BKH 10K 12 31 2012


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC  20549
Form 10-K
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
o
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 001-31303
 
BLACK HILLS CORPORATION
Incorporated in South Dakota
625 Ninth Street
IRS Identification Number
 
Rapid City, South Dakota  57701
46-0458824
Registrant’s telephone number, including area code
(605) 721-1700
 
 
 
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange
on which registered
Common stock of $1.00 par value
 
New York Stock Exchange

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           o

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes           o           No           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           o

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 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           o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    o

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).
Large accelerated filer    x 
Accelerated filer    o
Non-accelerated filer   o
Smaller reporting company o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes           o           No           x

State the aggregate market value of the voting stock held by non-affiliates of the Registrant.
 
At June 30, 2012                                  $1,400,316,896

Indicate the number of shares outstanding of each of the Registrant’s classes of common stock, as of the latest practicable date.
Class
Outstanding at January 31, 2013
Common stock, $1.00 par value
44,222,903

shares

Documents Incorporated by Reference
Portions of the Registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2013 Annual Meeting of Stockholders to be held on April 23, 2013, are incorporated by reference in Part III of this Form 10-K.





TABLE OF CONTENTS

 
 
 
  Page
 
 
 
GLOSSARY OF TERMS AND ABBREVIATIONS
 
 
 
 
 
 
 
 
WEBSITE ACCESS TO REPORTS
 
 
 
 
 
 
 
 
FORWARD-LOOKING INFORMATION
 
Part I
 
 
 
 
 
ITEMS 1. and 2.
BUSINESS AND PROPERTIES
 
 
 
 
 
 
 
ITEM 1A.
RISK FACTORS
 
 
 
 
 
 
 
ITEM 1B.
UNRESOLVED STAFF COMMENTS
 
 
 
 
 
 
 
ITEM 3.
LEGAL PROCEEDINGS
 
 
 
 
 
 
 
ITEM 4.
SPECIALIZED DISCLOSURES
 
Part II
 
 
 
 
 
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
 
 
 
 
 
 
ITEM 6.
SELECTED FINANCIAL DATA
 
 
 
 
 
 
 
ITEMS 7. and 7A.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
 
 
 
 
 
 
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
 
 
 
 
 
 
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
 
 
 
 
 
 
ITEM 9A.
CONTROLS AND PROCEDURES
 
 
 
 
 
 
 
ITEM 9B.
OTHER INFORMATION
 
Part III
 
 
 
 
 
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 
 
 
 
 
 
 
ITEM 11.
EXECUTIVE COMPENSATION
 
 
 
 
 
 
 
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
 
 
 
 
 
 
 
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
 
 
 
 
 
 
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
 
 
 
 
 
 
 
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
 
 
 
 
 
 
 
 
SIGNATURES
 
 
 
 
 
 
 
 
INDEX TO EXHIBITS
 

2



GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:
AFUDC
Allowance for Funds Used During Construction
AltaGas
AltaGas Renewable Energy Colorado LLC, a subsidiary of AltaGas Ltd.
AOCI
Accumulated Other Comprehensive Income
Aquila Transaction
Our July 14, 2008 acquisition of five utilities from Aquila, Inc.
ARO
Asset Retirement Obligations
ASC
Accounting Standards Codification
ASU
Accounting Standards Update as issued by the FASB
ATRA
American Taxpayer Relief Act of 2012
Basin Electric
Basin Electric Power Cooperative
Bbl
Barrel
Bcfe
Billion cubic feet equivalent
BHC
Black Hills Corporation; the Company
BHEP
Black Hills Exploration and Production, Inc., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Colorado IPP
Black Hills Colorado IPP, LLC a direct wholly-owned subsidiary of Black Hills Electric Generation
Black Hills Energy
The name used to conduct the business of Black Hills Utility Holdings, Inc., and its subsidiaries
Black Hills Electric Generation
Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Non-regulated Holdings
Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Power
Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings
Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Wyoming
Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
BLM
United States Bureau of Land Management
Btu
British thermal unit
CFTC
United States Commodity Futures Trading Commission
CG&A
Cawley, Gillespie & Associates, Inc., an independent consulting and engineering firm
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation
Cheyenne Light Pension Plan
The Cheyenne Light, Fuel and Power Company Pension Plan
Cheyenne Prairie
Cheyenne Prairie Generating Station currently being constructed in Cheyenne, Wyo. by Cheyenne Light and Black Hills Power. Construction is expected to be completed for this 132 megawatt facility in 2014.
City of Gillette
The City of Gillette, Wyoming, affiliate of the JPB. The JPB financed the purchase of 23 percent of Wygen III power plant for the City of Gillette
CO2
Carbon dioxide
Colorado Electric
Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado Gas
Black Hills Colorado Gas Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Cooling Degree Day
A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.

3



CPCN
Certificate of Public Convenience and Necessity
CPUC
Colorado Public Utilities Commission
CT
Combustion turbine
CVA
Credit Valuation Adjustment
DC
Direct current
De-designated interest rate swaps
The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under the accounting for derivatives and hedges but subsequently de-designated in December 2008
Dodd-Frank
Dodd-Frank Wall Street Reform and Consumer Protection Act
DOE
United States Department of Energy
DSM
Demand Side Management
Dth
Dekatherms
EBITDA
Earnings before interest, taxes, depreciation and amortization, a non-GAAP measurement
ECA
Energy Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of fuel and purchased power through to customers.
Economy Energy
Electricity purchased by one utility from another utility to take the place of electricity that would have cost more to produce on the utility’s own system
Enserco
Enserco Energy Inc., a formerly wholly-owned subsidiary of Black Hills Non-regulated Holdings, which is presented in discontinued operations throughout this Annual Report filed on Form 10-K
EPA
United States Environmental Protection Agency
EPA Region VIII
EPA Region VIII (Mountains and Plains) located in Denver serving Colorado, Montana, North Dakota, South Dakota, Utah, Wyoming and 27 Tribal Nations
Equity Forward Agreement
Equity Forward Agreement with J. P. Morgan connected to a public offering of 4,413,519 million shares of Black Hills Corporation common stock, including the over-allotment shares
EWG
Exempt Wholesale Generator
FASB
Financial Accounting Standards Board
FDIC
Federal Depository Insurance Corporation
FERC
United States Federal Energy Regulatory Commission
Fitch
Fitch Ratings
GAAP
Accounting principles generally accepted in the United States of America
GCA
Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to the customer.
GHG
Greenhouse gases
Global Settlement
Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
Happy Jack
Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
Hastings
Hastings Fund Management Ltd
Heating Degree Day
A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
Idaho Cogeneration Facility
Partnership investment owned 50 percent by Black Hills Electric Generation, sold Jan. 18, 2011
IFRS
International Financial Reporting Standards
IIF
IIF BH Investment LLC, a subsidiary of an investment entity advised by J.P. Morgan Asset Management
Iowa Gas
Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP
Independent power producer
IPP Transaction
The July 11, 2008 sale of seven of our IPP plants to affiliates of Hastings and IIF
IRS
United States Internal Revenue Service

4



IUB
Iowa Utilities Board
J.P. Morgan
J.P. Morgan Securities LLC
JPB
Consolidated Wyoming Municipalities Electric Power System Joint Powers Board. The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette
Kansas Gas
Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
kV
Kilovolt
LIBOR
London Interbank Offered Rate
LOE
Lease Operating Expense
Loveland Area Project
Part of the Western Area Power Association transmission system
MACT
Maximum Achievable Control Technology
MAPP
Mid-Continent Area Power Pool
MATS
Utility Mercury and Air Toxics Rules under the United States EPA National Emissions Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units
Mbbl
Thousand barrels of oil
Mcf
Thousand cubic feet
Mcfe
Thousand cubic feet equivalent
MDU
Montana Dakota Utilities Co., a regulated utility division of MDU Resources Group, Inc.
MEAN
Municipal Energy Agency of Nebraska
MGP
Manufactured Gas Plants
MMBtu
Million British thermal units
MMcf
Million cubic feet
MMcfe
Million cubic feet equivalent
Moody’s
Moody’s Investors Service, Inc.
MSHA
Mine Safety and Health Administration
MTPSC
Montana Public Service Commission
MW
Megawatts
MWh
Megawatt-hours
NA
Not Applicable
Native load
Energy required to serve customers within our service territory
Nebraska Gas
Black Hills Nebraska Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
NERC
North American Electric Reliability Corporation
NGL
Natural Gas Liquids (Gallon equals 7 Mcfe)
NOx
Nitrogen oxide
NOL
Net operating loss
NPDES
National Pollutant Discharge Elimination System
NPSC
Nebraska Public Service Commission
NYMEX
New York Mercantile Exchange
OPEC
Organization of the Petroleum Exporting Countries
OSHA
Occupational Safety & Health Administration
PPA
Power Purchase Agreement
PPACA
Patient Protection and Affordable Care Act of 2010
PSCo
Public Service Company of Colorado
PUD
Proved undeveloped reserves
PUHCA 2005
Public Utility Holding Company Act of 2005
RCRA
Resource Conservation and Recovery Act
REPA
Renewable Energy Purchase Agreement

5



Revolving Credit Facility
Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2017
SDPUC
South Dakota Public Utilities Commission
SEC
U. S. Securities and Exchange Commission
Silver Sage
Silver Sage Windpower, LLC, owned by Duke Energy Generation Services
SO2
Sulfur dioxide
S&P
Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
Spinning Reserve
Generation capacity that is on-line but unloaded and that can respond within 10 minutes to compensate for generation or transmission outages.
System Peak Demand
Represents the highest point of customer usage for a single hour for the system in total. Our system peaks include demand loads for 100 percent of plants regardless of joint ownership.
TCA
Transmission Cost Adjustment -- adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
ug/m3
Micrograms per Cubic Meter of Air

Twin Eagle
Twin Eagle Resource Management, LLC
VEBA
Voluntary Employee Benefit Association
VOC
Volatile Organic Compounds
WDEQ
Wyoming Department of Environmental Quality
WECC
Western Electricity Coordinating Council
WPSC
Wyoming Public Service Commission
WRDC
Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings

Website Access to Reports

The reports we file with the SEC are available free of charge at our website www.blackhillscorp.com as soon as reasonably practicable after they are filed. In addition, the charters of our Audit, Governance and Compensation Committees are located on our website along with our Code of Business Conduct, Code of Ethics for our Chief Executive Officer and Senior Finance Officers, Corporate Governance Guidelines of the Board of Directors and Policy for Director Independence. The information contained on our website is not part of this document.

Forward-Looking Information

This Form 10-K contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.


6



PART I

ITEMS 1 AND 2.
BUSINESS AND PROPERTIES

History and Organization

Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company,” “we,” “us” or “our”), is a diversified energy company headquartered in Rapid City, S.D. Our predecessor company, Black Hills Power and Light Company, was incorporated and began providing electric utility service in 1941. It was formed through the purchase and combination of several existing electric utilities and related assets, some of which had served customers in the Black Hills region since 1883. In 1956, we began producing, selling and marketing various forms of energy through non-regulated businesses.

We operate principally in the United States with two major business groups: Utilities and Non-regulated Energy. Our Utilities Group is comprised of our regulated Electric Utilities and regulated Gas Utilities segments, and our Non-regulated Energy Group is comprised of our Power Generation, Coal Mining and Oil and Gas segments.

For more than 15 years, we also owned and operated Enserco, an energy marketing business that engaged in natural gas, crude oil, coal, power and environmental marketing and trading in the United States and Canada. On Feb. 29, 2012, we sold Enserco, representing our entire Energy Marketing segment, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the reclassification of this segment as discontinued operations. See Note 23 in the accompanying Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further details.

Business Group
Financial Segment
Utilities
Electric Utilities
 
Gas Utilities
 
 
Non-regulated Energy
Power Generation
 
Coal Mining
 
Oil and Gas

Our Electric Utilities segment generates, transmits and distributes electricity to approximately 202,000 electric customers in South Dakota, Wyoming, Colorado and Montana and also distributes natural gas to approximately 35,000 gas utility customers of Cheyenne Light in Cheyenne, Wyo. Our Gas Utilities segment serves approximately 532,000 natural gas utility customers in Colorado, Nebraska, Iowa and Kansas. Our Electric Utilities own 859 megawatts of generation and 8,530 miles of electric transmission and distribution lines, and our Gas Utilities own 624 miles of intrastate gas transmission pipelines and 19,979 miles of gas distribution mains and service lines. Our Utilities Group generated net income of $79.6 million for the year ended December 31, 2012 and had total assets of $3.2 billion at December 31, 2012.

Our Power Generation segment produces electric power from our generating plants and sells the electric capacity and energy primarily to our utilities under long-term contracts. Our Coal Mining segment produces coal at our coal mine near Gillette, Wyo. Our Oil and Gas segment engages in the exploration, development and production of crude oil and natural gas, primarily in the Rocky Mountain region. Our Non-regulated Energy Group generated net income of $24.7 million for the year ended December 31, 2012 and had total assets of $0.5 billion at December 31, 2012.

Segment Financial Information

We discuss our business strategy and other prospective information in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations. Financial information regarding our business segments is incorporated herein by reference to Item 8 - Financial Statements and Supplementary Data, and particularly Note 17 to the Consolidated Financial Statements, in this Annual Report on Form 10-K.

Discontinued Operations in the accompanying financial information includes the results of our Energy Marketing segment sold in February 2012.


7



Business Group Overview

Utilities Group

We conduct electric utility operations and combination electric and gas utility operations through three subsidiaries: Black Hills Power (South Dakota, Wyoming and Montana), Cheyenne Light (Wyoming), and Colorado Electric (Colorado). Our Electric Utilities generate, transmit and distribute electricity to approximately 202,000 customers; and also distribute natural gas to approximately 35,000 natural gas utility customers of Cheyenne Light in Cheyenne, Wyo. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates.

We conduct natural gas utility operations on a state-by-state basis through our Colorado Gas, Nebraska Gas, Iowa Gas and Kansas Gas subsidiaries. Our Gas Utilities distribute and transport natural gas through our distribution network to approximately 532,000 customers. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.

We also provide non-regulated services through our Service Guard and Tech Services product lines. Service Guard primarily provides appliance repair services to approximately 62,000 residential customers through company technicians and third party service providers, typically through on-going monthly service agreements. Tech Services primarily serves gas transportation customers throughout our service territory by constructing customer-owned gas infrastructure facilities, typically through one-time contracts, with a limited number of on-going monthly maintenance agreements.


Electric Utilities Segment

Capacity and Demand

System peak demands for the Electric Utilities for each of the last three years are listed below:

 
System Peak Demand (in megawatts)
 
 
 
 
 
 
 
 
 
 
 
 
 
2012
 
2011
 
2010
 
 
Summer
Winter
 
Summer
Winter
 
Summer
 
Winter
 
 
 
 
 
 
 
 
 
 
 
 
Black Hills Power
449
362
 
452
408
 
396
 
377
 
Cheyenne Light
187
174
 
181
175
 
176
 
164
 
Colorado Electric
400
284
 
392
297
 
384
 
289
 
Total Electric Utilities Peak Demands
1,036
820
 
1,025
880
 
956
 
830
 



8



Regulated Power Plants

As of December 31, 2012, our Electric Utilities’ ownership interests in electric generation plants were as follows:

Unit
Fuel
Type
Location
Ownership
Interest %
Owned Capacity (MW)
Year
Installed
Black Hills Power:
 
 
 
 
 
Wygen III (1)
Coal
Gillette, Wyo.
52.0%
57.2
2010
Neil Simpson II
Coal
Gillette, Wyo.
100.0%
90.0
1995
Wyodak (2)
Coal
Gillette, Wyo.
20.0%
72.4
1978
Osage (3)
Coal
Osage, Wyo.
100.0%
34.5
1948-1952
Ben French (3)
Coal
Rapid City, S.D.
100.0%
25.0
1960
Neil Simpson I (3)
Coal
Gillette, Wyo.
100.0%
21.8
1969
Neil Simpson CT
Gas
Gillette, Wyo.
100.0%
40.0
2000
Lange CT
Gas
Rapid City, S.D.
100.0%
40.0
2002
Ben French Diesel #1-5
Oil
Rapid City, S.D.
100.0%
10.0
1965
Ben French CTs #1-4
Gas/Oil
Rapid City, S.D.
100.0%
80.0
1977-1979
Cheyenne Light:
 
 
 
 
 
Wygen II
Coal
Gillette, Wyo.
100.0%
95.0
2008
Colorado Electric (4):
 
 
 
 
 
Busch Ranch Wind Farm (5)
Wind
Pueblo, Colo.
50.0%
14.5
2012
Pueblo Airport Generation
Gas
Pueblo, Colo.
100.0%
180.0
2011
W.N. Clark #1-2 (6)
Coal
Canon City, Colo.
100.0%
40.0
1955, 1959
Pueblo #5 (3)
Gas
Pueblo, Colo.
100.0%
9.0
1941, 2001
Pueblo #6 (3)
Gas
Pueblo, Colo.
100.0%
20.0
1949
AIP Diesel
Oil
Pueblo, Colo.
100.0%
10.0
2001
Diesel #1-5
Oil
Pueblo, Colo.
100.0%
10.0
1964
Diesel #1-5
Oil
Rocky Ford, Colo.
100.0%
10.0
1964
Total Megawatt Capacity
 
 
 
859.4
 
________________________
(1)
Wygen III, a 110 megawatt mine-mouth coal-fired power plant, is operated by Black Hills Power. Black Hills Power has a 52 percent ownership interest, MDU owns 25 percent and the City of Gillette owns the remaining 23 percent interest. Our WRDC coal mine furnishes all of the fuel supply for the plant.
(2)
Wyodak, a 362 megawatt mine-mouth coal-fired power plant, is owned 80 percent by PacifiCorp and 20 percent by Black Hills Power. This baseload plant is operated by PacifiCorp and our WRDC coal mine furnishes all of the fuel supply for the plant.
(3)
Operations at Osage were suspended Oct. 1, 2010, Ben French was suspended on Aug. 31, 2012 and Pueblo Unit #5 and Pueblo Unit #6 were suspended as of Dec. 31, 2012 due to the availability of more economical generation alternatives when evaluating costs to retrofit these plants to comply with environmental standards, including EPA regulations. Osage, Ben French and Neil Simpson I will be retired on or before March 21, 2014. While the net book value of these plants is estimated to be insignificant at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates.
(4)
Colorado Electric entered into a 20-year PPA with Black Hills Colorado IPP for 200 megawatts of power from their gas-fired plants. This PPA, accounted for as a capital lease, was effective on Jan. 1, 2012.
(5)
Busch Ranch Wind Farm, a 29 megawatt wind farm, is operated by Colorado Electric. Colorado Electric has a 50 percent ownership interest in the wind farm and AltaGas owns the remaining 50 percent. Colorado Electric has a 25-year REPA with AltaGas for their 14.5 megawatts of power from the wind farm. The wind farm became operational Oct. 16, 2012.
(6)
In December 2010, Colorado Electric received a final order from the CPUC that approved the retirement of its W.N. Clark coal-fired generation facility by Dec. 31, 2013. Operations were suspended at this facility on Dec. 31, 2012. While the net book value of the W.N. Clark plant is estimated to be insignificant at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates.


9



The following table shows the Electric Utilities’ annual average cost of fuel utilized to generate electricity and the average price paid for purchased power (excluding contracted capacity) per megawatt-hour:
Fuel Source (dollars per megawatt-hour)
2012
 
2011
2010
Coal
$
14.42

 
$
15.89

$
12.77

 
 
 
 
 
Gas and Oil
$
52.08

(a) 
$
150.00

$
131.28

 
 
 
 
 
Total Average Fuel Cost
$
16.05

 
$
16.77

$
13.57

 
 
 
 
 
Purchased Power - Coal, Gas and Oil
$
26.70

 
$
28.80

$
29.57

 
 
 
 
 
Purchased Power - Renewable Sources
$
47.45

 
$
46.71

$
45.76

__________
(a)
With the commencement of operations of the 180 megawatt gas-fired units in Pueblo, Colo., and the low price of natural gas compared to oil, the average cost of fuel per MWh decreased.

The following table shows our Electric Utilities’ power supply, by resource as a percent of the total power supply for our energy needs:
Power Supply
2012
2011
2010
Coal
37
%
38
%
42
%
Gas, Oil and Wind
2



Total Generated
39

38

42

Purchased
61

62

58

Total
100
%
100
%
100
%

Purchased Power. We have executed various agreements to support our Electric Utilities’ capacity and energy needs beyond our regulated power plants’ generation. Key contracts include:

Black Hills Power’s PPA with PacifiCorp expiring on Dec. 31, 2023, which provides for the purchase of 50 megawatts of coal-fired baseload power;

Colorado Electric’s PPA with Black Hills Colorado IPP expiring on Dec. 31, 2031, which provides 200 megawatts of energy and capacity to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease;

Colorado Electric’s PPA with Cargill expiring on Dec. 31, 2013, whereby Colorado Electric purchases 50 megawatts of economy energy;

Colorado Electric’s PPA with AltaGas expiring on Oct. 16, 2037, which provides up to 14.5 megawatts of wind energy from AltaGas’ owned interest in the Busch Ranch Wind Project;
 
Cheyenne Light’s PPA with Black Hills Wyoming expiring on Aug. 31, 2014, whereby Black Hills Wyoming provides 40 megawatts of energy and capacity from its Gillette CT;

Cheyenne Light’s PPA with Black Hills Wyoming expiring on Dec. 31, 2022, whereby Black Hills Wyoming provides 60 megawatts of unit-contingent capacity and energy from its Wygen I facility. The PPA includes an option for Cheyenne Light to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility between 2013 and 2019. The purchase price related to the option is $2.55 million per megawatt. The purchase price is reduced annually by an amount of annual depreciation assuming a facility life of 35 years;

Cheyenne Light’s 20-year PPA with Duke Energy expiring on Sept. 3, 2028, which provides up to 29.4 megawatts of wind energy from the Happy Jack Wind Farm to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50 percent of the facility’s output to Black Hills Power;


10



Cheyenne Light’s 20-year PPA with Duke Energy expiring on Sept. 30, 2029, which provides up to 30 megawatts of wind energy from the Silver Sage wind farm to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 20 megawatts of energy from Silver Sage to Black Hills Power; and

Cheyenne Light and Black Hills Power’s Generation Dispatch Agreement requires Black Hills Power to purchase all of Cheyenne Light’s excess energy.

Power Sales Agreements. Our Electric Utilities have various long-term power sales agreements. Key agreements include:

MDU owns a 25 percent ownership interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, Black Hills Power will provide MDU with 25 megawatts from its other generation facilities or from system purchases with reimbursement of costs by MDU;

The City of Gillette owns a 23 percent ownership interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, Black Hills Power will provide the City of Gillette with its first 23 megawatts from its other generation facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, Black Hills Power will also provide the City of Gillette its operating component of spinning reserves;

Black Hills Power’s agreement to supply up to 20 megawatts of energy and capacity to MEAN under a contract that expires in 2023. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchased over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:
2013-2017
20 megawatts - 10 megawatts contingent on Wygen III and 10 megawatts contingent on Neil Simpson II
2018-2019
15 megawatts - 10 megawatts contingent on Wygen III and 5 megawatts contingent on Neil Simpson II
2020-2021
12 megawatts - 6 megawatts contingent on Wygen III and 6 megawatts contingent on Neil Simpson II
2022-2023
10 megawatts - 5 megawatts contingent on Wygen III and 5 megawatts contingent on Neil Simpson II;

Black Hills Power’s PPA with MEAN, whereby MEAN will purchase 5 megawatts of unit-contingent capacity from Neil Simpson II and 5 megawatts of unit-contingent capacity from Wygen III through May 2015; and

Cheyenne Light’s agreement with Basin Electric, whereby Cheyenne Light will supply 40 megawatts of capacity and energy through March 31, 2013 and a separate agreement whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through March 31, 2013.

Transmission and Distribution. Through our Electric Utilities, we own electric transmission systems composed of high voltage transmission lines (greater than 69 kV) and low voltage lines (69 or fewer kV). We also jointly own high voltage lines with Basin Electric and Powder River Energy Corporation.

At December 31, 2012, our Electric Utilities owned the electric transmission and distribution lines shown below:
Utility
State
Transmission
(in Line Miles)
Distribution
(in Line Miles)
Black Hills Power
South Dakota, Wyoming
592

3,059

Black Hills Power - Jointly Owned (1)
South Dakota, Wyoming
44


Cheyenne Light
South Dakota, Wyoming
25

1,229

Colorado Electric
Colorado
236

3,345

(1)
Through Black Hills Power, we own 35 percent of a DC transmission tie that interconnects the Western and Eastern transmission grids, which are independently-operated transmission grids serving the western United States and eastern United States, respectively. This transmission tie, which is 65 percent owned by Basin Electric, provides transmission access to both the WECC region in the West and the MAPP region in the East. The transfer capacity of the tie is 200 megawatts from West to East, and 200 megawatts from East to West. Black Hills Power's electric system is located in the WECC region. This transmission tie allows us to buy and sell energy in the Eastern grid without having to isolate and physically reconnect load or generation between the two transmission grids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously, provides additional opportunities to sell excess generation or to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids.


11



Black Hills Power has firm point-to-point transmission access to deliver up to 50 megawatts of power on PacifiCorp’s transmission system to wholesale customers in the WECC region through 2023.

Black Hills Power also has firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyo. to serve our power sales contract with MDU through 2017, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.

In order to serve Cheyenne Light’s existing load, Cheyenne Light has a network transmission agreement with Western Area Power Association’s Loveland Area Project.

Operating Agreements. Our Electric Utilities have the following material operating agreements:

Shared Services Agreements - Black Hills Power, Cheyenne Light, and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity charges for the use of assets by the affiliate entity. Black Hills Colorado IPP and Colorado Electric are also parties to a facility fee agreement, whereby Colorado Electric charges Black Hills Colorado IPP for the use of Colorado Electric assets.

Jointly Owned Facilities - Black Hills Power, the City of Gillette and MDU are parties to a shared joint ownership agreement, whereby Black Hills Power charges the City of Gillette and MDU for administrative services, plant operations and maintenance for their share of the Wygen III generating facility for the life of the plant. Colorado Electric and AltaGas are parties to a shared joint ownership agreement whereby Colorado Electric charges AltaGas for operations and maintenance for their share of the Busch Ranch Wind Farm.


Operating Statistics

The following tables summarize degree days, revenue, quantities generated and purchased, quantities sold, and customers for our Electric Utilities:
Degree Days
2012
2011
2010
 
Actual
Variance from
30-Year Average
Actual
Variance from
30-Year Average
Actual
Variance from
30-Year Average
Heating Degree Days:
 
 
 
 
 
 
Black Hills Power
6,206

(13)%
7,579

5%
7,272

1%
Cheyenne Light
6,304

(11)%
7,321

(1)%
7,033

(5)%
Colorado Electric
4,921

(13)%
5,749

3%
5,518

(1)%
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
Black Hills Power
937

47%
700

17%
532

(11)%
Cheyenne Light
568

63%
431

58%
345

26%
Colorado Electric
1,322

47%
1,259

37%
1,074

16%


12



Revenue - Electric (in thousands)
2012
2011
2010
 
 
 
 
Residential:
 
 
 
Black Hills Power
$
58,523

$
59,826

$
53,549

Cheyenne Light
32,053

31,287

29,506

Colorado Electric (a)
91,550

84,646

76,596

Total Residential
182,126

175,759

159,651

 
 
 
 
Commercial:
 
 
 
Black Hills Power
73,858

72,889

65,997

Cheyenne Light
55,600

55,331

52,765

Colorado Electric
82,849

73,355

66,490

Total Commercial
212,307

201,575

185,252

 
 
 
 
Industrial:
 
 
 
Black Hills Power
25,656

25,723

22,621

Cheyenne Light
16,105

11,629

10,542

Colorado Electric
37,540

33,332

28,812

Total Industrial
79,301

70,684

61,975

 
 
 
 
Municipal:
 
 
 
Black Hills Power
3,268

3,172

3,029

Cheyenne Light
1,807

1,765

1,293

Colorado Electric
13,373

12,912

10,443

Total Municipal
18,448

17,849

14,765

 
 
 
 
Subtotal Retail Revenue - Electric
492,182

465,867

421,643

 
 
 
 
Contract Wholesale:
 
 
 
Total Contract Wholesale - Black Hills Power
20,290

18,105

22,996

 
 
 
 
Off-system/Power Marketing Wholesale:
 
 
 
Black Hills Power
31,905

34,889

36,354

Cheyenne Light
8,365

9,371

9,750

Colorado Electric (b)
6,003

13,018

10,859

Total Off-system/Power Marketing Wholesale
46,273

57,278

56,963

 
 
 
 
Other Revenue (c):
 
 
 
Black Hills Power
29,809

31,027

25,217

Cheyenne Light
2,336

2,449

3,230

Colorado Electric
4,652

2,787

2,374

Total Other Revenue
36,797

36,263

30,821

 
 
 
 
Total Revenue - Electric
$
595,542

$
577,513

$
532,423

_____________________
(a)
2012 includes a $2.1 million construction savings incentive.
(b)
Off-system sales revenue during part of 2010 was deferred until a sharing mechanism was approved by the CPUC in December 2011. As a result, Colorado Electric had deferred $8.4 million in off-system revenue during 2010 which was all recognized in December 2011.
(c)
Other revenue primarily consists of transmission revenue.


13




Quantities Generated and Purchased (megawatt-hour)
2012
2011
2010
 
 
 
 
Generated -
 
 
 
Coal-fired:
 
 
 
Black Hills Power
1,796,936

1,717,008

1,987,037

Cheyenne Light
587,832

674,518

734,241

Colorado Electric
235,080

268,317

257,896

Total Coal - fired
2,619,848

2,659,843

2,979,174

 
 
 
 
Gas, Oil and Wind:
 
 
 
Black Hills Power
33,183

15,221

19,269

Cheyenne Light



Colorado Electric
84,874

2,342

930

Total Gas, Oil and Wind
118,057

17,563

20,199

 
 
 
 
Total Generated:
 
 
 
Black Hills Power
1,830,119

1,732,229

2,006,306

Cheyenne Light
587,832

674,518

734,241

Colorado Electric
319,954

270,659

258,826

Total Generated
2,737,905

2,677,406

2,999,373

 
 
 
 
Purchased -
 
 
 
Black Hills Power
1,678,090

1,720,640

1,440,579

Cheyenne Light
807,659

745,983

696,756

Colorado Electric
1,794,229

1,948,321

1,969,896

Total Purchased (a)
4,279,978

4,414,944

4,107,231

 
 
 
 
Total Generated and Purchased
7,017,883

7,092,350

7,106,604

_______________
(a)
Includes wind power of 199,079 MWh, 189,255 MWh and 167,520 MWh in 2012, 2011 and 2010, respectively.


14



Quantities (megawatt-hour)
2012
2011
2010
 
 
 
 
Residential:
 
 
 
Black Hills Power
532,342

550,935

547,193

Cheyenne Light
261,792

264,492

261,607

Colorado Electric
614,521

629,752

628,553

Total Residential
1,408,655

1,445,179

1,437,353

 
 
 
 
Commercial:
 
 
 
Black Hills Power
731,785

720,978

720,119

Cheyenne Light
577,141

601,162

603,323

Colorado Electric
723,216

720,060

726,005

Total Commercial
2,032,142

2,042,200

2,049,447

 
 
 
 
Industrial:
 
 
 
Black Hills Power
407,301

408,337

382,562

Cheyenne Light
224,448

172,840

161,082

Colorado Electric
358,490

351,862

347,673

Total Industrial
990,239

933,039

891,317

 
 
 
 
Municipal:
 
 
 
Black Hills Power
35,933

34,235

33,908

Cheyenne Light
9,631

9,827

6,477

Colorado Electric
121,480

126,320

113,689

Total Municipal
167,044

170,382

154,074

 
 
 
 
Subtotal Retail Quantity Sold
4,598,080

4,590,800

4,532,191

 
 
 
 
Contract Wholesale:
 
 
 
Total Contract Wholesale - Black Hills Power
340,036

349,520

468,782

 
 
 
 
Off-system Wholesale:
 
 
 
Black Hills Power
1,263,457

1,226,548

1,163,058

Cheyenne Light
229,062

278,528

311,524

Colorado Electric
160,430

282,929

274,942

Total Off-system Wholesale
1,652,949

1,788,005

1,749,524

 
 
 
 
Total Quantity Sold:
 
 
 
Black Hills Power
3,310,854

3,290,553

3,315,622

Cheyenne Light
1,302,074

1,326,849

1,344,013

Colorado Electric
1,978,137

2,110,923

2,090,862

Total Quantity Sold
6,591,065

6,728,325

6,750,497

 
 
 
 
Losses and Company Use:
 
 
 
Black Hills Power
197,355

162,316

131,263

Cheyenne Light
93,417

93,652

86,984

Colorado Electric
136,046

108,057

137,860

Total Losses and Company Use
426,818

364,025

356,107

 
 
 
 
Total Energy Sold
7,017,883

7,092,350

7,106,604






15



Customers at End of Year
2012
2011
2010
Residential:
 
 
 
Black Hills Power
55,296

54,955

54,811

Cheyenne Light
35,438

35,159

34,913

Colorado Electric
81,795

81,811

81,902

Total Residential
172,529

171,925

171,626

 
 
 
 
Commercial:
 
 
 
Black Hills Power
12,857

12,864

12,779

Cheyenne Light
4,276

4,277

4,132

Colorado Electric
11,220

11,206

11,185

Total Commercial
28,353

28,347

28,096

 
 
 
 
Industrial:
 
 
 
Black Hills Power
44

45

40

Cheyenne Light
2

2

2

Colorado Electric
61

68

63

Total Industrial
107

115

105

 
 
 
 
Other Electric Customers:
 
 
 
Black Hills Power
308

311

309

Cheyenne Light
240

243

254

Colorado Electric
475

506

510

Total Other Electric Customers
1,023

1,060

1,073

 
 
 
 
Subtotal Retail Customers
202,012

201,447

200,900

 
 
 
 
Contract Wholesale:
 
 
 
Total Contract Wholesale - Black Hills Power
3

3

3

 
 
 
 
Total Customers:
 
 
 
Black Hills Power
68,508

68,178

67,942

Cheyenne Light
39,956

39,681

39,301

Colorado Electric
93,551

93,591

93,660

Total Electric Customers at Year-End
202,015

201,450

200,903




16



Cheyenne Light Natural Gas Distribution

Included in the Electric Utilities is Cheyenne Light’s natural gas distribution system. The following table summarizes certain operating information for the natural gas distribution operations of Cheyenne Light:
 
2012
2011
2010
Revenue - Gas (in thousands):
 
 
 
Residential
$
19,327

$
22,044

$
22,562

Commercial
8,613

10,264

10,801

Industrial
2,715

3,597

3,425

Other Sales Revenue
769

913

803

Total Revenue - Gas
$
31,424

$
36,818

$
37,591

 
 
 
 
Gross Margin - Gas (in thousands):
 
 
 
Residential
$
10,712

$
10,426

$
10,004

Commercial
2,963

3,345

3,376

Industrial
551

504

427

Other Gross Margin
766

545

720

Total Gross Margin - Gas
$
14,992

$
14,820

$
14,527

 
 
 
 
Quantities Sold (Dth):
 
 
 
Residential
2,215,858

2,585,056

2,636,839

Commercial
1,447,522

1,538,616

1,572,638

Industrial
598,408

689,935

667,062

Total Quantities Sold
4,261,788

4,813,607

4,876,539

 
 
 
 
Gas Customers at Year-End
35,021

34,807

34,461




17



Gas Utilities Segment

At Dec. 31, 2012, our Gas Utilities owned the gas transmission and distribution lines by state shown below (in line miles):
 
Intrastate Gas
Transmission Pipelines
Gas Distribution
Mains
Gas Distribution
Service Lines
Colorado
124

3,005

896

Nebraska
44

3,451

3,494

Iowa
170

2,747

2,422

Kansas
286

2,664

1,300

Total
624

11,867

8,112


The following tables for our Gas Utilities summarize degree days, revenue, gross margin, volumes sold and customers:

Degree Days
 
2012
2011
2010
 
Actual
Variance From
30-Year Average
Actual
Variance From
30-Year Average
Actual
Variance From
30-Year Average
Heating Degree Days:
 
 
 
 
 
 
Colorado
5,186

(18)%
5,991

(7)%
5,803

(9)%
Nebraska
5,198

(15)%
6,190

(1)%
6,222

—%
Iowa
6,093

(10)%
7,013

(4)%
6,934

(5)%
Kansas (a)
4,190

(15)%
4,954

(1)%
4,918

(1)%
Combined (b)
5,518

(13)%
6,455

(3)%
6,410

(3)%
________________
(a)
Kansas Gas has an approved weather normalization mechanism within its rate structure, which minimizes weather impact on gross margins.
(b)
The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism.


18



Operating Statistics

Revenue (in thousands)
2012
2011
2010
 
 
Residential:
 
 
 
Colorado
$
48,406

$
58,102

$
55,211

Nebraska
98,339

125,493

120,365

Iowa
82,669

106,292

105,255

Kansas
55,096

65,185

69,859

Total Residential
284,510

355,072

350,690

 
 
 
 
Commercial:
 
 
 
Colorado
9,558

12,172

11,880

Nebraska
30,894

40,659

40,720

Iowa
36,550

46,179

46,762

Kansas
15,677

20,362

21,953

Total Commercial
92,679

119,372

121,315

 
 
 
 
Industrial:
 
 
 
Colorado
1,963

2,063

1,409

Nebraska
876

860

3,126

Iowa
2,458

2,521

2,243

Kansas
13,614

19,571

14,312

Total Industrial
18,911

25,015

21,090

 
 
 
 
Other Sales Revenue:
 
 
 
Colorado
181

96

97

Nebraska
2,066

1,971

1,960

Iowa
452

550

836

Kansas
5,124

3,031

3,451

Total Other Sales Revenue
7,823

5,648

6,344

 
 
 
 
Distribution:
 
 
 
Colorado
60,108

72,433

68,597

Nebraska
132,175

168,983

166,171

Iowa
122,129

155,542

155,096

Kansas
89,511

108,149

109,575

Total Distribution
403,923

505,107

499,439

 
 
 
 
Transportation:
 
 
 
Colorado
866

846

784

Nebraska
10,589

11,175

11,289

Iowa
4,128

3,935

3,708

Kansas
5,762

5,909

5,471

Total Transportation
21,345

21,865

21,252

 
 
 
 
Total Regulated Revenue
425,268

526,972

520,691

 
 
 
 
Non-regulated Services
28,813

27,612

30,016

 
 
 
 
Total Revenue
$
454,081

$
554,584

$
550,707


19




Gross Margin (in thousands)
2012
2011
2010
 
 
Residential:
 
 
 
Colorado
$
16,400

$
17,711

$
18,153

Nebraska
46,982

51,640

49,074

Iowa
39,561

47,491

44,269

Kansas
28,734

29,701

29,591

Total Residential
131,677

146,543

141,087

 
 
 
 
Commercial:
 
 
 
Colorado
2,680

2,960

3,215

Nebraska
10,201

11,643

11,965

Iowa
11,071

11,702

11,616

Kansas
6,097

6,603

6,544

Total Commercial
30,049

32,908

33,340

 
 
 
 
Industrial:
 
 
 
Colorado
581

450

360

Nebraska
249

217

379

Iowa
257

288

235

Kansas
2,362

2,373

1,878

Total Industrial
3,449

3,328

2,852

 
 
 
 
Other Sales Margins:
 
 
 
Colorado
181

96

97

Nebraska
2,066

1,971

1,960

Iowa
452

549

836

Kansas
4,787

2,455

2,722

Total Other Sales Margins
7,486

5,071

5,615

 
 
 
 
Distribution:
 
 
 
Colorado
19,842

21,217

21,825

Nebraska
59,498

65,471

63,378

Iowa
51,341

60,030

56,956

Kansas
41,980

41,132

40,735

Total Distribution
172,661

187,850

182,894

 
 
 
 
Transportation:
 
 
 
Colorado
866

846

784

Nebraska
10,589

11,175

11,289

Iowa
4,128

3,935

3,708

Kansas
5,762

5,909

5,470

Total Transportation
21,345

21,865

21,251

 
 
 
 
Total Regulated Gross Margin:
 
 
 
Colorado
20,708

22,063

22,609

Nebraska
70,087

76,646

74,667

Iowa
55,469

63,965

60,664

Kansas
47,742

47,041

46,205

Total Regulated Gross Margin
194,006

209,715

204,145

 
 
 
 
Non-regulated Services
14,726

12,908

12,845

 
 
 
 
Total Gross Margin
$
208,732

$
222,623

$
216,990




20



Quantities Sold (in Dth)
2012
2011
2010
 
 
 
 
Residential:
 
 
 
Colorado
5,869,817

6,437,860

6,284,559

Nebraska
9,555,073

12,076,979

12,210,574

Iowa
8,732,301

10,490,129

10,556,045

Kansas
5,681,199

6,853,163

6,926,928

Total Residential
29,838,390

35,858,131

35,978,106

 
 
 
 
Commercial:
 
 
 
Colorado
1,284,082

1,472,747

1,473,924

Nebraska
3,952,067

4,833,604

5,009,105

Iowa
5,304,162

6,192,167

6,061,954

Kansas
2,121,063

2,676,439

2,673,805

Total Commercial
12,661,374

15,174,957

15,218,788

 
 
 
 
Industrial:
 
 
 
Colorado
463,566

344,576

259,985

Nebraska
158,445

120,779

544,457

Iowa
492,633

409,723

354,435

Kansas
3,675,678

3,743,735

2,718,767

Total Industrial
4,790,322

4,618,813

3,877,644

 
 
 
 
Other:
 
 
 
Colorado



Nebraska


1,341

Iowa


69,306

Kansas
68,419

112,253

120,445

Total Other
68,419

112,253

191,092

 
 
 
 
Distribution:
 
 
 
Colorado
7,617,465

8,255,183

8,018,468

Nebraska
13,665,585

17,031,362

17,765,477

Iowa
14,529,096

17,092,019

17,041,740

Kansas
11,546,359

13,385,590

12,439,945

Total Distribution
47,358,505

55,764,154

55,265,630

 
 
 
 
Transportation:
 
 
 
Colorado
850,156

869,570

808,859

Nebraska
26,649,759

24,972,560

27,327,173

Iowa
18,294,228

18,358,692

17,422,525

Kansas
14,686,679

15,015,310

14,320,893

Total Transportation
60,480,822

59,216,132

59,879,450

 
 
 
 
Total Volumes Sold:
 
 
 
Colorado
8,467,621

9,124,753

8,827,327

Nebraska
40,315,344

42,003,922

45,092,650

Iowa
32,823,324

35,450,711

34,464,265

Kansas
26,233,038

28,400,900

26,760,838

Total Quantities Sold
107,839,327

114,980,286

115,145,080





21




Customers
2012
2011
2010
 
 
 
 
Residential:
 
 
 
Colorado
68,927

67,496

66,766

Nebraska
176,953

176,386

176,244

Iowa
135,897

135,161

134,782

Kansas
98,516

98,043

97,844

Total Residential
480,293

477,086

475,636

 
 
 
 
Commercial:
 
 
 
Colorado
3,681

3,678

3,620

Nebraska
15,626

15,664

15,221

Iowa
15,398

15,398

15,300

Kansas
9,584

9,453

9,469

Total Commercial
44,289

44,193

43,610

 
 
 
 
Industrial:
 
 
 
Colorado
213

209

208

Nebraska
136

141

149

Iowa
94

94

93

Kansas
1,261

1,365

1,394

Total Industrial
1,704

1,809

1,844

 
 
 
 
Transportation:
 
 
 
Colorado
36

30

22

Nebraska
4,115

4,128

4,270

Iowa
412

393

392

Kansas
1,166

1,142

1,054

Total Transportation
5,729

5,693

5,738

 
 
 
 
Other:
 
 
 
Colorado



Nebraska


2

Iowa


68

Kansas
7

7

8

Total Other
7

7

78

 
 
 
 
Total Customers:
 
 
 
Colorado
72,857

71,413

70,616

Nebraska
196,830

196,319

195,886

Iowa
151,801

151,046

150,635

Kansas
110,534

110,010

109,769

Total Customers at Year-End
532,022

528,788

526,906


22



Utilities Group Business Characteristics

Seasonal Variations of Business

Our Electric Utilities and Gas Utilities are seasonal businesses and weather patterns may impact their operating performance. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as market price. In particular, demand is often greater in the summer and winter months for cooling and heating, respectively. Because our Electric Utilities have a diverse customer and revenue base, and we have historically optimized the utilization of our electric power supply resources, the impact on our operations may not be as significant when weather conditions are warmer in the winter and cooler in the summer. Conversely, for our Gas Utilities, natural gas is used primarily for residential and commercial heating, so the demand for this product depends heavily upon weather throughout our service territories, and as a result, a significant amount of natural gas revenue is normally recognized in the heating season consisting of the first and fourth quarters.

Competition

We generally have limited competition for the retail distribution of electricity and natural gas in our service areas. In the past, various restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate, but none of these initiatives have been adopted to date, with the exception of Montana. Although we face competition from independent marketers for the sale of natural gas to our industrial and commercial customers, in instances where independent marketers displace us as the seller of natural gas, we still collect a distribution charge for transporting the gas through our distribution network. In Colorado, our electric utility is subject to rules which may require competitive bidding for generation supply. Because of these rules, we face competition from other utilities and non-affiliated independent power producers for the right to provide electric energy and capacity for Colorado Electric when resource plans require additional resources.

Rates and Regulation

Current Rates
 
Our utilities are subject to the jurisdiction of the public utilities commissions in the states where they operate. The commissions oversee services and facilities, rates and charges, accounting, valuation of property, depreciation rates and various other matters. The public utility commissions determine the rates we are allowed to charge for our utility services. Rate decisions are influenced by many factors, including the cost of providing service, capital expenditures, the prudence of our costs, views concerning appropriate rates of return, the rates of other utilities, general economic conditions and the political environment. Certain commissions also have jurisdiction over the issuance of debt or securities, and the creation of liens on property located in their states to secure bonds or other securities.

23




The following table illustrates certain enacted regulatory information with respect to the states in which the Utilities Group operate:
Subsidiary
Jurisdic-tion
Authorized Rate of Return on Equity
Authorized Return on Rate Base
Capital Structure Debt/Equity
Effective Date
Tariff and Rate Matters
Percentage of Power Marketing Activity Shared with Customers
Electric Utilities:
 
 
 
 
 
 
Black Hills Power
SD
Global Settlement
8.6%
Global Settlement
4/2010
ECA, TCA, Energy Efficiency Cost Recovery/DSM
65%
 
SD
 
8.16%
 
6/2011
Environmental Improvement Cost Recovery Adjustment Tariff
NA
 
WY
10.5%
8.6%
48%/52%
6/2010
ECA, TCA
50% subject to symmetrical deadband
 
MT
15.0%
11.7%
47%/53%
1983
ECA
NA
 
FERC
10.8%
9.1%
43%/57%
2/2009
FERC Transmission Tariff
NA
Cheyenne Light - Electric
WY
9.6%
8.0%
46%/54%
7/2012
ECA, Energy Efficiency Cost Recovery/ DSM, Rate Base Recovery on Acquisition Adjustment
NA
Cheyenne Light - Gas
WY
9.6%
8.0%
46%/54%
7/2012
GCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery of Acquisition Adjustment
NA
Colorado Electric
CO
9.8%-10.2%
8.5%
50.9%/49.1%
1/2012
ECA, TCA, Energy Efficiency Cost Recovery/DSM, Renewable Energy Standard Adjustment
75% through 2013; 90% thereafter
 
 
 
 
 
 
 
 
Gas Utilities:
 
 
 
 
 
 
Colorado Gas
CO
9.6%
8.4%
50%/50%
12/2012
GCA, Energy Efficiency Cost Recovery/ DSM
NA
Nebraska Gas
NE
10.1%
9.1%
48%/52%
9/2010
GCA, Cost of Bad Debt Collected through GCA
NA
Kansas Gas
KS
Global Settlement
Global Settlement
49.3%/50.7%
10/2007
GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA
NA
Iowa Gas
IA
Global Settlement
Global Settlement
Global Settlement
2/2011
GCA, Energy Efficiency Cost Recovery/DSM
NA

We produce and/or distribute energy in four states; Colorado, Montana, South Dakota and Wyoming. The regulatory provisions for recovering the costs to supply electricity vary by state. In all states we have cost adjustment mechanisms for our Electric Utilities that allow us to pass the prudently-incurred cost of fuel and purchased power through to customers. These mechanisms allow the utility operating in that state to collect, or refund, the difference between the cost of commodities and certain services embedded in our base rates and the actual cost of the commodities and certain services without filing a general rate case. Some states in which our utilities operate also allow the utility operating in that state to automatically adjust rates periodically for the cost of new transmission or environmental improvements and, in some instances, the utility has the opportunity to earn its authorized return on new capital investment immediately with these adjustments. Some of the mechanisms we have in place include the following:

In October 2012, the WPSC approved Cheyenne Prairie’s construction financing rider which allows for recovery of construction financing costs from customers during the construction period in lieu of traditional AFUDC. The rider was implemented Nov. 1, 2012 and will allow Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period on approximately 60 percent of the total project cost that relates to Wyoming customers, while also saving customers money over the long-term. This will increase gross margin by approximately $5.5 million and $7.8 million in 2013 and 2014, respectively.

24




In Wyoming, Cheyenne Light has annual cost adjustment mechanisms that allow us to pass the prudently-incurred cost of fuel and purchased power through to electric customers. Until July 1, 2012 at Cheyenne Light, our pass-through mechanism relating to transmission and the ECA was subject to a $1.0 million threshold: we collected or refunded 95 percent of the increase or decrease that exceeded the $1.0 million threshold, and we absorbed the increase or retained the savings for costs below the threshold as well as the 5 percent not collected or refunded above the threshold. Effective July 1, 2012, the $1.0 million threshold was eliminated and the sharing mechanism was modified to 85 percent to the customer.

In South Dakota, beginning April 1, 2010, Black Hills Power has an annual adjustment clause which provides for the direct recovery of increased fuel and purchased power incurred to serve South Dakota customers. Additionally, as of April 1, 2010, the ECA was modified in the rate case settlement to contain an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 65 percent of off-system power marketing operating income. The modification also adjusts the methodology to directly assign renewable resources and firm purchases to the customer load. In Wyoming beginning June 1, 2010 a similar Fuel and Purchased Power Cost Adjustment was instituted.

In South Dakota, we have an approved annual Environmental Improvement Cost Recovery Adjustment tariff that went into effect June 1, 2011 and recovers costs associated with generation plant environmental improvements.

We have an approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of Black Hills Power’s open access transmission tariff. The revenue requirement is based on an equity return of 10.8 percent, a capital structure of 57 percent equity and 43 percent debt, and a return on rate base which is adjusted annually.

In Colorado, we have an ECA for semi-annual increases or decreases in purchased power and fuel costs and a TCA for transmission costs. The ECA provides for the direct recovery of increased purchased power and fuel costs or the issuance of credits for decreases in purchased power, environmental generation and fuel costs. The TCA is an annual rider to the customer’s bill which allows the utility to earn an authorized return on new transmission investment and recovery of operations and maintenance costs related to transmission. Effective Jan. 1, 2012, the CPUC approved adjustments to the ECA. These adjustments allow for the recovery of transmission expenses paid to other providers, symmetrical interest, and the sharing of off-system sales margins, less certain operating costs, where the customer receives 75 percent through 2013. This sharing percentage increases to 90 percent to the customer in 2014 and thereafter.

We distribute natural gas in five states; Colorado, Iowa, Nebraska, Kansas and Wyoming. All of our Gas Utilities and Cheyenne Light’s natural gas distribution, have GCAs that allow us to pass the prudently-incurred cost of gas and certain services through to the customer. Some of the mechanisms we have in place are:

In Kansas, we have a weather normalization tariff that provides a pass-through mechanism for weather margin variability that occurs from the level used to establish base rates to be paid by the customer, as well as tariffs that provide for more timely recovery for certain capital expenditures and fluctuations in property taxes.

In Kansas and Nebraska, we are allowed to recover the portion of uncollectible accounts related to gas costs through GCAs.


25



Pending Rates

The following summarizes certain state and federal rate cases, riders and surcharges with activity occurring in 2012 (dollars in millions):
 
Type of Service
Date Requested
Revenue Amount Requested
Iowa Gas (1)
Gas
12/2012
$
0.9

Black Hills Power (2)
Electric
12/2012
$
13.7

Black Hills Power (3)
Electric
12/2012
$
9.2


(1)
Iowa Gas filed a request for a Capital Infrastructure Automatic Adjustment Mechanism with the IUB in December 2012. If approved, the adjustment could result in a revenue increase of $0.9 million in 2013 which reflects a request for recovery of costs since our prior rate case in 2010. Also if approved, an adjustment request will be required to be filed annually thereafter and subsequent filings will vary in size based on eligible infrastructure replacements and the timing of future general rate case filings. The filing is currently under review by the IUB.

(2)
In December 2012, Black Hills Power filed a rate case with the SDPUC requesting an electric revenue increase of $13.7 million, or 9.94 percent, to recover investment in distribution and transmission lines, generation plant upgrades, environmental compliance and increased operating costs. Black Hills Power has requested an effective date of April 1, 2013. A decision is anticipated during the third quarter of 2013. If the SDPUC has not reached a decision within 180 days, interim rates will go into effect June 16, 2013.

(3)
In December 2012, Black Hills Power filed a request with the SDPUC to use a construction financing rider during the construction of Cheyenne Prairie in lieu of traditional AFUDC. This rider would be similar to the one approved by the WPSC for Cheyenne Light and Black Hills Power for Wyoming customers. On Jan. 17, 2013, the SDPUC approved a stipulation with interim rates effective April 1, 2013, subject to refund. The rider will allow Black Hills Power to earn and collect a rate of return during the construction period on its approximately 40 percent share of the total project cost that relates to South Dakota customers, while also saving customers money over the long-term. If approved, this will increase gross margin by approximately $3.6 million and $5.6 million in 2013 and 2014, respectively. We anticipate a final ruling by the SDPUC on this rider during the third quarter of 2013.

Other State Regulations

Certain states where we conduct electric utility operations have adopted renewable energy portfolio standards that require or encourage our Electric Utilities to source, by a certain future date, a minimum percentage of the electricity delivered to customers from renewable energy generation facilities. At Dec. 31, 2012, we were subject to the following renewable energy portfolio standards or objectives:

Colorado. Colorado has adopted a renewable energy standard that requires our Colorado Electric subsidiary to generate, or cause to be generated, electricity from renewable energy sources equaling: (i) 12 percent of retail sales through 2014; (ii) 20 percent of retail sales from 2015 to 2019; and (iii) 30 percent of retail sales by 2020. Of these amounts, 3 percent must be generated from distributed generation sources with one-half of these resources being located at customer facilities. The law limits the net annual incremental retail rate impact from these renewable resource acquisitions (as compared to non-renewable resources) to 2 percent and encourages the CPUC to consider earlier and timely cost recovery for utility investment in renewable resources, including the use of a forward rider mechanism. We are currently in compliance with these standards, and our current strategy is to incorporate renewable energy as required to comply with the standards going forward however, the 2 percent limitation may prohibit us from reaching the percentages set forth in the standards.

Montana. Montana established a renewable portfolio standard that requires Black Hills Power to obtain a percentage of its retail electric sales in Montana from eligible renewable resources according to the following schedule: (i) 10 percent for compliance through 2014; and (ii) 15 percent for compliance year 2015 and thereafter. Utilities can meet this standard by entering into long-term purchase contracts for electricity bundled with renewable-energy credits, by purchasing the renewable-energy credits separately, or by a combination of both. The law includes cost caps that limit the additional cost utilities must pay for renewable energy and allows cost recovery from customers for contracts pre-approved by the MTPSC. We are currently in compliance with applicable standards, and our current strategy is to incorporate renewable energy as required to comply with the standards.

26




South Dakota. South Dakota has adopted a renewable portfolio objective that encourages, but does not mandate utilities to generate, or cause to be generated, at least 10 percent of their retail electricity supply from renewable energy sources by 2015. Absent a specific renewable energy mandate in South Dakota, our current strategy is to prudently incorporate renewable energy into our resource supply, seeking to minimize associated rate increases for our utility customers.

Wyoming. Wyoming is exploring the implementation of renewable energy portfolio standards but has not currently adopted standards.

Mandatory portfolio standards have increased, and may continue to increase the power supply costs of our Electric Utility operations. Although we will seek to recover these higher costs in rates, we can provide no assurance that we will be able to secure full recovery of the costs we pay to be in compliance with standards or objectives. We cannot at this time reasonably forecast the potential costs associated with any new renewable energy standards that have been or may be proposed at the federal or state level.

Federal Regulation

Energy Policy Act. Black Hills Corporation is a holding company whose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and holding companies regulated by FERC under the Federal Power Act and PUHCA 2005.

Federal Power Act. The Federal Power Act gives FERC exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC’s jurisdiction must maintain tariffs and rate schedules on file with FERC that govern the rates, terms, and conditions for the provision of FERC-jurisdictional wholesale power and transmission services. Public utilities are also subject to accounting, record-keeping, and reporting requirements administered by FERC. FERC also places certain limitations on transactions between public utilities and their affiliates. Our public Electric Utility subsidiaries provide FERC-jurisdictional services subject to FERC’s oversight.

Our Electric Utilities, Black Hills Colorado IPP and Black Hills Wyoming are authorized by FERC to make wholesale sales of electric capacity and energy at market-based rates under tariffs on file with FERC. As a condition of their market-based rate authority, each files Electric Quarterly Reports with FERC. Black Hills Power owns and operates FERC-jurisdictional interstate transmission facilities and provides open access transmission service under tariffs on file with FERC. Our Electric Utilities are subject to routine audit by FERC with respect to their compliance with FERC’s regulations.

The Federal Power Act gave FERC authority to certify and oversee a national electric reliability organization with authority to promulgate and enforce mandatory reliability standards applicable to all users, owners, and operators of the bulk-power system. FERC has certified NERC as the electric reliability organization. NERC has promulgated mandatory reliability standards, and NERC, in conjunction with regional reliability organizations that operate under FERC’s and NERC’s authority and oversight, enforces those mandatory reliability standards.

PUHCA 2005. PUHCA 2005 gives FERC authority with respect to the books and records of a utility holding company. As a utility holding company with centralized service company subsidiaries, Black Hills Service Company and Black Hills Utility Holdings, we are subject to FERC’s authority under PUHCA 2005.

Environmental Matters

We are subject to numerous federal, state and local laws and regulations relating to the protection of the environment and the safety and health of personnel and the public. These laws and regulations affect a broad range of our utility activities, and generally regulate: (i) the protection of air and water quality; (ii) the identification, generation, storage, handling, transportation, disposal, record-keeping, labeling, reporting of, and emergency response in connection with hazardous and toxic materials and wastes, including asbestos; and (iii) the protection of plant and animal species and minimization of noise emissions.


27



Based on current regulations, technology and plans, the following table contains our current estimates of capital expenditures expected to be incurred over the next three years to comply with current environmental laws and regulations as described below, including regulations that cover water, air, soil and other pollutants, but excluding plant closures and the cost of new generation. The ultimate cost could be significantly different from the amounts estimated.
Environmental Expenditure Estimates
Total
(in millions)
2013
$
3.3

2014
2.1

2015
0.8

Total
$
6.2


Water Issues

Our facilities are subject to a variety of state and federal regulations governing existing and potential water/wastewater discharges and protection of surface waters from oil pollution. Generally, such regulations are promulgated under the Clean Water Act and govern overall water/wastewater discharges through NPDES and stormwater permits. All of our facilities that are required to have such permits have those permits in place and are in compliance with discharge limitations and plan implementation requirements. The EPA was scheduled to propose updated regulations for wastewater discharge from power generators by Dec. 14, 2012, with a scheduled implementation date of May 2014. However, in December 2012, the proposed rule deadline was extended to April 19, 2013. These rules may have a significant impact on our coal-fired units. Additionally, the EPA regulates surface water oil pollution through its oil pollution prevention regulations. All of our facilities under this program have their required plans in place.

Air Emissions

Our generation facilities are subject to federal, state and local laws and regulations relating to the protection of air quality. These laws and regulations cover, among other pollutants, carbon monoxide, SO2, NOx, mercury particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies.

Clean Air Act

Title IV of the Clean Air Act created an SO2 allowance trading program as part of the federal acid rain program. Each allowance gives the owner the right to emit one ton of SO2, and certain facilities are allocated allowances based on their historical operating data. At the end of each year, each emitting unit must have enough allowances to cover its emissions for the year just ended. Allowances may be traded so affected units that expect to emit more SO2 than their allocated allowances may purchase allowances in the open market.

Title IV applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT II, Lange CT, Wygen II, Wygen III and Wyodak plants. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2042. For future plants, we plan to secure the requisite number of allowances by reducing SO2 emissions through the use of low sulfur fuels, installation of “back end” control technology, use of banked allowances, and if necessary, the purchase of allowances on the open market. We expect to integrate the cost of obtaining the required number of allowances needed for future projects into our overall financial analysis of such new projects.

Title V of the Clean Air Act requires that all of our generating facilities obtain operating permits. All of our existing facilities have received Title V permits, with the exception of Wygen III. Wygen III is allowed to operate under its construction permit until the Title V permit is issued by the state. The Title V application for Wygen III was submitted in January 2011, with the permit expected in 2013. The application was filed in accordance with regulatory requirements.

In 2011, the EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates on Dec. 21, 2012, which impose emission limits, fuel requirements and monitoring requirements. The rule has a compliance deadline of March 21, 2014. In anticipation of this rule and our evaluation of costs to retrofit these plants, we suspended operations at the Osage plant in October 2010 and as a result of this rule, we suspended operations at the Ben French facility on Aug. 31, 2012 with plans to retire Osage, Ben French and Neil Simpson I on or before March 21, 2014. In conjunction with the Colorado Clean Air Clean Jobs Act, the CPUC issued an order approving the closure of the W.N. Clark facility no later than Dec. 31, 2013. This facility suspended operations Dec. 31, 2012.

28




On February 16, 2012, the EPA published in the Federal Register the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (MATS), with an effective date of April 16, 2012. This rule imposes requirements for mercury, acid gases, metals and other pollutants. Affected units will have three years from the rule effective date to be in compliance, with a pathway defined to apply for a one year extension due to certain circumstances. The current state air permits for Wygen II and Wygen III provide mercury emission limits and monitoring requirements with which we are in compliance. Wygen II has been utilized for internal study and review of mercury emission control technology and has mercury monitors in place. In 2009, we added mercury monitors to our Neil Simpson II plant. The Wygen III plant, which commenced operations in 2010, also has mercury monitors. Neil Simpson II, Wygen II, Wygen III and the Wyodak plant are expected to be in compliance by the compliance deadline, without incurring significant costs.

On June 23, 2010, the EPA published in the Federal Register the GHG Tailoring Rule, implementing regulations of GHG for permitting purposes. This rule will impact us in the event of a major modification at an existing facility or in the event of a new major source as defined by EPA regulations. Existing permitted facilities will see monitoring and reporting requirements incorporated into their operating permits upon renewal. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could result in more stringent emission control practices and technologies. As Wyoming state law prohibits regulation of GHG, the EPA will review and develop requirements for that portion of a new source construction permit or for a major modification of an existing source. This additional process will increase the time and expense for the permitting process. In addition, unlike a Wyoming issued permit, an appeal of an EPA issued GHG air permit to construct requires an automatic stay to the project, meaning that construction cannot commence until the appeal is resolved. This aspect adds considerable risk to new construction projects as well as to major modifications to existing projects. Wyoming has been working to modify this statute and implement GHG regulations. It is anticipated that EPA will approve Wyoming’s GHG program by the spring of 2014.

On April 13, 2012, the EPA proposed Electric Utility New Source Performance Standards for GHG. These standards will apply to Cheyenne Prairie. They are scheduled to be final in the first half of 2013 and, as proposed, would not have a significant impact on this project. However, until we can evaluate the final version, we cannot be certain of this assumption.

In August 2012, the EPA proposed revisions to the Electric Utility New Source Performance Standards for stationary combustion turbines. This rule is expected to be finalized in 2013 and, as proposed, will be applicable to the Pueblo Airport Generating Station, Cheyenne Prairie and eventually all the combustion turbines in our fleet. Among other things, the rule seeks to eliminate startup exemptions and clearly define overhauls for impact on the EPA’s New Source Review regulations, with the intention of eventually bringing all units under the applicability of this rule. The primary impact is expected to be on our older existing units, which will eventually be required to meet tighter NOx emission limitations.

By May 3, 2013, all our diesel generator engines must comply with the EPA’s Stationary Reciprocating Internal Combustion Engine Hazardous Air Pollutant regulations. Evaluations have been completed and emission control equipment is being installed to meet that deadline.

The EPA is expected to propose a more stringent ozone ambient air standard in 2013. If the lower range of the proposed standard is selected, it is anticipated that Campbell County, Wyoming would be a non-attainment area. Under those conditions, the State of Wyoming may evaluate Neil Simpson II, Wygen II and Wygen III for further reductions in NOx emissions. On Dec. 14, 2012 EPA signed revisions to the Particulate Matter 2.5 annual ambient air quality standard, lowering the annual limit from 15 to 12 ug/m3. EPA's website indicates that all counties where we currently have power generation facilities are expected to be able to comply with the new standard. This action is expected to result in more restrictive particulate matter emission limitations on any new construction and major modifications to our existing units.

In 2011, the State of Wyoming issued a letter requiring Neil Simpson II to include startup and shutdown SO2 & NOx emissions when evaluating compliance with permitted emission limits. This represented a significant change from requirements in the original 1993 air permit. Some minor engineered design changes were made to enable improved scrubber performance during startup and those changes have been successful in enabling the unit to meet the new requirements. The unit was previously fitted with state of the art low NOx burners that enable compliance with this new requirement. In the future the State of Wyoming may require similar changes to Wygen I and Wygen II.


29



Regional Haze

In January 2011, the states of Wyoming and South Dakota submitted their plans to EPA Region VIII, identifying NOx, SO2 and particulate matter emission reductions intended to meet the Class I Areas (National Parks and Wilderness Areas) visibility improvement requirements under the EPA’s Regional Haze Program. Although none of our South Dakota or Wyoming power plants were included in those plans, we anticipate that in the next required revisions due in 2016, some of our plants will be included. It is our expectation Ben French, Osage and Neil Simpson I will be permanently retired on or prior to March 21, 2014; however, if not retired, it is highly probable these plants along with Neil Simpson II, will be included in revised regulations.

In the 2010 legislative session, the State of Colorado passed House Bill 1365, the Colorado Clean Air Clean Jobs Act, a coordinated utility plan to reduce air emissions from coal fired power plants and promote the use of natural gas and other low emitting resources. One of the intents of this Act was to require utilities to consider a spectrum of regulations when evaluating their emission reduction plans, with the final package ultimately comprising Colorado's Regional Haze Plan that would be submitted to EPA for approval. This Act had a significant impact on our W.N. Clark facility and on Dec. 15, 2010, the CPUC issued an order approving closure of the W.N. Clark plant by Dec. 31, 2013. On Jan. 7, 2011, the State Air Quality Control Commission adopted the CPUC order into the Colorado State Implementation Plan and in the Dec. 31, 2012 Federal Register, EPA Region VIII gave full approval to that plan, establishing the closure of W.N. Clark as a federally approved state regulation and as such is now federally enforceable.

A number of our power plants have been subject to new state and EPA regulations issued in the last couple of years. As the result of these regulations and the associated costs to retrofit many of our older generating plants, we have announced the suspension of operations and planned retirements for the following plants:
Plant
Company
Megawatts
Type of Plant
Date Suspended
Planned Retirement Date
Age of Plant (in years)
Osage
Black Hills Power
 
34.5

 
Coal
Oct. 1, 2010
March 21, 2014
64
Ben French
Black Hills Power
 
25.0

 
Coal
Aug. 31, 2012
March 21, 2014
52
Neil Simpson I
Black Hills Power
 
21.8

 
Coal
NA
March 21, 2014
43
W.N. Clark
Colorado Electric
 
42.0

 
Coal
Dec. 31, 2012
Dec. 31, 2013
57
Pueblo Unit #5
Colorado Electric
 
9.0

 
Gas
Dec. 31, 2012
to be determined
71
Pueblo Unit #6
Colorado Electric
 
20.0

 
Gas
Dec. 31, 2012
to be determined
63
 
Total MW
 
152.3

 
 
 
 
 

In addition Neil Simpson II is expected to be included in the Wyoming Regional Haze Plan update due to the EPA in 2016. The Wyodak Power Plant is included in EPA's currently proposed Regional Haze Federal Implementation Plan, which includes additional NOx controls.

Greenhouse Gas Regulations

We utilize a diversified energy portfolio of power generation assets that include a fuel mix of coal, natural gas and wind sources, and minimal quantities of both solar and hydroelectric power. Of these generation resources, coal-fired power plants are the most significant sources of CO2 emissions. The EPA is intending to finalize the first GHG emission standards sometime in the first half of 2013, which will be applicable to new steam electric generating units, as described above. This rule, with its very low proposed CO2 emissions standards, effectively prohibits new coal-fired power plants from being constructed until carbon capture and sequestration becomes technically and economically feasible. The EPA will also be developing GHG emission standards for existing steam electric generating units. We expect the EPA to issue a proposed rule in 2013 and while we cannot predict the terms of the regulation, any federally mandated GHG reductions or limits on CO2 emissions at our existing plants could have a material impact on our customer rates, financial position, results of operations and/or cash flows. In 2011, the EPA’s GHG Tailoring Rule went into effect, requiring GHG emissions to be addressed in new major source construction permits and to be addressed upon renewal of Title V Operating Permits. Since there are no emission standards or caps currently in place, we cannot predict how this requirement will impact our existing facilities upon permit renewal. In 2012, we reported 2011 GHG emissions from our Power Generation and Gas Utilities in order to comply with the EPA’s GHG Annual Inventory regulation, issued in 2009. In addition to federal legislative activity, GHG regulations have been proposed in various states and alleged climate change issues are the subject of a number of lawsuits, the outcome of which could impact the utility industry. We will continue to review GHG impacts as legislation or regulation develops and litigation is resolved.


30



New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, and the closure of certain generating facilities. To the extent our regulated fossil-fuel generating plants are included in rate base, we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility customers and other purchasers of the power generated by our non-regulated power plants, including utility affiliates. Any unrecovered costs could have a material impact on our results of operations, financial position or cash flows. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Under state permits, we dispose of all solid wastes collected as a result of burning coal at our power plants in approved solid waste disposal sites. Ash and waste from flue gas and sulfur removal from the Ben French, Wyodak, Neil Simpson I, Neil Simpson II, Wygen II and Wygen III plants are deposited in mined areas at the WRDC coal mine. These disposal areas are currently located below some shallow water aquifers in the mine. In 2009, the State of Wyoming confirmed its past approval of this practice but may re-evaluate and limit ash disposal to mined areas that are above future groundwater aquifers. This change would increase disposal costs, which cannot be quantified until the exact requirements are known. None of the solid waste from the burning of coal is currently classified as hazardous material, but the waste does contain minute traces of metals that could be perceived as polluting if such metals leached into underground water. We conducted investigations which concluded that the wastes are relatively insoluble and will not measurably affect the post-mining ground water quality.

As of Oct. 1, 2010, we suspended operations at the Osage power plant and it is scheduled to be retired on or before March 21, 2014. This plant has an on-site ash impoundment that is near capacity. An application to close the impoundment was filed with the State of Wyoming on Nov. 3, 2010 and approved on April 13, 2012. Site closure work is underway with post closure monitoring to continue for 30 years. If Osage should ever re-start, ash disposal will be at our WRDC coal mine.

As of Aug. 31, 2012, we suspended operations at Ben French which is scheduled to close on or before March 21, 2014. We have also announced plans to close Neil Simpson I on or before March 21, 2014.

Our W.N. Clark plant which suspended operations on Dec. 31, 2012 and is scheduled to be retired by Dec. 31, 2013, sends coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages. For our Pueblo Airport Generation site in Pueblo, CO, we have posted a bond with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility.

Agreements are in place that require PacifiCorp and MEAN to be responsible for any costs related to the solid waste from their ownership interest in the Wyodak plant and Wygen I plant, respectively. As operator of Wygen III, Black Hills Power has a similar agreement in place for any such costs related to solid waste from Wygen III. Under their separate but related operating agreement, Black Hills Power, MDU and the City of Gillette each share the costs for solid waste from Wygen III according to their respective ownership interests.

Additional unexpected material costs could also result in the future if any regulatory agency determines that solid waste from the burning of coal contains a hazardous material that requires special treatment, including previously disposed solid waste. In that event, the regulatory authority could hold entities that disposed of such waste responsible for remedial treatment. On June 21, 2010, the EPA published in the Federal Register the proposed coal combustion residuals regulations. The regulations are complex and contain various options for ash management that the EPA will be selecting from to form the final version of the rule. We cannot determine the likely impact on our operations until the final version of the rule is known, which appears to be scheduled for some time in 2013. However, if ash becomes subject to regulations as a hazardous waste, implementation requirements could have a material impact on our financial position, results of operations or cash flows.

Manufactured Gas Processing

Some federal and state laws authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment.


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As a result of the Aquila Transaction, we acquired whole and partial liabilities for several former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for a $1.0 million insurance recovery, now valued at $1.1 million, which will be used to help offset remediation costs. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.

In March 2011, Nebraska Gas executed an Allocation, Indemnification and Access Agreement with the successor to the former operator of the Nebraska MGPs. Under this agreement, Nebraska Gas received $1.9 million from the successor to the operator for Nebraska Gas to remediate two sites in Nebraska (Blair and Plattsmouth) and the successor would be responsible for remediation activity at the two remaining sites in Nebraska (Columbus and Norfolk). Subsequent to this transaction, Nebraska Gas enrolled Blair and Plattsmouth in Nebraska’s Voluntary Cleanup Program. Site remediation was completed in September 2012, however there is a potential for additional minimal remediation work at Plattsmouth. If required, it is expected to be completed by mid-2013. Both Nebraska sites will be required to monitor groundwater quality for a minimum two year period.

As of Dec. 31, 2012, we estimate a range of approximately $2.9 million to $6.3 million to remediate these MGP sites in both Nebraska and Iowa.

Prior to Black Hills Corporation’s ownership, Aquila received rate orders that enabled recovery of environmental cleanup costs in certain jurisdictions. We anticipate recovery of these current and future costs would be allowed. Additionally, we may pursue recovery or agreements with other potentially responsible parties when and where permitted.

Non-regulated Energy Group

Our Non-regulated Energy Group, which operates through various subsidiaries, produces and sells electric capacity and energy through a portfolio of generating plants, produces and sells coal from our mine located in the Powder River Basin in Wyoming and acquires, explores for, develops and produces natural gas and crude oil primarily in the Rocky Mountain region. The Non-regulated Energy Group consists of three business segments for reporting purposes:

Power Generation

Coal Mining

Oil and Gas

For more than 15 years, we also owned and operated Enserco, an energy marketing business that engaged in natural gas, crude oil, coal, power and environmental marketing and trading in the United States and Canada. On Feb. 29, 2012, we sold Enserco, our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the reclassification of this segment as discontinued operations.


Power Generation Segment

Our Power Generation segment, which operates through Black Hills Electric Generation and its subsidiaries, acquires, develops and operates our non-regulated power plants. As of Dec. 31, 2012, we held varying interests in independent power plants operating in Wyoming and Colorado with a total net ownership of 309 MW.

Portfolio Management

We sell capacity and energy under a combination of mid- to long-term contracts, which mitigates the impact of a potential downturn in future power prices. We currently sell a substantial majority of our non-regulated generating capacity under contracts having terms greater than one year.


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As of Dec. 31, 2012, the power plant ownership interests held by our Power Generation segment included:
Power Plants
Fuel Type
Location
Ownership
Interest
Owned Capacity (MW)
In Service Date
Gillette CT
Gas
Gillette, Wyo.
100.0%
40.0

2001
Wygen I
Coal
Gillette, Wyo.
76.5%
68.9

2003
Pueblo Airport Generation (1)
Gas
Pueblo, Colo.
100.0%
200.0

2012
 
 
 
 
308.9

 
_________________________
(1)
Black Hills Colorado IPP owns and operates this facility. This facility provides capacity and energy to Colorado Electric under a 20-year PPA with Colorado Electric. This PPA is accounted for as a capital lease.

Black Hills Wyoming - Gillette CT. The Gillette CT is a simple-cycle, gas-fired combustion turbine located at our Gillette, Wyo. energy complex. The facility’s energy and capacity is sold to Cheyenne Light under a 3-year PPA that expires in August 2014. We are exploring various alternatives for the Gillette CT following expiration of its contract with Cheyenne Light, including contracting or selling the unit to another party. We sell excess power from our generating capacity into the wholesale power markets when it is available and economical.

Black Hills Wyoming - Wygen I. The Wygen I generation facility is a mine-mouth, coal-fired power plant with a total capacity of 90 megawatts located at our Gillette, Wyo. energy complex. We own 76.5 percent of the plant. We sell 60 megawatts of unit contingent capacity and energy from this plant to Cheyenne Light under a PPA that expires on Dec. 31, 2022. The PPA includes an option for Cheyenne Light to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility between 2013 and 2019. The purchase price in the contract related to the option is $2.6 million per megawatt reduced annually by an amount of annual depreciation assuming a facility life of 35 years. We expect Cheyenne Light to exercise its option to purchase sometime during the next several years. We sell excess power from our generating capacity into the wholesale power markets when it is available and economical.

Black Hills Colorado IPP - Pueblo Airport Generation. The Pueblo Airport Generation facility consists of two 100 megawatt combined-cycle gas-fired power generation plants located at a site shared with Colorado Electric. The plants commenced operation on Jan. 1, 2012, and the assets are accounted for as a capital lease under a 20-year PPA with Colorado Electric. Under the PPA with Colorado Electric, Colorado Electric has the ability to utilize our generating plants to sell energy in the wholesale power markets when it is available and economical.

Operating Agreement. Black Hills Wyoming and MEAN are parties to a shared joint ownership agreement, whereby Black Hills Wyoming charges MEAN for administrative services, plant operations and maintenance for their share of the Wygen I generating facility for the life of the plant.

Competition. The independent power industry consists of many strong and capable competitors, some of which may have more extensive operating experience, or greater financial resources than we possess.

With respect to the merchant power sector, FERC has taken steps to increase access to the national transmission grid by utility and non-utility purchasers and sellers of electricity, and foster competition within the wholesale electricity markets. Our Power Generation business could face greater competition if utilities are permitted to robustly invest in power generation assets. However, state regulatory rules requiring utilities to competitively bid generation resources may provide opportunity for independent power producers in some regions.

Environmental Regulation. Many of the environmental laws and regulations applicable to our regulated Electric Utilities also apply to our Power Generation operations. See the discussion above under the “Environmental” and “Regulation” captions for the Utilities Group for additional information on certain laws and regulations.

The Energy Policy Act of 1992. The passage of the Energy Policy Act of 1992 encouraged independent power production by providing certain exemptions from regulation for EWGs. EWGs are exclusively in the business of owning or operating, or both owning and operating, eligible power facilities and selling electric energy at wholesale. EWGs are subject to FERC regulation, including rate regulation. We own three EWGs: Gillette CT, Wygen I and 200 megawatts at the Pueblo Airport Generating Facility. Our EWGs have been granted market-based rate authority, which allows FERC to waive certain accounting, record-keeping and reporting requirements imposed on public utilities with cost-based rates.


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Clean Air Act. The Clean Air Act impacts our Power Generation business in a manner similar to the impact disclosed for our Electric Utilities. Our Gillette CT, Wygen I and Pueblo Airport Generating facilities are subject to Titles IV and V of the Clean Air Act and have the required permits in place or have applications submitted in accordance with regulatory time lines. As a result of SO2 allowances credited to us from the installation of sulfur removal equipment at our jointly owned Wyodak plant, we hold sufficient allowances for our Gillette CT and Wygen I plants through 2042, without purchasing additional allowances. The EPA’s MACT rule described in the Utilities Group section will apply to Wygen I.

Clean Water Act. The Clean Water Act impacts our Power Generation business in a manner similar to the impact described above for our Electric Utilities. Each of our facilities that is required to have NPDES permits have those permits and are in compliance with discharge limitations. Also, as the EPA regulates surface water oil pollution prevention through its oil pollution prevention regulations, each of our facilities regulated under this program have the requisite plans in place.