10-K 1 teg-12312013x10k.htm 10-K TEG-12.31.2013-10K
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________ to ___________________
Commission File Number
 
Registrant; State of Incorporation;
Address; and Telephone Number
 
IRS Employer Identification No.
 
 
 
 
 
1-11337
 
INTEGRYS ENERGY GROUP, INC.
(A Wisconsin Corporation)
130 East Randolph Street
Chicago, IL 60601-6207
(312) 228-5400
 
39-1775292
Securities registered pursuant to Section 12(b) of the Act:
 
Title of each class
 
Name of each exchange on which registered
 
 
 
 
 
 
 
Common Stock, $1 par value
 
New York Stock Exchange
 
 
6.00% Junior Subordinated Notes due 2073
 
New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [X]    No [ ]
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes [ ]    No [X]
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 [ ]



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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [X]    No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
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 [X]
Accelerated filer [ ]
 
Non-accelerated filer [ ]
Smaller reporting company [ ]
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ]    No [X]
 
State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant.
 
 
 
 
 
$4,623,528,068 as of June 28, 2013
 
 
Number of shares outstanding of each class of common stock, as of
 
 
February 25, 2014
 
 
 
 
 
Common Stock, $1 par value, 79,963,091 shares
 
DOCUMENT INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Integrys Energy Group, Inc. Annual Meeting of Shareholders to be held on May 15, 2014 are incorporated by reference into Part III.
 




INTEGRYS ENERGY GROUP, INC.
ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2013

TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


i


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ITEM 12.
 
 
 
 
 
 
 
 
 
 
 
 
 
A.
Statements of Income
 
 
 
B.
Statements of Comprehensive Income
 
 
 
C.
Balance Sheets
 
 
 
D.
Statements of Cash Flows
 
 
 
E.
Notes to Parent Company Financial Statements
 
 
 
 
 


ii


Acronyms Used in this Annual Report on Form 10-K
 
 
 
AFUDC
 
Allowance for Funds Used During Construction
AMRP
 
Accelerated Natural Gas Main Replacement Program
ASC
 
Accounting Standards Codification
ATC
 
American Transmission Company LLC
EPA
 
United States Environmental Protection Agency
FASB
 
Financial Accounting Standards Board
FERC
 
Federal Energy Regulatory Commission
GAAP
 
United States Generally Accepted Accounting Principles
IBS
 
Integrys Business Support, LLC
ICC
 
Illinois Commerce Commission
IRS
 
United States Internal Revenue Service
ITF
 
Integrys Transportation Fuels, LLC
MERC
 
Minnesota Energy Resources Corporation
MGU
 
Michigan Gas Utilities Corporation
MISO
 
Midcontinent Independent System Operator, Inc.
MPSC
 
Michigan Public Service Commission
MPUC
 
Minnesota Public Utilities Commission
N/A
 
Not Applicable
NSG
 
North Shore Gas Company
PELLC
 
Peoples Energy, LLC (formerly known as Peoples Energy Corporation)
PGL
 
The Peoples Gas Light and Coke Company
PSCW
 
Public Service Commission of Wisconsin
SEC
 
United States Securities and Exchange Commission
UPPCO
 
Upper Peninsula Power Company
WDNR
 
Wisconsin Department of Natural Resources
WPS
 
Wisconsin Public Service Corporation
WRPC
 
Wisconsin River Power Company



iii


Forward-Looking Statements

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are not guarantees of future results and conditions. 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 involve a number of risks and uncertainties. Some risks and uncertainties that could cause actual results to differ materially from those expressed or implied in forward-looking statements include those described in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2013, and those identified below:

The timing and resolution of rate cases and related negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated businesses;
Federal and state legislative and regulatory changes, including deregulation and restructuring of the electric and natural gas utility industries, financial reform, health care reform, energy efficiency mandates, reliability standards, pipeline integrity and safety standards, and changes in tax and other laws and regulations to which we and our subsidiaries are subject;
The risk of terrorism or cyber security attacks, including the associated costs to protect our assets and respond to such events;
The risk of failure to maintain the security of personally identifiable information, including the associated costs to notify affected persons and to mitigate their information security concerns;
Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards;
Costs and effects of litigation and administrative proceedings, settlements, investigations, and claims;
The ability to retain market-based rate authority;
The effects, extent, and timing of competition or additional regulation in the markets in which our subsidiaries operate;
Changes in credit ratings and interest rates caused by volatility in the financial markets and actions of rating agencies and their impact on our and our subsidiaries’ liquidity and financing efforts;
The risk of financial loss, including increases in bad debt expense, associated with the inability of our and our subsidiaries’ counterparties, affiliates, and customers to meet their obligations;
The effects of political developments, as well as changes in economic conditions and the related impact on customer energy use, customer growth, and our ability to adequately forecast energy use for our customers;
The ability to use tax credit and loss carryforwards;
The investment performance of employee benefit plan assets and related actuarial assumptions, which impact future funding requirements;
The risk associated with the value of goodwill or other intangible assets and their possible impairment;
The timely completion of capital projects within estimates, as well as the recovery of those costs through established mechanisms;
Potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed timely or within budgets;
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;
Changes in technology, particularly with respect to new, developing, or alternative sources of generation;
Unusual weather and other natural phenomena, including related economic, operational, and/or other ancillary effects of any such events;
The impact of unplanned facility outages;
The financial performance of ATC and its corresponding contribution to our earnings;
The timing and outcome of any audits, disputes, and other proceedings related to taxes;
The effectiveness of risk management strategies, the use of financial and derivative instruments, and the related recovery of these costs from customers in rates;
The effect of accounting pronouncements issued periodically by standard-setting bodies; and
Other factors discussed elsewhere herein and in other reports we file 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.



1


PART I

ITEM 1. BUSINESS

A. GENERAL

In this report, when we refer to "us," "we," "our," or "ours," we are referring to Integrys Energy Group, Inc. References to "Notes" are to the Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

For more information about our business operations, including financial and geographic information about each reportable business segment, see Note 27, Segments of Business, and Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations.

Integrys Energy Group, Inc.

We are a diversified energy holding company headquartered in Chicago, Illinois. We were incorporated in Wisconsin in 1993. Our wholly owned subsidiaries provide products and services in both the regulated and nonregulated energy markets. In addition, we have a 34% equity interest in ATC (an electric transmission company operating in Illinois, Michigan, Minnesota, and Wisconsin). We have five reportable segments, which we discuss below.

Facilities

For information regarding our facilities, see Item 2 - Properties. For our utility and nonregulated plant asset book value, see Note 5, Property, Plant, and Equipment.

Available Information

Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, registration statements, and any amendments to these documents are available, free of charge, on our website, www.integrysgroup.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. Reports, statements, and amendments posted on our website do not include access to exhibits and supplemental schedules electronically filed with the reports, statements, or amendments. We are not including the information contained on or available through our website as a part of, or incorporating such information by reference into, this Annual Report on Form 10-K.

You may obtain materials we filed with or furnished to the SEC at the SEC Public Reference Room at 100 F Street, NE, Washington, DC 20549. To obtain information on the operation of the Public Reference Room, you may call the SEC at 1-800-SEC-0330. You may also view our reports, proxy and registration statements, and other information (including exhibits) filed or furnished electronically with the SEC, at the SEC's website at www.sec.gov.

B. REGULATED NATURAL GAS UTILITY OPERATIONS

Our natural gas utility segment includes the regulated natural gas utility operations of MERC, MGU, NSG, PGL, and WPS. MERC and MGU, both Delaware corporations, began operations in July 2006 and April 2006, respectively, when we acquired their existing natural gas distribution operations in Minnesota and Michigan. NSG and PGL, both Illinois corporations, began operations in 1900 and 1855, respectively. We acquired NSG and PGL in February 2007 in the PELLC merger. WPS, a Wisconsin corporation, began operations in 1883.

Our regulated natural gas utilities provide service to approximately 1,698,000 residential, commercial and industrial, transportation, and other customers. Our customers are located in Chicago and the northern suburbs of Chicago, northeastern Wisconsin and an adjacent portion of Michigan's Upper Peninsula, various cities and communities throughout Minnesota, and the southern portion of lower Michigan.

Natural Gas Supply

Our regulated natural gas utilities manage portfolios of natural gas supply contracts, storage services, and pipeline transportation services designed to meet varying customer use patterns at the lowest reasonable cost.

Our regulated natural gas supply requirements are met through a combination of fixed price purchases, index price purchases, contracted and owned storage, peak-shaving facilities, and natural gas supply call options. Our regulated natural gas subsidiaries contract for fixed-term firm natural gas supply each year (in the United States and Canada) to meet the demand of firm system sales customers. To supplement natural gas supply and manage risk, our regulated natural gas utilities purchase additional natural gas supply on the monthly and daily spot markets.

For more information on our regulated natural gas utility supply and transportation contracts, see Note 15, Commitments and Contingencies.



2


Our regulated natural gas utilities own two storage fields and contract with various other underground storage service providers for additional storage services. Storage allows us to manage significant changes in daily natural gas demand and to purchase steady levels of natural gas on a year-round basis, thus providing a hedge against supply cost volatility. Our regulated natural gas utilities contract with local distribution companies and interstate pipelines to purchase firm transportation services. We believe that having multiple pipelines that serve our regulated natural gas service territory benefits our customers by improving reliability, providing access to a diverse supply of natural gas, and fostering competition among these service providers. These benefits can lead to favorable conditions for our regulated natural gas utilities when negotiating new agreements for transportation and storage services. Our regulated natural gas utilities further reduce their supply cost volatility through the use of financial instruments such as commodity futures, swaps, and options as part of their hedging programs.

PGL owns and operates an underground natural gas storage reservoir in central Illinois (Manlove Field) and a natural gas pipeline system that connects Manlove Field to Chicago with eight major interstate pipelines. These assets are directed primarily to serving rate-regulated retail customers and are included in PGL's regulatory rate base. PGL also uses a portion of these company-owned storage and pipeline assets as a natural gas hub, which consists of providing transportation and storage services in interstate commerce to its wholesale customers. Customers deliver natural gas to PGL for storage through an injection into the storage reservoir, and PGL returns the natural gas to the customers under an agreed schedule through a withdrawal from the storage reservoir. Title to the natural gas does not transfer to PGL. Therefore, all natural gas related only to the hub remains customer-owned. PGL recognizes service fees associated with the natural gas hub services provided to wholesale customers. These service fees reduce the cost of natural gas and services charged to retail customers in rates.

The table below is a rollforward of PGL's natural gas in storage balances related to the natural gas hub as well as natural gas hub service fees collected from wholesale customers:
Thousands of Dekatherms (MDth)
 
2013
 
2012
 
2011
Beginning Balance, January 1
 
5,240

 
5,261

 
5,156

Injections
 
7,000

 
7,000

 
7,000

Withdrawals
 
(7,097
)
 
(7,021
)
 
(6,895
)
Ending Balance, December 31
 
5,143

 
5,240

 
5,261


(Millions)
 
2013
 
2012
 
2011
Natural gas hub service fees
 
$
4.3

 
$
3.9

 
$
5.4


Our regulated natural gas utilities had adequate capacity to meet all firm natural gas demand obligations during 2013 and expect to have adequate capacity to meet all firm demand obligations during 2014. Our regulated natural gas utilities' forecasted design peak-day throughput is 3,857 MDth for the 2013 through 2014 heating season.

The sources of our deliveries to customers (including transportation customers) for regulated natural gas utility operations were as follows:
(MDth)
 
2013
 
2012
 
2011
Natural gas purchases
 
232,007

 
184,188

 
217,288

Natural gas purchases for electric generation
 
2,246

 
2,215

 
1,780

Customer-owned natural gas received
 
191,101

 
176,598

 
181,021

Underground storage, net
 
6,123

 
2,749

 
(1,425
)
Hub fuel in kind *
 
179

 
179

 
180

Liquefied petroleum gas (propane)
 
1

 
1

 
1

Owned storage cushion injection
 
(1,097
)
 
(1,097
)
 
(1,098
)
Contracted pipeline and storage compressor fuel, franchise requirements, and unaccounted-for natural gas
 
(12,992
)
 
(8,037
)
 
(10,809
)
Total
 
417,568

 
356,796

 
386,938


*
This delivered natural gas was originally provided by hub customers whose contract requires them to provide additional natural gas to compensate for unaccounted-for natural gas in future deliveries.

Regulatory Matters

Our regulated natural gas utility retail rates are regulated by the ICC, MPSC, MPUC, and PSCW. These commissions have general supervisory and regulatory powers over public utilities in their respective jurisdictions.

Sales are made and services are rendered by the regulated natural gas utilities pursuant to rate schedules on file with the respective commissions. These rate schedules contain various service classifications, which largely reflect customers' different uses and levels of consumption. Our regulated natural gas utilities bill customers for the distribution of natural gas as well as for a natural gas charge representing third-party costs for purchasing, transporting, and storing natural gas. This charge also includes gains, losses, and costs incurred under hedging programs, the amount of which is also subject to applicable commission authority. Prudently incurred natural gas costs are passed through to customers in current rates and,


3


therefore, have no impact on margins. Commissions in respective jurisdictions conduct annual proceedings regarding the reconciliation of revenues from the natural gas charge and related natural gas costs.

Almost all of the natural gas our regulated natural gas utilities distribute is transported to our distribution systems by interstate pipelines. The pipelines' transportation and storage services, including PGL's natural gas hub, are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. In addition, the state commissions are responsible for monitoring our regulated natural gas utilities' safety compliance programs for our pipelines under United States Department of Transportation regulations. These regulations include 49 Code of Federal Regulations (CFR) Part 192 (Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards) and 49 CFR Part 195 (Transportation of Hazardous Liquids by Pipeline).

All of our regulated natural gas utility subsidiaries are required to provide service and grant credit (with applicable deposit requirements) to customers within their service territories. Our regulated natural gas utilities are generally not allowed to discontinue service during winter moratorium months to residential customers who do not pay their bills. The Federal and certain state governments have programs that provide for a limited amount of funding for assistance to low-income customers of the utilities.

See Note 26, Regulatory Environment, for information regarding rate cases, decoupling mechanisms, bad debt recovery mechanisms, and other cost recovery mechanisms at our regulated natural gas utilities.

Other Matters

Seasonality

Since the majority of our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. During 2013, the regulated natural gas utility segment recorded approximately 64% of its revenues in January, February, March, November, and December.

Competition

Although our natural gas retail rates are regulated by various commissions, the regulated natural gas utilities still face varying degrees of competition from other entities and other forms of energy available to consumers. Many large commercial and industrial customers have the ability to switch between natural gas and alternate fuels. Due to the volatility of energy commodity prices, our regulated natural gas utilities have seen customers with dual fuel capability switch to alternate fuels for short periods of time, then switch back to natural gas as market rates change.

Our regulated natural gas utilities all offer natural gas transportation service, and certain of our regulated natural gas utilities also offer interruptible natural gas sales to enable customers to better manage their energy costs. Transportation customers purchase natural gas directly from third-party natural gas suppliers and use our regulated natural gas utilities' distribution systems to transport the natural gas to their facilities. Our regulated natural gas utilities still earn a distribution charge for transporting the natural gas for these customers. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has no impact on our regulated natural gas utility segment net income, as it is offset by an equal reduction to natural gas costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change.
 
Working Capital Requirements

The working capital needs of our regulated natural gas utility operations vary significantly over time due to volatility in levels of natural gas inventories and the price of natural gas. Our regulated natural gas utilities' working capital needs are met by cash generated from operations and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of the winter natural gas supply needs is typically purchased and stored from April through November. Also, planned capital spending on our regulated natural gas distribution facilities is concentrated in April through November. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.

C. REGULATED ELECTRIC UTILITY OPERATIONS

The electric utility segment includes the regulated electric utility operations of WPS and UPPCO. WPS, a Wisconsin corporation, began operations in 1883. UPPCO, a Michigan corporation, began operations in 1884. We acquired UPPCO in September 1998. In January 2014, we announced an agreement to sell UPPCO. The transaction is expected to close later in 2014. See Note 29, Subsequent Event, for more information.

The regulated electric utility operations of WPS and UPPCO provide service to approximately 497,000 residential, commercial and industrial, wholesale, and other customers. WPS's customers are located in northeastern Wisconsin and an adjacent portion of Michigan's Upper Peninsula. UPPCO's customers are located in Michigan's Upper Peninsula. Wholesale electric service is provided to various WPS customers, including municipal utilities, electric cooperatives, energy marketers, other investor-owned utilities, and municipal joint action agencies. UPPCO no longer provides


4


power supply service to wholesale electric customers due to the expiration of its remaining wholesale electric contracts in 2011. In 2013, retail electric revenues accounted for 89.0% of total electric revenues, while wholesale electric revenues accounted for 11.0% of total electric revenues.

In 2013, WPS reached a firm peak demand of 2,299 megawatts on July 18. At the time of this peak, WPS's total firm resources (i.e., generation plus firm purchases) totaled 3,213 megawatts.

The PSCW requires WPS to maintain a planning reserve margin above its projected annual peak demand forecast to help ensure reliability of electric service to its customers. The PSCW has a 14.5% reserve margin requirement for long-term planning (planning years two through ten). For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO under Module E of its Open Access Transmission and Energy Markets Tariff. MISO has a 14.2% reserve margin requirement from January 1 through May 31, 2014, and 14.8% for the remainder of 2014. The MPSC does not have minimum guidelines for future supply reserves.

In 2013, UPPCO reached a firm peak demand of 101 megawatts on August 20. At the time of this peak, UPPCO's total firm resources totaled 131 megawatts. The MPSC does not have minimum guidelines for future supply reserves; however, the MISO short-term planning reserve margin requirements described above also apply to UPPCO.

WPS and UPPCO expect future supply reserves to meet the minimum planning reserve margin requirements for 2014. WPS and UPPCO had adequate capacity through company-owned generation units and power purchase contracts to meet all firm electric demand obligations during 2013 and expect to have adequate capacity to meet all obligations during 2014.

Electric Supply

Both WPS and UPPCO are members of MISO, a FERC-approved, independent, nonprofit organization, which operates a financial and physical electric wholesale market in the Midwest. WPS and UPPCO offer their generation and bid their customer load into the MISO market. MISO evaluates WPS's, UPPCO's, and other market participants' energy offers into, and subsequent withdrawals from, the system to economically dispatch electricity within the system. MISO settles the participants' offers and bids based on locational marginal prices, which are market-driven values based on the specific time and location of the purchase and/or sale of energy.

Electric Generation and Supply Mix

The sources of our electric utility supply were as follows:
(Millions)
 
 
 
 
 
 
Energy Source (kilowatt-hours)
 
2013
 
2012
 
2011
Company-owned generation units
 
 
 
 
 
 
  Coal
 
8,723.1

 
7,390.1

 
8,634.5

  Natural gas, fuel oil, and tire-derived fuel
 
1,539.6

 
176.1

 
135.8

  Wind
 
309.7

 
330.6

 
309.3

  Hydro
 
307.1

 
251.2

 
348.9

Total company-owned generation units
 
10,879.5

 
8,148.0

 
9,428.5

Power purchase contracts
 
 
 
 
 
 
  Nuclear (Kewaunee Power Station) (1)
 
2,808.3

 
2,655.5

 
2,674.4

  Hydro
 
553.8

 
392.6

 
570.7

  Natural gas (Fox Energy Center, LLC (2) and Combined Locks Energy Center, LLC (3))
 
395.1

 
2,892.6

 
1,593.9

  Wind
 
209.1

 
220.1

 
210.6

  Other
 
674.0

 
1,580.5

 
235.8

Total power purchase contracts
 
4,640.3

 
7,741.3

 
5,285.4

Purchased power from MISO
 
863.9

 
849.3

 
1,605.2

Purchased power from other
 
107.3

 
106.3

 
100.1

Total purchased power
 
5,611.5

 
8,696.9

 
6,990.7

Opportunity sales
 
 
 
 
 
 
  Sales to MISO
 
(1,592.0
)
 
(1,800.6
)
 
(1,242.0
)
  Net sales to other
 
(407.8
)
 
(128.4
)
 
(64.6
)
Total opportunity sales
 
(1,999.8
)
 
(1,929.0
)
 
(1,306.6
)
Total electric utility supply
 
14,491.2

 
14,915.9

 
15,112.6


(1)
This power purchase contract expired in December 2013.

(2)
This power purchase contract was terminated in connection with the purchase of Fox Energy Company LLC in March 2013. See Note 3, Acquisitions, for more information.

(3)
This power purchase contract expired in October 2011.



5


Fuel Costs

The cost of fuel per generation of one million British thermal units was as follows:
Fuel Type
 
2013
 
2012
 
2011
Coal
 
$
2.57

 
$
2.52

 
$
2.44

Natural gas
 
3.47

 
3.97

 
5.64

Fuel oil
 
21.78

 
26.12

 
21.24


Coal Supply

Coal is the primary fuel source for WPS's electric generation facilities. WPS's regulated fuel portfolio strategy is to maintain a 35- to 45-day supply of coal at each plant site. The majority of the coal is purchased from Powder River Basin mines located in Wyoming. This low sulfur coal has been WPS's lowest cost coal source of any of the subbituminous coal-producing regions in the United States. Historically, WPS has purchased coal directly from the producer for its wholly owned plants. WPS also purchases the coal for the jointly owned Weston 4 plant, and Dairyland Power Cooperative reimburses WPS for its share of the coal costs. Wisconsin Power and Light Company purchases coal for the jointly owned Edgewater and Columbia plants and is reimbursed by WPS for its share of the coal costs. At December 31, 2013, WPS had coal transportation contracts in place for 100% of its 2014 coal transportation requirements. See Note 15, Commitments and Contingencies, for more information on coal purchases and coal deliveries under contract.

Power Purchase Agreements

Our electric utilities enter into short-term and long-term power purchase agreements to meet a portion of their electric energy supply needs. See Note 15, Commitments and Contingencies, for more information on power purchase obligations.

Regulatory Matters

WPS's retail electric rates are regulated by the PSCW and the MPSC. UPPCO's retail electric rates are regulated by the MPSC. The FERC regulates wholesale electric rates for WPS and UPPCO. WPS and UPPCO must also comply with mandatory electric system reliability standards developed by the North American Electric Reliability Corporation (NERC), the electric reliability organization certified by the FERC. The Midwest Reliability Organization is responsible for the enforcement of NERC’s standards for WPS and UPPCO.

The PSCW sets rates through its ratemaking process, which is based on recovery of operating costs and a return on invested capital. One of the cost recovery components is fuel and purchased power, which is governed by a fuel window mechanism. See Note 1(e), Revenue and Customer Receivables, for more information. The MPSC's ratemaking process is similar to the PSCW's, with the exception of fuel and purchased power costs, which are recovered on a one-for-one basis. WPS has formula-based rates, as approved by the FERC, for the sale of electricity to its wholesale customers.

See Note 26, Regulatory Environment, for more information regarding the rate cases and decoupling mechanisms of our electric utilities.

Hydroelectric Licenses

WPS, UPPCO, and WRPC (a company in which WPS has 50% ownership) have long-term licenses from the FERC for their hydroelectric facilities.

Other Matters

Seasonality

Our electric utility sales in Wisconsin are generally higher during the summer months due to the air conditioning requirements of customers. Our regulated electric utility sales in Michigan do not follow a significant seasonal trend due to cooler climate conditions in the Upper Peninsula of Michigan.

Competition

The retail electric utility market in Wisconsin is regulated by the PSCW. Retail electric customers currently do not have the ability to choose their electric supplier. However, utilities still face competition from other energy sources, such as self-generation by large industrial customers and alternative energy sources. In addition, utilities work to attract new customers into their service territories in order to increase sales. As a result, there is competition among utilities to keep energy rates low. Wisconsin utilities have continued to refine regulated tariffs in order to pass on the true cost of electricity to each class of customer by reducing or eliminating rate subsidies among different ratepayer classes.



6


Michigan electric energy markets are open to competition, subject to certain limitations. During 2012 and 2013, alternate energy suppliers entered our service territories in the Upper Peninsula of Michigan, creating an active competitive market.
 
D. INTEGRYS ENERGY SERVICES

Integrys Energy Services, Inc., a Wisconsin corporation, was established in 1994. Integrys Energy Services is a diversified nonregulated retail energy supply and services company that primarily sells electricity and natural gas in deregulated markets. In addition, Integrys Energy Services invests in energy assets with renewable attributes, primarily distributed solar assets.

Integrys Energy Services and its subsidiaries market electricity and natural gas in various retail markets, serving commercial and industrial customers, as well as direct and aggregated small commercial and residential customers. Aggregated customers are municipalities, associations, or groups of customers that have joined together to negotiate the purchase of electricity or natural gas as a larger group. At December 31, 2013, Integrys Energy Services was serving aggregated customers in Illinois, Ohio, and Michigan.

Integrys Energy Services invests in and promotes renewable energy, primarily distributed solar, which it believes is important to the future of the energy industry. Clean, renewable, and efficient energy sources are developed, acquired, owned, and operated by Integrys Energy Services. Integrys Energy Services assists customers with selecting an energy solution that meets their needs and collaborates with developers of energy projects to overcome challenges with integrating the technical, regulatory, and financial aspects of their projects.

Integrys Energy Services invested in a joint venture with Duke Energy Generation Services to build and finance distributed solar projects throughout the United States. While there is no current commitment to invest in new solar projects through this joint venture, Duke Energy Generation Services and Integrys Energy Services are continuing to pursue projects that meet acceptable return requirements and intend to equally fund the necessary equity capital for construction and ownership of future solar projects.

Integrys Energy Services uses physical and financial derivative instruments, including forwards, futures, options, and swaps, to manage its exposure to market risks from its energy assets and energy supply portfolios in accordance with limits and approvals established in its risk management and credit policies.

As previously discussed, Integrys Energy Services' long-term energy asset strategy is to invest in distributed renewable projects. Consistent with this strategy, Integrys Energy Services is currently pursuing the sale of Combined Locks Energy Center, a natural gas-fired cogeneration facility located in Wisconsin. In March 2013, WPS Empire State, Inc., a subsidiary of Integrys Energy Services, sold all of the membership interests of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC, both of which owned natural gas-fired generation plants located in the state of New York. In addition, in November 2012, Sunbury Holdings, LLC, a subsidiary of Integrys Energy Services, sold all of the membership interests of WPS Westwood Generation, LLC, a waste coal generation plant located in Pennsylvania. For more information, see Note 4, Discontinued Operations.

Energy Supply

Physical supply obligations are created when Integrys Energy Services executes forward retail customer sales contracts. Integrys Energy Services' electricity supply requirements are primarily met through bilateral electricity purchase agreements with generation companies and other marketers, as well as purchases from regional power pools. Integrys Energy Services does not own natural gas reserves, so all natural gas supply is procured from producers and other suppliers in the wholesale market. Natural gas is sourced at the customer demand regions, or from the supply region and transported to the customer demand regions under natural gas transportation contracts.

Fuel Supply for Generation Facilities

Integrys Energy Services' natural gas-fired facility (51.5% of its installed generation portfolio) is subject to market price volatility and is dispatched to produce energy only when it is economical to do so. This facility was classified as held for sale. See Note 4, Discontinued Operations, for more information regarding this held for sale facility. Integrys Energy Services' renewable energy facilities (48.5% of its installed generation portfolio) are powered by renewable resources such as solar irradiance or landfill gas. There is no market price risk associated with the fuel supply of these facilities; however, production at these facilities can be intermittent due to the availability of the renewable energy resource.

Regulatory Matters

Integrys Energy Services is a FERC-authorized power marketer and has all of the licenses required to conduct business in the states in which it operates.



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Other Matters

Customer Segmentation

As of December 31, 2013, Integrys Energy Services' largest retail electric markets included Illinois, New York, New England, Michigan, Mid-Atlantic, and Ohio. In addition, Integrys Energy Services' largest retail natural gas markets included Wisconsin, Mid-Atlantic, Illinois, Michigan, and Ohio. Integrys Energy Services continuously reviews and evaluates the profitability of its operations in each of its markets. Integrys Energy Services continues to concentrate on adding customers in existing markets and placing emphasis on business that provides an appropriate rate of return. See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations - Introduction for a discussion of the current strategy for Integrys Energy Services.

Integrys Energy Services is not dependent on any one customer segment. Rather, a significant percentage of its retail sales volume is derived from residential customers and several industries, including educational services; paper and allied products; food and kindred products; executive, legislative, and general government; real estate; and health services.

Seasonality

Integrys Energy Services’ business, in the aggregate, is somewhat seasonal with certain products selling more heavily in certain seasons than in others. Sales of natural gas generally peak in the winter months, while sales of electricity generally peak in the summer months. The first and fourth quarters, in the aggregate, have typically been the most profitable periods. Integrys Energy Services' business can be volatile as a result of market conditions and the related market opportunities available to its customers.

Competition

Integrys Energy Services is a nonregulated retail energy marketer that competes against regulated utilities and other retail energy marketers on the basis of price, reliability, customer service, product offerings, financial strength, consumer convenience, performance, and reputation.

The competitive landscape differs in each regional area and within each targeted customer segment. For residential and small commercial customers, the primary competitive challenges come from the incumbent utility (provider of default service), established national marketers, regional marketers, and affiliated utility marketing companies. The large commercial, institutional, and industrial segments are very competitive in most markets with nearly all natural gas customers having already switched away from utility supply to a competitive retail energy provider. National affiliated marketers, energy producers, and other independent retail energy companies compete for customers in this segment.

The local utilities generally have the advantage of long-standing relationships with their customers, and they have longer operating histories, greater financial and other resources, and greater name recognition in their markets compared to Integrys Energy Services. In addition, local utilities have been subject to many years of regulatory oversight and, thus, have a significant amount of experience regarding the policy preferences of their regulators. Local utilities may seek to decrease their tariff retail rates to limit or preclude opportunities for competitive energy suppliers and may seek to establish rates, terms, and conditions to the disadvantage of competitive energy suppliers.

The retail electric and natural gas markets in which Integrys Energy Services operates continue to evolve. Integrys Energy Services has been able to take advantage of continued growth opportunities as evidenced by increasing volumes delivered and contracted for future delivery in certain markets. During 2013, delivered electric and natural gas volumes grew approximately 60% and 58%, respectively, compared with 2012. In addition, Integrys Energy Services' electric and natural gas volumes for future delivery grew by approximately 3% and 102%, respectively, from December 31, 2012 to December 31, 2013. The low growth in electric volumes for future delivery is primarily due to being selected as the electric supplier for the City of Chicago aggregation program in December 2012. Although this contract extends through May 2015, the City of Chicago initially committed volumes through only May 2014. As of December 31, 2013, the City of Chicago had not yet committed volumes for the remaining term of the contract. Despite continued growth, sustained low commodity prices, capital costs, and market volatility have led to continued competitive pressure on per-unit margins.

Working Capital

The working capital needs of Integrys Energy Services vary significantly over time due to volatility in commodity prices and related collateral calls, and levels of natural gas storage inventories. Integrys Energy Services' working capital needs are met by cash generated from operations, equity infusions, and short-term debt. As of December 31, 2013, Integrys Energy Services had the ability to borrow up to $665.0 million through an intercompany credit facility with us. As of December 31, 2013, we had provided total parental guarantees of $541.5 million on behalf of Integrys Energy Services, which includes guarantees for the current retail business as well as residual guarantees related to exited businesses. Our exposure under these guarantees related to open transactions at December 31, 2013, was $296.2 million.



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E. ELECTRIC TRANSMISSION INVESTMENT

The electric transmission investment segment consists of our approximate 34% ownership interest in ATC. ATC, which began operations in 2001, owns and operates the electric transmission system, under the direction of the MISO, in parts of Wisconsin, Illinois, Minnesota and the Upper Peninsula of Michigan. ATC is subject to regulation by FERC as to rates, terms of service, and financing and by state regulatory commissions as to other aspects of business, including the construction of electric transmission assets. See Note 8, Equity Method Investments, for more information about ATC.

F. HOLDING COMPANY AND OTHER SEGMENT

The holding company and other segment includes the operations of the Integrys Energy Group holding company and the PELLC holding company, along with any nonutility activities at IBS, MERC, MGU, NSG, PGL, UPPCO, and WPS. The compressed natural gas operations of ITF are included in this segment as of September 1, 2011, the date on which we acquired Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle). See Note 3, Acquisitions, for more information about the acquisition of Trillium and Pinnacle.

G. ENVIRONMENTAL MATTERS

See Note 15, Commitments and Contingencies, for more information on our environmental matters.

H. CAPITAL REQUIREMENTS

For information on our capital requirements, see Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.

I. EMPLOYEES

At December 31, 2013, our consolidated subsidiaries had the following full-time employees:
 
 
Total Number of Employees
 
Percentage of Employees Covered by Collective Bargaining Agreements
PGL
 
1,296

 
74
%
IBS
 
1,288

 
%
WPS
 
1,242

 
69
%
Integrys Energy Services
 
294

 
%
MERC
 
217

 
20
%
NSG
 
166

 
77
%
MGU
 
159

 
69
%
UPPCO
 
118

 
81
%
ITF
 
108

 
%
Total
 
4,888

 
45
%

Our subsidiaries have collective bargaining agreements with various unions which are summarized in the table below.
Union
 
Subsidiary
 
Contract Expiration Date
Local 510 of the International Brotherhood of Electrical Workers, AFL CIO
 
UPPCO
 
April 12, 2014
Local 12295 of the United Steelworkers of America, AFL CIO CLC
 
MGU
 
January 15, 2015
Local 417 of the Utility Workers Union of America, AFL CIO
 
MGU
 
February 15, 2016
Local 31 of the International Brotherhood of Electrical Workers, AFL CIO
 
MERC
 
May 31, 2016
Local 420 of the International Union of Operating Engineers
 
WPS
 
October 16, 2016
Local 18007 of the Utility Workers Union of America
 
PGL
 
April 30, 2018
Local 2285 of the International Brotherhood of Electrical Workers, AFL CIO
 
NSG
 
June 30, 2019



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J. EXECUTIVE OFFICERS OF INTEGRYS ENERGY GROUP
Name and Age (1)
 
 
Position and Business
Experience During Past Five Years
 
Effective
Date
 
 
 
 
 
 
Charles A. Schrock
60
 
Chairman and Chief Executive Officer
 
01-01-14
 
 
 
Chairman, President and Chief Executive Officer
 
04-01-10
 
 
 
President and Chief Executive Officer
 
01-01-09
 
 
 
 
 
 
Lawrence T. Borgard
52
 
President and Chief Operating Officer
 
01-01-14
 
 
 
President and Chief Operating Officer – Utilities
 
04-05-09
 
 
 
President and Chief Operating Officer – Integrys Gas Group (2)
 
02-21-07
 
 
 
 
 
 
Phillip M. Mikulsky
65
 
Executive Vice President – Corporate Initiatives and Chief Security Officer
 
01-01-13
 
 
 
Executive Vice President – Business Performance and Shared Services
 
12-26-10
 
 
 
Executive Vice President – Corporate Development and Shared Services
 
09-21-08
 
 
 
 
 
 
Mark A. Radtke
52
 
Executive Vice President – Shared Services and Chief Strategy Officer
 
01-01-13
 
 
 
Executive Vice President and Chief Strategy Officer
 
12-26-10
 
 
 
Chief Executive Officer – Integrys Energy Services
 
01-10-10
 
 
 
President and Chief Executive Officer – Integrys Energy Services
 
06-01-08
 
 
 
 
 
 
James F. Schott
56
 
Vice President and Chief Financial Officer
 
01-01-13
 
 
 
Vice President – External Affairs
 
03-22-10
 
 
 
Vice President – Regulatory Affairs
 
07-18-04
 
 
 
 
 
 
Linda M. Kallas
54
 
Vice President and Controller
 
05-16-13
 
 
 
Vice President and Corporate Controller
 
09-01-12
 
 
 
Vice President of Finance and Accounting Services
 
06-06-07
 
 
 
 
 
 
William J. Guc
44
 
Vice President and Treasurer
 
12-01-10
 
 
 
Vice President – Finance and Accounting and Controller – Integrys Energy Services
 
03-07-10
 
 
 
Vice President and Controller – Integrys Energy Services
 
09-21-08
 
 
 
 
 
 
William D. Laakso
51
 
Vice President – Human Resources and Corporate Communications
 
01-01-13
 
 
 
Vice President – Human Resources
 
09-21-08
 
 
 
 
 
 
Jodi J. Caro
48
 
Vice President, General Counsel and Secretary
 
11-09-12
 
 
 
Vice President, General Counsel and Assistant Secretary
 
02-19-12
 
 
 
Vice President of Legal Services
 
01-07-08
 
 
 
 
 
 
Daniel J. Verbanac
50
 
President – Integrys Energy Services
 
01-01-10
 
 
 
Chief Operating Officer – Integrys Energy Services (previously named WPS Energy Services)
 
02-15-04

(1)
Officers and their ages are as of January 1, 2014. None of the executives listed above are related by blood, marriage, or adoption to any of our other officers listed or to any of our directors. Each officer holds office until his or her successor has been duly elected and qualified, or until his or her death, resignation, disqualification, or removal.

(2)
The Integrys Gas Group included MGU, MERC, NSG, and PGL.



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ITEM 1A. RISK FACTORS

You should carefully consider the following risk factors, as well as the other information included or incorporated by reference in this Annual Report on Form 10-K, when making an investment decision.

We are subject to government regulation, which may have a negative impact on our businesses, financial position, and results of operations.

We are subject to comprehensive regulation by several federal and state regulatory agencies and local governmental bodies. This regulation significantly influences our operating environment and may affect our ability to recover costs from regulated utility customers. Many aspects of our operations are regulated, including, but not limited to, construction and operation of facilities, conditions of service, the issuance of securities, and the rates that we can charge customers. We are required to have numerous permits, approvals, and certificates from these agencies to operate our business. Failure to comply with any applicable rules or regulations may lead to penalties or customer refunds, which could have a material adverse impact on our financial results.

Existing statutes and regulations may be revised or reinterpreted by federal and state regulatory agencies, or these agencies may adopt new laws and regulations that apply to us. We are unable to predict the impact on our business and operating results of any such actions by these agencies. However, changes in regulations or the imposition of additional regulations may require us to incur additional expenses or change business operations, which may have an adverse impact on our results of operations.

The rates, including adjustments determined under riders, that our regulated utilities are allowed to charge for retail and wholesale services are the most important factors influencing our business, financial position, results of operations, and liquidity. Rate regulation is premised on providing an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital. However, there is no assurance that regulatory commissions will consider all the costs of our regulated utilities to have been prudently incurred. In addition, the regulatory process will not always result in rates that will produce full recovery of such costs or provide for a reasonable return on equity. Certain expense and revenue items are deferred as regulatory assets and liabilities for future recovery or refund to customers, as authorized by regulators. Future recovery of regulatory assets is not assured, and is generally subject to review by regulators in rate proceedings for prudence and reasonableness. If recovery of costs is not approved or is no longer deemed probable, regulatory assets would be recognized in current period expense and could have a material adverse impact on our financial results.

Our operations are subject to risks beyond our control, including but not limited to, cyber security attacks, terrorist attacks, acts of war, or unauthorized access to personally identifiable information.

Any future terrorist attack, cyber security attack, and/or act of war affecting our facilities and operations could have an adverse impact on our results of operations, financial condition, and cash flows. The energy industry uses sophisticated information technology systems and network infrastructure, which control an interconnected system of generation, distribution, and transmission systems shared with other third parties. A successful physical or cyber security attack may occur despite our security measures or those that we require our vendors to take, which include compliance with reliability standards and critical infrastructure protection standards. Successful physical and cyber security attacks, including those targeting information systems and electronic control systems used at generating facilities and electric and natural gas transmission, distribution, and storage systems, could severely disrupt our operations and result in loss of service to customers. The risk of such attacks may also increase our capital and operating costs as a result of having to implement increased security measures for protection of our information technology and infrastructure.

Our business requires the collection and retention of personally identifiable information of our customers, shareholders, and employees, who expect that we will adequately protect such information. A significant theft, loss, or fraudulent use of personally identifiable information may cause our business reputation to be adversely impacted, may lead to potentially large costs to notify and protect the impacted persons, and/or may cause us to become subject to legal claims, fines, or penalties, any of which could adversely impact our results of operations.

The costs of repairing damage to our facilities, protecting personally identifiable information, and notifying impacted persons, as well as related legal claims, may not be recoverable in rates, may exceed the insurance limits on our insurance policies, or, in some cases, may not be covered by insurance.

We are subject to environmental laws and regulations, compliance with which could be difficult and costly.

We are subject to numerous federal and state environmental laws and regulations that affect many aspects of our operations, including future operations. These laws and regulations relate to air emissions, water quality, wastewater discharges, hazardous materials management, and the generation, transport, and disposal of solid and hazardous wastes. Such laws and regulations require us to implement compliance processes and obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections, and other approvals. Existing laws and regulations may be revised and/or new laws and regulations passed, including, but not limited to, rules addressing greenhouse gases such as carbon dioxide and methane, mercury, sulfur dioxide, and nitrogen oxide emissions, and the management of coal combustion byproducts, including fly ash.



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The EPA began regulating greenhouse gas emissions under the Clean Air Act (CAA) by applying the Best Available Control Technology (BACT) requirements, which are associated with the New Source Review Program. These requirements apply to new and modified larger greenhouse gas emitters. In September 2013, the EPA reproposed rules that impose carbon dioxide emission rate limits on new electric generating units and is expected to finalize such rules in a timely manner. The EPA is also expected to propose rules for existing units by no later than June 1, 2014, and issue final rules by June 1, 2015, with state implementation plans due by June 30, 2016. Until legislation is passed at the federal or state level or the EPA adopts final rules for electric utility steam generating units, it remains unclear as to (1) which industry sectors will be impacted, (2) when compliance will be required, (3) the magnitude of the greenhouse gas emissions reductions that will be required, and (4) the costs and opportunities associated with compliance.

It is possible that future carbon legislation and greenhouse gas emission regulations will increase the cost of electricity produced at fossil fuel-fired generation units. Future regulation may also affect the capital expenditures we would make for our generation units or distribution systems, including costs to further limit the greenhouse gas emissions from our operations through control technology such as carbon capture and storage. Any such regulation may also create substantial additional costs in the form of taxes or emission allowances and could also affect the availability or cost of fossil fuels. The steps we could be required to take to ensure that our facilities are in compliance with any such laws and regulations could be prohibitively expensive. As a result, certain coal-fired electric generating facilities may become uneconomical to run and could result in early retirement of some of our units or may force us to convert the units to an alternative type of fuel.

Our natural gas delivery systems may generate fugitive gas as a result of normal operations and as a result of excavation, construction, and repair of natural gas delivery systems. Fugitive gas typically vents to the atmosphere and consists primarily of methane. Carbon dioxide is also a byproduct of natural gas consumption. As a result, future legislation to regulate greenhouse gas emissions could increase the price of natural gas, restrict the use of natural gas, adversely affect our ability to operate our natural gas facilities, and/or reduce natural gas demand.

Environmental laws and regulations can also require us to incur expenditures for cleanup costs, damages arising from contaminated properties, and monitoring obligations. We accrue liabilities and defer costs (recorded as regulatory assets) incurred in connection with our former manufactured gas plant sites. These costs include all recoverable costs incurred to date, management's best estimates of future costs for investigation and remediation, and legal expenses, and are net of amounts recovered by or that may be recovered from insurance or other entities. The ultimate costs to remediate these sites could vary from the amounts currently accrued.

There is uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Citizen groups that feel environmental regulations are not being sufficiently enforced by environmental regulatory agencies may also bring citizen enforcement actions against us. Such actions could seek penalties, injunctive relief, and costs of litigation. There is also a risk that private citizens may bring lawsuits to recover environmental damages they believe they have incurred.

Compliance with current and future environmental laws and regulations may result in increased capital, operating, and other costs. Compliance could also impact future results of operations, cash flows, and financial condition if such costs are not recoverable through regulated rates. Noncompliance could result in fines, penalties, and injunctive measures negatively affecting our operations and facilities.

Any change in our authority to sell electricity at market-based rates may impact earnings.

The FERC has authorized certain of our subsidiaries to sell electricity in the wholesale market at market prices. These subsidiaries must file an updated market power analysis with the FERC at least every three years to demonstrate the subsidiary does not possess market power in that region. The FERC retains the authority to modify, revoke, or rescind this market-based rate authority. If the FERC determines that the relevant market is not workably competitive, that we or our subsidiaries possess market power, that we are not charging just and reasonable rates, or that we have not complied with the rules required in order to maintain market-based rates, the FERC may require our subsidiaries to sell power at a price based upon the costs incurred in producing the power, or otherwise revoke or rescind our authority in that market. Our revenues and profit margins may be negatively affected by any reduction by the FERC of the rates we may receive, or otherwise by any revocation or rescission of such authority.

Our nonregulated businesses may be unable to achieve acceptable returns as a result of competition from existing and future competitors, which could impact our earnings.

Our nonregulated businesses, including both our retail energy business, Integrys Energy Services, and our compressed natural gas business, ITF, face competition for customers. Competitors may be willing to accept lower returns, which would allow them to offer lower prices and other incentives, which may impact our ability to attract and retain customers.

In some retail markets, the principal competitor of Integrys Energy Services may be the incumbent retail energy provider. The incumbent retail energy provider has the advantage of long-standing relationships with its customers, including well-known brand recognition, or may have access to previously regulated assets. Additionally, Integrys Energy Services may face competition from a number of other competitive energy service providers, other energy market participants, or nationally branded providers of consumer products and services.



12


The market for renewable and efficient energy generation, including compressed natural gas, is relatively new, highly competitive, and rapidly evolving. We can provide no assurance that Integrys Energy Services and ITF will be able to compete successfully against current or potential competitors, who may have longer operating histories, better brand recognition, or greater financial, technical, and marketing resources than we do.

Increased competition for our nonregulated businesses may result in price reductions, reduced gross margins, and loss of market share. Any of these could harm our business and adversely affect our operating results and financial condition.

Adverse capital and credit market conditions could negatively affect our ability to meet liquidity needs, access capital, and/or grow or sustain our current business. Cost of capital and disruptions, uncertainty, and/or volatility in the financial markets could adversely impact our results of operations and financial condition, as well as exert downward pressure on our stock price.

Having access to the credit and capital markets, at a reasonable cost, is necessary for us to fund our operations and capital requirements. The capital and credit markets provide us with liquidity to operate and grow our businesses that is not otherwise provided from operating cash flows and also supports our ability to provide credit support for our subsidiaries. Disruptions, uncertainty, and/or volatility in those markets could increase our cost of capital or limit the availability of capital. If we or our subsidiaries are unable to access the credit and capital markets on terms that are reasonable, we may have to delay raising capital, issue shorter-term securities, and/or bear an increased cost of capital. This, in turn, could impact our ability to grow or sustain our current businesses, cause a reduction in earnings, result in a credit rating downgrade, and/or limit our ability to sustain our current common stock dividend level.

A reduction in our or our subsidiaries' credit ratings could materially and adversely affect our business, financial position, results of operations, and liquidity.

We cannot be sure that any of our or our subsidiaries' credit ratings will not be lowered by a rating agency if, in the rating agency’s judgment, circumstances in the future so warrant. Any downgrade could:

Require the payment of higher interest rates in future financings and possibly reduce the potential pool of creditors;
Increase borrowing costs under certain existing credit facilities;
Limit access to the commercial paper market;
Limit the availability of adequate credit support for our subsidiaries’ operations; and
Require provision of additional credit assurance, including cash margin calls, to contract counterparties.

Counterparties and customers may not meet their obligations.

We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, coal, or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to replace the underlying commitment at then-current market prices or we may be unable to meet all of our customers' natural gas and electric requirements unless or until alternative supply arrangements are put in place. In such event, we may incur losses, or our results of operations, financial position, or liquidity could otherwise be adversely affected.

Some of our customers are experiencing, or may experience, financial problems that could have a significant impact on their creditworthiness. We cannot provide assurance that financially distressed customers will not default on their obligations to us and that such defaults will not have a material adverse impact on our business, financial position, results of operations, or cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, could adversely impact our receivable collections or increase our bad debt allowances for these customers, which could adversely affect our operating results. In addition, such events might force customers to reduce their future use of our products and services, which could have a material adverse impact on our results of operations and financial condition.

Our operations are subject to various conditions which can result in fluctuations in the number of customers and their energy use.

Our operations are affected by the demand for electricity and natural gas, which can vary greatly based upon:

Fluctuations in general economic conditions and growth in the service areas in which we operate;
Weather conditions; and
Our customers' continued focus on energy efficiency and ability to meet their own energy needs.

We may not be able to use tax credit and/or net operating loss carryforwards.

We have significantly reduced our consolidated federal and state income tax liability in the past through tax credits and net operating loss carryforwards available under the applicable tax codes. We have not fully used these tax credits and net operating loss carryforwards in our previous tax filings, and we may not be able to fully use the tax credits and net operating losses available as carryforwards if our future federal and state taxable income and related income tax liability is insufficient to permit the use of such credits and losses. In addition, any future disallowance


13


of some or all of those tax credits or net operating loss carryforwards as a result of legislative change or adverse determination by one of the applicable taxing jurisdictions could materially affect our tax obligations and financial results.

Poor investment performance of retirement plan investments and other factors impacting retirement plan costs could unfavorably impact our liquidity and results of operations.

We have employee benefit plans that cover substantially all of our employees and retirees. Our cost of providing these benefit plans varies depending upon actual plan experience and assumptions concerning the future. These assumptions include earnings on and/or valuations of plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, estimated withdrawals by retirees, and required or voluntary contributions to the plans. Depending on the investment performance over time and other factors impacting our costs, we could be required to make larger contributions in the future to fund these plans. These additional funding obligations could have a material adverse impact on our cash flows, financial condition, and/or results of operations. Changes made to the plans may also impact current and future pension and other postretirement benefit costs.

We have recorded goodwill and other intangibles that could become impaired.

To the extent the value of goodwill or other intangibles becomes impaired, we have had to, and in the future, may also be required to, incur material noncash charges relating to such impairments. These impairment charges could have a material impact on our financial results.

We are actively involved with several capital projects, which are significant and are subject to a number of risks and uncertainties that may adversely affect the cost, timing, and completion of the projects.

Our regulated utilities are capital intensive and require significant investments in energy generation, natural gas storage, delivery, and other projects, including projects for environmental compliance and distribution system improvements. These projects include our AMRP at PGL, our emission control project called ReACT™ on Weston 3 for WPS, and our System Modernization and Reliability Project (SMRP) at WPS.

Achieving the intended benefits of any large construction project is subject to many uncertainties. These uncertainties include the ability to adhere to established budgets and time frames, the availability of labor and materials at estimated costs, the availability and cost of financing, and weather. There may also be contractor or supplier performance issues or adverse changes in their creditworthiness and difficulties meeting critical regulatory requirements. If construction of the projects should materially and adversely deviate from the schedules, estimates, and projections submitted to and approved by the applicable commissions, the commissions could deem these additional capital costs as imprudent and disallow recovery through currently established recovery mechanisms.

Furthermore, jointly owned projects, such as implementing emission control technology at the Columbia plant, are subject to the risk that one or more of the joint owners becomes either unable or unwilling to continue to fund project financial commitments. New joint owners would be difficult to secure at equivalent financial terms, or changes in the joint ownership make-up could increase project costs and/or delay the completion.

To the extent that delays occur, costs become unrecoverable, or we otherwise become unable to effectively manage and complete our capital projects, our results of operations, cash flows, and financial condition may be adversely affected.

Fluctuating commodity prices may impact energy margins and result in changes to liquidity requirements.

The margins and liquidity requirements of our businesses are impacted by changes in the forward and current market prices of natural gas, coal, electricity, renewable energy credits, and ancillary services. Changes in price could result in:

Higher working capital costs, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;
Increased liquidity requirements due to potential counterparty margin calls related to the use of derivative instruments to manage commodity price and volume exposure;
Reduced profitability to the extent that reduced margins, increased bad debt, and interest expense are not recovered through rates;
Higher rates charged to our customers, which could impact the company’s competitive position;
Reduced demand for energy, which could impact margins and operating expenses; and
Shutting down of generation facilities if the cost of generation exceeds the market price for electricity.

Our operations are subject to risks arising from the reliability of our electric generation, transmission and distribution facilities, natural gas infrastructure facilities and other facilities, as well as the reliability of third-party transmission providers.

The operation of electric generation and natural gas and electric distribution facilities involves many risks, including the risk of potential breakdown or failure of equipment or processes, which may occur due to storms, natural disasters, or other catastrophic events. Other risks include aging infrastructure, fuel supply or transportation disruptions, accidents, employee labor disputes, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, and performance below expected levels. Because our electric generation facilities are


14


interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by unexpected or uncontrollable events occurring on the systems of these third parties.

Operation of our power plants below expected capacity could result in lost revenues and increased expenses, including higher operating and maintenance costs, purchased power costs, and capital requirements. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems may occur and are an inherent risk of our business. Unplanned outages may reduce our revenues or may require us to incur significant costs by forcing us to operate our higher cost electric generators or obtain replacement power from third parties in the open market to satisfy our power sales obligations. Insurance, warranties, performance guarantees, or recovery through the regulatory process may not cover any or all of the lost revenues or increased expenses.

New and pending environmental regulations may force many generation facility owners in the Midwest, including our electric utilities, to retire a significant number of older coal-fired generation facilities, resulting in a potential reduction in the region's capacity reserve margin to below acceptable risk levels. This could also impair the reliability of the Midwest portion of the grid, especially during peak demand periods. A reduction in available future capacity could also adversely affect our ability to serve our customers' needs.

We are obligated to provide safe and reliable service to customers within our service territories. Meeting this commitment requires significant capital resources. Failure to provide safe and reliable service and failure to meet regulatory reliability standards could adversely affect our operating results through the imposition of penalties and fines or other adverse regulatory outcomes.

As a holding company, we rely on the earnings of our subsidiaries to meet our financial obligations.

We are a holding company, and our investments in our subsidiaries are our primary assets. Substantially all of our operations are conducted by our subsidiaries. Consequently, our ability to meet our financial obligations and pay dividends on our common stock is dependent upon the ability of our subsidiaries to make payments to us, whether through dividends or otherwise. Our subsidiaries are separate legal entities that have no obligation to pay any of our obligations or to make any funds available for that purpose or for the payment of dividends on our common stock. The ability of our subsidiaries to make payments to us depends on their earnings, cash flows, capital requirements, general financial condition, and regulatory limitations. In addition, each subsidiary's ability to pay dividends to us depends on any statutory and/or contractual restrictions, which may include requirements to maintain levels of debt or equity ratios, working capital, or other assets. Our utility subsidiaries are regulated by various state utility commissions, which generally possess broad powers to ensure that the needs of the utility customers are being met.

We are subject to the Wisconsin Public Utility Holding Act, which may limit merger, acquisition, and sale opportunities that could benefit our shareholders.

The Wisconsin Public Utility Holding Company Law limits our ability to invest in nonutility related businesses and may make it more difficult for others to obtain control of us. This law mandates that the PSCW must first determine that the acquisition is in the best interests of utility customers, investors, and the public. Those interests may, to some extent, be mutually exclusive. This provision and other requirements of the Wisconsin Public Utility Holding Company Act may delay, or reduce the likelihood of, a sale or change of control thus reducing the likelihood that shareholders will receive a takeover premium for their shares.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.



15


ITEM 2. PROPERTIES

A. REGULATED

Natural Gas Facilities

At December 31, 2013, our natural gas properties were located in Illinois, Wisconsin, Minnesota, and Michigan, and consisted of the following:

Approximately 22,300 miles of natural gas distribution mains,
Approximately 1,000 miles of natural gas transmission mains,
Approximately 1.3 million natural gas lateral services,
298 natural gas distribution and transmission gate stations,
A 3.9 billion-cubic-foot underground natural gas storage field located in Michigan,
A 38.0 billion-cubic-foot underground natural gas storage reservoir located in central Illinois,* and
A 2.0 billion-cubic-foot liquefied natural gas plant located in central Illinois.*

*
PGL owns and operates this reservoir and liquefied natural gas plant in central Illinois (Manlove Field). PGL also owns a natural gas pipeline system that connects Manlove Field to Chicago with eight major interstate pipelines. The underground storage reservoir also serves NSG under a contractual arrangement. PGL uses its natural gas storage and pipeline assets as a natural gas hub in the Chicago area.

Electric Facilities

The following table summarizes information on our electric generation facilities, including owned and jointly owned facilities, as of December 31, 2013:
Type
 
Name
 
Location
 
Primary Fuel
 
Rated Capacity
(Megawatts)
(1)
 
Steam
 
Columbia Units 1 and 2
 
Portage, Wisconsin
 
Coal
 
350.8

(2) 
 
 
Edgewater Unit 4
 
Sheboygan, Wisconsin
 
Coal
 
94.3

(2) 
 
 
Pulliam (4 units)
 
Green Bay, Wisconsin
 
Coal
 
325.5

(3) 
 
 
Weston Units 1, 2, and 3
 
Marathon County, Wisconsin
 
Coal
 
449.8

(3) 
 
 
Weston Unit 4
 
Marathon County, Wisconsin
 
Coal
 
375.8

(2) 
Total Steam
 
 
 
 
 
 
 
1,596.2

 
 
 
 
 
 
 
 
 
 
 
Combustion Turbine and Diesel
 
Fox Energy Center
 
Kaukauna, Wisconsin
 
Natural Gas
 
556.1

 
 
 
De Pere Energy Center
 
De Pere, Wisconsin
 
Natural Gas
 
164.2

 
 
 
Gladstone
 
Gladstone, Michigan
 
Oil
 
16.7

 
 
 
Juneau #31
 
Adams County, Wisconsin
 
Distillate Fuel Oil
 
6.2

(4) 
 
 
Portage
 
Houghton, Michigan
 
Oil
 
17.1

 
 
 
Pulliam #31
 
Green Bay, Wisconsin
 
Natural Gas
 
85.0

 
 
 
West Marinette #31
 
Marinette, Wisconsin
 
Natural Gas
 
38.2

 
 
 
West Marinette #32
 
Marinette, Wisconsin
 
Natural Gas
 
38.2

 
 
 
West Marinette #33
 
Marinette, Wisconsin
 
Natural Gas
 
77.1

 
 
 
Weston #31
 
Marathon County, Wisconsin
 
Natural Gas
 
12.9

 
 
 
Weston #32
 
Marathon County, Wisconsin
 
Natural Gas
 
42.4

 
Total Combustion Turbine and Diesel
 
 
 
 
 
 
 
1,054.1

 
 
 
 
 
 
 
 
 
 
 
Hydroelectric
 
Various
 
Michigan
 
Hydro
 
17.0

 
 
 
Various
 
Wisconsin
 
Hydro
 
60.7

(5) 
Total Hydroelectric
 
 
 
 
 
 
 
77.7

 
 
 
 
 
 
 
 
 
 
 
Wind
 
Lincoln
 
Wisconsin
 
Wind
 
0.9

 
 
 
Crane Creek
 
Iowa
 
Wind
 
20.2

 
Total Wind
 
 
 
 
 
 
 
21.1

 
 
 
 
 
 
 
 
 
 
 
Total System
 
 
 
 
 
 
 
2,749.1

 

(1)
Based on capacity ratings for summer 2014, which can differ from nameplate capacity, especially on wind projects. The summer period is the most relevant for capacity planning purposes at our electric utilities. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.



16


(2)
These facilities are jointly owned by WPS and various other utilities. The capacity indicated for each of these units is equal to WPS's portion of total plant capacity based on its percent of ownership.
Wisconsin Power and Light Company operates the Columbia and Edgewater units. WPS holds a 31.8% ownership interest in these facilities.
WPS operates the Weston 4 facility and holds a 70% ownership interest in this facility. Dairyland Power Cooperative holds the remaining 30% interest.

(3)  
In connection with the WPS Consent Decree with the EPA, early retirement of the Weston 1, Pulliam 5, and Pulliam 6 generating units is probable. These units have an aggregate generating capacity of 166.9 megawatts (based on summer 2014 capacity ratings). See Note 15, Commitments and Contingencies, for more information regarding the Consent Decree.

(4)  
WRPC owns and operates the Juneau unit. WPS holds a 50% ownership interest in WRPC and is entitled to 50% of the total capacity from the Juneau unit.

(5)  
WRPC owns and operates the Castle Rock and Petenwell units. WPS holds a 50% ownership interest in WRPC and is entitled to 50% of the total capacity at Castle Rock and Petenwell. WPS's share of capacity for Castle Rock is 8.6 megawatts, and WPS's share of capacity for Petenwell is 10.5 megawatts.

As of December 31, 2013, our electric utilities owned approximately 25,100 miles of electric distribution lines located in Michigan and Wisconsin and 174 electric distribution substations.

General

Substantially all of our utility plant at WPS, PGL, and NSG is subject to first mortgage liens.

B. INTEGRYS ENERGY SERVICES

The following table summarizes information on the energy asset facilities owned by Integrys Energy Services as of December 31, 2013:
Type
 
Name
 
Location
 
Fuel
 
Rated Capacity
(Megawatts)
(1)
 
Combined Cycle
 
Combined Locks
 
Combined Locks, Wisconsin
 
Natural Gas
 
45.5

(2) 
 
 
 
 
 
 
 
 
 
 
Reciprocating Engine
 
Winnebago
 
Rockford, Illinois
 
Landfill Gas
 
6.4

 
 
 
 
 
 
 
 
 
 
 
Solar
 
Various
 
Various States
 
Solar Irradiance
 
36.4

(3) 
 
 
 
 
 
 
 
 
 
 
Total Energy Assets
 
 
 
 
 
 
 
88.3

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Length of Pipeline
(Miles)
 
 
 
 
 
 
 
 
 
 
 
Landfill Gas Transportation
 
LGS
 
Brazoria County, Texas
 
N/A
 
33
 

(1)
Based on capacity ratings for summer 2014.

(2)
Combined Locks has an additional five megawatts of capacity available at this facility through the lease of a steam turbine. Integrys Energy Services is currently pursuing the sale of Combined Locks. See Note 4, Discontinued Operations, for more information.

(3)
The solar facilities consist of small distributed solar projects ranging from 0.1 to 4.0 megawatts in size. A portion of the solar facilities are wholly owned by subsidiaries of Integrys Energy Services and others are owned by INDU Solar Holdings, LLC, which is jointly owned by Integrys Energy Services and Duke Energy Generation Services. Of the capacity listed, 9.8 megawatts is Integrys Energy Services' portion of total solar capacity based on its ownership in INDU Solar Holdings, LLC.

C. HOLDING COMPANY AND OTHER

The following table summarizes information on the compressed natural gas fueling stations owned by ITF as of December 31, 2013:
Type
 
Name
 
Location
 
Number of Locations *
Compressed Natural Gas (CNG)
 
Various
 
Various States
 
25


*  
The CNG fueling stations consist of 22 stations that are wholly owned and operated by ITF. ITF operates two stations that are owned by AMP Trillium LLC, which is jointly owned by ITF and AMP Americas, LLC. ITF holds a 30% ownership interest in AMP Trillium LLC. Additionally, ITF operates one station that is owned by EVO Trillium LLC, which is jointly owned by ITF and Environmental Alternative Fuels, LLC. ITF holds a 15% ownership interest in EVO - Trillium LLC.



17


ITEM 3. LEGAL PROCEEDINGS

See Note 15, Commitments and Contingencies, for more information on material legal proceedings and matters related to us and our subsidiaries.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.



18


PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock and Dividend Data

Our common stock is traded on the New York Stock Exchange under the ticker symbol "TEG." The transfer agent and registrar for our common stock is American Stock Transfer & Trust Company, LLC, 6201 15th Avenue, Brooklyn, NY 11219. The quarterly high and low sales prices for our common stock and the cash dividends per share declared for each quarter during the past two years were as follows:
 
 
2013
 
2012
Quarter
 
High
 
Low
 
Dividends
 
High
 
Low
 
Dividends
First
 
$
58.27

 
$
52.55

 
$
0.68

 
$
54.88

 
$
50.80

 
$
0.68

Second
 
62.75

 
55.39

 
0.68

 
57.55

 
50.89

 
0.68

Third
 
63.58

 
53.80

 
0.68

 
61.92

 
51.79

 
0.68

Fourth
 
59.74

 
52.70

 
0.68

 
55.83

 
51.14

 
0.68


As of the close of business on February 19, 2014, we had 24,603 holders of record of our common stock.

Dividend Restrictions

We are a holding company and our ability to pay dividends is largely dependent upon the ability of our subsidiaries to make payments to us in the form of dividends or otherwise. See Note 19, Common Equity, for more information regarding restrictions on the ability of our subsidiaries to pay us dividends.

Equity Compensation Plans

See Item 11 - Executive Compensation for information regarding equity securities authorized for issuance under our equity compensation plans.

Issuer Purchases of Equity Securities

As of February 5, 2013, we began issuing new shares of common stock to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans. Prior to this date, shares were purchased on the open market to meet the requirements of these plans. There were no common stock purchases during the three months ended December 31, 2013. In conjunction with the announcement of the proposed sale of UPPCO, beginning February 5, 2014, we went back to purchasing shares on the open market to meet the requirements of these plans.



19


ITEM 6. SELECTED FINANCIAL DATA

INTEGRYS ENERGY GROUP, INC.
COMPARATIVE FINANCIAL DATA AND OTHER STATISTICS
As of or for Year Ended December 31
 
 
 
 
 
 
 
 
 
 
(Millions, except per share amounts, stock price, return on average equity, and number of shareholders and employees)
 
2013 *
 
2012
 
2011
 
2010
 
2009
Total revenues
 
$
5,634.6

 
$
4,212.4

 
$
4,685.9

 
$
5,169.8

 
$
7,464.7

Net income (loss) from continuing operations
 
350.0

 
294.0

 
230.0

 
245.2

 
(74.8
)
Net income (loss) attributed to common shareholders
 
351.8

 
281.4

 
227.4

 
220.9

 
(69.6
)
Total assets
 
11,243.5

 
10,327.4

 
9,983.2

 
9,816.8

 
11,844.6

Preferred stock of subsidiary
 
51.1

 
51.1

 
51.1

 
51.1

 
51.1

Long-term debt (excluding current portion)
 
2,956.2

 
1,931.7

 
1,845.0

 
2,134.6

 
2,367.7

 
 
 
 
 
 
 
 
 
 
 
Average shares of common stock
 
 
 
 
 
 
 
 
 
 
Basic
 
79.5

 
78.6

 
78.6

 
77.5

 
76.8

Diluted
 
80.1

 
79.3

 
79.1

 
78.0

 
76.8

 
 
 
 
 
 
 
 
 
 
 
Earnings (loss) per common share (basic)
 
 
 
 
 
 
 
 
 
 
Net income (loss) from continuing operations
 
$
4.37

 
$
3.70

 
$
2.89

 
$
3.13

 
$
(1.01
)
Earnings (loss) per common share (basic)
 
4.43

 
3.58

 
2.89

 
2.85

 
(0.91
)
Earnings (loss) per common share (diluted)
 
 
 
 
 
 
 
 
 
 
Net income (loss) from continuing operations
 
4.33

 
3.67

 
2.87

 
3.11

 
(1.01
)
Earnings (loss) per common share (diluted)
 
4.39

 
3.55

 
2.87

 
2.83

 
(0.91
)
Dividends per common share declared
 
2.72

 
2.72

 
2.72

 
2.72

 
2.72

 
 
 
 
 
 
 
 
 
 
 
Stock price at year-end
 
$
54.41

 
$
52.22

 
$
54.18

 
$
48.51

 
$
41.99

Book value per share
 
$
41.05

 
$
38.84

 
$
38.01

 
$
37.57

 
$
37.51

Return on average equity
 
11.2
%
 
9.4
%
 
7.7
%
 
7.7
%
 
(2.4
)%
Number of common stock shareholders
 
24,908

 
28,425

 
28,993

 
30,352

 
32,755

Number of employees
 
4,888

 
4,717

 
4,619

 
4,612

 
5,025


*
Includes the impact of the acquisition of the Fox Energy Center at the electric utilities in March 2013.



20


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

We are a diversified energy holding company with regulated natural gas and electric utility operations (serving customers in Illinois, Michigan, Minnesota, and Wisconsin), an approximate 34% equity ownership interest in ATC (a federally regulated electric transmission company), and
nonregulated energy operations.
 
Strategic Overview

Our goal is to create long-term value for shareholders and customers through growth in our core regulated businesses. We also have a nonregulated energy services business segment that is focused on growth within a controlled risk profile.

The essential components of our business strategy are:

Maintaining and Growing a Strong Regulated Utility BaseA strong regulated utility base is essential to maintaining a strong balance sheet, predictable cash flows, the desired risk profile, attractive dividends, and quality credit ratings. We believe the following projects have helped, or will help, maintain and grow our regulated utility base and meet our customers' needs:

An accelerated annual investment in natural gas distribution facilities (primarily replacement of cast iron mains) at PGL,
WPS's purchase of the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility located in Wisconsin, in 2013,
WPS's continued investment in environmental projects to improve air quality and meet or exceed the requirements set by environmental regulators,
WPS's System Modernization and Reliability Project to underground and upgrade certain electric distribution facilities in northern Wisconsin that will begin in 2014, and
Our approximate 34% ownership interest in ATC, a transmission company that had over $3.4 billion of transmission assets at December 31, 2013. ATC plans to invest approximately $3.0 billion to $3.6 billion in transmission system improvements during the next ten years. Although ATC's equity requirements to fund its capital investments will primarily be met by earnings reinvestment, we plan to continue to fund our share of the equity portion of future ATC growth as necessary.

For more detailed information on our capital expenditure program, see Liquidity and Capital Resources – Capital Requirements.

Providing Safe, Reliable, Competitively Priced, and Environmentally Sound Energy and Related Services Our mission is to provide customers with the best value in energy and related services. We strive to effectively operate a mixed portfolio of generation assets and prudently invest in new generation and distribution assets, while maintaining or exceeding environmental standards. This allows us to provide a safe, reliable, value-priced service to our customers. Our presence in the compressed natural gas fueling marketplace, while not currently significant, is complementary to our existing businesses and is consistent with our mission.

Operating a Nonregulated Energy Services Business Segment with a Controlled Risk and Capital Profile – Through our nonregulated Integrys Energy Services subsidiary, we provide retail natural gas and electric products to end-use customers primarily in the northeast quadrant of the United States. This subsidiary is focused on operating within select retail electric and natural gas markets in its current market footprint where it has experience and believes it will have the most success growing its recurring retail customer based business at acceptable returns. In addition, Integrys Energy Services continues to develop, acquire, own, and operate renewable energy projects, primarily distributed solar generation, in the United States. This strategy is intended to result in dependable cash and earnings contributions with a controlled risk and capital profile.

Integrating Resources to Provide Operational ExcellenceWe are committed to integrating resources of all our businesses and finding the best and most efficient processes while meeting all applicable legal and regulatory requirements. We strive to provide the best value to our customers and shareholders by embracing constructive change, leveraging capabilities and expertise, and using creative solutions to meet or exceed our customers' expectations. "Operational Excellence" initiatives have been implemented to reduce costs and encourage top performance in the areas of project management, process improvement, contract administration, and compliance.

Placing Strong Emphasis on Asset and Risk Management Our asset management strategy calls for the continuous assessment of existing assets, the acquisition of assets, and contractual commitments to obtain resources that complement our existing business and strategy. The goal is to provide the most efficient use of resources while maximizing return and maintaining an acceptable risk profile. This strategy focuses on acquiring assets consistent with strategic plans and disposing of assets, including property, plant, and equipment and entire business units, that are no longer strategic to ongoing operations, are not performing as intended, or have an unacceptable risk profile. We maintain a portfolio approach to risk and earnings.

Our risk management strategy includes the management of market, credit, liquidity, and operational risks through the normal course of business. Forward purchases and sales of electric capacity, energy, natural gas, and other commodities, and the use of derivative financial instruments, including commodity swaps and options, provide tools to reduce the risk associated with price movement in a volatile energy market. Each business


21


unit manages the risk profile related to these instruments consistent with our risk management policies, which are approved by the Board of Directors. The Corporate Risk Management Group, which reports through the Chief Financial Officer, provides corporate oversight.

RESULTS OF OPERATIONS 

Earnings Summary
 
 
Year Ended December 31
 
Change in 2013 Over 2012
 
Change in 2012 Over 2011
(Millions, except per share amounts)
 
2013
 
2012
 
2011
 
Natural gas utility operations
 
$
123.4

 
$
93.4

 
$
103.3

 
32.1
%
 
(9.6
)%
Electric utility operations
 
110.9

 
107.9

 
100.5

 
2.8
%
 
7.4
 %
Electric transmission investment
 
53.9

 
52.4

 
47.8

 
2.9
%
 
9.6
 %
Integrys Energy Services’ operations
 
78.3

 
41.1

 
(6.1
)
 
90.5
%
 
N/A

Holding company and other operations
 
(14.7
)
 
(13.4
)
 
(18.1
)
 
9.7
%
 
(26.0
)%
 
 
 
 
 
 
 
 
 
 
 
Net income attributed to common shareholders
 
$
351.8

 
$
281.4

 
$
227.4

 
25.0
%
 
23.7
 %
 
 
 
 
 
 
 
 
 
 
 
Basic earnings per share
 
$
4.43

 
$
3.58

 
$
2.89

 
23.7
%
 
23.9
 %
Diluted earnings per share
 
$
4.39

 
$
3.55

 
$
2.87

 
23.7
%
 
23.7
 %
 
 
 
 
 
 
 
 
 
 
 
Average shares of common stock
 
 

 
 

 
 
 
 
 
 
Basic
 
79.5

 
78.6

 
78.6

 
1.1
%
 
 %
Diluted
 
80.1

 
79.3

 
79.1

 
1.0
%
 
0.3
 %

2013 Compared with 2012

Our earnings increased $70.4 million year over year. The following items were the main contributors to the increase:

A $37.2 million after-tax non-cash increase in Integrys Energy Services’ margins related to derivative and inventory fair value adjustments.

The $30.3 million after-tax positive impact of rate orders at the utilities.

A $30.1 million after-tax increase due to an increase in sales volumes at the natural gas utilities, net of decoupling. Weather was colder than normal in 2013 and warmer than normal in 2012. In addition, certain of our natural gas utilities did not have decoupling impacts in 2012 to offset the impact of weather.

A $14.5 million increase in net income from discontinued operations. See Note 4, Discontinued Operations, for more information.

The $9.9 million after-tax positive impact of the first quarter 2013 reversal of reserves recorded in 2012 against decoupling accruals at PGL and NSG. See Note 26, Regulatory Environment, for more information.

These increases were partially offset by:

A $27.4 million after-tax increase in operating expenses at the natural gas utilities, excluding items directly offset in margins, driven by an increase in natural gas distribution costs.

An $11.0 million after-tax increase in operating expenses at Integrys Energy Services, driven by an increase in sales and marketing costs and outside service fees, primarily related to the expansion of the residential and small commercial customer business.

A $10.9 million after-tax increase in electric transmission expense and maintenance expense, excluding the newly acquired Fox Energy Center, at the electric utilities. The increase in maintenance expense was driven primarily by a plant outage at Weston 3.

2012 Compared with 2011

The $54.0 million increase in our earnings was driven by:

A $60.1 million after-tax non-cash increase in Integrys Energy Services’ margins related to derivative and inventory fair value adjustments.

A $33.7 million after-tax positive impact related to rate orders at the natural gas utilities, excluding items directly offset in operating expenses.


22



These increases were partially offset by:

A $26.2 million after-tax decrease in natural gas utility margins due to lower sales volumes driven by warmer weather, net of decoupling.

A $12.5 million decrease in income from discontinued operations at Integrys Energy Services. See Note 4, Discontinued Operations, for more information.

Regulated Natural Gas Utility Segment Operations 
 
 
Year Ended December 31
 
Change in 2013 Over 2012
 
Change in 2012 Over 2011
(Millions, except heating degree days)
 
2013
 
2012
 
2011
 
 
Revenues
 
$
2,105.0

 
$
1,672.0

 
$
1,998.0

 
25.9
 %
 
(16.3
)%
Purchased natural gas costs
 
1,046.2

 
775.0

 
1,101.4

 
35.0
 %
 
(29.6
)%
Margins
 
1,058.8

 
897.0

 
896.6

 
18.0
 %
 
 %
 
 
 
 
 
 
 
 
 
 


Operating and maintenance expense
 
632.7

 
527.5

 
523.6

 
19.9
 %
 
0.7
 %
Depreciation and amortization expense
 
136.0

 
131.8

 
126.1

 
3.2
 %
 
4.5
 %
Taxes other than income taxes
 
38.2

 
35.6

 
35.6

 
7.3
 %
 
 %
Operating income
 
251.9

 
202.1

 
211.3

 
24.6
 %
 
(4.4
)%
 
 
 
 
 
 
 
 
 
 


Miscellaneous income
 
1.2

 
0.6

 
2.2

 
100.0
 %
 
(72.7
)%
Interest expense
 
50.2

 
47.3

 
48.4

 
6.1
 %
 
(2.3
)%
Other expense
 
(49.0
)
 
(46.7
)
 
(46.2
)
 
4.9
 %
 
1.1
 %
 
 
 
 
 
 
 
 
 
 


Income before taxes
 
$
202.9

 
$
155.4

 
$
165.1

 
30.6
 %
 
(5.9
)%
 
 
 
 
 
 
 
 
 
 


Retail throughput in therms
 
 

 
 

 
 

 
 

 


Residential
 
1,663.6

 
1,324.8

 
1,541.5

 
25.6
 %
 
(14.1
)%
Commercial and industrial
 
534.8

 
406.0

 
469.5

 
31.7
 %
 
(13.5
)%
Other
 
74.0

 
75.3

 
61.3

 
(1.7
)%
 
22.8
 %
Total retail throughput in therms
 
2,272.4

 
1,806.1

 
2,072.3

 
25.8
 %
 
(12.8
)%
 
 
 
 
 
 
 
 
 
 


Transport throughput in therms
 
 

 
 

 
 

 
 

 


Residential
 
252.7

 
204.0

 
237.4

 
23.9
 %
 
(14.1
)%
Commercial and industrial
 
1,650.6

 
1,557.9

 
1,559.7

 
6.0
 %
 
(0.1
)%
Total transport throughput in therms
 
1,903.3

 
1,761.9

 
1,797.1

 
8.0
 %
 
(2.0
)%
 
 
 
 
 
 
 
 
 
 


Total throughput in therms
 
4,175.7

 
3,568.0

 
3,869.4

 
17.0
 %
 
(7.8
)%
 
 
 
 
 
 
 
 
 
 


Weather
 
 

 
 

 
 

 
 

 


Average actual heating degree days
 
7,285

 
5,601

 
6,675

 
30.1
 %
 
(16.1
)%
Average normal heating degree days
 
6,600

 
6,709

 
6,702

 
(1.6
)%
 
0.1
 %

Natural gas utility margins are defined as natural gas utility operating revenues less purchased natural gas costs. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. There was an approximate 7% increase and an approximate 20% decrease in the average per-unit cost of natural gas sold during 2013 and 2012, respectively, which had no impact on margins.



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2013 Compared with 2012

Margins

Regulated natural gas utility segment margins increased $161.8 million, driven by:

An approximate $67 million net increase in margins due to sales volume variances and our decoupling mechanisms.

The combined effect of the change in weather year over year and the impact of our decoupling mechanisms increased margins approximately $50 million. In 2012, margins at the natural gas utilities were negatively impacted by unusually warm weather, and the majority of our natural gas utilities either did not have decoupling mechanisms in place or the mechanism did not cover weather-related volume variances. In 2013, decoupling mechanisms were in place for all the natural gas utilities, but colder than normal weather did have a positive impact on MGU's margins as their decoupling mechanism does not cover weather-related volume variances. Margins for certain customer classes in both years were sensitive to volume variances as they were not covered by the decoupling mechanisms. See Note 26, Regulatory Environment, for more information on our decoupling mechanisms.

In 2013, PGL and NSG recorded an increase in revenues of approximately $17 million when reserves established in 2012 against regulatory assets related to decoupling from a prior period were reversed. The reversal was recorded after the Illinois Appellate Court issued an opinion in March 2013 that affirmed the ICC's order approving the decoupling mechanisms. See Note 26, Regulatory Environment, for more information.

An approximate $53 million increase in margins related to certain riders at PGL and NSG and certain energy efficiency programs at four of our natural gas utilities. This increase was offset by an equal increase in operating expenses, resulting in no impact on earnings.

Our natural gas utilities billed approximately $27 million more to customers for energy efficiency programs at MGU, NSG, PGL, and WPS in 2013.

PGL and NSG recovered approximately $26 million more for environmental cleanup costs at their former manufactured gas plant sites related to an increase in remediation activity during 2013. See Note 15, Commitments and Contingencies, for more information about the manufactured gas plant sites.

An approximate $31 million net increase in margins due to rate orders. See Note 26, Regulatory Environment, for more information.

The rate increases at PGL and NSG, effective June 27, 2013, and January 21, 2012, and other impacts of rate design, had an approximate $32 million positive impact on margins.

MERC recognized an approximate $2 million increase in margins primarily driven by the impact of a July 2012 rate order from the MPUC. Customer refunds were accrued in 2012 as a result of 2011 interim rates that had been in effect.

A reduction in rates at WPS, effective January 1, 2013, resulted in an approximate $3 million negative impact on margins.

An approximate $8 million increase in margins due to the MPUC's approval of MERC's energy conservation incentives in December 2013. These financial incentives were earned by MERC for achieving certain conservation improvement program goals.

Operating Income

Operating income at the regulated natural gas utility segment increased $49.8 million. This increase was driven by the $161.8 million increase in margins discussed above, partially offset by a $112.0 million increase in operating expenses.

The increase in operating expenses was primarily due to:

A $31.7 million increase in energy efficiency program expenses at our natural gas utilities. Margins increased by an equal amount, resulting in no impact on earnings.

A $28.6 million increase driven by higher amortization of regulatory assets at certain of our natural gas utilities related to environmental cleanup costs for manufactured gas plant sites. For approximately $26 million of the increase in expenses, margins increased by an equal amount, resulting in no impact on earnings.

A $22.1 million increase in natural gas distribution costs, primarily at PGL. The increase was partially due to increased labor and contractor costs driven by additional compliance work. A portion of the compliance work was driven by new local regulations related to natural gas distribution main openings and repairs in the public way. Natural gas distribution costs also increased due to a plastic pipe fittings replacement project.


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An $8.3 million net increase in employee benefit costs. The total employee benefit costs increase of $10.4 million was primarily due to higher pension expense, largely at PGL, driven by a lower discount rate in 2013. The lower discount rate did not significantly impact the other natural gas utilities due to an increase in contributions to those plans in prior years, which increased plan assets. WPS deferred $2.1 million of certain increases in pension and other employee benefit costs that will be recovered in a future rate proceeding as a result of its 2013 rate order. See Note 26, Regulatory Environment, for more information.

A $7.2 million increase in bad debt expense, driven by a cost of natural gas component included as part of PGL's and NSG's bad debt expense tracking mechanisms. This natural gas component is charged to customers based on actual volumes and natural gas prices. As a result of this component, bad debt expense was primarily impacted by both higher natural gas costs in 2013 and an increase in sales volumes. However, the increase in bad debt expense does not impact earnings as it is offset by higher rates through a rider mechanism, resulting in higher margins.

A $5.2 million increase in legal and outside services expense.

A $4.2 million net increase in depreciation and amortization expense. Continued investment in property and equipment, primarily the AMRP at PGL, drove the increase in expense. Partially offsetting the increase was a $3.4 million reduction in expense at MERC related to a new depreciation study approved by the MPUC on July 29, 2013. The study included changes to salvage values and costs of removal, as well as extensions to the service lives of certain assets. In addition, there was a $2.5 million reduction in expense at MGU. In January 2013, the Michigan Court of Appeals issued an order reversing the MPSC's previously ordered disallowance associated with the early retirement of certain MGU assets in 2010. See Note 26, Regulatory Environment, for more information.

A $2.7 million increase in asset usage charges from IBS, driven by new software for both natural gas management and work asset management that was placed in service during the third quarter of 2013.

A $2.6 million increase in taxes other than income taxes, driven by the Illinois invested capital tax. This tax assessment is based on an entity's equity and long-term debt balances, which have increased for PGL in 2013.

Other Expense

Other expense at the regulated natural gas utilities increased $2.3 million in 2013. Interest expense on long-term debt increased, driven by higher average long-term debt outstanding in 2013.

2012 Compared with 2011

Margins

Regulated natural gas utility segment margins increased $0.4 million, driven by:

An approximate $42 million net increase in margins due to rate orders. See Note 26, Regulatory Environment, for more information.

The rate increases at PGL and NSG, effective January 21, 2012, and other impacts of rate design, had an approximate $48 million positive impact on margins.

A reduction in rates at WPS, effective January 1, 2012, resulted in an approximate $5 million negative impact on margins. The rate decrease was driven by reduced contributions to the Focus on Energy Program, which promotes residential and small business energy efficiency and renewable energy products. The margin impact from the reduction in contributions is offset by lower operating expenses.

MERC had an approximate $1 million decrease in margins in 2012 primarily driven by the impact of a rate order from the MPUC finalized in January 2013. A preliminary order was received in July 2012 that adjusted 2011 interim rates in effect since February 1, 2011.

An approximate $4 million net increase in margins related to certain riders at PGL and NSG. This increase was offset by an equal increase in operating expenses, resulting in no impact on earnings.

PGL and NSG billed approximately $7 million more to customers for energy efficiency programs in 2012.

PGL and NSG refunded approximately $2 million more to customers under bad debt riders in 2012.

PGL and NSG recovered approximately $1 million less for environmental cleanup costs at their former manufactured gas plant sites in 2012. The lower recovery reflects a pass-through to customers in rates of an environmental settlement received by NSG from a potentially responsible party's performance and payment bond. The impact of the settlement was partially offset by an increase in remediation activity at PGL during 2012. See Note 15, Commitments and Contingencies, for more information about the manufactured gas plant sites.



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The above increases in margins were partially offset by an approximate $43 million net decrease in margins, including the impact of decoupling, due to a 7.8% decrease in volumes sold.

Substantially warmer weather during 2012 drove an approximate $55 million decrease in margins. Heating degree days decreased 16.1%.

Lower sales volumes excluding the impact of weather resulted in an approximate $6 million decrease in margins. Sales volumes were slightly lower due to lower use per customer.

Decoupling impacts at certain natural gas utilities drove an approximate $18 million increase in margins. Decoupling does not cover all jurisdictions or customer classes.

Decoupling accruals in 2012 had an approximate $9 million positive impact on the year-over-year variance. Decoupling lessened the negative impact from some of the decreased sales volumes at WPS and MGU through higher future recoveries from customers. This was limited by an $8.0 million decoupling cap that was reached by WPS during the second quarter of 2012. In 2012, reserves were recorded against all decoupling accruals at PGL and NSG after an ICC order declared these amounts may be subject to refund. See Note 26, Regulatory Environment, for more information.

Decoupling accruals in 2011 had an approximate $9 million positive impact on the year-over-year variance. Decoupling lessened the positive impact in 2011 from some of the higher sales volumes at PGL, NSG, WPS, and MGU through higher future refunds to customers.

Operating Income

Operating income at the regulated natural gas utility segment decreased $9.2 million. This decrease was driven by a $9.6 million increase in operating expenses.

The increase in operating expenses was primarily related to:

A $24.6 million increase in natural gas distribution costs, primarily at PGL. The increase was partially due to increased labor costs driven by annual wage increases, as well as additional employees required for compliance work related to inside safety inspections and corrosion review. Additional contractors were also needed for street restoration and pipe maintenance to replace employees that were moved to the AMRP project.

A $5.7 million increase in depreciation and amortization expense resulting from increased investment in property and equipment, primarily driven by the AMRP.

An approximate $4 million net increase at PGL and NSG driven by an increase in regulatory liabilities related to energy efficiency programs, partially offset by higher amortization of regulatory liabilities related to bad debt riders and lower amortization of regulatory assets related to environmental cleanup costs for manufactured gas plant sites. Margins increased by an equal amount, resulting in no impact on earnings.

These increases were partially offset by:

A $9.9 million decrease in energy efficiency program expenses related to WPS's participation in the Focus on Energy Program and MERC's conservation improvement program. Costs for both programs are recovered in rates.

An $8.6 million decrease in bad debt expense, driven by a new cost of gas component included as part of PGL's and NSG's bad debt expense tracking mechanisms. The change in the bad debt mechanisms was approved in PGL's and NSG's rate orders, effective January 21, 2012. In those orders, the ICC required that a natural gas cost component of the bad debt mechanism be charged to customers based on actual volumes and natural gas prices. As a result of this component, bad debt expense was primarily impacted by lower natural gas costs in 2012 and, to a lesser extent, by the decrease in sales volumes. However, $6.8 million of the decrease in bad debt expense does not impact earnings as it is offset by lower rates, resulting in lower margins.

A $2.7 million decrease in workers compensation expense related to both fewer incidents and less severe injuries during 2012, primarily at PGL.

A $2.4 million decrease in asset usage charges from IBS driven by certain computer hardware that was fully depreciated in 2011.