UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2011
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission |
| Registrant; State of Incorporation; |
| IRS Employer |
1-3016 |
| WISCONSIN PUBLIC SERVICE CORPORATION (A Wisconsin Corporation) |
| 39-0715160 |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o |
| Accelerated filer o |
|
|
|
Non-accelerated filer x |
| Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
| Common stock, $4 par value, |
WISCONSIN PUBLIC SERVICE CORPORATION
QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended September 30, 2011
|
|
| Page | ||||
|
|
|
| ||||
|
| 1 - 2 | |||||
|
|
|
| ||||
| 3 | ||||||
|
|
|
| ||||
| 3 | ||||||
|
|
|
| ||||
|
| 3 | |||||
|
| 4 | |||||
|
| 5 | |||||
|
| 6 | |||||
|
|
|
| ||||
| CONDENSED NOTES TO FINANCIAL STATEMENTS OF Wisconsin Public Service Corporation and Subsidiary |
| 7 — 24 | ||||
|
|
|
| ||||
|
|
|
|
| Page |
|
|
|
|
| 7 |
|
| ||
|
|
| 7 |
|
| ||
|
|
| 8 |
|
| ||
|
|
| 9 |
|
| ||
|
|
| 10 |
|
| ||
|
|
| 11 |
|
| ||
|
|
| 17 |
|
| ||
|
|
| 17 |
|
| ||
|
|
| 18 |
|
| ||
|
|
| 18 |
|
| ||
|
|
| 19 |
|
| ||
|
|
| 20 |
|
| ||
|
|
| 22 |
|
| ||
|
|
| 22 |
|
| ||
|
|
| 23 |
|
| ||
|
|
| 24 |
|
| ||
|
|
|
| ||||
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
| 25 — 40 | |||||
|
|
|
| ||||
| 41 | ||||||
|
|
|
| ||||
| 42 |
| 43 | ||
|
|
|
|
| 43 | ||
|
|
|
|
| 43 | ||
|
|
|
|
| 43 | ||
|
|
|
|
|
| 44 | |
|
|
|
|
|
| 45 |
|
| Commonly Used Acronyms in this Quarterly Report on Form 10-Q |
|
|
|
ASU |
| Accounting Standards Update |
|
|
|
ATC |
| American Transmission Company LLC |
|
|
|
BACT |
| Best Available Control Technology |
|
|
|
CAA |
| Clean Air Act |
|
|
|
CSAPR |
| Cross State Air Pollution Rule |
|
|
|
EPA |
| United States Environmental Protection Agency |
|
|
|
FTR |
| Financial Transmission Right |
|
|
|
GAAP |
| United States Generally Accepted Accounting Principles |
|
|
|
IRS |
| United States Internal Revenue Service |
|
|
|
ITC |
| Investment Tax Credit |
|
|
|
MISO |
| Midwest Independent Transmission System Operator, Inc. |
|
|
|
N/A |
| Not Applicable |
|
|
|
NOI |
| Notice of Intent |
|
|
|
NOV |
| Notice of Violation |
|
|
|
NYMEX |
| New York Mercantile Exchange |
|
|
|
PSCW |
| Public Service Commission of Wisconsin |
|
|
|
SEC |
| United States Securities and Exchange Commission |
|
|
|
WDNR |
| Wisconsin Department of Natural Resources |
|
|
|
WPS |
| Wisconsin Public Service Corporation |
|
|
|
WRPC |
| Wisconsin River Power Company |
In this report, we make statements concerning expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are subject to assumptions and uncertainties; therefore, actual results may differ materially from those expressed or implied by such forward-looking statements. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot provide assurance that such statements will prove correct.
Forward-looking statements include, among other things, statements concerning management’s expectations and projections regarding earnings, regulatory matters, fuel and natural gas costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, environmental expenditures, liquidity and capital resources, trends, estimates, completion of construction projects, and other matters.
Forward-looking statements involve a number of risks and uncertainties. Some risks that could cause results to differ from any forward-looking statement include those described in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010, as may be amended or supplemented in Part II, Item 1A of our subsequently filed Quarterly Reports on Form 10-Q (including this report). Other risks and uncertainties include, but are not limited to:
· | Resolution of pending and future rate cases and negotiations (including the recovery of deferred costs) and other regulatory decisions impacting us; |
· | The individual and cumulative impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric and natural gas utility industries; financial reform; health care reform; changes in environmental and other regulations, including but not limited to, greenhouse gas emissions, other environmental regulations impacting coal-fired generation facilities, energy efficiency mandates, renewable energy standards, and reliability standards; and changes in tax and other laws and regulations to which we and our subsidiary are subject; |
· | Current and future litigation and regulatory proceedings, enforcement actions or inquiries, including but not limited to, manufactured gas plant site cleanup, third-party intervention in permitting and licensing projects, and compliance with CAA requirements at generation plants; |
· | The impacts of changing financial market conditions, credit ratings, and interest rates on the liquidity and financing efforts of us and our subsidiary; |
· | The risks associated with changing commodity prices (particularly natural gas and electricity) and the available sources of fuel, natural gas, and purchased power, including their impact on margins, working capital, and liquidity requirements; |
· | Resolution of audits or other tax disputes with the IRS, Wisconsin Department of Revenue, Michigan Department of Treasury, or other revenue agencies; |
· | The effects, extent, and timing of additional competition or regulation in the markets in which we operate; |
· | Investment performance of employee benefit plan assets, including actuarial assumptions, and the related impact on future funding requirements; |
· | Changes in technology, particularly with respect to new, developing, or alternative sources of generation; |
· | Effects of and changes in political and legal developments, as well as economic conditions and the related impact on customer demand, including the ability to adequately forecast energy usage for our customers; |
· | Potential business strategies, including acquisitions and construction or disposition of assets or businesses, which cannot be assured to be completed timely or within budgets; |
· | The direct or indirect effects of terrorist incidents, natural disasters, or responses to such events; |
· | The effectiveness of risk management strategies, the use of financial and derivative instruments, and the ability to recover costs from customers in rates associated with the use of those strategies and financial and derivative instruments; |
· | The risk of financial loss, including increases in bad debt expense, associated with the inability of our and our subsidiary’s counterparties, affiliates, and customers to meet their obligations; |
· | Customer usage, weather and other natural phenomena; |
· | Contributions to earnings by non-consolidated equity method and other investments, which may vary from projections; |
· | The effect of accounting pronouncements issued periodically by standard-setting bodies; and |
· | Other factors discussed elsewhere herein and in other reports we and/or Integrys Energy Group file from time to time with the SEC. |
Except to the extent required by the federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.
WISCONSIN PUBLIC SERVICE CORPORATION
|
| Three Months Ended |
| Nine Months Ended |
| ||||||||
| September 30 |
| September 30 |
| |||||||||
(Millions) |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Operating revenues |
| $ | 376.8 |
| $ | 388.1 |
| $ | 1,169.6 |
| $ | 1,200.1 |
|
|
|
|
|
|
|
|
|
|
| ||||
Cost of fuel, natural gas, and purchased power |
| 168.2 |
| 164.3 |
| 545.9 |
| 540.0 |
| ||||
Operating and maintenance expense |
| 109.7 |
| 115.0 |
| 333.9 |
| 334.2 |
| ||||
Depreciation and amortization expense |
| 23.9 |
| 26.6 |
| 71.6 |
| 83.9 |
| ||||
Taxes other than income taxes |
| 11.8 |
| 11.5 |
| 36.0 |
| 35.0 |
| ||||
Operating income |
| 63.2 |
| 70.7 |
| 182.2 |
| 207.0 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Miscellaneous income |
| 2.9 |
| 3.0 |
| 10.1 |
| 10.3 |
| ||||
Interest expense |
| (11.1 | ) | (13.4 | ) | (39.4 | ) | (40.5 | ) | ||||
Other expense |
| (8.2 | ) | (10.4 | ) | (29.3 | ) | (30.2 | ) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Income before taxes |
| 55.0 |
| 60.3 |
| 152.9 |
| 176.8 |
| ||||
Provision for income taxes |
| 19.7 |
| 20.1 |
| 54.9 |
| 63.8 |
| ||||
Net income |
| 35.3 |
| 40.2 |
| 98.0 |
| 113.0 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Preferred stock dividend requirements |
| (0.7 | ) | (0.7 | ) | (2.3 | ) | (2.3 | ) | ||||
Net income attributed to common shareholder |
| $ | 34.6 |
| $ | 39.5 |
| $ | 95.7 |
| $ | 110.7 |
|
The accompanying condensed notes are an integral part of these statements.
WISCONSIN PUBLIC SERVICE CORPORATION
| September 30 |
| December 31 |
| |||
(Millions) |
| 2011 |
| 2010 |
| ||
|
|
|
|
|
| ||
Assets |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 5.3 |
| $ | 71.4 |
|
Accounts receivable and accrued unbilled revenues, net of reserves of $4.3 and $3.1, respectively |
| 162.2 |
| 203.9 |
| ||
Receivables from related parties |
| 4.1 |
| 4.2 |
| ||
Inventories |
| 95.6 |
| 70.4 |
| ||
Regulatory assets |
| 25.3 |
| 46.0 |
| ||
Materials and supplies, at average cost |
| 29.0 |
| 25.5 |
| ||
Prepaid taxes |
| 88.8 |
| 90.0 |
| ||
Other current assets |
| 14.8 |
| 16.7 |
| ||
Current assets |
| 425.1 |
| 528.1 |
| ||
|
|
|
|
|
| ||
Property, plant, and equipment, net of accumulated depreciation of $1,272.4 and $1,213.8, respectively |
| 2,339.0 |
| 2,345.7 |
| ||
Regulatory assets |
| 362.5 |
| 379.0 |
| ||
Receivables from related parties |
| 13.2 |
| 13.7 |
| ||
Goodwill |
| 36.4 |
| 36.4 |
| ||
Other long-term assets |
| 85.8 |
| 83.1 |
| ||
Total assets |
| $ | 3,262.0 |
| $ | 3,386.0 |
|
|
|
|
|
|
| ||
Liabilities and Shareholders’ Equity |
|
|
|
|
| ||
Short-term debt |
| $ | 120.3 |
| $ | 10.0 |
|
Current portion long-term debt |
| — |
| 150.0 |
| ||
Accounts payable |
| 101.4 |
| 102.8 |
| ||
Payables to related parties |
| 16.4 |
| 23.2 |
| ||
Regulatory liabilities |
| 8.5 |
| 18.5 |
| ||
Other current liabilities |
| 62.6 |
| 59.1 |
| ||
Current liabilities |
| 309.2 |
| 363.6 |
| ||
|
|
|
|
|
| ||
Long-term debt to parent |
| 8.1 |
| 8.6 |
| ||
Long-term debt |
| 721.2 |
| 721.1 |
| ||
Deferred income taxes |
| 464.9 |
| 427.9 |
| ||
Deferred investment tax credits |
| 8.8 |
| 9.2 |
| ||
Regulatory liabilities |
| 268.8 |
| 255.9 |
| ||
Environmental remediation liabilities |
| 69.4 |
| 76.1 |
| ||
Pension and other postretirement benefit obligations |
| 167.0 |
| 220.4 |
| ||
Payables to related parties |
| 8.4 |
| 9.0 |
| ||
Other long-term liabilities |
| 91.7 |
| 95.8 |
| ||
Long-term liabilities |
| 1,808.3 |
| 1,824.0 |
| ||
|
|
|
|
|
| ||
Commitments and contingencies |
|
|
|
|
| ||
|
|
|
|
|
| ||
Preferred stock - $100 par value; 1,000,000 shares authorized; 511,882 shares issued and outstanding |
| 51.2 |
| 51.2 |
| ||
Common stock - $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding |
| 95.6 |
| 95.6 |
| ||
Additional paid-in capital |
| 554.2 |
| 626.7 |
| ||
Retained earnings |
| 443.5 |
| 424.9 |
| ||
Total liabilities and shareholders’ equity |
| $ | 3,262.0 |
| $ | 3,386.0 |
|
The accompanying condensed notes are an integral part of these statements.
WISCONSIN PUBLIC SERVICE CORPORATION
Preferred stock |
|
|
|
|
|
|
|
|
|
Cumulative; $100 par value; 1,000,000 shares authorized with no mandatory redemption - |
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
| Series |
| Shares Outstanding |
|
|
|
|
|
|
| 5.00 | % | 131,916 |
| 13.2 |
| 13.2 |
|
|
| 5.04 | % | 29,983 |
| 3.0 |
| 3.0 |
|
|
| 5.08 | % | 49,983 |
| 5.0 |
| 5.0 |
|
|
| 6.76 | % | 150,000 |
| 15.0 |
| 15.0 |
|
|
| 6.88 | % | 150,000 |
| 15.0 |
| 15.0 |
|
Total preferred stock |
|
|
|
|
| 51.2 |
| 51.2 |
|
Long-term debt to parent |
|
|
|
|
|
|
|
|
|
|
| Series |
| Year Due |
|
|
|
|
|
|
| 8.76 | % | 2015 |
| 3.2 |
| 3.4 |
|
|
| 7.35 | % | 2016 |
| 4.9 |
| 5.2 |
|
Total long-term debt to parent |
|
|
|
|
| 8.1 |
| 8.6 |
|
Long-term debt |
|
|
|
|
|
|
|
|
| ||
First Mortgage Bonds |
|
|
|
|
|
|
|
|
| ||
|
| Series |
| Year Due |
|
|
|
|
| ||
|
| 7.125 | % | 2023 |
| 0.1 |
| 0.1 |
| ||
Senior Notes |
|
|
|
|
|
|
|
|
| ||
|
| Series |
| Year Due |
|
|
|
|
| ||
|
| 6.125 | % | 2011 |
| — |
| 150.0 |
| ||
|
| 4.875 | % | 2012 |
| 150.0 |
| 150.0 |
| ||
|
| 3.95 | % | 2013 |
| 22.0 |
| 22.0 |
| ||
|
| 4.80 | % | 2013 |
| 125.0 |
| 125.0 |
| ||
|
| 6.375 | % | 2015 |
| 125.0 |
| 125.0 |
| ||
|
| 5.65 | % | 2017 |
| 125.0 |
| 125.0 |
| ||
|
| 6.08 | % | 2028 |
| 50.0 |
| 50.0 |
| ||
| �� | 5.55 | % | 2036 |
| 125.0 |
| 125.0 |
| ||
Total First Mortgage Bonds and Senior Notes |
|
|
|
|
| 722.1 |
| 872.1 |
| ||
Unamortized discount on long-term debt |
|
|
|
|
| (0.9 | ) | (1.0 | ) | ||
Total |
|
|
|
|
| 721.2 |
| 871.1 |
| ||
Current portion |
|
|
|
|
| — |
| (150.0 | ) | ||
Total long-term debt |
|
|
|
|
| 721.2 |
| 721.1 |
| ||
Total capitalization |
|
|
|
|
| $ | 1,873.8 |
| $ | 1,928.1 |
|
The accompanying condensed notes are an integral part of these statements.
WISCONSIN PUBLIC SERVICE CORPORATION
|
| Nine Months Ended |
| ||||
| September 30 |
| |||||
(Millions) |
| 2011 |
| 2010 |
| ||
|
|
|
|
|
| ||
Operating Activities |
|
|
|
|
| ||
Net income |
| $ | 98.0 |
| $ | 113.0 |
|
Adjustments to reconcile net income to net cash provided by operating activities |
|
|
|
|
| ||
Depreciation and amortization expense |
| 71.6 |
| 83.9 |
| ||
Recoveries and refunds of regulatory assets and liabilities |
| 23.2 |
| 7.9 |
| ||
Deferred income taxes and investment tax credit |
| 31.5 |
| 43.2 |
| ||
Bad debt expense |
| 5.0 |
| 4.7 |
| ||
Pension and other postretirement expense |
| 16.3 |
| 18.2 |
| ||
Pension and other postretirement contributions |
| (61.6 | ) | (17.3 | ) | ||
Equity income, net of dividends |
| (0.7 | ) | (0.6 | ) | ||
Other |
| 13.3 |
| (4.7 | ) | ||
Changes in working capital |
|
|
|
|
| ||
Collateral on deposit |
| 0.6 |
| (3.6 | ) | ||
Accounts receivable and accrued unbilled revenues |
| 36.2 |
| 46.8 |
| ||
Inventories |
| (25.6 | ) | (6.6 | ) | ||
Other current assets |
| (0.1 | ) | 17.6 |
| ||
Accounts payable |
| (12.0 | ) | (18.7 | ) | ||
Other current liabilities |
| (5.9 | ) | (28.4 | ) | ||
Accrued Taxes |
| 1.6 |
| 4.8 |
| ||
Net cash provided by operating activities |
| 191.4 |
| 260.2 |
| ||
|
|
|
|
|
| ||
Investing Activities |
|
|
|
|
| ||
Capital expenditures |
| (67.8 | ) | (65.8 | ) | ||
Proceeds from sale of property, plant, and equipment |
| 2.0 |
| 2.5 |
| ||
Other |
| 1.9 |
| 2.9 |
| ||
Net cash used for investing activities |
| (63.9 | ) | (60.4 | ) | ||
|
|
|
|
|
| ||
Financing Activities |
|
|
|
|
| ||
Redemption of notes payable |
| (10.0 | ) | — |
| ||
Short-term debt, net |
| 120.3 |
| (7.0 | ) | ||
Redemption of long-term debt |
| (150.0 | ) | — |
| ||
Payments of long-term debt |
| (0.5 | ) | (0.5 | ) | ||
Dividends to parent |
| (76.9 | ) | (74.7 | ) | ||
Return of capital to parent |
| (75.0 | ) | (15.0 | ) | ||
Preferred stock dividends |
| (2.3 | ) | (2.3 | ) | ||
Other |
| 0.8 |
| 0.8 |
| ||
Net cash used for financing activities |
| (193.6 | ) | (98.7 | ) | ||
Net change in cash and cash equivalents |
| (66.1 | ) | 101.1 |
| ||
Cash and cash equivalents at beginning of period |
| 71.4 |
| 6.0 |
| ||
Cash and cash equivalents at end of period |
| $ | 5.3 |
| $ | 107.1 |
|
The accompanying condensed notes are an integral part of these statements.
WISCONSIN PUBLIC SERVICE CORPORATION AND SUBSIDIARY
CONDENSED NOTES TO FINANCIAL STATEMENTS
September 30, 2011
As used in these notes, the term “financial statements” refers to the condensed consolidated financial statements. This includes the condensed consolidated balance sheets, condensed consolidated statements of income, condensed consolidated statements of capitalization, and condensed consolidated statements of cash flows, unless otherwise noted. In this report, when we refer to “us,” “we,” “our,” or “ours,” we are referring to WPS.
Our financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q and in accordance with GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2010.
In management’s opinion, these unaudited financial statements include all adjustments considered necessary for a fair presentation of financial results. All adjustments are normal and recurring, unless otherwise noted. Financial results for an interim period may not give a true indication of results for the year.
Reclassifications
We reclassified $9.1 million reported in other current assets at December 31, 2010, to prepaid taxes to match the current period presentation on the balance sheet.
NOTE 2—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:
|
| Nine Months Ended September 30 |
| ||||
(Millions) |
| 2011 |
| 2010 |
| ||
Cash paid for interest |
| $ | 29.8 |
| $ | 29.8 |
|
Cash paid for income taxes |
| 31.8 |
| 9.7 |
| ||
Construction costs funded through accounts payable totaled $7.6 million at September 30, 2011, and $4.2 million at September 30, 2010. These costs were treated as noncash investing activities.
NOTE 3—RISK MANAGEMENT ACTIVITIES
We use derivative instruments to manage commodity costs. None of these derivatives are designated as hedges for accounting purposes. The derivatives include physical commodity contracts and NYMEX futures and options used by both the electric and natural gas utility segments to manage the risks associated with the market price volatility of natural gas supply costs and the costs of gasoline and diesel fuel used by utility vehicles. The electric utility segment also uses FTRs to manage electric transmission congestion costs and NYMEX oil futures and options to reduce price risk related to coal transportation.
The following tables show our assets and liabilities from risk management activities.
|
|
|
| September 30, 2011 |
| ||||
(Millions) |
| Balance Sheet |
| Assets from |
| Liabilities from |
| ||
FTRs |
| Other Current |
| $ | 2.6 |
| $ | 0.4 |
|
Natural gas contracts |
| Other Current |
| 0.2 |
| 1.4 |
| ||
Petroleum product contracts |
| Other Current |
| 0.2 |
| — |
| ||
Coal contract |
| Other Current |
| — |
| 0.3 |
| ||
Coal contract |
| Other Long-term |
| 0.4 |
| 0.6 |
| ||
Total |
| Other Current |
| $ | 3.0 |
| $ | 2.1 |
|
Total |
| Other Long-term |
| $ | 0.4 |
| $ | 0.6 |
|
* All derivatives are recognized on the balance sheet at their fair value unless they 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. We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.
|
|
|
| December 31, 2010 |
| ||||
(Millions) |
| Balance Sheet |
| Assets from |
| Liabilities from |
| ||
FTRs |
| Other Current |
| $ | 2.2 |
| $ | 0.2 |
|
Natural gas contracts |
| Other Current |
| 0.4 |
| 2.3 |
| ||
Petroleum product contracts |
| Other Current |
| 0.3 |
| — |
| ||
Coal contract |
| Other Current |
| — |
| 1.2 |
| ||
Coal contract |
| Other Long-term |
| 3.7 |
| — |
| ||
Total |
| Other Current |
| $ | 2.9 |
| $ | 3.7 |
|
Total |
| Other Long-term |
| $ | 3.7 |
| $ | — |
|
* All derivatives are recognized on the balance sheet at their fair value unless they 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. We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.
The table below shows the unrealized gains (losses) recorded related to derivatives.
|
|
|
| Three Months Ended |
| Nine Months |
| ||||||||
(Millions) |
| Financial Statement Presentation |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||
FTRs |
| Balance Sheet — Regulatory assets (current) |
| $ | 0.2 |
| $ | 1.0 |
| $ | (0.5 | ) | $ | 0.6 |
|
FTRs |
| Balance Sheet — Regulatory liabilities (current) |
| (0.5 | ) | (3.1 | ) | (0.4 | ) | (0.3 | ) | ||||
Natural gas contracts |
| Balance Sheet — Regulatory assets (current) |
| (1.7 | ) | (3.1 | ) | 0.7 |
| (3.2 | ) | ||||
Natural gas contracts |
| Balance Sheet — Regulatory assets (long-term) |
| — |
| 0.1 |
| — |
| — |
| ||||
Natural gas contracts |
| Balance Sheet — Regulatory liabilities (current) |
| (0.1 | ) | — |
| (0.2 | ) | (0.1 | ) | ||||
Natural gas contracts |
| Income Statement — Cost of fuel, natural gas, and purchased power |
| (0.1 | ) | (0.2 | ) | — |
| (0.1 | ) | ||||
Petroleum product contracts |
| Balance Sheet — Regulatory assets (current) |
| — |
| N/A |
| (0.1 | ) | N/A |
| ||||
Petroleum product contracts |
| Balance Sheet — Regulatory liabilities (current) |
| (0.2 | ) | N/A |
| — |
| N/A |
| ||||
Petroleum product contracts |
| Income Statement — Operating and maintenance expense |
| (0.1 | ) | — |
| — |
| (0.1 | ) | ||||
Coal contract |
| Balance Sheet — Regulatory assets (current) |
| 1.1 |
| N/A |
| 0.9 |
| N/A |
| ||||
Coal contract |
| Balance Sheet — Regulatory assets (long-term) |
| 2.4 |
| N/A |
| (0.6 | ) | N/A |
| ||||
Coal contract |
| Balance Sheet — Regulatory liabilities (long-term) |
| 0.5 |
| N/A |
| (3.2 | ) | N/A |
| ||||
We had the following notional volumes of outstanding derivative contracts:
|
| September 30, 2011 |
| December 31, 2010 |
| ||||
Commodity |
| Purchases |
| Other |
| Purchases |
| Other |
|
Natural gas (millions of therms) |
| 101.1 |
| N/A |
| 100.6 |
| N/A |
|
FTRs (millions of kilowatt-hours) |
| N/A |
| 7,529.5 |
| N/A |
| 5,645.3 |
|
Petroleum products (barrels) |
| 21,631.0 |
| N/A |
| 44,648.0 |
| N/A |
|
Coal contract (millions of tons) |
| 4.3 |
| N/A |
| 4.9 |
| N/A |
|
The following table shows our cash collateral positions.
(Millions) |
| September 30, 2011 |
| December 31, 2010 |
| ||
Cash collateral provided to others |
| $ | 3.2 |
| $ | 3.7 |
|
NOTE 4—SHORT-TERM DEBT AND LINES OF CREDIT
Our short-term borrowings consisted of sales of commercial paper and short-term notes.
(Millions, except percentages) |
| September 30, 2011 |
| December 31, 2010 |
| ||
Commercial paper outstanding |
| $ | 120.3 |
| — |
| |
Average discount rate on outstanding commercial paper |
| 0.25 | % | — |
| ||
Short-term notes payable outstanding |
| — |
| $ | 10.0 |
| |
Average interest rate on short-term notes payable outstanding |
| — |
| 0.32 | % | ||
The commercial paper outstanding at September 30, 2011, had maturity dates ranging from October 3, 2011, through October 14, 2011.
The table below presents our average amount of short-term borrowings outstanding based on daily outstanding balances during the nine months ended September 30:
(Millions) |
| 2011 |
| 2010 |
| ||
Average amount of commercial paper outstanding |
| $ | 33.1 |
| $ | 0.1 |
|
Average amount of short-term notes payable outstanding |
| 4.8 |
| 10.0 |
| ||
We manage our liquidity by maintaining adequate external financing commitments. The information in the table below relates to our short-term debt, lines of credit, and remaining available capacity:
(Millions) |
| Maturity |
| September 30, 2011 |
| December 31, 2010 |
| ||
Revolving credit facility (1) |
| 04/23/13 |
| $ | 115.0 |
| $ | 115.0 |
|
Revolving credit facility (2) |
| 05/15/12 |
| $ | 135.0 |
| — |
| |
Revolving short-term notes payable (3) |
| 05/13/11 |
| — |
| 10.0 |
| ||
|
|
|
|
|
|
|
| ||
Total short-term credit capacity |
|
|
| $ | 250.0 |
| $ | 125.0 |
|
|
|
|
|
|
|
|
| ||
Less: |
|
|
|
|
|
|
| ||
Letters of credit issued inside credit facilities |
|
|
| $ | 0.2 |
| $ | 0.2 |
|
Loans outstanding under credit agreements and notes payable |
|
|
| — |
| 10.0 |
| ||
Commercial paper outstanding |
|
|
| 120.3 |
| — |
| ||
|
|
|
|
|
|
|
| ||
Available capacity under existing agreements |
|
|
| $ | 129.5 |
| $ | 114.8 |
|
(1) Supports our commercial paper borrowing program.
(2) In May 2011, we entered into a new revolving credit agreement to support our commercial paper borrowing program. We have requested approval from the PSCW to extend this facility through May 17, 2014.
(3) These short-term notes payable were repaid in May 2011.
At September 30, 2011, we were in compliance with all financial covenants related to outstanding short-term debt. Our revolving credit agreement contains financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%, excluding non-recourse debt. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.
The table below shows our effective tax rates:
|
| Three Months Ended |
| Nine Months Ended |
| ||||
|
| 2011 |
| 2010 |
| 2011 |
| 2010 |
|
|
|
|
|
|
|
|
|
|
|
Effective Tax Rate |
| 35.8 | % | 33.3 | % | 35.9 | % | 36.1 | % |
We calculate our interim period provision for income taxes based on our projected annual effective tax rate as adjusted for certain discrete items.
Our effective tax rate for the three months ended September 30, 2010, was lower than the federal statutory tax rate of 35%. This difference primarily related to the federal income tax benefit of wind production tax credits and other various tax differences. State income tax obligations partially offset the lower effective tax rate.
For all other periods presented in the table above, our effective tax rate did not differ materially from the federal statutory tax rate of 35%.
During the three months ended September 30, 2011, there was not a significant change in our liability for unrecognized tax benefits. During the nine months ended September 30, 2011, we decreased our
liability for unrecognized tax benefits by $4.3 million. The decrease was driven by the settlement of an IRS examination in the second quarter of 2011.
NOTE 6—COMMITMENTS AND CONTINGENCIES
Commodity Purchase Obligations and Purchase Order Commitments
We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates.
The purchase obligations described below were as of September 30, 2011.
· Our electric utility segment had obligations of $142.2 million related to coal supply and transportation that extend through 2016, obligations of $1,335.8 million for either capacity or energy related to purchased power that extend through 2027, and obligations of $5.4 million for other commodities that extend through 2013.
· Our natural gas utility segment had obligations of $358.3 million related to natural gas supply and transportation contracts that extend through 2024.
· We also had commitments of $167.3 million in the form of purchase orders issued to various vendors that relate to normal business operations, including construction projects.
Environmental
CAA New Source Review Issues
Weston and Pulliam Plants:
In November 2009, the EPA issued us an NOV alleging violations of the CAA’s New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. We continue to meet with the EPA and exchange proposals on a possible resolution. We are currently unable to estimate the possible loss or range of loss related to this matter.
In May 2010, we received from the Sierra Club an NOI to file a civil lawsuit based on allegations that we violated the CAA at the Weston and Pulliam plants. We entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. We are working on a possible resolution with the Sierra Club and the EPA. We are currently unable to estimate the possible loss or range of loss related to this matter.
Columbia and Edgewater Plants:
In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the operator of the Columbia and Edgewater plants, and the other joint owners of these plants (including us). The NOV alleges violations of the CAA’s New Source Review requirements related to certain projects completed at those plants. WP&L and the other joint owners exchanged proposals with the EPA on a possible resolution. We are currently unable to estimate the possible loss or range of loss related to this matter.
In September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Columbia plant did not comply with the CAA. The Court stayed the proceeding until September 11, 2011, and, although the stay has not been extended, the Sierra Club
continues to participate in settlement negotiations with the EPA and the joint owners of the Columbia plant. We are currently unable to estimate the possible loss or range of loss related to this matter.
In December 2009, we, along with the other co-owners of the Edgewater plant, received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA. The Sierra Club cited the EPA’s failure to take actions against the joint owners and operator of the Edgewater plant based upon allegations of failure to comply with the CAA. If the EPA does not take action against us and/or the other joint owners, it is likely that the Sierra Club will.
In September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Edgewater plant did not comply with the CAA. The Court stayed the proceeding until December 2, 2011, to allow the Sierra Club to participate in settlement negotiations with the EPA and the joint owners of the Edgewater plant. We are currently unable to estimate the possible loss or range of loss related to this matter.
EPA Settlements with Other Utilities:
In response to the EPA’s CAA enforcement initiative, several utilities elected to settle with the EPA, while others are in litigation. The fines, penalties, and costs of beneficial environmental projects associated with settlements involving comparably-sized facilities to Weston and Pulliam combined ranged between $6 million and $30 million. The regulatory interpretations upon which the lawsuits or settlements are based may change depending on future court decisions made in the pending litigation.
If it were settled or determined that historical projects at the Weston, Pulliam, Columbia, and Edgewater plants required either a state or federal CAA permit, we may, under the applicable statutes, be required to complete the following remedial steps:
· shut down the facility,
· install additional pollution control equipment and/or impose emission limitations, and/or
· conduct a beneficial environmental project.
In addition, we may also be required to pay a fine. Finally, under the CAA, citizen groups may pursue a claim.
Weston Air Permits
Weston 4 Construction Permit:
From 2004 to 2009, the Sierra Club filed various petitions objecting to the construction permit issued for the Weston 4 plant. In June 2010, the Wisconsin Court of Appeals affirmed the Weston 4 construction permit, but directed the WDNR to reopen the permit to set specific visible emissions limits. In July 2010, we, the WDNR, and the Sierra Club filed Petitions for Review with the Wisconsin Supreme Court. In March 2011, the Wisconsin Supreme Court denied all Petitions for Review. Other than the specific visible emissions limits issue, all other challenges to the construction permit are now resolved. We are working with the WDNR and the Sierra Club to resolve this issue. We do not expect this matter to have a material impact on our financial statements.
Weston Title V Air Permit:
In November 2010, the WDNR provided a draft revised permit. We objected to proposed changes in mercury limits and requirements on the boiler as beyond the authority of the WDNR. We continue to
meet with the WDNR to resolve these issues. On September 14, 2011, the WDNR issued a draft revised permit and a request for public comments and we filed comments objecting to certain provisions in the draft permit. We do not expect this matter to have a material impact on our financial statements.
WDNR Issued NOVs:
Since 2008, we received four NOVs from the WDNR alleging various violations of the different air permits for the Weston plant, Weston 4, Weston 1, and Weston 2, as well as one NOV for a clerical error involving pages missing from a quarterly report for Weston. Corrective actions have been taken for the events in the five NOVs. Discussions with the WDNR on the severity classification of the events continue. Management believes it is likely that the WDNR will refer at least some of the NOVs to the state Justice Department for enforcement. We do not expect this matter to have a material impact on our financial statements.
Pulliam Title V Air Permit
The WDNR issued the renewal of the permit for the Pulliam plant in April 2009. In June 2010, the EPA issued an order directing the WDNR to respond to comments raised by the Sierra Club in its June 2009 Petition objecting to this permit. We have been working with the WDNR to address the order.
We also challenged the permit in a contested case proceeding and Petition for Judicial Review. The Petition was dismissed in an order remanding the matter to the WDNR. In February 2011, the WDNR granted a contested case proceeding on the issues we raised, which included averaging times in the emission limits in the permit. We participated in the contested case proceeding on October 11 and 12, 2011, and a decision is pending.
In October 2010, we received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA based on what the Sierra Club alleges to be the EPA’s unreasonable delay in performing its duties related to the grant or denial of the permit. We recently received notification that the Sierra Club filed suit against the EPA in April 2011. As such, we will move to intervene in the case as a necessary party.
We are reviewing all of these matters, but we do not expect them to have a material impact on our financial statements.
Columbia Title V Air Permit
In October 2009, the EPA issued an order objecting to the permit renewal issued by the WDNR for the Columbia plant. The order determined that the WDNR did not adequately analyze whether a project in 2006 constituted a “major modification that required a permit.” The EPA’s order directed the WDNR to resolve the objections within 90 days and “terminate, modify, or revoke and reissue” the permit accordingly.
In July 2010, we, along with our co-owners, received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA. The Sierra Club alleges that the EPA should assert jurisdiction over the permit because the WDNR failed to respond to the EPA’s objection within 90 days.
In September 2010, the WDNR issued a draft construction permit and a draft revised Title V permit in response to the EPA’s order. In November 2010, the EPA notified the WDNR that the EPA “does not believe the WDNR’s proposal is responsive to the order.” In January 2011, the WDNR issued a letter
stating that upon review of the submitted public comments, the WDNR has determined not to issue the draft permits that were proposed to respond to the EPA’s order. In February 2011, the Sierra Club filed for a declaratory action, claiming that the EPA had to assert jurisdiction over the permits. In May 2011, the WDNR issued a second draft Title V permit in response to the EPA’s order. We are monitoring this situation with WP&L and meeting with the WDNR. We do not expect this matter to have a material impact on our financial statements.
Mercury and Interstate Air Quality Rules
Mercury:
The State of Wisconsin’s mercury rule, Chapter NR 446, requires a 40% reduction from the 2002 through 2004 baseline mercury emissions in Phase I, beginning January 1, 2010, through the end of 2014. In Phase II, which begins in 2015, electric generating units above 150 megawatts will be required to reduce mercury emissions by 90%. Reductions can be phased in and the 90% target delayed until 2021 if additional sulfur dioxide and nitrogen oxide reductions are implemented. By 2015, electric generating units above 25 megawatts but less than 150 megawatts must reduce their mercury emissions to a level defined by the BACT rule. As of September 30, 2011, we estimate capital costs of approximately $11 million, which includes estimates for both wholly owned and jointly owned plants, to achieve the required Phase I and Phase II reductions. The capital costs are expected to be recovered in future rate cases.
In March 2011, the EPA issued a draft rule that will regulate emissions of mercury and other hazardous air pollutants. A final rule is expected in December 2011.
Sulfur Dioxide and Nitrogen Oxide:
The EPA issued the Clean Air Interstate Rule (CAIR) in 2005 in order to reduce sulfur dioxide and nitrogen oxide emissions from utility boilers located in 29 states, including Wisconsin and Michigan. In July 2008, the United States Court of Appeals (Court of Appeals) issued a decision vacating CAIR, which the EPA appealed. In December 2008, the Court of Appeals reinstated CAIR and directed the EPA to address the deficiencies noted in its previous ruling to vacate CAIR. In July 2011, the EPA issued a final CAIR replacement rule known as CSAPR. The new rule becomes effective January 1, 2012, and as such, CAIR is still in place for the remainder of 2011. In comparison to the CAIR rule, CSAPR significantly reduces the emission allowances allocated to our existing units for sulfur dioxide and nitrogen oxide in 2012, with a further reduction in 2014.
CSAPR also establishes new sulfur dioxide and nitrogen oxide emission allowances and does not allow carryover of the existing nitrogen oxide emission allowances allocated to us under CAIR. We did not acquire any CAIR nitrogen oxide emission allowances for 2011 and beyond other than those directly allocated to us, which were free. Sulfur dioxide emission allowances allocated under the Acid Rain Program will continue to be issued and surrendered independent of the CSAPR emission allowance program. Thus, we do not expect any material impact on our financial statements as a result of being unable to carryover existing emission allowances.
Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule are considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they are in compliance with CAIR. Although particulate emissions also contribute to visibility impairment, the WDNR’s modeling has shown the impairment to be so insignificant that additional capital expenditures on controls are not warranted. The EPA has not indicated whether units in compliance with CSAPR will also be considered in compliance with BART.
In order to be in compliance with CSAPR, additional sulfur dioxide and nitrogen oxide controls will need to be installed, emission allowances will need to be purchased, and/or we will have to make other changes to how we operate our existing units. The installation of any necessary controls will be scheduled as part of our long-term maintenance plan for our existing units; however, we do not currently believe we can timely meet the new CSAPR sulfur dioxide and nitrogen oxide emission limits without purchasing additional emission allowances or by changing how we operate our existing units. Due to the fact that the rule has only recently been finalized, we are currently unable to predict whether, or if, additional emission allowances will be available to purchase or how much it will cost to comply. We are also currently unable to predict whether CSAPR will cause us to idle or abandon certain units or impact the estimated useful lives of certain units. We expect to recover costs incurred to comply with CSAPR in future rates.
We are currently reviewing the EPA’s final rule and its potential impact on us. Numerous petitions have been filed with the EPA and the D.C. Circuit Court by companies (including us) and states affected by CSAPR, seeking reconsideration and a stay of the rule. The outcome and timing of responses by the EPA and the D.C. Circuit Court are uncertain.
Manufactured Gas Plant Remediation
We operated facilities in the past at multiple sites for the purpose of manufacturing and storing manufactured gas. In connection with these activities, waste materials were produced that may have resulted in soil and groundwater contamination at these sites. Under certain laws and regulations relating to the protection of the environment, we are required to undertake remedial action with respect to some of these materials. We are coordinating the investigation and cleanup of the sites subject to EPA jurisdiction under what is called a “multi-site” program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies.
We are responsible for the environmental remediation of ten sites, of which seven have been transferred to the EPA Superfund Alternative Sites Program. Under the EPA’s program, the remedy decisions at these sites will be made using risk-based criteria typically used at Superfund sites. As of September 30, 2011, we estimated and accrued for $69.4 million of future undiscounted investigation and cleanup costs for all sites. We may adjust these estimates in the future due to remedial technology, regulatory requirements, remedy determinations, and any claims of natural resource damages. As of September 30, 2011, we recorded a regulatory asset of $72.8 million, which is net of insurance recoveries received of $22.2 million, related to the expected recovery of both cash expenditures and estimated future expenditures through rates. Under current PSCW policies, we may not recover carrying costs associated with the cleanup expenditures.
Management believes that any costs incurred for environmental activities relating to former manufactured gas plant operations that are not recoverable through contributions from other entities or
from insurance carriers have been prudently incurred and are, therefore, recoverable through rates. Accordingly, we do not expect these costs to have a material impact on our financial statements. However, any changes in the approved rate mechanisms for recovery of these costs, or any adverse conclusions by the various regulatory commissions with respect to the prudence of costs actually incurred, could materially adversely affect rate recovery of such costs.
Greenhouse Gases
The EPA began regulating greenhouse gas emissions under the CAA in January 2011 by applying the BACT requirements (associated with the New Source Review program) to new and modified larger greenhouse gas emitters. Technology to remove and sequester greenhouse gas emissions is not commercially available at scale. Therefore, the EPA issued guidance that defines BACT in terms of improvements in energy efficiency as opposed to relying on pollution control equipment. In December 2010, the EPA announced its intent to develop new source performance standards for greenhouse gas emissions. The standards would apply to new and modified, as well as existing, electric utility steam generating units. The EPA planned to propose these standards in 2011 and finalize them in 2012; however, the proposal has since been delayed. Currently there is no applicable federal or state legislation pending that specifically addresses greenhouse gas emissions.
We periodically evaluate both the technical and cost implications that may result from future state, regional, or federal greenhouse gas regulatory programs. This evaluation indicates it is probable that any regulatory program that caps emissions or imposes a carbon tax will increase costs for us and our customers. The greatest impact is likely to be on fossil fuel-fired generation, with a less significant impact on natural gas storage and distribution operations. Efforts are underway within the utility industry to find a feasible method for capturing carbon dioxide from pulverized coal-fired units and to develop cleaner ways to burn coal.
A risk exists that any greenhouse gas legislation or regulation will increase the cost of producing energy using fossil fuels. However, we believe the capital expenditures being made at our plants are appropriate under any reasonable mandatory greenhouse gas program. We also believe that our future expenditures to control greenhouse gas emissions or meet renewable portfolio standards will be recoverable in rates. We will continue to monitor and manage potential risks and opportunities associated with future greenhouse gas legislative or regulatory actions.
The following table shows our outstanding guarantees:
(Millions) |
| Total Amounts |
| Less Than 1 |
| Over |
| |||
Standby letters of credit (1) |
| $ | 0.3 |
| $ | 0.3 |
| $ | — |
|
Other guarantee (2) |
| 0.6 |
| — |
| 0.6 |
| |||
Total guarantees |
| $ | 0.9 |
| $ | 0.3 |
| $ | 0.6 |
|
(1) At our request, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to us. These amounts are not reflected on our Balance Sheets.
(2) Issued for workers compensation coverage in Wisconsin and Michigan. This amount is not reflected on our Balance Sheets.
The following table shows the components of net periodic benefit cost for our benefit plans:
|
| Pension Benefits |
| Other Postretirement Benefits |
| ||||||||||||||||||||
|
| Three Months |
| Nine Months |
| Three Months |
| Nine Months |
| ||||||||||||||||
|
| Ended |
| Ended |
| Ended |
| Ended |
| ||||||||||||||||
(Millions) |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||||||
Service cost |
| $ | 2.8 |
| $ | 2.8 |
| $ | 8.4 |
| $ | 8.6 |
| $ | 1.8 |
| $ | 1.4 |
| $ | 5.3 |
| $ | 4.3 |
|
Interest cost |
| 9.0 |
| 9.2 |
| 27.1 |
| 27.5 |
| 3.8 |
| 3.6 |
| 11.4 |
| 10.6 |
| ||||||||
Expected return on plan assets |
| (11.7 | ) | (9.9 | ) | (35.1 | ) | (29.7 | ) | (3.6 | ) | (3.5 | ) | (10.7 | ) | (10.6 | ) | ||||||||
Amortization of transition obligation |
| — |
| — |
| — |
| — |
| 0.1 |
| 0.1 |
| 0.2 |
| 0.2 |
| ||||||||
Amortization of prior service cost (credit) |
| 1.2 |
| 1.2 |
| 3.6 |
| 3.6 |
| (0.9 | ) | (0.9 | ) | (2.6 | ) | (2.7 | ) | ||||||||
Amortization of net actuarial loss |
| 2.2 |
| 1.0 |
| 6.5 |
| 3.1 |
| 0.7 |
| 0.3 |
| 2.2 |
| 0.9 |
| ||||||||
Regulatory deferral * |
| — |
| 1.2 |
| — |
| 3.4 |
| — |
| (0.4 | ) | — |
| (1.0 | ) | ||||||||
Net periodic benefit cost |
| $ | 3.5 |
| $ | 5.5 |
| $ | 10.5 |
| $ | 16.5 |
| $ | 1.9 |
| $ | 0.6 |
| $ | 5.8 |
| $ | 1.7 |
|
* The PSCW authorized us to recover net increased 2009 pension costs and to refund net decreased 2009 other postretirement benefit costs as part of the limited rate case re-opener for 2010. Amortization and recovery/refund of these costs occurred in 2010.
We record transition obligations, prior service costs (credits), and net actuarial losses that have not yet been recognized as a component of net periodic benefit cost as net regulatory assets.
We make contributions to our plans in accordance with legal and tax requirements. These contributions do not necessarily occur evenly throughout the year. For the nine months ended September 30, 2011, $61.6 million of contributions were made to our pension plans and contributions made to our other postretirement benefit plans were not significant. We expect to contribute an additional $1.1 million to our pension plans and $10.9 million to our other postretirement benefit plans during the remainder of 2011. Additional contributions are dependent on various factors, including our liquidity position and the impact of tax law changes.
Various laws, regulations, and financial covenants impose restrictions on our ability to pay dividends to the sole holder of our common stock, Integrys Energy Group.
The PSCW allows us to pay normal dividends on our common stock of no more than 103% of the previous year’s common stock dividend. In addition, the PSCW currently requires us to maintain a calendar year average financial common equity ratio of 50.24% or higher. We must obtain PSCW approval if the payment of dividends would cause us to fall below this authorized level of common equity. Integrys Energy Group’s right to receive dividends on our common stock is also subject to the prior rights of our preferred shareholders and to provisions in our restated articles of incorporation, which limit the amount of common stock dividends that we may pay if our common stock and common stock surplus accounts constitute less than 25% of our total capitalization.
Our short-term debt obligations contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of outstanding debt obligations.
As of September 30, 2011, total restricted net assets were approximately $1,058.7 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $25.6 million at September 30, 2011.
Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.
Integrys Energy Group may provide equity contributions to us or request a return of capital from us in order to maintain utility common equity levels consistent with those allowed by the PSCW. Wisconsin law prohibits us from making loans to or guaranteeing obligations of Integrys Energy Group or its other subsidiaries. During the nine months ended September 30, 2011, we returned $75.0 million of capital to Integrys Energy Group and paid common stock dividends of $76.9 million to Integrys Energy Group. We did not receive any equity contributions from Integrys Energy Group during the nine months ended September 30, 2011.
NOTE 10—STOCK-BASED COMPENSATION
Our employees may be granted awards under Integrys Energy Group’s stock-based compensation plans. At September 30, 2011, stock options, performance stock rights, and restricted share units were outstanding under the various plans. Compensation cost associated with these awards is allocated to us based on the percentages used for allocation of the award recipients’ labor costs.
Compensation cost recognized for stock options was not significant during the three and nine months ended September 30, 2011, and 2010.
Compensation cost recognized for performance stock rights during the three months ended September 30, 2011, was not significant and was $2.3 million for the three months ended September 30, 2010. Compensation cost recognized for performance stock rights during the nine months ended
September 30, 2011, was not significant and for the nine months ended September 30, 2010, was $3.3 million.
Compensation cost recognized for restricted share and restricted share unit awards during the three months ended September 30, 2011, and 2010, was $0.7 million and $2.1 million, respectively. Compensation cost recognized for these awards during the nine months ended September 30, 2011, and 2010, was $2.6 million and $3.2 million, respectively.
NOTE 11—VARIABLE INTEREST ENTITIES
We have a variable interest in an entity through a power purchase agreement relating to the cost of fuel. This agreement contains a tolling arrangement in which we supply the scheduled fuel and purchase capacity and energy from the facility. This contract expires in 2016. As of September 30, 2011, and December 31, 2010, we had approximately 500 megawatts of capacity available under this agreement.
We evaluated this variable interest entity for possible consolidation. In this case, we considered which interest holder has the power to direct the activities that most significantly impact the economics of the variable interest entity; this interest holder is considered the primary beneficiary of the entity and is required to consolidate the entity. For a variety of reasons, including qualitative factors such as the length of the remaining term of the contract compared with the remaining life of the plants and the fact that we do not have the power to direct the operations and maintenance of the facility, we determined we are not the primary beneficiary of this variable interest entity.
At September 30, 2011, the assets and liabilities on the Balance Sheets that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts owed for current deliveries of power. We have not guaranteed any debt or provided any equity support, liquidity arrangements, performance guarantees, or other commitments associated with this contract. There is no significant potential exposure to loss as a result of our involvement with the variable interest entity.
Fair Value Measurements
The following tables show assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy.
|
| September 30, 2011 |
| ||||||||||
(Millions) |
| Level 1 |
| Level 2 |
| Level 3 |
| Total |
| ||||
Risk management assets |
|
|
|
|
|
|
|
|
| ||||
FTRs |
| $ | — |
| $ | — |
| $ | 2.6 |
| $ | 2.6 |
|
Natural gas contracts |
| 0.2 |
| — |
| — |
| 0.2 |
| ||||
Petroleum products contracts |
| 0.2 |
| — |
| — |
| 0.2 |
| ||||
Coal contract |
| — |
| — |
| 0.4 |
| 0.4 |
| ||||
Total |
| $ | 0.4 |
| $ | — |
| $ | 3.0 |
| $ | 3.4 |
|
|
|
|
|
|
|
|
|
|
| ||||
Risk management liabilities |
|
|
|
|
|
|
|
|
| ||||
FTRs |
| $ | — |
| $ | — |
| $ | 0.4 |
| $ | 0.4 |
|
Natural gas contracts |
| 1.4 |
| — |
| — |
| 1.4 |
| ||||
Coal contract |
| — |
| — |
| 0.9 |
| 0.9 |
| ||||
Total |
| $ | 1.4 |
| $ | — |
| $ | 1.3 |
| $ | 2.7 |
|
|
| December 31, 2010 |
| ||||||||||
(Millions) |
| Level 1 |
| Level 2 |
| Level 3 |
| Total |
| ||||
Risk management assets |
|
|
|
|
|
|
|
|
| ||||
FTRs |
| $ | — |
| $ | — |
| $ | 2.2 |
| $ | 2.2 |
|
Natural gas contracts |
| 0.4 |
| — |
| — |
| 0.4 |
| ||||
Petroleum products contracts |
| 0.3 |
| — |
| — |
| 0.3 |
| ||||
Coal contract |
| — |
| — |
| 3.7 |
| 3.7 |
| ||||
Total |
| $ | 0.7 |
| $ | — |
| $ | 5.9 |
| $ | 6.6 |
|
|
|
|
|
|
|
|
|
|
| ||||
Risk management liabilities |
|
|
|
|
|
|
|
|
| ||||
FTRs |
| $ | — |
| $ | — |
| $ | 0.2 |
| $ | 0.2 |
|
Natural gas contracts |
| 2.3 |
| — |
| — |
| 2.3 |
| ||||
Coal contract |
| — |
| — |
| 1.2 |
| 1.2 |
| ||||
Total |
| $ | 2.3 |
| $ | — |
| $ | 1.4 |
| $ | 3.7 |
|
The risk management assets and liabilities listed in the tables include NYMEX futures and options, as well as financial contracts used to manage transmission congestion costs in the MISO market. NYMEX contracts are valued using the NYMEX end-of-day settlement price, which is a Level 1 input. The valuation for FTRs is derived from historical data from MISO, which is considered a Level 3 input. The valuation for the physical coal contract is categorized in Level 3 due to the significance of internally-developed inputs. For more information on derivative instruments, see Note 3, “Risk Management Activities.” There were no transfers between the levels of the fair value hierarchy during the three and nine months ended September 30, 2011, and 2010.
The following tables set forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements.
|
| Three Months Ended September 30, 2011 |
| Nine Months Ended September 30, 2011 |
| ||||||||||||||
(Millions) |
| FTRs |
| Coal Contract |
| Total |
| FTRs |
| Coal Contract |
| Total |
| ||||||
Balance at the beginning of period |
| $ | 3.4 |
| $ | (4.3 | ) | $ | (0.9 | ) | $ | 2.0 |
| $ | 2.5 |
| $ | 4.5 |
|
Net realized gain (loss) included in earnings |
| 0.2 |
| — |
| 0.2 |
| (1.1 | ) | — |
| (1.1 | ) | ||||||
Net unrealized gain (loss) recorded as regulatory assets or liabilities |
| (0.3 | ) | 4.2 |
| 3.9 |
| (0.9 | ) | (1.7 | ) | (2.6 | ) | ||||||
Purchases |
| — |
| — |
| — |
| 2.8 |
| — |
| 2.8 |
| ||||||
Sales |
| (0.1 | ) | — |
| (0.1 | ) | (0.2 | ) | — |
| (0.2 | ) | ||||||
Settlements |
| (1.0 | ) | (0.4 | ) | (1.4 | ) | (0.4 | ) | (1.3 | ) | (1.7 | ) | ||||||
Balance at the end of period |
| $ | 2.2 |
| $ | (0.5 | ) | $ | 1.7 |
| $ | 2.2 |
| $ | (0.5 | ) | $ | 1.7 |
|
|
| Three Months Ended September 30, 2010 |
| Nine Months Ended September 30, 2010 |
| ||
(Millions) |
| FTRs |
| FTRs |
| ||
Balance at the beginning of period |
| $ | 6.2 |
| $ | 3.1 |
|
Net realized gain included in earnings |
| 0.5 |
| 3.7 |
| ||
Net unrealized gain (loss) recorded as regulatory assets or liabilities |
| (2.1 | ) | 0.3 |
| ||
Net purchases and settlements |
| (0.7 | ) | (3.2 | ) | ||
Balance at the end of period |
| $ | 3.9 |
| $ | 3.9 |
|
Unrealized gains and losses on FTRs and the coal contract are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on FTRs, as well as the related transmission congestion costs, are recorded in cost of fuel, natural gas, and purchased power on the Statements of Income.
Fair Value of Financial Instruments
The following table shows the financial instruments included on our Balance Sheets that are not recorded at fair value.
|
| September 30, 2011 |
| December 31, 2010 |
| ||||||||
(Millions) |
| Carrying |
| Fair |
| Carrying |
| Fair |
| ||||
Long-term debt |
| $ | 721.2 |
| $ | 810.1 |
| $ | 871.1 |
| $ | 924.3 |
|
Preferred stock |
| 51.2 |
| 53.7 |
| 51.2 |
| 46.9 |
| ||||
The fair values of long-term debt are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair values of preferred stock are estimated based on quoted market prices, when available, or by using a perpetual dividend discount model.
Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, notes payable, and outstanding commercial paper, the carrying amount for each such item approximates fair value.
Total miscellaneous income was as follows:
|
| Three Months Ended |
| Nine Months Ended |
| ||||||||
(Millions) |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||
Equity earnings on investments |
| $ | 2.6 |
| $ | 2.5 |
| $ | 8.0 |
| $ | 8.1 |
|
Key executive life insurance |
| 0.1 |
| 0.1 |
| 1.1 |
| 1.5 |
| ||||
Other |
| 0.2 |
| 0.4 |
| 1.0 |
| 0.7 |
| ||||
Total miscellaneous income |
| $ | 2.9 |
| $ | 3.0 |
| $ | 10.1 |
| $ | 10.3 |
|
NOTE 14—REGULATORY ENVIRONMENT
Wisconsin
2012 Rate Reopener
On May 2, 2011, we filed a rate reopener with the PSCW for limited items. We requested an electric rate increase of $33.7 million and a natural gas rate increase of $1.1 million, to be effective January 1, 2012. We subsequently withdrew our request for a natural gas rate increase. The proposed electric rate increase was primarily driven by higher fuel and purchased power costs, higher transmission costs, and increased Focus on Energy payments in 2012.
In response to the final EPA CSAPR issued in July 2011, we filed for an additional $31.2 million increase in electric rates for 2012. Subsequently, we filed with the PSCW to reduce our 2012 payments to the Focus on Energy program for both electric and natural gas service and to net our actual 2010 electric decoupling under-collection with the expected 2011 electric decoupling over-collection. These filings resulted in a revised proposed electric rate increase for 2012 of $35.2 million and a proposed natural gas rate decrease for 2012 of $7.2 million. We expect to have a final order from the PSCW in December 2011.
2011 Rates
On January 13, 2011, the PSCW issued a final written order authorizing an electric rate increase of $21.0 million, calculated on a per unit basis. However, the rate order assumed declining sales volumes, a lower authorized return on common equity, lower rate base, and other reduced costs, which results in lower total revenues and margins. The $21.0 million included $20.0 million of recovery of prior deferrals, the majority of which related to the recovery of the 2009 electric decoupling deferral. The $21.0 million excluded the impact of a $15.2 million estimated fuel refund (including carrying costs) from 2010. The PSCW rate order also required an $8.3 million decrease in natural gas rates, which included $7.1 million of recovery for the 2009 decoupling deferral, resulting in lower natural gas revenues and margins. The new rates reflect a 10.30% return on common equity, down from a 10.90% return on common equity in the previous rate order, and a common equity ratio of 51.65% in our regulatory capital structure.
The order also addressed the new Wisconsin electric fuel rule, which was finalized on March 1, 2011. The new fuel rule is effective retroactive to January 1, 2011. It requires the deferral of under or
over-collections of fuel and purchased power costs that exceed a 2% price variance from the cost of fuel and purchased power included in rates. Under or over-collections deferred in the current year will be recovered or refunded in a future rate proceeding. As of September 30, 2011, no amounts were deferred related to 2011 fuel and purchased power costs. However, during the third quarter of 2011, we recorded a $1.8 million short-term regulatory liability as a result of a proposed adjustment for a coal inventory true-up.
2010 Rates
On December 22, 2009, the PSCW issued a final written order, effective January 1, 2010. It authorized an electric rate increase of $18.2 million, offset by an $18.2 million refund of 2009 and 2008 fuel cost over-collections. It also authorized a retail natural gas rate increase of $13.5 million. Based on an order issued on April 1, 2010, the remaining $10.0 million of the total 2008 and 2009 fuel cost over-collections, plus interest of $1.3 million, was refunded to customers in April and May 2010. The 2010 fuel cost over-collections were made subject to refund as of that date. As of September 30, 2011, the balance of the 2010 fuel cost over-collections to be refunded to customers throughout 2011 was $3.9 million, which was recorded as a short-term regulatory liability.
At September 30, 2011, we reported three segments. We manage our reportable segments separately due to their different operating and regulatory environments. Our principal business segments are the regulated electric utility operations and the regulated natural gas utility operations. The other segment includes nonutility activities, including equity earnings from our investments in WRPC and WPS Investments, LLC, which holds an interest in ATC.
The table below presents information related to our reportable segments.
|
| Regulated Utilities |
|
|
|
|
|
|
| ||||||||||
(Millions) |
| Electric |
| Natural |
| Total |
| Other |
| Reconciling |
| WPS |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Three Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
September 30, 2011 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
External revenues |
| $ | 339.8 |
| $ | 37.0 |
| $ | 376.8 |
| $ | 0.3 |
| $ | (0.3 | ) | $ | 376.8 |
|
Intersegment revenues |
| — |
| 4.1 |
| 4.1 |
| — |
| (4.1 | ) | — |
| ||||||
Depreciation and amortization expense |
| 20.1 |
| 3.7 |
| 23.8 |
| 0.2 |
| (0.1 | ) | 23.9 |
| ||||||
Miscellaneous income |
| 0.2 |
| 0.1 |
| 0.3 |
| 2.6 |
| — |
| 2.9 |
| ||||||
Interest expense |
| 8.5 |
| 2.0 |
| 10.5 |
| 0.6 |
| — |
| 11.1 |
| ||||||
Provision (benefit) for income taxes |
| 23.5 |
| (3.8 | ) | 19.7 |
| — |
| — |
| 19.7 |
| ||||||
Preferred stock dividend requirements |
| (0.6 | ) | (0.1 | ) | (0.7 | ) | — |
| — |
| (0.7 | ) | ||||||
Net income (loss) attributed to common shareholder |
| 38.7 |
| (6.3 | ) | 32.4 |
| 2.2 |
| — |
| 34.6 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Three Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
September 30, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Operating revenues |
| $ | 345.2 |
| $ | 42.9 |
| $ | 388.1 |
| $ | 0.4 |
| $ | (0.4 | ) | $ | 388.1 |
|
Depreciation and amortization expense |
| 21.2 |
| 5.4 |
| 26.6 |
| 0.1 |
| (0.1 | ) | 26.6 |
| ||||||
Miscellaneous income |
| 0.2 |
| — |
| 0.2 |
| 2.8 |
| — |
| 3.0 |
| ||||||
Interest expense |
| 9.9 |
| 2.6 |
| 12.5 |
| 0.9 |
| — |
| 13.4 |
| ||||||
Provision (benefit) for income taxes |
| 23.6 |
| (4.6 | ) | 19.0 |
| 1.1 |
| — |
| 20.1 |
| ||||||
Preferred stock dividend requirements |
| (0.5 | ) | (0.2 | ) | (0.7 | ) | — |
| — |
| (0.7 | ) | ||||||
Net income (loss) attributed to common shareholder |
| 44.2 |
| (5.8 | ) | 38.4 |
| 1.1 |
| — |
| 39.5 |
|
|
| Regulated Utilities |
|
|
|
|
|
|
| ||||||||||
(Millions) |
| Electric |
| Natural Gas |
| Total |
| Other |
| Reconciling |
| WPS |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Nine Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
September 30, 2011 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
External revenues |
| $ | 923.0 |
| $ | 246.6 |
| $ | 1,169.6 |
| $ | 1.0 |
| $ | (1.0 | ) | $ | 1,169.6 |
|
Intersegment revenues |
| — |
| 8.8 |
| 8.8 |
| — |
| (8.8 | ) | — |
| ||||||
Depreciation and amortization expense |
| 60.3 |
| 11.2 |
| 71.5 |
| 0.5 |
| (0.4 | ) | 71.6 |
| ||||||
Miscellaneous income (expense) |
| 0.5 |
| — |
| 0.5 |
| 9.6 |
| — |
| 10.1 |
| ||||||
Interest expense |
| 30.5 |
| 7.1 |
| 37.6 |
| 1.8 |
| — |
| 39.4 |
| ||||||
Provision for income taxes |
| 43.7 |
| 8.4 |
| 52.1 |
| 2.8 |
| — |
| 54.9 |
| ||||||
Preferred stock dividend requirements |
| (1.9 | ) | (0.4 | ) | (2.3 | ) | — |
| — |
| (2.3 | ) | ||||||
Net income attributed to common shareholder |
| 78.2 |
| 12.2 |
| 90.4 |
| 5.3 |
| — |
| 95.7 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Nine Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
September 30, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Operating revenues |
| $ | 944.1 |
| $ | 256.0 |
| $ | 1,200.1 |
| $ | 1.1 |
| $ | (1.1 | ) | $ | 1,200.1 |
|
Depreciation and amortization expense |
| 67.0 |
| 16.9 |
| 83.9 |
| 0.4 |
| (0.4 | ) | 83.9 |
| ||||||
Miscellaneous income |
| 0.5 |
| 0.1 |
| 0.6 |
| 9.7 |
| — |
| 10.3 |
| ||||||
Interest expense |
| 29.9 |
| 7.9 |
| 37.8 |
| 2.7 |
| — |
| 40.5 |
| ||||||
Provision for income taxes |
| 52.1 |
| 8.4 |
| 60.5 |
| 3.3 |
| — |
| 63.8 |
| ||||||
Preferred stock dividend requirements |
| (1.8 | ) | (0.5 | ) | (2.3 | ) | — |
| — |
| (2.3 | ) | ||||||
Net income attributed to common shareholder |
| 93.7 |
| 12.9 |
| 106.6 |
| 4.1 |
| — |
| 110.7 |
|
NOTE 16—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 other comprehensive income be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Reclassification adjustments from other comprehensive income to net income are also required to be reported on the face of the financial statements; however, the FASB has proposed a deferral of this requirement. 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 2011-08, “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. This guidance is not expected to have a significant impact on our financial statements.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2010.
SUMMARY
We are a regulated electric and natural gas utility and a wholly owned subsidiary of Integrys Energy Group, Inc. We derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers. We also provide wholesale electric service to numerous utilities and cooperatives for resale.
RESULTS OF OPERATIONS
Earnings Summary
|
| Three Months Ended |
| Change in |
| Nine Months Ended |
| Change in |
| ||||||||
|
| September 30 |
| 2011 Over |
| September 30 |
| 2011 Over |
| ||||||||
(Millions) |
| 2011 |
| 2010 |
| 2010 |
| 2011 |
| 2010 |
| 2010 |
| ||||
Electric utility operations |
| $ | 38.7 |
| $ | 44.2 |
| (12.4 | )% | $ | 78.2 |
| $ | 93.7 |
| (16.5 | )% |
Natural gas utility operations |
| (6.3 | ) | (5.8 | ) | 8.6 | % | 12.2 |
| 12.9 |
| (5.4 | )% | ||||
Other operations |
| 2.2 |
| 1.1 |
| 100.0 | % | 5.3 |
| 4.1 |
| 29.3 | % | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Net income attributed to common shareholder |
| $ | 34.6 |
| $ | 39.5 |
| (12.4 | )% | $ | 95.7 |
| $ | 110.7 |
| (13.6 | )% |
Third Quarter 2011 Compared with Third Quarter 2010
We recognized earnings of $34.6 million for the third quarter of 2011, compared with $39.5 million for the same quarter in 2010. This $4.9 million decrease was driven by a $6.7 million after-tax decrease in electric utility margins mainly caused by differences in the current rate order compared with the previous rate order.
Nine Months 2011 Compared with Nine Months 2010
We recognized earnings of $95.7 million for the nine months ended September 30, 2011, compared with $110.7 million for the same period in 2010. The primary driver of the $15.0 million decrease in earnings was a $15.4 million after-tax decrease in electric utility margins. This decrease was mainly caused by differences in the current rate order compared with the previous rate order.
Regulated Electric Utility Segment Operations
|
| Three Months Ended |
| Change in |
| Nine Months Ended |
| Change in |
| ||||||||
|
| September 30 |
| 2011 Over |
| September 30 |
| 2011 Over |
| ||||||||
(Millions, except heating degree days) |
| 2011 |
| 2010 |
| 2010 |
| 2011 |
| 2010 |
| 2010 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Revenues |
| $ | 339.8 |
| $ | 345.2 |
| (1.6 | )% | $ | 923.0 |
| $ | 944.1 |
| (2.2 | )% |
Fuel and purchased power costs |
| 146.4 |
| 140.7 |
| 4.1 | % | 397.3 |
| 392.7 |
| 1.2 | % | ||||
Margins |
| 193.4 |
| 204.5 |
| (5.4 | )% | 525.7 |
| 551.4 |
| (4.7 | )% | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Operating and maintenance expense |
| 91.7 |
| 95.2 |
| (3.7 | )% | 279.5 |
| 276.6 |
| 1.0 | % | ||||
Depreciation and amortization expense |
| 20.1 |
| 21.2 |
| (5.2 | )% | 60.3 |
| 67.0 |
| (10.0 | )% | ||||
Taxes other than income taxes |
| 10.5 |
| 10.1 |
| 4.0 | % | 32.1 |
| 30.8 |
| 4.2 | % | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Operating income |
| 71.1 |
| 78.0 |
| (8.8 | )% | 153.8 |
| 177.0 |
| (13.1 | )% | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Miscellaneous income |
| 0.2 |
| 0.2 |
| — | % | 0.5 |
| 0.5 |
| — | % | ||||
Interest expense |
| (8.5 | ) | (9.9 | ) | (14.1 | )% | (30.5 | ) | (29.9 | ) | 2.0 | % | ||||
Other expense |
| (8.3 | ) | (9.7 | ) | (14.4 | )% | (30.0 | ) | (29.4 | ) | 2.0 | % | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Income before taxes |
| $ | 62.8 |
| $ | 68.3 |
| (8.1 | )% | $ | 123.8 |
| $ | 147.6 |
| (16.1 | )% |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Sales in kilowatt-hours |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Residential |
| 816.3 |
| 814.2 |
| 0.3 | % | 2,182.0 |
| 2,161.7 |
| 0.9 | % | ||||
Commercial and industrial |
| 2,135.9 |
| 2,082.1 |
| 2.6 | % | 6,023.2 |
| 5,965.6 |
| 1.0 | % | ||||
Wholesale |
| 1,247.2 |
| 1,347.9 |
| (7.5 | )% | 3,415.2 |
| 3,717.5 |
| (8.1 | )% | ||||
Other |
| 7.1 |
| 7.3 |
| (2.7 | )% | 23.3 |
| 23.8 |
| (2.1 | )% | ||||
Total sales in kilowatt-hours |
| 4,206.5 |
| 4,251.5 |
| (1.1 | )% | 11,643.7 |
| 11,868.6 |
| (1.9 | )% | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Weather |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Heating degree days |
| 246 |
| 227 |
| 8.4 | % | 5,222 |
| 4,415 |
| 18.3 | % | ||||
Cooling degree days |
| 494 |
| 478 |
| 3.3 | % | 596 |
| 616 |
| (3.2 | )% |
Third Quarter 2011 Compared with Third Quarter 2010
Revenues
Regulated electric utility segment revenues decreased $5.4 million, driven by:
· An approximate $8 million decrease in revenues from wholesale customers. The decrease was due to lower sales volumes and lower non-fuel revenue requirements driven by a lower return on common equity, lower rate base, and other reduced costs.
· An approximate $6 million decrease in retail revenues due to differences between our current rate order and the previous rate order. An increase in revenues calculated on a per-unit basis was more than offset by the impact of decoupling. The decoupling mechanism had a significant impact due to changes in the current rate order that impacted the decoupling calculation. For more details on the current rate order, see Note 14, “Regulatory Environment.”
· These decreases were partially offset by:
· An approximate $4 million increase in market opportunity sales driven by an increase in demand due to warmer weather during the cooling season. Market opportunity sales do not directly impact margins. The revenues from these sales are used to reduce fuel and purchased power costs recovered through the power supply cost recovery mechanism.
· An approximate $4 million increase in revenues due to a 1.9% increase in sales volumes to retail customers.
Margins
Regulated electric utility segment margins decreased $11.1 million, driven by:
· An approximate $11 million decrease in retail margins due to differences between our current rate order and the previous rate order, as discussed above.
· An approximate $3 million decrease in margins from wholesale customers. The decrease was due to lower sales volumes and lower non-fuel revenue requirements driven by a lower return on common equity, lower rate base, and other reduced costs.
· A partially offsetting approximate $2 million increase in margins due to a 1.9% increase in sales volumes to retail customers.
Operating Income
Operating income at the regulated electric utility segment decreased $6.9 million. The decrease was driven by the $11.1 million decrease in margins, partially offset by a $4.2 million decrease in operating expenses.
The decrease in operating expenses was the result of:
· A $4.5 million decrease in employee benefit costs. The decrease was primarily due to changes in the fair value of amounts owed to plan participants under deferred compensation plans and lower pension expense. Lower pension expense was driven by an increase in contributions, which increased plan assets.
· A $3.1 million decrease in stock-based compensation expense. In the third quarter of 2010, we began accounting for performance stock rights, restricted shares, and restricted share units as liability awards. The decrease was driven by changes in the fair value of these awards, primarily related to Integrys Energy Group’s stock price. We also recorded additional expense related to the change in accounting method in the third quarter of 2010.
· These decreases were partially offset by:
· A $1.4 million increase in electric transmission expense.
· A $0.9 million increase in the amortization of various regulatory deferrals. This increase was offset in revenues, resulting in no impact on earnings.
· A $0.9 million increase in customer assistance expense related to payments made to the Focus on Energy program. The program promotes residential and small business energy efficiency and renewable energy products.
Other Expense
Other expense decreased $1.4 million, driven by a decrease in interest expense due to the maturity and repayment of $150 million of long-term debt in August 2011.
Nine Months 2011 Compared with Nine Months 2010
Revenues
Regulated electric utility segment revenues decreased $21.1 million, driven by:
· An approximate $16 million decrease in revenues from wholesale customers. The decrease was due to lower sales volumes and lower non-fuel revenue requirements driven by a lower return on common equity, lower rate base, and other reduced costs.
· An approximate $13 million decrease in retail revenues due to differences between our current rate order and the previous rate order. An increase in revenues calculated on a per-unit basis was more than offset by the impact of decoupling. The decoupling mechanism had a significant impact due to changes in the current rate order that impacted the decoupling calculation. For more details on the current rate order, see Note 14, “Regulatory Environment.”
· A partially offsetting approximate $4 million increase in revenues due to a 1.0% increase in sales volumes to retail customers. The increase in sales volumes was driven by colder weather during the 2011 heating season, as evidenced by the increase in heating degree days.
Margins
Regulated electric utility segment margins decreased $25.7 million, driven by:
· An approximate $24 million decrease in retail margins due to differences between our current rate order and the previous rate order, as discussed above.
· An approximate $6 million decrease in margins from wholesale customers. The decrease was due to lower sales volumes and lower non-fuel revenue requirements driven by a lower return on common equity, lower rate base, and other reduced costs.
· A partially offsetting approximate $2 million increase in margins due to a 1.0% increase in sales volumes to retail customers. The increase in sales volumes was driven by colder weather during the 2011 heating season, as evidenced by the increase in heating degree days.
Operating Income
Operating income at the regulated electric utility segment decreased $23.2 million. The decrease was driven by the $25.7 million decrease in margins, partially offset by a $2.5 million decrease in operating expenses.
The decrease in operating expenses was primarily related to:
· A $7.8 million decrease in employee benefit costs. The decrease was primarily due to changes in the fair value of amounts owed to plan participants under deferred compensation plans and lower pension expense. Lower pension expense was driven by an increase in contributions, which increased plan assets.
· A $6.7 million decrease in depreciation and amortization expense. The PSCW approved lower depreciation rates effective January 1, 2011, and we had lower software amortization in 2011.
· A $2.9 million decrease in stock-based compensation expense. In the third quarter of 2010, we began accounting for performance stock rights, restricted shares, and restricted share units as liability awards. The decrease was driven by changes in the fair value of these awards, primarily related to Integrys Energy Group’s stock price. We also recorded additional expense related to the change in accounting method in the third quarter of 2010.
· These decreases were partially offset by:
· A $3.2 million increase in the amortization of various regulatory deferrals. This increase was offset in revenues, resulting in no impact on earnings.
· A $3.0 million increase in customer assistance expense related to payments made to the Focus on Energy program.
· A $2.2 million increase in maintenance expense. One of the main drivers of this increase was the timing of scheduled plant outages.
· A $2.0 million increase in electric transmission expense.
· A $2.0 million increase in various electric generation operating expenses.
· A $1.3 million increase in taxes other than income taxes driven by an increase in gross receipts taxes.
· A $0.7 million increase in injuries and damages expenses.
Regulated Natural Gas Utility Segment Operations
|
| Three Months Ended |
| Change in |
| Nine Months Ended |
| Change in |
| ||||||||
|
| September 30 |
| 2011 Over |
| September 30 |
| 2011 Over |
| ||||||||
(Millions, except heating degree days) |
| 2011 |
| 2010 |
| 2010 |
| 2011 |
| 2010 |
| 2010 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Revenues |
| $ | 41.1 |
| $ | 42.9 |
| (4.2 | )% | $ | 255.4 |
| $ | 256.0 |
| (0.2 | )% |
Natural gas purchased for resale |
| 26.2 |
| 23.8 |
| 10.1 | % | 158.1 |
| 148.0 |
| 6.8 | % | ||||
Margins |
| 14.9 |
| 19.1 |
| (22.0 | )% | 97.3 |
| 108.0 |
| (9.9 | )% | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Operating and maintenance expense |
| 18.0 |
| 20.0 |
| (10.0 | )% | 54.1 |
| 57.3 |
| (5.6 | )% | ||||
Depreciation and amortization expense |
| 3.7 |
| 5.4 |
| (31.5 | )% | 11.2 |
| 16.9 |
| (33.7 | )% | ||||
Taxes other than income taxes |
| 1.3 |
| 1.3 |
| — | % | 3.9 |
| 4.2 |
| (7.1 | )% | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Operating income (loss) |
| (8.1 | ) | (7.6 | ) | 6.6 | % | 28.1 |
| 29.6 |
| (5.1 | )% | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Miscellaneous income |
| 0.1 |
| — |
| N/A |
| — |
| 0.1 |
| (100.0 | )% | ||||
Interest expense |
| (2.0 | ) | (2.6 | ) | (23.1 | )% | (7.1 | ) | (7.9 | ) | (10.1 | )% | ||||
Other expense |
| (1.9 | ) | (2.6 | ) | (26.9 | )% | (7.1 | ) | (7.8 | ) | (9.0 | )% | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Income (loss) before taxes |
| $ | (10.0 | ) | $ | (10.2 | ) | (2.0 | )% | $ | 21.0 |
| $ | 21.8 |
| (3.7 | )% |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Retail throughput in therms |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Residential |
| 15.0 |
| 16.7 |
| (10.2 | )% | 168.7 |
| 144.4 |
| 16.8 | % | ||||
Commercial and industrial |
| 11.8 |
| 12.1 |
| (2.5 | )% | 98.2 |
| 83.7 |
| 17.3 | % | ||||
Other |
| 9.5 |
| 8.0 |
| 18.8 | % | 23.2 |
| 18.0 |
| 28.9 | % | ||||
Total retail throughput in therms |
| 36.3 |
| 36.8 |
| (1.4 | )% | 290.1 |
| 246.1 |
| 17.9 | % | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Transport throughput in therms |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commercial and industrial |
| 68.4 |
| 66.4 |
| 3.0 | % | 252.9 |
| 241.5 |
| 4.7 | % | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Total throughput in therms |
| 104.7 |
| 103.2 |
| 1.5 | % | 543.0 |
| 487.6 |
| 11.4 | % | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Weather |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Heating degree days |
| 246 |
| 227 |
| 8.4 | % | 5,222 |
| 4,415 |
| 18.3 | % |
Third Quarter 2011 Compared with Third Quarter 2010
Revenues
Regulated natural gas utility segment revenues decreased $1.8 million, driven by:
· An approximate $3 million decrease related to a rate order effective January 14, 2011. See Note 14, “Regulatory Environment,” for more information on this rate order.
· An approximate $3 million decrease in revenues as a result of a 10.2% decrease in residential sales volumes, including the impact of decoupling. We attribute this decrease to lower use per customer in the third quarter of 2011.
· A partially offsetting approximate $3 million increase in revenues as a result of an approximate 12% increase in the average per-unit cost of natural gas sold. We pass through prudently incurred natural gas commodity costs to our customers in current rates.
· A partially offsetting approximate $1 million increase in revenues related to recovery of a regulatory asset related to previous energy efficiency legislation.
Margins
Regulated natural gas utility segment margins decreased $4.2 million. The negative impact of the rate order discussed above drove an approximate $3 million decrease. Lower residential sales volumes, including the impact of decoupling, also decreased margins by approximately $2 million.
Operating Loss
The operating loss at the regulated natural gas utility segment increased $0.5 million. This increase was primarily driven by the $4.2 million decrease in margins discussed above, partially offset by a $3.7 million decrease in operating expenses.
The decrease in operating expenses primarily related to:
· A $1.7 million decrease in depreciation and amortization expense. We received approval for lower depreciation rates from the PSCW, effective January 1, 2011.
· A $0.7 million decrease in employee benefits expense. The decrease was driven by changes in the fair value of amounts owed to plan participants under deferred compensation plans.
· A $0.7 million decrease in customer assistance expense related to payments made to the Focus on Energy program. The program promotes residential and small business energy efficiency and renewable energy products.
· A $0.7 million decrease in stock-based compensation expense. In the third quarter of 2010, we began accounting for performance stock rights, restricted shares, and restricted share units as liability awards. The decrease was driven by changes in the fair value of these awards, primarily related to Integrys Energy Group’s stock price. We also recorded additional expense related to the change in accounting method in the third quarter of 2010.
Nine Months 2011 Compared with Nine Months 2010
Revenues
Regulated natural gas utility segment revenues decreased $0.6 million, driven by:
· An approximate $16 million decrease in revenues as a result of an approximate 9% decrease in the average per-unit cost of natural gas sold.
· An approximate $12 million decrease in revenues related to the negative impact of a rate order effective January 14, 2011. See Note 14, “Regulatory Environment,” for more information on this rate order.
· A partially offsetting approximate $24 million net increase in revenues as a result of an 11.4% increase in sales volumes.
· Colder weather during the 2011 heating season, as shown by the 18.3% increase in heating degree days, drove an approximate $24 million increase in revenues.
· Higher sales volumes excluding the impact of weather resulted in approximately $13 million of additional revenues. We attribute this increase to a combination of higher use per customer and improved economic conditions for certain customer classes.
· Partially offsetting these increases was the approximate $13 million decrease from our decoupling mechanism.
· A partially offsetting approximate $2 million increase in revenues related to recovery of a regulatory asset related to previous energy efficiency legislation.
Margins
Regulated natural gas utility segment margins decreased $10.7 million. This decrease was driven by the negative impact of the rate order discussed above.
Operating Income
Operating income at the regulated natural gas utility segment decreased $1.5 million. This decrease was primarily driven by the $10.7 million decrease in margins discussed above, partially offset by a $9.2 million decrease in operating expenses.
The decrease in operating expenses primarily related to:
· A $5.7 million decrease in depreciation and amortization expense. We received approval for lower depreciation rates from the PSCW, effective January 1, 2011.
· A $1.6 million decrease in customer assistance expense related to payments made to the Focus on Energy program.
· A $0.9 million decrease in employee benefits expense. The decrease was driven by lower pension expense and changes in the fair value of amounts owed to plan participants under deferred compensation plans. The decrease in pension expense was driven by an increase in contributions, which increased plan assets.
· A $0.7 million decrease in stock-based compensation expense. In the third quarter of 2010, we began accounting for performance stock rights, restricted shares, and restricted share units as liability awards. The decrease was driven by changes in the fair value of these awards, primarily related to Integrys Energy Group’s stock price. We also recorded additional expense for the change in accounting method in the third quarter of 2010.
Other Segment Operations
|
| Three Months Ended |
| Change in |
| Nine Months Ended |
| Change in |
| ||||||||
|
| September 30 |
| 2011 Over |
| September 30 |
| 2011 Over |
| ||||||||
(Millions) |
| 2011 |
| 2010 |
| 2010 |
| 2011 |
| 2010 |
| 2010 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Operating income |
| $ | 0.2 |
| $ | 0.3 |
| (33.3 | )% | $ | 0.3 |
| $ | 0.4 |
| (25.0 | )% |
Other income |
| 2.0 |
| 1.9 |
| 5.3 | % | 7.8 |
| 7.0 |
| 11.4 | % | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Income before taxes |
| $ | 2.2 |
| $ | 2.2 |
| — | % | $ | 8.1 |
| $ | 7.4 |
| 9.5 | % |
Third Quarter 2011 Compared with Third Quarter 2010
There was no change in income before taxes for other segment operations.
Nine Months 2011 Compared with Nine Months 2010
Income before taxes for other segment operations increased $0.7 million. The increase was driven by lower interest expense owed to participants in the deferred compensation plans.
Provision for Income Taxes
|
| Three Months Ended |
| Nine Months Ended |
| ||||
|
| September 30 |
| September 30 |
| ||||
|
| 2011 |
| 2010 |
| 2011 |
| 2010 |
|
|
|
|
|
|
|
|
|
|
|
Effective Tax Rate |
| 35.8 | % | 33.3 | % | 35.9 | % | 36.1 | % |
Third Quarter 2011 Compared with Third Quarter 2010
Our effective tax rate increased in the third quarter of 2011. This increase primarily related to adjustments required by GAAP recorded in the third quarter of 2011 to ensure the year-to-date interim effective tax rate reflected the projected annual effective tax rate.
Nine Months 2011 Compared with Nine Months 2010
Our effective tax rate decreased during 2011. As a result of the 2010 federal health care reform, we expensed $4.5 million of deferred income taxes during the first quarter of 2010. See “Liquidity and Capital Resources, Other Future Considerations — Federal Health Care Reform” for more information. Also contributing to the lower effective tax rate was an increase in the federal income tax benefit of wind production tax credits in 2011. These decreases were partially offset when we increased our deferred income tax liabilities and expensed $1.6 million of income taxes in 2011 for a tax law change in Wisconsin. See “Liquidity and Capital Resources, Other Future Considerations — Recent Tax Law Changes” for more information.
LIQUIDITY AND CAPITAL RESOURCES
We believe we have adequate resources to fund ongoing operations and future capital expenditures. These resources include cash balances, liquid assets, operating cash flows, access to debt markets, and available borrowing capacity. However, our operating cash flows and access to capital markets can be impacted by macroeconomic factors outside of our control. Our borrowing costs can be impacted by short-term and long-term debt ratings assigned by independent credit rating agencies, as well as the market rates for interest.
Operating Cash Flows
During the nine months ended September 30, 2011, net cash provided by operating activities was $191.4 million, compared with $260.2 million for the same period in 2010. The $68.8 million decrease in net cash provided by operating activities was largely driven by a $44.3 million increase in contributions to pension and other postretirement benefit plans. In addition, net cash paid for income taxes increased by $22.1 million, primarily due to a tax refund for 2009 that was received in 2010.
Investing Cash Flows
Net cash used for investing activities was $63.9 million during the nine months ended September 30, 2011, compared with $60.4 million for the same period in 2010. The $3.5 million increase in net cash used for investing activities was primarily driven by a $2.0 million increase in cash used to fund capital expenditures (discussed below).
Capital Expenditures
Capital expenditures by business segment for the nine months ended September 30 were as follows:
Reportable Segment (millions) |
| 2011 |
| 2010 |
| Change |
| |||
Electric utility |
| $ | 50.4 |
| $ | 48.4 |
| $ | 2.0 |
|
Natural gas utility |
| 17.1 |
| 17.4 |
| (0.3 | ) | |||
Other |
| 0.3 |
| — |
| 0.3 |
| |||
WPS consolidated |
| $ | 67.8 |
| $ | 65.8 |
| $ | 2.0 |
|
The increase in capital expenditures at the electric utility segment was mainly due to the purchase of a combustion turbine, construction of temporary ash storage, and various projects at the Columbia plant. These expenditures were partially offset by the period-over-period impact of cash payments made in 2010 relating to the Crane Creek Wind Farm project, which was placed in service for accounting purposes in December 2009.
Financing Cash Flows
Net cash used for financing activities was $193.6 million during the nine months ended September 30, 2011, compared with $98.7 million for the same period in 2010. The $94.9 million increase in net cash used for financing activities was driven by:
· A $150.0 million increase due to the repayment of our 6.125% Senior Notes which matured in 2011.
· A $60.0 million increase in return of capital payments to Integrys Energy Group.
Partially offsetting these increases was a $127.3 million decrease due to $120.3 million of net borrowings of commercial paper in 2011, compared with $7.0 million of net repayments in 2010.
Significant Financing Activities
We had $120.3 million of outstanding commercial paper borrowings at September 30, 2011, and no outstanding commercial paper borrowings at September 30, 2010. We had no other outstanding short-term debt at September 30, 2011, and $10.0 million of short-term notes outstanding at September 30, 2010. See Note 4, “Short-Term Debt and Lines of Credit,” for more information.
Credit Ratings
We use internally generated funds and commercial paper borrowings to satisfy most of our capital requirements. We periodically issue long-term debt and receive equity contributions from Integrys Energy Group to reduce short-term debt, fund future growth, and maintain capitalization ratios as authorized by the PSCW.
Our current credit ratings are listed in the table below:
Credit Ratings |
| Standard & Poor’s |
| Moody’s |
|
Issuer credit rating |
| A- |
| A2 |
|
First mortgage bonds |
| N/A |
| Aa3 |
|
Senior secured debt |
| A |
| Aa3 |
|
Preferred stock |
| BBB |
| Baa1 |
|
Commercial paper |
| A-2 |
| P-1 |
|
Credit facility |
| N/A |
| A2 |
|
Credit ratings are not recommendations to buy or sell securities. They are subject to change, and each rating should be evaluated independently of any other rating.
On January 21, 2011, Standard & Poor’s confirmed our “stable” outlook, while revising the outlook for Integrys Energy Group to “positive” from “stable.”
Future Capital Requirements and Resources
Contractual Obligations
The following table shows our contractual obligations as of September 30, 2011, including those of our subsidiary.
|
|
|
| Payments Due By Period |
| |||||||||||
(Millions) |
| Total Amounts |
| 2011 |
| 2012 to |
| 2014 to |
| 2016 and |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Long-term debt principal and interest payments (1) |
| $ | 1,047.9 |
| $ | 9.8 |
| $ | 366.2 |
| $ | 174.4 |
| $ | 497.5 |
|
Operating lease obligations |
| 20.2 |
| 0.3 |
| 3.3 |
| 1.6 |
| 15.0 |
| |||||
Commodity purchase obligations (2) |
| 1,841.7 |
| 71.2 |
| 609.3 |
| 302.5 |
| 858.7 |
| |||||
Purchase orders (3) |
| 167.3 |
| 164.8 |
| 2.5 |
| — |
| — |
| |||||
Pension and other postretirement funding obligations (4) |
| 304.3 |
| 12.0 |
| 142.5 |
| 121.1 |
| 28.7 |
| |||||
Total contractual cash obligations |
| $ | 3,381.4 |
| $ | 258.1 |
| $ | 1,123.8 |
| $ | 599.6 |
| $ | 1,399.9 |
|
(1) Represents bonds and notes issued. We record all principal obligations on the balance sheet.
(2) The costs of commodity purchase obligations are expected to be recovered in future customer rates.
(3) Includes obligations related to normal business operations and large construction obligations.
(4) Obligations for pension and other postretirement benefit plans, other than the Integrys Energy Group Retirement Plan, cannot reasonably be estimated beyond 2013.
The table above does not reflect payments related to the manufactured gas plant remediation liability of $69.4 million at September 30, 2011, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 6, “Commitments and Contingencies,” for more information about environmental liabilities. The table also does not reflect any payments for the September 30, 2011 liability of $0.5 million related to unrecognized tax benefits, as the amount and timing of payments are uncertain. See Note 5, “Income Taxes,” for more information on unrecognized tax benefits.
Capital Requirements
As of September 30, 2011, our capital expenditures for the three-year period 2011 through 2013 were expected to be as follows:
(Millions) |
|
|
| |
Environmental projects |
| $ | 373.6 |
|
Electric and natural gas distribution projects |
| 116.8 |
| |
Electric and natural gas delivery and customer service projects |
| 45.3 |
| |
Other projects |
| 141.0 |
| |
Total capital expenditures |
| $ | 676.7 |
|
All projected capital and investment expenditures are subject to periodic review and may vary significantly from the estimates, depending on a number of factors. These factors include, but are not limited to, industry restructuring, regulatory constraints and requirements, changes in tax laws and regulations, market volatility, and economic trends.
Capital Resources
Management prioritizes the use of capital and debt capacity, determines cash management policies, uses risk management policies to hedge the impact of volatile commodity prices, and makes decisions regarding capital requirements in order to manage the liquidity and capital resource needs of the business segments. We plan to meet our capital requirements for the period 2011 through 2013 primarily through internally generated funds, debt financing, and equity infusions from Integrys Energy Group. We plan to keep debt to equity ratios at levels that can support current credit ratings and corporate growth. We believe we have adequate financial flexibility and resources to meet our future needs.
At September 30, 2011, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. Our long-term debt obligations contain covenants related to payment of principal and interest when due and various financial reporting obligations. Failure to comply with these covenants could result in an event of default, which, if not cured or waived, could result in acceleration of outstanding debt obligations.
See Note 4, “Short-Term Debt and Lines of Credit,” for more information on credit facilities and other short-term credit agreements, including short-term debt covenants.
Other Future Considerations
Decoupling
The PSCW approved the implementation of decoupling on a four-year trial basis, effective January 1, 2009, for our natural gas and electric residential and small commercial and industrial sales. Decoupling allows us to adjust rates going forward to recover or refund differences between the actual and authorized margin per customer impact of changes in volumes. The mechanism does not adjust for changes in volume resulting from changes in customer count, nor does it cover all customer classes. This decoupling mechanism includes an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers are included in rates upon approval in a rate order.
Climate Change
The EPA began regulating greenhouse gas emissions under the CAA in January 2011 by applying the BACT requirements (associated with the New Source Review program) to new and modified larger greenhouse gas emitters. Technology to remove and sequester greenhouse gas emissions is not commercially available at scale. Therefore, the EPA issued guidance that defines BACT in terms of improvements in energy efficiency as opposed to relying on pollution control equipment. In December 2010, the EPA announced its intent to develop new source performance standards for greenhouse gas emissions. The standards would apply to new and modified, as well as existing, electric utility steam generating units. The EPA planned to propose these standards in 2011 and finalize them in 2012; however, the proposal has since been delayed. Currently there is no applicable federal or state legislation pending that specifically addresses greenhouse gas emissions.
A risk exists that any greenhouse gas legislation or regulation will increase the cost of producing energy using fossil fuels. However, we believe the capital expenditures being made at our plants are appropriate under any reasonable mandatory greenhouse gas program. We also believe that our future expenditures to control greenhouse gas emissions or meet renewable portfolio standards will be recoverable in rates. We will continue to monitor and manage potential risks and opportunities associated with future greenhouse gas legislative or regulatory actions.
All of our generation and distribution facilities are located in the upper Midwest region of the United States. The same is true for all of our customers’ facilities. The physical risks posed by climate change for these areas are not expected to be significant at this time. Ongoing evaluations will be conducted as more information on the extent of such physical changes becomes available.
Federal Health Care Reform
In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (HCR) were signed into law. HCR contains various provisions that will affect the cost of providing health care coverage to our active and retired employees and their dependents. Although these provisions become effective at various times over the next 10 years, some provisions that affect the cost of providing benefits to retirees were reflected in our financial statements in 2010 and 2011.
Beginning in 2013, a provision of HCR will eliminate the tax deduction for employer-paid postretirement prescription drug charges to the extent those charges will be offset by the receipt of a federal Medicare Part D subsidy. As a result, we eliminated $4.5 million of our deferred tax asset related to postretirement benefits in 2010. All of this flowed through to net income as a component of income tax expense in 2010. We expect to seek rate recovery for the income impacts of this tax law change. If recovery in rates becomes probable, income tax expense will be reduced in that period. We are not currently able to predict how much, if any, will be recovered in rates.
In June 2011, Governor Walker signed into law a two-year budget bill. Under the bill, the Wisconsin tax code was changed to conform to the federal tax code, retroactive to December 2010 (discussed below). In accounting for this tax law change, we expensed an additional $1.6 million of deferred income taxes in 2011 related to the Medicare Part D subsidy.
Other provisions of HCR include the elimination of certain annual and lifetime maximum benefits and the broadening of plan eligibility requirements. It also includes the elimination of pre-existing condition restrictions, an excise tax on high-cost health plans, changes to the Medicare Part D prescription drug program, and numerous other changes. We participate in the Early Retiree Reinsurance Program that became effective on June 1, 2010. We continue to assess the extent to which the provisions of the new law will affect our future health care and related employee benefit plan costs.
Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act)
The Dodd-Frank Act was signed into law in July 2010. The majority of the implementation rules will be finalized and become effective over the 24 months following the signing of the act. Depending on the final rules, certain provisions of the Dodd-Frank Act relating to derivatives could increase capital and/or collateral requirements. Final rules for these provisions are expected in late 2011 or early 2012. We are monitoring developments related to this act and their impacts on our future financial results.
Recent Tax Law Changes
Federal
In December 2010, President Obama signed into law The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. This act includes tax incentives, such as an extension and increase of bonus depreciation, the extension of the research and experimentation credit, and the extension of treasury grants in lieu of claiming the ITC or production tax credit for certain renewable energy investments. In September 2010, President Obama signed into law the Small Business Jobs Act of 2010. This act includes tax incentives, such as an extension to bonus depreciation and changes to listed property, that affect us. We anticipate that these tax law changes will likely result in $40.0 million to $50.0 million of reduced cash payments for taxes during 2011 through 2012. These tax incentives may also reduce our utility rate base and, thus, future earnings relative to prior expectations. We have primarily used the proceeds from these incentives to make incremental contributions to our various employee benefit plans and to fund additional capital investments. In addition, these tax incentives have helped reduce our financing needs.
Michigan
In May 2011, Governor Snyder signed legislation that replaced Michigan’s business tax with a state income tax, effective January 1, 2012. In accounting for this tax law change, we deferred $1.0 million in 2011 for recovery in future rates.
Wisconsin
In June 2011, Governor Walker signed into law a two-year budget bill. Under the bill, the Wisconsin tax code was changed to conform to the federal tax code, retroactive to December 2010. In accounting for this tax law change, we expensed an additional $1.6 million of deferred income taxes in 2011 related to the Medicare Part D subsidy. We are continuing to analyze the implications of this bill.
CRITICAL ACCOUNTING POLICIES
We have reviewed our critical accounting policies for new critical accounting estimates and other significant changes and have found that the disclosures made in our Annual Report on Form 10-K for the year ended December 31, 2010, are still current and that there have been no significant changes.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Our market risks have not changed materially from the market risks reported in our 2010 Annual Report on Form 10-K.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of WPS’s disclosure controls and procedures (as defined by Securities Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based upon that evaluation, management, including our Chief Executive Officer and Chief Financial Officer, has concluded that WPS’s disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Control
There were no changes in our internal control over financial reporting (as defined by Securities Exchange Act Rules 13a-15(f) and 15d-15(f)) during the quarter ended September 30, 2011, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
For information on our material legal proceedings and matters, see Note 6, “Commitments and Contingencies.”
There were no material changes in the risk factors previously disclosed in Part I, Item 1A of our 2010 Annual Report on Form 10-K, which was filed with the SEC on February 24, 2011.
The documents listed in the Exhibit Index are attached as exhibits or incorporated by reference herein.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant, Wisconsin Public Service Corporation, has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| Wisconsin Public Service Corporation |
|
|
|
|
Date: November 2, 2011 | /s/ Diane L. Ford |
| Diane L. Ford |
| Vice President and Corporate Controller |
|
|
| (Duly Authorized Officer and Chief Accounting Officer) |
WISCONSIN PUBLIC SERVICE CORPORATION
FOR THE QUARTER ENDED SEPTEMBER 30, 2011
Exhibit No. |
| Description |
|
|
|
12 |
| Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements |
|
|
|
31.1 |
| Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Wisconsin Public Service Corporation |
|
|
|
31.2 |
| Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Wisconsin Public Service Corporation |
|
|
|
32 |
| Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for Wisconsin Public Service Corporation |
|
|
|
101 * |
| Financial statements from the Quarterly Report on Form 10-Q of Wisconsin Public Service Corporation for the quarter ended September 30, 2011, filed on November 2, 2011, formatted in eXtensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Income, (ii) the Condensed Consolidated Balance Sheets, (iii) the Condensed Consolidated Statements of Capitalization, (iv) the Condensed Consolidated Statements of Cash Flows, (v) the Condensed Notes To Financial Statements, and (vi) document and entity information |
* In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.