BKH 10K 12 2014


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, 2014
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.    x

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, 2014                                  $2,696,775,649

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, 2015
Common stock, $1.00 par value
44,676,072

shares
Documents Incorporated by Reference
Portions of the Registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2015 Annual Meeting of Stockholders to be held on April 28, 2015, 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.
MINE SAFETY 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:
AC
Alternating current
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
Baseload plant
A power generation facility used to meet some or all of a given region’s continuous energy demand, producing energy at a constant rate.
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, includes Black Hills Gas Resources, Inc. and Black Hills Plateau Production LLC, direct wholly-owned subsidiaries of Black Hills Exploration and Production, Inc.
BHSC
Black Hills Service Company LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
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 is a 132 MW natural-gas fired generating facility jointly owned by Black Hills Power and Cheyenne Light in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014.
City of Gillette
The City of Gillette, Wyoming, affiliate of the JPB. The JPB financed the purchase of 23% of Wygen III power plant for the City of Gillette.
CO2
Carbon dioxide

3




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.
CPCN
Certificate of Public Convenience and Necessity
CPUC
Colorado Public Utilities Commission
CT
Combustion turbine
CVA
Credit Valuation Adjustment
DART
Days Away Restricted Transferred (number of cases with days away from work or job transfer or restrictions multiplied by 200,000 then divided by total hours worked for all employees during the year covered)
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. These swaps were settled in November 2013.
Dodd-Frank
Dodd-Frank Wall Street Reform and Consumer Protection Act
DSM
Demand Side Management
DRSPP
Dividend Reinvestment and Stock Purchase Plan
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 energy 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
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
GADS
Generation Availability Data System
GCA
Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to customers.
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

4




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.
IEEE
Institute of Electrical and Electronics Engineers
IFRS
International Financial Reporting Standards
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
IRS
United States Internal Revenue Service
IUB
Iowa Utilities Board
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.
KCC
Kansas Corporation Commission
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
N/A
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 (1 barrel equals 6 Mcfe)
NOAA
National Oceanic and Atmospheric Administration

5



NOAA Climate Normals
This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service.

NOx
Nitrogen oxide
NOL
Net operating loss
NOPA
Notice of Proposed Adjustment
NPDES
National Pollutant Discharge Elimination System
NPSC
Nebraska Public Service Commission
NYMEX
New York Mercantile Exchange
OCI
Other Comprehensive Income
OSHA
Occupational Safety & Health Administration
OTC
Over-the-counter
PCA
Power Cost Adjustment
PCCA
Power Capacity Cost Adjustment
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
Quad O Regulation
40 CFR 60 Subpart OOOO - Standards of performance for crude oil and natural gas production, transmission and distribution
RCRA
Resource Conservation and Recovery Act
RICE
Reciprocating Internal Combustion Engines
REPA
Renewable Energy Purchase Agreement
Revolving Credit Facility
Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2019
RMSA
Retirement Medical Savings Account
SAIDI
System Average Interruption Duration Index
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.
S&S
Significant and substantial
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% 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.
TCIR
Total Case Incident Rate (average number of work-related injuries incurred by 100 workers during a one-year period)
TIPA
Tax Increase Prevention Act of 2014
VEBA
Voluntary Employee Benefit Association
VOC
Volatile Organic Compound
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
WTI
West Texas Intermediate Crude


6



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.


7



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 growth-oriented, vertically-integrated energy company headquartered in Rapid City, South Dakota. 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 regulated Electric Utilities and regulated Gas Utilities segments, and our Non-regulated Energy Group is comprised of Power Generation, Coal Mining and Oil and Gas segments.

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 205,400 electric customers in South Dakota, Wyoming, Colorado and Montana and also distributes natural gas to approximately 36,000 gas utility customers of Cheyenne Light in and around Cheyenne, Wyoming. Our Gas Utilities segment serves approximately 543,200 natural gas utility customers in Colorado, Nebraska, Iowa and Kansas. Our Electric Utilities own 841 MW of generation and 8,660 miles of electric transmission and distribution lines, and our Gas Utilities own 645 miles of intrastate gas transmission pipelines and 19,058 miles of gas distribution mains and service lines. Our Utilities Group generated net income of $101 million for the year ended December 31, 2014, and had total assets of $3.7 billion at December 31, 2014.

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, Wyoming, and sells the coal primarily under long-term contracts to mine-mouth electric generation facilities including our own regulated and non-regulated generating plants. 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 $28 million for the year ended December 31, 2014, and had total assets of $0.5 billion at December 31, 2014.

For more than 15 years, prior to February 2012, 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 February 29, 2012, we sold Enserco, representing our entire Energy Marketing segment, which resulted in this segment being reclassified as discontinued operations. See Note 21 in the accompanying Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further details.

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 4 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.


8



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 205,400 customers; and also distribute natural gas to approximately 36,000 natural gas utility customers of Cheyenne Light in and around Cheyenne, Wyoming. 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 543,200 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 63,000 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. Tech Services also provides electrical system construction services to large industrial customers of our electric utilities.


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 MW)
 
 
2014
 
2013
 
2012
 
 
Summer
Winter
 
Summer
Winter
 
Summer
 
Winter
 
Black Hills Power
410
389
 
422
403
 
449
 
362
 
Cheyenne Light
198
197
 
185
192
 
187
 
174
 
Colorado Electric
384
298
 
381
280
 
400
 
284
 
Total Electric Utilities Peak Demands
992
884
 
988
875
 
1,036
 
820
 



9


Regulated Power Plants

As of December 31, 2014, 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 (1):
 
 
 
 
 
Cheyenne Prairie (2)
Gas
Cheyenne, Wyoming
58%
55.0
2014
Wygen III (3)
Coal
Gillette, Wyoming
52%
57.2
2010
Neil Simpson II
Coal
Gillette, Wyoming
100%
90.0
1995
Wyodak (4)
Coal
Gillette, Wyoming
20%
72.4
1978
Neil Simpson CT
Gas
Gillette, Wyoming
100%
40.0
2000
Lange CT
Gas
Rapid City, South Dakota
100%
40.0
2002
Ben French Diesel #1-5
Oil
Rapid City, South Dakota
100%
10.0
1965
Ben French CTs #1-4
Gas/Oil
Rapid City, South Dakota
100%
80.0
1977-1979
Cheyenne Light:
 
 
 
 
 
Cheyenne Prairie (2)
Gas
Cheyenne, Wyoming
42%
40.0
2014
Cheyenne Prairie CT (2)
Gas
Cheyenne, Wyoming
100%
37.0
2014
Wygen II
Coal
Gillette, Wyoming
100%
95.0
2008
Colorado Electric:
 
 
 
 
 
Busch Ranch Wind Farm (5)
Wind
Pueblo, Colorado
50%
14.5
2012
Pueblo Airport Generation
Gas
Pueblo, Colorado
100%
180.0
2011
AIP Diesel
Oil
Pueblo, Colorado
100%
10.0
2001
Diesel #1-5
Oil
Pueblo, Colorado
100%
10.0
1964
Diesel #1-5
Oil
Rocky Ford, Colorado
100%
10.0
1964
Total MW Capacity
 
 
 
841.1
 
________________________
(1)
The Osage, Ben French, and Neil Simpson I generating plants, having a combined capacity of 81.3 MW, were retired on March 21, 2014 due to the availability of more economical generation alternatives when evaluating costs to retrofit these plants to comply with environmental standards, including EPA regulations. The remaining net book value of these plants is deferred as a Regulatory asset on the accompanying Consolidated Balance Sheets. We have requested recovery for the remaining net book values of these plants and prudent decommissioning costs of these units. The WPSC granted approval to our request in the Wyoming rate case approved in August 2014, and our request with the SDPUC is pending with a decision expected in March 2015.
(2)
Cheyenne Prairie, a 132 MW natural gas-fired power generation facility was placed into commercial operations on October 1, 2014 to support the customers of Black Hills Power and Cheyenne Light. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Cheyenne Light and one combined-cycle, 95 MW unit that is jointly-owned by Cheyenne Light (40 MW) and Black Hills Power (55 MW).
(3)
Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by Black Hills Power. Black Hills Power has a 52% ownership interest, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our WRDC coal mine supplies all of the fuel for the plant.
(4)
Wyodak, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by Black Hills Power. This baseload plant is operated by PacifiCorp and our WRDC coal mine supplies all of the fuel for the plant.
(5)
Busch Ranch Wind Farm, a 29 MW wind farm, is operated by Colorado Electric. Colorado Electric has a 50% ownership interest in the wind farm and AltaGas owns the remaining 50%. Colorado Electric has a 25-year REPA with AltaGas for their 14.5 MW of power from the wind farm. The wind farm became operational October 16, 2012.


10


The Electric Utilities’ annual average cost of fuel utilized to generate electricity and the average price paid for purchased power (excluding contracted capacity) per MWh for the years ended December 31 is as follows:
Fuel Source (dollars per megawatt-hour)
2014
2013
2012
Coal
$
10.92

$
10.89

$
14.42

 
 
 
 
Natural Gas
$
77.31

$
53.53

$
52.08

 
 
 
 
Diesel Oil
$
174.04

$
233.47

$
280.29

 
 
 
 
Total Average Fuel Cost
$
14.82

$
14.65

$
16.05

 
 
 
 
Purchased Power - Coal, Gas and Oil
$
35.21

$
29.95

$
26.70

 
 
 
 
Purchased Power - Renewable Sources
$
50.27

$
49.20

$
47.45


Our Electric Utilities’ power supply, by resource as a percent of the total power supply for our energy needs for the years ended December 31 is as follows:
Power Supply
2014
2013
2012
Coal
34
%
36
%
37
%
Gas, Oil and Wind
4

4

2

Total Generated
38

40

39

Purchased
62

60

61

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 December 31, 2023, which provides for the purchase of 50 MW of coal-fired baseload power;

Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, which provides 200 MW 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 on the accompanying Consolidated Financial Statements;

Colorado Electric’s PPA with Cargill expiring on December 31, 2015, which provides for the purchase of 50 MW of energy during heavy load timing intervals;

Colorado Electric’s PPA with Cargill expiring on December 31, 2016, which provides for the purchase of 50 MW of energy during light load timing intervals;

Colorado Electric’s PPA with AltaGas expiring on October 16, 2037, which provides up to 14.5 MW of wind energy from AltaGas’ owned interest in the Busch Ranch Wind Project;
 
Cheyenne Light’s PPA with Black Hills Wyoming expiring on December 31, 2022, whereby Black Hills Wyoming provides 60 MW 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 through 2019. The purchase price related to the option is $2.6 million per MW adjusted for capital additions and reduced by depreciation over a 35-year life beginning January 1, 2009 (approximately $5 million per year);

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


11


Cheyenne Light’s 20-year PPA with Duke Energy expiring on September 30, 2029, which provides up to 30 MW of wind energy from the Silver Sage wind farm to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 20 MW 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% 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 MW from its other generation facilities or from system purchases with reimbursement of costs by MDU;

Black Hills Power has an agreement through December 31, 2023 to serve MDU capacity and energy up to a maximum of 50 MW.

The City of Gillette owns a 23% 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 MW 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 MW 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:
2015-2017
20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019
15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021
12 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023
10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II; and

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

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 kV or less). We also jointly own high voltage lines with Basin Electric and Powder River Energy Corporation.

At December 31, 2014, 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
1,182

2,474

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


Cheyenne Light
South Dakota, Wyoming
48

1,257

Colorado Electric
Colorado
585

3,070

__________________________
(1)
Black Hills Power owns 35% 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% 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 MW from West to East, and 200 MW 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.


12


Black Hills Power has firm point-to-point transmission access to deliver up to 50 MW 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, Wyoming, 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.
Black Hills Power and Cheyenne Light also receive certain staffing and management services from BHSC for Cheyenne Prairie.

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 information for our Electric Utilities:

Degree Days
2014
2013
2012
 
Actual
Variance from 30-Year Average (b)
Actual
Variance from 30-Year Average (b)
Actual
Variance from 30-Year Average (b)
Heating Degree Days:
 
 
 
 
 
 
Black Hills Power
7,373

4%
7,582

9%
6,206

(13)%
Cheyenne Light
7,100

—%
7,386

4%
6,304

(11)%
Colorado Electric
5,534

—%
5,740

1%
4,921

(13)%
Combined (a)
6,473

2%
6,691

5%
5,629

(12)%
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
Black Hills Power
481

(28)%
724

8%
937

47%
Cheyenne Light
336

(5)%
520

48%
568

63%
Colorado Electric
919

(4)%
1,230

28%
1,322

47%
Combined (a)
654

(12)%
918

7%
1,043

47%
________________
(a) The combined heating degree days are calculated based on a weighted average of total customers by state.
(b)
30-Year Average is from NOAA Climate Normals.

13


Revenue - Electric (in thousands)
2014
2013
2012
Residential:
 
 
 
Black Hills Power
$
69,712

$
64,566

$
58,523

Cheyenne Light
36,634

35,778

32,053

Colorado Electric (a)
94,391

95,631

91,550

Total Residential
200,737

195,975

182,126

 
 
 
 
Commercial:
 
 
 
Black Hills Power
91,882

80,289

73,858

Cheyenne Light
59,758

57,444

55,600

Colorado Electric
90,909

87,732

82,849

Total Commercial
242,549

225,465

212,307

 
 
 
 
Industrial:
 
 
 
Black Hills Power
28,451

27,705

25,656

Cheyenne Light
29,066

20,803

16,105

Colorado Electric
39,219

38,037

37,540

Total Industrial
96,736

86,545

79,301

 
 
 
 
Municipal:
 
 
 
Black Hills Power
3,409

3,421

3,268

Cheyenne Light
1,930

1,918

1,807

Colorado Electric
13,312

13,106

13,373

Total Municipal
18,651

18,445

18,448

 
 
 
 
Subtotal Retail Revenue - Electric
558,673

526,430

492,182

 
 
 
 
Contract Wholesale:
 
 
 
Total Contract Wholesale - Black Hills Power
21,206

21,956

20,290

 
 
 
 
Off-system/Power Marketing Wholesale:
 
 
 
Black Hills Power
28,002

29,580

31,905

Cheyenne Light
8,179

8,712

8,365

Colorado Electric
5,726

8,329

6,003

Total Off-system/Power Marketing Wholesale
41,907

46,621

46,273

 
 
 
 
Other Revenue: (b)
 
 
 
Black Hills Power
25,826

26,510

29,809

Cheyenne Light
2,253

1,916

2,336

Colorado Electric (c)
7,691

4,612

4,652

Total Other Revenue
35,770

33,038

36,797

 
 
 
 
Total Revenue - Electric
$
657,556

$
628,045

$
595,542

_____________________
(a)
2013 includes $0.7 million and 2012 includes $2.1 million in construction savings incentives from the construction of the Pueblo Airport Generating Station.
(b)
Other revenue primarily consists of transmission revenue.
(c)
Increase in 2014 is primarily due to $1.8 million in technical service revenues for facility improvements at one of our large industrial customers.


14



Quantities Generated and Purchased (MWh)
2014
2013
2012
Generated -
 
 
 
Coal-fired:
 
 
 
Black Hills Power (a)
1,591,061

1,768,483

1,796,936

Cheyenne Light
697,220

688,318

587,832

Colorado Electric (b)


222,647

Total Coal - fired
2,288,281

2,456,801

2,607,415

 
 
 
 
Natural Gas and Oil:
 
 
 
Black Hills Power (c)
44,984

33,374

33,183

Cheyenne Light (c)
12,534



Colorado Electric (d)
140,942

247,758

84,874

Total Natural Gas and Oil
198,460

281,132

118,057

 
 
 
 
Wind:
 
 
 
Colorado Electric
48,318

45,765

12,433

Total Wind
48,318

45,765

12,433

 
 
 
 
Total Generated:
 
 
 
Black Hills Power
1,636,045

1,801,857

1,830,119

Cheyenne Light
709,754

688,318

587,832

Colorado Electric
189,260

293,523

319,954

Total Generated
2,535,059

2,783,698

2,737,905

 
 
 
 
Purchased -
 
 
 
Black Hills Power
1,446,630

1,441,286

1,678,090

Cheyenne Light
766,475

779,677

807,659

Colorado Electric
1,898,232

1,886,627

1,794,229

Total Purchased (e)
4,111,337

4,107,590

4,279,978

 
 
 
 
Total Generated and Purchased
6,646,396

6,891,288

7,017,883

_______________
(a)
Neil Simpson I was retired on March 21, 2014.
(b)
W.N. Clark suspended operations in 2012.
(c)
Cheyenne Prairie was placed into commercial service on October 1, 2014.
(d)
Decrease in 2014 generation primarily due to increased commodity prices that impacted power marketing sales.
(e)
Includes wind power of 224,229 MWh, 222,069 MWh, and 199,079 MWh in 2014, 2013 and 2012, respectively.


15


Quantities (MWh)
2014
2013
2012
Residential:
 
 
 
Black Hills Power
542,008

555,204

532,342

Cheyenne Light
261,038

272,490

261,792

Colorado Electric
598,872

619,857

614,521

Total Residential
1,401,918

1,447,551

1,408,655

 
 
 
 
Commercial:
 
 
 
Black Hills Power
782,238

730,701

731,785

Cheyenne Light
528,689

544,636

577,141

Colorado Electric
685,094

703,604

723,216

Total Commercial
1,996,021

1,978,941

2,032,142

 
 
 
 
Industrial:
 
 
 
Black Hills Power
399,648

404,009

407,301

Cheyenne Light
382,306

281,727

224,448

Colorado Electric
432,167

371,102

358,490

Total Industrial
1,214,121

1,056,838

990,239

 
 
 
 
Municipal:
 
 
 
Black Hills Power
32,076

34,344

35,933

Cheyenne Light
9,425

9,848

9,631

Colorado Electric
122,247

114,732

121,480

Total Municipal
163,748

158,924

167,044

 
 
 
 
Subtotal Retail Quantity Sold
4,775,808

4,642,254

4,598,080

 
 
 
 
Contract Wholesale:
 
 
 
Total Contract Wholesale - Black Hills Power
340,871

357,193

340,036

 
 
 
 
Off-system Wholesale:
 
 
 
Black Hills Power
808,257

1,002,847

1,263,457

Cheyenne Light
191,069

234,566

229,062

Colorado Electric
119,315

219,349

160,430

Total Off-system Wholesale
1,118,641

1,456,762

1,652,949

 
 
 
 
Total Quantity Sold:
 
 
 
Black Hills Power
2,905,098

3,084,298

3,310,854

Cheyenne Light
1,372,527

1,343,267

1,302,074

Colorado Electric
1,957,695

2,028,644

1,978,137

Total Quantity Sold
6,235,320

6,456,209

6,591,065

 
 
 
 
Other Uses, Losses or Generation, net (a):
 
 
 
Black Hills Power
177,577

158,845

197,355

Cheyenne Light
103,702

124,728

93,417

Colorado Electric
129,797

151,506

136,046

Total Other Uses, Losses and Generation, net
411,076

435,079

426,818

 
 
 
 
Total Energy
6,646,396

6,891,288

7,017,883

________________________
(a)
Includes company uses, line losses, test energy and excess exchange production.





16


Customers at End of Year
2014
2013
2012
Residential:
 
 
 
Black Hills Power
56,511

55,840

55,296

Cheyenne Light
36,253

35,780

35,438

Colorado Electric
82,710

82,371

81,795

Total Residential
175,474

173,991

172,529

 
 
 
 
Commercial:
 
 
 
Black Hills Power (a)
13,173

12,888

12,857

Cheyenne Light
4,489

4,471

4,276

Colorado Electric
11,156

11,060

11,220

Total Commercial
28,818

28,419

28,353

 
 
 
 
Industrial:
 
 
 
Black Hills Power (a)
23

46

44

Cheyenne Light
4

3

2

Colorado Electric
66

61

61

Total Industrial
93

110

107

 
 
 
 
Other Electric Customers:
 
 
 
Black Hills Power
325

310

308

Cheyenne Light
224

232

240

Colorado Electric
469

469

475

Total Other Electric Customers
1,018

1,011

1,023

 
 
 
 
Subtotal Retail Customers
205,403

203,531

202,012

 
 
 
 
Contract Wholesale:
 
 
 
Total Contract Wholesale - Black Hills Power
3

3

3

 
 
 
 
Total Customers:
 
 
 
Black Hills Power
70,035

69,087

68,508

Cheyenne Light
40,970

40,486

39,956

Colorado Electric
94,401

93,961

93,551

Total Electric Customers at End of Year
205,406

203,534

202,015

________________________
(a)
Change in customers is due to classification change to Commercial billing in 2014 based on customer’s business type.


17


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:

 
2014
2013
2012
Revenue - Gas (in thousands):
 
 
 
Residential
$
24,426

$
23,047

$
19,327

Commercial
11,279

10,326

8,613

Industrial
2,945

3,050

2,715

Other Sales Revenue
1,104

840

769

Total Revenue - Gas
$
39,754

$
37,263

$
31,424

 
 
 
 
Gross Margin - Gas (in thousands):
 
 
 
Residential
$
11,615

$
12,706

$
10,712

Commercial
3,582

3,993

2,963

Industrial
525

598

551

Other Gross Margin
1,104

881

766

Total Gross Margin - Gas
$
16,826

$
18,178

$
14,992

 
 
 
 
Quantities Sold (Dth):
 
 
 
Residential
2,515,243

2,728,797

2,215,858

Commercial
1,482,904

1,653,021

1,447,522

Industrial
539,848

652,539

598,408

Total Quantities Sold
4,537,995

5,034,357

4,261,788

 
 
 
 
Gas Customers at Year-End
36,033

35,494

35,021



18




Gas Utilities Segment

The following tables summarize certain operating information for our Gas Utilities.

System Infrastructure (in line miles) as of
Intrastate Gas
Transmission Pipelines
Gas Distribution
Mains
Gas Distribution
Service Lines
December 31, 2014
Colorado
126

3,030

942

Nebraska
44

3,482

2,474

Iowa
182

2,690

2,373

Kansas
293

2,755

1,312

Total
645

11,957

7,101


Degree Days

 
2014
 
2013
 
2012
 
Actual
Variance From
30-Year Average (c)
 
Actual
Variance From
30-Year Average (c)
 
Actual
Variance From
30-Year Average (c)
Heating Degree Days:
 
 
 
 
 
 
 
 
Colorado
6,108

(3)%
 
6,310

1%
 
5,186

(18)%
Nebraska
6,193

2%
 
6,516

8%
 
5,198

(15)%
Iowa
7,875

16%
 
7,743

14%
 
6,093

(10)%
Kansas (a)
5,099

4%
 
5,294

8%
 
4,190

(15)%
Combined (b)
6,780

7%
 
6,922

9%
 
5,518

(13)%
________________
(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.
(c)
30-Year Average is from NOAA climate normals.


19



Operating Statistics
Revenue (in thousands)
2014
2013
2012
Residential:
 
 
 
Colorado
$
58,439

$
53,296

$
48,406

Nebraska
135,052

122,197

98,339

Iowa
124,145

98,498

82,669

Kansas
74,128

67,501

55,096

Total Residential
391,764

341,492

284,510

 
 
 
 
Commercial:
 
 
 
Colorado
12,233

10,515

9,558

Nebraska
39,947

37,190

30,894

Iowa
60,640

47,494

36,550

Kansas
24,966

21,440

15,677

Total Commercial
137,786

116,639

92,679

 
 
 
 
Industrial:
 
 
 
Colorado
1,909

1,661

1,963

Nebraska
830

900

876

Iowa
4,386

3,436

2,458

Kansas
16,963

15,753

13,614

Total Industrial
24,088

21,750

18,911

 
 
 
 
Other:
 
 
 
Colorado
118

(17
)
181

Nebraska
2,440

2,265

2,066

Iowa
724

543

452

Kansas
2,836

2,326

5,124

Total Other Sales Revenue
6,118

5,117

7,823

 
 
 
 
Distribution:
 
 
 
Colorado
72,699

65,455

60,108

Nebraska
178,269

162,552

132,175

Iowa
189,895

149,971

122,129

Kansas
118,893

107,020

89,511

Total Distribution
559,756

484,998

403,923

 
 
 
 
Transportation:
 
 
 
Colorado
968

1,033

866

Nebraska
14,272

12,943

10,589

Iowa
4,934

4,809

4,128

Kansas
7,448

6,472

5,762

Total Transportation
27,622

25,257

21,345

 
 
 
 
Total Regulated Revenue
587,378

510,255

425,268

 
 
 
 
Non-regulated Services
30,390

29,434

28,813

 
 
 
 
Total Revenue
$
617,768

$
539,689

$
454,081


20



Gross Margin (in thousands)
2014
2013
2012
Residential:
 
 
 
Colorado
$
18,100

$
18,244

$
16,400

Nebraska
54,996

53,367

46,982

Iowa
44,134

42,961

39,561

Kansas
32,809

32,111

28,734

Total Residential
150,039

146,683

131,677

 
 
 
 
Commercial:
 
 
 
Colorado
3,048

3,009

2,680

Nebraska
11,708

11,560

10,201

Iowa
13,206

13,060

11,071

Kansas
8,115

7,436

6,097

Total Commercial
36,077

35,065

30,049

 
 
 
 
Industrial:
 
 
 
Colorado
464

519

581

Nebraska
239

250

249

Iowa
294

321

257

Kansas
2,336

2,220

2,362

Total Industrial
3,333

3,310

3,449

 
 
 
 
Other:
 
 
 
Colorado
118

(17
)
181

Nebraska
2,441

2,266

2,066

Iowa
724

543

452

Kansas
1,990

1,723

4,787

Total Other Sales Margins
5,273

4,515

7,486

 
 
 
 
Distribution:
 
 
 
Colorado
21,730

21,755

19,842

Nebraska
69,384

67,443

59,498

Iowa
58,358

56,885

51,341

Kansas
45,250

43,490

41,980

Total Distribution
194,722

189,573

172,661

 
 
 
 
Transportation:
 
 
 
Colorado
968

1,033

866

Nebraska
14,272

12,943

10,589

Iowa
4,934

4,809

4,128

Kansas
7,448

6,472

5,762

Total Transportation
27,622

25,257

21,345

 
 
 
 
Total Regulated Gross Margin:
 
 
 
Colorado
22,698

22,788

20,708

Nebraska
83,656

80,386

70,087

Iowa
63,292

61,694

55,469

Kansas
52,698

49,962

47,742

Total Regulated Gross Margin
222,344

214,830

194,006

 
 
 
 
Non-regulated Services
14,572

14,396

14,726

 
 
 
 
Total Gross Margin
$
236,916

$
229,226

$
208,732





21



Distribution Quantities Sold and Transportation (in Dth)
2014
2013
2012
Residential:
 
 
 
Colorado
6,718,508

6,969,741

5,869,817

Nebraska
13,068,132

12,717,565

9,555,073

Iowa
12,172,281

11,359,220

8,732,301

Kansas
7,313,273

7,174,085

5,681,199

Total Residential
39,272,194

38,220,611

29,838,390

 
 
 
 
Commercial:
 
 
 
Colorado
1,537,704

1,506,227

1,284,082

Nebraska
4,644,645

4,770,370

3,952,067

Iowa
7,182,173

7,056,978

5,304,162

Kansas
3,043,685

2,867,696

2,121,063

Total Commercial
16,408,207

16,201,271

12,661,374

 
 
 
 
Industrial:
 
 
 
Colorado
354,630

405,047

463,566

Nebraska
122,662

150,227

158,445

Iowa
630,912

648,173

492,633

Kansas
3,384,797

3,355,930

3,675,678

Total Industrial
4,493,001

4,559,377

4,790,322

 
 
 
 
Wholesale and Other:
 
 
 
Kansas
150,014

116,234

68,419

Total Wholesale and Other
150,014

116,234

68,419

 
 
 
 
Distribution Quantities Sold:
 
 
 
Colorado
8,610,842

8,881,015

7,617,465

Nebraska
17,835,439

17,638,162

13,665,585

Iowa
19,985,366

19,064,371

14,529,096

Kansas
13,891,769

13,513,945

11,546,359

Total Distribution Quantities Sold
60,323,416

59,097,493

47,358,505

 
 
 
 
Transportation:
 
 
 
Colorado
950,819

1,015,791

850,156

Nebraska
30,669,764

28,171,610

26,649,759

Iowa
19,959,462

20,176,525

18,294,228

Kansas
15,883,098

14,457,620

14,686,679

Total Transportation
67,463,143

63,821,546

60,480,822

 
 
 
 
Total Distribution Quantities Sold and Transportation:
 
 
 
Colorado
9,561,661

9,896,806

8,467,621

Nebraska
48,505,203

45,809,772

40,315,344

Iowa
39,944,828

39,240,896

32,823,324

Kansas
29,774,867

27,971,565

26,233,038

Total Distribution Quantities Sold and Transportation
127,786,559

122,919,039

107,839,327





22



Customers at End of Year
2014
2013
2012
Residential:
 
 
 
Colorado
72,360

70,410

68,927

Nebraska
180,014

178,389

176,953

Iowa
138,503

137,525

135,897

Kansas
99,359

99,315

98,516

Total Residential
490,236

485,639

480,293

 
 
 
 
Commercial:
 
 
 
Colorado
3,788

3,737

3,681

Nebraska
15,900

15,739

15,626

Iowa
15,303

15,418

15,398

Kansas
10,547

9,832

9,584

Total Commercial
45,538

44,726

44,289

 
 
 
 
Industrial:
 
 
 
Colorado
205

207

213

Nebraska
147

136

136

Iowa
90

94

94

Kansas
1,277

1,358

1,261

Total Industrial
1,719

1,795

1,704

 
 
 
 
Transportation:
 
 
 
Colorado
34

36

36

Nebraska
4,151

4,240

4,115

Iowa
418

421

412

Kansas
1,145

1,171

1,166

Total Transportation
5,748

5,868

5,729

 
 
 
 
Wholesale:
 
 
 
Kansas
8

7

7

Total Wholesale
8

7

7

 
 
 
 
Total Customers:
 
 
 
Colorado
76,387

74,390

72,857

Nebraska
200,212

198,504

196,830

Iowa
154,314

153,458

151,801

Kansas
112,336

111,683

110,534

Total Customers at End of Year
543,249

538,035

532,022



23


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. Various restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate. These initiatives would be aimed at increasing competition or providing for distributed generation. To date, there has been no material impact to our utilities. 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 costs we incur, 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.

24



The following table illustrates information about certain enacted regulatory provisions with respect to the states in which the Utilities Group operates:
Subsidiary
Jurisdic-tion
Authorized Rate of Return on Equity
Authorized Return on Rate Base
Capital Structure Debt/Equity
Authorized Rate Base (in millions)
Effective Date
Tariff and Rate Matters
Percentage of Power Marketing Activity Shared with Customers
Electric Utilities:
 
 
 
 
 
 
 
Black Hills Power
WY
9.9%
8.13%
46.7%/53.3%
$46.8
10/2014
ECA
65%
 
SD
Global Settlement
7.93%
Global Settlement
$440.2
6/2013
ECA, TCA, Energy Efficiency Cost Recovery/DSM
65%
 
SD
 
8.16%
 
 
6/2011
Environmental Improvement Cost Recovery Adjustment Tariff
N/A
 
MT
15.0%
11.7%
47%/53%
 
1983
ECA
N/A
 
FERC
10.8%
9.1%
43%/57%
 
2/2009
FERC Transmission Tariff
N/A
Cheyenne Light - Electric
WY
9.9%
7.98%
46%/54%
$376.8
10/2014
PCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery on Acquisition Adjustment
N/A
 
FERC
10.6%
8.51%
46%/54%
$31.5
5/2014
FERC Transmission Tariff
N/A
Cheyenne Light - Gas
WY
9.9%
7.98%
46%/54%
$59.6
10/2014
GCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery on Acquisition Adjustment
N/A
Colorado Electric
CO
9.83%
7.55%
50.2%/49.8%
$448.3
1/2015
ECA, TCA, PCCA, Energy Efficiency Cost Recovery/DSM, Renewable Energy Standard Adjustment, Construction Rider
90%
 
 
 
 
 
 
 
 
 
Gas Utilities:
 
 
 
 
 
 
 
Colorado Gas
CO
9.6%
8.4%
50%/50%
$64.0
12/2012
GCA, Energy Efficiency Cost Recovery/DSM
N/A
Nebraska Gas
NE
10.1%
9.1%
48%/52%
$161.0
9/2010
GCA, Cost of Bad Debt Collected through GCA, Infrastructure System Replacement Cost Recovery Surcharge
N/A
Kansas Gas
KS
Global Settlement
Global Settlement
Global Settlement
$127.4
1/2015
GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA
N/A
Iowa Gas
IA
Global Settlement
Global Settlement
Global Settlement
$110.2
2/2011
GCA, Energy Efficiency Cost Recovery/DSM/Capital Infrastructure Automatic Adjustment Mechanism
N/A

We produce and/or distribute electricity in four states: Colorado, South Dakota, Wyoming and Montana. The regulatory provisions for recovering the costs to supply electricity vary by state. In all states, subject to thresholds noted below, 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.


25


Some of the mechanisms we have in place include the following:

In Wyoming, Cheyenne Light has an annual cost adjustment mechanism that allows us to pass the prudently-incurred costs of fuel and purchased power through to electric customers. Until October 1, 2014, at Cheyenne Light, our pass-through sharing mechanism relating to transmission and the PCA, returned 85% to the customer, and the Company retained 15%. Effective October 1, 2014, coal and coal related costs are passed through under an 85% / 15% distribution methodology, and purchased power costs, transmission, and natural gas costs are passed through under a 95% / 5% distribution methodology.

In South Dakota, Black Hills Power has an annual adjustment clause which provides for the direct recovery of increased fuel and purchased power cost incurred to serve South Dakota customers. Additionally, the ECA contains an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 65% 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 a similar fuel and purchased power cost adjustment is also in place.

In South Dakota, we have an approved annual Environmental Improvement Cost Recovery Adjustment tariff that went into effect June 1, 2011, which 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.

We have an approved FERC Transmission Tariff that determines the revenue component of Cheyenne Light’s open access transmission tariff.

In Colorado, we have a quarterly ECA rider (the rider was semi-annual until August 1, 2013) that allows us to recover forecasted increases or decreases in purchased energy and fuel costs, including the recovery for amounts payable to others for the transmission of the utility's electricity over transmission facilities owned by others, symmetrical interest, and the sharing of off-system sales margins, less certain operating costs (customer receives 90%). Through 2013, this sharing percentage allowed 75% to the customers. The ECA provides for not only direct recovery, but also for the issuance of credits for decreases in purchased energy, fuel costs and eligible energy resources. Additionally, Colorado allows an annual TCA rider, that includes nine months of actual transmission investment and three months of forecasted investment, with an annual true-up mechanism.

On December 19, 2014, Colorado Electric received approval from the CPUC to implement a rider effective January 1, 2015 to recover a return on the construction costs of a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant.

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 between rate cases. Some of the mechanisms we have in place include the following:

In Kansas, we have a tariff pass-through mechanism for weather normalization, as well as tariffs that provide timely recovery of certain capital expenditures and property tax fluctuations.

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

In Iowa, we have a Capital Infrastructure Automatic Adjustment Mechanism that allows for recovery of certain capital infrastructure investments.

In Nebraska, we have an Infrastructure System Replacement Cost mechanism that allows for recovery of certain capital infrastructure investments.


26


Pending Rates and Rate Activity

The following table summarizes recent activity of certain state and federal rate cases, riders and surcharges (dollars in millions):
 
Type of Service
Date Requested
Effective Date
Revenue Amount Requested
Revenue Amount Approved
Cheyenne Light (a)
Electric/Gas
12/2013
10/2014
$
14.1

$
9.2

Black Hills Power (b)
Electric
1/2014
10/2014
$
2.8

$
2.2

Black Hills Power (c)
Electric
3/2014
10/2014
$
14.6

pending

Iowa Gas (d)
Gas
2/2014
4/2014
$
0.5

$
0.5

Kansas Gas (e)
Gas
4/2014
1/2015
$
7.3

$
5.2

Colorado Electric (f)
Electric
4/2014
1/2015
$
4.0

$
3.1

____________________
(a)
On July 31, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Cheyenne Light of $8.4 million and $0.8 million for annual electric and natural gas revenue, respectively, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 54% equity and 46% debt. The WPSC’s decision provides Cheyenne Light a return on its investment in Cheyenne Prairie and associated infrastructure, and provides recovery of its share of operating expenses for this natural gas-fired facility.

(b)
On August 21, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Black Hills Power of approximately $2.2 million for annual electric revenue, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 53.3% equity and 46.7% debt. The WPSC’s decision provides Black Hills Power a return on its investment in Cheyenne Prairie and associated infrastructure and provides recovery of its share of operating expenses for this natural gas-fired facility.

(c)
On March 31, 2014, Black Hills Power filed a rate request with the SDPUC to increase annual revenue by $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25% and a capital structure of approximately 53.3% equity and 46.7% debt. Black Hills Power implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. We expect a final decision from the SDPUC on our rate request by the end of the first quarter of 2015. Interim rates will be trued up as necessary based on the final approval.

(d)
On April 15, 2014, the IUB approved a capital investment recovery surcharge increase of $0.5 million.

(e)
On April 29, 2014, Kansas Gas filed a rate request with the KCC to increase annual revenue to recover infrastructure and increased operating costs. On October 24, 2014, a settlement agreement was reached between Kansas Gas, the KCC and intervenors to increase base rates by $5.2 million. On December 16, 2014, Kansas Gas received approval from the KCC to increase base rates by $5.2 million.

(f)
On April 30, 2014, Colorado Electric filed a rate request with the CPUC to recover increased operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The filing also requested to implement a rider to recover a return on the construction costs for a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant. On December 19, 2014, Colorado Electric received approval from the CPUC for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt, as well as approving implementation of the rider.



27


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 December 31, 2014, we were subject to the following renewable energy portfolio standards or objectives:

Colorado. Colorado adopted a renewable energy standard that has two components: (i) electric resource standards and (ii) a 2% retail rate impact for compliance with the electric resource standards. The electric resource standards require our Colorado Electric subsidiary to generate, or cause to be generated, electricity from renewable energy sources equaling: (i) 20% of retail sales from 2015 to 2019; and (ii) 30% of retail sales by 2020. Of these amounts, 3% must be generated from distributed generation sources with one-half of these resources being located at customer facilities. The net annual incremental retail rate impact from these renewable resource acquisitions (as compared to non-renewable resources) is limited to 2%. The standard 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. On May 5, 2014, Colorado Electric issued an all-source generation request for approximately 42 MW of summer seasonal firm capacity in 2017, 2018 and 2019 and up to 60 MW of eligible renewable energy resources to serve its customers in southern Colorado. Colorado IPP submitted solar and wind bids in response to this request. On December 23, 2014, the independent evaluator submitted a report to the Colorado Public Utilities Commission confirming the ranking of the bids. The report’s results indicate that Colorado IPP’s bids were not among the highest ranked bids. However, two of the highest ranked bids provide an opportunity for Colorado Electric or our power generation segment to be partial or full owners of the facilities. At its deliberation in February 2015, the Commission determined none of the alternatives was acceptable, because of potential short-term rate impacts. The Commission discussed the possibility that Colorado Electric could more economically comply with the renewable energy standard by purchasing renewable energy credits. The purchase of renewable energy credits will be considered in a separate proceeding. After review of the Commission’s decision regarding the all source solicitation (which has not yet been issued), Colorado Electric will determine whether to seek reconsideration.

Montana. In 2005, Montana established a renewable portfolio standard that requires public utilities to obtain a percentage of their retail electricity sales from eligible renewable resources. In March 2013, Black Hills Power filed a petition with the MTPSC requesting a waiver of the renewable portfolio standards primarily due to exceeding the applicable “cost cap” included in the standards. In March 2013, the Montana Legislature adopted legislation that had the effect of excluding Black Hills Power from all renewable portfolio standard requirements under State Senate Bill 164, primarily due to the very low number of customers we have in Montana and the relatively high cost of meeting the renewable requirements.

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% of their retail electricity supply from renewable energy sources by 2015.

Wyoming. Wyoming currently has no renewable energy portfolio standard.

Absent a specific renewable energy mandate in the territories we serve, our current strategy is to prudently incorporate renewable energy into our resource supply, seeking to minimize associated rate increases for our utility customers. 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.


28


Federal Power Act. The Federal Power Act gives FERC exclusive rate-making 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 authorizes FERC 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, BHSC 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.

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)
2015
$
2.9

2016
3.5

2017
1.9

Total
$
8.3


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 storm water 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 proposed effluent limitation guidelines and standards on June 7, 2013. The EPA has a September 2015 deadline to issue a final regulation. These rules may have an impact on the Wyodak Plant, potentially requiring a modification to the methods of handling coal ash. Additionally, the EPA regulates surface water oil pollution through its oil pollution prevention regulations. All of our facilities subject to these regulations have compliant prevention plans in place.


29


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 regime as part of the federal acid rain program. Each allowance gives the owner the right to emit one ton of SO2. Certain facilities are allocated allowances based on their historical operating data. At the end of each year, each emitting unit must possess allowances sufficient to cover its emissions for the preceding year. Allowances may be traded, so affected units that expect to emit more SO2 than their allocated allowances may purchase allowances on the open market.

Title IV applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen II, Wygen III, Pueblo Airport Generating Station, Cheyenne Prairie and Wyodak plants. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2044. 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, Pueblo Airport Generating Station and Cheyenne Prairie Generating Station. Wygen III, Pueblo Airport Generating Station and Cheyenne Prairie Generating Station are allowed to operate under their 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 2015. The Pueblo Airport Generating Station Title V application was filed in September 2012, with the permit expected in 2015. The Cheyenne Prairie Generating Station Title V application will be submitted in 2015. All applications were or will be 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 December 21, 2012, which impose emission limits, fuel requirements and monitoring requirements. The rule had a compliance deadline of March 21, 2014. Due to costs to retrofit these plants, we suspended operations at the Osage plant in October 2010 and suspended operations at the Ben French facility on August 31, 2012. We permanently retired Osage, Ben French and Neil Simpson I on 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 December 31, 2013. The W.N. Clark facility suspended operations December 31, 2012 and was retired on December 31, 2013 in accordance with the Colorado Clean Air Clean Jobs Act.

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 have a compliance deadline of April 16, 2015, with a pathway defined to apply for a one year extension due to certain very limited 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. Neil Simpson II, Wygen II and Wygen III have been utilized for internal study and review of mercury emission control technology and have mercury monitors in place. Neil Simpson II, Wygen II, Wygen III and the Wyodak plant are expected to be in compliance with MATS by the compliance deadline, without incurring significant costs.

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 2015 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.


30


By May 3, 2013, all of our diesel generator engines were required to comply with the EPA’s Stationary Reciprocating Internal Combustion Engine Hazardous Air Pollutant regulations. Evaluations were completed, emission control equipment was installed and emission testing confirmed compliance with those requirements.

On December 17, 2014, the EPA proposed a more stringent ozone ambient air standard. This rule is expected to be finalized in October 2015. If the lower range of the proposed standard is selected, it is anticipated the Gillette and Cheyenne, Wyoming regions would be non-attainment areas. Also, the Colorado front-range non-attainment area is expected to be expanded. Under those conditions, the states could evaluate our projects for further reductions in NOx emissions.

In 2011, the State of Wyoming issued a letter requiring Neil Simpson II to include startup and shutdown SO2 and NOx emissions when evaluating compliance with permitted emission limits. This represented a significant change from requirements provided in the original 1993 air permit. Minor engineered design changes were made to improve scrubber performance during startup. Those changes enabled the unit to meet the new requirements. The unit was previously fitted with state of the art low NOx burners that support compliance with this new requirement. Also in 2014, Neil Simpson II, Wygen II and Wygen III have converted startup fuel from diesel to natural gas to support start-up requirements and future Greenhouse Gas state compliance plans.

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, Neil Simpson II will be included. Ben French, Osage and Neil Simpson I were permanently retired on March 21, 2014.

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 purpose 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. As required by the Act, we retired the W.N. Clark facility on December 31, 2013.

A number of our power plants have been subject to new state and EPA regulations issued in recent years. As the result of these regulations and the associated costs to retrofit many of our older generating plants, we have since permanently retired the following plants:
Plant
Company
MW
Type of Plant
Date Suspended
Actual Retirement Date
Age of Plant (in years)
Osage
Black Hills Power
 
34.5

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

 
Coal
August 31, 2012
March 21, 2014
52