DTE Energyis a diversified energy company with 2013 operating revenues of approximately $9.7 billionand approximately $26 billionin assets. We are the parent company of DTE Electricand DTE Gas, regulated electric and natural gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout Michigan. We operate three energy-related non-utility segments with operations throughout the United States.
The following table summarizes our financial results:
(In millions, except per share amounts) Income from continuing operations $ 668
$ 674 $ 723Diluted earnings per common share from continuing operations $ 3.76 $ 3.88 $ 4.20The decrease in 2013 income from continuing operations is primarily due to lower earnings in the Energy Trading segment, partially offset by higher earnings in the Gas and Power and Industrial Projects segments. The decrease in 2012 income from continuing operations is principally driven by an income tax benefit of $87 millionin the Corporate and Other segment related to the enactment of the MCIT in the second quarter of 2011 and lower results in the Energy Trading segment, partially offset by improved results in the Electric segment.
Please see detailed explanations of segment performance in the following Results of Operations section.
Our utilities' growth will be driven by environmental and renewable investments in addition to base infrastructure investments. We are focused on executing plans to achieve operational excellence and customer satisfaction with a focus on customer affordability. We operate in a constructive regulatory environment and have solid relationships with our regulators.
We have significant investments in our non-utility businesses. We employ disciplined investment criteria when assessing meaningful, low-risk growth opportunities that leverage our assets, skills and expertise and provide diversity in earnings and geography. 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.
A key priority for
DTE Energyis to maintain a strong balance sheet which facilitates access to capital markets and reasonably priced short-term and long-term financing. Near-term growth will be funded through internally generated cash flows, issuance of debt and issuance of equity through our dividend reinvestment plan and pension and other employee benefit plans. We have an enterprise risk management program that, among other things, is designed to monitor and manage our exposure to earnings and cash flow volatility related to commodity price changes, interest rates and counterparty credit risk.
Our utility businesses require significant base capital investments each year in order to maintain and improve the reliability of asset bases, including power generation plants, distribution systems, storage fields and other facilities and fleets.
DTE Electric'scapital investments over the 2014-2018 period are estimated at $5.6 billionfor base infrastructure, $700 millionfor mandated environmental compliance requirements and $400 millionfor renewable energy and energy efficiency expenditures. DTE Electricplans to seek regulatory approval in general rate case filings and renewable energy plan filings for capital expenditures consistent with prior ratemaking treatment. DTE Gas'scapital investments over the 2014-2018 period are estimated at $700 millionfor base infrastructure and $500 millionfor gas main renewal, meter move out and pipeline integrity programs. In April 2013, the MPSC issued an order approving an infrastructure recovery mechanism (IRM) and authorized the recovery of the cost of service related to $77 millionof annual investment in its gas main renewal and meter move out and pipeline integrity programs. DTE Gasplans to seek regulatory approval in general rate case filings for base infrastructure capital expenditures consistent with prior ratemaking treatment. 25
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.
DTE Electricis subject to the EPAozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPAand the State of Michiganhave issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. These rules will lead to additional emission controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, acid gases, particulate matter and mercury emissions. To comply with these requirements, DTE Electrichas spent approximately $2.0 billionthrough 2013. It is estimated that DTE Electricwill make capital expenditures of approximately $280 millionin 2014 and up to approximately $1.2 billionof additional capital expenditures through 2021 based on current regulations. Climate regulation and/or legislation has been proposed and discussed within the U.S. Congressand the EPA. The EPAis implementing regulatory actions under the Clean Air Act to address emissions of greenhouse gases (GHGs). EPAregulation of GHGs requires the best available control technology (BACT) for new major sources or modifications to existing major sources that cause significant increases in GHG emissions. In June 2012, the EPAproposed new source performance standards for carbon dioxide emissions from new fossil-fueled power plants. These new source performance standards were re-proposed on September 20, 2013, under a presidential directive issued on June 25, 2013. Under the same presidential directive, the EPAis expected to propose performance standards for carbon dioxide emissions from existing and modified plants by June 1, 2014and issue final standards by June 1, 2015. DTE Energywill be an active participant in working with the EPAand other stakeholders to shape the final performance standards for new and existing power plants. The standards for new sources are not expected to have a material impact on the Company. It is not possible to determine the potential impact of future regulations on existing sources at this time. 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 per MPSC protocols. Increased costs for energy produced from traditional coal based sources could also increase the economic viability of energy produced from renewable and/or nuclear sources, from energy efficiency initiatives, and from the potential development of market-based trading of carbon offsets which could provide new business opportunities for our utility and non-utility segments. At the present time, it is not possible to quantify the financial implication of these climate related legislative or regulatory initiatives on DTE Energyor its customers.
See Note 19 of the Notes to the Consolidated Financial Statements and Items 1. and 2. Business and Properties for further discussion of Environmental Matters.
The next few years will be a period of rapid change for
Looking forward, we will focus on several areas that we expect will improve future performance:
• electric and gas customer satisfaction;
• electric reliability;
• rate competitiveness and affordability;
• regulatory stability and investment recovery for our utilities;
• growth of our utility asset base;
• employee engagement;
• cost structure optimization across all business segments;
• cash, capital and liquidity to maintain or improve our financial strength; and
• investments 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.
(In millions) Net Income (Loss) Attributable to
DTE Energyby Segment: Electric $ 484 $ 483 $ 434Gas 143 115 110 Gas Storage and Pipelines 70 61 57 Power and Industrial Projects 66 42 38 Energy Trading (58 ) 12 52 Corporate and Other (44 ) (47 ) 23 Income From Continuing Operations Attributable to DTE Energy Company 661 666
Discontinued Operations - (56 ) (3 ) Net Income Attributable to DTE Energy Company
$ 661 $ 610 $ 711ELECTRIC
Our Electric segment consists principally of
Electric results are discussed below:
2013 2012 2011 (In millions) Operating Revenues
$ 5,199 $ 5,293 $ 5,154Fuel and Purchased Power 1,668 1,758 1,716 Gross Margin 3,531 3,535 3,438 Operation and Maintenance 1,377 1,429 1,370 Depreciation and Amortization 902 827
Taxes Other Than Income 261 257
Asset (Gains) and Losses, Reserves and Impairments, Net (3 ) (2 ) 13 Operating Income
Other (Income) and Deductions 258 261
Income Tax Expense 252 280
Net Income Attributable to DTE Energy Company
$ 484 $ 483 $ 434Operating Income as a % of Operating Revenues 19 % 19
% 19 %
Gross margin decreased by
$4 millionin 2013 and increased $97 millionin 2012. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statements of Operations. 27 --------------------------------------------------------------------------------
The following table details changes in various gross margin components relative to the comparable prior period:
2013 2012 (In millions) Base sales, inclusive of weather effect
$ (54 ) $ 79
Restoration tracker, discontinued in
39 25 Renewable energy program 19 35 Low income energy assistance surcharge (12 ) 4 Regulatory mechanisms and other 4 1 Increase (decrease) in gross margin
$ (4 ) $ 972013 2012 2011 (In thousands of MWh) Electric Sales Residential 15,273 15,666 15,907 Commercial 16,661 16,832 16,779 Industrial 10,303 9,989 9,739 Other 942 958 3,136 43,179 43,445 45,561 Interconnection sales (a) 3,883 2,125 3,512 Total Electric Sales 47,062 45,570 49,073 Electric Deliveries Retail and Wholesale 43,179 43,445 45,561
Electric Customer Choice, including self generators (b) 5,200 5,197
Total Electric Sales and Deliveries 48,379 48,642
(a) Represents power that is not distributed by
(b) Represents deliveries for self generators who have purchased power from
alternative energy suppliers to supplement their power requirements.
Operation and maintenance expense decreased
$52 millionin 2013 and increased $59 millionin 2012. The decrease in 2013 is primarily due to lower employee benefit expenses of $90 million, lower power plant generation expenses of $14 millionand reduced low income energy assistance of $12 million, partially offset by higher restoration and line clearance expenses of $19 million, higher corporate administrative expenses of $17 million, increased uncollectible expenses of $11 million, higher energy optimization and renewable energy expenses of $8 million, and increased distribution operations expenses of $8 million. The increase in 2012 is primarily due to higher employee benefit expenses of $53 million, increased energy optimization and renewable energy expenses of $17 million, higher power plant generation expenses of $12 million, increased distribution operations expenses of $4 millionand higher expenses for low income energy assistance of $4 million, partially offset by reduced restoration and line clearance expenses of $22 millionand reduced uncollectible expenses of $9 million. Depreciation and amortization expense increased $75 millionin 2013 and $9 millionin 2012. The 2013 increase was due to higher amortization of regulatory assets of $57 million, primarily related to Securitization, and increased depreciation of $18 milliondue to a higher depreciable base. The 2012 increase was due to higher amortization of regulatory assets of $43 million, primarily related to Securitization, partially offset by the net effect of $34 millionof lower depreciation rates on a higher depreciable base. Asset (gains) and losses, reserves and impairments, net increased $1 millionin 2013 and increased $15 millionin 2012. The 2012 increase was primarily due to a 2011 accrual of $19 millionresulting from management's revisions of the timing and estimate of cash flows for the decommissioning of Fermi 1, partially offset by a 2011 revision of $6 millionin the timing and estimate of cash flows for the Fermi 1 asbestos removal obligation and other items. Other (income) and deductions were lower by $3 millionin 2013 and by $37 millionin 2012. The decrease in 2013 was primarily due to 2012 one time expenses of $11 millionrelated to Michiganballot proposals and higher 2013 investment earnings of $10 million, offset by the 2013 contribution to the DTE Energy Foundationof $18 million. The decrease in 2012 was due primarily to the 2011 contribution to the DTE Energy Foundationof $21 millionand lower interest expense of $17 million. 28
-------------------------------------------------------------------------------- Income tax expense decreased
$28 millionin 2013 and increased $15 millionin 2012. The variances were impacted by variations in pre-tax income and higher production tax credits. Outlook - We continue to move forward in our efforts to achieve operational excellence, sustained strong cash flows and earn our authorized return on equity. We expect that our planned significant environmental expenditures will result in earnings growth. Looking forward, additional factors may impact earnings such as weather, the outcome of regulatory proceedings, benefit plan design changes, investment returns and changes in discount rate assumptions in benefit plans and health care costs, and uncertainty of legislative or regulatory actions regarding climate change and electric customer choice. We expect to continue our efforts to improve productivity and decrease our costs while improving customer satisfaction with consideration of customer rate affordability. In June 2013, the City of Detroitannounced a transition of its Public Lighting Department'scustomers to the DTE Electricdistribution system over a five to seven year system conversion period. See Note 11 of the Notes to Consolidated Financial Statements. GAS
Our Gas segment consists of
Gas results are discussed below:
2013 2012 2011 (In millions) Operating Revenues
$ 1,474 $ 1,315 $ 1,505Cost of Gas 624 550 744 Gross Margin 850 765 761 Operation and Maintenance 429 385 394 Depreciation and Amortization 95 92 89 Taxes Other Than Income 56 54 54 Operating Income 270 234 224 Other (Income) and Deductions 50 69
Income Tax Expense 77 50
Net Income Attributable to
Gross margin increased
$85 millionin 2013 and increased $4 millionin 2012. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statements of Operations.
The following table details changes in various gross margin components relative to the comparable prior period:
2013 2012 (In millions) Weather
$ 72 $ (41 )Uncollectible tracking mechanism 20 - Lost and stolen gas 9 29 Self implementation and rate orders 15 5 Revenue decoupling mechanism (16 ) 11 Energy optimization revenue (3 ) 6 Midstream storage and transportation revenues (8 ) 6 Other (4 ) (12 ) Increase in gross margin $ 85 $ 429
2013 2012 2011 Gas Markets (in Bcf) Gas sales 128 104 123 End user transportation 157 157 141 285 261 264
Intermediate transportation 300 264 273
585 525 537 Operation and maintenance expense increased
$44 millionin 2013 and decreased $9 millionin 2012. The increase in 2013 is primarily due to higher gas operations expenses of $24 million, higher maintenance and repair costs of $14 million, higher transmission costs of $14 million, higher corporate administrative expenses of $8 millionand increased uncollectible expenses of $5 million, partially offset by lower employee benefit expenses of $19 millionand reduced energy optimization expenses of $3 million. The decrease in 2012 is primarily due to reduced uncollectible expenses of $9 million, lower legal liability expenses of $4 millionand lower customer service expenses of $3 million, partially offset by increased energy optimization expenses of $6 millionand higher employee benefit expenses of $3 million. Other (income) and deductions were lower by $19 millionin 2013 and higher by $15 millionin 2012. The decrease in 2013 is due to lack of a contribution to the DTE Energy Foundationin 2013, partially offset by a $5 millioncontribution to low income energy assistance funds. The increase in 2012 was due primarily to the contribution to the DTE Energy Foundationof $21 million, partially offset by lower interest expenses of $5 million. Outlook - We continue to move forward in our efforts to achieve operational excellence, sustained strong cash flows and earn our authorized return on equity. We expect that our planned significant infrastructure capital expenditures will result in earnings growth. Looking forward, additional factors may impact earnings such as weather, the outcome of regulatory proceedings, benefit plan design changes, and investment returns and changes in discount rate assumptions in benefit plans and health care costs. We expect to continue our efforts to improve productivity and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.
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:
2013 2012 2011 (In millions) Operating Revenues
$ 132 $ 96 $ 91Operation and Maintenance 25 19 16 Depreciation and Amortization 23 8 6 Taxes Other Than Income 3 3 3
Asset (Gains) and Losses and Reserves, Net - 3 - Operating Income
81 63 66 Other (Income) and Deductions (36 ) (40 ) (28 ) Income Tax Expense 45 39 35 Net Income 72 64 59 Noncontrolling interest 2 3 2
Net Income Attributable to
Net income attributable to
DTE Energyincreased $9 millionand $4 millionin 2013 and 2012, respectively. Operating revenues increased $36 millionand Depreciation expense increased $15 millionin 2013 due to the operation of the Bluestone and Susquehannaprojects. The 2013 increase in Operating revenues was partially offset by lower storage revenue due to lower market rates. The 2012 increase in Net income was primarily driven by higher earnings from our pipeline equity investments. 30
-------------------------------------------------------------------------------- Outlook - Our Gas Storage and Pipelines business expects to maintain its steady growth by developing an asset portfolio with multiple growth platforms through investment in new projects and expansions.
Millennium Pipelinecompleted its Phase One expansion in 2013, and its Phase Two expansion is scheduled to be in service in 2014. Additionally, Bluestone, a 44-mile lateral pipeline in Susquehanna County, Pennsylvaniaand Broome County, New Yorkis in service and volumes are increasing. We plan to expand the capacity of the Bluestone lateral by constructing additional compression facilities, meter upgrades, and other initiatives to accommodate increased shipper demand. Through our agreement with Southwestern Energy Services Companyand affiliates, we believe Bluestone lateral and Susquehannagathering system are strategically positioned for future growth of the Marcellus shale.
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; produce reduced emissions fuel (REF) and sell electricity from biomass-fired energy projects.
Power and Industrial Projects results are discussed below:
2013 2012 2011 (In millions) Operating Revenues
$ 1,950 $ 1,823 $ 1,129Operation and Maintenance 1,914 1,788 1,025 Depreciation and Amortization 72 65 60 Taxes other than Income 15
Asset (Gains) and Losses, Reserves and Impairments, Net (4 ) (5 ) (12 ) Operating Income (Loss)
(47 ) (41 ) 46 Other (Income) and Deductions (73 ) (44 ) (10 ) Income Taxes Expense 8 - 17 Production Tax Credits (53 ) (44 ) (6 ) (45 ) (44 ) 11 Net Income 71 47 45 Noncontrolling interest 5 5 7 Net Income Attributable to DTE Energy Company
Operating revenues increased
$127 millionin 2013 and increased $694 millionin 2012. The 2013 increase is primarily due to a $161 millionincrease associated with higher volumes from REF projects, of which $25 millionrepresents affiliate transactions, and a $102 millionincrease due to the on-site energy projects acquired in the 2012 fourth quarter, partially offset by a $75 milliondecrease from exiting the coal transportation and marketing business, and a $63 milliondecrease due primarily to lower coal prices associated with the steel business. The 2012 increase is primarily due to a $740 millionincrease associated with higher volumes from REF projects, of which $554 millionrepresents affiliate transactions, and a $30 millionincrease due to the on-site energy projects acquired in the 2012 fourth quarter, partially offset by a $44 milliondecrease primarily due to lower volumes associated with the steel business, and a $28 milliondecrease in coal transportation and marketing services business. Operation and maintenance expense increased $126 millionin 2013 and increased $763 millionin 2012. The 2013 increase is primarily due to a $173 millionincrease associated with higher volumes from REF projects, of which $25 millionrepresents affiliate transactions and an $84 millionincrease due to the on-site energy projects acquired in the 2012 fourth quarter, partially offset by a $67 milliondecrease from exiting the coal transportation and marketing business, and a $67 milliondecrease due primarily to lower coal prices associated with the steel business. The 2012 increase is primarily due to a $770 millionincrease associated with higher volumes from REF projects, of which $562 millionrepresents affiliate transactions, a $25 millionincrease due to the on-site energy projects acquired in the 2012 fourth quarter and an $11 millioncustomer settlement, partially offset by a $20 milliondecrease primarily due to lower volumes associated with the steel business and a $26 milliondecrease in coal transportation and marketing services business. Depreciation and amortization expense increased by $7 millionin 2013 and increased by $5 millionin 2012. The 2013 increase is primarily due to $10 millionassociated with the on-site energy projects acquired in the 2012 fourth quarter, partially offset by a $3 milliondecrease from exiting the coal transportation and marketing business. The 2012 increase was primarily due to $4 millionassociated with the on-site energy projects acquired in the 2012 fourth quarter. 31
-------------------------------------------------------------------------------- Asset (gains) and losses, reserves and impairments, net decreased by
$1 millionin 2013 and decreased by $7 millionin 2012. The 2012 decrease was due primarily to a $3 millionloss on the sale of assets associated with our coal transloading terminal and $3 millionof impairments related to non-strategic assets. Other (income) and deductions were higher by $29 millionin 2013 and $34 millionin 2012 due primarily to income that is recognized when refined coal is produced and tax credits are generated.
Production tax credits increased by
Outlook - The Company has constructed and placed in service nine REF facilities including four facilities located at third party owned coal-fired power plants. The Company has sold membership interests in four of the facilities. We continue to optimize these facilities by seeking investors for facilities operating at
DTE Electricand other utility sites. Additionally, we intend to relocate two underutilized facilities, located at DTE Electricsites, to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2014 and future years. We expect sustained production levels of metallurgical coke and pulverized coal supplied to steel industry customers for 2014. Substantially all of the metallurgical coke margin is maintained under long-term contracts. We have four biomass-fired power generation facilities in operation, and we are converting an additional facility to be placed in service in 2014. Our on-site energy services will continue to be delivered in accordance with the terms of long-term contracts. We will begin construction on a new natural gas-fired cogeneration facility and two landfill gas to energy projects during the year which are expected to be completed in 2014. We will continue to look for additional investment opportunities and other energy projects at favorable prices.
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 focuses on physical and financial power, natural gas and coal marketing and trading, structured transactions, enhancement of returns from
DTE Energy'sasset portfolio, and optimization of contracted natural gas pipeline transportation and storage, and generating capacity positions. Energy Trading also provides natural gas, power and related services, which may include the management of associated storage and transportation contracts on the customers' behalf, and the supply or purchase of renewable energy credits to various customers.
Energy Trading results are discussed below:
2013 2012 2011 (In millions) Operating Revenues
$ 1,771 $ 1,109 $ 1,276Fuel, Purchased Power and Gas 1,782 1,011 1,112 Gross Margin (11 ) 98 164 Operation and Maintenance 72 66 63 Depreciation and Amortization 1 2 3 Taxes Other Than Income 4 3 3 Operating Income (Loss) (88 ) 27 95 Other (Income) and Deductions 8 8
Income Tax Expense (Benefit) (38 ) 7
Net Income (Loss) Attributable to
Gross margin decreased
$109 millionin 2013 and decreased $66 millionin 2012. The overall decrease in gross margin in 2013 was primarily due to timing from mark-to-market adjustments on certain transactions in our gas structured strategy. 32 -------------------------------------------------------------------------------- Natural gas structured transactions typically involve a physical purchase or sale of natural gas in the future and/or natural gas basis financial instruments which are derivatives and a related non-derivative pipeline transportation contract. These gas structured transactions can result in significant earnings volatility as the derivative components are marked-to-market without revaluing the related non-derivative contracts. During the fourth quarter of 2013, we saw significant increases in gas prices which led to the volatility in the accounting earnings due to the physical component being marked-to-market without an offsetting mark on the transportation component. Unrealized losses from gas structured transactions were $89 millionin 2013. We anticipate that approximately 65% of the financial impact of this timing difference will reverse during the first quarter of 2014 as the underlying contracts are settled. The decrease in gross margin in 2013 represents a $1 milliondecrease in realized margins and a $108 milliondecrease in unrealized margins. The $1 milliondecrease in realized margins is due to $40 millionof unfavorable results, primarily in our power trading, power full requirements, and gas transportation strategies, offset by $39 millionof favorable results, primarily in our gas and coal trading, and gas structured strategies. The $108 milliondecrease in unrealized margins is due to $123 millionof unfavorable results, primarily in our gas structured, gas trading and gas transportation strategies, offset by $15 millionof favorable results, primarily in our power full requirements strategy. The decrease in gross margin in 2012 represents a $28 milliondecrease in realized margins and a $38 milliondecrease in unrealized margins. The $28 milliondecrease in realized margins is due to $74 millionof unfavorable results, primarily in our power and gas trading and power full requirements services strategies, offset by $46 millionof favorable results, primarily in our gas full requirements services, gas structured, and gas transportation strategies. The $38 milliondecrease in unrealized margins is due to $58 millionof unfavorable results, primarily in our power and gas full requirements services, power trading, and gas structured and storage strategies, offset by $20 millionof favorable results, primarily in our gas trading strategy. Outlook - In the near term, we expect market conditions to remain challenging and the profitability of this segment may be impacted by the volatility 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. The Energy Trading portfolio includes financial instruments, physical commodity contracts and natural gas inventory, as well as contracted natural gas pipeline transportation and storage, and generation capacity positions. Energy Trading also provides natural gas, power and related services, which may include the management of associated storage and transportation contracts on the customers' behalf under FERC Asset Management Arrangements, and the supply or purchase of renewable energy credits to various customers. Significant portions of the Energy Trading portfolio are economically hedged. Most financial instruments and physical power and natural gas contracts are deemed derivatives, whereas natural gas inventory, pipeline transportation, renewable energy credits, and 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 AND OTHER
Corporate and Other includes various holding company activities and holds certain non-utility debt and energy-related investments.
The 2013 net loss of
The 2012 net loss of
$47 millionrepresented a decrease of $70 millionfrom the 2011 net income of $23 million. The decrease resulted primarily from a income tax benefit of $87 millionrelated to the enactment of the MCIT in the second quarter of 2011 and lower interest costs.
See Note 12 of the Notes to Consolidated Financial Statements in Item 8 of this report.
Unconventional Gas Production
December 2012, the Company sold its 100% equity interest in its Unconventional Gas Production business which consisted of gas and oil production assets in the western Barnettand Marble Fallsshale areas of Texas. See Note 7 of the Notes to Consolidated Financial Statements.
CAPITAL RESOURCES AND LIQUIDITY
We use cash to maintain and expand our electric and natural 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 2014, we expect that cash from operations will be
$1.6 billiondue to lower surcharge collections and higher cash contributions to employee benefit plans. We anticipate base level utility capital investments, environmental, renewable and energy optimization expenditures and expenditures for non-utility businesses in 2014 of approximately $2.3 billion. We plan to seek regulatory approval to include utility capital expenditures in our regulatory rate base consistent with prior treatment. Capital spending for growth of existing or new non-utility businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria. 2013 2012 2011 (In millions) Cash and Cash Equivalents Cash Flow From(Used For) Operating activities: Net income $ 668 $ 618 $ 720Depreciation, depletion and amortization 1,094 1,018
Nuclear fuel amortization 38 29
Allowance for equity funds used during construction (15 ) (13 ) (6 ) Deferred income taxes
Loss on sale of non-utility business - 83
Asset (gains) and losses, reserves and impairments, net (8 ) 1
(21 ) Working capital and other 213 426 54 2,154 2,209 2,008 Investing activities: Plant and equipment expenditures - utility (1,534 ) (1,451 ) (1,382 ) Plant and equipment expenditures - non-utility (342 ) (369 ) (102 ) Proceeds from sale of non-utility business - 255
Proceeds from sale of assets 36 38
Acquisition, net of cash acquired - (198 ) - Other (66 ) (44 ) (94 ) (1,906 ) (1,769 ) (1,560 ) Financing activities: Issuance of long-term debt 1,234 759 1,179 Redemption of long-term debt (961 ) (639 ) (1,455 ) Short-term borrowings, net (109 ) (179 ) 269 Issuance of common stock 39 39 - Repurchase of common stock - - (18 ) Dividends on common stock (445 ) (407 ) (389 ) Other (19 ) (16 ) (31 ) (261 ) (443
) (445 ) Net Increase (Decrease) in Cash and Cash Equivalents
Cash from Operating Activities
A majority of our operating cash flow is provided by our electric and natural gas utilities, which are significantly influenced by factors such as weather, electric Customer Choice, regulatory deferrals, regulatory outcomes, economic conditions and operating costs. 34 --------------------------------------------------------------------------------
Cash from operations was lower by
Cash from operations was
$201 millionhigher in 2012. The improvement in operating cash flow reflects higher cash generated from working capital items, partially offset by lower net income after adjusting for non-cash and non-operating items (primarily depreciation, depletion and amortization, deferred income taxes, loss on sale of non-utility business and asset (gains) and losses, reserves and impairments, net).
The change in working capital items in 2013 primarily related to fuel inventories, derivative assets and liabilities and pension and other postretirement liabilities, partially offset by the change in accounts receivable, net. The change in working capital items in 2012 primarily related to pension and other postretirement obligations and income taxes.
Cash used for Investing Activities
Cash inflows associated with investing activities are primarily generated from the sale of assets, while cash outflows are the result of plant and equipment expenditures. In any given year, we will look to realize cash from under-performing or non-strategic assets or matured fully valued assets.
Capital spending within the utility business is primarily to maintain and improve our electric generation and electric and natural gas distribution infrastructure and to comply with environmental regulations and renewable energy requirements.
Capital spending within our non-utility businesses is primarily for ongoing maintenance, expansion and growth. We look to make growth 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 higher by
Net cash used for investing activities was higher by
$209 millionin 2012 due primarily to increased capital expenditures by our utility and non-utility businesses. The 2012 increase includes higher capital expenditures for the Bluestone Pipeline project and the Power and Industrial Projects acquisition of fourteen on-site energy projects, partially offset by the proceeds from the sale of the Unconventional Gas Production business.
Cash used for 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
Net cash used for financing activities was
We expect cash flow from operations to increase over the long-term primarily as a result of growth from our utilities and non-utility businesses. We expect growth in our utilities to be driven primarily by capital spending to maintain and improve our electric generation and electric and natural gas distribution infrastructure and to comply with 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 primarily in our Gas Storage and Pipelines and Power and Industrial Projects segments. We may be impacted by the timing of collection or refund 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 millionin long-term debt maturing in the next twelve months. The repayment of the principal amount of the Securitization debt is funded through a surcharge payable by DTE Electric'scustomers. The repayment of the other debt is expected to be paid through internally generated funds or the issuance of long-term debt. DTE Energyhas approximately $1.6 billionof available liquidity at December 31, 2013, consisting of cash and amounts available under unsecured revolving credit agreements.
At the discretion of management, and depending upon financial market conditions, we anticipate making 2014 contributions to the pension plans of up to
Various 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'scredit rating is downgraded below investment grade. As of December 31, 2013, the value of the transactions for which the Company would have been exposed to collateral requests had DTE Energy'scredit rating been below investment grade on such date was approximately $406 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. In addition, the Company maintains adequate credit facilities to meet this obligation should such an occurrence arise. 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 11, 12, 15, 17, and 20 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of
December 31, 2013: 2019 Total 2014 2015-2016 2017-2018 and Beyond (In millions) Long-term debt: Mortgage bonds, notes and other (a) $ 7,326 $ 695 $ 836 $ 416 $ 5,379Securitization bonds 302 197 105 - - Junior subordinated debentures 480 - - - 480 Capital lease obligations 19 8 11 - - Interest 6,091 429 670 631 4,361 Operating leases 230 35 58 45 92 Electric, gas, fuel, transportation and storage purchase obligations (b) 8,499 2,577 1,802 645 3,475 Other long-term obligations (c)(d)(e) 99 40 36 11 12 Total obligations $ 23,046 $ 3,981 $ 3,518 $ 1,748 $ 13,799
(b) Excludes amounts associated with full requirements contracts where no stated
minimum purchase volume is required.
(c) Includes liabilities for unrecognized tax benefits of
(d) Excludes other long-term liabilities of
from contracts or other agreements.
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 other 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 herein and
in Note 20 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,
DTE Electric, DTE Gasand 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 Energyis downgraded below investment grade. Certain of these contracts for DTE Electricand DTE Gascontain 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 Energyis 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 Energyand 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. 37 -------------------------------------------------------------------------------- In January 2013, Fitch raised the senior secured debt rating for DTE Gasfrom 'A-' to 'A' and affirmed the senior unsecured debt rating for DTE Energyat 'BBB' and senior secured debt rating for DTE Electricat 'A'. The upgrade reflects improved earnings and cash flows following recent rate case orders, a constructive regulatory environment, and strong credit metrics. In February 2013, based on steady improvement in the financial profiles due in large part to a constructive legislative and regulatory environment, Moody's upgraded DTE Energy'sunsecured debt rating from 'Baa2' to 'Baa1' and upgraded the secured debt rating of DTE Electricand DTE Gasfrom 'A2' to 'A1'. In August 2013, S&P raised the credit outlook from 'stable' to 'positive' for DTE Energy, DTE Electric, and DTE Gaspointing to the Company's improving business risk profile. S&P also revised its business risk profile to 'excellent'. In January 2014, based on a favorable view of the U.S. regulatory environment, Moody's upgraded DTE Energy'sunsecured debt rating from 'Baa1' to 'A3' and upgraded the secured debt rating of DTE Electricand DTE Gasfrom 'A1' to 'Aa3'.
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.
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.
DTE Electricand DTE Gasare 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.
See Note 11 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
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
DTE Electricand DTE Gasmeet 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, 2013and 2012. 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 analyses 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 3 and 4 of the Notes to Consolidated Financial Statements in Item 8 of this Report. 38
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. We believe the allowance for doubtful accounts is based on reasonable estimates. 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 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, 2013and determined that the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. As part of the annual impairment test, 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.
Terminal Fair Value Multiple Valuation Reporting Unit Goodwill Reduction % (a) Discount Rate (b) Methodology (c) (In millions) DCF, assuming Electric
$ 1,20837 % 7 % 9.0x stock sale DCF, assuming Gas 743 29 % 6 % 10.5x stock sale Power and Industrial DCF, assuming Projects (d) 26 65 % 9 % 10.0x asset sale (e) Gas Storage and DCF, assuming Pipelines 24 84 % 8 % 11.0x asset sale DCF, assuming Energy Trading 17 15 % 11 % n/a asset sale $ 2,018
(a) Percentage by which the fair value of equity 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 2014-2018 projected cash flows
plus a calculated terminal value. (d) Power and Industrial Projects excludes the Biomass reporting unit as this
unit has no allocated goodwill. (e) Asset sales were assumed except for Power and Industrial Projects' reduced
emissions fuels projects, which assumed stock sales.
The Energy Trading reporting unit passed Step 1 of the impairment test by a 15% margin. A substantive increase in the market interest rate or disruptions in cash flows for the Energy Trading reporting unit could result in an impairment charge in the foreseeable future. For example, holding all other variables constant, a 2% increase in the discount rate would lower the fair value by approximately
$49 million. At the lower fair value, the Energy Trading reporting unit would likely fail Step 1 of the test, potentially resulting in a charge for impairment of goodwill following the completion of the Step 2 analysis. 39 -------------------------------------------------------------------------------- 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.
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.
Pension and Other Postretirement Costs
We sponsor defined benefit pension plans and other postretirement benefit plans for eligible 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, benefit plan design changes and the level of benefits provided to employees and retirees. Pension and other 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 of
$228 millionin 2013, $220 millionin 2012, and $172 millionin 2011. Other postretirement benefits costs (credit) were $(42) millionin 2013, $151 millionin 2012 and $122 millionin 2011. Pension and other postretirement benefits costs for 2013 are calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 8.25%. 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 2014 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 and financial market risk considerations, we are changing our long-term rate of return assumptions for our pension plans and our other postretirement health and life plans from 8.25% for 2013 to 7.75% for our pension plans and to 8% for our other postretirement health and life plans for 2014. We believe these rates are reasonable assumptions for the long-term rate of return on our plan assets for 2014 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 2013 contributed to our investment performance resulting in unrecognized net gains. As of December 31, 2013, we had $150 millionof cumulative gains that remain to be recognized in the calculation of the MRV of pension assets related to investment performance in 2013, 2012 and 2011. For our other postretirement benefit plans, we use fair value when determining the MRV of other postretirement benefit plan assets, therefore all investment gains and losses have been recognized in the calculation of MRV for these plans. 40 -------------------------------------------------------------------------------- The discount rate that we utilize for determining future pension and other 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 other postretirement benefit payment streams with bond portfolios reflecting actual liability duration unique to our plans. The discount rate determined on this basis increased to 4.95% at December 31, 2013from 4.15% at December 31, 2012. We estimate that our 2014 total pension costs will approximate $175 millioncompared to $228 millionin 2013 primarily due to greater than expected 2013 returns, a higher discount rate, lower amortization of net actuarial losses and 2014 contributions. Our 2014 other postretirement benefit credit will approximate $(120) millioncompared to $(42) millionin 2013 due to the continued impact of plan design changes, favorable retiree medical utilization trends, greater than expected returns, a higher discount rate, lower amortization of net actuarial losses and modestly lower assumed long-term retiree medical inflation. Our health care trend rate for pre-65 participants assumes 7.5% for 2014 and 2015, 7% for 2016 and 2017, 6.5% in 2018, 6% in 2019, 5.75% in 2020, 5.5% in 2021, 5.25% in 2022, 5% in 2023, 4.75% in 2024 and 4.5% in 2025 and beyond. Our health care trend rate for post-65 participants assumes 6.5% for 2014 and 2015, 6.25% for 2016 and 2017, 6% in 2018, 5.75% in 2019, 5.5% in 2020, 5.25% in 2021, 5% in 2022, 4.75% in 2023, 4.5% in 2024 and beyond. Future actual pension and other postretirement benefit costs will depend on future investment performance, changes in future discount rates and various other factors related to plan design. Lowering the expected long-term rate of return on our plan assets by one percentage point would have increased our 2013 pension costs by approximately $32 million. Lowering the discount rate and the salary increase assumptions by one percentage point would have increased our 2013 pension costs by approximately $16 million. Lowering the expected long-term rate of return on our plan assets by one percentage point would have increased our 2013 other postretirement costs by approximately $13 million. Lowering the discount rate assumption by one percentage point would have decreased our 2013 other postretirement credit by approximately $27 million. Lowering the health care cost trend assumptions by one percentage point would have increased our other postretirement credit for 2013 by approximately $8 million. The value of our qualified pension and other postretirement benefit plan assets was $5.2 billionat December 31, 2013and $4.4 billionat December 31, 2012. At December 31, 2013, our qualified pension plans were underfunded by $565 millionand our other postretirement benefit plans were underfunded by $351 million. The 2013 funding levels generally improved due to increased discount rates, investment returns in excess of expected returns, plan sponsor contributions and plan design changes for our other postretirement benefits plans in 2013 and 2012. Pension and other postretirement costs and pension cash funding requirements may increase in future years without typical returns in the financial markets. We made contributions to our qualified pension plans of $277 millionin 2013 and $229 millionin 2012. 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 qualified pension plans of up to $345 millionin 2014 and up to $1.0 billionover the next five years. We made other postretirement benefit plan contributions of $264 millionand $140 millionin 2013 and 2012, respectively. We are required by orders issued by the MPSC to make other postretirement benefit contributions at least equal to the amounts included in our utilities' base rates. As a result, we anticipate making up to a $145 millioncontribution to our other postretirement plans in 2014 and, subject to MPSC funding requirements, up to $165 millionover the next five years. The planned contributions will be made in cash, DTE Energycommon stock or a combination of cash and stock.
See Note 20 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.
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, 2013, this IBNR liability was approximately $36 million. 41 --------------------------------------------------------------------------------
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 carry-forwards, for which the benefits have already been reflected in the financial statements. We believe the resulting tax reserve balances as of
December 31, 2013and 2012 are appropriate. 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 12 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, natural 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, pipeline transportation, renewable energy credits and storage assets. See Notes 3 and 4 of the Notes to Consolidated Financial Statements in Item 8 of this Report. The tables below do not include the expected earnings impact of non-derivative natural gas storage, transportation, certain power contracts and renewable energy credits which are subject to accrual accounting. 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'sreported 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, the Company records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g. electricity or natural 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 Company has established a fair value hierarchy that 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 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
The following tables provide details on changes in our MTM net asset (or liability) position during 2013:
Total (In millions) MTM at December 31, 2012 $ (4 ) Reclassify to realized upon settlement (89 ) Changes in fair value recorded to income (11 ) Amounts recorded to unrealized income (100 ) Changes in fair value recorded in regulatory liabilities 5 Change in collateral held by (for) others (9 ) Option premiums received and other (5 ) Amounts recorded in other comprehensive income 1 MTM at December 31, 2013
$ (112 )42
The table below shows the maturity of our MTM positions:
2017 and Source of Fair Value 2014 2015 2016 Beyond Total Fair Value (In millions) Level 1
$ (3 )$ - $ - $ - $ (3 ) Level 2 (42 ) (20 ) (2 ) - (64 ) Level 3 (37 ) (2 ) 2 1 (36 )
MTM before collateral adjustments
(103 ) Collateral adjustments (9 ) MTM at December 31, 2013 $ (112 )