capital expenditures and
could impact future earnings and cash flows. In addition, a
reduction in credit rating may require us to post collateral
related to various physical or financially settled contracts for
the purchase of energy-related commodities, products and
services, which could impact our liquidity.
Our ability to access capital markets is
important.
Our ability to access capital markets
is important to operate our businesses. In the past, turmoil in
credit markets has constrained, and may again in the future
constrain, our ability as well as the ability of our
subsidiaries to issue new debt, including commercial paper, and
refinance existing debt at reasonable interest rates. In
addition, the level of borrowing by other energy companies and
the market as a whole could limit our access to capital markets.
We have substantial amounts of credit facilities that expire in
2012 and 2013. We intend to seek to renew the facilities on or
before the expiration dates. However, we cannot predict the
outcome of these efforts, which could result in a decrease in
amounts available
and/or
an
increase in our borrowing costs and negatively impact our
financial performance.
Poor investment performance of pension and other
postretirement benefit plan holdings and other factors impacting
benefit plan costs could unfavorably impact our liquidity and
results of operations.
Our costs of providing
non-contributory defined benefit pension plans and other
postretirement benefit plans are dependent upon a number of
factors, such as the rates of return on plan assets, the level
of interest rates used to measure the required minimum funding
levels of the plans, future government regulation, and our
required or voluntary contributions made to the plans. The
performance of the debt and equity markets affects the value of
assets that are held in trust to satisfy future obligations
under our plans. We have significant benefit obligations and
hold significant assets in trust to satisfy these obligations.
These assets are subject to market fluctuations and will yield
uncertain returns, which may fall below our projected return
rates. A decline in the market value of the pension and
postretirement benefit plan assets will increase the funding
requirements under our pension and postretirement benefit plans
if the actual asset returns do not recover these declines in the
foreseeable future. Additionally, our pension and postretirement
benefit plan liabilities are sensitive to changes in interest
rates. As interest rates decrease, the liabilities increase,
22
Table of Contents
potentially increasing benefit expense and funding requirements.
Also, if future increases in pension and postretirement benefit
costs as a result of reduced plan assets are not recoverable
from Detroit Edison or MichCon customers, the results of
operations and financial position of our company could be
negatively affected. Without sustained growth in the plan
investments over time to increase the value of our plan assets,
we could be required to fund our plans with significant amounts
of cash. Such cash funding obligations could have a material
impact on our cash flows, financial position, or results of
operations.
If our goodwill becomes impaired, we may be required to
record a charge to earnings.
We annually review
the carrying value of goodwill associated with acquisitions made
by the Company for impairment. Factors that may be considered
for purposes of this analysis include any change in
circumstances indicating that the carrying value of our goodwill
may not be recoverable such as a decline in stock price and
market capitalization, future cash flows, and slower growth
rates in our industry. We cannot predict the timing, strength or
duration of any economic slowdown or subsequent recovery,
worldwide or in the economy or markets in which we operate;
however, when events or changes in circumstances indicate that
the carrying value of these assets may not be recoverable, the
Company may take a non-cash impairment charge, which could
potentially materially impact our results of operations and
financial position.
Weather significantly affects
operations.
Deviations from normal hot and cold
weather conditions affect our earnings and cash flow. Mild
temperatures can result in decreased utilization of our assets,
lowering income and cash flow. Ice storms, tornadoes, or high
winds can damage the electric distribution system infrastructure
and require us to perform emergency repairs and incur material
unplanned expenses. The expenses of storm restoration efforts
may not be fully recoverable through the regulatory process.
Operation of a nuclear facility subjects us to
risk.
Ownership of an operating nuclear
generating plant subjects us to significant additional risks.
These risks include, among others, plant security, environmental
regulation and remediation, and operational factors that can
significantly impact the performance and cost of operating a
nuclear facility. While we maintain insurance for various
nuclear-related risks, there can be no assurances that such
insurance will be sufficient to cover our costs in the event of
an accident or business interruption at our nuclear generating
plant, which may affect our financial performance.
Construction and capital improvements to our power facilities
subject us to risk.
We are managing ongoing and
planning future significant construction and capital improvement
projects at multiple power generation and distribution
facilities. Many factors that could cause delay or increased
prices for these complex projects are beyond our control,
including the cost of materials and labor, subcontractor
performance, timing and issuance of necessary permits,
construction disputes and weather conditions. Failure to
complete these projects on schedule and on budget for any reason
could adversely affect our financial performance and operations
at the affected facilities.
The supply
and/or
price
of energy commodities
and/or
related services may impact our financial
results.
We are dependent on coal for much of our
electrical generating capacity. Price fluctuations, fuel supply
disruptions and increases in transportation costs could have a
negative impact on the amounts we charge our utility customers
for electricity and on the profitability of our non-utility
businesses. Our access to natural gas supplies is critical to
ensure reliability of service for our utility gas customers. We
have hedging strategies and regulatory recovery mechanisms in
place to mitigate negative fluctuations in commodity supply
prices, but there can be no assurances that our financial
performance will not be negatively impacted by price
fluctuations. The price of energy also impacts the market for
our non-utility businesses that compete with utilities and
alternative electric suppliers.
The supply
and/or
price
of other industrial raw and finished inputs
and/or
related services may impact our financial
results.
We are dependent on supplies of certain
commodities, such as copper and limestone, among others, and
industrial materials and services in order to maintain
day-to-day
operations and maintenance of our facilities. Price fluctuations
or supply interruptions for these commodities and other items
could have a negative impact on the amounts we charge our
customers for our utility products and on the profitability of
our non-utility businesses.
Unplanned power plant outages may be
costly.
Unforeseen maintenance may be required to
safely produce electricity or comply with environmental
regulations. As a result of unforeseen maintenance, we may be
required to
23
Table of Contents
make spot market purchases of electricity that exceed our costs
of generation. Our financial performance may be negatively
affected if we are unable to recover such increased costs.
Our estimates of gas reserves are subject to
change.
While great care is exercised in
utilizing historical information and assumptions to develop
reasonable estimates of future production and cash flow, we
cannot provide absolute assurance that our estimates of our
Barnett gas reserves are accurate. We estimate proved gas
reserves and the future net cash flows attributable to those
reserves. There are numerous uncertainties inherent in
estimating quantities of proved gas reserves and cash flows
attributable to such reserves, including factors beyond our
control. Reserve engineering is a subjective process of
estimating underground accumulations of gas that cannot be
measured in an exact manner. The accuracy of an estimate of
quantities of reserves, or of cash flows attributable to such
reserves, is a function of the available data, assumptions
regarding expenditures for future development and exploration
activities, and of engineering and geological interpretation and
judgment. Additionally, reserves and future cash flows may be
subject to material downward or upward revisions, based upon
production history, development and exploration activities and
prices of gas. Actual future production, revenue, taxes,
development expenditures, operating expenses, quantities of
recoverable reserves and the value of cash flows from such
reserves may vary significantly from the assumptions and
underlying information we used.
Our ability to utilize production tax credits may be
limited.
To reduce U.S. dependence on
imported oil, the Internal Revenue Code provides production tax
credits as an incentive for taxpayers to produce fuels and
electricity from alternative sources. We have generated
production tax credits from coke production, landfill gas
recovery; biomass fired electric generation, reduced emission
fuel, steel industry fuel and gas production operations. All
production tax credits taken after 2008 are subject to audit by
the Internal Revenue Service (IRS). If our production tax
credits were disallowed in whole or in part as a result of an
IRS audit, there could be additional tax liabilities owed for
previously recognized tax credits that could significantly
impact our earnings and cash flows.
We rely on cash flows from subsidiaries.
DTE
Energy is a holding company. Cash flows from our utility and
non-utility subsidiaries are required to pay interest expenses
and dividends on DTE Energy debt and securities. Should a major
subsidiary not be able to pay dividends or transfer cash flows
to DTE Energy, our ability to pay interest and dividends would
be restricted.
Renewable portfolio standards and energy efficiency programs
may affect our business.
We are subject to
Michigan and potential future federal legislation and regulation
requiring us to secure sources of renewable energy. Under the
current Michigan legislation we will be required in the future
to provide a specified percentage of our power from Michigan
renewable energy sources. We are developing a strategy for
complying with the existing state legislation, but we do not
know what requirements may be added by federal legislation. We
are actively engaged in developing renewable energy projects and
identifying third party projects in which we can invest. We
cannot predict the financial impact or costs associated with
these future projects.
We are also required by Michigan legislation to implement energy
efficiency measures and provide energy efficiency customer
awareness and education programs. These requirements necessitate
expenditures and implementation of these programs creates the
risk of reducing our revenues as customers decrease their energy
usage. We do not know how these programs will impact our
business and future operating results.
Threats of terrorism or cyber attacks could affect our
business.
We may be threatened by problems such
as computer viruses or terrorism that may disrupt our operations
and could harm our operating results. Our industry requires the
continued operation of sophisticated information technology
systems and network infrastructure. Despite our implementation
of security measures, all of our technology systems are
vulnerable to disability or failures due to hacking, viruses,
acts of war or terrorism and other causes. If our information
technology systems were to fail and we were unable to recover in
a timely way, we might be unable to fulfill critical business
functions, which could have a material adverse effect on our
business, operating results, and financial condition.
In addition, our generation plants, gas pipeline and storage
facilities and electrical distribution facilities in particular
may be targets of terrorist activities that could disrupt our
ability to produce or distribute some portion of our energy
products. We have increased security as a result of past events
and we may be required by our regulators or by the future
terrorist threat environment to make investments in security
that we cannot currently predict.
24
Table of Contents
Our participation in energy trading markets subjects us to
risk.
Events in the energy trading industry have
increased the level of scrutiny on the energy trading business
and the energy industry as a whole. In certain situations we may
be required to post collateral to support trading operations,
which could be substantial. If access to liquidity to support
trading activities is curtailed, we could experience decreased
earnings potential and cash flows. Energy trading activities
take place in volatile markets and expose us to risks related to
commodity price movements. We routinely have speculative trading
positions in the market, within strict policy guidelines we set,
resulting from the management of our business portfolio. To the
extent speculative trading positions exist, fluctuating
commodity prices can improve or diminish our financial results
and financial position. We manage our exposure by establishing
and enforcing strict risk limits and risk management procedures.
During periods of extreme volatility, these risk limits and risk
management procedures may not work as planned and cannot
eliminate all risks associated with these activities.
We may not be fully covered by insurance.
We
have a comprehensive insurance program in place to provide
coverage for various types of risks, including catastrophic
damage as a result of acts of God, terrorism or a combination of
other significant unforeseen events that could impact our
operations. Economic losses might not be covered in full by
insurance or our insurers may be unable to meet contractual
obligations.
Failure to maintain the security of personally identifiable
information could adversely affect us.
In
connection with our business we collect and retain personally
identifiable information of our customers, shareholders and
employees. Our customers, shareholders and employees expect that
we will adequately protect their personal information, and the
United States regulatory environment surrounding information
security and privacy is increasingly demanding. A significant
theft, loss or fraudulent use of customer, shareholder, employee
or DTE Energy data by cybercrime or otherwise could adversely
impact our reputation and could result in significant costs,
fines and litigation.
A work interruption may adversely affect
us.
Unions represent approximately 5,000 of our
employees. A union choosing to strike would have an impact on
our business. We are unable to predict the effect a work
stoppage would have on our costs of operation and financial
performance.
Failure to retain and attract key executive officers and
other skilled professional and technical employees could have an
adverse effect on our operations.
Our business is
dependent on our ability to recruit, retain, and motivate
employees. Competition for skilled employees in some areas is
high and the inability to retain and attract these employees
could adversely affect our business and future operating results.
| Item 1B. | Unresolved Staff Comments |
None.
| Item 3. | Legal Proceedings |
We are involved in certain legal, regulatory, administrative and
environmental proceedings before various courts, arbitration
panels and governmental agencies concerning matters arising in
the ordinary course of business. These proceedings include
certain contract disputes, environmental reviews and
investigations, audits, inquiries from various regulators, and
pending judicial matters. We cannot predict the final
disposition of such proceedings. We regularly review legal
matters and record provisions for claims that are considered
probable of loss. The resolution of pending proceedings is not
expected to have a material effect on our operations or
financial statements in the periods they are resolved.
In February 2008, DTE Energy was named as one of approximately
24 defendant oil, power and coal companies in a lawsuit filed in
a United States District Court. DTE Energy was served with
process in March 2008. The plaintiffs, the Native Village of
Kivalina and City of Kivalina, which are home to approximately
400 people in Alaska, claim that the defendants’
business activities have contributed to global warming and, as a
result, higher temperatures are damaging the local economy and
leaving the island more vulnerable to storm activity in the fall
and winter. As a result, the plaintiffs are seeking damages of
up to $400 million for relocation costs associated with
moving the village to a safer location, as well as unspecified
attorney’s fees and expenses. On October 15, 2009, the
U.S. District Court granted defendants’ motions
dismissing all of plaintiffs’ federal claims in the case on
two
25
Table of Contents
independent grounds: (1) the court lacks subject matter
jurisdiction to hear the claims because of the political
question doctrine; and (2) plaintiffs lack standing to
bring their claims. The court also dismissed plaintiffs’
state law claims because the court lacked supplemental
jurisdiction over them after it dismissed the federal claims;
the dismissal of the state law claims was without prejudice. The
plaintiffs have appealed to the U.S. Court of Appeals for
the Ninth Circuit.
In July 2009, DTE Energy received a Notice of Violation/Finding
of Violation (NOV/FOV) from the EPA alleging, among other
things, that five of Detroit Edison’s power plants violated
New Source Performance standards, Prevention of Significant
Deterioration requirements, and operating permit requirements
under the Clean Air Act. In June 2010, the EPA issued a NOV/FOV
making similar allegations related to a recent project and
outage at Unit 2 of the Monroe Power Plant.
On August 5, 2010, the United States Department of Justice,
at the request of the EPA, brought a civil suit in the
U.S. District Court for the Eastern District of Michigan
against DTE Energy and Detroit Edison, related to the
June 2010 NOV/FOV and the outage work performed at Unit 2
of the Monroe Power Plant, but not relating to the July 2009
NOV/FOV. Among other relief, the EPA requested the court to
require Detroit Edison to install and operate the best available
control technology at Unit 2 of the Monroe Power Plant. Further,
the EPA requested the court to issue a preliminary injunction to
require Detroit Edison to (i) begin the process of
obtaining the necessary permits for the Monroe Unit 2
modification and (ii) offset the pollution from Monroe Unit
2 through emissions reductions from Detroit Edison’s fleet
of coal-fired power plants until the new control equipment is
operating. In January 2011, the EPA’s motion for
preliminary injunction was denied and the liability phase of the
civil suit has been scheduled for trial in May 2011.
DTE Energy and Detroit Edison believe that the plants identified
by the EPA, including Unit 2 of the Monroe Power Plant, have
complied with all applicable federal environmental regulations.
Depending upon the outcome of discussions with the EPA regarding
the NOV/FOV and the result of the civil action, Detroit Edison
could also be required to install additional pollution control
equipment at some or all of the power plants in question,
implement early retirement of facilities where control equipment
is not economical, engage in supplemental environmental
programs,
and/or
pay
fines. DTE Energy and Detroit Edison cannot predict the
financial impact or outcome of this matter, or the timing of its
resolution.
In October 2010, the Company received a Notice of Violation from
the MDNRE alleging that the Michigan coke battery facility
violated the visible emission readings and quench water sampling
requirements under applicable National Emissions Standards for
Hazardous Air Pollutants regulations. This Notice of Violation
resulted from the Company self reporting to the MDNRE and the
EPA questionable activities by an employee of a contractor hired
by the Company to perform visible emissions readings and quench
water sampling. The information provided by contractor was used
by the Company in filing certain reports with the MDNRE and the
EPA. The Company has ceased using the contractor for these
activities, has retained a new certified contractor to perform
the required activities and implemented standard operating
procedures designed to prevent a reoccurrence of such a
situation. At this time, the Company cannot predict the outcome
or financial impact of this issue.
In December 2010, the Company received a Notice of Violation
from the Detroit Water and Sewerage Department (DWSD) alleging
that effluent discharges from the Michigan coke battery facility
violated the City of Detroit Ordinance, the General
Pre-Treatment Standards and the terms of a Consent Judgment
entered between the Company and the DWSD with respect to the
Michigan coke battery facility in March 2009. The Company has
settled similar alleged violations with respect to the Michigan
coke battery facility with the DWSD in the past. The Company has
installed a biological waste water treatment plant at the
Michigan coke battery facility in accordance with the Consent
Judgement that is designed to meet the effluent limitations and
is in the process of optimizing plant performance to minimize
any future excursions of the Ordinance and the General
Pre-Treatment Standards. The DWSD has demanded payment of
$176,000 in penalties in connection with the alleged violations.
The Company is actively pursuing a settlement with DWSD, but we
cannot predict the outcome or financial impact of this matter.
In April 2006, the prior owners of the coke battery facility in
Pennsylvania that the Company purchased in 2008 received a
Notice of Violation/Finding of Violation from the EPA alleging
violations of the lowest achievable emission rate requirements
associated with visible emissions from the combustion stack,
door leaks and charging activities at the coke battery facility.
The EPA has also alleged certain violations of the Clean Water
Act, but has not
26
Table of Contents
issued a notice of violation in connection with these alleged
violations. The Company is in the process of negotiating a
Consent Order with the EPA to settle these historic air and
water issues. The Company will be required to complete ceramic
welding repairs to the coke battery facility and to make repairs
to the waste water treatment facility at the coke battery
facility. The Company will also be required to pay a fine in
connection with the settlement of these historic violations. At
this time, the Company cannot predict the outcome or financial
impact of this settlement or the timing of its resolution.
For additional discussion on legal matters, see Notes 12
and 20 of the Notes to Consolidated Financial Statements in
Item 8 of this Report.
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Our common stock is listed on the New York Stock Exchange, which
is the principal market for such stock. The following table
indicates the reported high and low sales prices of our common
stock on the Composite Tape of the New York Stock Exchange and
dividends paid per share for each quarterly period during the
past two years:
|
Dividends
|
||||||||||||||||
|
Paid
|
||||||||||||||||
| Year | Quarter | High | Low | per Share | ||||||||||||
| 2010 | ||||||||||||||||
| First | $ | 45.93 | $ | 41.25 | $ | 0.530 | ||||||||||
| Second | $ | 49.05 | $ | 43.00 | $ | 0.530 | ||||||||||
| Third | $ | 49.06 | $ | 44.93 | $ | 0.560 | ||||||||||
| Fourth | $ | 47.66 | $ | 44.27 | $ | 0.560 | ||||||||||
| 2009 | ||||||||||||||||
| First | $ | 37.11 | $ | 23.32 | $ | 0.530 | ||||||||||
| Second | $ | 32.43 | $ | 27.32 | $ | 0.530 | ||||||||||
| Third | $ | 36.46 | $ | 30.59 | $ | 0.530 | ||||||||||
| Fourth | $ | 44.96 | $ | 33.75 | $ | 0.530 | ||||||||||
At December 31, 2010, there were 169,428,406 shares of
our common stock outstanding. These shares were held by a total
of 74,822 shareholders of record.
Our Bylaws nullify Chapter 7B of the Michigan Business
Corporation Act (Act). This Act regulates shareholder rights
when an individual’s stock ownership reaches 20% of a
Michigan corporation’s outstanding shares. A shareholder
seeking control of the Company cannot require our Board of
Directors to call a meeting to vote on issues related to
corporate control within 10 days, as stipulated by the Act.
We paid cash dividends on our common stock of $360 million
in 2010, $348 million in 2009, and $344 million in
2008. The amount of future dividends will depend on our
earnings, cash flows, financial condition and other factors that
are periodically reviewed by our Board of Directors. Although
there can be no assurances, we anticipate paying dividends for
the foreseeable future.
See Note 14 of the Notes to Consolidated Financial
Statements in Item 8 of this Report for information on
dividend restrictions.
All of our equity compensation plans that provide for the annual
awarding of stock-based compensation have been approved by
shareholders. See Note 22 of the Notes to Consolidated
Financial Statements in Item 8 of this Report for
additional detail.
27
Table of Contents
See the following table for information as of December 31,
2010.
|
Number of Securities
|
Number of Securities
|
|||||||||||
|
to be Issued Upon
|
Weighted-Average
|
Remaining Available for
|
||||||||||
|
Exercise of
|
Exercise Price of
|
Future Issuance Under Equity
|
||||||||||
| Outstanding Options | Outstanding Options | Compensation Plans | ||||||||||
|
Plans approved by shareholders
|
4,827,457 | $ | 41.09 | 2,806,555 | ||||||||
UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases
of Equity Securities by the Issuer and Affiliated
Purchasers
The following table provides information about our purchases of
equity securities that are registered by the Company pursuant to
Section 12 of the Exchange Act for the year ended
December 31, 2010:
|
Number
|
||||||||||||||||||||
|
of Shares
|
Maximum Dollar
|
|||||||||||||||||||
|
Purchased as
|
Value that May
|
|||||||||||||||||||
|
Average
|
Part of Publicly
|
Yet Be
|
||||||||||||||||||
|
Number of
|
Price
|
Announced
|
Average
|
Purchased Under
|
||||||||||||||||
|
Shares
|
Paid per
|
Plans or
|
Price Paid
|
the Plans or
|
||||||||||||||||
| Purchased(1) | Share(1) | Programs | per Share | Programs | ||||||||||||||||
|
01/01/10 — 01/31/10
|
— | — | — | — | — | |||||||||||||||
|
02/01/10 — 02/28/10
|
— | — | — | — | — | |||||||||||||||
|
03/01/10 — 03/31/10
|
55,000 | $ | 45.07 | — | — | — | ||||||||||||||
|
04/01/10 — 04/30/10
|
— | — | — | — | — | |||||||||||||||
|
05/01/10 — 05/31/10
|
85,000 | 48.33 | — | — | — | |||||||||||||||
|
06/01/10 — 06/30/10
|
— | — | — | — | — | |||||||||||||||
|
07/01/10 — 07/31/10
|
— | — | — | — | — | |||||||||||||||
|
08/01/10 — 08/31/10
|
35,000 | 46.40 | — | — | — | |||||||||||||||
|
09/01/10 — 09/30/10
|
44,000 | 47.89 | — | — | — | |||||||||||||||
|
10/01/10 — 10/31/10
|
— | — | — | — | — | |||||||||||||||
|
11/01/10 — 11/30/10
|
15,000 | 45.34 | — | — | — | |||||||||||||||
|
12/01/10 — 12/31/10
|
— | — | — | — | — | |||||||||||||||
|
Total
|
234,000 | — | ||||||||||||||||||
| (1) | Represents shares of common stock purchased on the open market to provide shares to participants under various employee compensation and incentive programs. These purchases were not made pursuant to a publicly announced plan or program. |
28
Table of Contents
COMPARISON
OF CUMULATIVE FIVE YEAR TOTAL RETURN
Total
Return To Shareholders
(Includes reinvestment of dividends)
(Includes reinvestment of dividends)
|
Annual Return Percentage
|
||||||||||||||||||||
| Year Ended December 31 | ||||||||||||||||||||
| Company/Index | 2006 | 2007 | 2008 | 2009 | 2010 | |||||||||||||||
|
DTE Energy Company
|
17.66 | (5.03 | ) | (14.37 | ) | 30.08 | 9.06 | |||||||||||||
|
S&P 500 Index
|
15.79 | 5.49 | (37.00 | ) | 26.46 | 15.06 | ||||||||||||||
|
S&P 500 Multi-Utilities Index
|
16.74 | 10.86 | (24.34 | ) | 20.93 | 11.08 | ||||||||||||||
|
Indexed Returns
|
||||||||||||||||||||||||
| Year Ended December 31 | ||||||||||||||||||||||||
|
Base
|
||||||||||||||||||||||||
|
Period
|
||||||||||||||||||||||||
| Company/Index | 2005 | 2006 | 2007 | 2008 | 2009 | 2010 | ||||||||||||||||||
|
DTE Energy Company
|
100 | 117.66 | 111.74 | 95.68 | 124.46 | 135.73 | ||||||||||||||||||
|
S&P 500 Index
|
100 | 115.79 | 122.16 | 76.96 | 97.33 | 111.99 | ||||||||||||||||||
|
S&P 500 Multi-Utilities Index
|
100 | 116.74 | 129.42 | 97.92 | 118.41 | 131.53 | ||||||||||||||||||
Comparison
of Cumulative Five Year Total Return
29
Table of Contents
| Item 6. | Selected Financial Data |
The following selected financial data should be read in
conjunction with the accompanying Management’s Discussion
and Analysis in Item 7 of this Report and Notes to the
Consolidated Financial Statements in Item 8 of this Report.
| 2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
| (In millions, except per share amounts) | ||||||||||||||||||||
|
Operating Revenues
|
$ | 8,557 | $ | 8,014 | $ | 9,329 | $ | 8,475 | $ | 8,157 | ||||||||||
|
Net Income Attributable to DTE Energy Company
|
||||||||||||||||||||
|
Income from continuing operations(1)
|
$ | 630 | $ | 532 | $ | 526 | $ | 787 | $ | 389 | ||||||||||
|
Discontinued operations
|
— | — | 20 | 184 | 43 | |||||||||||||||
|
Cumulative effect of accounting changes
|
— | — | — | — | 1 | |||||||||||||||
|
Net Income Attributable to DTE Energy Company
|
$ | 630 | $ | 532 | $ | 546 | $ | 971 | $ | 433 | ||||||||||
|
Diluted Earnings Per Common Share
|
||||||||||||||||||||
|
Income from continuing operations
|
$ | 3.74 | $ | 3.24 | $ | 3.22 | $ | 4.61 | $ | 2.18 | ||||||||||
|
Discontinued operations
|
— | — | .12 | 1.08 | .24 | |||||||||||||||
|
Cumulative effect of accounting changes
|
— | — | — | — | .01 | |||||||||||||||
|
Diluted Earnings Per Common Share
|
$ | 3.74 | $ | 3.24 | $ | 3.34 | $ | 5.69 | $ | 2.43 | ||||||||||
|
Financial Information
|
||||||||||||||||||||
|
Dividends declared per share of common stock
|
$ | 2.18 | $ | 2.12 | $ | 2.12 | $ | 2.12 | $ | 2.075 | ||||||||||
|
Total assets
|
$ | 24,896 | $ | 24,195 | $ | 24,590 | $ | 23,742 | $ | 23,785 | ||||||||||
|
Long-term debt, including capital leases
|
$ | 7,089 | $ | 7,370 | $ | 7,741 | $ | 6,971 | $ | 7,474 | ||||||||||
|
Shareholders’ equity
|
$ | 6,722 | $ | 6,278 | $ | 5,995 | $ | 5,853 | $ | 5,849 | ||||||||||
| (1) | 2007 amounts include $580 million after-tax gain on the Antrim sale transaction and $210 million after-tax losses on hedge contracts associated with the Antrim sale. 2008 amounts include $80 million after-tax gain on the sale of a portion of the Barnett shale properties. See Note 10 of Notes to Consolidated Financial Statements in Item 8 of this Report. |
30
Table of Contents
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
OVERVIEW
DTE Energy is a diversified energy company with 2010 operating
revenues in excess of $8 billion and approximately
$25 billion in assets. We are the parent company of Detroit
Edison and MichCon, regulated electric and gas utilities engaged
primarily in the business of providing electricity and natural
gas sales, distribution and storage services throughout
southeastern Michigan. We operate four energy-related
non-utility segments with operations throughout the United
States.
The following table summarizes our financial results:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions, except per share amounts) | ||||||||||||
|
Net income attributable to DTE Energy Company
|
$ | 630 | $ | 532 | $ | 546 | ||||||
|
Diluted earnings per common share
|
$ | 3.74 | $ | 3.24 | $ | 3.34 | ||||||
The increase in 2010 Net income attributable to DTE Energy as
compared to 2009 was primarily due to improved results in the
Electric and Gas Utilities and in the Power and Industrial
Projects segment, partially offset by lower earnings in Energy
Trading. The decrease in Net income attributable to DTE Energy
in 2009 from 2008 was primarily due to an $80 million
after-tax gain recorded in the Unconventional Gas Production
segment on the 2008 sale of a portion of Barnett shale
properties, partially offset by higher earnings in the Electric
Utility and Energy Trading segments.
The items discussed below influenced our current financial
performance
and/or
may
affect future results:
| • | Impacts of national and regional economic conditions; | |
| • | Effects of weather on utility operations; | |
| • | Collectibility of accounts receivable on utility operations; | |
| • | Impact of regulatory decisions on utility operations; | |
| • | Non-utility operations; | |
| • | Capital investments, including required renewable, energy-efficiency, environmental, reliability-related and other costs; and | |
| • | Environmental matters. |
Reference in this report to “we,” “us,”
“our,” “Company” or “DTE” are to
DTE Energy and its subsidiaries, collectively.
UTILITY
OPERATIONS
Our Electric Utility segment consists of Detroit Edison, which
is engaged in the generation, purchase, distribution and sale of
electricity to approximately 2.1 million customers in
southeastern Michigan.
Our Gas Utility segment consists of MichCon and Citizens.
MichCon is engaged in the purchase, storage, transportation,
gathering, distribution and sale of natural gas to approximately
1.2 million customers throughout Michigan. Citizens
distributes natural gas in Adrian, Michigan to approximately
17,000 customers.
Detroit Edison has experienced decreased electric sales in 2010
driven primarily by a decrease in commercial sales, partially
offset by higher residential and industrial sales. Commercial
sales continue to be lower due primarily to customers
participating in the electric Customer Choice program. The
residential sales increase is a result of warmer summer weather.
Industrial sales are higher due to increased demand from
customers in the automotive and steel industries and their
related suppliers and other ancillary businesses. The impact of
customers participating in the electric Customer Choice program
is mitigated by the CIM, an over/under recovery mechanism which
measures non-fuel revenues that are lost or gained as a result
of fluctuations in electric Customer Choice sales. If annual
electric Customer Choice sales exceed the baseline amount from
Detroit Edison’s most recent rate case, 90 percent
31
Table of Contents
of its lost non-fuel revenues associated with sales above that
level may be recovered from full service customers. If annual
electric Customer Choice sales decrease below the baseline, the
Company must refund 90 percent of its increase in non-fuel
revenues associated with sales below that level to full service
customers. MichCon’s sales were lower due primarily to a
decrease in the number of customers, reduced natural gas usage
by customers due to economic conditions and an increased
emphasis on conservation of energy usage.
We have RDMs in place at both utilities. The RDMs are designed
to minimize the impact on revenues of changes in average
customer usage of electricity and natural gas. The January 2010
MPSC order in Detroit Edison’s 2009 rate case provided for,
among other items, the implementation of a pilot electric RDM
effective February 1, 2010. The electric RDM enables
Detroit Edison to recover or refund the change in revenue
resulting from the difference between actual average sales per
customer compared to the base level of average sales per
customer established in the MPSC order. The June 2010 MPSC order
in MichCon’s 2009 rate case provided for, among other
items, the implementation of a pilot gas RDM effective
July 1, 2010. The gas RDM enables MichCon to recover or
refund the change in revenue resulting from the difference in
weather-adjusted average sales per customer compared to the base
average sales per customer established in the MPSC order. The
RDMs for Detroit Edison and MichCon address changes in customer
usage due to general economic conditions and conservation, but
do not shield the utilities from the impacts of lost customers.
In addition, the pilot electric RDM materially shields Detroit
Edison from the impact of weather on customer usage. The pilot
gas RDM does not shield MichCon from the impact of weather on
customer usage. The electric and gas RDMs are subject to review
by the MPSC after the initial one-year pilot programs.
Both utilities continue to experience high levels of past due
receivables primarily attributable to economic conditions. Our
service territories continue to experience high levels of
unemployment, underemployment and low income households, home
foreclosures and a lack of adequate levels of assistance for
low-income customers. We have taken actions to manage the level
of past due receivables, including customer assistance forums,
contracting with collection agencies, working with Michigan
officials and others to increase the share of low-income funding
allocated to our customers, and increasing customer
disconnections. As a result of actions taken to manage the level
of past due receivables, arrears were reduced in 2010 in our
electric and gas utilities. Detroit Edison has an uncollectible
expense tracking mechanism that enables it to recover or refund
80 percent of the difference between the actual
uncollectible expense for each year and the $66 million
level reflected in base rates. In the June 2010 MPSC rate order,
the base amount of MichCon’s uncollectible expense tracking
mechanism was increased prospectively from $37 million to
$70 million and MichCon’s portion of recovery or
refund of the expenses above or below the base amount was
modified to 80 percent from 90 percent. The Detroit
Edison and MichCon uncollectible tracking mechanisms require
annual reconciliation proceedings before the MPSC.
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Uncollectible Expense
|
||||||||||||
|
Detroit Edison
|
$ | 58 | $ | 78 | $ | 87 | ||||||
|
MichCon
|
58 | 93 | 126 | |||||||||
| $ | 116 | $ | 171 | $ | 213 | |||||||
We are continuing our efforts to identify opportunities to
improve cash flow at our utility operations through working
capital initiatives and maintaining flexibility in the timing
and extent of our long-term capital projects. We are actively
managing our cash, capital expenditures, cost structure and
liquidity to maintain our financial strength. See the Capital
Resources and Liquidity section in this Management’s
Discussion and Analysis for further discussion of our liquidity
outlook.
NON-UTILITY
OPERATIONS
We have significant investments in non-utility businesses. We
employ disciplined investment criteria when assessing
opportunities that leverage our assets, skills and expertise.
Specifically, we invest in targeted energy markets with
attractive competitive dynamics where meaningful scale is in
alignment with our risk profile. We expect growth opportunities
in the Gas Storage and Pipelines and Power and Industrial
Projects segments in the future. Expansion of these businesses
will also result in our ability to further diversify
geographically.
32
Table of Contents
Gas Storage and Pipelines owns partnership interests in two
natural gas storage fields and two interstate pipelines serving
the Midwest, Ontario and Northeast markets. Much of the growth
in demand for natural gas is expected to occur in the Eastern
Canada and the Northeast U.S. regions. Our Vector and
Millennium pipelines are well positioned to provide access
routes and low-cost expansion options to these markets. In
addition, Millennium Pipeline is well positioned for growth
related to the Marcellus shale, especially with respect to
Marcellus production in Northern Pennsylvania and along the
southern tier of New York.
Our Unconventional Gas Production business is engaged in natural
gas and oil exploration, development and production primarily
within the Barnett shale in north Texas. Our acreage covers an
area that produces high Btu gas which provides a significant
contribution to revenues from the value of natural gas liquids
extracted from the gas stream. During this period of low natural
gas prices, these natural gas liquids, with prices correlated to
crude oil prices, have provided a significant increase to our
realized wellhead price. Our drilling efforts have and will
continue to target liquids rich gas and oil producing locations.
We continue to develop our holdings and to seek opportunities
for additional monetization of select properties, when
conditions are appropriate.
Power and Industrial Projects is comprised primarily of projects
that deliver energy and products and services to industrial,
commercial and institutional customers; provide coal
transportation, marketing and trading services; and sell
electricity from biomass-fired energy projects. This business
segment provides services using project assets usually located
on or near the customers’ premises in the steel,
automotive, pulp and paper, airport and other industries.
Renewable energy, environmental and economic trends are creating
growth opportunities. The increasing number of states with
renewable portfolio standards and energy efficiency mandates
provides the opportunity to market the expertise of the Power
and Industrial Projects segment in renewable power generation,
landfill gas recovery, reduced emission fuel and other related
services.
Energy Trading focuses on physical and financial power and gas
marketing and trading, structured transactions, enhancement of
returns from DTE Energy’s asset portfolio, and optimization
of contracted natural gas pipeline transportation and storage,
and power transmission and generating capacity positions. Energy
Trading also provides natural gas, power and ancillary services
to various utilities which may include the management of
associated storage and transportation contracts on the
customers’ behalf.
CAPITAL
INVESTMENTS
We anticipate significant capital investments during the next
three years concentrated primarily in Detroit Edison.
| 2011-2013 | ||||
| (In billions) | ||||
|
Capital Investments
|
||||
|
Detroit Edison
|
$ | 3.4 — 3.8 | ||
|
MichCon
|
0.5 — 0.6 | |||
|
Non-Utility
|
0.6 — 0.9 | |||
| $ | 4.5 — 5.3 | |||
Our utility businesses require significant capital investments
each year in order to maintain and improve the reliability of
their asset bases, including power generation plants,
distribution systems, storage fields and other facilities and
fleets. For both Detroit Edison and MichCon we plan to seek
regulatory approval in general rate case filings to include
these capital expenditures within our regulatory rate base
consistent with prior general rate case filing treatment.
Detroit Edison is required to implement a
20-year
renewable energy plan to address the provisions of Michigan
Public Act 295 of 2008, with the goals of delivering cleaner
renewable electric generation to its customers, further
diversifying Detroit Edison’s and the State of
Michigan’s sources of electric supply and addressing the
state and national goals of increasing energy independence.
Detroit Edison will seek separate regulatory approval and
recovery of these renewable capital expenditures within our
regulatory rate base through our renewable energy plan filings.
In April 2010, the Company signed an agreement with the
U.S. Department of Energy for a grant of approximately
$84 million in matching funds on total anticipated spending
of approximately $168 million related to the accelerated
deployment of smart grid technology in Michigan through 2012.
The smart grid technology includes
33
Table of Contents
the establishment of an advanced metering infrastructure and
other technologies that address improved electric distribution
service. See Note 2 of the Notes to Consolidated Financial
Statements.
Non-utility investments are expected primarily in continued
investment in gas storage and pipeline assets and renewable
opportunities in the Power and Industrial Projects businesses.
ENVIRONMENTAL
MATTERS
We are subject to extensive environmental regulation. Additional
costs may result as the effects of various substances on the
environment are studied and governmental regulations are
developed and implemented. Actual costs to comply could vary
substantially. We expect to continue recovering environmental
costs related to utility operations through rates charged to our
customers.
Air —
Detroit Edison is subject to the EPA
ozone transport and acid rain regulations that limit power plant
emissions of sulfur dioxide and nitrogen oxides. Since 2005, the
EPA and the State of Michigan have issued additional emission
reduction regulations relating to ozone, fine particulate,
regional haze and mercury air pollution. The new rules will lead
to additional controls on fossil-fueled power plants to reduce
nitrogen oxide, sulfur dioxide and mercury emissions. To comply
with these requirements, Detroit Edison has spent approximately
$1.5 billion through 2010. The Company estimates Detroit
Edison will make capital expenditures of over $230 million
in 2011 and up to $2.1 billion of additional capital
expenditures through 2020 based on current regulations. Further,
additional rulemakings are expected over the next few years
which could require additional controls for sulfur dioxide,
nitrogen oxides and hazardous air pollutants. It is not possible
to quantify the impact of those expected rulemakings at this
time.
In July 2009, DTE Energy received a Notice of Violation/Finding
of Violation (NOV/FOV) from the EPA alleging, among other
things, that five Detroit Edison power plants violated New
Source Performance standards, Prevention of Significant
Deterioration requirements, and operating permit requirements
under the Clean Air Act. An additional NOV/FOV was received in
June 2010 related to a recent project and outage at Unit 2 of
the Monroe Power Plant.
On August 5, 2010, the United States Department of Justice,
at the request of the EPA, brought a civil suit in the
U.S. District Court for the Eastern District of Michigan
against DTE Energy and Detroit Edison, related to the June 2010
NOV/FOV and the outage work performed at Unit 2 of the Monroe
Power Plant, but not relating to the July 2009 NOV/FOV. Among
other relief, the EPA requested the court to require Detroit
Edison to install and operate the best available control
technology at Unit 2 of the Monroe Power Plant. Further, the EPA
requested the court to issue a preliminary injunction to require
Detroit Edison to (i) begin the process of obtaining the
necessary permits for the Monroe Unit 2 modification and
(ii) offset the pollution from Monroe Unit 2 through
emissions reductions from Detroit Edison’s fleet of
coal-fired power plants until the new control equipment is
operating. In January 2011, the EPA’s motion for
preliminary injunction was denied and the liability phase of the
civil suit has been scheduled for trial in May 2011.
DTE Energy and Detroit Edison believe that the plants identified
by the EPA, including Unit 2 of the Monroe Power Plant, have
complied with all applicable federal environmental regulations.
Depending upon the outcome of discussions with the EPA regarding
the NOV/FOV and the result of the civil action, the Company
could also be required to install additional pollution control
equipment at some or all of the power plants in question,
implement early retirement of facilities where control equipment
is not economical, engage in supplemental environmental
programs,
and/or
pay
fines. The Company cannot predict the financial impact or
outcome of this matter, or the timing of its resolution.
Water
— In response to an EPA regulation,
Detroit Edison is required to examine alternatives for reducing
the environmental impacts of the cooling water intake structures
at several of its facilities. Based on the results of completed
studies and expected future studies, Detroit Edison may be
required to install additional control technologies to reduce
the impacts of the water intakes. Initially, it was estimated
that Detroit Edison could incur up to approximately
$55 million in additional capital expenditures over the
four to six years subsequent to 2008 to comply with these
requirements. However, a January 2007 circuit court decision
remanded back to the EPA several provisions of the federal
regulation that has resulted in a delay in compliance dates. The
decision also raised the
34
Table of Contents
possibility that Detroit Edison may have to install cooling
towers at some facilities at a cost substantially greater than
was initially estimated for other mitigative technologies. In
2008, the Supreme Court agreed to review the remanded
cost-benefit analysis provision of the rule and in April 2009
upheld the EPA’s use of this provision in determining best
technology available for reducing environmental impacts. The EPA
continues to develop a revised rule, a draft of which is
expected to be published in the first quarter of 2011, with a
final rule scheduled for mid-2012. The EPA has also issued an
information collection request to begin a review of steam
electric effluent guidelines. It is not possible at this time to
quantify the impacts of these developing requirements.
Manufactured Gas Plant (MGP) and Other Sites —
Prior to the construction of major interstate natural gas
pipelines, gas for heating and other uses was manufactured
locally from processes involving coal, coke or oil. The
facilities, which produced gas, have been designated as MGP
sites. Gas Utility owns, or previously owned, fifteen such
former MGP sites. Detroit Edison owns, or previously owned,
three former MGP sites. In addition to the MGP sites, we are
also in the process of cleaning up other sites where
contamination is present as a result of historical and ongoing
utility operations. These other sites include an engineered ash
storage facility, electrical distribution substations, gas
pipelines, and underground and aboveground storage tank
locations. Cleanup activities associated with these sites will
be conducted over the next several years.
Any significant change in assumptions, such as remediation
techniques, nature and extent of contamination and regulatory
requirements, could impact the estimate of remedial action costs
for the sites and affect the Company’s financial position
and cash flows. The Company anticipates the cost amortization
methodology approved by the MPSC for MichCon, which allows
MichCon to amortize the MGP costs over a ten-year period
beginning with the year subsequent to the year the MGP costs
were incurred, and the cost deferral and rate recovery mechanism
for Citizens Fuel Gas approved by the City of Adrian, will
prevent environmental costs from having a material adverse
impact on the Company’s results of operations.
Landfill
— Detroit Edison owns and operates a
permitted engineered ash storage facility at the Monroe Power
Plant to dispose of fly ash from the coal fired power plant.
Detroit Edison performed an engineering analysis in 2009 and
identified the need for embankment side slope repairs and
reconstruction.
The EPA has published proposed rules to regulate coal ash under
the authority of the Resources Conservation and Recovery Act
(RCRA). The proposed rule published on June 21, 2010
contains two primary regulatory options to regulate coal ash
residue. The EPA is currently considering either, to designate
coal ash as a “Hazardous Waste” as defined by RCRA or
to regulate coal ash as non- hazardous waste under RCRA.
However, agencies and legislatures have urged the EPA to
regulate coal ash as a non-hazardous waste. If the EPA were to
designate coal ash as a hazardous waste, the agency could apply
some, or all, of the disposal and reuse standards that have been
applied to other existing hazardous wastes. Some of the
regulatory actions currently being contemplated could have a
significant impact on our operations and financial position and
the rates we charge our customers. It is not possible to
quantify the impact of those expected rulemakings at this time.
Non-Utility
The Company’s non-utility affiliates are subject to a
number of environmental laws and regulations dealing with the
protection of the environment from various pollutants.
The Michigan coke battery facility received and responded to
information requests from the EPA that resulted in the issuance
of a Notice of Violation in June of 2007 alleging potential
maximum achievable control technologies and new source review
violations. The EPA is in the process of reviewing the
Company’s position of demonstrated compliance and has not
initiated escalated enforcement. At this time, the Company
cannot predict the impact of this issue. Furthermore, the
Michigan coke battery facility is the subject of an
investigation by the MDNRE concerning visible emissions readings
that resulted from the Company self reporting to MDNRE
questionable activities by an employee of a contractor hired by
the Company to perform the visible emissions readings. At this
time, the Company cannot predict the impact of this
investigation.
The Company is also in the process of settling historical air
and water violations at its coke battery facility located in
Pennsylvania. At this time, the Company cannot predict the
impact of this settlement. The Company received two notices of
violation from the Pennsylvania Department of Environmental
Protection in 2010 alleging
35
Table of Contents
violations of the permit for the Pennsylvania coke battery
facility in connection with coal pile storm water runoff. The
Company has implemented best management practices to address
this issue and is currently seeking a permit from the
Pennsylvania Department of Environmental Protection to upgrade
its wastewater treatment technology to a biological treatment
facility. The Company expects to spend approximately
$0.7 million on the existing waste water treatment system
to comply with existing water discharge requirements. The
Company may spend an additional $13 million over the next
few years to meet future regulatory requirements and gain other
operational improvements/savings. The Company’s non-utility
affiliates are substantially in compliance with all
environmental requirements, other than as noted above.
Global
Climate Change
Climate regulation
and/or
legislation is being proposed and discussed within the
U.S. Congress and the EPA. Despite passage of a greenhouse
gas cap and trade bill by the U.S. House in June 2009, the
Senate has been unable to pass a similar climate bill. A
greenhouse gas cap and trade program is not expected to be
included in energy or climate bills to be considered by the
112th Congress. Meanwhile, the EPA is beginning to implement
regulatory actions under the Clean Air Act to address emission
of greenhouse gases. The EPA regulation of greenhouse gases
(GHGs) begins in 2011 requiring the best available control
technology (BACT) for major sources or modifications to existing
major sources that cause significant increases in GHG emissions.
The impact of this rule is uncertain until BACT is better
defined by the permitting agencies. Pending or future
legislation or other regulatory actions could have a material
impact on our operations and financial position and the rates we
charge our customers. Impacts include expenditures for
environmental equipment beyond what is currently planned,
financing costs related to additional capital expenditures, the
purchase of emission offsets from market sources and the
retirement of facilities where control equipment is not
economical. We would seek to recover these incremental costs
through increased rates charged to our utility customers.
Increased costs for energy produced from traditional sources
could also increase the economic viability of energy produced
from renewable
and/or
nuclear sources and energy efficiency initiatives and the
development of market-based trading of carbon offsets providing
business opportunities for our utility and non-utility segments.
It is not possible to quantify these impacts on DTE Energy or
its customers at this time.
OUTLOOK
The next few years will be a period of rapid change for DTE
Energy and for the energy industry. Our strong utility base,
combined with our integrated non-utility operations, position us
well for long-term growth.
Looking forward, we will focus on several areas that we expect
will improve future performance:
| • | improving Electric and Gas Utility customer satisfaction; | |
| • | continuing to pursue regulatory stability and investment recovery for our utilities; | |
| • | managing the growth of our utility asset base; | |
| • | optimizing our cost structure across all business segments; | |
| • | managing cash, capital and liquidity to maintain or improve our financial strength; and | |
| • | investing in businesses that integrate our assets and leverage our skills and expertise. |
We will continue to pursue opportunities to grow our businesses
in a disciplined manner if we can secure opportunities that meet
our strategic, financial and risk criteria.
RESULTS
OF OPERATIONS
The following sections provide a detailed discussion of the
operating performance and future outlook of our segments.
36
Table of Contents
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Net Income Attributable to DTE Energy by Segment:
|
||||||||||||
|
Electric Utility
|
$ | 441 | $ | 376 | $ | 331 | ||||||
|
Gas Utility
|
127 | 80 | 85 | |||||||||
|
Gas Storage and Pipelines
|
51 | 49 | 38 | |||||||||
|
Unconventional Gas Production(1)
|
(11 | ) | (9 | ) | 84 | |||||||
|
Power and Industrial Projects
|
85 | 31 | 40 | |||||||||
|
Energy Trading
|
6 | 75 | 42 | |||||||||
|
Corporate & Other
|
(69 | ) | (70 | ) | (94 | ) | ||||||
|
Discontinued Operations
|
— | — | 20 | |||||||||
|
Net Income Attributable to DTE Energy Company
|
$ | 630 | $ | 532 | $ | 546 | ||||||
| (1) | 2008 net income of the Unconventional Gas Production segment resulted principally from the gain on the sale of a portion of our Barnett shale properties See Note 10 of the Notes to the Consolidated Financial Statements in Item 8 of this Report. |
ELECTRIC
UTILITY
Our Electric Utility segment consists of Detroit Edison.
Electric Utility results are discussed below:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Operating Revenues
|
$ | 4,993 | $ | 4,714 | $ | 4,874 | ||||||
|
Fuel and Purchased Power
|
1,580 | 1,491 | 1,778 | |||||||||
|
Gross Margin
|
3,413 | 3,223 | 3,096 | |||||||||
|
Operation and Maintenance
|
1,305 | 1,277 | 1,322 | |||||||||
|
Depreciation and Amortization
|
849 | 844 | 743 | |||||||||
|
Taxes Other Than Income
|
237 | 205 | 232 | |||||||||
|
Asset (Gains) Losses, Reserves and Impairments, Net
|
(6 | ) | (2 | ) | (1 | ) | ||||||
|
Operating Income
|
1,028 | 899 | 800 | |||||||||
|
Other (Income) and Deductions
|
317 | 295 | 283 | |||||||||
|
Income Tax Provision
|
270 | 228 | 186 | |||||||||
|
Net Income Attributable to DTE Energy Company
|
$ | 441 | $ | 376 | $ | 331 | ||||||
|
Operating Income as a Percent of Operating Revenues
|
21 | % | 19 | % | 16 | % | ||||||
Gross margin
increased $190 million in 2010 and
increased $127 million in 2009. Revenues associated with
certain tracking mechanisms and surcharges are offset by related
expenses elsewhere in the Consolidated Statement of Operations.
The following table details changes in various gross margin
components relative to the comparable prior period:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Weather, net of RDM
|
$ | 84 | $ | (66 | ) | |||
|
Energy optimization and renewable surcharge/regulatory offset
|
(10 | ) | 54 | |||||
|
Securitization bond and tax surcharge rate increase
|
40 | 62 | ||||||
|
2010 rate order, surcharges and other
|
76 | 77 | ||||||
|
Increase in gross margin
|
$ | 190 | $ | 127 | ||||
37
Table of Contents
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands of MWh) | ||||||||||||
|
Electric Sales
|
||||||||||||
|
Residential
|
15,726 | 14,625 | 15,492 | |||||||||
|
Commercial
|
16,570 | 18,200 | 18,920 | |||||||||
|
Industrial
|
10,195 | 9,922 | 13,086 | |||||||||
|
Other
|
3,210 | 3,229 | 3,218 | |||||||||
| 45,701 | 45,976 | 50,716 | ||||||||||
|
Interconnection sales(1)
|
4,876 | 5,156 | 3,583 | |||||||||
|
Total Electric Sales
|
50,577 | 51,132 | 54,299 | |||||||||
|
Electric Deliveries
|
||||||||||||
|
Retail and Wholesale
|
45,701 | 45,976 | 50,716 | |||||||||
|
Electric Customer Choice, including self generators(2)
|
5,005 | 1,477 | 1,457 | |||||||||
|
Total Electric Sales and Deliveries
|
50,706 | 47,453 | 52,173 | |||||||||
| (1) | Represents power that is not distributed by Detroit Edison. | |
| (2) | Includes deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements. |
| 2010 | 2009 | 2008 | ||||||||||||||||||||||
| (In thousands of MWh) | ||||||||||||||||||||||||
|
Power Generated and Purchased
|
||||||||||||||||||||||||
|
Power Plant Generation
|
||||||||||||||||||||||||
|
Fossil
|
39,433 | 73 | % | 40,595 | 74 | % | 41,254 | 71 | % | |||||||||||||||
|
Nuclear
|
7,738 | 14 | 7,406 | 14 | 9,613 | 17 | ||||||||||||||||||
| 47,171 | 87 | 48,001 | 88 | 50,867 | 88 | |||||||||||||||||||
|
Purchased Power
|
6,638 | 13 | 6,495 | 12 | 6,877 | 12 | ||||||||||||||||||
|
System Output
|
53,809 | 100 | % | 54,496 | 100 | % | 57,744 | 100 | % | |||||||||||||||
|
Less Line Loss and Internal Use
|
(3,232 | ) | (3,364 | ) | (3,445 | ) | ||||||||||||||||||
|
Net System Output
|
50,577 | 51,132 | 54,299 | |||||||||||||||||||||
|
Average Unit Cost ($/MWh)
|
||||||||||||||||||||||||
|
Generation(1)
|
$ | 18.94 | $ | 18.20 | $ | 17.93 | ||||||||||||||||||
|
Purchased Power
|
$ | 42.38 | $ | 37.74 | $ | 69.50 | ||||||||||||||||||
|
Overall Average Unit Cost
|
$ | 21.83 | $ | 20.53 | $ | 24.07 | ||||||||||||||||||
| (1) | Represents fuel costs associated with power plants. |
Operation and maintenance
expense increased
$28 million in 2010 and decreased $45 million in 2009.
The increase in 2010 is primarily due to higher restoration and
line clearance expenses of $40 million, higher energy
optimization and renewable energy expenses of $18 million,
higher legal expenses of $15 million, partially offset by
reduced uncollectible expenses of $20 million, lower
generation expenses of $18 million and lower employee
benefit-related expenses of $6 million. The decrease in
2009 was primarily due to $71 million from continuous
improvement initiatives and other cost reductions resulting in
lower contract labor and outside services expense, information
technology and other staff expenses, $14 million of lower
employee benefit-related expenses, lower restoration and line
clearance expenses of $12 million, $9 million of
reduced uncollectible expenses and $6 million of reduced
maintenance activities, partially offset by higher pension and
health care costs of $54 million and $14 million of
energy optimization and renewable energy expenses.
38
Table of Contents
Depreciation and amortization
expense increased
$5 million in 2010 and $101 million in 2009 due
primarily to a higher depreciable base and increased
amortization of regulatory assets.
Taxes other than income
were higher by $32 million
in 2010 due primarily to a $30 million reduction in
property tax expense in 2009 due to refunds received in
settlement of appeals of assessments for prior years.
Outlook
— We continue to move forward in our
efforts to improve the operating performance and cash flow of
Detroit Edison. The 2010 MPSC order provided for an
uncollectible expense tracking mechanism which financially
assists in mitigating the impacts of economic conditions in our
service territory and a revenue decoupling mechanism that
addresses changes in average customer usage due to general
economic conditions, weather and conservation. These and other
tracking mechanisms and surcharges are expected to result in
lower earnings volatility. We expect that our planned
significant environmental and renewable expenditures will result
in earnings growth. Looking forward, we face additional
challenges, such as higher levels of capital spending,
volatility in prices for coal and other commodities, increased
transportation costs, investment returns and changes in discount
rate assumptions in benefit plans and health care costs, lower
levels of wholesale sales due to contract expirations, and
uncertainty of legislative or regulatory actions regarding
climate change. We expect to continue our continuous improvement
efforts to improve productivity and decrease our costs while
improving customer satisfaction with consideration of customer
rate affordability.
GAS
UTILITY
Our Gas Utility segment consists of MichCon and Citizens.
Gas Utility results are discussed below:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Operating Revenues
|
$ | 1,648 | $ | 1,788 | $ | 2,152 | ||||||
|
Cost of Gas
|
870 | 1,057 | 1,378 | |||||||||
|
Gross Margin
|
778 | 731 | 774 | |||||||||
|
Operation and Maintenance
|
378 | 415 | 464 | |||||||||
|
Depreciation and Amortization
|
92 | 107 | 102 | |||||||||
|
Taxes Other Than Income
|
55 | 49 | 48 | |||||||||
|
Asset (Gains) and Losses, Net
|
— | (18 | ) | (26 | ) | |||||||
|
Operating Income
|
253 | 178 | 186 | |||||||||
|
Other (Income) and Deductions
|
59 | 59 | 60 | |||||||||
|
Income Tax Provision
|
67 | 39 | 41 | |||||||||
|
Net Income Attributable to DTE Energy Company
|
$ | 127 | $ | 80 | $ | 85 | ||||||
|
Operating Income as a Percent of Operating Revenues
|
15 | % | 10 | % | 9 | % | ||||||
Gross margin
increased $47 million in 2010 and
decreased $43 million in 2009. Revenues associated with
certain tracking mechanisms and surcharges are offset by related
expenses elsewhere in the Consolidated Statement
39
Table of Contents
of Operations. The following table details changes in various
gross margin components relative to the comparable prior period:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
2010 self-implementation and rate order
|
$ | 125 | $ | — | ||||
|
Lost and stolen gas
|
13 | (15 | ) | |||||
|
Midstream transportation and storage revenues
|
(20 | ) | 22 | |||||
|
Uncollectible tracking mechanism
|
(43 | ) | (28 | ) | ||||
|
Lower sales volumes
|
— | (13 | ) | |||||
|
Weather
|
(23 | ) | (4 | ) | ||||
|
Other
|
(5 | ) | (5 | ) | ||||
|
Increase (decrease) in gross margin
|
$ | 47 | $ | (43 | ) | |||
|
Gas Markets (in Bcf)
|
||||||||||||
|
Gas sales
|
118 | 137 | 148 | |||||||||
|
End user transportation
|
140 | 124 | 123 | |||||||||
| 258 | 261 | 271 | ||||||||||
|
Intermediate transportation
|
391 | 463 | 438 | |||||||||
| 649 | 724 | 709 | ||||||||||
Operation and maintenance
expense decreased
$37 million in 2010 and $49 million in 2009. The
decrease in 2010 is primarily due to reduced uncollectible
expenses of $35 million and the deferral of
$32 million of previously expensed CTA restructuring
expenses, partially offset by higher maintenance expenses of
$11 million, increased energy optimization expenses of
$9 million, higher employee benefit-related expenses of
$3 million and expense of $3 million for contributions
to the Low Income Energy Efficiency Fund. The decrease in 2009
was primarily due to $33 million of reduced uncollectible
expenses, $15 million of lower employee benefit-related
expenses, $14 million from continuous improvement
initiatives and other cost reductions resulting in lower
contract labor and outside services expense, information
technology and other staff expenses, partially offset by higher
health care expenses of $8 million and $4 million of
energy optimization expenses. See Note 12 of Notes to
Consolidated Financial Statements in Item 8 of this report.
Depreciation and amortization
expense decreased
$15 million in 2010 due to the March 2010 MPSC order that
reduced MichCon’s depreciation rates effective
April 1, 2010.
Asset (gains) losses, net
decreased $18 million due
to 2009 gains on the sale of base gas and the sale of certain
gathering and processing assets.
Outlook —
We continue to move forward in our
efforts to improve the operating performance and cash flow of
Gas Utility. Unfavorable economic trends have resulted in a
decrease in the number of customers in our service territory,
increased customer conservation and continued high levels of
theft and uncollectible accounts receivable. The MPSC has
provided for an uncollectible expense tracking mechanism which
assists in mitigating the impacts of economic conditions in our
service territory and a revenue decoupling mechanism that
addresses changes in average customer usage due to general
economic conditions and conservation. These and other tracking
mechanisms and surcharges are expected to result in lower
earnings volatility in the future. Looking forward, we face
additional issues, such as volatility in gas prices, investment
returns and changes in discount rate assumptions in benefit
plans and health care costs. We expect to continue an intense
focus on our continuous improvement efforts to improve
productivity, minimize lost and stolen gas, and decrease our
costs while improving customer satisfaction with consideration
of customer rate affordability.
40
Table of Contents
GAS
STORAGE AND PIPELINES
Our Gas Storage and Pipelines segment consists of our
non-utility gas pipelines and storage businesses.
Gas Storage and Pipelines results are discussed below:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Operating Revenues
|
$ | 83 | $ | 82 | $ | 71 | ||||||
|
Operation and Maintenance
|
14 | 15 | 12 | |||||||||
|
Depreciation and Amortization
|
5 | 5 | 5 | |||||||||
|
Taxes Other Than Income
|
2 | 2 | 3 | |||||||||
|
Asset (Gains) and Losses, Net
|
— | — | 1 | |||||||||
|
Operating Income
|
62 | 60 | 50 | |||||||||
|
Other (Income) and Deductions
|
(25 | ) | (23 | ) | (12 | ) | ||||||
|
Income Tax Provision
|
32 | 33 | 24 | |||||||||
|
Net Income
|
55 | 50 | 38 | |||||||||
|
Noncontrolling interest
|
4 | 1 | — | |||||||||
|
Net Income Attributable to DTE Energy
|
$ | 51 | $ | 49 | $ | 38 | ||||||
Net income attributable to DTE Energy increased $2 million
and $11 million in 2010 and 2009, respectively. The 2010
increase was driven by higher gas storage revenues and lower
project development costs. The 2009 increase was driven by
higher operating revenues resulting from increased capacity sold
and higher rates from renewing storage contracts related to
long-term agreements. In addition, in 2009 we had higher equity
earnings from our investments in the Vector and Millennium
Pipelines, reflecting a first full year of operations for
Millennium.
Outlook —
Our Gas Storage and Pipelines
business expects to continue its steady growth plan and is
evaluating new pipeline and storage investment opportunities.
UNCONVENTIONAL
GAS PRODUCTION
Our Unconventional Gas Production business is engaged in natural
gas and oil exploration, development and production within the
Barnett shale in northern Texas. In January 2008, we sold a
portion of our Barnett shale properties for gross proceeds of
approximately $260 million. We recognized a gain of
$128 million ($80 million after-tax) on the sale in
2008.
Unconventional Gas Production results are discussed below:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Operating Revenues
|
$ | 32 | $ | 31 | $ | 48 | ||||||
|
Operation and Maintenance
|
16 | 15 | 22 | |||||||||
|
Depreciation, Depletion and Amortization
|
15 | 16 | 12 | |||||||||
|
Taxes Other Than Income
|
2 | 1 | 1 | |||||||||
|
Asset (Gains) and Losses, Net
|
10 | 6 | (120 | ) | ||||||||
|
Operating Income (Loss)
|
(11 | ) | (7 | ) | 133 | |||||||
|
Other (Income) and Deductions
|
6 | 6 | 2 | |||||||||
|
Income Tax Provision (Benefit)
|
(6 | ) | (4 | ) | 47 | |||||||
|
Net Income (Loss) Attributable to DTE Energy Company
|
$ | (11 | ) | $ | (9 | ) | $ | 84 | ||||
41
Table of Contents
Operating revenues
increased $1 million in 2010 as a
result of higher commodity prices, and an increase in oil
production. The 2009 decrease of $17 million was due to
lower commodity prices realized for physical sales as well as a
reduction in volumes hedged.
Operation and maintenance
expense increased
$1 million in 2010 due to more wells on line and increased
water handling cost. The decrease of $7 million in 2009 was
due to operational efficiencies and lower costs for goods and
services due to economic conditions.
Asset (gains) and losses, net
increased $4 million
in 2010 and decreased $126 million in 2009. The increase in
2010 was due to impairment of unproved leasehold positions that
the Company does not intend to drill prior to expiration. The
2009 decrease was due to the gain of $128 million
($80 million after-tax) on the 2008 sale of a portion of
our Barnett shale properties and $2 million lower
impairment in 2009 of expired or expiring leasehold positions
that the Company did not intend to drill at then current
commodity prices.
Outlook —
In the longer-term, we plan to
continue to develop our holdings in the western portion of the
Barnett shale and to seek opportunities for additional
monetization of select properties when conditions are
appropriate. Our strategy for 2011 is to maintain our focus on
reducing operating expenses and optimizing production volume.
Given the current outlook of low natural gas prices, drilling
efforts will continue to target liquids rich gas and oil
production. During 2011, we expect total capital investment of
$25 million to drill approximately 20 new wells and
continue to acquire select acreage and achieve production of
approximately 6 Bcfe of natural gas, compared with
5 Bcfe in 2010.
POWER AND
INDUSTRIAL PROJECTS
Power and Industrial Projects is comprised primarily of projects
that deliver energy and utility-type products and services to
industrial, commercial and institutional customers; provide coal
transportation services and marketing; and sell electricity from
biomass-fired energy projects.
Power and Industrial Projects results are discussed below:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Operating Revenues
|
$ | 1,144 | $ | 661 | $ | 987 | ||||||
|
Operation and Maintenance
|
978 | 593 | 899 | |||||||||
|
Depreciation and Amortization
|
60 | 40 | 34 | |||||||||
|
Taxes other than Income
|
14 | 9 | 12 | |||||||||
|
Other Asset (Gains) and Losses, Reserves and Impairments, Net
|
(14 | ) | (6 | ) | 6 | |||||||
|
Operating Income
|
106 | 25 | 36 | |||||||||
|
Other (Income) and Deductions
|
13 | (1 | ) | (20 | ) | |||||||
|
Income Taxes
|
||||||||||||
|
Provision
|
36 | 5 | 18 | |||||||||
|
Production Tax Credits
|
(33 | ) | (12 | ) | (7 | ) | ||||||
| 3 | (7 | ) | 11 | |||||||||
|
Net Income
|
90 | 33 | 45 | |||||||||
|
Noncontrolling interest
|
5 | 2 | 5 | |||||||||
|
Net Income Attributable to DTE Energy Company
|
$ | 85 | $ | 31 | $ | 40 | ||||||
VIEs
— As discussed in Notes 1 and 3 of
Notes to the Consolidated Financial Statements, effective
January 1, 2010, we adopted the provisions of ASU
2009-17,
Amendments to FASB Interpretation 46(R)
. ASU
2009-17
changed the methodology for determining the primary beneficiary
of a VIE from a quantitative risk and rewards-based model to a
qualitative determination. The Company re-evaluated prior VIE
and primary beneficiary determinations and, as a result, began
consolidating five entities. Since these entities were
previously accounted for under the equity method, the VIE
consolidation had no impact on Net Income Attributable to DTE
Energy. As a
42
Table of Contents
result of the consolidation of these VIEs, Operating Revenues
and Operations and Maintenance expense increased
$174 million and $122 million, respectively, in 2010.
Operating revenues
increased $309 million, net of
VIE adjustments, in 2010 and decreased $326 million in
2009. The 2010 increase is attributed primarily to
$172 million of higher coke sales and a $156 million
increase in
on-site
services, partially offset by a $18 million decrease in
coal trading and transportation services. The 2009 decrease is
due primarily to $111 million reduction in certain coal
structured transactions, $176 million of lower pricing and
volumes of coal and emissions and $84 million of lower coke
demand, partially offset by a $107 million increase in coal
related services.
Operation and maintenance
expense increased
$262 million, net of VIE adjustments, in 2010 and decreased
$306 million in 2009. The increase is due primarily to
$118 million of higher coke production and a
$154 million increase in
on-site
services, partially offset by $10 million of lower coal
trading and transportation services. The 2009 decrease is due
primarily to $111 million decrease in certain coal
structured transactions and $64 million of lower coke
demand, $141 million of lower pricing and volumes of coal
and emissions and operating expenses, partially offset by
$75 million of higher coal related services.
Asset (Gains) Losses
were higher by $8 million in
2010 due primarily to the sale of DTE Rail Services and an
increase in installment gains from the sale of a coke battery.
Other (income) and deductions
were lower by
$14 million in 2010 and lower by $19 million in 2009.
The decreases in both years were due primarily to lower equity
earnings in various projects and higher intercompany interest
associated with project investment.
Outlook
— We expect sustained production levels
of metallurgical coke and pulverized coal supplied to steel
industry customers for 2011. Beginning in 2011, substantially
all of the metallurgical coke is under long-term contracts. The
tax credits associated with our steel industry fuels facilities
expired at December 31, 2010 that will result in lower tax
credits of approximately $29 million in 2011. We supply
on-site
energy services to the domestic automotive manufacturers who
have also experienced stabilized demand for automobiles. Our
on-site
energy services will continue to be delivered in accordance with
the terms of long-term contracts.
In late 2009, we began operating reduced emission fuel
facilities located at Detroit Edison owned coal-fired power
plants. The facilities reduce Nitrogen Oxide (NO) and Mercury
(Hg) emissions and qualify for production tax credits when the
fuel is sold to an unrelated party through 2019. We continue to
optimize these facilities by seeking investors for facilities
operating at Detroit Edison sites and intend to relocate other
facilities to alternative sites which may provide increased
production and emission reduction opportunities in 2011 and
future years. In January 2011, the Company entered into an
agreement to sell a membership interest in one of these reduced
emission fuel facilities that is located at a Detroit Edison
site.
Environmental and economic trends are creating growth
opportunities for renewable power. The increasing number of
states with renewable portfolio standards and energy efficiency
mandates provides investment opportunity in waste-wood power
generation. In addition to the three facilities in operation, we
will convert and place into service two additional facilities in
2011 and 2013. We will continue to look for additional
investment opportunities for waste-wood renewable power
generation and other energy projects at favorable prices.
Effective January 1, 2011, our existing long-term rail
transportation contract, at rates significantly below the
current market, expired and we anticipate a decrease in
transportation-related revenue of approximately
$130 million as a result. The decrease in revenue will be
mostly offset by lower variable costs incurred to provide the
transportation.
We will continue to work with suppliers and the railroads to
promote secure and competitive access to coal to meet the energy
requirements of our customers. Power and Industrial Projects
will continue to leverage its extensive energy-related operating
experience and project management capability to develop
additional energy projects to serve energy intensive industrial
customers.
ENERGY
TRADING
Energy Trading focuses on physical and financial power and gas
marketing and trading, structured transactions, enhancement of
returns from DTE Energy’s asset portfolio, and optimization
of contracted natural gas
43
Table of Contents
pipeline transportation and storage, and power transmission and
generating capacity positions. Energy Trading also provides
natural gas, power and ancillary services to various utilities
which may include the management of associated storage and
transportation contracts on the customers’ behalf.
Energy Trading results are discussed below:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Operating Revenues
|
$ | 875 | $ | 804 | $ | 1,388 | ||||||
|
Fuel, Purchased Power and Gas
|
786 | 603 | 1,235 | |||||||||
|
Gross Margin
|
89 | 201 | 153 | |||||||||
|
Operation and Maintenance
|
59 | 71 | 68 | |||||||||
|
Depreciation and Amortization
|
5 | 5 | 5 | |||||||||
|
Taxes Other Than Income
|
2 | 3 | 2 | |||||||||
|
Operating Income
|
23 | 122 | 78 | |||||||||
|
Other (Income) and Deductions
|
12 | 10 | 5 | |||||||||
|
Income Tax Provision (Benefit)
|
5 | 37 | 31 | |||||||||
|
Net Income Attributable to DTE Energy Company
|
$ | 6 | $ | 75 | $ | 42 | ||||||
Gross margin
decreased $112 million in 2010 and
increased $48 million in 2009. The overall decrease in
gross margin in 2010 was the result of lower economic
performance, lower commodity prices, lower volatility in the
markets we participate in and lower risk positions relative to
2009, coupled with the absence of prior year timing-related
gains. We experienced timing-related earnings volatility based
on market movement related to derivative contracts.
The decrease in 2010 represents a $78 million decrease in
realized margins and $34 million decrease in unrealized
margins. The $78 million decrease in realized margins is
due to $108 million of unfavorable results, primarily in
our power and gas trading and gas full requirements strategies,
offset by $30 million of favorable results, primarily in
our power full requirements and power origination strategies.
The $34 million decrease in unrealized margins is due to
$56 million of unfavorable results, primarily in our power
trading strategy and the absence of prior year timing-related
gains related to our gas transportation strategy. These
decreases were offset by $22 million of favorable results,
primarily due to timing-related gains in our gas full
requirements strategy.
The $48 million increase in gross margin in 2009 was due to
increases in realized margins of $69 million, offset by
decreases in unrealized margins of $21 million. The
$69 million increase in realized margins was primarily the
result of increases in our gas trading strategy and
timing-related increases in our gas storage and gas
transportation strategies. The $21 million decrease in
unrealized margins consisted of unfavorable results of
$58 million from our gas trading and gas storage
strategies, partially offset by increases of $29 million
primarily in our power trading strategy and timing-related
improvements of $8 million in our oil strategies.
Operation and maintenance
expense decreased
$12 million in 2010 and increased $3 million in 2009.
The 2010 decrease was primarily due to lower incentive costs.
The 2009 increase was due to higher payroll and incentive costs
and commissions, partially offset by lower contractor expense
and allocated corporate costs.
Income tax provision
decreased $32 million in 2010.
This decrease is due to lower pretax income, partially offset by
$10 million of favorable tax-related adjustments in 2009
resulting from the settlement of federal income tax audits.
Income taxes were higher by $6 million in 2009 due to
higher pretax income, partially offset by the $10 million
of favorable tax-related adjustments.
Outlook —
In the near term, we expect market
conditions to remain challenging and the profitability of this
segment may be impacted by the volatility or lack thereof in
commodity prices in the markets we participate in and the
uncertainty of impacts associated with financial reform,
regulatory changes and changes in operating rules of regional
transmission organizations.
44
Table of Contents
The Energy Trading portfolio includes financial instruments,
physical commodity contracts and gas inventory, as well as
contracted natural gas pipeline transportation and storage, and
power transmission and generation capacity positions. Energy
Trading also provides natural gas, power and ancillary services
to various utilities which may include the management of
associated storage and transportation contracts on the
customers’ behalf. Significant portions of the Energy
Trading portfolio are economically hedged. Most financial
instruments and physical power and gas contracts are deemed
derivatives, whereas natural gas inventory, power transmission,
pipeline transportation and certain storage assets are not
derivatives. As a result, we will experience earnings volatility
as derivatives are
marked-to-market
without revaluing the underlying non-derivative contracts and
assets. Our strategy is to economically manage the price risk of
these underlying non-derivative contracts and assets with
futures, forwards, swaps and options. This results in gains and
losses that are recognized in different interim and annual
accounting periods.
See also the “Fair Value” section that follows.
CORPORATE &
OTHER
Corporate & Other includes various holding company
activities and holds certain non-utility debt and energy-related
investments.
The 2010 net loss of $69 million was an improvement of
$1 million from the 2009 net loss of $70 million.
The net $1 million improvement was a result of the 2009
donation to the DTE Energy Foundation of $10 million and
lower impairments of investments of $3 million, partially
offset by higher state and local taxes of $3 million,
higher tax related interest of $5 million, increased
financing costs of $5 million. The 2010 donation to the DTE
Energy Foundation of $14 million was made by Detroit Edison
and MichCon.
The 2009 net loss of $70 million decreased from the
net loss of $94 million in 2008 due to $34 million
favorable tax-related adjustments primarily resulting from the
settlement of federal income tax audits, $10 million lower
inter-company interest expense and $9 million lower costs
related to natural gas forward contracts associated with the
2007 sale of the Antrim Shale properties. These favorable
variances were partially offset by a $10 million donation
of cash and
available-for-sale
securities to the DTE Energy Foundation, $10 million
resulting from a realignment of employee benefit expense from
MichCon, $7 million increase in financing fees,
$1 million increased impairment of investments and a
$1 million decrease in interest income.
CUMULATIVE
EFFECT OF ACCOUNTING CHANGES
Effective January 1, 2008, we adopted ASC 820
(SFAS No. 157,
Fair Value Measurements)
. The
cumulative effect adjustment upon adoption of ASC 820
represented a $4 million increase to the January 1,
2008 balance of retained earnings. See also the “Fair
Value” section.
CAPITAL
RESOURCES AND LIQUIDITY
Cash
Requirements
We use cash to maintain and expand our electric and gas
utilities and to grow our non-utility businesses, retire and pay
interest on long-term debt and pay dividends. We believe that we
will have sufficient internal and external capital resources to
fund anticipated capital and operating requirements. In 2011, we
expect that cash from operations will be $1.9 billion due
to lower working capital requirements. We anticipate base level
capital investments and expenditures for existing businesses in
2011 of up to $1.4 billion. The capital needs of our
utilities will increase due primarily to environmental
expenditures. We plan to seek regulatory approval to include
these capital expenditures within our regulatory rate base
consistent with prior treatment. Capital spending for growth of
45
Table of Contents
existing or new non-utility businesses will depend on the
existence of opportunities that meet our strict risk-return and
value creation criteria.
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Cash and Cash Equivalents
|
||||||||||||
|
Cash Flow From (Used For)
|
||||||||||||
|
Operating activities:
|
||||||||||||
|
Net income
|
$ | 639 | $ | 535 | $ | 553 | ||||||
|
Depreciation, depletion and amortization
|
1,027 | 1,020 | 899 | |||||||||
|
Deferred income taxes
|
457 | 205 | 348 | |||||||||
|
Gain on sale of non-utility business
|
— | — | (128 | ) | ||||||||
|
Gain on sale of synfuel and other assets, net and synfuel
impairment
|
(5 | ) | (10 | ) | (35 | ) | ||||||
|
Working capital and other
|
(293 | ) | 69 | (78 | ) | |||||||
| 1,825 | 1,819 | 1,559 | ||||||||||
|
Investing activities:
|
||||||||||||
|
Plant and equipment expenditures — utility
|
(1,011 | ) | (960 | ) | (1,183 | ) | ||||||
|
Plant and equipment expenditures — non-utility
|
(88 | ) | (75 | ) | (190 | ) | ||||||
|
Proceeds from sale of non-utility business
|
— | — | 253 | |||||||||
|
Proceeds (refunds) from sale of synfuels and other assets
|
56 | 83 | (278 | ) | ||||||||
|
Restricted cash and other investments
|
(183 | ) | (112 | ) | (125 | ) | ||||||
| (1,226 | ) | (1,064 | ) | (1,523 | ) | |||||||
|
Financing activities:
|
||||||||||||
|
Issuance of long-term debt
|
614 | 427 | 1,310 | |||||||||
|
Redemption of long-term debt
|
(663 | ) | (486 | ) | (446 | ) | ||||||
|
Repurchase of long-term debt
|
— | — | (238 | ) | ||||||||
|
Short-term borrowings, net
|
(177 | ) | (417 | ) | (340 | ) | ||||||
|
Issuance of common stock
|
36 | 35 | — | |||||||||
|
Repurchase of common stock
|
— | — | (16 | ) | ||||||||
|
Dividends on common stock and other
|
(396 | ) | (348 | ) | (354 | ) | ||||||
| (586 | ) | (789 | ) | (84 | ) | |||||||
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
$ | 13 | $ | (34 | ) | $ | (48 | ) | ||||
Cash
from Operating Activities
A majority of our operating cash flow is provided by our
electric and gas utilities, which are significantly influenced
by factors such as weather, electric Customer Choice, regulatory
deferrals, regulatory outcomes, economic conditions and
operating costs.
Cash from operations totaling $1.8 billion in 2010 was
consistent with the comparable 2009 period. The operating cash
flow comparison primarily reflects higher net income after
adjusting for non-cash and non-operating items (depreciation,
depletion and amortization, deferred income taxes and gains on
sales of assets), offset by higher working capital requirements.
Cash from operations totaling $1.8 billion in 2009,
increased $260 million from the comparable 2008 period. The
operating cash flow comparison primarily reflects lower working
capital requirements and higher net income after adjusting for
non-cash and non-operating items (depreciation, depletion and
amortization, deferred income taxes and gains on sales of
assets).
Cash
from Investing Activities
Cash inflows associated with investing activities are primarily
generated from the sale of assets, while cash outflows are
primarily generated from plant and equipment expenditures. In
any given year, we will look to realize
46
Table of Contents
cash from under-performing or non-strategic assets or matured
fully valued assets. Capital spending within the utility
business is primarily to maintain our generation and
distribution infrastructure, comply with environmental
regulations and gas pipeline replacements. Capital spending
within our non-utility businesses is for ongoing maintenance and
expansion. The balance of non-utility spending is for growth,
which we manage very carefully. We look to make investments that
meet strict criteria in terms of strategy, management skills,
risks and returns. All new investments are analyzed for their
rates of return and cash payback on a risk adjusted basis. We
have been disciplined in how we deploy capital and will not make
investments unless they meet our criteria. For new business
lines, we initially invest based on research and analysis. We
start with a limited investment, we evaluate results and either
expand or exit the business based on those results. In any given
year, the amount of growth capital will be determined by the
underlying cash flows of the Company with a clear understanding
of any potential impact on our credit ratings.
Net cash used for investing activities was approximately
$1.2 billion in 2010, compared with net cash used for
investing activities of $1.1 billion in 2009. The change
was primarily driven by increased capital expenditures by our
utility and non-utility businesses.
Net cash used for investing activities was approximately
$1.1 billion in 2009, compared with net cash used for
investing activities of $1.5 billion in 2008. The change
was primarily driven by reduced capital expenditures by our
utility and non-utility businesses and the completion of refund
payments to our synfuel partners in 2008.
Cash
from Financing Activities
We rely on both short-term borrowing and long-term financing as
a source of funding for our capital requirements not satisfied
by our operations.
Our strategy is to have a targeted debt portfolio blend of fixed
and variable interest rates and maturity. We continually
evaluate our leverage target, which is currently 50% to 52%, to
ensure it is consistent with our objective to have a strong
investment grade debt rating.
Net cash used for financing activities was $586 million in
2010, compared to net cash used for financing activities of
approximately $789 million for the same period in 2009. The
change was primarily attributable to decreased payments for
short-term borrowings. Increases in issuances of long-term debt
were offset by increased long-term debt redemptions.
Net cash used for financing activities was $789 million in
2009, compared to net cash used for financing activities of
approximately $84 million for the same period in 2008. The
change was primarily attributable to lower proceeds from the
issuance of long-term debt.
Outlook
We expect cash flow from operations to increase over the
long-term primarily as a result of growth from our utilities and
the non-utility businesses. We expect growth in our utilities to
be driven primarily by new and existing state and federal
regulations that will result in additional environmental and
renewable energy investments which will increase the base from
which rates are determined. Our non-utility growth is expected
from additional investments in energy projects as economic
conditions improve.
We may be impacted by the delayed collection of underrecoveries
of our various recovery and tracking mechanisms as a result of
timing of MPSC orders. Energy prices are likely to be a source
of volatility with regard to working capital requirements for
the foreseeable future. We are continuing our efforts to
identify opportunities to improve cash flow through working
capital initiatives and maintaining flexibility in the timing
and extent of our long-term capital projects.
We have approximately $900 million in long-term debt
maturing in the next twelve months. DTE Energy has
$600 million of unsecured debt maturing in June 2011 which
is expected to be funded through a combination of internally
generated funds and short- term debt. Substantially all of the
remaining debt maturities relate to Securitization and other
Detroit Edison issues. The repayment of the principal amount of
the Securitization debt is
47
Table of Contents
funded through a surcharge payable by Detroit Edison’s
electric customers. The repayment of the other Detroit Edison
debt is expected to be refinanced with long-term debt.
In August 2010, DTE Energy and its wholly owned subsidiaries,
Detroit Edison and MichCon, entered into amended and restated
two-year $1 billion unsecured revolving credit agreements
and new three-year $800 million unsecured revolving credit
agreements with a syndicate of 23 banks that may be used for
general corporate borrowings, but are intended to provide
liquidity support for each of the companies’ commercial
paper programs. No one bank provides more than 8.25% of the
commitment in any facility. Borrowings under the facilities are
available at prevailing short-term interest rates. DTE Energy
has approximately $1.7 billion of available liquidity at
December 31, 2010.
In March 2010, the PPACA and the HCERA were enacted into law
(collectively, the “Act”). The Act is a comprehensive
health care reform bill. A provision of the PPACA repeals the
current rule permitting deduction of the portion of the drug
coverage expense that is offset by the Medicare Part D
subsidy, effective for taxable years beginning after
December 31, 2012. We have initiated changes in benefit
design and delivery and are continuing to evaluate alternatives
to minimize the impact of the legislation. We contributed
$200 million to our pension plans during the year ended
December 31, 2010, including a DTE Energy stock
contribution of $100 million in March 2010. We
contributed $160 million to our postretirement medical and
life insurance benefit plans during the year ended
December 31, 2010, including a transfer of $25 million
from the MichCon Grantor Trust. In January 2011, we contributed
$200 million to our pension plans. Also, we contributed
$81 million to our postretirement medical and life
insurance plans in January 2011, and we expect to contribute up
to an additional $90 million throughout the remainder of
2011.
In July 2010, a federal financial reform act was signed into
law. The legislation reshapes financial regulation and is
intended to address specific issues that contributed to the
financial crisis. Most major areas of the legislation will be
dependent upon regulatory interpretation, rulemaking and
implementation. We do not expect any material effect on our
operations and financial position.
The Tax Relief, Unemployment Insurance Reauthorization, and Job
Creation Act of 2010 provided for a special allowance for bonus
depreciation in 2011 and 2012. Bonus depreciation is accelerated
depreciation on certain types of business equipment that allows
a tax deduction of either 50% or 100% of the cost of qualifying
property in the year the asset is placed in service. DTE Energy
expects to generate approximately $100 million to
$200 million of cash in
2011-2012
from bonus depreciation deductions, a significant portion of
which is expected to result from Detroit Edison property, plant
and equipment expenditures during the qualifying period. The
cash benefit is an acceleration of tax deductions that the
Company would otherwise have received over 20 years.
We believe we have sufficient operating flexibility, cash
resources and funding sources to maintain adequate amounts of
liquidity and to meet our future operating cash and capital
expenditure needs. However, virtually all of our businesses are
capital intensive, or require access to capital, and the
inability to access adequate capital could adversely impact
earnings and cash flows.
See Notes 12, 16, 18, and 21 of the Notes to Consolidated
Financial Statements in Item 8 of this Report.
48
Table of Contents
Contractual
Obligations
The following table details our contractual obligations for debt
redemptions, leases, purchase obligations and other long-term
obligations as of December 31, 2010:
|
2016
|
||||||||||||||||||||
| Total | 2011 | 2012-2013 | 2014-2015 | and Beyond | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
|
Long-term debt:
|
||||||||||||||||||||
|
Mortgage bonds, notes and other
|
$ | 6,888 | $ | 765 | $ | 691 | $ | 1,036 | $ | 4,396 | ||||||||||
|
Securitization bonds
|
793 | 150 | 341 | 302 | — | |||||||||||||||
|
Trust preferred-linked securities
|
289 | — | — | — | 289 | |||||||||||||||
|
Capital lease obligations
|
62 | 12 | 18 | 18 | 14 | |||||||||||||||
|
Interest
|
5,547 | 457 | 814 | 649 | 3,627 | |||||||||||||||
|
Operating leases
|
211 | 39 | 58 | 40 | 74 | |||||||||||||||
|
Electric, gas, fuel, transportation and storage purchase
obligations(1)
|
5,921 | 2,175 | 1,670 | 744 | 1,332 | |||||||||||||||
|
Other long-term obligations(2)(3)(4)
|
243 | 49 | 44 | 31 | 119 | |||||||||||||||
|
Total obligations
|
$ | 19,954 | $ | 3,647 | $ | 3,636 | $ | 2,820 | $ | 9,851 | ||||||||||
| (1) | Excludes amounts associated with full requirements contracts where no stated minimum purchase volume is required. | |
| (2) | Includes liabilities for unrecognized tax benefits of $28 million. | |
| (3) | Excludes other long-term liabilities of $184 million not directly derived from contracts or other agreements. | |
| (4) | At December 31, 2010, we met the minimum pension funding levels required under the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 for our defined benefit pension plans. We may contribute more than the minimum funding requirements for our pension plans and may also make contributions to our benefit plans and our postretirement benefit plans; however, these amounts are not included in the table above as such amounts are discretionary. Planned funding levels are disclosed in the Capital Resources and Liquidity and Critical Accounting Estimates sections of MD&A and in Note 21 of the Notes to Consolidated Financial Statements in Item 8 of this Report. |
Credit
Ratings
Credit ratings are intended to provide banks and capital market
participants with a framework for comparing the credit quality
of securities and are not a recommendation to buy, sell or hold
securities. The Company’s credit ratings affect our cost of
capital and other terms of financing as well as our ability to
access the credit and commercial paper markets. Management
believes that our current credit ratings provide sufficient
access to the capital markets. However, disruptions in the
banking and capital markets not specifically related to us may
affect our ability to access these funding sources or cause an
increase in the return required by investors.
As part of the normal course of business, Detroit Edison,
MichCon and various non-utility subsidiaries of the Company
routinely enter into physical or financially settled contracts
for the purchase and sale of electricity, natural gas, coal,
capacity, storage and other energy-related products and
services. Certain of these contracts contain provisions which
allow the counterparties to request that the Company post cash
or letters of credit in the event that the senior unsecured debt
rating of DTE Energy is downgraded below investment grade.
Certain of these contracts for Detroit Edison and MichCon
contain similar provisions in the event that the senior
unsecured debt rating of the particular utility is downgraded
below investment grade. The amount of such collateral which
could be requested fluctuates based upon commodity prices and
the provisions and maturities of the underlying transactions and
could be substantial. Also, upon a downgrade below investment
grade, we could have restricted access to the commercial paper
market and if DTE Energy is downgraded below investment grade
our non-utility businesses, especially the Energy Trading and
Power and Industrial Projects segments, could be required to
restrict operations due to a lack of available liquidity. A
downgrade below investment grade could potentially increase the
borrowing costs of DTE
49
Table of Contents
Energy and its subsidiaries and may limit access to the capital
markets. The impact of a downgrade will not affect our ability
to comply with our existing debt covenants. While we currently
do not anticipate such a downgrade, we cannot predict the
outcome of current or future credit rating agency reviews.
In January 2010, Standard & Poor’s Rating Group
(Standard & Poor’s) revised the outlook on DTE
Energy and its subsidiaries to stable from negative, and raised
the short-term corporate credit and commercial paper ratings for
DTE Energy, Detroit Edison and MichCon to ‘A-2’ from
‘A-3’. The revision was primarily due to the
diminished possibility of a downgrade in light of the
Company’s decreasing regulatory risk. We have experienced
an improvement in our ability to issue commercial paper since
the restoration of our short-term ratings. Short-term
borrowings, principally in the form of commercial paper, provide
us with the liquidity needed on a daily basis. Our commercial
paper program is supported by our unsecured credit facilities.
Potential instability in the credit markets and any lowering of
ratings may impact future access to the commercial paper
markets, which may require us to draw on our
back-up
facilities. In June 2010, Standard & Poor’s
revised the outlook on DTE Energy and its subsidiaries to
positive from stable. The outlook revision reflected the
Company’s decreasing regulatory risk. In December 2010,
Standard and Poor’s upgraded the corporate credit rating of
DTE Energy and its utility subsidiaries to ‘BBB+’ from
‘BBB’ to reflect the company’s decreasing
regulatory risk and improved financial measures. At the same
time, Standard and Poor’s raised the rating on Detroit
Edison’s senior secured debt to ‘A’ from
‘A-’ and raised the rating on MichCon’s senior
secured debt to ‘A’ from ‘BBB+’. In January
2011, Fitch Ratings revised the rating outlook for Detroit
Edison to positive from stable due to improvement in its credit
protection measures as a result of supportive regulatory
policies in Michigan.
CRITICAL
ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with
generally accepted accounting principles require that management
apply accounting policies and make estimates and assumptions
that affect results of operations and the amounts of assets and
liabilities reported in the financial statements. Management
believes that the areas described below require significant
judgment in the application of accounting policy or in making
estimates and assumptions in matters that are inherently
uncertain and that may change in subsequent periods. Additional
discussion of these accounting policies can be found in the
Notes to Consolidated Financial Statements in Item 8 of
this Report.
Regulation
A significant portion of our business is subject to regulation.
This results in differences in the application of generally
accepted accounting principles between regulated and
non-regulated businesses. Detroit Edison and MichCon are
required to record regulatory assets and liabilities for certain
transactions that would have been treated as revenue or expense
in non-regulated businesses. Future regulatory changes or
changes in the competitive environment could result in the
discontinuance of this accounting treatment for regulatory
assets and liabilities for some or all of our businesses.
Management believes that currently available facts support the
continued use of regulatory assets and liabilities and that all
regulatory assets and liabilities are recoverable or refundable
in the current rate environment.
In March 2010, the PPACA and the HCERA were enacted into law
(collectively, the “Act”). A provision of the PPACA
repeals the current rule permitting deduction of the portion of
the drug coverage expense that is offset by the Medicare
Part D subsidy, effective for taxable years beginning after
December 31, 2012. This change in tax law required a
remeasurement of the deferred tax asset related to the Other
Postretirement Benefit Obligation (OPEB) and the deferred tax
liability related to the OPEB Regulatory Asset. Income tax
accounting rules require the impact of a change in tax law be
recognized in continuing operations in the Consolidated
Statements of Operations in the period that the tax law change
is enacted. However, regulated businesses may defer changes in
tax law if allowed by regulators. The MPSC’s historical
practice has been to recognize both the expense and working
capital impacts for OPEB costs. In addition, the current and
deferred tax effects related to OPEB costs have been recognized
consistently. The effects of the subsidy have been reflected
through lower tax expense included in rates. We believe we have
reasonable assurance that the impacts related to the enactment
of the Act are recoverable through rates in future periods.
Therefore, the amounts related to Detroit Edison of
$18 million and MichCon of $4 million have been
deferred as Regulatory Assets.
See Note 12 of the Notes to Consolidated Financial
Statements in Item 8 of this Report.
50
Table of Contents
Derivatives
and Hedging Activities
Derivatives are generally recorded at fair value and shown as
Derivative Assets or Liabilities. Changes in the fair value of
the derivative instruments are recognized in earnings in the
period of change, unless the derivative meets certain defined
conditions and qualifies as an effective hedge. The normal
purchases and normal sales exception requires, among other
things, physical delivery in quantities expected to be used or
sold over a reasonable period in the normal course of business.
Contracts that are designated as normal purchases and normal
sales are not recorded at fair value. Substantially all of the
commodity contracts entered into by Detroit Edison and MichCon
meet the criteria specified for this exception.
Fair value is defined as the price that would be received to
sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date
in a principal or most advantageous market. Fair value is a
market-based measurement that is determined based on inputs,
which refer broadly to assumptions that market participants use
in pricing assets and liabilities. These inputs can be readily
observable, market corroborated or generally unobservable
inputs. Management makes certain assumptions it believes that
market participants would use in pricing assets and liabilities,
including assumptions about risk, and the risks inherent in the
inputs to valuation techniques. Credit risk of the Company and
our counterparties is incorporated in the valuation of the
assets and liabilities through the use of credit reserves, the
impact of which was immaterial at December 31, 2010 and
2009. Management believes it uses valuation techniques that
maximize the use of observable market-based inputs and minimize
the use of unobservable inputs.
The fair values we calculate for our derivatives may change
significantly as inputs and assumptions are updated for new
information. Actual cash returns realized on our derivatives may
be different from the results we estimate using models. As fair
value calculations are estimates based largely on commodity
prices, we perform sensitivity analysis on the fair values of
our forward contracts. See sensitivity analysis in Item 7A.
Quantitative and Qualitative Disclosures About Market Risk. See
also the Fair Value section, herein. See Notes 4 and 5 of
the Notes to Consolidated Financial Statements in Item 8 of
this report.
Allowance
for Doubtful Accounts
We establish an allowance for doubtful accounts based on
historical losses and management’s assessment of existing
economic conditions, customer trends, and other factors. The
allowance for doubtful accounts for our two utilities is
calculated using the aging approach that utilizes rates
developed in reserve studies and applies these factors to past
due receivable balances. As a result of the reduction in past
due receivables in 2010, our allowance for doubtful accounts
decreased significantly from the 2009 balance. We believe the
allowance for doubtful accounts is based on reasonable
estimates. As part of the 2005 gas rate order for MichCon, the
MPSC provided for the establishment of an uncollectible expense
tracking mechanism that partially mitigates the impact
associated with MichCon uncollectible expenses. The MPSC
provided for a similar tracking mechanism for Detroit Edison in
its rate order received January 2010. Detroit Edison filed for
the suspension of the tracking mechanism effective with the
order in its pending rate case.
Asset
Impairments
Goodwill
Certain of our reporting units have goodwill or allocated
goodwill resulting from purchase business combinations. We
perform an impairment test for each of our reporting units with
goodwill annually or whenever events or circumstances indicate
that the value of goodwill may be impaired. In performing Step 1
of the impairment test, we compare the fair value of the
reporting unit to its carrying value including goodwill. If the
carrying value including goodwill were to exceed the fair value
of a reporting unit, Step 2 of the test would be performed. Step
2 of the impairment test requires the carrying value of goodwill
to be reduced to its fair value, if lower, as of the test date.
For Step 1 of the test, we estimate the reporting unit’s
fair value using standard valuation techniques, including
techniques which use estimates of projected future results and
cash flows to be generated by the reporting unit. Such
techniques generally include a terminal value that utilizes an
earnings multiple approach, which incorporates the current
market values of comparable entities. These cash flow valuations
involve a number of estimates that require
51
Table of Contents
broad assumptions and significant judgment by management
regarding future performance. We also employ market-based
valuation techniques to test the reasonableness of the
indications of value for the reporting units determined under
the cash flow technique.
We performed our annual impairment test as of October 1,
2010 and determined that except for the Coal Services reporting
unit, the estimated fair value of each reporting unit exceeded
its carrying value, and no impairment existed. The
$4 million of goodwill attributable to the Coal Services
reporting unit was written off in the fourth quarter of 2010 in
connection with the sale of rail services assets. We also
compared the aggregate fair value of our reporting units to our
overall market capitalization. The implied premium of the
aggregate fair value over market capitalization is likely
attributable to an acquisition control premium (the price in
excess of a stock’s market price that investors typically
pay to gain control of an entity). The results of the test and
key estimates that were incorporated are as follows.
As of October 1, 2010 Valuation Date
|
Fair Value
|
Discount
|
Terminal
|
||||||||||||||||
| Reporting Unit | Goodwill | Reduction %(a) | Rate | Multiple(b) | Valuation Methodology(c) | |||||||||||||
| ($ in millions) | ||||||||||||||||||
|
Electric Utility
|
$ | 1,206 | 26 | % | 7 | % | 8.0 | x | DCF, assuming stock sale | |||||||||
|
Gas Utility
|
759 | 7 | % | 7 | % | 9.5 | x | DCF, assuming stock sale | ||||||||||
|
Energy Services
|
28 | 66 | % | 13 | % | 9.0 | x | DCF, assuming asset sale(d) | ||||||||||
|
Coal Services
|
4 | (e) | n/a | 12 | % | 8.5 | x | DCF, assuming asset sale | ||||||||||
|
Gas Storage and Pipelines
|
8 | 66 | % | 10 | % | 8.0 | x | DCF, assuming asset sale | ||||||||||
|
Energy Trading
|
17 | 74 | % | 15 | % | n/a | Blended DCF, economic value of trading portfolio | |||||||||||
|
Unconventional Gas Production
|
2 | 62 | % | 13 | % | n/a | Blended DCF, transaction multiples | |||||||||||
| $ | 2,024 | |||||||||||||||||
| (a) | Percentage by which the fair value of the reporting unit would need to decline to equal its carrying value, including goodwill. | |
| (b) | Multiple of enterprise value (sum of debt plus equity value) to earnings before interest, taxes, depreciation and amortization (EBITDA.) | |
| (c) | Discounted cash flows (DCF) incorporated 2011-2015 projected cash flows plus a calculated terminal value. | |
| (d) | Asset sales were assumed except for Energy Services’ reduced emissions fuel projects, which assumed stock sales. | |
| (e) | Goodwill attributable to Coal Services was written off in connection with the sale of rail services assets. Refer to Note 10 of the Notes to Consolidated Financial Statements in Item 8 of this Report. |
The Gas Utility reporting unit passed Step 1 of the impairment
test by a 7% margin. A substantive decrease in market multiples,
negative regulatory actions or other disruptions in cash flows
for the Gas Utility reporting unit could result in an impairment
charge in the foreseeable future. For example, at the current
discount rate and holding all other variables constant, a 0.5x
decrease in the terminal multiple would lower the fair value by
approximately $130 million. At the lower fair value, the
Gas Utility reporting unit would likely fail Step 1 of the test
potentially resulting in a charge for impairment of goodwill
following completion of the Step 2 analysis.
We perform an annual impairment test each October. In between
annual tests, we monitor our estimates and assumptions regarding
estimated future cash flows, including the impact of movements
in market indicators in future quarters and will update our
impairment analyses if a triggering event occurs. While we
believe our assumptions are reasonable, actual results may
differ from our projections. To the extent projected results or
cash flows are revised downward, the reporting unit may be
required to write down all or a portion of its goodwill, which
would adversely impact our earnings.
52
Table of Contents
Long-Lived
Assets
We evaluate the carrying value of our long-lived assets,
excluding goodwill, when circumstances indicate that the
carrying value of those assets may not be recoverable.
Conditions that could have an adverse impact on the cash flows
and fair value of the long-lived assets are deteriorating
business climate, condition of the asset, or plans to dispose of
the asset before the end of its useful life. The review of
long-lived assets for impairment requires significant
assumptions about operating strategies and estimates of future
cash flows, which require assessments of current and projected
market conditions. An impairment evaluation is based on an
undiscounted cash flow analysis at the lowest level for which
independent cash flows of long-lived assets can be identified
from other groups of assets and liabilities. Impairment may
occur when the carrying value of the asset exceeds the future
undiscounted cash flows. When the undiscounted cash flow
analysis indicates a long-lived asset is not recoverable, the
amount of the impairment loss is determined by measuring the
excess of the long-lived asset over its fair value. An
impairment would require us to reduce both the long-lived asset
and current period earnings by the amount of the impairment,
which would adversely impact our earnings. See Note 11 of
Notes to Consolidated Financial Statements in Item 8 of
this Report.
Pension
and Postretirement Costs
We sponsor defined benefit pension plans and postretirement
benefit plans for substantially all of the employees of the
Company. The measurement of the plan obligations and cost of
providing benefits under these plans involve various factors,
including numerous assumptions and accounting elections. When
determining the various assumptions that are required, we
consider historical information as well as future expectations.
The benefit costs are affected by, among other things, the
actual rate of return on plan assets, the long-term expected
return on plan assets, the discount rate applied to benefit
obligations, the incidence of mortality, the expected remaining
service period of plan participants, level of compensation and
rate of compensation increases, employee age, length of service,
the anticipated rate of increase of health care costs and the
level of benefits provided to employees and retirees. Pension
and postretirement benefit costs attributed to the segments are
included with labor costs and ultimately allocated to projects
within the segments, some of which are capitalized.
We had pension costs for pension plans of $112 million in
2010, $58 million in 2009, and $24 million in 2008.
Postretirement benefits costs for all plans were
$164 million in 2010, $205 million in 2009 and
$142 million in 2008. Pension and postretirement benefits
costs for 2010 are calculated based upon a number of actuarial
assumptions, including an expected long-term rate of return on
our plan assets of 8.75%. In developing our expected long-term
rate of return assumptions, we evaluated asset class risk and
return expectations, as well as inflation assumptions. Projected
returns are based on broad equity, bond and other markets. Our
2011 expected long-term rate of return on pension plan assets is
based on an asset allocation assumption utilizing active
investment management of 47% in equity markets, 25% in fixed
income markets, and 28% invested in other assets. Because of
market volatility, we periodically review our asset allocation
and rebalance our portfolio when considered appropriate. Given
market conditions, we are lowering our long-term rate of return
assumption for our pension plans to 8.50% for 2011. Our
long-term rate of return assumption for our postretirement
health and life plans will remain at 8.75% for 2011. We believe
these two rates are reasonable assumptions for the long-term
rate of return on our plan assets for 2011 given our investment
strategy. We will continue to evaluate our actuarial
assumptions, including our expected rate of return, at least
annually.
We calculate the expected return on pension and other
postretirement benefit plan assets by multiplying the expected
return on plan assets by the market-related value (MRV) of plan
assets at the beginning of the year, taking into consideration
anticipated contributions and benefit payments that are to be
made during the year. Current accounting rules provide that the
MRV of plan assets can be either fair value or a calculated
value that recognizes changes in fair value in a systematic and
rational manner over not more than five years. For our pension
plans, we use a calculated value when determining the MRV of the
pension plan assets and recognize changes in fair value over a
three-year period. Accordingly, the future value of assets will
be impacted as previously deferred gains or losses are
recognized. Financial markets in 2010 contributed to our
investment performance resulting in unrecognized net gains. As
of December 31, 2010, we had $242 million of
cumulative losses that remain to be recognized in the
calculation of the MRV of pension assets. For our postretirement
benefit plans, we use fair value when
53
Table of Contents
determining the MRV of postretirement benefit plan assets,
therefore all investment losses and gains have been recognized
in the calculation of MRV for these plans.
The discount rate that we utilize for determining future pension
and postretirement benefit obligations is based on a yield curve
approach and a review of bonds that receive one of the two
highest ratings given by a recognized rating agency. The yield
curve approach matches projected pension plan and postretirement
benefit payment streams with bond portfolios reflecting actual
liability duration unique to our plans. The discount rate
determined on this basis decreased to 5.5% at December 31,
2010 from 5.9% at December 31, 2009. We estimate that our
2011 total pension costs will approximate $167 million
compared to $112 million in 2010 primarily due to a lower
discount rate, partially offset by better than expected asset
returns in 2010 and 2011 contributions. Our 2011 postretirement
benefit costs will approximate $137 million compared to
$164 million in 2010 primarily due to changing our strategy
for providing post-65 prescription drug benefits to retirees,
better than expected asset returns in 2010 and favorable retiree
medical utilization. These positive impacts were partially
offset by a lower discount rate and updated assumed long-term
retiree medical inflation. Our health care trend rate assumes 7%
for 2011 through 2015, 6.5% in 2016, 6% in 2017, 5.5% in 2018
and 5% in 2019 and beyond. Future actual pension and
postretirement benefit costs will depend on future investment
performance, changes in future discount rates and various other
factors related to plan design. The pension cost tracking
mechanism that provided for recovery or refunding of pension
costs above or below amounts reflected in Detroit Edison’s
base rates, at the request of Detroit Edison, was not
reauthorized by the MPSC in its rate order effective
January 1, 2009. The MPSC approved the deferral of the
non-capitalized portion of MichCon’s negative pension
expense. MichCon records a regulatory liability for any negative
pension costs, as determined under generally accepted accounting
principles.
Lowering the expected long-term rate of return on our plan
assets by one percentage point would have increased our 2010
pension costs by approximately $30 million. Lowering the
discount rate and the salary increase assumptions by one
percentage point would have increased our 2010 pension costs by
approximately $10 million. Lowering the health care cost
trend assumptions by one percentage point would have decreased
our postretirement benefit service and interest costs for 2010
by approximately $25 million.
The value of our pension and postretirement benefit plan assets
was $3.9 billion at December 31, 2010 and
$3.4 billion at December 31, 2009. At
December 31, 2010 our pension plans were underfunded by
$872 million and our other postretirement benefit plans
were underfunded by $1.3 billion. The 2010 and 2009 funding
levels were generally similar due to positive investment
performance returns and plan sponsor contributions in 2010 and
2009, largely offset by the decreased discount rates.
Pension and postretirement costs and pension cash funding
requirements may increase in future years without typical
returns in the financial markets. We made contributions to our
pension plans of $200 million in each of 2010 and 2009.
Also, we contributed $200 million to our pension plans in
January 2011. At the discretion of management, consistent with
the Pension Protection Act of 2006, and depending upon financial
market conditions, we anticipate making contributions to our
pension plans of up to $1.2 billion over the next five
years. We made postretirement benefit plan contributions of
$160 million and $205 million in 2010 and 2009,
respectively. We are required by orders issued by the MPSC to
make postretirement benefit contributions at least equal to the
amounts included in Detroit Edison’s and MichCon’s
base rates. As a result, we contributed $81 million to our
postretirement plans in January 2011 and expect to make up to an
additional $90 million contribution to our postretirement
plans in 2011 and, subject to MPSC funding requirements, up to
$850 million over the next five years. The planned
contributions will be made in cash, DTE Energy common stock or a
combination of cash and stock.
See Note 21 of the Notes to Consolidated Financial
Statements in Item 8 of this Report.
Legal
Reserves
We are involved in various legal proceedings, claims and
litigation arising in the ordinary course of business. We
regularly assess our liabilities and contingencies in connection
with asserted or potential matters, and establish reserves when
appropriate. Legal reserves are based upon management’s
assessment of pending and threatened legal proceedings and
claims against us.
54
Table of Contents
Insured
and Uninsured Risks
Our comprehensive insurance program provides coverage for
various types of risks. Our insurance policies cover risk of
loss including property damage, general liability, workers’
compensation, auto liability, and directors’ and
officers’ liability. Under our risk management policy, we
self-insure portions of certain risks up to specified limits,
depending on the type of exposure. The maximum self-insured
retention for various risks is as follows: property damage-
$10 million, general liability- $7 million,
workers’ compensation- $9 million, and auto
liability-$7 million.
We have an actuarially determined estimate of our incurred but
not reported (IBNR) liability prepared annually and we adjust
our reserves for self-insured risks as appropriate. As of
December 31, 2010, this IBNR liability was approximately
$39 million.
Accounting
for Tax Obligations
We are required to make judgments regarding the potential tax
effects of various financial transactions and results of
operations in order to estimate our obligations to taxing
authorities. We account for uncertain income tax positions using
a benefit recognition model with a two-step approach, a
more-likely-than-not recognition criterion and a measurement
attribute that measures the position as the largest amount of
tax benefit that is greater than 50% likely of being realized
upon ultimate settlement. If the benefit does not meet the more
likely than not criteria for being sustained on its technical
merits, no benefit will be recorded. Uncertain tax positions
that relate only to timing of when an item is included on a tax
return are considered to have met the recognition threshold. We
also have non-income tax obligations related to property, sales
and use and employment-related taxes and ongoing appeals related
to these tax matters.
Accounting for tax obligations requires judgments, including
assessing whether tax benefits are more likely than not to be
sustained, and estimating reserves for potential adverse
outcomes regarding tax positions that have been taken. We also
assess our ability to utilize tax attributes, including those in
the form of carryforwards, for which the benefits have already
been reflected in the financial statements. We do not record
valuation allowances for deferred tax assets related to capital
losses that we believe will be realized in future periods. We
believe the resulting tax reserve balances as of
December 31, 2010 and December 31, 2009 are
appropriately accounted. The ultimate outcome of such matters
could result in favorable or unfavorable adjustments to our
consolidated financial statements and such adjustments could be
material.
See Note 13 of the Notes to Consolidated Financial
Statements in Item 8 of this Report.
NEW
ACCOUNTING PRONOUNCEMENTS
See Note 3 of the Notes to Consolidated Financial
Statements in Item 8 of this Report.
FAIR
VALUE
Derivatives are generally recorded at fair value and shown as
Derivative Assets or Liabilities. Contracts we typically
classify as derivative instruments include power, gas, oil and
certain coal forwards, futures, options and swaps, and foreign
currency exchange contracts. Items we do not generally account
for as derivatives include natural gas inventory, power
transmission, pipeline transportation and certain storage
assets. See Notes 4 and 5 of the Notes to Consolidated
Financial Statements.
As a result of adherence to generally accepted accounting
principles, the tables below do not include the expected
earnings impact of non-derivative gas storage, transportation
and power contracts. Consequently, gains and losses from these
positions may not match with the related physical and financial
hedging instruments in some reporting periods, resulting in
volatility in DTE Energy’s reported
period-by-period
earnings; however, the financial impact of the timing
differences will reverse at the time of physical delivery
and/or
settlement.
The Company manages its
mark-to-market
(MTM) risk on a portfolio basis based upon the delivery period
of its contracts and the individual components of the risks
within each contract. Accordingly, it records and manages the
energy purchase and sale obligations under its contracts in
separate components based on the commodity (e.g. electricity or
gas), the product (e.g. electricity for delivery during peak or
off-peak hours), the delivery location (e.g. by region), the
risk profile (e.g. forward or option), and the delivery period
(e.g. by month and year).
55
Table of Contents
The Company has established a fair value hierarchy, which
prioritizes the inputs to valuation techniques used to measure
fair value in three broad levels. The fair value hierarchy gives
the highest priority to quoted prices (unadjusted) in active
markets for identical assets or liabilities
(Level 1) and the lowest priority to unobservable
inputs (Level 3). For further discussion of the fair value
hierarchy, see Note 4 of the Notes to Consolidated
Financial Statements.
The following tables provide details on changes in our MTM net
asset (or liability) position during 2010:
| Total | ||||
| (In millions) | ||||
|
MTM at December 31, 2009
|
$ | (93 | ) | |
|
Reclassify to realized upon settlement
|
(3 | ) | ||
|
Changes in fair value recorded to income
|
123 | |||
|
Amounts recorded to unrealized income
|
120 | |||
|
Changes in fair value recorded in regulatory liabilities
|
6 | |||
|
Amounts recorded in other comprehensive income pre-tax
|
1 | |||
|
Change in collateral held for others
|
(42 | ) | ||
|
Option premiums paid (received) and other
|
(36 | ) | ||
|
MTM at December 31, 2010
|
$ | (44 | ) | |
The table below shows the maturity of our MTM positions:
|
2014
|
||||||||||||||||||||
|
and
|
Total Fair
|
|||||||||||||||||||
| Source of Fair Value | 2011 | 2012 | 2013 | Beyond | Value | |||||||||||||||
| (In millions) | ||||||||||||||||||||
|
Level 1
|
$ | 9 | $ | (23 | ) | $ | 11 | $ | 10 | $ | 7 | |||||||||
|
Level 2
|
(68 | ) | (54 | ) | (32 | ) | — | (154 | ) | |||||||||||
|
Level 3
|
29 | 33 | (2 | ) | (1 | ) | 59 | |||||||||||||
|
Total MTM before netting adjustments
|
$ | (30 | ) | $ | (44 | ) | $ | (23 | ) | $ | 9 | $ | (88 | ) | ||||||
|
Collateral adjustments
|
$ | 44 | ||||||||||||||||||
|
Total MTM at December 31, 2010
|
$ | (44 | ) | |||||||||||||||||
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
Market
Price Risk
DTE Energy has commodity price risk in both utility and
non-utility businesses arising from market price fluctuations.
The Electric and Gas utility businesses have risks in
conjunction with the anticipated purchases of coal, natural gas,
uranium, electricity, and base metals to meet their service
obligations. However, the Company does not bear significant
exposure to earnings risk as such changes are included in the
form of PSCR and GCR regulatory rate-recovery mechanisms. In
addition, changes in the price of natural gas can impact the
valuation of lost and stolen gas, storage sales revenue and
uncollectible expenses at the Gas Utility. Gas Utility manages
its market price risk related to storage sales revenue primarily
through the sale of long-term storage contracts. The Company is
exposed to short-term cash flow or liquidity risk as a result of
the time differential between actual cash settlements and
regulatory rate recovery.
Our Gas Storage and Pipelines business segment has limited
exposure to natural gas price fluctuations and manages its
exposure through the sale of long-term storage and
transportation contracts.
Our Unconventional Gas Production business segment has exposure
to natural gas and crude oil price fluctuations. These commodity
price fluctuations can impact both current year earnings and
reserve valuations. To manage this exposure we may use forward
energy and futures contracts.
56
Table of Contents
Our Power and Industrial Projects business segment is subject to
electricity, natural gas, coal and coal-based product price risk
and other risks associated with the weakened U.S. economy.
To the extent that commodity price risk has not been mitigated
through the use of long-term contracts, we manage this exposure
using forward energy, capacity and futures contracts.
Our Energy Trading business segment has exposure to electricity,
natural gas, crude oil, heating oil, and foreign currency
exchange price fluctuations. These risks are managed by our
energy marketing and trading operations through the use of
forward energy, capacity, storage, options and futures
contracts, within pre-determined risk parameters.
Credit
Risk
Bankruptcies
The Company purchases and sells electricity, gas, coal, coke and
other energy products from and to numerous companies operating
in the steel, automotive, energy, retail, financial and other
industries. Certain of its customers have filed for bankruptcy
protection under Chapter 11 of the U.S. Bankruptcy
Code. The Company regularly reviews contingent matters relating
to these customers and its purchase and sale contracts and
records provisions for amounts considered at risk of probable
loss. The Company believes its accrued amounts are adequate for
probable loss. The final resolution of these matters may have a
material effect on its consolidated financial statements.
Other
The Company has tracking mechanisms to mitigate a significant
amount of losses related to uncollectible accounts receivable at
Detroit Edison and MichCon. These mechanisms are subject to the
jurisdiction of the MPSC and are periodically reviewed. See
Note 12 of the Notes to Consolidated Financial Statements
in Item 8 of this Report.
We engage in business with customers that are non-investment
grade. We closely monitor the credit ratings of these customers
and, when deemed necessary, we request collateral or guarantees
from such customers to secure their obligations.
Trading
Activities
We are exposed to credit risk through trading activities. Credit
risk is the potential loss that may result if our trading
counterparties fail to meet their contractual obligations. We
utilize both external and internal credit assessments when
determining the credit quality of our trading counterparties.
The following table displays the credit quality of our trading
counterparties as of December 31, 2010:
|
Credit Exposure
|
||||||||||||
|
Before Cash
|
Cash
|
Net Credit
|
||||||||||
| Collateral | Collateral | Exposure | ||||||||||
| (In millions) | ||||||||||||
|
Investment Grade(1)
|
||||||||||||
|
A− and Greater
|
$ | 163 | $ | (10 | ) | $ | 153 | |||||
|
BBB+ and BBB
|
199 | — | 199 | |||||||||
|
BBB−
|
54 | — | 54 | |||||||||
|
Total Investment Grade
|
416 | (10 | ) | 406 | ||||||||
|
Non-investment grade(2)
|
2 | — | 2 | |||||||||
|
Internally Rated — investment grade(3)
|
147 | — | 147 | |||||||||
|
Internally Rated — non-investment grade(4)
|
12 | — | 12 | |||||||||
|
Total
|
$ | 577 | $ | (10 | ) | $ | 567 | |||||
| (1) | This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investor Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group (Standard & Poor’s). The five |
57
Table of Contents
| largest counterparty exposures combined for this category represented approximately 36 percent of the total gross credit exposure. | ||
| (2) | This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures combined for this category represented less than one percent of the total gross credit exposure. | |
| (3) | This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, but are considered investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately 18 percent of the total gross credit exposure. | |
| (4) | This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately two percent of the total gross credit exposure. |
Interest
Rate Risk
We are subject to interest rate risk in connection with the
issuance of debt and preferred securities. In order to manage
interest costs, we may use treasury locks and interest rate swap
agreements. Our exposure to interest rate risk arises primarily
from changes in U.S. Treasury rates, commercial paper rates
and London Inter-Bank Offered Rates (LIBOR). As of
December 31, 2010, we had a floating rate
debt-to-total
debt ratio of approximately two percent (excluding securitized
debt).
Foreign
Currency Exchange Risk
We have foreign currency exchange risk arising from market price
fluctuations associated with fixed priced contracts. These
contracts are denominated in Canadian dollars and are primarily
for the purchase and sale of power as well as for long-term
transportation capacity. To limit our exposure to foreign
currency exchange fluctuations, we have entered into a series of
exchange forward contracts through January 2013. Additionally,
we may enter into fair value foreign currency exchange hedges to
mitigate changes in the value of contracts or loans.
Summary
of Sensitivity Analysis
We performed a sensitivity analysis on the fair values of our
commodity contracts, long-term debt obligations and foreign
currency exchange forward contracts. The commodity contracts and
foreign currency exchange risk listed below principally relate
to our energy marketing and trading activities. The sensitivity
analysis involved increasing and decreasing forward rates at
December 31, 2010 and 2009 by a hypothetical 10% and
calculating the resulting change in the fair values.
The results of the sensitivity analysis calculations as of
December 31, 2010 and 2009:
|
Assuming a
|
Assuming a
|
|||||||||||||||||
| 10% Increase in Rates | 10% Decrease in Rates | |||||||||||||||||
| As of December 31, | As of December 31, | |||||||||||||||||
| Activity | 2010 | 2009 | 2010 | 2009 | Change in the Fair Value of | |||||||||||||
| (In millions) | ||||||||||||||||||
|
Coal Contracts
|
$ | 1 | $ | — | $ | (1 | ) | $ | — | Commodity contracts | ||||||||
|
Gas Contracts
|
$ | (11 | ) | $ | (2 | ) | $ | 10 | $ | 1 | Commodity contracts | |||||||
|
Oil Contracts
|
$ | — | $ | 1 | $ | — | $ | (1 | ) | Commodity contracts | ||||||||
|
Power Contracts
|
$ | (5 | ) | $ | (3 | ) | $ | 5 | $ | 2 | Commodity contracts | |||||||
|
Interest Rate Risk
|
$ | (291 | ) | $ | (290 | ) | $ | 313 | $ | 313 | Long-term debt | |||||||
|
Foreign Currency Exchange Risk
|
$ | 6 | $ | 2 | $ | 7 | $ | (2 | ) | Forward contracts | ||||||||
|
Discount Rates
|
$ | — | $ | — | $ | — | $ | — | Commodity contracts | |||||||||
For further discussion of market risk, see Note 5 of the
Notes to Consolidated Financial Statements in Item 8 of
this Report.
58
Table of Contents
| Item 8. | Financial Statements and Supplementary Data |
The following consolidated financial statements and financial
statement schedule are included herein.
| Page | ||||
| 60 | ||||
|
Consolidated Financial Statements
|
||||
| 61 | ||||
| 63 | ||||
| 64 | ||||
| 66 | ||||
| 67 | ||||
| 68 | ||||
| 69 | ||||
| 69 | ||||
| 72 | ||||
| 76 | ||||
| 77 | ||||
| 84 | ||||
| 89 | ||||
| 89 | ||||
| 90 | ||||
| 91 | ||||
| 92 | ||||
| 93 | ||||
| 94 | ||||
| 101 | ||||
| 104 | ||||
| 104 | ||||
| 106 | ||||
| 108 | ||||
| 108 | ||||
| 109 | ||||
| 110 | ||||
| 115 | ||||
| 128 | ||||
| 131 | ||||
| 132 | ||||
| 134 | ||||
|
Financial Statement Schedule
|
||||
| 146 | ||||
59
Table of Contents
Controls
and Procedures
| (a) | Evaluation of disclosure controls and procedures |
Management of the Company carried out an evaluation, under the
supervision and with the participation of DTE Energy’s
Chief Executive Officer (CEO) and Chief Financial Officer (CFO),
of the effectiveness of the design and operation of the
Company’s disclosure controls and procedures (as defined in
Exchange Act
Rules 13a-15(e)
and
15d-15(e))
as of December 31, 2010, which is the end of the period
covered by this report. Based on this evaluation, the
Company’s CEO and CFO have concluded that such disclosure
controls and procedures are effective in providing reasonable
assurance that information required to be disclosed by the
Company in reports that it files or submits under the Exchange
Act (i) is recorded, processed, summarized and reported
within the time periods specified in the SEC’s rules and
forms and (ii) is accumulated and communicated to the
Company’s management, including its CEO and CFO, as
appropriate to allow timely decisions regarding required
disclosure. Due to the inherent limitations in the effectiveness
of any disclosure controls and procedures, management cannot
provide absolute assurance that the objectives of its disclosure
controls and procedures will be attained.
| (b) | Management’s report on internal control over financial reporting |
Management of the Company is responsible for establishing and
maintaining adequate internal control over financial reporting
as such term is defined in Exchange Act
Rules 13a-15(f)
and
15d-15(f).
Internal control over financial reporting is a process designed
by, or under the supervision of, our CEO and CFO, to provide
reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for
external purposes in accordance with generally accepted
accounting principles.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
Management of the Company has assessed the effectiveness of the
Company’s internal control over financial reporting as of
December 31, 2010. In making this assessment, management
used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) in
Internal
Control — Integrated Framework.
Based on this
assessment, management concluded that, as of December 31,
2010, the Company’s internal control over financial
reporting was effective based on those criteria.
The effectiveness of the Company’s internal control over
financial reporting as of December 31, 2010 has been
audited by PricewaterhouseCoopers LLP, an independent registered
public accounting firm who also audited the Company’s
financial statements, as stated in their report which appears
herein.
| (c) | Changes in internal control over financial reporting |
There have been no changes in the Company’s internal
control over financial reporting during the quarter ended
December 31, 2010 that have materially affected, or are
reasonably likely to materially affect, the Company’s
internal control over financial reporting.
60
Table of Contents
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of DTE Energy Company:
In our opinion, the consolidated financial statements listed in
the accompanying index present fairly, in all material respects,
the financial position of DTE Energy Company and its
subsidiaries at December 31, 2010 and 2009, and the results
of their operations and their cash flows for the years then
ended in conformity with accounting principles generally
accepted in the United States of America. In addition, in our
opinion, the financial statement schedule for the years ended
December 31, 2010 and 2009 listed in the accompanying index
presents fairly, in all material respects, the information set
forth therein when read in conjunction with the related
consolidated financial statements. Also in our opinion, the
Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2010,
based on criteria established in
Internal Control —
Integrated Framework
issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The
Company’s management is responsible for these financial
statements and financial statement schedule, for maintaining
effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over
financial reporting, included in the accompanying
Management’s report on internal control over financial
reporting. Our responsibility is to express opinions on these
financial statements, on the financial statement schedule, and
on the Company’s internal control over financial reporting
based on our integrated audits. We conducted our audits in
accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we
plan and perform the audits to obtain reasonable assurance about
whether the financial statements are free of material
misstatement and whether effective internal control over
financial reporting was maintained in all material respects. Our
audits of the financial statements included examining, on a test
basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used
and significant estimates made by management, and evaluating the
overall financial statement presentation. Our audit of internal
control over financial reporting included obtaining an
understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audits also
included performing such other procedures as we considered
necessary in the circumstances. We believe that our audits
provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s
internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of
management and directors of the company; and (iii) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Detroit, Michigan
February 18, 2011
61
Table of Contents
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of DTE Energy Company:
We have audited the consolidated statements of operations, cash
flows, comprehensive income, and changes in equity of DTE Energy
Company and subsidiaries (the “Company”) for the year
ended December 31, 2008. Our audit also included the 2008
information in the financial statement schedule listed in the
accompanying index. These financial statements and financial
statement schedule are the responsibility of the Company’s
management. Our responsibility is to express an opinion on the
consolidated financial statements and financial statement
schedule based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the results of operations and
cash flows of DTE Energy Company and subsidiaries for the year
ended December 31, 2008 in conformity with accounting
principles generally accepted in the United States of America.
Also, in our opinion, such 2008 financial statement schedule,
when considered in relation to the basic consolidated financial
statements of the Company taken as a whole, presents fairly, in
all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Detroit, Michigan
February 27, 2009
(August 20, 2009, as to the effects of the retrospective
adoption of Accounting Standards Codification (“ASC”)
810-10
and
ASC 260-10
as described in Note 3 to the consolidated financial
statements)
62
Table of Contents
DTE
Energy Company
| Year Ended December 31 | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In millions, except per share amounts) | ||||||||||||
|
Operating Revenues
|
$ | 8,557 | $ | 8,014 | $ | 9,329 | ||||||
|
Operating Expenses
|
||||||||||||
|
Fuel, purchased power and gas
|
3,190 | 3,118 | 4,306 | |||||||||
|
Operation and maintenance
|
2,578 | 2,372 | 2,694 | |||||||||
|
Depreciation, depletion and amortization
|
1,027 | 1,020 | 901 | |||||||||
|
Taxes other than income
|
308 | 275 | 304 | |||||||||
|
Gain on sale of non-utility business
|
— | — | (128 | ) | ||||||||
|
Other asset (gains) and losses, reserves and impairments, net
|
(10 | ) | (20 | ) | (11 | ) | ||||||
| 7,093 | 6,765 | 8,066 | ||||||||||
|
Operating Income
|
1,464 | 1,249 | 1,263 | |||||||||
|
Other (Income) and Deductions
|
||||||||||||
|
Interest expense
|
549 | 545 | 503 | |||||||||
|
Interest income
|
(12 | ) | (19 | ) | (19 | ) | ||||||
|
Other income
|
(78 | ) | (102 | ) | (104 | ) | ||||||
|
Other expenses
|
55 | 43 | 64 | |||||||||
| 514 | 467 | 444 | ||||||||||
|
Income Before Income Taxes
|
950 | 782 | 819 | |||||||||
|
Income Tax Provision
|
311 | 247 | 288 | |||||||||
|
Income from Continuing Operations
|
639 | 535 | 531 | |||||||||
|
Discontinued Operations Income, net of tax
|
— | — | 22 | |||||||||
|
Net Income
|
639 | 535 | 553 | |||||||||
|
Less: Net Income Attributable to Noncontrolling Interests
From
|
||||||||||||
|
Continuing operations
|
9 | 3 | 5 | |||||||||
|
Discontinued operations
|
— | — | 2 | |||||||||
| 9 | 3 | 7 | ||||||||||
|
Net Income Attributable to DTE Energy Company
|
$ | 630 | $ | 532 | $ | 546 | ||||||
|
Basic Earnings per Common Share
|
||||||||||||
|
Income from continuing operations
|
$ | 3.75 | $ | 3.24 | $ | 3.22 | ||||||
|
Discontinued operations
|
— | — | .12 | |||||||||
|
Total
|
$ | 3.75 | $ | 3.24 | $ | 3.34 | ||||||
|
Diluted Earnings per Common Share
|
||||||||||||
|
Income from continuing operations
|
$ | 3.74 | $ | 3.24 | $ | 3.22 | ||||||
|
Discontinued operations
|
— | — | .12 | |||||||||
|
Total
|
$ | 3.74 | $ | 3.24 | $ | 3.34 | ||||||
|
Weighted Average Common Shares Outstanding
|
||||||||||||
|
Basic
|
168 | 164 | 163 | |||||||||
|
Diluted
|
169 | 164 | 163 | |||||||||
|
Dividends Declared per Common Share
|
$ | 2.18 | $ | 2.12 | $ | 2.12 | ||||||
See Notes to Consolidated Financial Statements
63
Table of Contents
DTE
Energy Company
| December 31 | ||||||||
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
ASSETS
|
||||||||
|
Current Assets
|
||||||||
|
Cash and cash equivalents
|
$ | 65 | $ | 52 | ||||
|
Restricted cash (Note 2)
|
120 | 84 | ||||||
|
Accounts receivable (less allowance for doubtful accounts of
$196 and $262, respectively)
|
||||||||
|
Customer
|
1,393 | 1,438 | ||||||
|
Other
|
402 | 217 | ||||||
|
Inventories
|
||||||||
|
Fuel and gas
|
460 | 309 | ||||||
|
Materials and supplies
|
202 | 200 | ||||||
|
Deferred income taxes
|
139 | 167 | ||||||
|
Derivative assets
|
131 | 209 | ||||||
|
Other
|
255 | 201 | ||||||
| 3,167 | 2,877 | |||||||
|
Investments
|
||||||||
|
Nuclear decommissioning trust funds
|
939 | 817 | ||||||
|
Other
|
518 | 598 | ||||||
| 1,457 | 1,415 | |||||||
|
Property
|
||||||||
|
Property, plant and equipment
|
21,574 | 20,588 | ||||||
|
Less accumulated depreciation, depletion and amortization
|
(8,582 | ) | (8,157 | ) | ||||
| 12,992 | 12,431 | |||||||
|
Other Assets
|
||||||||
|
Goodwill
|
2,020 | 2,024 | ||||||
|
Regulatory assets
|
4,058 | 4,110 | ||||||
|
Securitized regulatory assets
|
729 | 870 | ||||||
|
Intangible assets
|
67 | 54 | ||||||
|
Notes receivable
|
123 | 113 | ||||||
|
Derivative assets
|
77 | 116 | ||||||
|
Other
|
206 | 185 | ||||||
| 7,280 | 7,472 | |||||||
|
Total Assets
|
$ | 24,896 | $ | 24,195 | ||||
See Notes to Consolidated Financial Statements
64
Table of Contents
DTE
Energy Company
Consolidated
Statements of Financial
Position —
(Continued)
| December 31 | ||||||||
| 2010 | 2009 | |||||||
| (In millions, except shares) | ||||||||
|
LIABILITIES AND EQUITY
|
||||||||
|
Current Liabilities
|
||||||||
|
Accounts payable
|
$ | 729 | $ | 723 | ||||
|
Accrued interest
|
111 | 114 | ||||||
|
Dividends payable
|
95 | 88 | ||||||
|
Short-term borrowings
|
150 | 327 | ||||||
|
Current portion long-term debt, including capital leases
|
925 | 671 | ||||||
|
Derivative liabilities
|
142 | 220 | ||||||
|
Other
|
597 | 502 | ||||||
| 2,749 | 2,645 | |||||||
|
Long-Term Debt (net of current portion)
|
||||||||
|
Mortgage bonds, notes and other
|
6,114 | 6,237 | ||||||
|
Securitization bonds
|
643 | 793 | ||||||
|
Trust preferred-linked securities
|
289 | 289 | ||||||
|
Capital lease obligations
|
43 | 51 | ||||||
| 7,089 | 7,370 | |||||||
|
Other Liabilities
|
||||||||
|
Deferred income taxes
|
2,632 | 2,096 | ||||||
|
Regulatory liabilities
|
1,328 | 1,337 | ||||||
|
Asset retirement obligations
|
1,498 | 1,420 | ||||||
|
Unamortized investment tax credit
|
75 | 85 | ||||||
|
Derivative liabilities
|
110 | 198 | ||||||
|
Liabilities from transportation and storage contracts
|
83 | 96 | ||||||
|
Accrued pension liability
|
866 | 881 | ||||||
|
Accrued postretirement liability
|
1,275 | 1,287 | ||||||
|
Nuclear decommissioning
|
149 | 136 | ||||||
|
Other
|
275 | 328 | ||||||
| 8,291 | 7,864 | |||||||
|
Commitments and Contingencies (Notes 12 and 20)
|
||||||||
|
Equity
|
||||||||
|
Common stock, without par value, 400,000,000 shares
authorized, 169,428,406 and 165,400,045 shares issued and
outstanding, respectively
|
3,440 | 3,257 | ||||||
|
Retained earnings
|
3,431 | 3,168 | ||||||
|
Accumulated other comprehensive loss
|
(149 | ) | (147 | ) | ||||
|
Total DTE Energy Company Shareholders’ Equity
|
6,722 | 6,278 | ||||||
|
Noncontrolling interests
|
45 | 38 | ||||||
|
Total Equity
|
6,767 | 6,316 | ||||||
|
Total Liabilities and Equity
|
$ | 24,896 | $ | 24,195 | ||||
See Notes to Consolidated Financial Statements
65
Table of Contents
DTE
Energy Company
| Year Ended December 31 | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Operating Activities
|
||||||||||||
|
Net income
|
$ | 639 | $ | 535 | $ | 553 | ||||||
|
Adjustments to reconcile net income to net cash from operating
activities:
|
||||||||||||
|
Depreciation, depletion and amortization
|
1,027 | 1,020 | 899 | |||||||||
|
Deferred income taxes
|
457 | 205 | 348 | |||||||||
|
Gain on sale of non-utility business
|
— | — | (128 | ) | ||||||||
|
Other asset (gains), losses and reserves, net
|
(5 | ) | (10 | ) | (4 | ) | ||||||
|
Gain on sale of interests in synfuel projects
|
— | — | (31 | ) | ||||||||
|
Contributions from synfuel partners
|
— | — | 14 | |||||||||
|
Changes in assets and liabilities, exclusive of changes shown
separately (Note 23)
|
(293 | ) | 69 | (92 | ) | |||||||
|
Net cash from operating activities
|
1,825 | 1,819 | 1,559 | |||||||||
|
Investing Activities
|
||||||||||||
|
Plant and equipment expenditures — utility
|
(1,011 | ) | (960 | ) | (1,183 | ) | ||||||
|
Plant and equipment expenditures — non-utility
|
(88 | ) | (75 | ) | (190 | ) | ||||||
|
Proceeds from sale of interests in synfuel projects
|
— | — | 84 | |||||||||
|
Refunds to synfuel partners
|
— | — | (387 | ) | ||||||||
|
Proceeds from sale of non-utility business
|
— | — | 253 | |||||||||
|
Proceeds from sale of other assets, net
|
56 | 83 | 25 | |||||||||
|
Restricted cash for debt redemption
|
(32 | ) | 2 | 54 | ||||||||
|
Proceeds from sale of nuclear decommissioning trust fund assets
|
377 | 295 | 232 | |||||||||
|
Investment in nuclear decommissioning trust funds
|
(410 | ) | (315 | ) | (255 | ) | ||||||
|
Consolidation of VIEs
|
19 | — | — | |||||||||
|
Investment in Millennium Pipeline Project
|
(49 | ) | (15 | ) | (31 | ) | ||||||
|
Other investments
|
(88 | ) | (79 | ) | (125 | ) | ||||||
|
Net cash used for investing activities
|
(1,226 | ) | (1,064 | ) | (1,523 | ) | ||||||
|
Financing Activities
|
||||||||||||
|
Issuance of long-term debt
|
614 | 427 | 1,310 | |||||||||
|
Redemption of long-term debt
|
(663 | ) | (486 | ) | (446 | ) | ||||||
|
Repurchase of long-term debt
|
— | — | (238 | ) | ||||||||
|
Short-term borrowings, net
|
(177 | ) | (417 | ) | (340 | ) | ||||||
|
Issuance of common stock
|
36 | 35 | — | |||||||||
|
Repurchase of common stock
|
— | — | (16 | ) | ||||||||
|
Dividends on common stock
|
(360 | ) | (348 | ) | (344 | ) | ||||||
|
Other
|
(36 | ) | — | (10 | ) | |||||||
|
Net cash used for financing activities
|
(586 | ) | (789 | ) | (84 | ) | ||||||
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
13 | (34 | ) | (48 | ) | |||||||
|
Cash and Cash Equivalents Reclassified from Assets Held for
Sale
|
— | — | 11 | |||||||||
|
Cash and Cash Equivalents at Beginning of Period
|
52 | 86 | 123 | |||||||||
|
Cash and Cash Equivalents at End of Period
|
$ | 65 | $ | 52 | $ | 86 | ||||||
See Notes to Consolidated Financial Statements
66
Table of Contents
DTE
Energy Company
|
Accumulated
|
||||||||||||||||||||||||
|
Other
|
Non-
|
|||||||||||||||||||||||
| Common Stock |
Retained
|
Comprehensive
|
Controlling
|
|||||||||||||||||||||
| Shares | Amount | Earnings | Loss | Interest | Total | |||||||||||||||||||
| (Dollars in millions, shares in thousands) | ||||||||||||||||||||||||
|
Balance, December 31, 2007
|
163,232 | $ | 3,176 | $ | 2,790 | $ | (113 | ) | $ | 48 | $ | 5,901 | ||||||||||||
|
Net income (loss)
|
— | — | 546 | — | 7 | 553 | ||||||||||||||||||
|
Implementation of ASC 820, net of tax
|
— | — | 4 | — | — | 4 | ||||||||||||||||||
|
Implementation of ASC 715 measurement date provision, net
of tax
|
— | — | (9 | ) | — | — | (9 | ) | ||||||||||||||||
|
Dividends declared on common stock
|
— | — | (346 | ) | — | — | (346 | ) | ||||||||||||||||
|
Repurchase and retirement of common stock
|
(479 | ) | (16 | ) | — | — | — | (16 | ) | |||||||||||||||
|
Benefit obligations, net of tax
|
— | — | — | (22 | ) | — | (22 | ) | ||||||||||||||||
|
Foreign currency translation, net of tax
|
— | — | — | (2 | ) | — | (2 | ) | ||||||||||||||||
|
Net change in unrealized losses on derivatives, net of tax
|
— | — | — | 6 | — | 6 | ||||||||||||||||||
|
Net change in unrealized losses on investments, net of tax
|
— | — | — | (34 | ) | — | (34 | ) | ||||||||||||||||
|
Contributions from noncontrolling interests
|
— | — | — | — | 14 | 14 | ||||||||||||||||||
|
Stock-based compensation, distributions to noncontrolling
interests and other
|
267 | 15 | — | — | (26 | ) | (11 | ) | ||||||||||||||||
|
Balance, December 31, 2008
|
163,020 | 3,175 | 2,985 | (165 | ) | 43 | 6,038 | |||||||||||||||||
|
Net income
|
— | — | 532 | — | 3 | 535 | ||||||||||||||||||
|
Dividends declared on common stock
|
— | — | (349 | ) | — | — | (349 | ) | ||||||||||||||||
|
Issuance of common stock
|
1,109 | 35 | — | — | — | 35 | ||||||||||||||||||
|
Benefit obligations, net of tax
|
— | — | — | 7 | — | 7 | ||||||||||||||||||
|
Foreign currency translation, net of tax
|
— | — | — | 2 | — | 2 | ||||||||||||||||||
|
Net change in unrealized losses on derivatives, net of tax
|
— | — | — | 1 | — | 1 | ||||||||||||||||||
|
Net change in unrealized losses on investments, net of tax
|
— | — | — | 8 | — | 8 | ||||||||||||||||||
|
Contributions from noncontrolling interests
|
— | — | — | — | 4 | 4 | ||||||||||||||||||
|
Stock-based compensation, distributions to noncontrolling
interests and other
|
1,271 | 47 | — | — | (12 | ) | 35 | |||||||||||||||||
|
Balance, December 31, 2009
|
165,400 | 3,257 | 3,168 | (147 | ) | 38 | 6,316 | |||||||||||||||||
|
Net income
|
— | — | 630 | — | 9 | 639 | ||||||||||||||||||
|
Dividends declared on common stock
|
— | — | (367 | ) | — | — | (367 | ) | ||||||||||||||||
|
Issuance of common stock
|
777 | 36 | — | — | — | 36 | ||||||||||||||||||
|
Contribution of common stock to pension plan
|
2,224 | 100 | — | — | — | 100 | ||||||||||||||||||
|
Benefit obligations, net of tax
|
— | — | — | 15 | — | 15 | ||||||||||||||||||
|
Foreign currency translation, net of tax
|
— | — | — | 1 | — | 1 | ||||||||||||||||||
|
Net change in unrealized losses on derivatives, net of tax
|
— | — | — | 2 | — | 2 | ||||||||||||||||||
|
Net change in unrealized losses on investments, net of tax
|
— | — | — | (20 | ) | — | (20 | ) | ||||||||||||||||
|
Stock-based compensation, distributions to noncontrolling
interests and other
|
1,027 | 47 | — | — | (2 | ) | 45 | |||||||||||||||||
|
Balance, December 31, 2010
|
169,428 | $ | 3,440 | $ | 3,431 | $ | (149 | ) | $ | 45 | $ | 6,767 | ||||||||||||
See Notes to Consolidated Financial Statements
67
Table of Contents
DTE
Energy Company
The following table displays comprehensive income:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Net income
|
$ | 639 | $ | 535 | $ | 553 | ||||||
|
Other comprehensive income (loss), net of tax:
|
||||||||||||
|
Benefit obligations:
|
||||||||||||
|
Benefit obligations, net of taxes of $3, $4 and $(12)
|
5 | 7 | (22 | ) | ||||||||
|
Amounts reclassified to benefit obligations related to
consolidation of VIEs (Note 1), net of taxes of $5,
$ — and $ —
|
10 | — | — | |||||||||
| 15 | 7 | (22 | ) | |||||||||
|
Net unrealized gains on derivatives:
|
||||||||||||
|
Gains arising during the period, net of taxes of $1, $2 and $2
|
1 | 3 | 4 | |||||||||
|
Amounts reclassified to income, net of taxes of $1, $(1) and $1
|
1 | (2 | ) | 2 | ||||||||
| 2 | 1 | 6 | ||||||||||
|
Net unrealized gains (losses) on investments:
|
||||||||||||
|
Gains (losses) arising during the period, net of taxes of $(6),
$3 and $(19)
|
(10 | ) | 5 | (34 | ) | |||||||
|
Amounts reclassified to income, net of taxes of $ —,
$2 and $ —
|
— | 3 | — | |||||||||
|
Amounts reclassified to benefit obligations related to
consolidation of VIEs (Note 1), net of taxes of $(5),
$ — and $ —
|
(10 | ) | — | — | ||||||||
| (20 | ) | 8 | (34 | ) | ||||||||
|
Foreign currency translation, net of taxes of $ —, $1
and $(1)
|
1 | 2 | (2 | ) | ||||||||
|
Comprehensive income
|
637 | 553 | 501 | |||||||||
|
Less: Comprehensive income attributable to noncontrolling
interests
|
9 | 3 | 7 | |||||||||
|
Comprehensive income attributable to DTE Energy Company
|
$ | 628 | $ | 550 | $ | 494 | ||||||
See Notes to Consolidated Financial Statements
68
Table of Contents
DTE
Energy Company
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
| NOTE 1 — | ORGANIZATION AND BASIS OF PRESENTATION |
Corporate
Structure
DTE Energy owns the following businesses:
| • | Detroit Edison, an electric utility engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeast Michigan; | |
| • | MichCon, a natural gas utility engaged in the purchase, storage, transportation, gathering, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity; and | |
| • | Other businesses are involved in 1) natural gas pipelines and storage; 2) unconventional gas and oil project development and production; 3) power and industrial projects and coal transportation and marketing; and 4) energy marketing and trading operations. |
Detroit Edison and MichCon are regulated by the MPSC. Certain
activities of Detroit Edison and MichCon, as well as various
other aspects of businesses under DTE Energy are regulated by
the FERC. In addition, the Company is regulated by other federal
and state regulatory agencies including the NRC, the EPA and the
MDNRE.
References in this report to “Company” or
“DTE” are to DTE Energy and its subsidiaries,
collectively.
Basis
of Presentation
The accompanying Consolidated Financial Statements are prepared
using accounting principles generally accepted in the United
States of America. These accounting principles require
management to use estimates and assumptions that impact reported
amounts of assets, liabilities, revenues and expenses, and the
disclosure of contingent assets and liabilities. Actual results
may differ from the Company’s estimates.
Certain prior year balances were reclassified to match the
current year’s financial statement presentation.
Principles
of Consolidation
The Company consolidates all majority owned subsidiaries and
investments in entities in which it has controlling influence.
Non-majority owned investments are accounted for using the
equity method when the Company is able to influence the
operating policies of the investee. Non-majority owned
investments include investments in limited liability companies,
partnerships or joint ventures. When the Company does not
influence the operating policies of an investee, the cost method
is used. These consolidated financial statements also reflect
the Company’s proportionate interests in certain jointly
owned utility plant. The Company eliminates all intercompany
balances and transactions.
Effective January 1, 2010, the Company adopted the
provisions of ASU
2009-17,
Amendments to FASB Interpretation 46(R)
. ASU
2009-17
changed the methodology for determining the primary beneficiary
of a VIE from a quantitative risk and rewards-based model to a
qualitative determination. There is no grandfathering of
previous consolidation conclusions. As a result, the Company
re-evaluated all prior VIE and primary beneficiary
determinations. The requirements of ASU
2009-17
were
adopted on a prospective basis.
The Company evaluates whether an entity is a VIE whenever
reconsideration events occur. The Company consolidates VIEs for
which it is the primary beneficiary. If the Company is not the
primary beneficiary and an ownership interest is held, the VIE
is accounted for under the equity method of accounting. When
assessing the determination of the primary beneficiary, the
Company considers all relevant facts and circumstances,
including: the power, through voting or similar rights, to
direct the activities of the VIE that most significantly impact
the VIE’s economic performance and the obligation to absorb
the expected losses
and/or
the
right to receive the expected
69
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
returns of the VIE. The Company performs ongoing reassessments
of all VIEs to determine if the primary beneficiary status has
changed.
Legal entities within the Company’s Power and Industrial
Projects segments enter into long-term contractual arrangements
with customers to supply energy-related products or services.
The entities are generally designed to pass-through the
commodity risk associated with these contracts to the customers,
with the Company retaining operational and customer default
risk. These entities generally are VIEs. The Company
re-evaluated prior VIE and primary beneficiary determinations
and, as a result, in 2010 began consolidating five entities that
were previously accounted for as equity investments. The primary
reason for the change in the primary beneficiary conclusion was
the determination that the Company’s responsibility for the
management and operations of the VIEs afforded the Company the
power to direct the significant activities of the VIEs. In
addition, the Company has interests in certain VIEs that we
share control of all significant activities for those entities
with our partners, and therefore are accounted for under the
equity method.
The Company has variable interests in VIEs through certain of
its long-term purchase contracts. As of December 31, 2010,
the carrying amount of assets and liabilities in the
Consolidated Statement of Financial Position that relate to its
variable interests under long-term purchase contracts are
predominately related to working capital accounts and generally
represent the amounts owed by the Company for the deliveries
associated with the current billing cycle under the contracts.
The Company has not provided any form of financial support
associated with these long-term contracts. There is no
significant potential exposure to loss as a result of its
variable interests through these long-term purchase contracts.
In 2001, Detroit Edison financed a regulatory asset related to
Fermi 2 and certain other regulatory assets through the sale of
rate reduction bonds by a wholly-owned special purpose entity,
Securitization. Detroit Edison performs servicing activities
including billing and collecting surcharge revenue for
Securitization. Under ASU
2009-17,
this entity is now a VIE, and continues to be consolidated as
the Company is the primary beneficiary.
DTE Energy has interests in various unconsolidated trusts that
were formed for the purpose of issuing preferred securities and
lending the gross proceeds to the Company. The assets of the
trusts are debt securities of DTE Energy with terms similar to
those of the related preferred securities. Payments the Company
makes are used by the trusts to make cash distributions on the
preferred securities it has issued. DTE Energy has reviewed
these interests and has determined they are VIEs, but the
Company is not the primary beneficiary as it does not have
variable interests in the trusts and therefore, the trusts are
not consolidated by the Company.
The maximum risk exposure for consolidated VIEs is reflected on
the Company’s Consolidated Statements of Financial
Position. For non-consolidated VIEs, the maximum risk exposure
is generally limited to its investment and amounts which it has
guaranteed.
70
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
The following table summarizes the major balance sheet items for
consolidated VIEs as of December 31, 2010 and
December 31, 2009. Amounts at December 31, 2010 for
consolidated VIEs that are either (1) assets that can be
used only to settle obligations of the VIE or
(2) liabilities for which creditors do not have recourse to
the general credit of the primary beneficiary are segregated in
the restricted amounts column. Entities, in which the Company
holds a majority voting interest and is the primary beneficiary,
that meet the definition of a business and whose assets can be
used for purposes other than the settlement of the VIE’s
obligations have been excluded from the table below.
| December 31, 2010 | ||||||||||||||||||||
|
Restricted
|
December 31,
|
|||||||||||||||||||
| Securitization | Other | Total | Amounts | 2009 | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
|
ASSETS
|
||||||||||||||||||||
|
Cash and cash equivalents
|
$ | — | $ | 4 | $ | 4 | $ | — | $ | 2 | ||||||||||
|
Restricted cash
|
104 | 8 | 112 | 112 | — | |||||||||||||||
|
Accounts receivable
|
42 | 8 | 50 | 44 | 4 | |||||||||||||||
|
Inventories
|
— | 99 | 99 | — | 9 | |||||||||||||||
|
Other current assets
|
— | 1 | 1 | — | — | |||||||||||||||
|
Property, plant and equipment
|
— | 54 | 54 | 38 | 45 | |||||||||||||||
|
Securitized regulatory assets
|
729 | — | 729 | 729 | — | |||||||||||||||
|
Other assets
|
13 | 9 | 22 | 21 | 9 | |||||||||||||||
| $ | 888 | $ | 183 | $ | 1,071 | $ | 944 | $ | 69 | |||||||||||
| LIABILITIES | ||||||||||||||||||||
|
Accounts payable and accrued current liabilities
|
$ | 17 | $ | 27 | $ | 44 | $ | 18 | $ | 3 | ||||||||||
|
Current portion long-term debt, including capital leases
|
150 | 7 | 157 | 157 | 4 | |||||||||||||||
|
Other current liabilities
|
62 | 6 | 68 | 66 | 1 | |||||||||||||||
|
Mortgage bonds, notes and other
|
— | 35 | 35 | 35 | 17 | |||||||||||||||
|
Securitization bonds
|
643 | — | 643 | 643 | — | |||||||||||||||
|
Capital lease obligations
|
— | 23 | 23 | 23 | 26 | |||||||||||||||
|
Other long term liabilities
|
6 | 7 | 13 | 12 | — | |||||||||||||||
| $ | 878 | $ | 105 | $ | 983 | $ | 954 | $ | 51 | |||||||||||
Amounts for non-consolidated VIEs as of December 31, 2010
and December 31, 2009 are as follows:
|
December 31,
|
December 31,
|
|||||||
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Other investments
|
$ | 98 | $ | 178 | ||||
|
Note receivable and bank loan guarantee
|
6 | 11 | ||||||
|
Trust preferred — linked securities
|
289 | 289 | ||||||
71
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| NOTE 2 — | SIGNIFICANT ACCOUNTING POLICIES |
Revenues
Revenues from the sale and delivery of electricity, and the
sale, delivery and storage of natural gas are recognized as
services are provided. Detroit Edison and MichCon record
revenues for electric and gas provided but unbilled at the end
of each month. Rates for Detroit Edison and MichCon include
provisions to adjust billings for fluctuations in fuel and
purchased power costs, cost of natural gas and certain other
costs. Revenues are adjusted for differences between actual
costs and the amounts billed in current rates. Under or over
recovered revenues related to these cost tracking mechanisms are
recorded on the Consolidated Statement of Financial Position and
are recovered or returned to customers through adjustments to
the billing factors. See Note 12 for further discussion of
cost recovery mechanisms.
Detroit Edison has a CIM, which is an over/under recovery
mechanism that measures non-fuel revenues lost or gained as a
result of fluctuations in electric Customer Choice sales. If
annual electric Customer Choice sales exceed the baseline amount
from Detroit Edison’s most recent rate case,
90 percent of its lost non-fuel revenues associated with
sales above that level may be recovered from full service
customers. If annual electric Customer Choice sales decrease
below the baseline, the Company must refund 90 percent of
its increase in non-fuel revenues associated with sales below
that level to full service customers.
Detroit Edison and MichCon have RDMs that are designed to
minimize the impact on revenues of changes in average customer
usage of electricity and natural gas. The January 2010 MPSC
order in Detroit Edison’s 2009 rate case provided for,
among other items, the implementation of a pilot electric RDM
effective February 1, 2010. The electric RDM enables
Detroit Edison to recover or refund the change in revenue
resulting from the difference between actual average sales per
customer compared to the base level of average sales per
customer established in the MPSC order. The June 2010 MPSC order
in MichCon’s 2009 rate case provided for, among other
items, the implementation of a pilot gas RDM effective
July 1, 2010. The gas RDM enables MichCon to recover or
refund the change in revenue resulting from the difference in
weather-adjusted average sales per customer compared to the base
average sales per customer established in the MPSC order. The
RDMs for Detroit Edison and MichCon address changes in customer
usage due to general economic conditions and conservation, but
do not shield the utilities from the impacts of lost customers.
In addition, the pilot electric RDM materially shields Detroit
Edison from the impact of weather on customer usage. The pilot
gas RDM does not shield MichCon from the impact of weather on
customer usage. The electric and gas RDMs are subject to review
by the MPSC after the initial one-year pilot programs.
Non-utility businesses recognize revenues as services are
provided and products are delivered. Revenues and energy costs
related to trading contracts are presented on a net basis in the
Consolidated Statements of Operations. Commodity derivatives
used for trading purposes are accounted for using the
mark-to-market
method with unrealized gains and losses recorded in Operating
Revenues.
Accounting
for ISO Transactions
Detroit Edison participates in the energy market through MISO.
MISO requires that we submit hourly day-ahead, real time and FTR
bids and offers for energy at locations across the MISO region.
Detroit Edison accounts for MISO transactions on a net hourly
basis in each of the day-ahead, real-time and FTR markets and
net transactions across all MISO energy market locations. In any
single hour Detroit Edison records net purchases in Fuel,
purchased power and gas and net sales in Operating revenues on
the Consolidated Statements of Operations. Detroit Edison
records net sale billing adjustments when invoices are received.
Detroit Edison records expense accruals for future net purchases
adjustments based on historical experience, and reconciles
accruals to actual expenses when invoices are received from MISO.
Energy Trading participates in the energy markets through
various independent system operators and regional transmission
organizations. These markets require that we submit hourly
day-ahead, real time bids and offers for
72
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
energy at locations across each region. We submit bids in the
annual and monthly auction revenue rights and FTR auctions to
the regional transmission organizations. Energy Trading accounts
for these transactions on a net hourly basis for the day-ahead,
real-time and FTR markets. These transactions are related to our
trading contracts which are presented on a net basis in
Operating revenues in the Consolidated Statements of Income.
Comprehensive
Income
Comprehensive income is the change in Common shareholders’
equity during a period from transactions and events from
non-owner sources, including net income. As shown in the
following table, amounts recorded to accumulated other
comprehensive loss for the year ended December 31, 2010
include unrealized gains and losses from derivatives accounted
for as cash flow hedges, unrealized gains and losses on
available for sale securities, the Company’s interest in
comprehensive income of equity investees, and changes in benefit
obligations, consisting of deferred actuarial losses, prior
service costs and transition amounts related to pension and
other postretirement benefit plans, and foreign currency
translation adjustments.
|
Net
|
Net
|
Accumulated
|
||||||||||||||||||
|
Unrealized
|
Unrealized
|
Foreign
|
Other
|
|||||||||||||||||
|
Gain/(Loss)
|
Gain/(Loss)
|
Benefit
|
Currency
|
Comprehensive
|
||||||||||||||||
| on Derivatives | on Investments | Obligations | Translation | Loss | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
|
Beginning balances
|
$ | (6 | ) | $ | (10 | ) | $ | (131 | ) | $ | — | $ | (147 | ) | ||||||
|
Current period change, net of tax
|
2 | (20 | ) | 15 | 1 | (2 | ) | |||||||||||||
|
Ending balance
|
$ | (4 | ) | $ | (30 | ) | $ | (116 | ) | $ | 1 | $ | (149 | ) | ||||||
Cash
Equivalents and Restricted Cash
Cash and cash equivalents include cash on hand, cash in banks
and temporary investments purchased with remaining maturities of
three months or less. Restricted cash consists of funds held to
satisfy requirements of certain debt, primarily Securitization
bonds, and partnership operating agreements. Restricted cash
designated for interest and principal payments within one year
is classified as a current asset.
Receivables
Accounts receivable are primarily composed of trade receivables
and unbilled revenue. Our accounts receivable are stated at net
realizable value.
The allowance for doubtful accounts for Detroit Edison and
MichCon is generally calculated using the aging approach that
utilizes rates developed in reserve studies. We establish an
allowance for uncollectible accounts based on historical losses
and management’s assessment of existing economic
conditions, customer trends, and other factors. Customer
accounts are generally considered delinquent if the amount
billed is not received by the due date, which is typically in
21 days, however, factors such as assistance programs may
delay aggressive action. We assess late payment fees on trade
receivables based on past-due terms with customers. Customer
accounts are written off when collection efforts have been
exhausted, generally one year after service has been terminated.
The customer allowance for doubtful accounts for our other
businesses is calculated based on specific review of probable
future collections based on receivable balances in excess of
90 days.
Unbilled revenues of $575 million and $618 million are
included in customer accounts receivable at December 31,
2010 and 2009, respectively.
73
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Notes
Receivable
Notes receivable, or financing receivables, are primarily
comprised of capital lease receivables and loans and are
included in Other current assets and Notes receivable on the
Company’s Consolidated Statements of Financial Position.
Notes receivable are typically considered delinquent when
payment is not received for periods ranging from 60 to
120 days. The Company ceases accruing interest (nonaccrual
status), considers a note receivable impaired, and establishes
an allowance for credit loss when it is probable that all
principal and interest amounts due will not be collected in
accordance with the contractual terms of the note receivable.
Cash payments received on nonaccrual status notes receivable,
that do not bring the account contractually current, are first
applied to contractually owed past due interest, with any
remainder applied to principle. Accrual of interest is generally
resumed when the note receivable becomes contractually current.
In determining the allowance for credit losses for notes
receivable, we consider the historical payment experience and
other factors that are expected to have a specific impact on the
counterparty’s ability to pay. In addition, the Company
monitors the credit ratings of the counterparties from which we
have notes receivable.
Inventories
The Company generally values inventory at average cost.
Gas inventory of $43 million and $44 million as of
December 31, 2010 and 2009, respectively, at MichCon is
determined using the
last-in,
first-out (LIFO) method. At December 31, 2010, the
replacement cost of gas remaining in storage exceeded the LIFO
cost by $147 million. At December 31, 2009, the
replacement cost of gas remaining in storage exceeded the LIFO
cost by $218 million.
Property,
Retirement and Maintenance, and Depreciation, Depletion and
Amortization
Property is stated at cost and includes construction-related
labor, materials, overheads and, for utility property, an
allowance for funds used during construction (AFUDC). The cost
of utility properties retired, less salvage value, is charged to
accumulated depreciation. Expenditures for maintenance and
repairs are charged to expense when incurred, except for Fermi 2.
The Company bases depreciation provisions for utility property
at Detroit Edison and MichCon on straight-line and
units-of-production
rates approved by the MPSC.
Non-utility property is depreciated over its estimated useful
life using straight-line, declining-balance or
units-of-production
methods.
The Company credits depreciation, depletion and amortization
expense when it establishes regulatory assets for plant-related
costs such as depreciation or plant-related financing costs. The
Company charges depreciation, depletion and amortization expense
when it amortizes these regulatory assets. The Company credits
interest expense to reflect the accretion income on certain
regulatory assets.
Approximately $3 million and $13 million of expenses
related to Fermi 2 refueling outages were accrued at
December 31, 2010 and December 31, 2009, respectively.
Amounts are accrued on a pro-rata basis over an
18-month
period that coincides with scheduled refueling outages at Fermi
2. This accrual of outage costs matches the regulatory recovery
of these costs in rates set by the MPSC.
See Note 7.
74
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Unconventional
Gas Production
The Company follows the successful efforts method of accounting
for investments in gas properties. Under this method of
accounting, all property acquisition costs and costs of
exploratory and development wells are capitalized when incurred,
pending determination of whether the well contains proved
reserves. If an exploratory well does not contain proved
reserves, the costs of drilling the well are expensed. The costs
of development wells are capitalized, whether productive or
nonproductive. Geological and geophysical costs on exploratory
prospects and the costs of carrying and retaining properties
without economical quantities of proved reserves are expensed as
incurred. An impairment loss is recorded if the net capitalized
costs of proved gas properties exceed the aggregate related
undiscounted future net revenues. An impairment loss is recorded
to the extent that capitalized costs of unproved properties, on
a
property-by-property
basis, are considered not to be realizable. Depreciation,
depletion and amortization of proved gas properties are
determined using the
units-of-production
method.
Long-Lived
Assets
Long-lived assets are reviewed for impairment whenever events or
changes in circumstances indicate the carrying amount of an
asset may not be recoverable. If the carrying amount of the
asset exceeds the expected future cash flows generated by the
asset, an impairment loss is recognized resulting in the asset
being written down to its estimated fair value. Assets to be
disposed of are reported at the lower of the carrying amount or
fair value, less costs to sell.
Intangible
Assets
The Company has certain intangible assets relating to emission
allowances, renewable energy credits and non-utility contracts.
Emission allowances and renewable energy credits are charged to
expense as the allowances and credits are consumed in the
operation of the business. The Company’s intangible assets
related to emission allowances were $9 million at
December 31, 2010 and 2009. The Company’s intangible
assets related to renewable energy credits were $17 million
at December 31, 2010. The Company had no renewable energy
credits at December 31, 2009. The gross carrying amount and
accumulated amortization of contract intangible assets at
December 31, 2010 were $63 million and
$22 million, respectively. The gross carrying amount and
accumulated amortization of contract intangible assets at
December 31, 2009 were $64 million and
$19 million, respectively. The Company amortizes contract
intangible assets on a straight-line basis over the expected
period of benefit, ranging from 4 to 30 years. Intangible
assets amortization expense was $4 million in 2010,
$4 million in 2009 and $7 million in 2008.
Amortization expense of intangible assets is estimated to be
$4 million annually for 2011 through 2015.
Excise
and Sales Taxes
The Company records the billing of excise and sales taxes as a
receivable with an offsetting payable to the applicable taxing
authority, with no net impact on the Consolidated Statements of
Operations.
Deferred
Debt Costs
The costs related to the issuance of long-term debt are deferred
and amortized over the life of each debt issue. In accordance
with MPSC regulations applicable to the Company’s electric
and gas utilities, the unamortized discount, premium and expense
related to debt redeemed with a refinancing are amortized over
the life of the replacement issue. Discount, premium and expense
on early redemptions of debt associated with non-utility
operations are charged to earnings.
Investments
in Debt and Equity Securities
The Company generally classifies investments in debt and equity
securities as either trading or
available-for-sale
and has recorded such investments at market value with
unrealized gains or losses included in earnings
75
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
or in other comprehensive income or loss, respectively. Changes
in the fair value of Fermi 2 nuclear decommissioning investments
are recorded as adjustments to regulatory assets or liabilities,
due to a recovery mechanism from customers. The Company’s
equity investments are reviewed for impairment each reporting
period. If the assessment indicates that the impairment is other
than temporary, a loss is recognized resulting in the equity
investment being written down to its estimated fair value. See
Note 4.
Offsetting
Amounts Related to Certain Contracts
The Company offsets the fair value of derivative instruments
with cash collateral received or paid for those derivative
instruments executed with the same counterparty under a master
netting agreement, which reduces both the Company’s total
assets and total liabilities. As of December 31, 2010 and
December 31, 2009, the total cash collateral posted, net of
cash collateral received, was $77 million and
$117 million, respectively. Derivative assets and
derivative liabilities are shown net of collateral of
$9 million and $33 million, respectively, as of
December 31, 2010 and $34 million and
$120 million, respectively, as of December 31, 2009.
The Company recorded cash collateral received of $2 million
and cash collateral paid of $35 million not related to
unrealized derivative positions as of December 31, 2010.
The Company recorded cash collateral received of $1 million
and cash collateral paid of $32 million not related to
unrealized derivative positions, as of December 31, 2009.
These amounts are included in accounts receivable and accounts
payable and are recorded net by counterparty.
Government
Grants
Grants are recognized when there is reasonable assurance that
the grant will be received and that any conditions associated
with the grant will be met. When grants are received related to
Property, Plant and Equipment, the Company reduces the basis of
the assets on the Consolidated Statements of Financial Position,
resulting in lower depreciation expense over the life of the
associated asset. Grants received related to expenses are
reflected as a reduction of the associated expense in the period
in which the expense is incurred.
Other
Accounting Policies
See the following notes for other accounting policies impacting
the Company’s consolidated financial statements:
| Note | Title | |
|
3
|
New Accounting Pronouncements | |
|
4
|
Fair Value | |
|
5
|
Financial and Other Derivative Instruments | |
|
6
|
Goodwill | |
|
9
|
Asset Retirement Obligation | |
|
12
|
Regulatory Matters | |
|
13
|
Income Taxes | |
|
21
|
Retirement Benefits and Trusteed Assets | |
|
22
|
Stock-based Compensation |
| NOTE 3 — | NEW ACCOUNTING PRONOUNCEMENTS |
Variable
Interest Entity
In June 2009, the FASB issued ASU
2009-17,
Amendments to FASB Interpretation 46(R).
This standard
amends the consolidation guidance that applies to VIEs and
affects the overall consolidation analysis under
ASC 810-10,
Consolidation
. The amendments to the consolidation
guidance affect all entities and enterprises
76
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
currently within the scope of
ASC 810-10,
as well as qualifying special purpose entities that are
currently outside the scope of
ASC 810-10.
Accordingly, the Company reconsidered its previous
ASC 810-10
conclusions, including (1) whether an entity is a VIE,
(2) whether the enterprise is the VIE’s primary
beneficiary, and (3) what type of financial statement
disclosures are required. ASU
2009-17
is
effective as of the beginning of the first fiscal year that
begins after November 15, 2009. The Company adopted the
standard as of January 1, 2010. The adoption of the
standard resulted in the consolidation of certain entities
within the Power and Industrial Projects segment where the
investments in such entities were previously accounted for under
the equity method. See Note 1.
Fair
Value Measurements and Disclosures
In January 2010, the FASB issued ASU
2010-06,
Improving Disclosures about Fair Value Measurements
. ASU
2010-06
requires details of transfers in and out of Level 1 and 2
fair value measurements and the gross presentation of activity
within the Level 3 fair value measurement roll forward. The
new disclosures are required of all entities that are required
to provide disclosures about recurring and nonrecurring fair
value measurements. The Company adopted ASU
2010-06
effective January 1, 2010, except for the gross
presentation of the Level 3 fair value measurement roll
forward which is effective for annual reporting periods
beginning after December 15, 2010 and for interim reporting
periods within those years.
Determining
Whether Instruments Granted in Share-Based Payment Transactions
Are Participating Securities
The Company adopted the requirements of
ASC 260-10
(FASB Staff Position EITF
No. 03-6-1,
Determining Whether Instruments Granted in Share-Based
Payment Transactions are Participating Securities)
effective
January 1, 2009 and applied the requirements
retrospectively. This FSP addresses whether instruments granted
in share-based payment transactions are participating securities
prior to vesting and, therefore, need to be included in the
earnings allocation in computing earnings per share. The
adoption of the FSP had the effect of reducing previously
reported 2008 amounts for basic and diluted earnings per common
share by $.03 and $.02, respectively.
Noncontrolling
Interests in Consolidated Financial Statements
The Company adopted
ASC 810-10
(SFAS No. 160,
Noncontrolling Interests in
Consolidated Financial Statements — an Amendment of
ARB No. 51)
effective as of January 1, 2009
and applied the new presentation and disclosure requirements
retrospectively. As a result, the formats and captions of
certain 2008 financial statement amounts were revised, including
reclassifying minority interest expense as net income
attributable to noncontrolling interests, and separately
reflecting activity of noncontrolling interests in the
Consolidated Statements of Equity and of Comprehensive Income.
| NOTE 4 — | FAIR VALUE |
Fair value is defined as the price that would be received to
sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date
in a principal or most advantageous market. Fair value is a
market-based measurement that is determined based on inputs,
which refer broadly to assumptions that market participants use
in pricing assets or liabilities. These inputs can be readily
observable, market corroborated or generally unobservable
inputs. The Company makes certain assumptions it believes that
market participants would use in pricing assets or liabilities,
including assumptions about risk, and the risks inherent in the
inputs to valuation techniques. Credit risk of the Company and
its counterparties is incorporated in the valuation of assets
and liabilities through the use of credit reserves, the impact
of which was immaterial at December 31, 2010 and
December 31, 2009. The Company believes it uses valuation
techniques that maximize the use of observable market-based
inputs and minimize the use of unobservable inputs.
77
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
A fair value hierarchy has been established, which prioritizes
the inputs to valuation techniques used to measure fair value in
three broad levels. The fair value hierarchy gives the highest
priority to quoted prices (unadjusted) in active markets for
identical assets or liabilities (Level 1) and the
lowest priority to unobservable inputs (Level 3). In some
cases, the inputs used to measure fair value might fall in
different levels of the fair value hierarchy. All assets and
liabilities are required to be classified in their entirety
based on the lowest level of input that is significant to the
fair value measurement in its entirety. Assessing the
significance of a particular input may require judgment
considering factors specific to the asset or liability, and may
affect the valuation of the asset or liability and its placement
within the fair value hierarchy. The Company classifies fair
value balances based on the fair value hierarchy defined as
follows:
| • | Level 1 — Consists of unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access as of the reporting date. | |
| • | Level 2 — Consists of inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. | |
| • | Level 3 — Consists of unobservable inputs for assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints. |
The following table presents assets and liabilities measured and
recorded at fair value on a recurring basis as of
December 31, 2010:
|
Netting
|
Net Balance at
|
|||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Adjustments(2) | December 31, 2010 | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
|
Assets:
|
||||||||||||||||||||
|
Nuclear decommissioning trusts
|
$ | 599 | $ | 340 | $ | — | $ | — | $ | 939 | ||||||||||
|
Other investments(1)
|
56 | 55 | — | — | 111 | |||||||||||||||
|
Derivative assets:
|
||||||||||||||||||||
|
Foreign currency exchange contracts
|
— | 20 | — | (20 | ) | — | ||||||||||||||
|
Commodity Contracts:
|
||||||||||||||||||||
|
Natural Gas
|
1,846 | 128 | 12 | (1,960 | ) | 26 | ||||||||||||||
|
Electricity
|
— | 649 | 117 | (589 | ) | 177 | ||||||||||||||
|
Other
|
68 | 4 | 4 | (71 | ) | 5 | ||||||||||||||
|
Total derivative assets
|
1,914 | 801 | 133 | (2,640 | ) | 208 | ||||||||||||||
|
Total
|
$ | 2,569 | $ | 1,196 | $ | 133 | $ | (2,640 | ) | $ | 1,258 | |||||||||
78
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
|
Netting
|
Net Balance at
|
|||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Adjustments(2) | December 31, 2010 | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
|
Liabilities:
|
||||||||||||||||||||
|
Derivative liabilities:
|
||||||||||||||||||||
|
Foreign currency exchange contracts
|
$ | — | $ | (30 | ) | $ | — | $ | 20 | $ | (10 | ) | ||||||||
|
Interest rate contracts
|
— | (1 | ) | — | — | (1 | ) | |||||||||||||
|
Commodity Contracts:
|
||||||||||||||||||||
|
Natural Gas
|
(1,844 | ) | (263 | ) | (11 | ) | 1,955 | (163 | ) | |||||||||||
|
Electricity
|
— | (653 | ) | (63 | ) | 643 | (73 | ) | ||||||||||||
|
Other
|
(63 | ) | (8 | ) | — | 66 | (5 | ) | ||||||||||||
|
Total derivative liabilities
|
(1,907 | ) | (955 | ) | (74 | ) | 2,684 | (252 | ) | |||||||||||
|
Total
|
$ | (1,907 | ) | $ | (955 | ) | $ | (74 | ) | $ | 2,684 | $ | (252 | ) | ||||||
|
Net Assets as of December 31, 2010
|
$ | 662 | $ | 241 | $ | 59 | $ | 44 | $ | 1,006 | ||||||||||
|
Assets:
|
||||||||||||||||||||
|
Current
|
$ | 1,299 | $ | 663 | $ | 49 | $ | (1,880 | ) | $ | 131 | |||||||||
|
Noncurrent(3)
|
1,270 | 533 | 84 | (760 | ) | 1,127 | ||||||||||||||
|
Total Assets
|
$ | 2,569 | $ | 1,196 | $ | 133 | $ | (2,640 | ) | $ | 1,258 | |||||||||
|
Liabilities:
|
||||||||||||||||||||
|
Current
|
$ | (1,290 | ) | $ | (730 | ) | $ | (21 | ) | $ | 1,899 | $ | (142 | ) | ||||||
|
Noncurrent
|
(617 | ) | (225 | ) | (53 | ) | 785 | (110 | ) | |||||||||||
|
Total Liabilities
|
$ | (1,907 | ) | $ | (955 | ) | $ | (74 | ) | $ | 2,684 | $ | (252 | ) | ||||||
|
Net Assets as of December 31, 2010
|
$ | 662 | $ | 241 | $ | 59 | $ | 44 | $ | 1,006 | ||||||||||
The following table presents assets and liabilities measured and
recorded at fair value on a recurring basis as of
December 31, 2009:
|
Netting
|
Net Balance at
|
|||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Adjustments(2) | December 31, 2009 | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
|
Assets:
|
||||||||||||||||||||
|
Cash equivalents
|
$ | 15 | $ | — | $ | — | $ | — | $ | 15 | ||||||||||
|
Nuclear decommissioning trusts
|
549 | 268 | — | — | 817 | |||||||||||||||
|
Other Investments(1)
|
50 | 57 | — | — | 107 | |||||||||||||||
|
Derivative assets
|
1,080 | 1,207 | 385 | (2,347 | ) | 325 | ||||||||||||||
|
Total
|
$ | 1,694 | $ | 1,532 | $ | 385 | $ | (2,347 | ) | $ | 1,264 | |||||||||
|
Liabilities:
|
||||||||||||||||||||
|
Derivative liabilities
|
$ | (1,120 | ) | $ | (1,370 | ) | $ | (361 | ) | $ | 2,433 | $ | (418 | ) | ||||||
|
Total
|
$ | (1,120 | ) | $ | (1,370 | ) | $ | (361 | ) | $ | 2,433 | $ | (418 | ) | ||||||
|
Net Assets at December 31, 2009
|
$ | 574 | $ | 162 | $ | 24 | $ | 86 | $ | 846 | ||||||||||
79
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| (1) | Excludes cash surrender value of life insurance investments. | |
| (2) | Amounts represent the impact of master netting agreements that allow the Company to net gain and loss positions and cash collateral held or placed with the same counterparties. | |
| (3) | Includes $111 million of other investments that are included in the Consolidated Statements of Financial Position in Other Investments at December 31, 2010. |
The following tables present the fair value reconciliation of
Level 3 assets and liabilities measured at fair value on a
recurring basis for the years ended December 31, 2010 and
2009:
| Year Ended December 31, 2010 | ||||||||||||||||
| Natural Gas | Electricity | Other | Total | |||||||||||||
| (In millions) | ||||||||||||||||
|
Asset balance as of January 1, 2010
|
$ | 2 | $ | 19 | $ | 3 | $ | 24 | ||||||||
|
Changes in fair value recorded in income
|
4 | 64 | 1 | 69 | ||||||||||||
|
Changes in fair value recorded in regulatory assets/liabilities
|
— | — | 6 | 6 | ||||||||||||
|
Purchases, issuances and settlements
|
(8 | ) | (73 | ) | (6 | ) | (87 | ) | ||||||||
|
Transfers in/out of Level 3
|
3 | 44 | — | 47 | ||||||||||||
|
Asset balance as of December 31, 2010
|
$ | 1 | $ | 54 | $ | 4 | $ | 59 | ||||||||
|
The amount of total gains (losses) included in net income
attributed to the change in unrealized gains (losses) related to
assets and liabilities held at December 31, 2010
|
$ | (4 | ) | $ | (6 | ) | $ | 1 | $ | (9 | ) | |||||
| Year Ended December 31, 2009 | ||||||||||||||||
| Natural Gas | Electricity | Other | Total | |||||||||||||
| (In millions) | ||||||||||||||||
|
Asset (Liability) balance as of January 1, 2009
|
$ | (183 | ) | $ | (5 | ) | $ | 5 | $ | (183 | ) | |||||
|
Changes in fair value recorded in income
|
(17 | ) | 59 | (1 | ) | 41 | ||||||||||
|
Changes in fair value recorded in other comprehensive income
|
8 | — | — | 8 | ||||||||||||
|
Purchases, issuances and settlements
|
(15 | ) | (30 | ) | 1 | (44 | ) | |||||||||
|
Transfers in/out of Level 3
|
209 | (5 | ) | (2 | ) | 202 | ||||||||||
|
Asset (Liability) balance as of December 31, 2009
|
$ | 2 | $ | 19 | $ | 3 | $ | 24 | ||||||||
|
The amount of total gains (losses) included in net income
attributed to the change in unrealized gains (losses) related to
assets and liabilities held at December 31, 2009
|
$ | (60 | ) | $ | 154 | $ | (1 | ) | $ | 93 | ||||||
Transfers in/out of Level 3 represent existing assets or
liabilities that were either previously categorized as a higher
level and for which the inputs to the model became unobservable
or assets and liabilities that were previously classified as
Level 3 for which the lowest significant input became
observable during the period. Transfers in/out of Level 3
are reflected as if they had occurred at the beginning of the
period. No significant transfers between Level 1 and 2
occurred in years ended December 31, 2010 and
December 31, 2009. Transfers from Level 2 to
Level 3 representing $9 million of assets reflect
inputs related to certain power transactions identified as
unobservable due to lack of available broker quotes for the year
ended December 31, 2010. Transfers from Level 3 to
Level 2
80
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
representing $35 million of liabilities reflect inputs
related to certain power transactions identified as observable
due to available broker quotes for the year ended
December 31, 2010. Transfers out of Level 3 of
$202 million reflect increased reliance on broker quotes
for certain gas transactions for the year ended
December 31, 2009.
Cash
Equivalents
Cash equivalents include investments with maturities of three
months or less when purchased. The cash equivalents shown in the
fair value table are comprised of investments in money market
funds. The fair values of the shares of these funds are based on
observable market prices and, therefore, have been categorized
as Level 1 in the fair value hierarchy.
Nuclear
Decommissioning Trusts and Other Investments
The nuclear decommissioning trusts and other investments hold
debt and equity securities directly and indirectly through
commingled funds and institutional mutual funds. Exchange-traded
debt and equity securities held directly are valued using quoted
market prices in actively traded markets. The commingled funds
and institutional mutual funds which hold exchange-traded equity
or debt securities are valued based on the underlying
securities, using quoted prices in actively traded markets.
Non-exchange-traded fixed income securities are valued based
upon quotations available from brokers or pricing services. A
primary price source is identified by asset type, class or issue
for each security. The trustees monitor prices supplied by
pricing services and may use a supplemental price source or
change the primary price source of a given security if the
trustees determine that another price source is considered to be
preferable. DTE Energy has obtained an understanding of how
these prices are derived, including the nature and observability
of the inputs used in deriving such prices. Additionally, DTE
Energy selectively corroborates the fair values of securities by
comparison of market-based price sources.
Derivative
Assets and Liabilities
Derivative assets and liabilities are comprised of physical and
financial derivative contracts, including futures, forwards,
options and swaps that are both exchange-traded and
over-the-counter
traded contracts. Various inputs are used to value derivatives
depending on the type of contract and availability of market
data. Exchange-traded derivative contracts are valued using
quoted prices in active markets. DTE Energy considers the
following criteria in determining whether a market is considered
active: frequency in which pricing information is updated,
variability in pricing between sources or over time and the
availability of public information. Other derivative contracts
are valued based upon a variety of inputs including commodity
market prices, broker quotes, interest rates, credit ratings,
default rates, market-based seasonality and basis differential
factors. DTE Energy monitors the prices that are supplied by
brokers and pricing services and may use a supplemental price
source or change the primary price source of an index if prices
become unavailable or another price source is determined to be
more representative of fair value. DTE Energy has obtained an
understanding of how these prices are derived. Additionally, DTE
Energy selectively corroborates the fair value of its
transactions by comparison of market-based price sources.
Mathematical valuation models are used for derivatives for which
external market data is not readily observable, such as
contracts which extend beyond the actively traded reporting
period.
Fair
Value of Financial Instruments
The fair value of long-term debt is determined by using quoted
market prices when available and a discounted cash flow analysis
based upon estimated current borrowing rates when quoted market
prices are not available. The table below shows the fair value
and the carrying value for long-term debt securities. Certain
other financial
81
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
instruments, such as notes payable, customer deposits and notes
receivable are not shown as carrying value approximates fair
value. See Note 5 for further fair value information on
financial and derivative instruments.
| December 31, 2010 | December 31, 2009 | |||||||||||||||
| Fair Value | Carrying Value | Fair Value | Carrying Value | |||||||||||||
|
Long-Term Debt
|
$ | 8.5 billion | $ | 8.0 billion | $ | 8.3 billion | $ | 8.0 billion | ||||||||
Nuclear
Decommissioning Trust Funds
Detroit Edison has a legal obligation to decommission its
nuclear power plants following the expiration of their operating
licenses. This obligation is reflected as an asset retirement
obligation on the Consolidated Statements of Financial Position.
See Note 9 for additional information.
The NRC has jurisdiction over the decommissioning of nuclear
power plants and requires decommissioning funding based upon a
formula. The MPSC and FERC regulate the recovery of costs of
decommissioning nuclear power plants and both require the use of
external trust funds to finance the decommissioning of Fermi 2.
Rates approved by the MPSC provide for the recovery of
decommissioning costs of Fermi 2 and the disposal of low-level
radioactive waste. Detroit Edison is continuing to
fund FERC jurisdictional amounts for decommissioning even
though explicit provisions are not included in FERC rates. The
Company believes the MPSC and FERC collections will be adequate
to fund the estimated cost of decommissioning using the NRC
formula. The decommissioning assets, anticipated earnings
thereon and future revenues from decommissioning collections
will be used to decommission Fermi 2. The Company expects the
liabilities to be reduced to zero at the conclusion of the
decommissioning activities. If amounts remain in the trust funds
for Fermi 2 following the completion of the decommissioning
activities, those amounts will be disbursed based on rulings by
the MPSC and FERC. The decommissioning of Fermi 1 is funded by
Detroit Edison. Contributions to the Fermi 1 trust are
discretionary.
The following table summarizes the fair value of the nuclear
decommissioning trust fund assets:
|
December 31
|
December 31
|
|||||||
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Fermi 2
|
$ | 910 | $ | 790 | ||||
|
Fermi 1
|
3 | 3 | ||||||
|
Low level radioactive waste
|
26 | 24 | ||||||
|
Total
|
$ | 939 | $ | 817 | ||||
At December 31, 2010, investments in the nuclear
decommissioning trust funds consisted of approximately 61% in
publicly traded equity securities, 38% in fixed debt instruments
and 1% in cash equivalents. At December 31, 2009,
investments in the nuclear decommissioning trust funds consisted
of approximately 51% in publicly traded equity securities, 48%
in fixed debt instruments and 1% in cash equivalents. The debt
securities at both December 31, 2010 and December 31,
2009 had an average maturity of approximately 6 and
5 years, respectively.
The costs of securities sold are determined on the basis of
specific identification. The following table sets forth the
gains and losses and proceeds from the sale of securities by the
nuclear decommissioning trust funds:
| Year Ended December 31 | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Realized gains
|
$ | 192 | $ | 37 | $ | 34 | ||||||
|
Realized losses
|
$ | (83 | ) | $ | (55 | ) | $ | (49 | ) | |||
|
Proceeds from sales of securities
|
$ | 377 | $ | 295 | $ | 232 | ||||||
82
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Realized gains and losses from the sale of securities for the
Fermi 2 trust and the low level radioactive waste funds are
recorded to the Regulatory asset and Nuclear decommissioning
liability. The following table sets forth the fair value and
unrealized gains for the nuclear decommissioning trust funds:
|
Fair
|
Unrealized
|
|||||||
| Value | Gains | |||||||
| (In millions) | ||||||||
|
As of December 31, 2010
|
||||||||
|
Equity securities
|
$ | 572 | $ | 77 | ||||
|
Debt securities
|
361 | 11 | ||||||
|
Cash and cash equivalents
|
6 | — | ||||||
| $ | 939 | $ | 88 | |||||
|
As of December 31, 2009
|
||||||||
|
Equity securities
|
$ | 420 | $ | 135 | ||||
|
Debt securities
|
388 | 17 | ||||||
|
Cash and cash equivalents
|
9 | — | ||||||
| $ | 817 | $ | 152 | |||||
Securities held in the nuclear decommissioning trust funds are
classified as
available-for-sale.
As Detroit Edison does not have the ability to hold impaired
investments for a period of time sufficient to allow for the
anticipated recovery of market value, all unrealized losses are
considered to be other than temporary impairments.
Impairment charges for unrealized losses incurred by the Fermi 2
trust are recognized as a Regulatory asset. Detroit Edison
recognized $26 million and $48 million of unrealized
losses as Regulatory assets at December 31, 2010 and 2009,
respectively. Since the decommissioning of Fermi 1 is funded by
Detroit Edison rather than through a regulatory recovery
mechanism, there is no corresponding regulatory asset treatment.
Therefore, impairment charges for unrealized losses incurred by
the Fermi 1 trust are recognized in earnings immediately. There
were no impairment charges in 2010, 2009 and 2008 for Fermi 1.
Other
Available- For- Sale Securities
The following table summarizes the fair value of the
Company’s investment in
available-for-sale
debt and equity securities, excluding nuclear decommissioning
trust fund assets:
| December 31, 2010 | December 31, 2009 | |||||||||||||||
| Fair Value | Carrying value | Fair Value | Carrying Value | |||||||||||||
| (In millions) | ||||||||||||||||
|
Cash equivalents
|
$ | 133 | $ | 133 | $ | 106 | $ | 106 | ||||||||
|
Equity securities
|
$ | 6 | $ | 6 | $ | 11 | $ | 11 | ||||||||
At December 31, 2010 and 2009, these securities are
comprised primarily of money-market and equity securities.
During the year ended December 31, 2010, no amounts of
unrealized losses on available for sale securities were
reclassified out of other comprehensive income into losses for
the period. During the year ended December 31, 2009,
$3 million of unrealized losses on
available-for-sale
securities were reclassified out of other comprehensive income
into earnings. This reclassification includes an other than
temporary impairment of equity securities of $4 million.
Gains (losses) related to trading securities held at
December 31, 2010, 2009, and 2008 were $7 million,
$8 million and $(14) million respectively.
83
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| NOTE 5 — | FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS |
The Company recognizes all derivatives at their fair value as
Derivative Assets or Liabilities on the Consolidated Statements
of Financial Position unless they qualify for certain scope
exceptions, including the normal purchases and normal sales
exception. Further, derivatives that qualify and are designated
for hedge accounting are classified as either hedges of a
forecasted transaction or the variability of cash flows to be
received or paid related to a recognized asset or liability
(cash flow hedge), or as hedges of the fair value of a
recognized asset or liability or of an unrecognized firm
commitment (fair value hedge). For cash flow hedges, the portion
of the derivative gain or loss that is effective in offsetting
the change in the value of the underlying exposure is deferred
in Accumulated other comprehensive income and later reclassified
into earnings when the underlying transaction occurs. For fair
value hedges, changes in fair values for the derivative are
recognized in earnings each period. Gains and losses from the
ineffective portion of any hedge are recognized in earnings
immediately. For derivatives that do not qualify or are not
designated for hedge accounting, changes in the fair value are
recognized in earnings each period.
The Company’s primary market risk exposure is associated
with commodity prices, credit, interest rates and foreign
currency exchange. The Company has risk management policies to
monitor and manage market risks. The Company uses derivative
instruments to manage some of the exposure. The Company uses
derivative instruments for trading purposes in its Energy
Trading segment and the coal marketing activities of its Power
and Industrial Projects segment. Contracts classified as
derivative instruments include power, gas, oil and certain coal
forwards, futures, options and swaps, and foreign currency
exchange contracts. Items not classified as derivatives include
natural gas inventory, unconventional gas reserves, power
transmission, pipeline transportation and certain storage assets.
Electric Utility
— Detroit Edison generates,
purchases, distributes and sells electricity. Detroit Edison
uses forward energy and capacity contracts to manage changes in
the price of electricity and fuel. Substantially all of these
contracts meet the normal purchases and sales exemption and are
therefore accounted for under the accrual method. Other
derivative contracts are recoverable through the PSCR mechanism
when settled. This results in the deferral of unrealized gains
and losses as Regulatory assets or liabilities until realized.
Gas Utility
— MichCon purchases, stores,
transports, gathers, distributes and sells natural gas and sells
storage and transportation capacity. MichCon has fixed-priced
contracts for portions of its expected gas supply requirements
through March 2014. Substantially all of these contracts meet
the normal purchases and sales exemption and are therefore
accounted for under the accrual method. MichCon may also sell
forward transportation and storage capacity contracts. Forward
transportation and storage contracts are not derivatives and are
therefore accounted for under the accrual method.
Gas Storage and Pipelines —
This segment is
primarily engaged in services related to the transportation and
storage of natural gas. Fixed-priced contracts are used in the
marketing and management of transportation and storage services.
Generally these contracts are not derivatives and are therefore
accounted for under the accrual method.
Unconventional Gas Production
— The
Unconventional Gas Production business is engaged in
unconventional natural gas and oil project development and
production. The Company uses derivative contracts to manage
changes in the price of natural gas and crude oil. In 2010 and
prior periods, these derivatives were designated as cash flow
hedges. Approximately $1 million after-tax gain recorded in
Accumulated other comprehensive income at the end of 2009 was
reclassified to earnings as the related production affected
earnings through 2010. Total pre-tax gains from derivative
contracts on natural gas during 2010 were approximately
$3 million.
Power and Industrial Projects
— Business units
within this segment manage and operate onsite energy and
pulverized coal projects, coke batteries, landfill gas recovery
and power generation assets. These businesses utilize
fixed-priced contracts in the marketing and management of their
assets. These contracts are generally not
84
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
derivatives and are therefore accounted for under the accrual
method. The segment also engages in coal marketing which
includes the marketing and trading of physical coal and coal
financial instruments, and forward contracts for the purchase
and sale of emissions allowances. Certain of these physical and
financial coal contracts and contracts for the purchase and sale
of emission allowances are derivatives and are accounted for by
recording changes in fair value to earnings.
Energy Trading — Commodity Price Risk —
Energy Trading markets and trades electricity and natural
gas physical products and energy financial instruments, and
provides risk management services utilizing energy commodity
derivative instruments. Forwards, futures, options and swap
agreements are used to manage exposure to the risk of market
price and volume fluctuations in its operations. These
derivatives are accounted for by recording changes in fair value
to earnings unless hedge accounting criteria are met.
Energy Trading — Foreign Currency Exchange
Risk —
Energy Trading has foreign currency
exchange forward contracts to economically hedge fixed Canadian
dollar commitments existing under power purchase and sale
contracts and gas transportation contracts. The Company enters
into these contracts to mitigate price volatility with respect
to fluctuations of the Canadian dollar relative to the
U.S. dollar. These derivatives are accounted for by
recording changes in fair value to earnings unless hedge
accounting criteria are met.
Corporate and Other — Interest Rate
Risk —
The Company uses interest rate swaps,
treasury locks and other derivatives to hedge the risk
associated with interest rate market volatility. In 2004 and
2000, the Company entered into a series of interest rate
derivatives to limit its sensitivity to market interest rate
risk associated with the issuance of long-term debt. Such
instruments were designated as cash flow hedges. The Company
subsequently issued long-term debt and terminated these hedges
at a cost that is included in other comprehensive loss. Amounts
recorded in other comprehensive loss will be reclassified to
interest expense through 2033. In 2011, the Company estimates
reclassifying less than $1 million of losses to earnings.
Credit Risk —
The utility and non-utility
businesses are exposed to credit risk if customers or
counterparties do not comply with their contractual obligations.
The Company maintains credit policies that significantly
minimize overall credit risk. These policies include an
evaluation of potential customers’ and counterparties’
financial condition, credit rating, collateral requirements or
other credit enhancements such as letters of credit or
guarantees. The Company generally uses standardized agreements
that allow the netting of positive and negative transactions
associated with a single counterparty. The Company maintains a
provision for credit losses based on factors surrounding the
credit risk of its customers, historical trends, and other
information. Based on the Company’s credit policies and its
December 31, 2010 provision for credit losses, the
Company’s exposure to counterparty nonperformance is not
expected to have a material adverse effect on the Company’s
financial statements.
Derivative
Activities
The Company manages its MTM risk on a portfolio basis based upon
the delivery period of its contracts and the individual
components of the risks within each contract. Accordingly, it
records and manages the energy purchase and sale obligations
under its contracts in separate components based on the
commodity (e.g. electricity or gas), the product (e.g.
electricity for delivery during peak or off-peak hours), the
delivery location (e.g. by region), the risk profile (e.g.
forward or option), and the delivery period (e.g. by month and
year). The following describe the four categories of activities
represented by their operating characteristics and key risks:
| • | Asset Optimization — Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with power transmission, gas transportation and storage capacity. Changes in the value of derivatives in this category economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility. |
85
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| • | Marketing and Origination — Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers. | |
| • | Fundamentals Based Trading — Represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure. | |
| • | Other — Includes derivative activity at Detroit Edison related to FTRs and forward contracts related to emissions. Changes in the value of derivative contracts at Detroit Edison are recorded as Derivative Assets or Liabilities, with an offset to Regulatory Assets or Liabilities as the settlement value of these contracts will be included in the PSCR mechanism when realized. |
The following represents the fair value of derivative
instruments as of December 31, 2010:
| Derivative Assets | Derivative Liabilities | |||||||
| (In millions) | ||||||||
|
Derivatives designated as hedging instruments:
|
||||||||
|
Interest rate contracts
|
$ | — | $ | (1 | ) | |||
|
Total derivatives designated as hedging instruments:
|
$ | — | $ | (1 | ) | |||
|
Derivatives not designated as hedging instruments:
|
||||||||
|
Foreign currency exchange contracts
|
$ | 20 | $ | (30 | ) | |||
|
Commodity Contracts:
|
||||||||
|
Natural Gas
|
1,986 | (2,118 | ) | |||||
|
Electricity
|
766 | (716 | ) | |||||
|
Other
|
76 | (71 | ) | |||||
|
Total derivatives not designated as hedging instruments:
|
$ | 2,848 | $ | (2,935 | ) | |||
|
Total derivatives:
|
||||||||
|
Current
|
$ | 2,011 | $ | (2,041 | ) | |||
|
Noncurrent
|
837 | (895 | ) | |||||
|
Total derivatives
|
$ | 2,848 | $ | (2,936 | ) | |||
| Derivative Assets | Derivative Liabilities | |||||||||||||||
| Current | Noncurrent | Current | Noncurrent | |||||||||||||
|
Reconciliation of derivative instruments to Consolidated
Statements of Financial Position:
|
||||||||||||||||
|
Total fair value of derivatives
|
$ | 2,011 | $ | 837 | $ | (2,041 | ) | $ | (895 | ) | ||||||
|
Counterparty netting
|
(1,871 | ) | (760 | ) | 1,871 | 760 | ||||||||||
|
Collateral adjustment
|
(9 | ) | — | 28 | 25 | |||||||||||
|
Total derivatives as reported
|
$ | 131 | $ | 77 | $ | (142 | ) | $ | (110 | ) | ||||||
86
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
The following represents the fair value of derivative
instruments as of December 31, 2009:
| Derivative Assets | Derivative Liabilities | |||||||
| (In millions) | ||||||||
|
Derivatives designated as hedging instruments:
|
||||||||
|
Commodity Contracts — Natural Gas
|
$ | 2 | $ | — | ||||
|
Derivatives not designated as hedging instruments:
|
||||||||
|
Foreign currency exchange contracts
|
$ | 24 | $ | (31 | ) | |||
|
Commodity Contracts:
|
||||||||
|
Natural Gas
|
1,323 | (1,552 | ) | |||||
|
Electricity
|
1,304 | (1,241 | ) | |||||
|
Other
|
19 | (27 | ) | |||||
|
Total derivatives not designated as hedging instruments:
|
$ | 2,670 | $ | (2,851 | ) | |||
|
Total derivatives:
|
||||||||
|
Current
|
$ | 1,860 | $ | (1,951 | ) | |||
|
Noncurrent
|
812 | (900 | ) | |||||
|
Total derivatives
|
$ | 2,672 | $ | (2,851 | ) | |||
| Derivative Assets | Derivative Liabilities | |||||||||||||||
| Current | Noncurrent | Current | Noncurrent | |||||||||||||
|
Reconciliation of derivative instruments to Consolidated
Statements of Financial Position:
|
||||||||||||||||
|
Total fair value of derivatives
|
$ | 1,860 | $ | 812 | $ | (1,951 | ) | $ | (900 | ) | ||||||
|
Counterparty netting
|
(1,644 | ) | (669 | ) | 1,644 | 669 | ||||||||||
|
Collateral adjustment
|
(7 | ) | (27 | ) | 87 | 33 | ||||||||||
|
Total derivatives as reported
|
$ | 209 | $ | 116 | $ | (220 | ) | $ | (198 | ) | ||||||
For the effective portion of natural gas derivatives designated
as cash flow hedges, the Company recognized an after-tax gain of
$1 million and $3 million in Other comprehensive
income for the years ended December 31, 2010 and 2009,
respectively. The Company reclassified an after-tax gain of
$2 million and $5 million from Accumulated other
comprehensive income into Operating revenue for the years ended
December 31, 2010 and 2009, respectively. For the effective
portion of interest swaps representing a discontinued cash flow
hedge, the Company reclassified an after-tax loss of
$3 million from Accumulated other comprehensive income into
Interest expense for the year ended December 31, 2009.
87
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
The effect of derivatives not designated as hedging instruments
on the Consolidated Statements of Operations for years ended
December 31, 2010 and December 31, 2009 is as follows:
|
Gain (Loss)
|
||||||||||
|
Recognized in
|
||||||||||
|
Income on
|
||||||||||
|
Location of Gain
|
Derivatives for
|
|||||||||
|
(Loss) Recognized
|
Years Ended
|
|||||||||
|
in Income
|
December 31 | |||||||||
| Derivatives not Designated as Hedging Instruments | On Derivatives | 2010 | 2009 | |||||||
| (In millions) | ||||||||||
|
Foreign currency exchange contracts
|
Operating Revenue | $ | (14 | ) | $ | (24 | ) | |||
|
Commodity Contracts:
|
||||||||||
|
Natural Gas
|
Operating Revenue | 61 | 179 | |||||||
|
Natural Gas
|
Fuel, purchased power and gas | (8 | ) | 4 | ||||||
|
Electricity
|
Operating Revenue | 80 | 19 | |||||||
|
Other
|
Operating Revenue | 9 | (4 | ) | ||||||
|
Other
|
Operation and maintenance | (5 | ) | 6 | ||||||
|
Total
|
$ | 123 | $ | 180 | ||||||
The effects of derivative instruments recoverable through the
PSCR mechanism when realized on the Consolidated Statements of
Financial Position are $1 million in losses related to
Emissions recognized in Regulatory assets and $6 million in
gains related to FTRs recognized in Regulatory liabilities for
the year ended December 31, 2010, and $14 million and
$2 million in losses related to Emissions recognized in
Regulatory assets and Regulatory liabilities, respectively, for
the year ended December 31, 2009.
The following represents the cumulative gross volume of
derivative contracts outstanding as of December 31, 2010:
| Commodity | Number of Units | |||
|
Natural Gas (MMBtu)
|
803,275,912 | |||
|
Electricity (MWh)
|
51,720,281 | |||
|
Foreign Currency Exchange ($ CAD)
|
238,336,031 | |||
Various non-utility subsidiaries of the Company have entered
into contracts which contain ratings triggers and are guaranteed
by DTE Energy. These contracts contain provisions which allow
the counterparties to request that the Company post cash or
letters of credit as collateral in the event that DTE
Energy’s credit rating is downgraded below investment
grade. Certain of these provisions (known as “hard
triggers”) state specific circumstances under which the
Company can be asked to post collateral upon the occurrence of a
credit downgrade, while other provisions (known as “soft
triggers”) are not as specific. For contracts with soft
triggers, it is difficult to estimate the amount of collateral
which may be requested by counterparties
and/or
which
the Company may ultimately be required to post. The amount of
such collateral which could be requested fluctuates based on
commodity prices (primarily gas, power and coal) and the
provisions and maturities of the underlying transactions. As of
December 31, 2010, the value of the transactions for which
the Company would have been exposed to collateral requests had
DTE Energy’s credit rating been below investment grade on
such date under both hard trigger and soft trigger provisions
was approximately $234 million. In circumstances where an
entity is downgraded below investment grade and collateral
requests are made as a result, the requesting parties often
agree to accept less than the full amount of their exposure to
the downgraded entity.
88
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| NOTE 6 — | GOODWILL |
The Company has goodwill resulting from purchase business
combinations.
The change in the carrying amount of goodwill for the fiscal
years ended December 31, 2010 and December 31, 2009 is
as follows:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Balance as of January 1
|
$ | 2,024 | $ | 2,037 | ||||
|
Goodwill attributable to sale of subsidiary in Power and
Industrial Projects
|
(4 | ) | — | |||||
|
Goodwill attributable to sale of subsidiary in Gas Utility
|
— | (13 | ) | |||||
|
Balance at December 31
|
$ | 2,020 | $ | 2,024 | ||||
| NOTE 7 — | PROPERTY, PLANT AND EQUIPMENT |
Summary of property by classification as of December 31:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Property, Plant and Equipment
|
||||||||
|
Electric Utility
|
||||||||
|
Generation
|
$ | 9,268 | $ | 8,833 | ||||
|
Distribution
|
6,800 | 6,618 | ||||||
|
Total Electric Utility
|
16,068 | 15,451 | ||||||
|
Gas Utility
|
||||||||
|
Distribution
|
2,460 | 2,386 | ||||||
|
Storage
|
395 | 383 | ||||||
|
Other
|
991 | 1,013 | ||||||
|
Total Gas Utility
|
3,846 | 3,782 | ||||||
|
Non-utility and other
|
1,660 | 1,355 | ||||||
|
Total
|
21,574 | 20,588 | ||||||
|
Less Accumulated Depreciation, Depletion and Amortization
|
||||||||
|
Electric Utility
|
||||||||
|
Generation
|
(3,850 | ) | (3,890 | ) | ||||
|
Distribution
|
(2,568 | ) | (2,243 | ) | ||||
|
Total Electric Utility
|
(6,418 | ) | (6,133 | ) | ||||
|
Gas Utility
|
||||||||
|
Distribution
|
(1,019 | ) | (972 | ) | ||||
|
Storage
|
(108 | ) | (113 | ) | ||||
|
Other
|
(512 | ) | (543 | ) | ||||
|
Total Gas Utility
|
(1,639 | ) | (1,628 | ) | ||||
|
Non-utility and other
|
(525 | ) | (396 | ) | ||||
|
Total
|
(8,582 | ) | (8,157 | ) | ||||
|
Net Property, Plant and Equipment
|
$ | 12,992 | $ | 12,431 | ||||
89
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
AFUDC capitalized during 2010 and 2009 was approximately
$10 million and $14 million, respectively.
The composite depreciation rate for Detroit Edison was 3.3% in
2010, 2009 and 2008. The composite depreciation rate for MichCon
was 2.5% in 2010, 3.1% in 2009 and 3.2% in 2008. In March 2010,
the MPSC issued an order reducing MichCon’s composite
depreciation rates effective April 1, 2010.
The average estimated useful life for each major class of
utility property, plant and equipment as of December 31,
2010 follows:
| Estimated Useful Lives in Years | ||||||||||||
| Utility | Generation | Distribution | Transmission | |||||||||
|
Electric
|
40 | 37 | N/A | |||||||||
|
Gas
|
N/A | 62 | 61 | |||||||||
The estimated useful lives for major classes of non-utility
assets and facilities ranges from 3 to 55 years.
Capitalized software costs are classified as Property, plant and
equipment and the related amortization is included in
Accumulated depreciation, depletion and amortization on the
Consolidated Statements of Financial Position. The Company
capitalizes the costs associated with computer software it
develops or obtains for use in its business. The Company
amortizes capitalized software costs on a straight-line basis
over the expected period of benefit, ranging from 3 to
20 years.
Capitalized software costs amortization expense was
$65 million in 2010, $66 million in 2009 and
$54 million in 2008. The gross carrying amount and
accumulated amortization of capitalized software costs at
December 31, 2010 were $602 million and
$252 million, respectively. The gross carrying amount and
accumulated amortization of capitalized software costs at
December 31, 2009 were $613 million and
$234 million, respectively. Amortization expense of
capitalized software costs is estimated to be approximately
$66 million annually for 2011 through 2015.
Gross property under capital leases was $153 million at
December 31, 2010 and December 31, 2009. Accumulated
amortization of property under capital leases was
$114 million and $93 million at December 31, 2010
and December 31, 2009, respectively.
| NOTE 8 — | JOINTLY OWNED UTILITY PLANT |
Detroit Edison has joint ownership interest in two power plants,
Belle River and Ludington Hydroelectric Pumped Storage. Detroit
Edison’s share of direct expenses of the jointly owned
plants are included in Fuel, purchased power and gas and
Operation and maintenance expenses in the Consolidated
Statements of Operations. Ownership information of the two
utility plants as of December 31, 2010 was as follows:
|
Ludington
|
||||||||
|
Hydroelectric
|
||||||||
| Belle River | Pumped Storage | |||||||
|
In-service date
|
1984-1985 | 1973 | ||||||
|
Total plant capacity
|
1,270MW | 1,872MW | ||||||
|
Ownership interest
|
* | 49 | % | |||||
|
Investment (in millions)
|
$ | 1,635 | $ | 199 | ||||
|
Accumulated depreciation (in millions)
|
$ | 923 | $ | 117 | ||||
| * | Detroit Edison’s ownership interest is 63% in Unit No. 1, 81% of the facilities applicable to Belle River used jointly by the Belle River and St. Clair Power Plants and 75% in common facilities used at Unit No. 2. |
90
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Belle
River
The Michigan Public Power Agency (MPPA) has an ownership
interest in Belle River Unit No. 1 and other related
facilities. The MPPA is entitled to 19% of the total capacity
and energy of the plant and is responsible for the same
percentage of the plant’s operation, maintenance and
capital improvement costs.
Ludington
Hydroelectric Pumped Storage
Consumers Energy Company has an ownership interest in the
Ludington Hydroelectric Pumped Storage Plant. Consumers Energy
is entitled to 51% of the total capacity and energy of the plant
and is responsible for the same percentage of the plant’s
operation, maintenance and capital improvement costs.
| NOTE 9 — | ASSET RETIREMENT OBLIGATIONS |
The Company has a legal retirement obligation for the
decommissioning costs for its Fermi 1 and Fermi 2 nuclear
plants. To a lesser extent, the Company has legal retirement
obligations for gas production facilities, gas gathering
facilities and various other operations. The Company has
conditional retirement obligations for gas pipeline retirement
costs and disposal of asbestos at certain of its power plants.
To a lesser extent, the Company has conditional retirement
obligations at certain service centers, compressor and gate
stations, and disposal costs for PCB contained within
transformers and circuit breakers. The Company recognizes such
obligations as liabilities at fair market value when they are
incurred, which generally is at the time the associated assets
are placed in service. Fair value is measured using expected
future cash outflows discounted at our credit-adjusted risk-free
rate. In its regulated operations, the Company recognizes
regulatory assets or liabilities for timing differences in
expense recognition for legal asset retirement costs that are
currently recovered in rates.
No liability has been recorded with respect to lead-based paint,
as the quantities of lead-based paint in the Company’s
facilities are unknown. In addition, there is no incremental
cost to demolitions of lead-based paint facilities vs.
non-lead-based paint facilities and no regulations currently
exist requiring any type of special disposal of items containing
lead-based paint.
The Ludington Hydroelectric Power Plant (a jointly owned plant)
has an indeterminate life and no legal obligation currently
exists to decommission the plant at some future date.
Substations, manholes and certain other distribution assets
within Detroit Edison have an indeterminate life. Therefore, no
liability has been recorded for these assets.
A reconciliation of the asset retirement obligations for 2010
follows:
| (In millions) | ||||
|
Asset retirement obligations at January 1, 2010
|
$ | 1,439 | ||
|
Accretion
|
92 | |||
|
Liabilities incurred
|
10 | |||
|
Liabilities settled
|
(9 | ) | ||
|
Revision in estimated cash flows
|
(22 | ) | ||
|
Consolidation of VIEs
|
4 | |||
|
Asset retirement obligations at December 31, 2010
|
1,514 | |||
|
Less amount included in current liabilities
|
(16 | ) | ||
| $ | 1,498 | |||
Detroit Edison has a legal obligation to decommission its
nuclear power plants following the expiration of their operating
licenses. This obligation is reflected as an asset retirement
obligation on the Consolidated Statements of Financial Position.
In 2010, Detroit Edison filed a rate case with the MPSC
proposing a reduction to the nuclear
91
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
decommissioning surcharge under the assumption that it would
request an extension of the Fermi 2 license for an additional
20 years beyond the term of the existing license which
expires in 2025. This proposed extension of the license,
including the associated impact on spent nuclear fuel, resulted
in a revision in estimated cash flows for the Fermi 2 asset
retirement obligation of approximately $22 million. It is
estimated that the cost of decommissioning Fermi 2 is
$1.3 billion in 2010 dollars and $10 billion in 2045
dollars, using a 6% inflation rate. In 2001, Detroit Edison
began the decommissioning of Fermi 1, with the goal of removing
the radioactive material and terminating the Fermi 1 license.
The decommissioning of Fermi 1 is expected to be completed by
2012. Approximately $1.3 billion of the asset retirement
obligations represent nuclear decommissioning liabilities that
are funded through a surcharge to electric customers over the
life of the Fermi 2 nuclear plant.
The NRC has jurisdiction over the decommissioning of nuclear
power plants and requires minimum decommissioning funding based
upon a formula. The MPSC and FERC regulate the recovery of costs
of decommissioning nuclear power plants and both require the use
of external trust funds to finance the decommissioning of Fermi
2. Rates approved by the MPSC provide for the recovery of
decommissioning costs of Fermi 2 and the disposal of low-level
radioactive waste. Detroit Edison is continuing to
fund FERC jurisdictional amounts for decommissioning even
though explicit provisions are not included in FERC rates. The
Company believes the MPSC and FERC collections will be adequate
to fund the estimated cost of decommissioning. The
decommissioning assets, anticipated earnings thereon and future
revenues from decommissioning collections will be used to
decommission Fermi 2. The Company expects the liabilities to be
reduced to zero at the conclusion of the decommissioning
activities. If amounts remain in the trust funds for Fermi 2
following the completion of the decommissioning activities,
those amounts will be disbursed based on rulings by the MPSC and
FERC.
A portion of the funds recovered through the Fermi 2
decommissioning surcharge and deposited in external trust
accounts is designated for the removal of non-radioactive assets
and the
clean-up
of
the Fermi site. This removal and
clean-up
is
not considered a legal liability. Therefore, it is not included
in the asset retirement obligation, but is reflected as the
nuclear decommissioning liability. The decommissioning of Fermi
1 is funded by Detroit Edison. Contributions to the Fermi 1
trust are discretionary. See Note 4 for additional
discussion of Nuclear Decommissioning
Trust Fund Assets.
| NOTE 10 — | DISPOSALS AND DISCONTINUED OPERATIONS |
Sale
of Rail Services Assets
In 2010, the Company sold certain non-strategic rail services
assets for gross proceeds of approximately $23 million. The
Company recognized a gain of approximately $5 million, net
of a write-off of goodwill of approximately $4 million.
Sale
of Gathering and Processing Assets
In 2009, the Company sold certain non-strategic gas gathering
and processing assets in northern Michigan for gross proceeds of
approximately $45 million, which approximated its carrying
value, including goodwill of approximately $13 million.
Sale
of Interest in Barnett Shale Properties
In 2008, the Company sold a portion of its Barnett shale
properties for gross proceeds of approximately
$260 million. The Company recognized a gain of
$128 million ($80 million after-tax) on the sale
during 2008.
Plan
to Sell Interest in Certain Power and Industrial
Projects
In 2007, the Company announced its plans to sell a 50% interest
in a portfolio of select Power and Industrial Projects. As a
result, the assets and liabilities of the Projects were
classified as held for sale at that time and the
92
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Company ceased recording depreciation and amortization expense
related to these assets. In 2008, the Company’s work on
this planned monetization was discontinued and the assets and
liabilities of the Projects were no longer classified as held
for sale. Depreciation and amortization resumed when the assets
were reclassified as held and used. In 2008, the Company
recorded a loss of $19 million related to the valuation
adjustment for the cumulative depreciation and amortization not
recorded during the held for sale period.
Synthetic
Fuel Business
The Company discontinued the operations of its synthetic fuel
production facilities throughout the United States as of
December 31, 2007. The Company provided certain guarantees
and indemnities in conjunction with the sales of interests in
its synfuel facilities. The guarantees cover potential
commercial, environmental, oil price and tax-related obligations
and will survive until 90 days after expiration of all
applicable statutes of limitations. The Company estimates that
its maximum potential liability under these guarantees at
December 31, 2010 is $2.6 billion, although payment
under these guarantees is not considered probable. The Company
has reported the business activity of the synthetic fuel
business as a discontinued operation. For the year ended
December 31, 2008, the synthetic fuels business had net
income of $22 million (including $2 million for
noncontrolling interests), primarily from asset gains, net of
income taxes.
| NOTE 11 — | OTHER IMPAIRMENTS AND RESTRUCTURING |
Other
Impairments — Barnett Shale
Our Unconventional Gas Production segment recorded pre-tax
impairment losses of $10 million, $6 million and
$8 million in 2010, 2009 and 2008, respectively. The
impairments related primarily to the write-off of expired or
expiring leasehold positions that the Company does not intend to
drill.
Restructuring
Costs
In 2005, the Company initiated a company-wide review of its
operations called the Performance Excellence Process. The
Company incurred CTA restructuring expense for employee
severance, early retirement programs and other costs which
include project management and consultant support. In September
2006, the MPSC issued an order approving a settlement agreement
that allowed Detroit Edison and MichCon, commencing in 2006, to
defer the incremental CTA. Further, the order provided for
Detroit Edison and MichCon to amortize the CTA deferrals over a
ten-year period beginning with the year subsequent to the year
the CTA was deferred. Detroit Edison deferred approximately
$24 million of CTA in 2008 as a regulatory asset and
capitalized $2 million. The recovery of these costs for
Detroit Edison was provided for by the MPSC in the order
approving the settlement in the show cause proceeding and in the
December 23, 2008 MPSC rate order. Detroit Edison amortized
prior year deferred CTA costs of $18 million in 2010,
$18 million in 2009 and $16 million in 2008. The
September 2006 order did not provide a regulatory recovery
mechanism for MichCon, therefore MichCon expensed CTA incurred
during the period 2006 through 2008. The Company incurred
restructuring expense, net of amounts deferred and capitalized
of $10 million in 2008. The June 2010 MPSC order provided
for MichCon’s recovery of the regulatory unamortized
balance of CTA. At June 30, 2010, MichCon deferred and
recognized in income approximately $32 million
($20 million after-tax) of previously expensed CTA. The
non-pension component of CTA of approximately $21 million
is included in Regulatory assets. The pension component of CTA
of approximately $11 million is included in Regulatory
liabilities. MichCon amortized approximately $2 million of
prior year deferred CTA costs in 2010. Amounts expensed are
recorded in Operation and maintenance expense on the
Consolidated Statements of Operations. Deferred amounts are
recorded in Regulatory assets and Regulatory liabilities on the
Consolidated Statements of Financial Position. See Note 12.
93
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| NOTE 12 — | REGULATORY MATTERS |
Regulation
Detroit Edison and MichCon are subject to the regulatory
jurisdiction of the MPSC, which issues orders pertaining to
rates, recovery of certain costs, including the costs of
generating facilities and regulatory assets, conditions of
service, accounting and operating-related matters. Detroit
Edison is also regulated by the FERC with respect to financing
authorization and wholesale electric activities. Regulation
results in differences in the application of generally accepted
accounting principles between regulated and non-regulated
businesses.
Regulatory
Assets and Liabilities
Detroit Edison and MichCon are required to record regulatory
assets and liabilities for certain transactions that would have
been treated as revenue or expense in non-regulated businesses.
Continued applicability of regulatory accounting treatment
requires that rates be designed to recover specific costs of
providing regulated services and be charged to and collected
from customers. Future regulatory changes or changes in the
competitive environment could result in the discontinuance of
this accounting treatment for regulatory assets and liabilities
for some or all of our businesses and may require the write-off
of the portion of any regulatory asset or liability that was no
longer probable of recovery through regulated rates. Management
believes that currently available facts support the continued
use of regulatory assets and liabilities and that all regulatory
assets and liabilities are recoverable or refundable in the
current rate environment.
The following are balances and a brief description of the
regulatory assets and liabilities at December 31:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Assets
|
||||||||
|
Recoverable pension and postretirement costs:
|
||||||||
|
Pension
|
$ | 1,742 | $ | 1,670 | ||||
|
Postretirement costs
|
624 | 665 | ||||||
|
Asset retirement obligation
|
336 | 415 | ||||||
|
Recoverable income taxes related to securitized regulatory assets
|
400 | 476 | ||||||
|
Deferred income taxes — Michigan Business Tax
|
383 | 407 | ||||||
|
Cost to achieve Performance Excellence Process
|
137 | 136 | ||||||
|
Choice incentive mechanism
|
105 | — | ||||||
|
Recoverable uncollectible expense
|
90 | 138 | ||||||
|
Other recoverable income taxes
|
85 | 89 | ||||||
|
Unamortized loss on reacquired debt
|
65 | 70 | ||||||
|
Accrued PSCR/GCR revenue
|
52 | — | ||||||
|
Deferred environmental costs
|
41 | 40 | ||||||
|
Enterprise Business Systems costs
|
21 | 24 | ||||||
|
Recoverable restoration expense
|
19 | — | ||||||
|
Electric Customer Choice implementation costs
|
— | 18 | ||||||
|
Other
|
58 | 15 | ||||||
| 4,158 | 4,163 | |||||||
|
Less amount included in current assets
|
(100 | ) | (53 | ) | ||||
| $ | 4,058 | $ | 4,110 | |||||
|
Securitized regulatory assets
|
$ | 729 | $ | 870 | ||||
94
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Liabilities
|
||||||||
|
Asset removal costs
|
$ | 479 | $ | 506 | ||||
|
Deferred income taxes — Michigan Business Tax
|
418 | 423 | ||||||
|
Negative pension offset
|
129 | 133 | ||||||
|
Renewable energy
|
125 | 32 | ||||||
|
Refundable income taxes
|
77 | 88 | ||||||
|
Refundable self implemented rates
|
52 | 27 | ||||||
|
Refundable revenue decoupling
|
47 | — | ||||||
|
Refundable costs under PA 141
|
33 | 27 | ||||||
|
Refundable restoration expense
|
15 | 15 | ||||||
|
Accrued PSCR/GCR refund
|
8 | 39 | ||||||
|
Fermi 2 refueling outage
|
3 | 13 | ||||||
|
Pension equalization mechanism
|
— | 75 | ||||||
|
Other
|
36 | 11 | ||||||
| 1,422 | 1,389 | |||||||
|
Less amount included in current liabilities
|
(94 | ) | (52 | ) | ||||
| $ | 1,328 | $ | 1,337 | |||||
As noted below, regulatory assets for which costs have been
incurred have been included (or are expected to be included, for
costs incurred subsequent to the most recently approved rate
case) in Detroit Edison or MichCon’s rate base, thereby
providing a return on invested costs. Certain regulatory assets
do not result from cash expenditures and therefore do not
represent investments included in rate base or have offsetting
liabilities that reduce rate base.
ASSETS
| • | Recoverable pension and postretirement costs — In 2007, the Company adopted ASC 715 (SFAS No. 158) which required, among other things, the recognition in other comprehensive income of the actuarial gains or losses and the prior service costs that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Detroit Edison and MichCon record the charge related to the additional liability as a regulatory asset since the traditional rate setting process allows for the recovery of pension and postretirement costs. The asset will reverse as the deferred items are recognized as benefit expenses in net income. (1) |
.
| • | Asset retirement obligation — This obligation is primarily for Fermi 2 decommissioning costs. The asset captures the timing differences between expense recognition and current recovery in rates and will reverse over the remaining life of the related plant. (1) | |
| • | Recoverable income taxes related to securitized regulatory assets — Receivable for the recovery of income taxes to be paid on the non-bypassable securitization bond surcharge. A non-bypassable securitization tax surcharge recovers the income tax over a fourteen-year period ending 2015. | |
| • | Deferred income taxes — Michigan Business Tax (MBT) — In July 2007, the MBT was enacted by the State of Michigan. State deferred tax liabilities were established for the Company’s utilities, and offsetting regulatory assets were recorded as the impacts of the deferred tax liabilities will be reflected in rates as the related taxable temporary differences reverse and flow through current income tax expense. (1) |
95
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| • | Cost to achieve Performance Excellence Process (PEP) — The MPSC authorized the deferral of costs to implement the PEP. These costs consist of employee severance, project management and consultant support. These costs are amortized over a ten-year period beginning with the year subsequent to the year the costs were deferred. | |
| • | Choice incentive mechanism — Detroit Edison receivable for non-fuel revenues lost as a result of fluctuations in electric Customer Choice sales. | |
| • | Recoverable uncollectible expense — Detroit Edison and MichCon receivable for the MPSC approved uncollectible expense tracking mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization. | |
| • | Other recoverable income taxes — Income taxes receivable from Detroit Edison’s customers representing the difference in property-related deferred income taxes and amounts previously reflected in Detroit Edison’s rates. This asset will reverse over the remaining life of the related plant. (1) | |
| • | Unamortized loss on reacquired debt — The unamortized discount, premium and expense related to debt redeemed with a refinancing are deferred, amortized and recovered over the life of the replacement issue. | |
| • | Accrued PSCR revenue — Receivable for the temporary under-recovery of and a return on fuel and purchased power costs incurred by Detroit Edison which are recoverable through the PSCR mechanism. | |
| • | Accrued GCR revenue — Receivable for the temporary under-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism. | |
| • | Deferred environmental costs — The MPSC approved the deferral of investigation and remediation costs associated with Gas Utility’s former MGP sites. Amortization of deferred costs is over a ten-year period beginning in the year after costs were incurred, with recovery (net of any insurance proceeds) through base rate filings. | |
| • | Enterprise Business Systems (EBS) costs — The MPSC approved the deferral and amortization over 10 years beginning in January 2009 of EBS costs that would otherwise be expensed. | |
| • | Recoverable restoration expense — Receivable for the MPSC approved restoration expenses tracking mechanism that tracks the difference between actual restoration expense and the amount provided for in base rates, recognized pursuant to the MPSC authorization. | |
| • | Electric Customer Choice implementation costs — PA 141 permits, after MPSC authorization, the recovery of and a return on costs incurred associated with the implementation of the electric Customer Choice program. | |
| • | Securitized regulatory assets — The net book balance of the Fermi 2 nuclear plant was written off in 1998 and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset and certain other regulatory assets were securitized pursuant to PA 142 and an MPSC order. A non-bypassable securitization bond surcharge recovers the securitized regulatory asset over a fourteen-year period ending in 2015. |
| (1) | Regulatory assets not earning a return. |
LIABILITIES
| • | Asset removal costs — The amount collected from customers for the funding of future asset removal activities. |
96
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| • | Deferred income taxes — Michigan Business Tax — In July 2007, the MBT was enacted by the State of Michigan. State deferred tax assets were established for the Company’s utilities, and offsetting regulatory liabilities were recorded as the impacts of the deferred tax assets will be reflected in rates. | |
| • | Negative pension offset — MichCon’s negative pension costs are not included as a reduction to its authorized rates; therefore, the Company is accruing a regulatory liability to eliminate the impact on earnings of the negative pension expense accrued. This regulatory liability will reverse to the extent MichCon’s pension expense is positive in future years. | |
| • | Renewable energy — Amounts collected in rates in excess of renewable energy expenditures. | |
| • | Refundable income taxes — Income taxes refundable to MichCon’s customers representing the difference in property-related deferred income taxes payable and amounts recognized pursuant to MPSC authorization. | |
| • | Refundable self implemented rates — Amounts refundable to customers for base rates implemented by Detroit Edison and MichCon in excess of amounts authorized in MPSC orders. | |
| • | Refundable revenue decoupling — Amounts refundable to Detroit Edison customers for the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established by the MPSC. Amounts refundable to MichCon customers for the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base level of average sales per customer established by the MPSC. | |
| • | Refundable costs under PA 141 — Detroit Edison’s 2007 CIM reconciliation and allocation resulted in the elimination of Regulatory Asset Recovery Surcharge (RARS) balances for commercial and industrial customers. RARS revenues received that exceed the regulatory asset balances are required to be refunded to the affected classes. | |
| • | Refundable restoration expense — Amounts refundable for the MPSC approved restoration expenses tracking mechanism that tracks the difference between actual restoration expense and the amount provided for in base rates, recognized pursuant to the MPSC authorization. | |
| • | Accrued PSCR refund — Liability for the temporary over-recovery of and a return on power supply costs and transmission costs incurred by Detroit Edison which are recoverable through the PSCR mechanism. | |
| • | Accrued GCR refund — Liability for the temporary over-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism. | |
| • | Fermi 2 refueling outage — Accrued liability for refueling outage at Fermi 2 pursuant to MPSC authorization. | |
| • | Pension equalization mechanism — Pension expense refundable to customers representing the difference created from volatility in the pension obligation and amounts recognized pursuant to MPSC authorization. |
2010
Electric Rate Case Filing
Detroit Edison filed a rate case on October 29, 2010 based
on a projected twelve-month period ending March 31, 2012.
The filing with the MPSC requested a $443 million increase
in base rates that is required to recover higher costs
associated with environmental compliance, operation and
maintenance of the Company’s electric distribution system
and generation plants, inflation, the capital costs of plant
additions, the reduction in territory sales, the impact from the
expiration of certain wholesale for resale contracts and the
increased migration of customers to the electric Customer Choice
program. Detroit Edison also proposed certain adjustments which
could reduce the net impact on the required increase in rates by
approximately $190 million. These adjustments relate to
electric Customer Choice migration, pension and other
postretirement benefits expenses and the Nuclear Decommissioning
surcharge.
97
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
2009
Electric Rate Case Filing
On January 11, 2010, the MPSC issued an order in Detroit
Edison’s January 26, 2009 rate case filing. The MPSC
approved an annual revenue increase of $217 million or a
4.8% increase in Detroit Edison’s annual revenue
requirement for 2010. Included in the approved increase in
revenues was a return on equity of 11% on an expected 49% equity
and 51% debt capital structure. In addition, the order provided
for continued application of adjustment mechanisms for electric
Customer Choice sales and expenses associated with restoration
costs (storm and non-storm) and line clearance expenses and
implementation of RDM and UETM mechanisms.
Since the final rate relief ordered was less than the
Company’s self-implemented rate increase of
$280 million effective on July 26, 2009, the MPSC
ordered refunds for the period the self-implemented rates were
in effect. On December 21, 2010, the MPSC issued an order
authorizing this refund to be applied as credits to customer
bills during the January 2011 billing period. Detroit Edison has
a refund liability of approximately $27 million, including
interest at December 31, 2010 representing the refund due
customers.
2009
Detroit Edison Depreciation Filing
In 2007, the MPSC ordered Michigan utilities to file
depreciation studies using the current method, an approach that
considers the time value of money and an inflation adjusted
method proposed by the Company that removes excess escalation.
In compliance with the MPSC order, Detroit Edison filed its
ordered depreciation studies in November 2009. The various
required depreciation studies indicate composite depreciation
rates from 3.05% to 3.54%. The Company has proposed no change to
its current composite depreciation rate of 3.33%. An MPSC order
is expected in the second quarter of 2011.
Renewable
Energy Plan
In March 2009, Detroit Edison filed its Renewable Energy Plan
with the MPSC as required under Michigan Public Act 295 of 2008.
The Renewable Energy Plan application requests authority to
recover approximately $35 million of additional revenue in
2009. The proposed revenue increase is necessary in order to
properly implement Detroit Edison’s
20-year
renewable energy plan, to deliver cleaner, renewable electric
generation to its customers, to further diversify Detroit
Edison’s and the State of Michigan’s sources of
electric supply, and to address the state and national goals of
increasing energy independence. An MPSC order was issued in June
2009 approving the renewable energy plan and customer
surcharges. The Renewable Energy Plan surcharges became
effective in September 2009. In August 2010, Detroit Edison
filed its reconciliation for the 2009 plan year indicating that
the 2009 actual renewable plan revenues and costs approximated
the related surcharge revenues and cost of the filed plan. An
MPSC order is expected in the third quarter of 2011.
Energy
Optimization (EO) Plans
In March 2009, Detroit Edison and MichCon filed EO Plans with
the MPSC as required under Michigan Public Act 295 of 2008. The
EO Plan applications are designed to help each customer class
reduce their electric and gas usage by: (1) building
customer awareness of energy efficiency options and
(2) offering a diverse set of programs and participation
options that result in energy savings for each customer class.
In March 2010, Detroit Edison and MichCon filed amended EO Plans
with the MPSC. Detroit Edison’s amended EO Plan application
proposed the recovery of EO expenditures for the period
2010-2015
of
$406 million and further requested approval of surcharges
to recover these costs, including a financial incentive
mechanism. MichCon’s amended EO Plan proposed the recovery
of EO expenditures for the period
2010-2015
of
$150 million and further requested approval of surcharges
that are designed to recover these costs, including a financial
incentive mechanism. The MPSC approved the amended EO Plans and
the surcharge and tariff sheets reflecting the exclusion of the
financial incentive mechanism. The disposition of the financial
incentive mechanisms is expected to be addressed in the EO
reconciliation cases. In April 2010, Detroit Edison and MichCon
filed reconciliations for the 2009 plan years. The Detroit
Edison
98
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
reconciliation included $3.2 million in overrecovery, net
of $3 million in incentives. The MichCon reconciliation
included an underrecovery of $0.2 million, net of
incentives of $0.9 million. On February 8, 2011, the
MPSC issued an order approving Detroit Edison’s and
MichCon’s 2009 EO reconciliation filings, including
financial incentives for both utilities.
Detroit
Edison Restoration Expense Tracker Mechanism (RETM) and Line
Clearance Tracker (LCT) Reconciliation
In March 2010, Detroit Edison filed an application with the MPSC
for approval of the reconciliation of its 2009 RETM and LCT. The
Company’s 2009 restoration and line clearance expenses are
less than the amount provided in rates. Accordingly, Detroit
Edison has proposed a refund in the amount of approximately
$16 million, including interest. An MPSC order is expected
in the second quarter of 2011.
Detroit
Edison Uncollectible Expense
True-Up
Mechanism (UETM)
In March 2010, Detroit Edison filed an application with the MPSC
for approval of its UETM for 2009 requesting recovery of
approximately $4.5 million consisting of costs related to
2009 uncollectible expense and associated carrying charges. In
August 2010, the MPSC determined that the UETM was effective
with its January 2010 order in Detroit Edison’s rate case
and dismissed the request for UETM expenses for 2009.
Detroit
Edison Regulatory Asset Recovery Surcharge (RARS)
Reconciliation
In April 2010, Detroit Edison filed an application with the MPSC
for approval of the final reconciliation of its RARS. On
January 20, 2011, the MPSC issued an order authorizing a
refund of approximately $28 million, including interest, to
be applied as credits to customer bills during the February 2011
billing period.
Power
Supply Cost Recovery Proceedings
The PSCR process is designed to allow Detroit Edison to recover
all of its power supply costs if incurred under reasonable and
prudent policies and practices. Detroit Edison’s power
supply costs include fuel costs, purchased and net interchange
power costs, nitrogen oxide and sulfur dioxide emission
allowances costs, urea costs, transmission costs and MISO costs.
The MPSC reviews these costs, policies and practices for
prudence in annual plan and reconciliation filings.
The following table summarizes Detroit Edison’s PSCR
reconciliation filing currently pending with the MPSC:
|
Net Over-Recovery,
|
PSCR Cost of
|
|||||||||||
| PSCR Year | Date Filed | Including Interest | Power Sold | |||||||||
|
2009
|
March 2010 | $ | 15.6 million | $ | 1.1 billion | |||||||
2010 Plan Year
— In September 2009, Detroit
Edison submitted its 2010 PSCR plan case seeking approval of a
levelized PSCR factor of 5.64 mills/kWh below the amount
included in base rates for all PSCR customers. The filing
supports a 2010 power supply expense forecast of
$1.2 billion. Also included in the filing is a request for
approval of the Company’s expense associated with the use
of urea in the selective catalytic reduction units at Monroe
power plant as well as a request for approval of a contract for
capacity and energy associated with a wind energy project. The
Company has also requested authority to recover transfer prices
for renewable energy, coke oven gas expense and other potential
expenses.
2011 Plan Year
— In September 2010, Detroit
Edison filed its 2011 PSCR plan case seeking approval of a
levelized PSCR factor of 2.98 mills/kWh below the amount
included in base rates for all PSCR customers. The filing
supports a total power supply expense forecast of
$1.2 billion. The plan also includes approximately
$36 million for the recovery of its projected 2010 PSCR
under-recovery.
99
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
2010
Gas Rate Case Filing
MichCon filed a rate case on July 27, 2010 based on a fully
projected 2011 test year. The filing with the MPSC requested a
$51 million increase in revenues. During the pendency of
this proceeding, MichCon continuously evaluated its case and
determined that it no longer desired to pursue the relief
requested. On December 13, 2010, the MPSC approved
MichCon’s request to withdraw this rate filing.
2009
Gas Rate Case Filing
On June 3, 2010, the MPSC issued an order in MichCon’s
June 9, 2009 rate case filing. The MPSC approved an annual
revenue increase of $119 million. Included in the approved
increase in revenues was a return on equity of 11% on an
expected permanent capital structure of 50.4% equity and 49.6%
debt. The rate order includes a $22 million impact of lower
depreciation rates as ordered by the MPSC in March 2010,
effective April 1, 2010. Since the final rate relief
ordered was less than the Company’s self-implemented rate
increase of $170 million effective on January 1, 2010,
the MPSC ordered refunds for the period the self-implemented
rates were in effect. On January 20, 2011, the MPSC issued
an order authorizing this refund to be applied as credits to
customer bills during the February 2011 billing period. MichCon
has a refund liability of approximately $26 million,
including interest at December 31, 2010 representing the
refund due customers.
Other key aspects of the MPSC order include the following:
| • | Continued application of an Uncollectible Expense Tracking Mechanism with two modifications. The base amount was increased prospectively from $37 million to $70 million with an 80/20 percent sharing of the expenses (modified from 90/10) above or below the base amount. | |
| • | Implementation of a pilot Revenue Decoupling Mechanism, that will require MichCon to recover or refund the change in distribution revenue resulting from the difference in weather-adjusted average sales per customer by rate schedule compared to the base average sales per customer by rate schedule established in the MPSC order for the period July 1, 2010 to June 30, 2011. | |
| • | Approval of the recovery of previously expensed CTA. See Note 11. |
2008
MichCon Depreciation Filing
On March 18, 2010, the MPSC issued an order reducing
MichCon’s composite depreciation rates from 2.97% to 2.38%
effective April 1, 2010.
MichCon
UETM
In March 2010, MichCon filed an application with the MPSC for
approval of its UETM for 2009 requesting approximately
$59 million consisting of $51 million of costs related
to 2009 uncollectible expense and associated carrying charges
and $8 million of under-collections for the 2007 UETM. On
December 21, 2010, the MPSC approved MichCon’s request
with new surcharges applicable to services rendered beginning on
January 1, 2011.
Gas
Cost Recovery Proceedings
The GCR process is designed to allow MichCon to recover all of
its gas supply costs if incurred under reasonable and prudent
policies and practices. The MPSC reviews these costs, policies
and practices for prudence in annual plan and reconciliation
filings.
The following table summarizes MichCon’s GCR reconciliation
filing currently pending with the MPSC:
|
Net Over-Recovery,
|
||||||||||||
| GCR Year | Date Filed | Including Interest | GCR Cost of Gas Sold | |||||||||
|
2009-2010
|
June 2010 | $ | 5.9 million | $ | 1.0 billion | |||||||
100
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
2010-2011
Plan Year
— In December 2009, MichCon filed its
GCR plan case for the
2010-2011
GCR plan year. The MPSC issued an order in this case in
September 2010 authorizing MichCon to charge a maximum of $7.06
per Mcf, adjustable monthly by a contingent factor. The MPSC
also approved MichCon’s proposed fixed price gas purchasing
program and provided clarification regarding treatment of
certain affiliate purchases.
2011-2012
Plan Year
— In December 2010, MichCon filed its
GCR plan case for the
2011-2012
GCR plan year. MichCon filed for a maximum base GCR factor of
$5.89 per Mcf adjustable monthly by a contingency factor.
Gas
Main Renewal and Gas Meter Move Out Programs
The June 3, 2010 MPSC gas rate case order required MichCon
to make filings related to gas main renewal and meter move-out
programs. In a July 30, 2010 filing, MichCon proposed to
implement a
10-year
gas
main renewal program beginning in 2012 which would require
capital expenditures of approximately $17 million per year
for renewing gas distribution mains, retiring gas mains, and
where appropriate and when related to the gas main renewal or
retirement activity, relocate inside meters to outside locations
and renew service lines.
In a September 30, 2010 filing, MichCon proposed to
implement a
10-year
gas
meter move out program beginning in 2012 which would require
capital expenditures of approximately $22 million per year
primarily for relocation of inside meters to the outside of
residents’ houses. Recovery of costs associated with these
two programs is expected to be provided through these filings or
future MichCon rate cases.
Other
The Company is unable to predict the outcome of the unresolved
regulatory matters discussed herein. Resolution of these matters
is dependent upon future MPSC orders and appeals, which may
materially impact the financial position, results of operations
and cash flows of the Company.
| NOTE 13 — | INCOME TAXES |
Income
Tax Summary
The Company files a consolidated federal income tax return.
Total income tax expense varied from the statutory federal
income tax rate for the following reasons:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Income before income taxes
|
$ | 950 | $ | 782 | $ | 819 | ||||||
|
Income tax expense at 35% statutory rate
|
$ | 333 | $ | 274 | $ | 287 | ||||||
|
Production tax credits
|
(33 | ) | (12 | ) | (7 | ) | ||||||
|
Investment tax credits
|
(6 | ) | (7 | ) | (7 | ) | ||||||
|
Depreciation
|
(4 | ) | (4 | ) | (4 | ) | ||||||
|
Employee Stock Ownership Plan dividends
|
(5 | ) | (5 | ) | (4 | ) | ||||||
|
Medicare part D subsidy
|
— | (6 | ) | (5 | ) | |||||||
|
Domestic production activities deduction
|
(7 | ) | (5 | ) | (2 | ) | ||||||
|
Goodwill attributed to the sale of Gas Utility subsidiaries
|
— | 4 | — | |||||||||
|
Settlement of Federal tax audit
|
(12 | ) | (11 | ) | — | |||||||
|
State and local income taxes, net of federal benefit
|
44 | 25 | 23 | |||||||||
|
Other, net
|
1 | (6 | ) | 7 | ||||||||
|
Income tax expense from continuing operations
|
$ | 311 | $ | 247 | $ | 288 | ||||||
|
Effective income tax rate
|
32.7 | % | 31.6 | % | 35.2 | % | ||||||
101
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Components of income tax expense were as follows:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Continuing operations
|
||||||||||||
|
Current income taxes
|
||||||||||||
|
Federal
|
$ | (172 | ) | $ | 25 | $ | 130 | |||||
|
State and other income tax expense
|
26 | 17 | 17 | |||||||||
|
Total current income taxes
|
(146 | ) | 42 | 147 | ||||||||
|
Deferred income taxes
|
||||||||||||
|
Federal
|
415 | 182 | 121 | |||||||||
|
State and other income tax expense
|
42 | 23 | 20 | |||||||||
|
Total deferred income taxes
|
457 | 205 | 141 | |||||||||
|
Total income taxes from continuing operations
|
311 | 247 | 288 | |||||||||
|
Discontinued operations
|
— | — | 12 | |||||||||
|
Total
|
$ | 311 | $ | 247 | $ | 300 | ||||||
Deferred tax assets and liabilities are recognized for the
estimated future tax effect of temporary differences between the
tax basis of assets or liabilities and the reported amounts in
the financial statements. Deferred tax assets and liabilities
are classified as current or noncurrent according to the
classification of the related assets or liabilities. Deferred
tax assets and liabilities not related to assets or liabilities
are classified according to the expected reversal date of the
temporary differences. Consistent with rate making treatment,
deferred taxes are offset in the table below for temporary
differences which have related regulatory assets and liabilities.
Deferred tax assets (liabilities) were comprised of the
following at December 31:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Property, plant and equipment
|
$ | (2,558 | ) | $ | (1,932 | ) | ||
|
Securitized regulatory assets
|
(396 | ) | (474 | ) | ||||
|
Alternative minimum tax credit carry-forwards
|
337 | 197 | ||||||
|
Merger basis differences
|
49 | 51 | ||||||
|
Pension and benefits
|
(36 | ) | 17 | |||||
|
Other comprehensive income
|
83 | 75 | ||||||
|
Derivative assets and liabilities
|
29 | 59 | ||||||
|
State net operating loss and credit carry-forwards
|
33 | 43 | ||||||
|
Other
|
(2 | ) | 78 | |||||
| (2,461 | ) | (1,886 | ) | |||||
|
Less valuation allowance
|
(32 | ) | (43 | ) | ||||
| $ | (2,493 | ) | $ | (1,929 | ) | |||
|
Current deferred income tax assets
|
$ | 139 | $ | 167 | ||||
|
Long-term deferred income tax liabilities
|
(2,632 | ) | (2,096 | ) | ||||
| $ | (2,493 | ) | $ | (1,929 | ) | |||
|
Deferred income tax assets
|
$ | 1,418 | $ | 1,462 | ||||
|
Deferred income tax liabilities
|
(3,911 | ) | (3,391 | ) | ||||
| $ | (2,493 | ) | $ | (1,929 | ) | |||
102
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Production tax credits earned in prior years but not utilized
totaled $337 million and are carried forward indefinitely
as alternative minimum tax credits. The majority of the
production tax credits earned, including all of those from our
synfuel projects, were generated from projects that had received
a private letter ruling (PLR) from the Internal Revenue Service
(IRS). These PLRs provide assurance as to the appropriateness of
using these credits to offset taxable income, however, these tax
credits are subject to IRS audit and adjustment.
The above table excludes deferred tax liabilities associated
with unamortized investment tax credits that are shown
separately on the Consolidated Statements of Financial Position.
Investment tax credits are deferred and amortized to income over
the average life of the related property.
The Company has state deferred tax assets related to net
operating loss and credit carry-forwards of $32 million and
$43 million at December 31, 2010 and 2009,
respectively. The state net operating loss and credit
carry-forwards expire from 2011 through 2030. The Company has
recorded valuation allowances at December 31, 2010 and 2009
of approximately $32 million and $43 million,
respectively, with respect to these deferred tax assets. In
assessing the realizability of deferred tax assets, the Company
considers whether it is more likely than not that some portion
or all of the deferred tax assets will not be realized. The
ultimate realization of deferred tax assets is dependent upon
the generation of future taxable income during the periods in
which those temporary differences become deductible.
Uncertain
Tax Positions
A reconciliation of the beginning and ending amount of
unrecognized tax benefits is as follows:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Balance at January 1
|
$ | 81 | $ | 72 | $ | 22 | ||||||
|
Additions for tax positions of prior years
|
4 | 15 | 12 | |||||||||
|
Reductions for tax positions of prior years
|
(4 | ) | (5 | ) | (5 | ) | ||||||
|
Additions for tax positions related to the current year
|
— | 7 | 47 | |||||||||
|
Settlements
|
(53 | ) | (5 | ) | (1 | ) | ||||||
|
Lapse of statute of limitations
|
— | (3 | ) | (3 | ) | |||||||
|
Balance at December 31
|
$ | 28 | $ | 81 | $ | 72 | ||||||
The Company had $5 million and $7 million of
unrecognized tax benefits at December 31, 2010 and at
December 31, 2009, respectively, that, if recognized, would
favorably impact its effective tax rate. During the next twelve
months, it is reasonably possible that the Company will settle
certain federal and state tax examinations and audits. As a
result, the Company believes that it is possible that there will
be a decrease in unrecognized tax benefits of up to
$13 million within the next twelve months.
The Company recognizes interest and penalties pertaining to
income taxes in Interest expense and Other expenses,
respectively, on its Consolidated Statements of Operations.
Accrued interest pertaining to income taxes totaled
$3 million and $6 million at December 31, 2010
and December 31, 2009, respectively. The Company had no
accrued penalties pertaining to income taxes. The Company
recognized interest expense related to income taxes of
$1 million, $(2) million and $2 million in 2010,
2009 and 2008, respectively.
In 2009, the Company settled a federal tax audit for the 2004
through 2006 tax years, which resulted in the recognition of
$9 million of unrecognized tax benefits. In 2010, the
Company settled a federal tax audit for the 2007 and 2008 tax
years, which resulted in the recognition of $53 million of
unrecognized tax benefits. The Company’s federal income tax
returns for 2009 and subsequent years remain subject to
examination by the IRS. The Company’s Michigan Business Tax
returns for the year 2008 and subsequent years remain subject to
examination by the State of Michigan. The Company also files tax
returns in numerous state and local jurisdictions with varying
statutes of limitation.
103
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Michigan
Business Tax
In July 2007, the Michigan Business Tax (MBT) was enacted by the
State of Michigan to replace the Michigan Single Business Tax
(MSBT) effective January 1, 2008. The MBT is comprised of
an apportioned modified gross receipts tax of 0.8 percent;
and an apportioned business income tax of 4.95 percent. The
MBT provides credits for Michigan business investment,
compensation, and research and development. Legislation was also
enacted, in 2007, by the State of Michigan creating a deduction
for businesses that realize an increase in their deferred tax
liability due to the enactment of the MBT. The MBT is accounted
for as an income tax.
The MBT consolidated deferred tax liability balance is
$366 million as of December 31, 2010 and
$357 million as of December 31, 2009 and is reported
net of the related federal tax benefit. The MBT deferred tax
asset balance is $330 million as of December 31, 2010
and $331 million as of December 31, 2009 and is
reported net of the related federal deferred tax liability. The
utilities’ regulatory asset balance is $383 million
and the regulatory liability balance is $418 million as of
December 31, 2010. The utilities’ regulatory asset
balance is $407 million and the regulatory liability
balance is $423 million as of December 31, 2009 and is
further discussed in Note 12.
| NOTE 14 — | COMMON STOCK |
Common
Stock
In March 2010, the Company contributed $100 million of DTE
Energy common stock to the DTE Energy Company Affiliates
Employee Benefit Plans Master Trust. The common stock was
contributed over four business days from March 26, 2010
through March 31, 2010 and was valued using the closing
market prices of DTE Energy common stock on each of those days
in accordance with fair value measurement and accounting
requirements.
Under the DTE Energy Company Long-Term Incentive Plan, the
Company grants non-vested stock awards to key employees,
primarily management. As a result of a stock award, a settlement
of an award of performance shares, or by exercise of a
participant’s stock option, the Company may deliver common
stock from the Company’s authorized but unissued common
stock
and/or
from outstanding common stock acquired by or on behalf of the
Company in the name of the participant.
Dividends
Certain of the Company’s credit facilities contain a
provision requiring the Company to maintain a total funded debt
to capitalization ratio, as defined in the agreements, of no
more than 0.65 to 1, which has the effect of limiting the amount
of dividends the Company can pay in order to maintain compliance
with this provision. See Note 18 for a definition of this
ratio. The effect of this provision as of December 31, 2010
was to restrict the payment of approximately $46 million of
total retained earnings of approximately $3.4 billion.
There are no other effective limitations with respect to the
Company’s ability to pay dividends.
| NOTE 15 — | EARNINGS PER SHARE |
The Company reports both basic and diluted earnings per share.
The calculation of diluted earnings per share assumes the
issuance of potentially dilutive common shares outstanding
during the period from the exercise of stock options. Effective
January 1, 2009, the adoption of new accounting
requirements clarifying the definition of participating
securities to be included in the earnings per share calculation
had the effect of reducing previously
104
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
reported 2008 amounts for basic and diluted earnings per share
by $.03 and $.02, respectively. A reconciliation of both
calculations is presented in the following table as of December
31:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions, expect per share amounts) | ||||||||||||
|
Basic Earnings per Share
|
||||||||||||
|
Net income attributable to DTE Energy Company
|
$ | 630 | $ | 532 | $ | 546 | ||||||
|
Average number of common shares outstanding
|
168 | 164 | 163 | |||||||||
|
Weighted average net restricted shares outstanding
|
1 | 1 | 1 | |||||||||
|
Dividends declared — common shares
|
$ | 365 | $ | 347 | $ | 344 | ||||||
|
Dividends declared — net restricted shares
|
2 | 2 | 2 | |||||||||
|
Total distributed earnings
|
$ | 367 | $ | 349 | $ | 346 | ||||||
|
Net income less distributed earnings
|
$ | 263 | $ | 183 | $ | 200 | ||||||
|
Distributed (dividends per common share)
|
$ | 2.18 | $ | 2.12 | $ | 2.12 | ||||||
|
Undistributed
|
1.57 | 1.12 | 1.22 | |||||||||
|
Total Basic Earnings per Common Share
|
$ | 3.75 | $ | 3.24 | $ | 3.34 | ||||||
|
Diluted Earnings per Share
|
||||||||||||
|
Net income attributable to DTE Energy Company
|
$ | 630 | $ | 532 | $ | 546 | ||||||
|
Average number of common shares outstanding
|
168 | 164 | 163 | |||||||||
|
Average incremental shares from assumed exercise of options
|
1 | — | — | |||||||||
|
Common shares for dilutive calculation
|
169 | 164 | 163 | |||||||||
|
Weighted average net restricted shares outstanding
|
1 | 1 | 1 | |||||||||
|
Dividends declared — common shares
|
$ | 365 | $ | 347 | $ | 344 | ||||||
|
Dividends declared — net restricted shares
|
2 | 2 | 2 | |||||||||
|
Total distributed earnings
|
$ | 367 | $ | 349 | $ | 346 | ||||||
|
Net income less distributed earnings
|
$ | 263 | $ | 183 | $ | 200 | ||||||
|
Distributed (dividends per common share)
|
$ | 2.18 | $ | 2.12 | $ | 2.12 | ||||||
|
Undistributed
|
1.56 | 1.12 | 1.22 | |||||||||
|
Total Diluted Earnings per Common Share
|
$ | 3.74 | $ | 3.24 | $ | 3.34 | ||||||
Options to purchase approximately 5 million shares,
4 million shares and 5 million shares of common stock
in 2010, 2009 and 2008, respectively, were not included in the
computation of diluted earnings per share because the
options’ exercise price was greater than the average market
price of the common shares, thus making these options
anti-dilutive.
105
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| NOTE 16 — |
|
Long-Term
Debt
The Company’s long-term debt outstanding and weighted
average interest rates (1) of debt outstanding at December
31 were:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Mortgage bonds, notes, and other
|
||||||||
|
DTE Energy Debt, Unsecured
|
||||||||
|
6.9% due 2011 to 2033
|
$ | 1,597 | $ | 1,597 | ||||
|
Detroit Edison Taxable Debt, Principally Secured
|
||||||||
|
5.5% due 2011 to 2038
|
2,915 | 2,829 | ||||||
|
Detroit Edison Tax-Exempt Revenue Bonds(2)
|
||||||||
|
5.5% due 2011 to 2038
|
1,283 | 1,263 | ||||||
|
MichCon Taxable Debt, Principally Secured
|
||||||||
|
6.1% due 2012 to 2033
|
889 | 889 | ||||||
|
Other Long-Term Debt, Including Non-Recourse Debt
|
195 | 180 | ||||||
| 6,879 | 6,758 | |||||||
|
Less amount due within one year
|
(765 | ) | (521 | ) | ||||
| $ | 6,114 | $ | 6,237 | |||||
|
Securitization bonds
|
||||||||
|
6.5% due 2011 to 2015
|
$ | 793 | $ | 933 | ||||
|
Less amount due within one year
|
(150 | ) | (140 | ) | ||||
| $ | 643 | $ | 793 | |||||
|
Trust preferred-linked securities
|
||||||||
|
7.8% due 2032
|
$ | 186 | $ | 186 | ||||
|
7.5% due 2044
|
103 | 103 | ||||||
| $ | 289 | $ | 289 | |||||
| (1) | Weighted average interest rates as of December 31, 2010 are shown below the description of each category of debt. | |
| (2) | Detroit Edison Tax-Exempt Revenue Bonds are issued by a public body that loans the proceeds to Detroit Edison on terms substantially mirroring the Revenue Bonds. |
106
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Debt
Issuances
In 2010, the Company issued the following long-term debt:
| Company | Month Issued | Type | Interest Rate | Maturity | Amount | |||||||||||
| (In millions) | ||||||||||||||||
|
Detroit Edison
|
August | Senior Notes(1) | 3.45 | % | 2020 | 300 | ||||||||||
|
Detroit Edison
|
September | Senior Notes(1)(2) | 4.89 | % | 2020 | 300 | ||||||||||
|
Detroit Edison
|
December | Tax-Exempt Revenue Bonds(3) | 5.00 | % | 2030 | 20 | ||||||||||
| $ | 620 | |||||||||||||||
| (1) | Proceeds were used to repay a portion of Detroit Edison’s $500 million 6.125% Senior Notes due October 1, 2010 and for general corporate purposes. | |
| (2) | These bonds were priced in March 2010 in a private placement transaction which was closed and funded in September 2010. | |
| (3) | Proceeds were used to finance the acquisition and construction of improvements to certain electrical generating facilities and pollution control equipment at Detroit Edison’s Monroe Power Plant. |
Debt
Retirements and Redemptions
In 2010, the following debt was retired:
| Company | Month Retired | Type | Interest Rate | Maturity | Amount | |||||||||||||||
| (In millions) | ||||||||||||||||||||
|
Detroit Edison
|
September | Senior Notes(1 | ) | 6.125 | % | 2010 | $ | 500 | ||||||||||||
| (1) | These Senior Notes, maturing October 1, 2010, were optionally redeemed on September 30, 2010. |
The following table shows the scheduled debt maturities,
excluding any unamortized discount or premium on debt:
|
2016 and
|
||||||||||||||||||||||||||||
| 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | ||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
|
Amount to mature
|
$ | 915 | $ | 520 | $ | 512 | $ | 861 | $ | 477 | $ | 4,685 | $ | 7,970 | ||||||||||||||
Trust Preferred-Linked
Securities
DTE Energy has interests in various unconsolidated trusts that
were formed for the sole purpose of issuing preferred securities
and lending the gross proceeds to the Company. The sole assets
of the trusts are debt securities of DTE Energy with terms
similar to those of the related preferred securities. Payments
the Company makes are used by the trusts to make cash
distributions on the preferred securities it has issued.
The Company has the right to extend interest payment periods on
the debt securities. Should the Company exercise this right, it
cannot declare or pay dividends on, or redeem, purchase or
acquire, any of its capital stock during the deferral period.
DTE Energy has issued certain guarantees with respect to
payments on the preferred securities. These guarantees, when
taken together with the Company’s obligations under the
debt securities and related indenture, provide full and
unconditional guarantees of the trusts’ obligations under
the preferred securities.
Financing costs for these issuances were paid for and deferred
by DTE Energy. These costs are being amortized using the
straight-line method over the estimated lives of the related
securities.
107
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Cross
Default Provisions
Substantially all of the net utility properties of Detroit
Edison and MichCon are subject to the lien of mortgages. Should
Detroit Edison or MichCon fail to timely pay their indebtedness
under these mortgages, such failure may create cross defaults in
the indebtedness of DTE Energy.
| NOTE 17 — | PREFERRED AND PREFERENCE SECURITIES |
As of December 31, 2010, the amount of authorized and
unissued stock is as follows:
|
Type of
|
Shares
|
|||||||||
| Company | Stock | Par Value | Authorized | |||||||
|
DTE Energy
|
Preferred | None | 5,000,000 | |||||||
|
Detroit Edison
|
Preferred | $ | 100 | 6,747,484 | ||||||
|
Detroit Edison
|
Preference | $ | 1 | 30,000,000 | ||||||
|
MichCon
|
Preferred | $ | 1 | 7,000,000 | ||||||
|
MichCon
|
Preference | $ | 1 | 4,000,000 | ||||||
| NOTE 18 — | SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS |
In August 2010, DTE Energy and its wholly owned subsidiaries,
Detroit Edison and MichCon, entered into amended and restated
two-year unsecured revolving credit agreements and new
three-year unsecured revolving credit agreements with a
syndicate of 23 banks that may be used for general corporate
borrowings, but are intended to provide liquidity support for
each of the companies’ commercial paper programs. No one
bank provides more than 8.25% of the commitment in any facility.
Borrowings under the facilities are available at prevailing
short-term interest rates. Additionally, DTE Energy has other
facilities to support letter of credit issuance.
The above agreements require the Company to maintain a total
funded debt to capitalization ratio of no more than 0.65 to 1.
In the agreements, “total funded debt” means all
indebtedness of the Company and its consolidated subsidiaries,
including capital lease obligations, hedge agreements and
guarantees of third parties’ debt, but excluding contingent
obligations, nonrecourse and junior subordinated debt and
certain equity-linked securities and, except for calculations at
the end of the second quarter, certain MichCon short-term debt.
“Capitalization” means the sum of (a) total
funded debt plus (b) “consolidated net worth,”
which is equal to consolidated total stockholders’ equity
of the Company and its consolidated subsidiaries (excluding
pension effects under certain FASB statements), as determined in
accordance with accounting principles generally accepted in the
United States of America. At December 31, 2010, the total
funded debt to total capitalization ratios for DTE Energy,
Detroit Edison and MichCon are 0.49 to 1, 0.52 to 1 and 0.46 to
1, respectively, and are in compliance with this financial
covenant. The availability under these combined facilities at
December 31, 2010 is shown in the following table:
| DTE Energy | Detroit Edison | MichCon | Total | |||||||||||||
| (In millions) | ||||||||||||||||
|
Unsecured revolving credit facility, expiring August 2012
|
$ | 538 | $ | 212 | $ | 250 | $ | 1,000 | ||||||||
|
Unsecured revolving credit facility, expiring August 2013
|
562 | 63 | 175 | 800 | ||||||||||||
|
Unsecured letter of credit facility, expiring in May 2013
|
50 | — | — | 50 | ||||||||||||
|
Unsecured letter of credit facility, expiring in August 2015
|
125 | — | — | 125 | ||||||||||||
|
Total credit facilities at December 31, 2010
|
$ | 1,275 | $ | 275 | $ | 425 | $ | 1,975 | ||||||||
|
Amounts outstanding at December 31, 2010:
|
||||||||||||||||
|
Commercial paper issuances
|
— | — | 150 | 150 | ||||||||||||
|
Letters of credit
|
153 | — | — | 153 | ||||||||||||
| 153 | — | 150 | 303 | |||||||||||||
|
Net availability at December 31, 2010
|
$ | 1,122 | $ | 275 | $ | 275 | $ | 1,672 | ||||||||
108
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
The Company has other outstanding letters of credit which are
not included in the above described facilities totaling
approximately $28 million which are used for various
corporate purposes.
The weighted average interest rate for short-term borrowings was
0.4% and 0.7% at December 31, 2010 and 2009, respectively.
In conjunction with maintaining certain exchange traded risk
management positions, the Company may be required to post cash
collateral with its clearing agent. The Company has a demand
financing agreement for up to $100 million with its
clearing agent. In April 2010, the agreement was amended to
allow for up to $50 million of additional margin financing
provided that the Company posts a letter of credit for the
incremental amount. At December 31, 2010, a
$10 million letter of credit was in place, raising capacity
under this facility for up to $110 million. The
$10 million letter of credit is included in the table
above. The amount outstanding under this agreement was
$39 million and $1 million at December 31, 2010
and December 31, 2009, respectively.
| NOTE 19 — | CAPITAL AND OPERATING LEASES |
Lessee
— The Company leases various assets
under capital and operating leases, including coal railcars,
office buildings, a warehouse, computers, vehicles and other
equipment. The lease arrangements expire at various dates
through 2031. Future minimum lease payments under non-cancelable
leases at December 31, 2010 were:
|
Capital
|
Operating
|
|||||||
| Leases | Leases | |||||||
| (In millions) | ||||||||
|
2011
|
$ | 12 | $ | 39 | ||||
|
2012
|
9 | 32 | ||||||
|
2013
|
9 | 26 | ||||||
|
2014
|
9 | 22 | ||||||
|
2015
|
9 | 18 | ||||||
|
Thereafter
|
14 | 74 | ||||||
|
Total minimum lease payments
|
$ | 62 | $ | 211 | ||||
|
Less imputed interest
|
9 | |||||||
|
Present value of net minimum lease payments
|
53 | |||||||
|
Less current portion
|
10 | |||||||
|
Non-current portion
|
$ | 43 | ||||||
Rental expense for operating leases was $54 million in
2010, $58 million in 2009, and $49 million in 2008.
109
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Lessor
— The Company leases a portion of its
pipeline system to the Vector Pipeline through a capital lease
contract that expires in 2020, with renewal options extending
for five years. The Company owns a 40% interest in the Vector
Pipeline. In addition, the Company has an energy services
agreement, a portion of which is accounted for as a capital
lease. The agreement expires in 2019, with a three or five year
renewal option. The components of the net investment in the
capital leases at December 31, 2010, were as follows:
| (In millions) | ||||
|
2011
|
$ | 12 | ||
|
2012
|
12 | |||
|
2013
|
12 | |||
|
2014
|
12 | |||
|
2015
|
12 | |||
|
Thereafter
|
56 | |||
|
Total minimum future lease receipts
|
116 | |||
|
Residual value of leased pipeline
|
40 | |||
|
Less unearned income
|
(64 | ) | ||
|
Net investment in capital lease
|
92 | |||
|
Less current portion
|
(4 | ) | ||
| $ | 88 | |||
| NOTE 20 — | COMMITMENTS AND CONTINGENCIES |
Environmental
Electric
Utility
Air
— Detroit Edison is subject to the EPA
ozone transport and acid rain regulations that limit power plant
emissions of sulfur dioxide and nitrogen oxides. Since 2005, the
EPA and the State of Michigan have issued additional emission
reduction regulations relating to ozone, fine particulate,
regional haze and mercury air pollution. The new rules will lead
to additional controls on fossil-fueled power plants to reduce
nitrogen oxide, sulfur dioxide and mercury emissions. To comply
with these requirements, Detroit Edison has spent approximately
$1.5 billion through 2010. The Company estimates Detroit
Edison will make capital expenditures of over $230 million
in 2011 and up to $2.1 billion of additional capital
expenditures through 2020 based on current regulations. Further,
additional rulemakings are expected over the next few years
which could require additional controls for sulfur dioxide,
nitrogen oxides and hazardous air pollutants. It is not possible
to quantify the impact of those expected rulemakings at this
time.
In July 2009, DTE Energy received a Notice of Violation/Finding
of Violation (NOV/FOV) from the EPA alleging, among other
things, that five of Detroit Edison’s power plants violated
New Source Performance standards, Prevention of Significant
Deterioration requirements, and operating permit requirements
under the Clean Air Act. In June 2010, the EPA issued a NOV/FOV
making similar allegations related to a recent project and
outage at Unit 2 of the Monroe Power Plant.
On August 5, 2010, the United States Department of Justice,
at the request of the EPA, brought a civil suit in the
U.S. District Court for the Eastern District of Michigan
against DTE Energy and Detroit Edison, related to the June 2010
NOV/FOV and the outage work performed at Unit 2 of the Monroe
Power Plant, but not relating to the July 2009 NOV/FOV. Among
other relief, the EPA is requesting the court to require Detroit
Edison to install and operate the best available control
technology at Unit 2 of the Monroe Power Plant. Further, the EPA
is requesting the court to issue a preliminary injunction to
require Detroit Edison to (i) begin the process of
obtaining the necessary permits
110
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
for the Monroe Unit 2 modification and (ii) offset the
pollution from Monroe Unit 2 through emissions reductions from
Detroit Edison’s fleet of coal-fired power plants until the
new control equipment is operating. In January 2011, the
EPA’s motion for preliminary injunction was denied and the
liability phase of the civil suit has been scheduled for trial
in May 2011.
DTE Energy and Detroit Edison believe that the plants identified
by the EPA, including Unit 2 of the Monroe Power Plant, have
complied with all applicable federal environmental regulations.
Depending upon the outcome of discussions with the EPA regarding
the NOV/FOV and the result of the civil action, Detroit Edison
could also be required to install additional pollution control
equipment at some or all of the power plants in question,
implement early retirement of facilities where control equipment
is not economical, engage in supplemental environmental
programs,
and/or
pay
fines. DTE Energy and Detroit Edison cannot predict the
financial impact or outcome of this matter, or the timing of its
resolution.
Water
— In response to an EPA regulation,
Detroit Edison is required to examine alternatives for reducing
the environmental impacts of the cooling water intake structures
at several of its facilities. Based on the results of completed
studies and expected future studies, Detroit Edison may be
required to install additional control technologies to reduce
the impacts of the water intakes. Initially, it was estimated
that Detroit Edison could incur up to approximately
$55 million in additional capital expenditures over the
four to six years subsequent to 2008 to comply with these
requirements. However, a January 2007 circuit court decision
remanded back to the EPA several provisions of the federal
regulation that has resulted in a delay in compliance dates. The
decision also raised the possibility that Detroit Edison may
have to install cooling towers at some facilities at a cost
substantially greater than was initially estimated for other
mitigative technologies. In 2008, the Supreme Court agreed to
review the remanded cost-benefit analysis provision of the rule
and in April 2009 upheld the EPA’s use of this provision in
determining best technology available for reducing environmental
impacts. Concurrently, the EPA continues to develop a revised
rule, a draft of which is expected to be published in the first
quarter of 2011, with a final rule scheduled for mid-2012. The
EPA has also issued an information collection request to begin a
review of steam electric effluent guidelines. It is not possible
at this time to quantify the impacts of these developing
requirements.
Contaminated Sites
— Prior to the construction
of major interstate natural gas pipelines, gas for heating and
other uses was manufactured locally from processes involving
coal, coke or oil. The facilities, which produced gas, have been
designated as manufactured gas plant (MGP) sites. Detroit Edison
conducted remedial investigations at contaminated sites,
including three former MGP sites. The investigations have
revealed contamination related to the by-products of gas
manufacturing at each site. In addition to the MGP sites, the
Company is also in the process of cleaning up other contaminated
sites, including the area surrounding an ash landfill,
electrical distribution substations, and underground and
aboveground storage tank locations. The findings of these
investigations indicated that the estimated cost to remediate
these sites is expected to be incurred over the next several
years. At December 31, 2010 and December 31, 2009, the
Company had $9 million accrued for remediation. Any
significant change in assumptions, such as remediation
techniques, nature and extent of contamination and regulatory
requirements, could impact the estimate of remedial action costs
for the sites and affect the Company’s financial position
and cash flows.
Landfill
— Detroit Edison owns and operates a
permitted engineered ash storage facility at the Monroe Power
Plant to dispose of fly ash from the coal fired power plant.
Detroit Edison performed an engineering analysis in 2009 and
identified the need for embankment side slope repairs and
reconstruction.
The EPA has published proposed rules to regulate coal ash under
the authority of the Resources Conservation and Recovery Act
(RCRA). The proposed rule published on June 21, 2010
contains two primary regulatory options to regulate coal ash
residue. The EPA is currently considering either designating
coal ash as a “Hazardous Waste” as defined by RCRA or
regulating coal ash as non-hazardous waste under RCRA. Agencies
and legislatures have urged the EPA to regulate coal ash as a
non-hazardous waste. If the EPA designates coal ash as a
hazardous waste, the agency could apply some, or all, of the
disposal and reuse standards that have been applied to other
existing hazardous wastes to disposal and reuse of coal ash.
Some of the regulatory actions currently being contemplated
111
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
could have a significant impact on our operations and financial
position and the rates we charge our customers. It is not
possible to quantify the impact of those expected rulemakings at
this time.
Gas
Utility
Contaminated Sites
— Gas Utility owns, or
previously owned, 15 former MGP sites. Investigations have
revealed contamination related to the by-products of gas
manufacturing at each site. In addition to the MGP sites, the
Company is also in the process of cleaning up other contaminated
sites. Cleanup activities associated with these sites will be
conducted over the next several years.
The MPSC has established a cost deferral and rate recovery
mechanism for investigation and remediation costs incurred at
former MGP sites. Accordingly, Gas Utility recognizes a
liability and corresponding regulatory asset for estimated
investigation and remediation costs at former MGP sites. As of
December 31, 2010 and December 31, 2009, the Company
had $36 million, accrued for remediation.
Any significant change in assumptions, such as remediation
techniques, nature and extent of contamination and regulatory
requirements, could impact the estimate of remedial action costs
for the sites and affect the Company’s financial position
and cash flows. The Company anticipates the cost amortization
methodology approved by the MPSC for MichCon, which allows
MichCon to amortize the MGP costs over a ten-year period
beginning with the year subsequent to the year the MGP costs
were incurred, and the cost deferral and rate recovery mechanism
for Citizens Fuel Gas approved by the City of Adrian, will
prevent environmental costs from having a material adverse
impact on the Company’s results of operations.
Non-Utility
The Company’s non-utility affiliates are subject to a
number of environmental laws and regulations dealing with the
protection of the environment from various pollutants.
The Michigan coke battery facility received and responded to
information requests from the EPA that resulted in the issuance
of a Notice of Violation in June of 2007 alleging potential
maximum achievable control technologies and new source review
violations. The EPA is in the process of reviewing the
Company’s position of demonstrated compliance and has not
initiated escalated enforcement. At this time, the Company
cannot predict the impact of this issue. Furthermore, the
Michigan coke battery facility is the subject of an
investigation by the MDNRE concerning visible emissions readings
that resulted from the Company self reporting to MDNRE
questionable activities by an employee of a contractor hired by
the Company to perform the visible emissions readings. At this
time, the Company cannot predict the impact of this
investigation.
The Company is also in the process of settling historical air
and water violations at its coke battery facility located in
Pennsylvania. At this time, the Company cannot predict the
impact of this settlement. The Company received two notices of
violation from the Pennsylvania Department of Environmental
Protection in 2010 alleging violations of the permit for the
Pennsylvania coke battery facility in connection with coal pile
storm water runoff. The Company has implemented best management
practices to address this issue and is currently seeking a
permit from the Pennsylvania Department of Environmental
Protection to upgrade its wastewater treatment technology to a
biological treatment facility. The Company expects to spend
approximately $0.7 million on the existing waste water
treatment system to comply with existing water discharge
requirements. The Company may spend an additional
$13 million over the next few years to meet future
regulatory requirements and gain other operational improvements
savings. The Company’s non-utility affiliates are
substantially in compliance with all environmental requirements,
other than as noted above.
112
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Other
In February 2008, DTE Energy was named as one of approximately
24 defendant oil, power and coal companies in a lawsuit filed in
a United States District Court. DTE Energy was served with
process in March 2008. The plaintiffs, the Native Village of
Kivalina and City of Kivalina, which are home to approximately
400 people in Alaska, claim that the defendants’
business activities have contributed to global warming and, as a
result, higher temperatures are damaging the local economy and
leaving the island more vulnerable to storm activity in the fall
and winter. As a result, the plaintiffs are seeking damages of
up to $400 million for relocation costs associated with
moving the village to a safer location, as well as unspecified
attorney’s fees and expenses. On October 15, 2009, the
U.S. District Court granted defendants’ motions
dismissing all of plaintiffs’ federal claims in the case on
two independent grounds: (1) the court lacks subject matter
jurisdiction to hear the claims because of the political
question doctrine; and (2) plaintiffs lack standing to
bring their claims. The court also dismissed plaintiffs’
state law claims because the court lacked supplemental
jurisdiction over them after it dismissed the federal claims;
the dismissal of the state law claims was without prejudice. The
plaintiffs have appealed to the U.S. Court of Appeals for
the Ninth Circuit.
Nuclear
Operations
Property
Insurance
Detroit Edison maintains property insurance policies
specifically for the Fermi 2 plant. These policies cover such
items as replacement power and property damage. The Nuclear
Electric Insurance Limited (NEIL) is the primary supplier of the
insurance policies.
Detroit Edison maintains a policy for extra expenses, including
replacement power costs necessitated by Fermi 2’s
unavailability due to an insured event. This policy has a
12-week waiting period and provides an aggregate
$490 million of coverage over a three-year period.
Detroit Edison has $500 million in primary coverage and
$2.25 billion of excess coverage for stabilization,
decontamination, debris removal, repair
and/or
replacement of property and decommissioning. The combined
coverage limit for total property damage is $2.75 billion.
In 2007, the Terrorism Risk Insurance Extension Act of 2005
(TRIA) was extended through December 31, 2014. A major
change in the extension is the inclusion of “domestic”
acts of terrorism in the definition of covered or
“certified” acts. For multiple terrorism losses caused
by acts of terrorism not covered under the TRIA occurring within
one year after the first loss from terrorism, the NEIL policies
would make available to all insured entities up to
$3.2 billion, plus any amounts recovered from reinsurance,
government indemnity, or other sources to cover losses.
Under the NEIL policies, Detroit Edison could be liable for
maximum assessments of up to approximately $28 million per
event if the loss associated with any one event at any nuclear
plant in the United States should exceed the accumulated funds
available to NEIL.
Public
Liability Insurance
As of January 1, 2011, as required by federal law, Detroit
Edison maintains $375 million of public liability insurance
for a nuclear incident. For liabilities arising from a terrorist
act outside the scope of TRIA, the policy is subject to one
industry aggregate limit of $300 million. Further, under
the Price-Anderson Amendments Act of 2005, deferred premium
charges up to $117.5 million could be levied against each
licensed nuclear facility, but not more than $17.5 million
per year per facility. Thus, deferred premium charges could be
levied against all owners of licensed nuclear facilities in the
event of a nuclear incident at any of these facilities.
113
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Nuclear
Fuel Disposal Costs
In accordance with the Federal Nuclear Waste Policy Act of 1982,
Detroit Edison has a contract with the U.S. Department of
Energy (DOE) for the future storage and disposal of spent
nuclear fuel from Fermi 2. Detroit Edison is obligated to pay
the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated
and sold. The fee is accounted as a component of nuclear fuel
expense. Delays have occurred in the DOE’s program for the
acceptance and disposal of spent nuclear fuel at a permanent
repository and the proposed fiscal year 2011 federal budget
recommends termination of funding for completion of the
government’s long-term storage facility. Detroit Edison is
a party in the litigation against the DOE for both past and
future costs associated with the DOE’s failure to accept
spent nuclear fuel under the timetable set forth in the Federal
Nuclear Waste Policy Act of 1982. Detroit Edison currently
employs a spent nuclear fuel storage strategy utilizing a fuel
pool. In 2011, the Company expects to begin loading spent
nuclear fuel into an
on-site
dry
cask storage facility which is expected to provide sufficient
storage capability for the life of the plant as defined by the
original operating license. Issues relating to long-term waste
disposal policy and to the disposition of funds contributed by
Detroit Edison ratepayers to the federal waste fund await future
governmental action.
Guarantees
In certain limited circumstances, the Company enters into
contractual guarantees. The Company may guarantee another
entity’s obligation in the event it fails to perform. The
Company may provide guarantees in certain indemnification
agreements. Finally, the Company may provide indirect guarantees
for the indebtedness of others.
In connection with the November 2010 sale of the steam heating
business by Thermal Ventures II, L.P. an $11 million bank
term loan was repaid and the guarantee by Detroit Edison was
released. In addition, Detroit Edison made a new $6 million
secured senior term loan to the new entity. The Company has
reserved the entire amount of the term loan.
The Company’s remaining guarantees are not individually
material with maximum potential payments totaling
$10 million at December 31, 2010.
The Company is periodically required to obtain performance
surety bonds in support of obligations to various governmental
entities and other companies in connection with its operations.
As of December 31, 2010, the Company had approximately
$14 million of performance bonds outstanding. In the event
that such bonds are called for nonperformance, the Company would
be obligated to reimburse the issuer of the performance bond.
The Company is released from the performance bonds as the
contractual performance is completed and does not believe that a
material amount of any currently outstanding performance bonds
will be called.
Millennium
Pipeline Project
The Company owns a 26 percent equity interest in the
Millennium Pipeline Project (Millennium). Millennium is
accounted for under the equity method. On August 26, 2010,
Millennium closed on a $725 million long-term financing
that is non-recourse to the Company. The proceeds thereof, along
with equity contributions from the project sponsors, repaid in
full Millennium’s $800 million construction loan and
settled certain forward-starting interest rate swaps related to
the new long-term financing. The Company’s share of the
equity contribution was $49 million. The project
partners’ guarantee of the $800 million construction
loan and forward-starting interest rate swaps was terminated
upon closing of the long-term financing. The project sponsors
have agreed to provide credit support to Millennium’s debt
service reserve requirement. The Company’s share of the
credit support is $9 million and is being satisfied with a
letter of credit in favor of the Trustee of the long-term bond
holders.
114
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Labor
Contracts
There are several bargaining units for the Company’s
approximately 5,000 represented employees. In the 2010 third
quarter, a new three-year agreement was ratified covering
approximately 3,800 represented employees. The majority of the
remaining represented employees are under contracts that expire
in June 2011 and August 2012.
Purchase
Commitments
As of December 31, 2010, the Company was party to numerous
long-term purchase commitments relating to a variety of goods
and services required for the Company’s business. These
agreements primarily consist of fuel supply commitments and
energy trading contracts. The Company estimates that these
commitments will be approximately $6 billion from 2011
through 2051 as detailed in the following table:
| (In millions) | ||||
|
2011
|
$ | 2,175 | ||
|
2012
|
1,085 | |||
|
2013
|
585 | |||
|
2014
|
471 | |||
|
2015
|
273 | |||
|
2016 — 2051
|
1,332 | |||
| $ | 5,921 | |||
The Company also estimates that 2011 capital expenditures will
be approximately $1.4 billion. The Company has made certain
commitments in connection with expected capital expenditures.
Bankruptcies
The Company purchases and sells electricity, gas, coal, coke and
other energy products from and to numerous companies operating
in the steel, automotive, energy, retail, financial and other
industries. Certain of its customers have filed for bankruptcy
protection under Chapter 11 of the U.S. Bankruptcy
Code. The Company regularly reviews contingent matters relating
to these customers and its purchase and sale contracts and
records provisions for amounts considered at risk of probable
loss. The Company believes its accrued amounts are adequate for
probable loss. The final resolution of these matters may have a
material effect on its consolidated financial statements.
Other
Contingencies
The Company is involved in certain other legal, regulatory,
administrative and environmental proceedings before various
courts, arbitration panels and governmental agencies concerning
claims arising in the ordinary course of business. These
proceedings include certain contract disputes, additional
environmental reviews and investigations, audits, inquiries from
various regulators, and pending judicial matters. The Company
cannot predict the final disposition of such proceedings. The
Company regularly reviews legal matters and records provisions
for claims that it can estimate and are considered probable of
loss. The resolution of these pending proceedings is not
expected to have a material effect on the Company’s
operations or financial statements in the periods they are
resolved.
See Notes 5 and 12 for a discussion of contingencies
related to derivatives and regulatory matters.
| NOTE 21 — | RETIREMENT BENEFITS AND TRUSTEED ASSETS |
Measurement
Date
In 2008, we changed the measurement date of our pension and
postretirement benefit plans from November 30 to
December 31. As a result, we recognized adjustments of
$17 million ($9 million after-tax) and $4 million
to
115
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
retained earnings and regulatory liabilities, respectively,
which represents approximately one month of pension and other
postretirement benefit costs for the period from
December 1, 2007 to December 31, 2008.
Pension
Plan Benefits
The Company has qualified defined benefit retirement plans for
eligible represented and non-represented employees. The plans
are noncontributory and cover substantially all employees. The
plans provide traditional retirement benefits based on the
employees’ years of benefit service, average final
compensation and age at retirement. In addition, certain
represented and non-represented employees are covered under cash
balance provisions that determine benefits on annual employer
contributions and interest credits. The Company also maintains
supplemental nonqualified, noncontributory, retirement benefit
plans for selected management employees. These plans provide for
benefits that supplement those provided by DTE Energy’s
other retirement plans.
The Company’s policy is to fund pension costs by
contributing amounts consistent with the Pension Protection Act
of 2006 provisions and additional amounts when it deems
appropriate. The Company contributed $200 million to its
pension plans in 2010, including a contribution of DTE Energy
stock of $100 million (consisting of approximately
2.2 million shares valued at an average price of $44.97 per
share). In January 2011, the Company contributed
$200 million to its pension plans.
Net pension cost includes the following components:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Service cost
|
$ | 64 | $ | 52 | $ | 55 | ||||||
|
Interest cost
|
202 | 203 | 190 | |||||||||
|
Expected return on plan assets
|
(258 | ) | (255 | ) | (259 | ) | ||||||
|
Amortization of:
|
||||||||||||
|
Net actuarial loss
|
100 | 52 | 32 | |||||||||
|
Prior service cost
|
4 | 6 | 6 | |||||||||
|
Net pension cost
|
$ | 112 | $ | 58 | $ | 24 | ||||||
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Other changes in plan assets and benefit obligations
recognized in other comprehensive income and regulatory
assets
|
||||||||
|
Net actuarial loss
|
$ | 166 | $ | 216 | ||||
|
Amortization of net actuarial loss
|
(100 | ) | (52 | ) | ||||
|
Amortization of prior service cost
|
(4 | ) | (6 | ) | ||||
|
Total recognized in other comprehensive income and regulatory
assets
|
$ | 62 | $ | 158 | ||||
|
Total recognized in net periodic pension cost, Other
comprehensive income and regulatory assets
|
$ | 174 | $ | 216 | ||||
|
Estimated amounts to be amortized from accumulated other
comprehensive income and regulatory assets into net periodic
benefit cost during next fiscal year
|
||||||||
|
Net actuarial loss
|
$ | 133 | $ | 100 | ||||
|
Prior service cost
|
3 | 4 | ||||||
116
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
The following table reconciles the obligations, assets and
funded status of the plans as well as the amounts recognized as
prepaid pension cost or pension liability in the Consolidated
Statements of Financial Position at December 31:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Accumulated benefit obligation, end of year
|
$ | 3,521 | $ | 3,193 | ||||
|
Change in projected benefit obligation
|
||||||||
|
Projected benefit obligation, beginning of year
|
$ | 3,436 | $ | 3,032 | ||||
|
Consolidation of VIEs
|
82 | — | ||||||
|
Service cost
|
64 | 52 | ||||||
|
Interest cost
|
202 | 203 | ||||||
|
Actuarial loss
|
216 | 351 | ||||||
|
Benefits paid
|
(215 | ) | (202 | ) | ||||
|
Projected benefit obligation, end of year
|
$ | 3,785 | $ | 3,436 | ||||
|
Change in plan assets
|
||||||||
|
Plan assets at fair value, beginning of year
|
$ | 2,549 | $ | 2,155 | ||||
|
Consolidation of VIEs
|
64 | — | ||||||
|
Actual return on plan assets
|
309 | 390 | ||||||
|
Company contributions
|
206 | 206 | ||||||
|
Benefits paid
|
(215 | ) | (202 | ) | ||||
|
Plan assets at fair value, end of year
|
$ | 2,913 | $ | 2,549 | ||||
|
Funded status of the plans
|
$ | (872 | ) | $ | (887 | ) | ||
|
Amount recorded as:
|
||||||||
|
Current liabilities
|
$ | (6 | ) | $ | (6 | ) | ||
|
Noncurrent liabilities
|
(866 | ) | (881 | ) | ||||
| $ | (872 | ) | $ | (887 | ) | |||
|
Amounts recognized in Accumulated other comprehensive loss,
pre-tax
|
||||||||
|
Net actuarial loss
|
$ | 195 | $ | 196 | ||||
|
Prior service (credit)
|
(4 | ) | (5 | ) | ||||
| $ | 191 | $ | 191 | |||||
|
Amounts recognized in regulatory assets (see Note 12)
|
||||||||
|
Net actuarial loss
|
$ | 1,730 | $ | 1,653 | ||||
|
Prior service cost
|
12 | 17 | ||||||
| $ | 1,742 | $ | 1,670 | |||||
117
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Assumptions used in determining the projected benefit obligation
and net pension costs are listed below:
| 2010 | 2009 | 2008 | ||||||||||
|
Projected benefit obligation
|
||||||||||||
|
Discount rate
|
5.50 | % | 5.90 | % | 6.90 | % | ||||||
|
Rate of compensation increase
|
4.00 | % | 4.00 | % | 4.00 | % | ||||||
|
Net pension costs
|
||||||||||||
|
Discount rate
|
5.90 | % | 6.90 | % | 6.50 | % | ||||||
|
Rate of compensation increase
|
4.00 | % | 4.00 | % | 4.00 | % | ||||||
|
Expected long-term rate of return on plan assets
|
8.75 | % | 8.75 | % | 8.75 | % | ||||||
The Company employs a formal process in determining the
long-term rate of return for various asset classes. Management
reviews historic financial market risks and returns and
long-term historic relationships between the asset classes of
equities, fixed income and other assets, consistent with the
widely accepted capital market principle that asset classes with
higher volatility generate a greater return over the long-term.
Current market factors such as inflation, interest rates, asset
class risks and asset class returns are evaluated and considered
before long-term capital market assumptions are determined. The
long-term portfolio return is also established employing a
consistent formal process, with due consideration of
diversification, active investment management and rebalancing.
Peer data is reviewed to check for reasonableness. The long-term
portfolio return is also established employing a consistent
formal process, with due consideration of diversification,
active investment and rebalancing. As a result of this process,
the Company is lowering its long-term rate of return assumptions
for its pension plans to 8.50% for 2011. The Company believes
this rate is a reasonable assumption for the long-term rate of
return on its plan assets for 2011 given its investment strategy.
At December 31, 2010, the benefits related to the
Company’s qualified and nonqualified pension plans expected
to be paid in each of the next five years and in the aggregate
for the five fiscal years thereafter are as follows:
| (In millions) | ||||
|
2011
|
$ | 217 | ||
|
2012
|
226 | |||
|
2013
|
231 | |||
|
2014
|
235 | |||
|
2015
|
244 | |||
|
2016 — 2020
|
1,343 | |||
| $ | 2,496 | |||
The Company employs a total return investment approach whereby a
mix of equities, fixed income and other investments are used to
maximize the long-term return on plan assets consistent with
prudent levels of risk, with consideration given to the
liquidity needs of the plan. The intent of this strategy is to
minimize plan expenses over the long-term. Risk tolerance is
established through consideration of future plan cash flows,
plan funded status, and corporate financial considerations. The
investment portfolio contains a diversified blend of equity,
fixed income and other investments. Furthermore, equity
investments are diversified across U.S. and
non-U.S. stocks,
growth and value investment styles, and large and small market
capitalizations. Fixed income securities generally include
corporate bonds of companies from diversified industries,
mortgage-backed securities, and U.S. Treasuries. Other
assets such as private equity and hedge funds are used to
enhance long-term returns while improving portfolio
diversification. Derivatives may be utilized in a risk
controlled manner, to potentially increase the portfolio beyond
the market value of invested assets and reduce portfolio
investment risk. Investment risk is measured and monitored
118
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
on an ongoing basis through annual liability measurements,
periodic asset/liability studies, and quarterly investment
portfolio reviews.
Target allocations for plan assets as of December 31, 2010
are listed below:
|
U.S. Large Cap Equity Securities
|
22 | % | ||
|
U.S. Small Cap and Mid Cap Equity Securities
|
5 | |||
|
Non U.S. Equity Securities
|
20 | |||
|
Fixed Income Securities
|
25 | |||
|
Hedge Funds and Similar Investments
|
20 | |||
|
Private Equity and Other
|
8 | |||
| 100 | % |
Fair
Value Measurements at December 31, 2010(a)
|
Balance at
|
||||||||||||||||
|
December 31,
|
||||||||||||||||
| Level 1 | Level 2 | Level 3 | 2010 | |||||||||||||
| (In millions) | ||||||||||||||||
|
Asset Category:
|
||||||||||||||||
|
Short-term investments(b)
|
$ | — | $ | 34 | $ | — | $ | 34 | ||||||||
|
Equity securities
|
||||||||||||||||
|
U.S. Large Cap(c)
|
686 | 38 | — | 724 | ||||||||||||
|
U.S. Small/Mid Cap(d)
|
181 | 8 | — | 189 | ||||||||||||
|
Non U.S(e)
|
285 | 222 | — | 507 | ||||||||||||
|
Fixed income securities(f)
|
61 | 658 | — | 719 | ||||||||||||
|
Other types of investments
|
||||||||||||||||
|
Hedge Funds and Similar Investments(g)
|
189 | 73 | 304 | 566 | ||||||||||||
|
Private Equity and Other(h)
|
— | — | 174 | 174 | ||||||||||||
|
Total
|
$ | 1,402 | $ | 1,033 | $ | 478 | $ | 2,913 | ||||||||
119
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Fair
Value Measurements at December 31, 2009(a)
|
Balance at
|
||||||||||||||||
|
December 31,
|
||||||||||||||||
| Level 1 | Level 2 | Level 3 | 2009 | |||||||||||||
| (In millions) | ||||||||||||||||
|
Asset Category:
|
||||||||||||||||
|
Short-term investments(b)
|
$ | — | $ | 63 | $ | — | $ | 63 | ||||||||
|
Equity securities
|
||||||||||||||||
|
U.S. Large Cap(c)
|
659 | 30 | — | 689 | ||||||||||||
|
U.S. Small/Mid Cap(d)
|
153 | 3 | — | 156 | ||||||||||||
|
Non U.S(e)
|
231 | 120 | — | 351 | ||||||||||||
|
Fixed income securities(f)
|
47 | 599 | — | 646 | ||||||||||||
|
Other types of investments
|
||||||||||||||||
|
Hedge Funds and Similar Investments(g)
|
— | — | 484 | 484 | ||||||||||||
|
Private Equity and Other(h)
|
— | — | 160 | 160 | ||||||||||||
|
Total
|
$ | 1,090 | $ | 815 | $ | 644 | $ | 2,549 | ||||||||
| (a) | See Note 4 — Fair Value for a description of levels within the fair value hierarchy. | |
| (b) | This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services. | |
| (c) | This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets. | |
| (d) | This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets. | |
| (e) | This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets. | |
| (f) | This category includes corporate bonds from diversified industries, U.S. Treasuries, and mortgage backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets. | |
| (g) | This category includes a diversified group of funds and strategies that attempt to capture financial market inefficiencies. In 2009, pricing for investments in this category was based on limited observable inputs as there was little, if any, publicly available pricing. Valuations for assets in this category may be based on relevant publicly-traded securities, derivatives, and privately-traded securities. In 2010, pricing for investments in this category included quoted prices in active markets and quotations from broker or pricing services. Non-exchanged traded securities held in commingled funds are classified as Level 2 assets. | |
| (h) | This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relative publicly-traded comparables and comparable transactions. |
120
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
The pension trust holds debt and equity securities directly and
indirectly through commingled funds and institutional mutual
funds. Exchange-traded debt and equity securities held directly
are valued using quoted market prices in actively traded
markets. The commingled funds and institutional mutual funds
which hold exchange-traded equity or debt securities are valued
based on underlying securities, using quoted prices in actively
traded markets. Non-exchange traded fixed income securities are
valued by the trustee based upon quotations available from
brokers or pricing services. A primary price source is
identified by asset type, class or issue for each security. The
trustees monitor prices supplied by pricing services and may use
a supplemental price source or change the primary price source
of a given security if the trustees challenge an assigned price
and determine that another price source is considered to be
preferable. DTE Energy has obtained an understanding of how
these prices are derived, including the nature and observability
of the inputs used in deriving such prices. Additionally, DTE
Energy selectively corroborates the fair values of securities by
comparison of market-based price sources.
Fair
Value Measurements Using Significant Unobservable Inputs
(Level 3):
|
Hedge Funds
|
||||||||||||
|
and Similar
|
Private Equity
|
|||||||||||
| Investments | and Other | Total | ||||||||||
| (In millions) | ||||||||||||
|
Beginning Balance at January 1, 2010
|
$ | 484 | $ | 160 | $ | 644 | ||||||
|
Total realized/unrealized gains (losses)
|
51 | 23 | 74 | |||||||||
|
Purchases, sales and settlements
|
(231 | ) | (9 | ) | (240 | ) | ||||||
|
Ending Balance at December 31, 2010
|
$ | 304 | $ | 174 | $ | 478 | ||||||
|
The amount of total gains (losses) for the period attributable
to the change in unrealized gains or losses related to assets
still held at the end of the period
|
$ | 29 | $ | 13 | $ | 42 | ||||||
|
Hedge Funds
|
||||||||||||
|
and Similar
|
Private Equity
|
|||||||||||
| Investments | and Other | Total | ||||||||||
| (In millions) | ||||||||||||
|
Beginning Balance at January 1, 2009
|
$ | 468 | $ | 159 | $ | 627 | ||||||
|
Total realized/unrealized gains (losses)
|
31 | (11 | ) | 20 | ||||||||
|
Purchases, sales and settlements
|
(15 | ) | 12 | (3 | ) | |||||||
|
Ending Balance at December 31, 2009
|
$ | 484 | $ | 160 | $ | 644 | ||||||
|
The amount of total gains (losses) for the period attributable
to the change in unrealized gains or losses related to assets
still held at the end of the period
|
$ | 34 | $ | (10 | ) | $ | 24 | |||||
The Company also sponsors defined contribution retirement
savings plans. Participation in one of these plans is available
to substantially all represented and non-represented employees.
The Company matches employee contributions up to certain
predefined limits based upon eligible compensation, the
employee’s contribution rate and, in some cases, years of
credited service. The cost of these plans was $34 million,
$33 million, and $33 million in each of the years
2010, 2009, and 2008, respectively.
Other
Postretirement Benefits
The Company provides certain postretirement health care and life
insurance benefits for employees who are eligible for these
benefits. The Company’s policy is to fund certain trusts to
meet its postretirement benefit obligations. Separate qualified
Voluntary Employees Beneficiary Association (VEBA) and 401(h)
trusts exist for
121
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
represented and non-represented employees. The Company
contributed $160 million to its postretirement medical and
life insurance benefit plans during 2010, including a transfer
of $25 million from the MichCon Grantor Trust.
In January 2011, the Company contributed $81 million to its
other postretirement benefit plans. At the discretion of
management, the Company may make up to an additional
$90 million contribution to its VEBA trusts through the
remainder of 2011.
Net postretirement cost includes the following components:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Service cost
|
$ | 61 | $ | 59 | $ | 62 | ||||||
|
Interest cost
|
125 | 133 | 121 | |||||||||
|
Expected return on plan assets
|
(74 | ) | (55 | ) | (75 | ) | ||||||
|
Amortization of:
|
||||||||||||
|
Net loss
|
54 | 72 | 38 | |||||||||
|
Prior service (credit)
|
(4 | ) | (6 | ) | (6 | ) | ||||||
|
Net transition obligation
|
2 | 2 | 2 | |||||||||
|
Net postretirement cost
|
$ | 164 | $ | 205 | $ | 142 | ||||||
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Other changes in plan assets and APBO recognized in other
comprehensive income and regulatory assets
|
||||||||
|
Net actuarial loss (gain)
|
$ | 93 | $ | (59 | ) | |||
|
Amortization of net actuarial loss
|
(54 | ) | (72 | ) | ||||
|
Prior service cost (credit)
|
(79 | ) | — | |||||
|
Amortization of prior service credit
|
4 | 6 | ||||||
|
Amortization of transition (asset)
|
(2 | ) | (2 | ) | ||||
|
Total recognized in other comprehensive income and regulatory
assets
|
$ | (38 | ) | $ | (127 | ) | ||
|
Total recognized in net periodic pension cost, other
comprehensive income and regulatory assets
|
$ | 126 | $ | 78 | ||||
| 2010 | 2009 | |||||||
|
Estimated amounts to be amortized from accumulated other
comprehensive income and regulatory assets into net periodic
benefit cost during next fiscal year
|
||||||||
|
Net actuarial loss
|
$ | 59 | $ | 53 | ||||
|
Prior service (credit)
|
$ | (26 | ) | $ | (3 | ) | ||
|
Net transition obligation
|
$ | 2 | $ | 2 | ||||
122
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
The following table reconciles the obligations, assets and
funded status of the plans including amounts recorded as accrued
postretirement cost in the Consolidated Statements of Financial
Position at December 31:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
|
Change in accumulated postretirement benefit obligation
|
||||||||
|
Accumulated postretirement benefit obligation, beginning of year
|
$ | 2,151 | $ | 2,032 | ||||
|
Consolidation of VIEs
|
21 | — | ||||||
|
Service cost
|
61 | 59 | ||||||
|
Interest cost
|
125 | 133 | ||||||
|
Plan amendments
|
(79 | ) | — | |||||
|
Actuarial loss
|
127 | 22 | ||||||
|
Medicare Part D subsidy
|
7 | 6 | ||||||
|
Benefits paid
|
(108 | ) | (101 | ) | ||||
|
Accumulated postretirement benefit obligation, end of year
|
$ | 2,305 | $ | 2,151 | ||||
|
Change in plan assets
|
||||||||
|
Plan assets at fair value, beginning of year
|
$ | 864 | $ | 598 | ||||
|
Actual return on plan assets
|
108 | 135 | ||||||
|
Company contributions
|
160 | 205 | ||||||
|
Benefits paid
|
(103 | ) | (74 | ) | ||||
|
Plan assets at fair value, end of year
|
$ | 1,029 | $ | 864 | ||||
|
Funded status, end of year
|
$ | (1,276 | ) | $ | (1,287 | ) | ||
|
Amount recorded as:
|
||||||||
|
Current liabilities
|
$ | (1 | ) | $ | — | |||
|
Noncurrent liabilities
|
$ | (1,275 | ) | $ | (1,287 | ) | ||
| $ | (1,276 | ) | $ | (1,287 | ) | |||
|
Amounts recognized in Accumulated other comprehensive loss,
pre-tax
|
||||||||
|
Net actuarial loss
|
$ | 46 | $ | 51 | ||||
|
Prior service (credit)
|
(28 | ) | (27 | ) | ||||
|
Net transition (asset)
|
(2 | ) | (12 | ) | ||||
| $ | 16 | $ | 12 | |||||
|
Amounts recognized in regulatory assets (See Note 12)
|
||||||||
|
Net actuarial loss
|
$ | 692 | $ | 646 | ||||
|
Prior service cost
|
(74 | ) | 1 | |||||
|
Net transition obligation
|
6 | 18 | ||||||
| $ | 624 | $ | 665 | |||||
123
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Assumptions used in determining the projected benefit obligation
and net benefit costs are listed below:
| 2010 | 2009 | 2008 | ||||||||||
|
Projected benefit obligation
|
||||||||||||
|
Discount rate
|
5.50 | % | 5.90 | % | 6.90 | % | ||||||
|
Net benefit costs
|
||||||||||||
|
Discount rate
|
5.90 | % | 6.90 | % | 6.50 | % | ||||||
|
Expected long-term rate of return on plan assets
|
8.75 | % | 8.75 | % | 8.75 | % | ||||||
|
Health care trend rate pre-65
|
7.00 | % | 7.00 | % | 7.00 | % | ||||||
|
Health care trend rate post-65
|
7.00 | % | 7.00 | % | 6.00 | % | ||||||
|
Ultimate health care trend rate
|
5.00 | % | 5.00 | % | 5.00 | % | ||||||
|
Year in which ultimate reached
|
2016 | 2016 | 2011 | |||||||||
A one percentage point increase in health care cost trend rates
would have increased the total service cost and interest cost
components of benefit costs by $32 million and increased
the accumulated benefit obligation by $300 million at
December 31, 2010. A one percentage point decrease in the
health care cost trend rates would have decreased the total
service and interest cost components of benefit costs by
$28 million and would have decreased the accumulated
benefit obligation by $287 million at December 31,
2010.
At December 31, 2010, the benefits expected to be paid,
including prescription drug benefits, in each of the next five
years and in the aggregate for the five fiscal years thereafter
are as follows:
| (In millions) | ||||
|
2011
|
$ | 110 | ||
|
2012
|
114 | |||
|
2013
|
137 | |||
|
2014
|
144 | |||
|
2015
|
151 | |||
|
2016 — 2020
|
866 | |||
| $ | 1,522 | |||
The process used in determining the long-term rate of return for
assets and the investment approach for the Company’s other
postretirement benefits plans is similar to those previously
described for its pension plans.
Target allocations for plan assets as of December 31, 2010
are listed below:
|
U.S. Large Cap Equity Securities
|
25 | % | ||
|
Non U.S. Equity Securities
|
20 | |||
|
Fixed Income Securities
|
25 | |||
|
Hedge Funds and Similar Investments
|
20 | |||
|
Private Equity and Other
|
10 | |||
| 100 | % |
124
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Fair
Value Measurements at December 31, 2010(a)
|
Balance at
|
||||||||||||||||
|
December 31,
|
||||||||||||||||
| Level 1 | Level 2 | Level 3 | 2010 | |||||||||||||
| (In millions) | ||||||||||||||||
|
Asset Category:
|
||||||||||||||||
|
Short-term investments(b)
|
$ | — | $ | 8 | $ | — | $ | 8 | ||||||||
|
Equity securities
|
||||||||||||||||
|
U.S. Large Cap(c)
|
126 | 62 | — | 188 | ||||||||||||
|
U.S. Small/Mid Cap(d)
|
60 | 58 | — | 118 | ||||||||||||
|
Non U.S(e)
|
79 | 122 | — | 201 | ||||||||||||
|
Fixed income securities(f)
|
4 | 252 | — | 256 | ||||||||||||
|
Other types of investments
|
||||||||||||||||
|
Hedge Funds and Similar Investments(g)
|
76 | 48 | 79 | 203 | ||||||||||||
|
Private Equity and Other(h)
|
— | — | 55 | 55 | ||||||||||||
|
Total
|
$ | 345 | $ | 550 | $ | 134 | $ | 1,029 | ||||||||
Fair
Value Measurements at December 31, 2009(a)
|
Balance at
|
||||||||||||||||
|
December 31,
|
||||||||||||||||
| Level 1 | Level 2 | Level 3 | 2009 | |||||||||||||
| (In millions) | ||||||||||||||||
|
Asset Category:
|
||||||||||||||||
|
Short-term investments(b)
|
$ | — | $ | 18 | $ | — | $ | 18 | ||||||||
|
Equity securities
|
||||||||||||||||
|
U.S. Large Cap(c)
|
148 | 80 | — | 228 | ||||||||||||
|
U.S. Small/Mid Cap(d)
|
46 | 50 | — | 96 | ||||||||||||
|
Non U.S(e)
|
73 | 69 | — | 142 | ||||||||||||
|
Fixed income securities(f)
|
8 | 234 | — | 242 | ||||||||||||
|
Other types of investments
|
||||||||||||||||
|
Hedge Funds and Similar Investments(g)
|
— | — | 92 | 92 | ||||||||||||
|
Private Equity and Other(h)
|
— | — | 46 | 46 | ||||||||||||
|
Total
|
$ | 275 | $ | 451 | $ | 138 | $ | 864 | ||||||||
| (a) | See Note 4 — Fair Value for a description of levels within the fair value hierarchy. | |
| (b) | This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services. | |
| (c) | This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets. | |
| (d) | This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets. |
125
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| (e) | This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets. | |
| (f) | This category includes corporate bonds from diversified industries, U.S. Treasuries, and mortgage backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets. | |
| (g) | This category includes a diversified group of funds and strategies that attempt to capture financial market inefficiencies. In 2009, pricing for investments in this category was based on limited observable inputs as there was little, if any, publicly available pricing. Valuations for assets in this category may be based on relevant publicly-traded securities, derivatives, and privately-traded securities. In 2010, pricing for investments in this category included quoted prices in active markets and quotations from broker or pricing services. Non-exchanged traded securities held in commingled funds are classified as Level 2 assets. | |
| (h) | This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relative publicly-traded comparables and comparable transactions. |
The VEBA trusts hold debt and equity securities directly and
indirectly through commingled funds and institutional mutual
funds. Exchange-traded debt and equity securities held directly
are valued using quoted market prices in actively traded
markets. The commingled funds and institutional mutual funds
which hold exchange-traded equity or debt securities are valued
based on underlying securities, using quoted prices in actively
traded markets. Non-exchange traded fixed income securities are
valued by the trustee based upon quotations available from
brokers or pricing services. A primary price source is
identified by asset type, class or issue for each security. The
trustees monitor prices supplied by pricing services and may use
a supplemental price source or change the primary price source
of a given security if the trustees challenge an assigned price
and determine that another price source is considered to be
preferable. DTE Energy has obtained an understanding of how
these prices are derived, including the nature and observability
of the inputs used in deriving such prices. Additionally, DTE
Energy selectively corroborates the fair values of securities by
comparison of market-based price sources.
Fair
Value Measurements Using Significant Unobservable Inputs
(Level 3):
|
Hedge Funds
|
||||||||||||
|
and Similar
|
Private Equity
|
|||||||||||
| Investments | and Other | Total | ||||||||||
| (In millions) | ||||||||||||
|
Beginning Balance at January 1, 2010
|
$ | 92 | $ | 46 | $ | 138 | ||||||
|
Total realized/unrealized gains
|
10 | 8 | 18 | |||||||||
|
Purchases, sales and settlements
|
(23 | ) | 1 | (22 | ) | |||||||
|
Ending Balance at December 31, 2010
|
$ | 79 | $ | 55 | $ | 134 | ||||||
|
The amount of total gains (losses) for the period attributable
to the change in unrealized gains or losses related to assets
still held at the end of the period
|
$ | 6 | $ | 7 | $ | 13 | ||||||
126
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
|
Hedge Funds
|
||||||||||||
|
and Similar
|
Private Equity
|
|||||||||||
| Investments | and Other | Total | ||||||||||
| (In millions) | ||||||||||||
|
Beginning Balance at January 1, 2009
|
$ | 76 | $ | 38 | $ | 114 | ||||||
|
Total realized/unrealized gains
|
6 | 5 | 11 | |||||||||
|
Purchases, sales and settlements
|
10 | 3 | 13 | |||||||||
|
Ending Balance at December 31, 2009
|
$ | 92 | $ | 46 | $ | 138 | ||||||
|
The amount of total gains (losses) for the period attributable
to the change in unrealized gains or losses related to assets
still held at the end of the period
|
$ | 7 | $ | 2 | $ | 9 | ||||||
Healthcare
Legislation
In March 2010, the PPACA and the HCERA were enacted into law
(collectively, the “Act”). The Act is a comprehensive
health care reform bill. A provision of the PPACA repeals the
current rule permitting deduction of the portion of the drug
coverage expense that is offset by the Medicare Part D
subsidy, effective for taxable years beginning after
December 31, 2012.
DTE Energy’s retiree healthcare plan includes the provision
of postretirement prescription drug coverage
(“coverage”) which is included in the calculation of
the recorded other postemployment benefit (OPEB) obligation.
Because the Company’s coverage meets certain criteria, DTE
Energy is eligible to receive the Medicare Part D subsidy.
With the enactment of the Act, the subsidy will continue to not
be subject to tax, but an equal amount of prescription drug
coverage expenditures will not be deductible. Income tax
accounting rules require the impact of a change in tax law be
recognized in continuing operations in the Consolidated
Statements of Operations in the period that the tax law change
is enacted.
For DTE Energy and its utilities this change in tax law required
a remeasurement of the Deferred Tax Asset related to the OPEB
obligation and the Deferred Tax Liability related to the OPEB
Regulatory Asset. The net impact of the remeasurement is
$23 million, $18 million and $4 million for DTE
Energy, Detroit Edison and MichCon, respectively. The Detroit
Edison and MichCon amounts have been deferred as Regulatory
Assets as the traditional rate setting process allows for the
recovery of income tax costs. Income tax expense of
$1 million was recognized related to corporate entities in
2010.
In December 2003, the Medicare Act was signed into law which
provides for a non-taxable federal subsidy to sponsors of
retiree health care benefit plans that provide a benefit that is
at least “actuarially equivalent” to the benefit
established by law. The effects of the subsidy reduced net
periodic postretirement benefit costs by $7 million in
2010, $20 million in 2009, and $14 million in 2008. At
December 31, 2010, the gross amount of federal subsidies
expected to be received in each of the next two years is
estimated to be $7 million in 2011 and $8 million in
2012.
Grantor
Trust
MichCon maintains a Grantor Trust to fund other postretirement
benefit obligations that invests in life insurance contracts and
income securities. Employees and retirees have no right, title
or interest in the assets of the Grantor Trust, and MichCon can
revoke the trust subject to providing the MPSC with prior
notification. The Company accounts for its investment at fair
value with unrealized gains and losses recorded to earnings.
127
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| NOTE 22 — | STOCK-BASED COMPENSATION |
The Company’s stock incentive program permits the grant of
incentive stock options, non-qualifying stock options, stock
awards, performance shares and performance units to employees
and members of its Board of Directors. Key provisions of the
stock incentive program are:
| • | Authorized limit is 9,000,000 shares of common stock; | |
| • | Prohibits the grant of a stock option with an exercise price that is less than the fair market value of the Company’s stock on the date of the grant; and | |
| • | Imposes the following award limits to a single participant in a single calendar year, (1) options for more than 500,000 shares of common stock; (2) stock awards for more than 150,000 shares of common stock; (3) performance share awards for more than 300,000 shares of common stock (based on the maximum payout under the award); or (4) more than 1,000,000 performance units, which have a face amount of $1.00 each. |
The Company records compensation expense at fair value over the
vesting period for all awards it grants. In addition, the
Company is required to record compensation expense at fair value
(as previous awards continue to vest) for the unvested portion
of previously granted stock option awards that were outstanding
as of January 1, 2006. As of December 31, 2008, all
such awards have been fully expensed.
Stock-based compensation for the reporting periods is as follows:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Stock-based compensation
|
$ | 52 | $ | 56 | $ | 38 | ||||||
|
Tax benefit of compensation
|
$ | 20 | $ | 22 | $ | 13 | ||||||
Approximately $3.3 million, $3.3 million, and
$1.6 million of stock-based compensation cost was
capitalized as part of fixed assets during 2010, 2009, and 2008,
respectively.
Options
Options are exercisable according to the terms of the individual
stock option award agreements and expire 10 years after the
date of the grant. The option exercise price equals the fair
value of the stock on the date that the option was granted.
Stock options vest ratably over a three-year period.
Stock option activity was as follows:
|
Weighted
|
Aggregate
|
|||||||||||
|
Number of
|
Average
|
Intrinsic
|
||||||||||
| Options | Exercise Price | Value | ||||||||||
| (In millions) | ||||||||||||
|
Options outstanding at January 1, 2010
|
5,593,392 | $ | 40.50 | |||||||||
|
Granted
|
611,500 | $ | 43.95 | |||||||||
|
Exercised
|
(1,256,897 | ) | $ | 39.74 | ||||||||
|
Forfeited or expired
|
(120,538 | ) | $ | 42.30 | ||||||||
|
Options outstanding at December 31, 2010
|
4,827,457 | $ | 41.09 | $ | 25 | |||||||
|
Options exercisable at December 31, 2010
|
3,440,401 | $ | 42.57 | $ | 13 | |||||||
As of December 31, 2010, the weighted average remaining
contractual life for the exercisable shares is 4.10 years.
As of December 31, 2010, 1,387,056 options were non-vested.
During 2010, 663,754 options vested.
128
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
The weighted average grant date fair value of options granted
during 2010, 2009, and 2008 was $5.62, $4.41, and $4.76,
respectively. The intrinsic value of options exercised for the
years ended December 31, 2010, 2009 and 2008 was
$9 million, $3 million, and $1 million,
respectively. Total option expense recognized during 2010, 2009
and 2008 was $4 million, $3 million and
$3 million, respectively.
The number, weighted average exercise price and weighted average
remaining contractual life of options outstanding were as
follows:
|
Weighted
|
||||||||||||
|
Average
|
||||||||||||
|
Weighted
|
Remaining
|
|||||||||||
|
Range of
|
Number of
|
Average
|
Contractual Life
|
|||||||||
| Exercise Prices | Options | Exercise Price | (Years) | |||||||||
|
$27.00 — $38.00
|
626,927 | $ | 27.76 | 8.16 | ||||||||
|
$38.01 — $42.00
|
1,902,170 | $ | 41.09 | 4.02 | ||||||||
|
$42.01 — $45.00
|
1,771,567 | $ | 43.96 | 5.87 | ||||||||
|
$45.01 — $50.00
|
526,793 | $ | 47.26 | 4.97 | ||||||||
| 4,827,457 | $ | 41.09 | 5.34 | |||||||||
The Company determined the fair value for these options at the
date of grant using a Black-Scholes based option pricing model
and the following assumptions:
| December 31 | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Risk-free interest rate
|
2.91 | % | 2.04 | % | 3.05 | % | ||||||
|
Dividend yield
|
5.08 | % | 4.98 | % | 5.20 | % | ||||||
|
Expected volatility
|
22.96 | % | 27.88 | % | 20.45 | % | ||||||
|
Expected life
|
6 years | 6 years | 6 years | |||||||||
The Company includes both historical and implied share-price
volatility in option volatility. Implied volatility is derived
from exchange traded options on DTE Energy common stock. The
Company’s expected life estimate is based on industry
standards.
Stock
Awards
Stock awards granted under the plan are restricted for varying
periods, generally for three years. Participants have all rights
of a shareholder with respect to a stock award, including the
right to receive dividends and vote the shares. Prior to vesting
in stock awards, the participant: (i) may not sell,
transfer, pledge, exchange or otherwise dispose of shares;
(ii) shall not retain custody of the share certificates;
and (iii) will deliver to the Company a stock power with
respect to each stock award.
The stock awards are recorded at cost that approximates fair
value on the date of grant. The cost is amortized to
compensation expense over the vesting period.
Stock award activity for the periods ended December 31 was:
| 2010 | 2009 | 2008 | ||||||||||
|
Fair value of awards vested (in millions)
|
$ | 19 | $ | 18 | $ | 18 | ||||||
|
Restricted common shares awarded
|
238,405 | 523,660 | 389,055 | |||||||||
|
Weighted average market price of shares awarded
|
$ | 44.08 | $ | 28.73 | $ | 41.96 | ||||||
|
Compensation cost charged against income (in millions)
|
$ | 12 | $ | 18 | $ | 20 | ||||||
129
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
The following table summarizes the Company’s stock awards
activity for the period ended December 31, 2010:
|
Weighted Average
|
||||||||
|
Restricted
|
Grant Date
|
|||||||
| Stock | Fair Value | |||||||
|
Balance at January 1, 2010
|
1,024,765 | $ | 37.11 | |||||
|
Grants
|
238,405 | $ | 44.08 | |||||
|
Forfeitures
|
(21,549 | ) | $ | 37.28 | ||||
|
Vested
|
(484,207 | ) | $ | 40.21 | ||||
|
Balance at December 31, 2010
|
757,414 | $ | 37.32 | |||||
Performance
Share Awards
Performance shares awarded under the plan are for a specified
number of shares of common stock that entitle the holder to
receive a cash payment, shares of common stock or a combination
thereof. The final value of the award is determined by the
achievement of certain performance objectives and market
conditions. The awards vest at the end of a specified period,
usually three years. The Company accounts for performance share
awards by accruing compensation expense over the vesting period
based on: (i) the number of shares expected to be paid
which is based on the probable achievement of performance
objectives; and (ii) the closing stock price market value.
The settlement of the award is based on the closing price at the
settlement date.
The Company recorded compensation expense as follows:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Compensation expense
|
$ | 36 | $ | 35 | $ | 15 | ||||||
|
Cash settlements(1)
|
$ | 3 | $ | 1 | $ | 3 | ||||||
|
Stock settlements(1)
|
$ | 23 | $ | 8 | $ | — | ||||||
| (1) | Sum of cash and stock settlements approximates the intrinsic value of the liability. |
During the vesting period, the recipient of a performance share
award has no shareholder rights. However, for performance shares
granted before 2010, recipients will be paid an amount equal to
the dividend equivalent on such shares. Performance shares
granted in 2010 or later will not be entitled to dividend
equivalent payments before the performance shares granted are
earned and vested. Performance share awards are nontransferable
and are subject to risk of forfeiture.
The following table summarizes the Company’s performance
share activity for the period ended December 31, 2010:
|
Performance
|
||||
| Shares | ||||
|
Balance at January 1, 2010
|
1,455,042 | |||
|
Grants
|
582,552 | |||
|
Forfeitures
|
(103,520 | ) | ||
|
Payouts
|
(406,821 | ) | ||
|
Balance at December 31, 2010
|
1,527,253 | |||
130
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Unrecognized
Compensation Costs
As of December 31, 2010, there was $44 million of
total unrecognized compensation cost related to non-vested stock
incentive plan arrangements. That cost is expected to be
recognized over a weighted-average period of 1.58 years.
|
Unrecognized
|
||||||||
|
Compensation
|
Weighted Average
|
|||||||
| Cost | to be Recognized | |||||||
| (In millions) | (In years) | |||||||
|
Options
|
$ | 2 | 1.40 | |||||
|
Stock awards
|
10 | 1.09 | ||||||
|
Performance shares
|
32 | 1.75 | ||||||
| $ | 44 | 1.58 | ||||||
| NOTE 23 — | SUPPLEMENTAL CASH FLOW INFORMATION |
A detailed analysis of the changes in assets and liabilities
that are reported in the Consolidated Statements of Cash Flows
follows:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Changes in Assets and Liabilities, Exclusive of Changes Shown
Separately
|
||||||||||||
|
Accounts receivable, net
|
$ | 79 | $ | 167 | $ | 328 | ||||||
|
Inventories
|
(133 | ) | 28 | 96 | ||||||||
|
Recoverable pension and postretirement costs
|
(32 | ) | (19 | ) | (1,324 | ) | ||||||
|
Accrued/prepaid pensions
|
67 | 11 | 944 | |||||||||
|
Accounts payable
|
12 | (162 | ) | (286 | ) | |||||||
|
Income taxes payable
|
(245 | ) | 43 | (22 | ) | |||||||
|
Derivative assets and liabilities
|
(48 | ) | (81 | ) | (178 | ) | ||||||
|
Postretirement obligation
|
(24 | ) | (147 | ) | 340 | |||||||
|
Other assets
|
(52 | ) | 58 | 3 | ||||||||
|
Other liabilities
|
83 | 171 | 7 | |||||||||
| $ | (293 | ) | $ | 69 | $ | (92 | ) | |||||
Supplementary cash and non-cash information for the years ended
December 31, were as follows:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Cash paid (received) for:
|
||||||||||||
|
Interest (net of interest capitalized)
|
$ | 551 | $ | 550 | $ | 496 | ||||||
|
Income taxes
|
$ | 93 | $ | 18 | $ | (59 | ) | |||||
|
Noncash financing activities: Common stock issued for employee
benefit plans
|
$ | 156 | $ | 47 | $ | 15 | ||||||
131
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
| NOTE 24 — | SEGMENT AND RELATED INFORMATION |
The Company sets strategic goals, allocates resources and
evaluates performance based on the following structure:
Electric Utility
segment consists of Detroit Edison,
which is engaged in the generation, purchase, distribution and
sale of electricity to approximately 2.1 million customers
in southeastern Michigan.
Gas Utility
segment consists of MichCon and
Citizens. MichCon is engaged in the purchase,
storage, transportation, gathering, distribution and sale of
natural gas to approximately 1.2 million customers
throughout Michigan and the sale of storage and transportation
capacity. Citizens distributes natural gas in Adrian, Michigan
to approximately 17,000 customers.
Gas Storage and Pipelines
consists of natural gas storage
and pipelines businesses.
Unconventional Gas Production
is engaged in
unconventional gas and oil project development and production.
Power and Industrial Projects
is comprised of coke
batteries and pulverized coal projects, reduced emission fuel
and steel industry fuel-related projects,
on-site
energy services, renewable power generation, landfill gas
recovery and coal transportation, marketing and trading.
Energy Trading
consists of energy marketing and trading
operations.
Corporate & Other,
includes various holding
company activities, holds certain non-utility debt and
energy-related investments.
The federal income tax provisions or benefits of DTE
Energy’s subsidiaries are determined on an individual
company basis and recognize the tax benefit of production tax
credits and net operating losses if applicable. The Michigan
Business Tax provision of the utility subsidiaries is determined
on an individual company basis and recognizes the tax benefit of
various tax credits and net operating losses if applicable. The
subsidiaries record federal and state income taxes payable to or
receivable from DTE Energy based on the federal and state tax
provisions of each company.
Inter-segment billing for goods and services exchanged between
segments is based upon tariffed or market-based prices of the
provider and primarily consists of power sales, gas sales and
coal transportation services in the following segments:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Electric Utility
|
$ | 30 | $ | 28 | $ | 16 | ||||||
|
Gas Utility
|
— | 2 | 7 | |||||||||
|
Gas Storage and Pipelines
|
4 | 5 | 10 | |||||||||
|
Power and Industrial Projects
|
161 | 11 | 80 | |||||||||
|
Energy Trading
|
89 | 93 | 145 | |||||||||
|
Corporate & Other
|
(65 | ) | (74 | ) | (80 | ) | ||||||
| $ | 219 | $ | 65 | $ | 178 | |||||||
132
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
Financial data of the business segments follows:
|
Net Income
|
||||||||||||||||||||||||||||||||||||
|
Attributable
|
||||||||||||||||||||||||||||||||||||
|
Depreciation,
|
to DTE
|
|||||||||||||||||||||||||||||||||||
|
Operating
|
Depletion &
|
Interest
|
Interest
|
Income
|
Energy
|
Total
|
Capital
|
|||||||||||||||||||||||||||||
| Revenue | Amortization | Income | Expense | Taxes | Company | Assets | Goodwill | Expenditures | ||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||
|
2010
|
||||||||||||||||||||||||||||||||||||
|
Electric Utility
|
$ | 4,993 | $ | 849 | $ | (1 | ) | $ | 313 | $ | 270 | $ | 441 | $ | 16,375 | $ | 1,206 | $ | 864 | |||||||||||||||||
|
Gas Utility
|
1,648 | 92 | (9 | ) | 66 | 67 | 127 | 3,854 | 759 | 147 | ||||||||||||||||||||||||||
|
Gas Storage and Pipelines
|
83 | 5 | (1 | ) | 6 | 32 | 51 | 391 | 9 | 5 | ||||||||||||||||||||||||||
|
Unconventional Gas Production
|
32 | 15 | — | 6 | (6 | ) | (11 | ) | 308 | 2 | 27 | |||||||||||||||||||||||||
|
Power and Industrial Projects
|
1,144 | 60 | (3 | ) | 33 | 3 | 85 | 1,236 | 27 | 53 | ||||||||||||||||||||||||||
|
Energy Trading
|
875 | 5 | — | 13 | 5 | 6 | 483 | 17 | 1 | |||||||||||||||||||||||||||
|
Corporate & Other
|
1 | 1 | (47 | ) | 160 | (60 | ) | (69 | ) | 2,249 | — | — | ||||||||||||||||||||||||
|
Reconciliation and Eliminations
|
(219 | ) | — | 49 | (48 | ) | — | — | — | — | — | |||||||||||||||||||||||||
|
Total
|
$ | 8,557 | $ | 1,027 | $ | (12 | ) | $ | 549 | $ | 311 | $ | 630 | $ | 24,896 | $ | 2,020 | $ | 1,097 | |||||||||||||||||
|
Net Income
|
||||||||||||||||||||||||||||||||||||
|
Attributable
|
||||||||||||||||||||||||||||||||||||
|
Depreciation,
|
to DTE
|
|||||||||||||||||||||||||||||||||||
|
Operating
|
Depletion &
|
Interest
|
Interest
|
Income
|
Energy
|
Total
|
Capital
|
|||||||||||||||||||||||||||||
| Revenue | Amortization | Income | Expense | Taxes | Company | Assets | Goodwill | Expenditures | ||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||||||||||
|
Electric Utility
|
$ | 4,714 | $ | 844 | $ | (1 | ) | $ | 324 | $ | 228 | $ | 376 | $ | 15,879 | $ | 1,206 | $ | 794 | |||||||||||||||||
|
Gas Utility
|
1,788 | 107 | (8 | ) | 68 | 39 | 80 | 3,832 | 759 | 166 | ||||||||||||||||||||||||||
|
Gas Storage and Pipelines
|
82 | 5 | (1 | ) | 10 | 33 | 49 | 367 | 9 | 2 | ||||||||||||||||||||||||||
|
Unconventional Gas Production
|
31 | 16 | — | 6 | (4 | ) | (9 | ) | 309 | 2 | 26 | |||||||||||||||||||||||||
|
Power and Industrial Projects
|
661 | 40 | (3 | ) | 30 | 7 | 31 | 1,118 | 31 | 45 | ||||||||||||||||||||||||||
|
Energy Trading
|
804 | 5 | (1 | ) | 10 | 37 | 75 | 552 | 17 | 2 | ||||||||||||||||||||||||||
|
Corporate & Other
|
— | 3 | (55 | ) | 147 | (79 | ) | (70 | ) | 2,138 | — | — | ||||||||||||||||||||||||
|
Reconciliation and Eliminations
|
(66 | ) | — | 50 | (50 | ) | — | — | — | — | — | |||||||||||||||||||||||||
|
Total
|
$ | 8,014 | $ | 1,020 | $ | (19 | ) | $ | 545 | $ | 247 | $ | 532 | $ | 24,195 | $ | 2,024 | $ | 1,035 | |||||||||||||||||
133
Table of Contents
DTE
Energy Company
Notes
to Consolidated Financial
Statements —
(Continued)
|
Net Income
|
||||||||||||||||||||||||||||||||||||
|
Attributable
|
||||||||||||||||||||||||||||||||||||
|
Depreciation,
|
to DTE
|
|||||||||||||||||||||||||||||||||||
|
Operating
|
Depletion &
|
Interest
|
Interest
|
Income
|
Energy
|
Total
|
Capital
|
|||||||||||||||||||||||||||||
| Revenue | Amortization | Income | Expense | Taxes | Company | Assets | Goodwill | Expenditures | ||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||
|
2008
|
||||||||||||||||||||||||||||||||||||
|
Electric Utility
|
$ | 4,874 | $ | 743 | $ | (6 | ) | $ | 293 | $ | 186 | $ | 331 | $ | 15,798 | $ | 1,206 | $ | 944 | |||||||||||||||||
|
Gas Utility
|
2,152 | 102 | (8 | ) | 66 | 41 | 85 | 3,884 | 772 | 239 | ||||||||||||||||||||||||||
|
Gas Storage and Pipelines
|
71 | 5 | (1 | ) | 7 | 24 | 38 | 316 | 9 | 19 | ||||||||||||||||||||||||||
|
Unconventional Gas Production(1)
|
48 | 12 | — | 2 | 47 | 84 | 314 | 2 | 101 | |||||||||||||||||||||||||||
|
Power and Industrial Projects
|
987 | 34 | (7 | ) | 20 | 11 | 40 | 1,126 | 31 | 65 | ||||||||||||||||||||||||||
|
Energy Trading
|
1,388 | 5 | (5 | ) | 10 | 31 | 42 | 787 | 17 | 5 | ||||||||||||||||||||||||||
|
Corporate & Other
|
(13 | ) | — | (41 | ) | 154 | (52 | ) | (94 | ) | 2,365 | — | — | |||||||||||||||||||||||
|
Reconciliation and Eliminations
|
(178 | ) | — | 49 | (49 | ) | — | — | — | — | — | |||||||||||||||||||||||||
|
Total from Continuing Operations
|
$ | 9,329 | $ | 901 | $ | (19 | ) | $ | 503 | $ | 288 | 526 | 24,590 | 2,037 | 1,373 | |||||||||||||||||||||
|
Discontinued Operations (Note 10)
|
20 | — | — | — | ||||||||||||||||||||||||||||||||
|
Total
|
$ | 546 | $ | 24,590 | $ | 2,037 | $ | 1,373 | ||||||||||||||||||||||||||||
| (1) | Net income attributable to DTE Energy Company of the Unconventional Gas Production segment in 2008 reflects the gain recognized on the sale of Barnett shale properties. See Note 10. |
| NOTE 25 — | SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED) |
Quarterly earnings per share may not total for the years, since
quarterly computations are based on weighted average common
shares outstanding during each quarter.
|
First
|
Second
|
Third
|
Fourth
|
|||||||||||||||||
| Quarter | Quarter | Quarter | Quarter | Year | ||||||||||||||||
| (In millions, except per share amounts) | ||||||||||||||||||||
|
2010
|
||||||||||||||||||||
|
Operating Revenues
|
$ | 2,453 | $ | 1,792 | $ | 2,139 | $ | 2,173 | $ | 8,557 | ||||||||||
|
Operating Income
|
$ | 472 | $ | 256 | $ | 386 | $ | 350 | $ | 1,464 | ||||||||||
|
Net Income Attributable to DTE Energy Company
|
$ | 229 | $ | 86 | $ | 163 | $ | 152 | $ | 630 | ||||||||||
|
Basic Earnings per Share
|
$ | 1.38 | $ | .51 | $ | .97 | $ | .90 | $ | 3.75 | ||||||||||
|
Diluted Earnings per Share
|
$ | 1.38 | $ | .51 | $ | .96 | $ | .90 | $ | 3.74 | ||||||||||
|
2009
|
||||||||||||||||||||
|
Operating Revenues
|
$ | 2,255 | $ | 1,688 | $ | 1,950 | $ | 2,121 | $ | 8,014 | ||||||||||
|
Operating Income
|
$ | 395 | $ | 215 | $ | 332 | $ | 307 | $ | 1,249 | ||||||||||
|
Net Income Attributable to DTE Energy Company
|
$ | 178 | $ | 83 | $ | 151 | $ | 120 | $ | 532 | ||||||||||
|
Basic Earnings per Share
|
$ | 1.09 | $ | .51 | $ | .92 | $ | .72 | $ | 3.24 | ||||||||||
|
Diluted Earnings per Share
|
$ | 1.09 | $ | .51 | $ | .92 | $ | .72 | $ | 3.24 |
134
Table of Contents
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
| Item 9A. | Controls and Procedures |
See Item 8. Financial Statements and Supplementary Data for
management’s evaluation of disclosure controls and
procedures, its report on internal control over financial
reporting, and its conclusion on changes in internal control
over financial reporting.
| Item 9B. | Other Information |
| Item 10. | Directors, Executive Officers and Corporate Governance |
| Item 11. | Executive Compensation |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
| Item 14. | Principal Accountant Fees and Services |
Information required by Part III (Items 10, 11, 12, 13
and 14) of this
Form 10-K
is incorporated by reference from DTE Energy’s definitive
Proxy Statement for its 2011 Annual Meeting of Common
Shareholders to be held May 5, 2011. The Proxy Statement
will be filed with the Securities and Exchange Commission,
pursuant to Regulation 14A, not later than 120 days
after the end of our fiscal year covered by this report on
Form 10-K,
all of which information is hereby incorporated by reference in,
and made part of, this
Form 10-K.
| Item 15. | Exhibits and Financial Statement Schedules |
|
(a)
|
The following documents are filed as part of this Annual Report on Form 10-K. | |
|
(1)
|
Consolidated financial statements. See “Item 8 — Financial Statements and Supplementary Data.” | |
|
(2)
|
Financial statement schedules. See “Item 8 — Financial Statements and Supplementary Data.” | |
|
(3)
|
Exhibits. | |
| (i) Exhibits filed herewith. | ||
|
3-1
|
Bylaws of DTE Energy Company, as amended through December 16, 2010. | |
|
12-46
|
Computation of Ratio of Earnings to Fixed Charges. | |
|
21-6
|
Subsidiaries of the Company. | |
|
23-23
|
Consent of PricewaterhouseCoopers LLP. | |
|
23-24
|
Consent of Deloitte & Touche LLP. | |
|
31-63
|
Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report. | |
|
31-64
|
Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report. | |
|
99-54
|
Amendment and Restatement of Master Trust Agreement for the DTE Energy Company Master Plan Trust between DTE Energy Corporate Services, LLC and DTE Energy Investment Committee and JP Morgan Chase Bank, N.A., dated as of October 15, 2010. |
135
Table of Contents
| (ii) Exhibits incorporated herein by reference . | ||
|
3(a)
|
Amended and Restated Articles of Incorporation of DTE Energy Company, dated December 13, 1995 and as amended from time to time (Exhibit 3.1 to Form 8-K dated May 6, 2010). | |
|
4(a)
|
Amended and Restated Indenture, dated as of April 9, 2001, between DTE Energy Company and Bank of New York, as trustee (Exhibit 4.1 to Registration Statement on Form S-3 (File No. 333-58834)). | |
| Supplemental Indenture, dated as of May 30, 2001, between DTE Energy Company and Bank of New York, as trustee (Exhibit 4-226 to Form 10-Q for the quarter ended June 30, 2001). (7.05% Senior Notes due 2011). | ||
| Supplemental Indenture, dated as of April 5, 2002 between DTE Energy Company and Bank of New York, as trustee (Exhibit 4-230 to Form 10-Q for the quarter ended March 31, 2002). (2002 Series A 6.65% Senior Notes due 2009). | ||
| Supplemental Indenture, dated as of April 1, 2003, between DTE Energy Company and Bank of New York, as trustee, creating 2003 Series A 6 3 / 8 % Senior Notes due 2033 (Exhibit 4(o) to Form 10-Q for the quarter ended March 31, 2003). (2003 Series A 6 3 / 8 % Senior Notes due 2033). | ||
| Supplemental Indenture, dated as of May 15, 2006, between DTE Energy Company and Bank of New York, as trustee (Exhibit 4-239 to Form 10-Q for the quarter ended June 30, 2006). (2006 Series B 6.35% Senior Notes due 2016). | ||
|
4(b)
|
Amended and Restated Trust Agreement of DTE Energy Trust I, dated as of January 15, 2002 (Exhibit 4-229 to Form 10-K for the year ended December 31, 2001). | |
|
4(c)
|
Amended and Restated Trust Agreement of DTE Energy Trust II, dated as of June 1, 2004 (Exhibit 4(q) to Form 10-Q for the quarter ended June 30, 2004). | |
|
4(d)
|
Trust Agreement of DTE Energy Trust III (Exhibit 4-21 to Registration Statement on Form S-3 (File No. 333-99955). | |
|
4(e)
|
Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-1 to Detroit Edison’s Registration Statement on Form A-2 (File No. 2-1630)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below: | |
| Supplemental Indenture, dated as of December 1, 1940, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-14 to Detroit Edison’s Registration Statement on Form A-2 (File No. 2-4609)). (amendment) | ||
| Supplemental Indenture, dated as of September 1, 1947, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-20 to Detroit Edison’s Registration Statement on Form S-1 (File No. 2-7136)). (amendment) | ||
| Supplemental Indenture, dated as of March 1, 1950, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-22 to Detroit Edison’s Registration Statement on Form S-1 (File No. 2-8290)). (amendment) | ||
| Supplemental Indenture, dated as of November 15, 1951, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-23 to Detroit Edison’s Registration Statement on Form S-1 (File No. 2-9226)). (amendment) | ||
| Supplemental Indenture, dated as of August 15, 1957, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 3-B-30 to Detroit Edison’s Form 8-K dated September 11, 1957). (amendment) |
136
Table of Contents
| Supplemental Indenture, dated as of December 1, 1966, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 2-B-32 to Detroit Edison’s Registration Statement on Form S-9 (File No. 2-25664)). (amendment) | ||
| Supplemental Indenture, dated as of February 15, 1990, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-212 to Detroit Edison’s Form 10-K for the year ended December 31, 2000). (1990 Series B, C, E and F) | ||
| Supplemental Indenture, dated as of May 1, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-178 to Detroit Edison’s Form 10-K for the year ended December 31, 1996). (1991 Series BP and CP) | ||
| Supplemental Indenture, dated as of May 15, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-179 to Detroit Edison’s Form 10-K for the year ended December 31, 1996). (1991 Series DP) | ||
| Supplemental Indenture, dated as of February 29, 1992, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-187 to Detroit Edison’s Form 10-Q for the quarter ended March 31, 1998). (1992 Series AP) | ||
| Supplemental Indenture, dated as of April 26, 1993, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-215 to Detroit Edison’s Form 10-K for the year ended December 31, 2000). (amendment) | ||
| Supplemental Indenture, dated as of August 1, 1999, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-204 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 1999). (1999 Series AP, BP and CP) | ||
| Supplemental Indenture, dated as of August 1, 2000, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-210 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2000). (2000 Series BP) | ||
| Supplemental Indenture, dated as of August 15, 2001, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-227 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2001). (2001 Series CP) | ||
| Supplemental Indenture, dated as of September 17, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison’s Registration Statement on Form S-3 (File No. 333-100000)). (amendment and successor trustee) | ||
| Supplemental Indenture, dated as of October 15, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-230 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2002). (2002 Series A and B) |
137
Table of Contents
| Supplemental Indenture, dated as of December 1, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-232 to Detroit Edison’s Form 10-K for the year ended December 31, 2002). (2002 Series C and D) | ||
| Supplemental Indenture, dated as of August 1, 2003, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-235 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2003). (2003 Series A) | ||
| Supplemental Indenture, dated as of March 15, 2004, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-238 to Detroit Edison’s Form 10-Q for the quarter ended March 31, 2004). (2004 Series A and B) | ||
| Supplemental Indenture, dated as of July 1, 2004, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-240 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2004). (2004 Series D) | ||
| Supplemental Indenture, dated as of April 1, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.3 to Detroit Edison’s Registration Statement on Form S-4 (File No. 333-123926)). (2005 Series AR and BR) | ||
| Supplemental Indenture, dated as of September 15, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.2 to Detroit Edison’s Form 8-K dated September 29, 2005). (2005 Series C) | ||
| Supplemental Indenture, dated as of September 30, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-248 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2005). (2005 Series E) | ||
| Supplemental Indenture, dated as of May 15, 2006, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-250 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2006). (2006 Series A) | ||
| Supplemental Indenture, dated as of April 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between the Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-251 to the Detroit Edison’s Form 10-Q for the quarter ended March 31, 2008). (2008 Series DT) | ||
| Supplemental Indenture, dated as of May 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-253 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2008). (2008 Series ET) | ||
| Supplemental Indenture, dated as of June 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-255 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2008). (2008 Series G) |
138
Table of Contents
| Supplemental Indenture, dated as of July 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-257 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2008). (2008 Series KT) | ||
| Supplemental Indenture, dated as of October 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A. as successor trustee (Exhibit 4-259 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2008). (2008 Series J) | ||
| Supplemental Indenture, dated as of December 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A., as successor trustee (Exhibit 4-261 to Detroit Edison’s Form 10-K for the year ended December 31, 2008). (2008 Series LT) | ||
| Supplemental Indenture, dated as of March 15, 2009 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A., as successor trustee (Exhibit 4-263 to Detroit Edison’s Form 10-Q for the quarter ended March 31, 2009). (2009 Series BT) | ||
| Supplemental Indenture, dated as of November 1, 2009 to Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A., as successor trustee (Exhibit 4-267 to Detroit Edison’s Form 10-K for the year ended December 31, 2009). (2009 Series CT) | ||
| Supplemental Indenture, dated as of August 1, 2010, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-269 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2010). (2010 Series B) | ||
| Supplemental Indenture, dated as of September 1, 2010, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-271 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2010). (2010 Series A) | ||
| Supplemental Indenture, dated as of December 1, 2010, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-273 to Detroit Edison’s Form 10-K for the year ended December 31, 2010). (2010 Series CT) | ||
|
4(f)
|
Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-152 to Detroit Edison’s Registration Statement (File No. 33-50325)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below: | |
| Tenth Supplemental Indenture, dated as of October 23, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-231 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2002). (5.20% Senior Notes due 2012 and 6.35% Senior Notes due 2032) | ||
| Eleventh Supplemental Indenture, dated as of December 1, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-233 to Detroit Edison’s Form 10-Q for the quarter ended March 31, 2003). (5.45% Senior Notes due 2032 and 5.25% Senior Notes due 2032) |
139
Table of Contents
| Twelfth Supplemental Indenture, dated as of August 1, 2003, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-236 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2003). (5 1 / 2 % Senior Notes due 2030) | ||
| Thirteenth Supplemental Indenture, dated as of April 1, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-237 to Detroit Edison’s Form 10-Q for the quarter ended March 31, 2004). (4.875% Senior Notes Due 2029 and 4.65% Senior Notes due 2028) | ||
| Fourteenth Supplemental Indenture, dated as of July 15, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-239 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2004). (2004 Series D 5.40% Senior Notes due 2014) | ||
| Sixteenth Supplemental Indenture, dated as of April 1, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison’s Registration Statement on Form S-4 (File No. 333-123926)). (2005 Series AR 4.80% Senior Notes due 2015 and 2005 Series BR 5.45% Senior Notes due 2035) | ||
| Eighteenth Supplemental Indenture, dated as of September 15, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison’s Form 8-K dated September 29, 2005). (2005 Series C 5.19% Senior Notes due October 1, 2023) | ||
| Nineteenth Supplemental Indenture, dated as of September 30, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-247 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2005). (2005 Series E 5.70% Senior Notes due 2037) | ||
| Twentieth Supplemental Indenture, dated as of May 15, 2006, to the Collateral Trust Indenture dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-249 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2006). (2006 Series A Senior Notes due 2036) | ||
| Twenty-second Supplemental Indenture, dated as of December 1, 2007, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison’s Form 8-K dated December 18, 2007). (2007 Series A Senior Notes due 2038) | ||
| Twenty-fourth Supplemental Indenture, dated as of May 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-254 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2008). (2008 Series ET Variable Rate Senior Notes due 2029) | ||
| Amendment dated June 1, 2009 to the Twenty-fourth Supplemental Indenture, dated as of May 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (2008 Series ET Variable Rate Senior Notes due 2029) (Exhibit 4-265 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2009) | ||
| Twenty-fifth Supplemental Indenture, dated as of June 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-256 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2008). (2008 Series G 5.60% Senior Notes due 2018) |
140
Table of Contents
| Twenty-sixth Supplemental Indenture, dated as of July 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-258 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2008). (2008 Series KT Variable Rate Senior Notes due 2020) | ||
| Amendment dated June 1, 2009 to the Twenty-sixth Supplemental Indenture, dated as of July 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-266 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2009) (2008 Series KT Variable Rate Senior Notes due 2020) | ||
| Twenty-seventh Supplemental Indenture, dated as of October 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-260 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2008). (2008 Series J 6.40% Senior Notes due 2013) | ||
| Twenty-eighth Supplemental Indenture, dated as of December 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-262 to Detroit Edison’s Form 10-K for the year ended December 31, 2008). (2008 Series LT 6.75% Senior Notes due 2038) | ||
| Twenty-ninth Supplemental Indenture, dated as of March 15, 2009, to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-264 to Detroit Edison’s Form 10-Q for the quarter ended March 31, 2009). (2009 Series BT 6.00% Senior Notes due 2036) | ||
| Thirtieth Supplemental Indenture, dated as of November 1, 2009, to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-268 to Detroit Edison’s Form 10-K for the year ended December 31, 2009). (2009 Series CT Variable Rate Notes due 2024) | ||
| Thirty-First Supplemental Indenture, dated as of August 1, 2010 to the Collateral Trust Indenture, dated as of June 1, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-270 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2010). (2010 Series B 3.45% Senior Notes due 2020) | ||
| Thirty-Second Supplemental Indenture, dated as of September 1, 2010, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-272 to Detroit Edison’s Form 10-Q for the quarter ended September 30, 2010). (2010 Series A 4.89% Senior Notes due 2020) | ||
|
4(g)
|
Trust Agreement of Detroit Edison Trust I. (Exhibit 4.9 to Registration Statement on Form S-3 (File No. 333-100000)). | |
|
4(h)
|
Trust Agreement of Detroit Edison Trust II. (Exhibit 4.10 to Registration Statement on Form S-3 (File No. 333-100000)). | |
|
4(i)
|
Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., as trustee, related to Senior Debt Securities (Exhibit 4-1 to Michigan Consolidated Gas Company Registration Statement on Form S-3 (File No. 333-63370)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below: | |
| Fourth Supplemental Indenture dated as of February 15, 2003, to the Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-3 to Michigan Consolidated Gas Company Form 10-Q for the quarter ended March 31, 2003). (5.70% Senior Notes, 2003 Series A due 2033) |
141
Table of Contents
| Fifth Supplemental Indenture dated as of October 1, 2004, to the Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-6 to Michigan Consolidated Gas Company Form 10-Q for the quarter ended September 31, 2004). (5.00% Senior Notes, 2004 Series E due 2019) | ||
| Sixth Supplemental Indenture dated as of April 1, 2008, to the Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-241 to Form 10-Q for the quarter ended March 31, 2008). (5.26% Senior Notes, 2008 Series ‘A’ due 2013, 6.04% Senior Notes, 2008 Series ‘B’ due 2018 and 6.44% Senior Notes, 2008 Series ‘C’ due 2023). | ||
| Seventh Supplemental Indenture, dated as of June 1, 2008 to Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-243 to Form 10-Q for the quarter ended June 30, 2008). (6.78% Senior Notes, 2008 Series F due 2028) | ||
| Eighth Supplemental Indenture, dated as of August 1, 2008 to Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-251 to Form 10-Q for the quarter ended September 30, 2008). (5.94% Senior Notes, 2008 Series H due 2015 and 6.36% Senior Notes, 2008 Series I due 2020) | ||
| Ninth Supplemental Indenture, dated as of December 1, 2008 to Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee. (Exhibit 4-252 to Form 10-K for the year ended December 31, 2008). (Floating Rate Senior Notes, 2008 Series M due 2009) | ||
|
4(j)
|
Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 (Exhibit 7-D to Michigan Consolidated Gas Company Registration Statement No. 2-5252) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below: | |
| Twenty-ninth Supplemental Indenture dated as of July 15, 1989, among Michigan Consolidated Gas Company and Citibank, N.A. and Robert T. Kirchner, as trustees, creating an issue of first mortgage bonds and providing for the modification and restatement of the Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 (Exhibit 4-2 to Michigan Consolidated Gas Company Registration Statement on Form S-3 (File No. 333-63370)). | ||
| Thirty-second Supplemental Indenture dated as of January 5, 1993 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-1 to Michigan Consolidated Gas Company Form 10-K for the year ended December 31, 1992). (First Mortgage Bonds Designated Secured Term Notes, Series B) | ||
| Thirty-third Supplemental Indenture dated as of May 1, 1995 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-2 to Michigan Consolidated Gas Company Registration Statement on Form S-3 (File No. 33-59093)). (First Mortgage Bonds Designated Secured Medium Term Notes, Series B) | ||
| Thirty-fourth Supplemental Indenture dated as of November 1, 1996 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-2 to Michigan Consolidated Gas Company Registration Statement on Form S-3 (File No. 333-16285)). (First Mortgage Bonds Designated Secured Medium Term Notes, Series C) | ||
| Thirty-fifth Supplemental Indenture dated as of June 18, 1998 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee, creating an issue of first mortgage bonds designated as collateral bonds (Exhibit 4-2 to Michigan Consolidated Gas Company Form 8-K dated June 18, 1998). | ||
| Thirty-seventh Supplemental Indenture dated as of February 15, 2003 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-4 to Michigan Consolidated Gas Company Form 10-Q for the quarter ended March 31, 2003). (5.70% collateral bonds due 2033) |
142
Table of Contents
| Thirty-eighth Supplemental Indenture dated as of October 1, 2004 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-5 to Michigan Consolidated Gas Company Form 10-Q for the quarter ended September 31, 2004). (2004 Series E collateral bonds) | ||
| Thirty-ninth Supplemental Indenture, dated as of April 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-240 to Form 10-Q for the quarter ended March 31, 2008). (2008 Series A, B and C Collateral Bonds) | ||
| Fortieth Supplemental Indenture, dated as of June 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-242 to Form 10-Q for the quarter ended June 30, 2008). (2008 Series F Collateral Bonds) | ||
| Forty-first Supplemental Indenture, dated as of August 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-250 to Form 10-Q for the quarter ended September 30, 2008). (2008 Series H and I Collateral Bonds) | ||
| Forty-second Supplemental Indenture, dated as of December 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., Trustee (Exhibit 4-253 to Form 10-K for the year ending December 31, 2008) (2008 Series M Collateral Bonds). | ||
|
10(a)
|
Form of Indemnification Agreement between DTE Energy Company and each of Gerard M. Anderson, Anthony F. Earley, Jr., Steven E. Kurmas, David E. Meador, Bruce D. Peterson, and non-employee Directors. (Exhibit 10-1 to Form 8-K dated December 6, 2007). | |
|
10(b)
|
Certain arrangements pertaining to the employment of Anthony F. Earley, Jr. with The Detroit Edison Company, dated April 25, 1994 (Exhibit 10-53 to The Detroit Edison Company’s Form 10-Q for the quarter ended March 31, 1994). | |
|
10(c)
|
Certain arrangements pertaining to the employment of Gerard M. Anderson with The Detroit Edison Company, dated October 6, 1993 (Exhibit 10-48 to The Detroit Edison Company’s Form 10-K for the year ended December 31, 1993). | |
|
10(d)
|
Certain arrangements pertaining to the employment of David E. Meador with The Detroit Edison Company, dated January 14, 1997 (Exhibit 10-5 to Form 10-K for the year ended December 31, 1996). | |
|
10(e)
|
Certain arrangements pertaining to the employment of Bruce D. Peterson, dated May 22, 2002 (Exhibit 10-48 to Form 10-Q for the quarter ended June 30, 2002). | |
|
10(f)
|
Amended and Restated Post-Employment Income Agreement, dated March 23, 1998, between The Detroit Edison Company and Anthony F. Earley, Jr. (Exhibit 10-21 to Form 10-Q for the quarter ended March 31, 1998). | |
|
10(g)
|
DTE Energy Company Annual Incentive Plan (Exhibit 10-44 to Form 10-Q for the quarter ended March 31, 2001). | |
|
10(h)
|
Amended and Restated DTE Energy Company 2006 Long-Term Incentive Plan (as amended and restated effective as of May 6, 2010) (Annex A to DTE Energy’s Definitive Proxy Statement dated March 29, 2010). | |
|
10(i)
|
DTE Energy Company Retirement Plan for Non-Employee Directors’ Fees (as amended and restated effective as of December 31, 1998) (Exhibit 10-31 to Form 10-K for the year ended December 31, 1998). | |
|
10(j)
|
The Detroit Edison Company Supplemental Long-Term Disability Plan, dated January 27, 1997 (Exhibit 10-4 to Form 10-K for the year ended December 31, 1996). |
143
Table of Contents
|
10(k)
|
Description of Executive Life Insurance Plan (Exhibit 10-47 to Form 10-Q for the quarter ended June 30, 2002). | |
|
10(l)
|
DTE Energy Affiliates Nonqualified Plans Master Trust, effective as of May 1, 2003 (Exhibit 10-49 to Form 10-Q for the quarter ended March 31, 2003). | |
|
10(m)
|
Form of Director Restricted Stock Agreement (Exhibit 10.1 to Form 8-K dated June 23, 2005). | |
|
10(n)
|
Form of Director Restricted Stock Agreement pursuant to the DTE Energy Company Long-Term Incentive Plan (Exhibit 10.1 to Form 8-K dated June 29, 2006). | |
|
10(o)
|
DTE Energy Company Executive Supplemental Retirement Plan as Amended and Restated, effective as of January 1, 2005. (Exhibit 10.75 to Form 10-K for year ended December 31, 2008) | |
| First Amendment to the DTE Energy Company Executive Supplemental Retirement Plan (Amended and Restated Effective January 1, 2005) dated as of December 2, 2009. (Exhibit 10.1 to Form 8-K dated December 8, 2009). | ||
|
10(p)
|
DTE Energy Company Supplemental Retirement Plan as Amended and Restated, effective as of January 1, 2005. (Exhibit 10.76 to Form 10-K for year ended December 31, 2008). | |
|
10(q)
|
DTE Energy Company Supplemental Savings Plan as Amended and Restated, effective as of January 1, 2005. (Exhibit 10.77 to Form 10-K for year ended December 31, 2008). | |
|
10(r)
|
DTE Energy Company Executive Deferred Compensation Plan as Amended and Restated, effective as of January 1, 2005. (Exhibit 10.78 to Form 10-K for year ended December 31, 2008). | |
|
10(s)
|
DTE Energy Company Plan for Deferring the Payment of Directors’ Fees as Amended and Restated, effective as of January 1, 2005. (Exhibit 10.79 to Form 10-K for year ended December 31, 2008). | |
|
10(t)
|
DTE Energy Company Deferred Stock Compensation Plan for Non-Employee Directors as Amended and Restated, effective January 1, 2005. (Exhibit 10.80 to Form 10-K for year ended December 31, 2008). | |
|
10(u)
|
Form of DTE Energy Three-Year Credit Agreement, dated as of August 20, 2010, by and among DTE Energy Company, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Capital, Bank of America, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.3 to Form 8-K filed on August 26, 2010). | |
|
10(v)
|
Form of MichCon Three-Year Credit Agreement, dated as of August 20, 2010, by and among Michigan Consolidated Gas Company, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Barclays Capital, Citibank N.A. and Bank of America N.A., as Co-Syndication Agents (Exhibit 10.4 to Form 8-K filed on August 26, 2010). | |
|
10(w)
|
Form of Detroit Edison Three-Year Credit Agreement, dated as of August 20, 2010, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank plc, as Administrative Agent, and Citibank N.A., JPMorgan Chase Bank, N.A. and the Royal Bank of Scotland plc, as Co-Syndication Agents (Exhibit 10.2 to Detroit Edison Form 8-K filed on August 26, 2010). | |
|
10(x)
|
Form of Amended and Restated DTE Energy Two-Year Credit Agreement, dated as of April 29, 2009 and amended and restated as of August 20, 2010, by and among DTE Energy Company, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Capital, Bank of America, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.1 to Form 8-K filed on August 26, 2010). | |
|
10(y)
|
Form of Amended and Restated MichCon Two-Year Credit Agreement, dated as of April 29, 2009 and amended and restated as of August 20, 2010, by and among Michigan Consolidated Gas Company, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Barclays Capital, Citibank N.A. and Bank of America N.A., as Co-Syndication Agents (Exhibit 10.2 to Form 8-K filed on August 26, 2010). |
144
Table of Contents
|
10(z)
|
Form of Amended and Restated Detroit Edison Two-Year Credit Agreement, dated as of April 29, 2009 and amended and restated as of August 20, 2010, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank plc, as Administrative Agent, and Citibank N.A., JPMorgan Chase Bank, N.A. and the Royal Bank of Scotland plc, as Co-Syndication Agents (Exhibit 10.1 to Detroit Edison Form 8-K filed on August 26, 2010). | |
| (iii) Exhibits furnished herewith: | ||
|
32-63
|
Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report. | |
|
32-64
|
Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report. | |
|
101.INS
|
XBRL Instance Document | |
|
101.SCH
|
XBRL Taxonomy Extension Schema | |
|
101.CAL
|
XBRL Taxonomy Extension Calculation Linkbase | |
|
101.DEF
|
XBRL Taxonomy Extension Definition Database | |
|
101.LAB
|
XBRL Taxonomy Extension Label Linkbase | |
|
101.PRE
|
XBRL Taxonomy Extension Presentation Linkbase |
145
Table of Contents
DTE
Energy Company
| Year Ending December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
|
Allowance for Doubtful Accounts (shown as deduction from
Accounts Receivable in the Consolidated Statements of Financial
Position)
|
||||||||||||
|
Balance at Beginning of Period
|
$ | 262 | $ | 265 | $ | 182 | ||||||
|
Additions:
|
||||||||||||
|
Charged to costs and expenses
|
113 | 155 | 198 | |||||||||
|
Charged to other accounts(1)
|
20 | 17 | 18 | |||||||||
|
Deductions(2)
|
(199 | ) | (175 | ) | (133 | ) | ||||||
|
Balance at End of Period
|
$ | 196 | $ | 262 | $ | 265 | ||||||
| (1) | Collection of accounts previously written off and, in 2008, balances previously held for sale of $4 million. | |
| (2) | Uncollectible accounts written off. |
146
Table of Contents
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
DTE ENERGY COMPANY
(Registrant)
(Registrant)
| By |
/s/
GERARD
M. ANDERSON
|
Gerard M. Anderson
President and
Chief Executive Officer
Date: February 18, 2011
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
date indicated.
|
By
|
/s/
GERARD
M. ANDERSON
|
By |
/s/
DAVID
E. MEADOR
|
|||
|
|
|
|||||
|
Gerard M. Anderson
President and Chief Executive Officer and Director |
David E. Meador
Executive Vice President and Chief Financial Officer |
|||||
|
By
|
/s/
PETER
B. OLEKSIAK
|
By |
/s/
GAIL
J. MCGOVERN
|
|||
|
|
|
|||||
|
Peter B. Oleksiak
Vice President, Controller and Chief Accounting Officer |
Gail J. McGovern, Director | |||||
|
By
|
/s/
LILLIAN
BAUDER
|
By |
/s/
EUGENE
A. MILLER
|
|||
|
|
|
|||||
| Lillian Bauder, Director | Eugene A. Miller, Director | |||||
|
By
|
/s/
DAVID
A. BRANDON
|
By |
/s/
MARK
A. MURRAY
|
|||
|
|
|
|||||
| David A. Brandon, Director | Mark A. Murray, Director | |||||
|
By
|
/s/
ANTHONY
F. EARLEY, JR.
|
By |
/s/
CHARLES
W. PRYOR, JR.
|
|||
|
|
|
|||||
|
Anthony F. Earley, Jr.
Executive Chairman and Director |
Charles W. Pryor, Jr., Director | |||||
|
By
|
/s/
W.
FRANK FOUNTAIN, JR.
|
By |
/s/
JOSUE
ROBLES, JR.
|
|||
|
|
|
|||||
| W. Frank Fountain, Jr., Director | Josue Robles, Jr., Director | |||||
|
By
|
/s/
ALLAN
D. GILMOUR
|
By |
/s/
RUTH
G. SHAW
|
|||
|
|
|
|||||
| Allan D. Gilmour, Director | Ruth G. Shaw, Director | |||||
|
By
|
/s/
FRANK
M. HENNESSEY
|
By |
/s/
JAMES
H. VANDENBERGHE
|
|||
|
|
|
|||||
| Frank M. Hennessey, Director | James H. Vandenberghe, Director | |||||
|
By
|
/s/
JOHN
E. LOBBIA
|
|||||
|
|
||||||
| John E. Lobbia, Director |
Date: February 18, 2011
147
TABLE OF CONTENTS
Part IItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 3. Legal ProceedingsPart IIItem 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataNote 1 Organization and Basis Of PresentationNote 2 Significant Accounting PoliciesNote 3 New Accounting PronouncementsNote 4 Fair ValueNote 5 Financial and Other Derivative InstrumentsNote 6 GoodwillNote 7 Property, Plant and EquipmentNote 8 Jointly Owned Utility PlantNote 9 Asset Retirement ObligationsNote 10 Disposals and Discontinued OperationsNote 11 Other Impairments and RestructuringNote 12 Regulatory MattersNote 13 Income TaxesNote 14 Common StockNote 15 Earnings Per ShareNote 16 Long-term DebtNote 17 Preferred and Preference SecuritiesNote 18 Short-term Credit Arrangements and BorrowingsNote 19 Capital and Operating LeasesNote 20 Commitments and ContingenciesNote 21 Retirement Benefits and Trusteed AssetsNote 22 Stock-based CompensationNote 23 Supplemental Cash Flow InformationNote 24 Segment and Related InformationNote 25 Supplementary Quarterly Financial Information (unaudited)Item 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accountant Fees and ServicesPart IVItem 15. Exhibits and Financial Statement Schedules