SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2011

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a)           Nature of Operations—We are a holding company whose primary wholly owned subsidiaries at December 31, 2011, included WPS, UPPCO, MGU, MERC, PGL, NSG, IBS, Integrys Energy Services, and ITF. Of these subsidiaries, six are regulated electric and/or natural gas utilities, one, IBS, is a centralized service company, one, Integrys Energy Services, is a nonregulated retail energy supply and services company, and one, ITF, is a nonregulated compressed natural gas fueling business. In addition, we have an approximate 34% interest in ATC.

As used in these notes, the term “financial statements” refers to the consolidated financial statements. This includes the consolidated statements of income, consolidated balance sheets, consolidated statements of equity, and consolidated statements of cash flows, unless otherwise noted.

The term “utility” refers to the regulated activities of the electric and natural gas utility companies, while the term “nonutility” refers to the activities of the electric and natural gas utility companies that are not regulated. The term “nonregulated” refers to activities at Integrys Energy Services, ITF, the Integrys Energy Group holding company, and the PELLC holding company.

(b)           Consolidated Basis of Presentation—The financial statements include our accounts and the accounts of all of our majority owned subsidiaries, after eliminating intercompany transactions and balances. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities. The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in businesses not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. For more information on equity method investments, see Note 9, “Investments in Affiliates, at Equity Method.”

(c)           Reclassifications—We reclassified $127.2 million reported in other current assets at December 31, 2010, to prepaid taxes to match the current year presentation on the balance sheet.

(d)           Use of Estimates—We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions that affect assets, liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

(e)           Cash and Cash Equivalents—Short-term investments with an original maturity of three months or less are reported as cash equivalents.

The following is supplemental disclosure to our statements of cash flows:

(Millions)	2011			2010			2009
Cash paid for interest	$	130.7		$	138.7		$	164.8
Cash (received) paid for income taxes	(80.0		)	(2.2		)	19.1

Significant noncash transactions were:

(Millions)	2011		2010		2009
Construction costs funded through accounts payable	$	58.6	$	18.3	$	30.4
Equity issued for stock-based compensation plans	15.8		3.0		—
Equity issued for reinvested dividends	5.4		22.6		—
Intangible assets (customer contracts) received in exchange for risk management assets	—		—		17.0

(f)            Revenues and Customer Receivables—Revenues related to the sale of energy are recognized when service is provided or energy is delivered to customers and include estimated amounts for services provided but not billed. At December 31, 2011 and 2010, our unbilled revenues were $282.1 million and $339.1 million, respectively. At December 31, 2011, there were no customers or industries that accounted for more than 10% of our revenues. We present revenue net of pass-through taxes on the income statements.

Our utility subsidiaries have various rate-adjustment mechanisms in place that currently provide for the recovery of prudently incurred electric fuel costs, purchased power costs, and natural gas costs, which allow subsequent adjustments to rates for changes in commodity costs. Other mechanisms also allow recovery for environmental costs, conservation improvement program (CIP) costs, bad debts, and energy conservation and management programs. A summary of significant rate-adjustment mechanisms follows:

·Fuel and purchased power costs are recovered from customers on a one-for-one basis by UPPCO, WPS’s wholesale electric operations, and WPS’s Michigan retail electric operations.

·WPS’s Wisconsin retail electric operations use a “fuel window” mechanism to recover fuel and purchased power costs. Under the fuel window rules effective January 1, 2011, a deferral is required for under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. Under or over-collections deferred in the current year are recovered or refunded in a future rate proceeding.

·The rates for all of our natural gas utilities include one-for-one recovery mechanisms for natural gas commodity costs.

·The rates of PGL and NSG include riders for cost recovery of both environmental cleanup and energy conservation and management program costs.

·MERC’s rates include a CIP rider for cost recovery of energy conservation and management program costs as well as recovery of a financial incentive for meeting energy savings goals.

·The rates of PGL, NSG, and MGU include riders for cost recovery or refund of bad debts based on the difference between actual bad debt cost (as defined in the latest rate order) and the amount recovered in rates.

·Decoupling mechanisms were in place at WPS, PGL, NSG, MGU, and UPPCO for 2011. These mechanisms differ state by state and allow utilities to adjust rates going forward to recover or refund all or a portion of the differences between actual and authorized margins.

Revenues are also impacted by other accounting policies related to PGL’s natural gas hub and our utility subsidiaries’ participation in the MISO market. Amounts collected from PGL’s wholesale customers that use the natural gas hub are credited to natural gas costs, resulting in a reduction to retail customers’ charges for natural gas and services. WPS and UPPCO both sell and purchase power in the MISO market. If WPS or UPPCO is a net seller in a particular hour, the net amount is reported as revenue. If WPS or UPPCO is a net purchaser in a particular hour, the net amount is recorded as utility cost of fuel, natural gas, and purchased power on the income statements.

ITF accounts for revenues from construction management projects with the percentage of completion method. Revenue is measured by the percentage of costs incurred to date to the estimated total costs for each contract. This method is used because management considers total costs to be the best available measure of progress on these contracts.

See Note 1(h), “Risk Management Activities,” for more information on the classification of certain unrealized gains and losses on derivative instruments in revenues.

(g)           Inventories—Inventories consist of natural gas in storage, liquid propane, and fossil fuels, including coal. Average cost is used to value fossil fuels, liquid propane, and natural gas in storage for the regulated utilities, excluding PGL and NSG. PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. Inventories stated on a LIFO basis represented approximately 37% of total inventories at December 31, 2011, and 34% of total inventories at December 31, 2010. The estimated replacement cost of natural gas in inventory at December 31, 2011, and December 31, 2010, exceeded the LIFO cost by approximately $65.7 million and $136.7 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per dekatherm of $3.06 at December 31, 2011, and $4.42 at December 31, 2010.

Inventories at Integrys Energy Services are valued at the lower of cost or market. Integrys Energy Services recorded net write-downs of $11.6 million, $0.9 million, and $44.2 million in 2011, 2010, and 2009, respectively.

(h)           Risk Management Activities—As part of our regular operations, we enter into contracts, including options, swaps, futures, forwards, and other contractual commitments, to manage market risks such as changes in commodity prices and interest rates, which are described more fully in Note 2, “Risk Management Activities.”  Derivative instruments at the utilities are entered into in accordance with the terms of the risk management plans approved by their respective Boards of Directors and, if applicable, by their respective regulators.

All derivatives are recognized on the balance sheets at their fair value unless they are designated as and qualify for the normal purchases and sales exception. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Most energy-related physical and financial derivatives at the utilities qualify for regulatory deferral. These derivatives are marked to fair value; the resulting risk management assets are offset with regulatory liabilities or decreases to regulatory assets, and risk management liabilities are offset with regulatory assets or decreases to regulatory liabilities. Management believes any gains or losses resulting from the eventual settlement of these derivative instruments will be refunded to or collected from customers in rates.

We classify unrealized gains and losses on derivative instruments that do not qualify for hedge accounting or regulatory deferral as a component of margins or operating and maintenance expense, depending on the nature of the transactions. Unrealized gains and losses on fair value hedges are recognized in current earnings, as are the changes in fair value of the hedged items. To the extent they are effective, the changes in the values of contracts designated as cash flow hedges are included in other comprehensive income, net of taxes. Fair value hedge ineffectiveness and cash flow hedge ineffectiveness are recorded in revenue, operating and maintenance expense, or interest expense on the statements of income, based on the nature of the transactions. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on the statements of cash flows unless the derivative contracts contain an other-than-insignificant financing element, in which case the cash flows are classified within financing activities.

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On the balance sheets, cash collateral provided to others is shown separately as collateral on deposit, and cash collateral received from others is reflected in other current liabilities.

We have risk management contracts with various counterparties. We monitor credit exposure levels and the financial condition of our counterparties on a continuous basis to minimize credit risk. At December 31, 2011, we did not have risk management contracts with any one counterparty or industry that accounted for more than 10% of our total credit risk exposure.

(i)            Emission Allowances—Integrys Energy Services accounts for emission allowances as intangible assets, with cash inflows and outflows related to purchases and sales of emission allowances recorded as investing activities in the Statements of Cash Flows. The utilities account for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating the utilities’ generation plants. Gains on sales of allowances at the utilities are returned to ratepayers. Losses on emission allowances at the utilities are included in the costs subject to the fuel window rules.

(j)            Property, Plant, and Equipment—Utility plant is stated at original cost, including any associated AFUDC and asset retirement costs. The costs of renewals and betterments of units of property (as distinguished from minor items of property) are capitalized as additions to the utility plant accounts. Except for land, no gains or losses are recognized in connection with ordinary retirements of utility property units. The utilities charge the cost of units of property retired, sold, or otherwise disposed of, less salvage value, to accumulated depreciation. In addition, the utilities record a regulatory liability for cost of removal accruals, which are included in rates. Actual removal costs are charged against the regulatory liability as incurred. Maintenance, repair, replacement, and renewal costs associated with items not qualifying as units of property are considered operating expenses. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates as approved by the applicable regulators. Annual utility composite depreciation rates are shown below. WPS received approval from the PSCW for lower depreciation rates, effective January 1, 2011.

Annual Utility Composite Depreciation Rates	2011		2010		2009
WPS — Electric	2.88	%	3.05	%	3.04	%
WPS — Natural gas	2.22	%	3.28	%	3.30	%
UPPCO	3.33	%	3.18	%	3.05	%
MGU	2.73	%	3.55	%	2.66	%
MERC	3.10	%	3.08	%	3.10	%
PGL	3.18	%	3.10	%	2.29	%
NSG	2.42	%	2.35	%	1.66	%

The majority of nonregulated plant is stated at cost, net of impairments recorded, and includes capitalized interest. The costs of renewals, betterments, and major overhauls are capitalized as additions to plant. Nonregulated plant acquired as a result of mergers and acquisitions have been recorded at fair value. The gains or losses associated with ordinary retirements are recorded in the period of retirement. Maintenance, repair, and minor replacement costs are expensed as incurred. Depreciation is computed for the majority of the nonregulated subsidiaries’ assets using the straight-line method over the assets’ useful lives.

We capitalize certain costs related to software developed or obtained for internal use and amortize those costs to operating expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statements.

See Note 6, “Property, Plant, and Equipment,” for details regarding our property, plant, and equipment balances.

(k)           Capitalized Interest and AFUDC—Our nonregulated subsidiaries capitalize interest for construction projects; however, interest capitalized was not significant during 2011, 2010, and 2009. Our utilities capitalize the cost of funds used for construction using a calculation that includes both internal equity and external debt components, as required by regulatory accounting. The internal equity component of capitalized AFUDC is accounted for as other income, and the external debt component is accounted for as a decrease to interest expense.

Approximately 50% of WPS’s retail jurisdictional construction work in progress expenditures are subject to the AFUDC calculation. For 2011, WPS’s average AFUDC retail rate was 7.71%, and its average AFUDC wholesale rate was 4.16%. WPS’s allowance for equity funds used during construction for 2011, 2010, and 2009 was $0.6 million, $0.7 million, and $5.1 million, respectively. WPS’s allowance for borrowed funds used during construction for 2011, 2010, and 2009 was $0.2 million, $0.3 million, and $2.0 million, respectively.

The AFUDC calculation for the other utilities and IBS is determined by the respective state commissions, each with specific requirements. Based on these requirements, the other utilities and IBS did not record significant AFUDC for 2011, 2010, or 2009.

(l)            Regulatory Assets and Liabilities—Regulatory assets represent probable future revenue associated with certain costs or liabilities that have been deferred and are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts collected in rates for future costs. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the year the determination is made. See Note 8, “Regulatory Assets and Liabilities,” for more information.

(m)          Asset Impairment—Goodwill and other intangible assets with indefinite lives are not amortized, but are subject to an annual impairment test. Other long-lived assets require an impairment review when events or circumstances indicate that the carrying amount may not be recoverable. We base our evaluation of other long-lived assets on the presence of impairment indicators such as the future economic benefit of the assets, any historical or future profitability measurements, and other external market conditions or factors. See Note 6, “Property, Plant, and Equipment,” for a discussion of recent impairments related to other long-lived assets.

Our reporting units containing goodwill perform annual goodwill impairment tests during the second quarter of each year, and interim impairment tests when impairment indicators are present. The carrying amount of the reporting unit’s goodwill is considered not recoverable if it exceeds the reporting unit’s fair value. An impairment loss is recorded for the excess of the carrying value of the goodwill over its implied fair value. For more information on our goodwill and other intangible assets, see Note 10, “Goodwill and Other Intangible Assets.”

The carrying amount of tangible long-lived assets held and used is considered not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value.

The carrying value of assets held for sale is not recoverable if it exceeds the fair value less estimated costs to sell the asset. An impairment loss is recorded for the excess of the asset’s carrying value over the fair value less estimated costs to sell.

The carrying values of cost and equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying values, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a loss is recognized equal to the amount by which the carrying value exceeds the investment’s fair value.

Integrys Energy Services evaluates emission allowances for impairment by comparing the expected undiscounted future cash flows to the carrying amount. When allowances are expected to be used for generation, the allowances are grouped with the related power plant in the impairment evaluation.

(n)           Retirement of Debt—Any call premiums or unamortized expenses associated with refinancing utility debt obligations are amortized consistent with regulatory treatment of those items, while gains or losses resulting from the retirement of utility debt that is not refinanced are either amortized over the remaining life of the original debt or recorded through current earnings. Any gains or losses resulting from the retirement of nonutility debt are recorded through current earnings.

(o)           Asset Retirement Obligations—We recognize legal obligations at fair value associated with the retirement of tangible long-lived assets that result from the acquisition, construction or development, and/or normal operation of the assets. A liability is recorded for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The asset retirement obligations are accreted using a credit-adjusted risk-free interest rate commensurate with the expected settlement dates of the asset retirement obligations; this rate is determined at the date the obligation is incurred. The associated retirement costs are capitalized as part of the related long-lived assets and are depreciated over the useful lives of the assets. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease in the carrying amount of the liability and the associated retirement cost. See Note 14, “Asset Retirement Obligations,” for more information.

(p)           Income Taxes—We file a consolidated United States income tax return that includes domestic subsidiaries of which our ownership is 80% or more. We and our consolidated subsidiaries are parties to a federal and state tax allocation arrangement under which each entity determines its provision for income taxes on a stand-alone basis. In several states, combined or consolidated filings are required for certain subsidiaries doing business in that state. The tax allocation arrangement equitably allocates the state taxes associated with these combined or consolidated filings.

Deferred income taxes have been recorded to recognize the expected future tax consequences of events that have been included in the financial statements by using currently enacted tax rates for the differences between the income tax basis of assets and liabilities and the basis reported in the financial statements. We record valuation allowances for deferred income tax assets when it is uncertain if the benefit will be realized in the future. Our regulated utilities defer certain adjustments made to income taxes that will impact future rates and record regulatory assets or liabilities related to these adjustments.

We use the deferral method of accounting for investment tax credits (ITCs). Under this method, we record the ITCs as deferred credits and amortize such credits as a reduction to the provision for income taxes over the life of the asset that generated the ITCs. Production tax credits generally reduce the provision for income taxes in the year that electricity from the qualifying facility is generated and sold. Investment tax credits and production tax credits that do not reduce income taxes payable for the current year are eligible for carryover and recognized as a deferred income tax asset. A valuation allowance is established unless it is more likely than not that the credits will be realized during the carryforward period.

We report interest and penalties accrued related to income taxes as a component of provision for income taxes in the income statements, as well as regulatory assets or regulatory liabilities on the balance sheets.

For more information regarding accounting for income taxes, see Note 15, “Income Taxes.”

(q)           Guarantees—Integrys Energy Group follows the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. For additional information on guarantees, see Note 17, “Guarantees.”

(r)           Employee Benefits —The costs of pension and other postretirement benefits are expensed over the periods during which employees render service. Our transition obligation related to other postretirement benefit plans that existed prior to the PELLC merger is being recognized over a 20-year period beginning in 1993. In computing the expected return on plan assets, we use a market-related value of plan assets. Changes in realized and unrealized investment gains and losses are recognized over the subsequent five years for plans sponsored by WPS, while differences between actual investment returns and the expected return on plan assets are recognized over a five-year period for pension plans sponsored by IBS and PELLC. The benefit costs associated with employee benefit plans are allocated among our subsidiaries based on employees’ time reporting and actuarial calculations, as applicable. Our regulators allow recovery in rates for the regulated utilities’ net periodic benefit cost calculated under GAAP.

We recognize the funded status of defined benefit postretirement plans on the balance sheet, and recognize changes in the plans’ funded status in the year in which the changes occur. Our nonregulated segments record changes in the funded status in other comprehensive income, and the regulated utilities record these changes in regulatory asset or liability accounts.

For additional information on our employee benefits, see Note 18, “Employee Benefit Plans.”

(s)           Fair Value—A fair value measurement is required to reflect the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Transaction costs should not be considered in the determination of fair value.

Fair value is 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 (exit price). We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities.

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methodologies.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

We determine fair value using a market-based approach that uses observable market inputs where available, and internally developed inputs where observable market data is not readily available. For the unobservable inputs, consideration is given to the assumptions that market participants would use in valuing the asset or liability. These factors include not only the credit standing of the counterparties involved, but also the impact of our nonperformance risk on our liabilities.

When possible, we base the valuations of our risk management assets and liabilities on quoted prices for identical assets in active markets. These valuations are classified in Level 1. The valuations of certain contracts include inputs related to market price risk (commodity or interest rate), price volatility (for option contracts), price correlation (for cross commodity contracts), credit risk, and time value. These inputs are available through multiple sources, including brokers and over-the-counter and online exchanges. Transactions valued using these inputs are classified in Level 2.

Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:

·While price curves may have been based on observable information, significant assumptions may have been made regarding seasonal or monthly shaping and locational basis differentials.

·Certain transactions were valued using price curves that extended beyond the quoted period. Assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term, primarily through the use of historically settled data or correlations to other locations.

We recognize transfers between the levels of the fair value hierarchy at the value as of the end of the reporting period.

See Note 23, “Fair Value,” for additional information.

(t)            New Accounting Pronouncements—ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS),” was issued in May 2011. The amendments change the wording used to describe the requirements for measuring fair value and for disclosing information about fair value measurements. The amendments also clarify the intent concerning the application of existing fair value measurement requirements. This guidance is effective for our reporting period ending March 31, 2012. Management is currently evaluating the impact that the adoption of this standard will have on our financial statements.

ASU 2011-05, “Presentation of Comprehensive Income,” was issued in June 2011. The guidance requires that the total of comprehensive income, the components of net income, and the components of OCI be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The FASB has deferred the requirement regarding the presentation of reclassification adjustments between OCI and net income on the face of the financial statements. This guidance is effective for our reporting period ending March 31, 2012, and is expected to change the format of our financial statements.

ASU 2011-08, “Testing Goodwill for Impairment,” was issued in September 2011. The amendments give companies an option to first perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If a company concludes that this is the case, the quantitative impairment test is required. Otherwise, a company can bypass the quantitative impairment test. This guidance is effective for our reporting period ending March 31, 2012, and is not expected to have a significant impact on our financial statements.

ASU 2011-11, “Disclosures about Offsetting Assets and Liabilities,” was issued in December 2011. The guidance requires enhanced disclosures about offsetting and related arrangements. This guidance is effective for our reporting period ending March 31, 2013. Management is currently evaluating the impact that the adoption of this standard will have on our financial statements.