-2.8%
-3.7%
-15.7%
-16.1%
-16.8%
1.5%
-17.7%
1.7%
0.4%
0.9%
Financial Highlights
DECEMBER 31,
On-System Revenues ($000)
Operating Income ($000)
Net Income ($000)
2015
2014
Percentage
Change
$565,934
$582,895
$96,301
$99,999
$56,597
$67,103
Earnings Per Weighted Average Common Share (Basic)
Earnings Per Weighted Average Common Share (Diluted)
Dividends Paid Per Share
Return On Common Equity (End Of Period)
Book Value Per Share Of Common Stock
Common Shares Outstanding (Year End) (000)
Weighted Average Common Shares Outstanding (Basic) (000)
$1.30
$1.29
$1.040
7.1%
$18.32
43,821
43,671
$1.55
$1.55
$1.025
8.6%
$18.02
43,479
43,291
Capital Expenditures (Including AFUDC) ($000)
$176,525
$222,852
-20.8%
Gross Plant ($000)
$2,601,592
$2,541,582
On-System Electric Sales (mWh)
4,935,725
5,026,415
On-System Gas Sales (000) (Mcf)
Electric Customers (Year End)
Gas Customers (Year End)
Owned System Capability (Net mW)
System Electric Peak Demand (Net mW)
System Gas Peak Demand (Mcf)
Employees
Earnings per share & Dividend
7,783
170,158
43,639
1,280
1,149
66,508
749
9,052
169,328
43,864
1,326
1,162
72,912
751
2.4%
-1.8%
-14.0%
0.5%
-0.5%
-3.9%
-1.1%
-8.8%
-0.3%
2015
2014
2013
EPS
DIVS
EPS
DIVS
EPS
DIVS
PAYOUT %
$ $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 $1.60 $1.80
80%
$1.04
$1.30
66%
68%
$1.025
$1.005
$1.55
$1.48
% 25% 50% 75% 100% 125% 150%
Front Cover Photo: Riverton 12 Combined Cycle Unit
Dear Fellow Shareholder,
One of the most notable events since our last annual report was the strategic
alternatives exploration undertaken by the Empire board this past year. As
a result of that process, on February 9, 2016, we announced an Agreement
and Plan of Merger under which Liberty Utilities, the U.S. subsidiary of
Algonquin Power & Utilities Corporation, will indirectly acquire Empire and
its subsidiaries. Empire shareholders will receive $34 per share of common
stock in cash upon closing of the merger. The purchase price represents
a 50 percent premium to the unaffected closing stock price of $22.65 on
December 10, 2015.
The proposed merger marks an exciting and significant evolution of our
organization. When combined with Liberty Utilities, we will be part of a
utility that serves approximately 780,000 customers. These customers
lie in a diverse geographic territory stretching from California to New
Hampshire. Joplin and Empire will serve as the geographic headquarters
for Liberty Utilities Central and our executive team will lead operations
for approximately 340,000 customers in the seven states included in the
Central region.
Our organizations share very similar values focusing on our customers,
employees, communities and shareholders. Those values are evident in
the agreement which will preserve the Empire brand for at least five years,
and maintain our current operations, staff, corporate headquarters and
community presence.
As part of a larger organization, we will benefit from greater scale, geographic
diversity and growth opportunities. We’ll also have Algonquin’s expertise
in renewable energy development to assist us in developing a least-cost
plan to comply with future environmental regulations like the Clean Power
Plan, which, despite the legal challenges, will likely have an impact on future
energy generation.
The merger will require approval from Empire shareholders in addition to
approval from state and federal regulators.
The journey we are embarking upon today bears a striking resemblance
to our past. The Empire District Electric Company was established in
1909 through the consolidation of several smaller area utility companies.
To achieve a larger scale, over a dozen more utility companies were
brought into the Empire fold over the next three decades, shaping much
of the western electrical service area we have today. Empire operated as
a subsidiary of the Cities Service Company, a New York based holding
company, until 1944 when Cities Service Company was prompted by the
Public Utilities Holding Company Act to divest its interest in Empire and
three other local utility companies. Those four local companies then joined
together to form the investor-owned, publicly traded utility known today as
The Empire District Electric Company.
t
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e
d
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s
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P
e
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r
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1
Over our 106-year history, our company and our industry have experienced
many changes. Yet our mission has remained the same – to provide safe,
reliable energy for our customers, value to our shareholders and a positive
work experience for our employees. We will continue to carry on this mission
in the new and exciting chapter that lies ahead.
Moving on to earnings and other highlights for 2015, as we expected,
earnings were impacted by regulatory lag associated with the Asbury Air
Quality Control System (AQCS). What we didn’t expect was exceptionally
mild weather for the year. As you know, weather is the wild card in our
business and we were reminded of this with the mildest fourth quarter
in over 30 years. Collectively, these factors forced earnings down to the
bottom of our guidance range.
Despite the weather, it was a year of many successes. Our retained earnings
reached $100 million for the first time; we maintained a healthy balance
sheet and a sustainable dividend; we achieved continued improvement in
service reliability for our customers; and our employees posted another
good safety performance.
In 2015 we entered the final phase of a multi-year compliance plan to reduce
fossil fuel emissions. The plan is capped with the new Riverton 12 Combined
Cycle Unit scheduled to begin commercial operation in the second quarter
of 2016. The AQCS at the coal-fired Asbury Power Plant, another critical
piece of the plan, completed its first full year of operation in 2015.
Communication has been an important part of our compliance plan,
so we continue to inform our customers about the costs and benefits
of major environmental projects and improvements within the regional
transmission system. Once the Riverton project is complete we will have
adequate production capacity and will be fully compliant with all current
environmental standards.
large
investments
Even with the
in environmental and efficiency
improvements, electricity is still a good value. To capitalize on that value,
we’re adding plug-in hybrid vehicles to our fleet and developing a plan to
encourage broader customer adoption of electric vehicles. We’re assisting
our customers who have chosen to install solar, and we continue to evaluate
our role in the solar energy value chain. When customers are considering
these options, we are here to provide the information and service they need.
Our initiative to strengthen the energy delivery system and enhance
reliability for our customers remains a top priority. We continue to invest in
system improvements and enhance work management processes. Our focus
on project planning, execution and evaluation is providing efficiency gains
and allowing us to target resources for cost savings over the long term.
After successful results with our Vegetation Management program and the
Operation Toughen Up initiative, we are moving forward with development
of a standardized, comprehensive preventative maintenance program to
enhance safe, reliable operation of our substations.
2
In the pages that follow, you’ll learn more about some of the most notable
accomplishments of the year. Each is united by a common theme: delivering
value to our shareholders, our customers and our employees.
In closing, thank you for your investment and belief in The Empire District
Electric Company.
Sincerely,
Brad Beecher
President and CEO
February 26, 2016
Maximo Power Delivery
A team of individuals is nearing completion on the next implementation phase of our Maximo work management system.
In 2015, the team’s efforts concentrated on the “Power Delivery-Construction” bundle – which includes Engineering and
Construction Design. The new system will aid in standardization for design and construction of transmission, distribution
and substation facilities and allow us to achieve greater efficiency. We also expect improved material and labor estimating
capability and post-construction reconciliations from the system. This will complete our transition away from a legacy work
management system.
Maximo Power Delivery Team
Chris S., Scott, Emily, Karen, Jacob, Regin, Kimberly,
Chris G., Dan, Debbie, Allen, Kent and Jason
3
Riverton 12 Combined Cycle
The Riverton 12 Combined Cycle Unit is in the final stages of testing and commissioning. The Riverton site has a long
history of providing energy to the Empire District region. Over the course of 110 years, power production at Riverton has
transformed from hydro to coal to natural gas. The project is the first large-frame combined cycle generating unit in Kansas
and is among the most efficient natural gas units in the country. The project was driven by the Mercury and Air Toxics
Standards and has an estimated cost of $165-$175 million. The high efficiency of this unit will help us hold down fuel costs
while lowering emissions and protecting the environment.
Ed, Riverton Energy Supply; and Tim, Energy Supply Services
4
The Riverton 12 Combined Cycle Unit
Riverton, Kansas
2015 RATE ACTIVITY
In 2015, we secured rates to begin recovering costs related to the Asbury AQCS project in Missouri, Kansas and Arkansas.
On October 16, 2015, we filed for new rates in Missouri and Oklahoma. The primary driver for the filings are costs related to
the Riverton 12 Combined Cycle Unit.
STATE
ARKANSAS
KANSAS
MISSOURI
MISSOURI
OKLAHOMA
TYPE
DATE EFFECTIVE/FILED*
ANNUAL REVENUE / REQUESTED*
ENVIRONMENTAL COST
RECOVERY RIDER
ENVIRONMENTAL RIDER
GENERAL
GENERAL
GENERAL
FEBRUARY 23
APRIL 14
JULY 26
OCTOBER 16*
OCTOBER 21*
$0.46M
$0.78M
$17.1M
$33.4M*
+ +
+ + An adminstrative rule took effect in Oklahoma in 2015 providing reciprocity treatment of Missouri rates for electric companies who serve less than
+ + 10 percent of their total customers within the state of Oklahoma. Total revenue for the Oklahoma jurisdiction is pending completion of the current
Missouri filing.
5
5
Welch, Oklahoma Project
Recently, we completed the second phase of the
Welch, Oklahoma, area transmission upgrade project
to provide greater reliability. This multi-year
project included replacement of a total of
27 miles of 34kV conductor, poles and
associated equipment.
Eighteen miles of replacement work
was completed in 2015. An improved
standard structure and construction
process was
used
to
easily
accommodate field variances and
structure heights. This modular
design, first used on NERC
projects in 2013 and 2014,
allows for efficient transport
and construction, resulting
in significant cost savings.
6
Service Reliability
The Columbus and Welch projects, along with many others, contributed to further improvement in system reliability indices.
In 2015, we reduced the average number of outage occurrences and the duration of outages affecting customers by 7
percent and 13 percent, respectively. We measure reliability using SAIDI (System Average Interruption Duration Index) and
SAIFI (System Average Interruption Frequency Index).
SAIDI
An index of 115 means the average
customer experienced a total of 115
outage minutes during the year.
Annual System SAIDI
9
3
2
4
4
1
6
4
1
3
3
1
5
1
1
2011 2012 2013 2014 2015
Annual System SAIFI
0
7
.
1
SAIFI
0
4
.
1
5
3
.
1
6
4
.
1
6
3
.
1
An index of 1.3 means the average
customer would experience 1.3 outages
during the year.
300
250
200
150
100
50
0
1.8
1.6
1.4
1.2
1
0.8
0.6
0.4
0.2
0
2011 2012 2013 2014 2015
Columbus, Kansas Area Substation
In our Southeast Kansas area, local officials joined us in the dedication of a new electrical substation on October 14.
The $4 million project is part of our ongoing initiative to strengthen the energy delivery system and enhance service
reliability for our customers. The improved breaker configuration will allow routine maintenance to be performed
without a customer outage and will aid in minimizing the number of customers affected if and when a fault causes
System Reliability Columbus
Explanation Text
an unexpected outage. This is one of several substation projects we completed in 2015.
7
5
Lineman’s Rodeo
In September, several Empire linemen
took part in the Annual International
Lineman’s Rodeo in Bonner Springs,
Kansas. The Rodeo is an opportunity for
linemen to showcase and enhance their
skills, test their safety awareness and learn
from their industry peers.
From a field of over 200 teams, one of our
journeyman teams placed in the top four in the
hurt-man rescue event earning a place on stage at
the awards ceremony. This is our best journeyman
team performance in over 20 years.
Gas Operations
projects
In our Gas Operations area, crews completed line replacement
in Nevada, Marceline and Weston, Missouri.
The projects replaced existing steel gas mains with
polyethylene pipe to enhance the safety and reliability of
service to customers.
Ben, Eric, and Aaron, Kodiak Line Operations
(Photo courtesy of Samantha Olson)
David, Platte City Gas Operations,
inspects gas line replacement work.
Wildlife Conservation
to
team
creative
solutions
In 2015, Empire’s Vegetation
applied
Management
ensure
reliable service for customers while
protecting habitat for native wildlife.
A 75-foot high alternative nesting
platform was installed for a pair of Osprey
near Stockton Lake, Missouri. Previously,
the pair nested on the arms of a nearby
transmission line, causing their nest to make
contact with an energized line, catch fire and
result in a power outage. The Osprey raised three
young birds in the new location in 2015. Osprey
return to the same nesting site each year, typically
in late February or early March. A video stream of the
Bolivar line crews assist with relocation of an osprey nest.
8
nesting site is available at www.empiredistrict.com.
The Wires Over Wildlife (WOW) program preserves and
enhances habitat on land beneath Empire’s transmission
lines. The program involves property owners willing to
maintain the area as a wildlife habitat with guidance from
the Missouri Department of Conservation and Empire.
Artist rendering of Kansas City University of Medicine
and Biosciences Medical School being established in Joplin.
Economic Development
Plans to establish a medical school
in Joplin were announced in 2015,
bringing the potential for an annual
regional economic impact of over $100
million when it reaches full capacity.
Kansas City University of Medicine and
Biosciences will develop the school using
the 150,000 square foot building previously
used by Mercy Hospital. Use of the existing
structure will allow the medical school to open in
the Fall of 2017 with an initial class of 150 students.
In July, Owens Corning announced it had selected
Joplin as the site for a new manufacturing operation.
They will invest $90 million to establish the operation
in a vacant facility just west of Joplin. The plant will
produce a type of mineral wool insulation used most often
in commercial buildings. The facility is expected to employ
over 100 workers and is slated to begin operation in June of
this year. After an initial ramp-up period, full electric load is
projected to be in the 5 to 6 megawatt range.
Hybrid Electric Vehicles
Electric vehicles (EV) have become an economic alternative
to gas vehicles. We are incorporating plug-in hybrids in
the Empire fleet and developing a plan to encourage
broader adoption of EVs by our customers. Our hybrid
fleet sedans can achieve the equivalent of 88 miles
per gallon when operating in combined electric/
gas mode. This will provide significant fuel savings
compared to standard gas-powered fleet vehicles.
Lower emissions are an added bonus.
Shawn, Business and Community Development;
Dave, Transportation Services
Solar Rebate Program
solar
totaling
A mandated
rebate
program resulted in 767 applications
of
capacity for customer-owned solar
installations on the Empire system as
of December 31, 2015. We have filed
to recover in rates the costs associated
11.5 Megawatts
with the rebate program.
The phrase “going off the grid” is often used
when referring to customers who go solar.
However, due to the varying availability of solar,
these customers depend on Empire’s energy
distribution system just as much today as they
always have. We are here to keep the energy system
in balance by providing electricity when the sun is
not shining and accepting the customer’s production
when it exceeds their needs.
9
Scott, Construction Design; Stephanie, Business and Community
Development; Background: Ryan, Meter Shop
Officers1
Bradley P. Beecher
President and Chief
Executive Officer
(Age 50, 26 years
of service)
Laurie A. Delano
Vice President –
Finance and
Chief Financial
Officer
(Age 60, 25 years
of service)
Ronald F. Gatz
Vice President and
Chief Operating
Officer – Gas
(Age 65, 14 years
of service)
Blake A. Mertens
Vice President –
Energy Supply
and Delivery
Operations
(Age 38, 14 years
of service)
Brent A. Baker
Vice President –
Customer Service,
Transmission, and
Engineering
(Age 37, 13 years
of service)
Directors1
Kelly S. Walters
Vice President and
Chief Operating
Officer – Electric
(Age 50, 23 years
of service)
Kenneth R. Allen
Retired Vice President – Finance
and Chief Financial Officer
Texas Industries, Inc.
Dallas, Texas
(Age 58, Director since 2005)
Mark T. Timpe
Treasurer
(Age 56, 2 years
of service)
Dale W. Harrington
Secretary and
Director of
Investor Relations
(Age 54, 25 years
of service)
Robert W. Sager
Controller, Asst.
Secretary and Asst.
Treasurer
(Age 41, 9 years of
service)
Bradley P. Beecher
President and Chief Executive Officer
The Empire District Electric Company
(Age 50, Director since 2011)
Ross C. Hartley
Co-Founder and Director, NIC, Inc.
Teton Village, Wyoming
(Age 68, Director since 1988)
D. Randy Laney
Chairman of the Board of Directors
The Empire District Electric Company
Farmington, Arkansas
(Age 61, Director since 2003)
Bonnie C. Lind
Senior Vice President, Chief Financial
Officer and Treasurer
Neenah Paper, Inc.
Alpharetta, Georgia
(Age 57, Director since 2009)
B. Thomas Mueller
Founder, President and Chief Executive
Officer, SALOV North America Corporation
Montclair, New Jersey
(Age 68, Director since 2003)
Thomas M. Ohlmacher
Retired President and Chief Operating
Officer, Non-regulated Energy
Black Hills Corporation
Fort Collins, Colorado
(Age 64, Director since 2011)
Paul R. Portney
Retired Professor of Economics and former
Dean, Eller College of Management
University of Arizona
Santa Barbara, California
(Age 70, Director since 2009)
Herbert J. Schmidt
Retired Executive Vice President, Con-way Inc.
and President, Con-way Truckload
The Villages, Florida
(Age 60, Director since 2010)
C. James Sullivan
Principal
The Sullivan Group LLC
Birmingham, Alabama
(Age 69, Director since 2010)
Committees of the Board
Audit Committee – Allen2 (Chair), Hartley, Lind2, Mueller2
Compensation Committee – Ohlmacher (Chair), Laney, Mueller, Portney
Nominating/Corporate Governance Committee – Lind (Chair), Hartley, Laney,
Sullivan
Retirement Committee – Sullivan (Chair), Allen, Schmidt
Security and Strategic Projects Committee – Schmidt (Chair), Ohlmacher,
Portney, Sullivan
Executive Committee – Beecher (Chair), Allen, Laney
Risk Oversight Committee – Laney (Chair), Allen, Lind, Ohlmacher, Schmidt
1 Ages shown as of March 1, 2016. 2 Audit Committee Financial Expert.
10
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
FORM 10-K
(cid:1) Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2015
(cid:2) Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
or
For the transition period from
to
.
Commission file number: 1-3368
THE EMPIRE DISTRICT ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Kansas
(State of Incorporation)
602 S. Joplin Avenue, Joplin, Missouri
(Address of principal executive offices)
44-0236370
(I.R.S. Employer Identification No.)
64801
(zip code)
Registrant’s telephone number: (417) 625-5100
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Stock ($1 par value)
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes (cid:1) No (cid:2)
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 (cid:2) No (cid:1)
(cid:1) 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 (cid:1) No (cid:2)
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding
12 months (or for such shorter period that the registrant was required to submit and post such files). Yes (cid:1) No (cid:2)
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. (cid:1)
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or
a smaller reporting company. See the definitions of ‘‘large accelerated filer,’’ ‘‘accelerated filer’’ and ‘‘smaller reporting
company’’ in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer (cid:1)
Smaller reporting company (cid:2)
Accelerated filer (cid:2)
Non-accelerated filer (cid:2)
(Do not check if a
smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes (cid:2) No (cid:1)
The aggregate market value of the registrant’s voting common stock held by nonaffiliates of the registrant, based on the
closing price on the New York Stock Exchange on June 30, 2015, was approximately $952,425,061.
As of February 1, 2016, 43,860,337 shares of common stock were outstanding.
The following documents have been incorporated by reference into the parts of the Form 10-K as indicated:
The Company’s proxy statement, filed pursuant
to Regulation 14A under the Securities Exchange
Act of 1934, for its Annual Meeting of
Stockholders to be held on April 28, 2016
Part of Item 10 of Part III
All of Item 11 of Part III
Part of Item 12 of Part III
All of Item 13 of Part III
All of Item 14 of Part III
TABLE OF CONTENTS
Forward Looking Statements
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3
Page
PART I
ITEM 1.
BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electric Generating Facilities and Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Construction Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel and Natural Gas Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electric Operating Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas Operating Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Officers and other Officers of Empire . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Environmental Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conditions Respecting Financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Our Web Site . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 1A. RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 1B. UNRESOLVED STAFF COMMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 2.
Electric Segment Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas Segment Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MINE SAFETY DISCLOSURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 3.
ITEM 4.
PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
ITEM 6.
ITEM 7.
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES . . . . . . . . . . . .
SELECTED FINANCIAL DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rate Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Markets and Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Contractual Obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Off-Balance Sheet Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Critical Accounting Policies
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recently Issued Accounting Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . .
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . . . . . . . . . . . . . .
ITEM 8.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
ITEM 9.
AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 9A. CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 9B. OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE . . . . . .
EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 11.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
ITEM 12.
PART III
5
5
6
8
8
9
11
12
13
14
14
15
16
17
17
25
25
25
27
27
27
27
28
30
30
30
36
43
44
44
50
50
51
51
54
54
57
127
127
127
128
128
MANAGEMENT AND RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . .
128
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
ITEM 14.
INDEPENDENCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PRINCIPAL ACCOUNTANT FEES AND SERVICES . . . . . . . . . . . . . . . . . . . . . . . . .
129
129
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES . . . . . . . . . . . . . . . . . . . .
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
130
136
PART IV
FORWARD LOOKING STATEMENTS
Certain matters discussed in this annual report are ‘‘forward-looking statements’’ intended to qualify
for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such
statements address or may address future plans, objectives, expectations and events or conditions
concerning various matters such as the pending acquisition of Empire by Liberty Utilities (Central) Co.
(Liberty), a subsidiary of Algonquin Power & Utilities Corp. (APUC) (the Merger), capital expenditures,
earnings, pension and other costs, competition, litigation, our construction program, our generation plans,
our financing plans, potential acquisitions, rate and other regulatory matters, liquidity and capital
resources and accounting matters. Forward-looking statements may contain words like ‘‘anticipate’’,
‘‘believe’’, ‘‘expect’’, ‘‘project’’, ‘‘objective’’ or similar expressions to identify them as forward-looking
statements. Factors that could cause actual results to differ materially from those currently anticipated in
such statements include:
(cid:127) weather, business and economic conditions and other factors which may impact sales volumes and
customer growth;
(cid:127) the impact of energy efficiency and alternative energy sources, including solar;
(cid:127) the costs and other impacts resulting from natural disasters, such as tornados and ice storms;
(cid:127) the amount, terms and timing of rate relief we seek and related matters;
(cid:127) the results of prudency and similar reviews by regulators of costs we incur, including capital
expenditures and fuel and purchased power costs, including any regulatory disallowances that could
result from prudency reviews;
(cid:127) unauthorized physical or virtual access to our facilities and systems and acts of terrorism, including,
but not limited to, cyber-terrorism;
(cid:127) legislation and regulation, including environmental regulation (such as NOx, SO2, mercury, ash and
CO2) and health care regulation;
(cid:127) the periodic revision of our construction and capital expenditure plans and cost and timing
estimates;
(cid:127) costs and activities associated with markets and transmission, including the Southwest Power Pool
(SPP) regional transmission organization (RTO) transmission development, and SPP Day-Ahead
Market;
(cid:127) electric utility restructuring, including deregulation;
(cid:127) spending rates, terminal value calculations and other factors integral to the calculations utilized to
test the impairment of goodwill, in addition to market and economic conditions which could
adversely affect the analysis and ultimately negatively impact earnings;
(cid:127) volatility in the credit, equity and other financial markets and the resulting impact on short term
debt costs and our ability to issue debt or equity securities, or otherwise secure funds to meet our
capital expenditure, dividend and liquidity needs;
(cid:127) the effect of changes in our credit ratings on the availability and cost of funds;
(cid:127) the performance of our pension assets and other post employment benefit plan assets and the
resulting impact on our related funding commitments;
(cid:127) our exposure to the credit risk of our hedging counterparties;
3
(cid:127) the cost and availability of purchased power and fuel, including costs and activities associated with
the SPP Day-Ahead Market, and the results of our activities (such as hedging) to reduce the
volatility of such costs;
(cid:127) interruptions or changes in our coal delivery, gas transportation or storage agreements or
arrangements;
(cid:127) operation of our electric generation facilities and electric and gas transmission and distribution
systems, including the performance of our joint owners;
(cid:127) our potential inability to attract and retain an appropriately qualified workforce;
(cid:127) changes in accounting requirements;
(cid:127) costs and effects of legal and administrative proceedings, settlements, investigations and claims;
(cid:127) performance of acquired businesses;
(cid:127) other circumstances affecting anticipated rates, revenues and costs; and
(cid:127) certain risks and uncertainties associated with the Merger, including, without limitation:
(cid:127) the risk that Empire may be unable to obtain shareholder approval for the proposed
transaction or that Liberty or Empire may be unable to obtain governmental and regulatory
approvals required for the proposed transaction, or required governmental and regulatory
approvals may delay the proposed transaction;
(cid:127) the risk that any other condition to the closing of the proposed transaction may not be satisfied;
(cid:127) the occurrence of any event, change or other circumstances that could give rise to the
termination of the merger agreement or could otherwise cause the failure of the Merger to
close;
(cid:127) the failure of Liberty or APUC to obtain any financing necessary to complete the merger;
(cid:127) the outcome of any legal proceedings, regulatory proceedings or enforcement matters that may
be instituted against Empire and others relating to the merger agreement;
(cid:127) the receipt of an unsolicited offer from another party to acquire assets or capital stock of
Empire that could interfere with the proposed Merger;
(cid:127) the timing to consummate the proposed transaction;
(cid:127) disruption from the proposed transaction making it more difficult to maintain relationships
with customers, employees, regulators or suppliers;
(cid:127) the diversion of management time and attention on the transaction;
(cid:127) the amount of costs, fees, expenses, and charges related to the Merger; and
(cid:127) the effect and timing of changes in laws or in governmental regulations (including
environmental laws and regulations) that could adversely affect our participation in the
Merger.
All such factors are difficult to predict, contain uncertainties that may materially affect actual results,
and may be beyond our control. Additional risks and uncertainties will be discussed in the proxy statement
and other materials that Empire will file with the SEC in connection with the Merger. New factors emerge
from time to time and it is not possible for management to predict all factors or to assess the impact of
each such factor on us. Any forward-looking statement speaks only as of the date on which such statement
is made, and we do not undertake any obligation to update any forward-looking statement to reflect events
or circumstances after the date on which such statement is made.
We caution you that any forward-looking statements are not guarantees of future performance and
involve known and unknown risk, uncertainties and other factors which may cause our actual results,
performance or achievements to differ materially from the facts, results, performance or achievements we
have anticipated in such forward-looking statements.
4
ITEM 1. BUSINESS
General
PART I
We operate our businesses as three segments: electric, gas and other. The Empire District Electric
Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the
generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas,
Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in
Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary engaged in the
distribution of natural gas in Missouri. Our other segment consists of our fiber optics business.
Our gross operating revenues in 2015 were derived as follows:
Electric segment sales* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
On-system revenues
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPP IM revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas segment sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other segment sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
86.6%
2.5
2.3
91.7%
6.9
1.4
*
Sales from our electric segment include 0.3% from the sale of water.
On-system electric revenues consist of residential, commercial, industrial, wholesale on-system and
other (which includes street lighting, other public authorities and interdepartmental usage).
The territory served by our electric operations embraces an area of about 10,000 square miles, located
principally in southwestern Missouri, and also includes smaller areas in southeastern Kansas, northeastern
Oklahoma and northwestern Arkansas. The principal economic activities of these areas include light
industry, agriculture and tourism. As of December 31, 2015, our electric operations served approximately
170,000 customers.
Our retail electric revenues for 2015 by jurisdiction were derived as follows:
Missouri
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
89.0%
4.8
2.8
3.4
We supply electric service at retail to 119 incorporated communities as of December 31, 2015, and to
various unincorporated areas and at wholesale to four municipally owned distribution systems. The largest
urban area we serve is the city of Joplin, Missouri, and its immediate vicinity, with a population of
approximately 160,000. We operate under franchises having original terms of twenty years or longer in
virtually all of the incorporated communities. Approximately 39% of our electric operating revenues in
2015 were derived from incorporated communities with franchises having at least ten years remaining and
approximately 31% were derived from incorporated communities in which our franchises have remaining
terms of ten years or less. Although our franchises contain no renewal provisions, in recent years we have
obtained renewals of all of our expiring electric franchises prior to the expiration dates.
Our three largest classes of on-system customers are residential, commercial and industrial, which
provided 41.7%, 31.1%, and 15.9%, respectively, of our electric operating revenues in 2015.
Our largest single on-system wholesale customer is the city of Monett, Missouri, which in 2015
accounted for approximately 2.4% of electric revenues. No single retail customer accounted for more than
1.9% of electric revenues in 2015.
5
Our gas operations serve customers in northwest, north central and west central Missouri. As of
December 31, 2015, our gas operations served approximately 43,200 customers. We provide natural gas
distribution to 48 communities and 434 transportation customers as of December 31, 2015. The largest
urban area we serve is the city of Sedalia with a population of over 20,000. We operate under franchises
having original terms of twenty years in virtually all of the incorporated communities. Eighteen of the
franchises have 10 years or more remaining on their term and 27 of the franchises have less than 10 years
remaining on their term. Although our franchises contain no renewal provisions, since our acquisition we
have obtained renewals of all our expiring gas franchises prior to the expiration dates.
Our gas operating revenues in 2015 were derived as follows:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
63.0%
25.6
0.8
8.9
1.7
No single retail customer accounted for more than 1% of gas revenues in 2015.
Our other segment consists of our fiber optics business. As of December 31, 2015, we have 99 fiber
customers.
Electric Generating Facilities and Capacity
At December 31, 2015, our generating plants consisted of:
Plant
State Line Combined Cycle (60% ownership) . . . . . . . . . . . . . . . . . . . . . .
Riverton — Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Empire Energy Center . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State Line Unit No. 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asbury . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Iatan (12% ownership) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plum Point Energy Station (7.52% ownership) . . . . . . . . . . . . . . . . . . . . .
Ozark Beach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capacity
(megawatts)(1)
295(2)
177(3)
257
96
198
191(2)
50(2)
16
Primary Fuel
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Coal
Coal
Coal
Hydro
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,280
(1) Based on summer rating conditions as utilized by Southwest Power Pool.
(2) Capacity reflects our allocated shares of the capacity of these plants.
(3) Does not include the combined cycle portion of Riverton Unit 12 as it was not yet in operation as of
December 31, 2015.
Our generating capacity consists of 64.4% natural gas, 34.3% coal and 1.3% hydro. We currently
supplement our on-system generating capacity with purchases of capacity and energy from other sources in
order to meet the demands of our customers and the capacity margins applicable to us under current
pooling agreements and National Electric Reliability Council rules. The Southwest Power Pool (SPP)
requires its members (including Empire) to maintain a minimum 12% capacity margin.
We have a long-term agreement, which expires in 2039, for the purchase of 50 megawatts of capacity
from the Plum Point Energy Station (Plum Point), a 670-megawatt, coal-fired generating facility near
Osceola, Arkansas. We began receiving purchased power under this agreement on September 1, 2010. We
6
also own, through an undivided interest, 50 megawatts of the unit’s capacity. We had the option to
purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement.
We evaluated this purchase option as part of our Integrated Resource Plan (IRP), which was filed with the
Missouri Public Service Commission (MPSC) on July 1, 2013. We did not exercise this option by the March
2015 notification deadline in the contract.
We have a long-term purchased power agreement, which expires in 2028, with Cloud County
Windfarm, LLC, owned by EDP Renewables North America LLC, Houston, Texas to purchase the energy
generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County,
Kansas. We also have a long-term contract, which expires in 2025, with Elk River Windfarm, LLC, owned
by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River
Windfarm located in Butler County, Kansas. We do not own any portion of either windfarm.
Operationally, we participate in the SPP Integrated Marketplace (IM) to meet our energy and
ancillary service requirements. Our generation resources are offered into the marketplace. The
marketplace solution determines what offered resources are committed and dispatched to meet
region-wide demand, energy, and ancillary service requirements. To the extent other resources offered to
the marketplace are more economic than our resources they will be utilized for our load, lowering our cost
compared to meeting requirements with only our resources.
We, and most other electric utilities with interstate transmission facilities, have placed our facilities
under the Federal Energy Regulatory Commission (FERC) regulated open access tariffs that provide all
wholesale buyers and sellers of electricity the opportunity to procure transmission services (at the same
rates) that the utilities provide themselves. We are a member of the Southwest Power Pool Regional
Transmission Organization (SPP RTO). See Item 7, ‘‘Management’s Discussion and Analysis of Financial
Condition and Results of Operations — Markets and Transmission.’’
The following chart sets forth our purchase commitments and our anticipated owned capacity (in
megawatts) during the indicated years. The capacity ratings we use for our generating units are based on
summer rating conditions under SPP guidelines. The portion of the purchased power that may be counted
as capacity from the Elk River Windfarm, LLC and the Cloud County Windfarm, LLC is included in this
chart. Because the wind power is an intermittent, non-firm resource, SPP rating criteria does not allow us
to count a substantial amount of the wind power as capacity. See Item 7, ‘‘Managements’ Discussion and
Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.’’
Year
Purchased
Power
Commitment(1)
Anticipated
Owned
Capacity
Total
Megawatts
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
86
86
86
86
86
1374(2)
1374
1374
1374
1374
1460(2)
1460
1460
1460
1460
(1) Includes 17 megawatts for the Elk River Windfarm, LLC and 19 megawatts for the Cloud County
Windfarm, LLC.
(2) Reflects the conversion of Riverton Unit 12 to a combined cycle.
The maximum hourly demand on our system reached a record high of 1,199 megawatts on January 8,
2010. Our maximum hourly summer demand of 1,198 megawatts was set on August 2, 2011.
7
Gas Facilities
At December 31, 2015, our principal gas utility properties consisted of approximately 87 miles of
transmission mains and approximately 1,189 miles of distribution mains.
The following table sets forth the three pipelines that serve our gas customers:
Service Area
Name of Pipeline
South . . . . . . . . . . . . . . . . . . . . . . . . . . . .
North . . . . . . . . . . . . . . . . . . . . . . . . . . . . Panhandle Eastern Pipe Line Company
Northwest
. . . . . . . . . . . . . . . . . . . . . . . . ANR Pipeline Company
Southern Star Central Gas Pipeline
Our all-time peak of 73,280 mcfs was established on January 7, 2010.
Construction Program
Total property additions (including construction work in progress but excluding AFUDC) for the
three years ended December 31, 2015, totaled $526.7 million and retirement expenditures during the same
period totaled $23.0 million. Please refer to Item 7, ‘‘Management’s Discussion and Analysis of Financial
Condition and Results of Operations — Liquidity and Capital Resources’’ for more information.
Our total capital expenditures, excluding AFUDC and expenditures to retire assets, were
$164.2 million in 2015 and for the next three years are estimated for planning purposes to be as follows:
Estimated Capital Expenditures
(amounts in millions)
2016
2017
2018
Total
New electric generating facilities:
Riverton Unit 12 combined cycle conversion . . . . . . . . . . . . . . .
$ 11.7
$
0.0
$
0.0
$ 11.7
Additions to existing electric generating facilities:
Asbury . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electric transmission facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electric distribution system additions . . . . . . . . . . . . . . . . . . . . . . .
General and other additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas system additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-regulated additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.6
13.7
23.3
46.7
10.9
4.1
2.1
3.9
17.8
29.6
40.5
8.3
4.1
2.1
10.0
25.2
26.2
62.0
28.9
5.0
2.1
16.5
56.7
79.1
149.2
48.1
13.2
6.3
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$115.1
$106.3
$159.4
$380.8
Construction expenditures for additions to our transmission and distribution systems constitute the
majority of the projected capital expenditures for the three-year period listed above beyond routine capital
expenditures. Customer reliability, communication and efficiency projects comprise $15 million of the 2018
general and other additions projection. Our estimated total capital expenditures (excluding AFUDC) for
2019 and 2020 are $150.9 million and $114.1 million, respectively.
Future capital expenditure needs are reviewed regularly and are subjected to our annual capital
budget prioritization process, wherein projects are ranked by type and urgency based on a variety of factors
culminating in a 5-year capital expenditure plan. (See Item 7, ‘‘Managements’ Discussion and Analysis of
Financial Condition and Results of Operations — Liquidity and Capital Resources’’ for detail regarding
our future estimated capital expenditures). Projects evaluated during the capital budget prioritization
process include, but are not limited to, those for capacity needs, replacement of aged infrastructure and
other projects to improve and/or enhance safety and reliability. Actual capital expenditures may vary
significantly from the estimates due to a number of factors including changes in customer requirements,
construction delays, changes in equipment delivery schedules, ability to raise capital, environmental
8
matters, the extent to which we receive timely and adequate rate increases, the extent of competition from
independent power producers and cogenerators, other changes in business conditions and changes in
legislation and regulation, including those relating to the energy industry. See ‘‘— Regulation’’ below and
Item 7, ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations —
Markets and Transmission.’’
Fuel and Natural Gas Supply
Electric Segment
Our total system output for 2015 and 2014, based on kilowatt-hours generated, was as follows:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Steam generation units — coal
Combustion turbine generation units — natural gas . . . . . . . . . . . . . . .
Hydro generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power — wind . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power — other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015
2014
50.2% 47.5%
26.6
0.9
16.7
5.6
26.5
1.2
18.2
6.6
Below are the total fuel requirements for our generating units in 2015 and 2014 (based on
kilowatt-hours generated):
Coal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tire derived fuel
2015
2014
65.0% 63.7%
34.6
0.3
0.1
35.8
0.4
0.1
Our Asbury Plant is fueled primarily by coal with oil being used as start-up fuel. In 2015, Asbury
burned a coal blend consisting of approximately 93.9% Western coal (Powder River Basin) and 6.1% blend
coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of
December 31, 2015, we had sufficient coal on hand to supply full load requirements at Asbury for
112 – 135 days, as compared to 44 – 77 days as of December 31, 2014, depending on the actual blend ratio.
The inventory increased during 2015 as low natural gas prices resulted in lower coal usage.
The following table sets forth the percentage of our anticipated coal requirements we have secured
through a combination of contracts and binding proposals for the following years:
Year
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Percentage
secured
100%
46%
23%
All of the Western coal used at our Asbury plant is shipped by rail, a distance of approximately
800 miles. We have a coal transportation agreement with the BNSF Railway Company and the Kansas City
Southern Railway Company which runs through 2019. We currently lease one aluminum unit train full time
to deliver Western coal to the Asbury Plant. Additional train capacity is leased on an as needed basis.
Unit 1 and Unit 2 at the Iatan Plant are coal-fired generating units which are jointly-owned by
KCP&L, a subsidiary of Great Plains Energy, Inc., Missouri Joint Municipal Electric Utility Commission,
Kansas Electric Power Cooperative (KEPCO) and us, with our share of ownership being 12% in each
plant. KCP&L is the operator of these plants and is responsible for arranging their fuel supply. KCP&L has
secured contracts for low sulfur Western coal in quantities sufficient to meet 90% of Iatan’s requirements
9
for 2016, 60% for 2017, 35% for 2018 and 10% for 2019. Coal is transported to Iatan by rail. Their rail
contract provides transportation services through December 31, 2018.
The Plum Point Energy Station is a 670-megawatt, coal-fired generating facility near Osceola,
Arkansas. We own, through an undivided interest, 50 megawatts of the plant’s capacity. NRG Energy
Services LLC is the operator of this plant. Plum Point Services Company, LLC (PPSC), the project
management company acting on behalf of the joint owners, is responsible for arranging its fuel supply.
PPSC has secured contracts for low sulfur Western coal in quantities sufficient to meet approximately 99%
of Plum Point’s requirements for 2016 and 47% for 2017. We have a 15-year lease agreement, expiring in
2024, for 54 railcars for our ownership share of Plum Point and another 15-year lease agreement, expiring
in 2025, for an additional 54 railcars associated with our Plum Point purchased power agreement.
Our Riverton Plant is fueled primarily by natural gas with oil available as backup for Units 10 and 11.
Unit 12 is fueled 100% by natural gas. Unit 7 was retired on June 30, 2014 and Unit 8 and Unit 9 were
retired on June 30, 2015. Construction continued during the year to convert Unit 12 to a combined cycle
unit. Based on kilowatt hours generated during 2015, Riverton’s generation was 100% natural gas.
Our Energy Center and State Line Unit No.1 combustion turbine facilities (not including the State
Line Combined Cycle (SLCC) Unit, which is fueled 100% by natural gas) are fueled primarily by natural
gas with oil also available for use primarily as backup. Based on kilowatt hours generated during 2015,
97.6% of the Energy Center generation was produced from natural gas and 99.4% of the State Line Unit 1
generation came from natural gas with the remainder being fuel oil. As of December 31, 2015, oil
inventories were sufficient for approximately 5 days of full load operation on Units No. 1, 2, 3 and 4 at the
Energy Center and 5 days of full load operation for State Line Unit No. 1. As typical oil usage is minimal,
these inventories are sufficient for our current requirements.
We and Westar Generating, Inc., a subsidiary of Westar Energy, Inc., share joint ownership of a
nominal 500-megawatt combined cycle unit, SLCC, at the State Line Power Plant. We are responsible for
the operation and maintenance of the SLCC Unit, and are entitled to 60% of the available capacity and
are responsible for approximately 60% of its costs.
We have firm transportation agreements with Southern Star Central Pipeline, Inc. which expire on
July 30, 2017, for the transportation of natural gas to the SLCC. This date is adjusted for periods of
contract suspension by us during SLCC outages. We have reached agreement with Southern Star to replace
these firm transportation agreements effective April 1, 2016 with a new agreement that runs through
October 2022. We have additional firm transportation agreements that provide firm transportation to our
Riverton plant sufficient to supply our Riverton Unit 12 through August, 2019. These transportation
agreements can also supply natural gas to State Line Unit No.1, the Empire Energy Center or the Riverton
Plant, as elected by us on a secondary basis. We expect that these transportation agreements will serve
nearly all of our natural gas transportation needs for our generating plants over the next several years. Any
remaining gas transportation requirements, although small, will be met by utilizing capacity release on
other holder contracts, interruptible transport, or delivered to the plants by others.
The majority of our physical natural gas supply requirements will be met by short-term forward
contracts and spot market purchases. Forward natural gas commodity prices and volumes are hedged
several years into the future in accordance with our Risk Management Policy in an attempt to lessen the
volatility in our fuel expenditures and gain predictability. In addition, we have an agreement with Southern
Star to purchase one million Dths of firm gas storage service capacity for a period of five years, expiring on
April 1, 2016. The reservation charge for this storage capacity is approximately $1.1 million annually. We
currently have no plans to renew this contract.
10
The following table sets forth a comparison of the costs, including transportation and other
miscellaneous costs, per million Btu, of various types of fuels used in our electric facilities:
Fuel Type / Facility
2015
2014
2013
Coal — Iatan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal — Asbury . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal — Plum Point . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil
$ 1.633
2.229
2.124
4.274
18.235
$ 1.738
2.363
2.314
5.268
17.512
$ 1.756
2.432
2.123
4.952
21.870
Weighted average cost of fuel burned per kilowatt-hour generated . . . . .
$2.5460
$2.9700
$2.8074
Gas Segment
We have agreements with many of the major suppliers in both the Midcontinent and Rocky Mountain
regions that provide us with both supply and price diversity. We continue to expand our supplier base to
enhance supply reliability as well as provide for increased price competition.
The following table sets forth the current costs, including storage, transportation and other
miscellaneous costs, per mcf of gas used in our gas operations:
Service Area
Name of Pipeline
2015
2014
2013
South . . . . . . . . . . . . . . . . . . .
North . . . . . . . . . . . . . . . . . . . Panhandle Eastern Pipe Line Company
Northwest
. . . . . . . . . . . . . . . ANR Pipeline Company
Southern Star Central Gas Pipeline
$4.7267
5.2457
3.3223
$4.6986
6.0201
4.8499
$5.4998
5.9746
4.7589
Weighted average cost per mcf
$4.6065
$4.9564
$5.4949
Employees
At December 31, 2015, we had 749 full-time employees, including 49 employees of EDG. 320 of the
EDE employees are members of Local 1474 of The International Brotherhood of Electrical Workers
(IBEW). On December 10, 2013, the Local 1474 IBEW ratified a new five-year agreement, effective
December 2, 2013, which will extend through October 31, 2018. At December 31, 2015, 32 EDG employees
were members of Local 1464 of the IBEW. In May 2013, Local 1464 of the IBEW ratified a four-year
agreement with EDG, effective June 1, 2013.
11
ELECTRIC OPERATING STATISTICS(1)
2015
2014
2013
2012
2011
Electric Operating On-System Revenues (000’s):
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Public authorities(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale on-system . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interdepartmental . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 230,571
171,727
88,185
15,273
18,032
444
$ 236,468
172,274
84,734
14,863
22,326
388
$ 227,656
162,444
80,497
14,707
20,036
229
$ 214,526
158,837
78,786
13,755
18,555
197
$ 221,687
157,435
78,925
13,653
19,140
201
Total system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 524,232
$ 531,053
$ 505,569
$ 484,656
$ 491,041
Electricity generated and purchased (000’s of kWh):
Steam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydro . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Combustion turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total generated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total generated and purchased . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interchange (net)
Total system output
Transmission by others losses(3)
Total for resale — non-system (prior to SPP IM)(4)
Net (sales)/purchases(to)/from SPP IM(4)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . .
. . . . . . . . . . . . . . . . .
2,478,188
41,927
1,315,185
3,835,300
1,101,043
4,936,343
—
4,936,343
—
—
345,251
2,407,914
60,652
1,361,860
3,830,426
1,254,416
5,084,842
(1)
5,084,841
—
(100,158)
386,267
2,813,441
57,449
1,452,936
4,323,826
1,660,193
5,984,019
432
5,984,451
(15,817)
(653,996)
—
2,865,037
57,719
1,486,643
4,409,399
1,545,327
5,954,726
(87)
5,954,639
(17,300)
(704,028)
—
2,805,744
48,898
1,484,472
4,339,114
1,870,901
6,210,015
(1,298)
6,208,717
(16,597)
(740,009)
—
Total native load . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5,281,594
5,370,950
5,314,638
5,233,311
5,452,111
Maximum hourly system demand (Kw)
. . . . . . . . . . . . . . . . . .
Owned capacity (end of period) (Kw) . . . . . . . . . . . . . . . . . . .
Annual load factor (%) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,149,000
1,280,000
52.47
1,162,000
1,326,000
52.76
1,080,000
1,377,000
56.18
1,142,000
1,391,000
52.17
1,198,000
1,392,000
51.95
Electric sales (000’s of kWh):
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Residential
Commercial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Public authorities(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale on-system . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale off-system . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPP EIS Resettlements, Other(4)
. . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Electric Sales
Company use (000’s of kWh)(5)
. . . . . . . . . . . . . . . . . . . . . . .
kWh losses (000’s of kWh)(7) . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale off-system(4)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,836,255
1,577,416
1,064,481
126,786
330,787
4,935,725
—
—
4,935,725
10,553
335,316
—
1,950,416
1,583,843
1,031,555
124,287
336,314
5,026,415
—
1,445
5,027,860
10,725
332,365
—
1,936,603
1,541,717
1,015,492
127,370
343,045
4,964,227
653,996
—
5,618,223
1,850,813
1,558,297
1,028,416
122,369
353,075
4,912,970
704,028
—
5,616,998
1,982,704
1,576,342
1,022,765
126,724
364,866
5,073,401
740,009
—
5,813,410
9,049
341,362
(653,996)
9,066
311,275
(704,028)
9,371
369,339
(740,009)
Total Native Load . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5,281,594
5,370,950
5,314,638
5,233,311
5,452,111
Customers (average number):
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Residential
Commercial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Public authorities(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale on-system . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale off-system . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
142,555
24,311
352
2,082
4
169,304
0
169,304
141,838
24,146
346
2,175
4
168,509
4
168,513
141,376
24,080
345
2,214
4
168,019
22
168,041
140,602
24,036
353
2,124
4
167,119
22
167,141
139,641
24,155
357
2,021
4
166,178
25
166,203
Average annual sales per residential customer (kWh) . . . . . . . . . .
Average annual revenue per residential customer . . . . . . . . . . . .
Average residential revenue per kWh . . . . . . . . . . . . . . . . . . .
Average commercial revenue per kWh . . . . . . . . . . . . . . . . . . .
Average industrial revenue per kWh . . . . . . . . . . . . . . . . . . . .
$
$
12,881
1,617
12.56¢
10.89¢
8.28¢
13,751
1,667
12.12¢
10.88¢
8.21¢
$
13,698
1,610
11.76¢
10.54¢
7.93¢
$
$
13,163
1,526
11.59¢
10.19¢
7.66¢
14,199
1,588
11.18¢
9.99¢
7.72¢
(1)
(2)
(3)
See Item 6, ‘‘Selected Financial Data’’ for additional financial information regarding Empire.
Includes Public Street & Highway Lighting and Public Authorities.
Energy provided in-kind to third party transmission providers to compensate for transmission losses associated with delivery of capacity
and energy under their transmission tariffs. (Prior to SPP IM).
(4) As of March 1, 2014, off-system sales and revenues were effectively replaced by SPP IM activity. See Item 7, ‘‘Management’s Discussion
and Analysis of Financial Condition and Results of Operations — SPP Integrated Marketplace (IM) and Off-System Electric
Transactions’’ below for additional information.
Includes kWh used by Company and Interdepartmental.
2012 includes the effect of our unbilled revenue adjustment.
(5)
(6)
12
GAS OPERATING STATISTICS(1)
2015
2014
2013
2012
2011
Gas Operating Revenues (000’s):
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
Industrial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Public authorities . . . . . . . . . . . . . . . . . . . . . . . .
Total retail sales revenues . . . . . . . . . . . . . . . . . . . .
Miscellaneous(2) . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation revenues . . . . . . . . . . . . . . . . . . . .
$26,282
10,698
315
287
37,582
421
3,699
$32,873
13,640
537
365
47,415
457
3,970
$31,561
13,673
515
342
46,091
435
3,515
$24,744
10,797
464
247
36,252
400
3,197
$28,999
12,506
682
324
42,511
464
3,455
Total Gas Operating Revenues . . . . . . . . . . . . . . . .
$41,702
$51,842
$50,041
$39,849
$46,430
Maximum Daily Flow (mcf) . . . . . . . . . . . . . . . . . .
66,508
72,912
60,118
58,281
67,789
Gas delivered to customers (000’s of mcf sales)(3)
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
Industrial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Public authorities . . . . . . . . . . . . . . . . . . . . . . . .
Total retail sales . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation sales . . . . . . . . . . . . . . . . . . . . . . .
Total gas operating and transportation sales . . . . . . .
Company use(3) . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation sales (cash outs) . . . . . . . . . . . . . .
Mcf losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,219
1,045
38
28
3,330
4,453
7,783
2
—
35
2,760
1,275
62
37
4,134
4,918
9,052
2
—
68
2,744
1,349
72
35
4,200
4,528
8,728
2
—
96
2,012
1,050
58
23
3,143
4,249
7,392
2
—
27
2,560
1,268
102
33
3,963
4,528
8,491
4
—
(47)
Total system sales . . . . . . . . . . . . . . . . . . . . . . . . . .
7,820
9,122
8,826
7,421
8,448
Customers (average number):
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
Industrial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Public authorities . . . . . . . . . . . . . . . . . . . . . . . .
Total retail customers . . . . . . . . . . . . . . . . . . . . . . .
Transportation customers . . . . . . . . . . . . . . . . . . .
Total gas customers
. . . . . . . . . . . . . . . . . . . . . . . .
37,484
4,857
20
143
42,504
434
42,938
37,572
4,872
22
138
42,604
422
43,026
37,777
4,917
24
140
42,858
340
43,198
37,897
4,921
23
138
42,979
326
43,305
38,051
4,951
26
136
43,164
311
43,475
(1) See Item 6, ‘‘Selected Financial Data’’ for additional financial information regarding Empire.
(2) Primarily includes miscellaneous service revenue and late fees.
(3) Includes mcf used by Company and Interdepartmental mcf.
13
Executive Officers and Other Officers of Empire
The names of our officers, their ages and years of service with Empire as of December 31, 2015,
positions held during the past five years and effective dates of such positions are presented below. All of
our officers, other than Mark T. Timpe (whose biographical information is set forth below), have been
employed by Empire for at least the last five years.
Age at
12/31/15
Positions With the Company
With the
Company Officer
Since
Since
Name
Bradley P. Beecher . . . . .
Laurie A. Delano . . . . . .
Kelly S. Walters . . . . . . .
Ronald F. Gatz . . . . . . . .
Blake Mertens . . . . . . . .
50
60
50
65
38
Brent Baker(1)
. . . . . . . .
37
Robert W. Sager . . . . . . .
Dale W. Harrington(2) . . .
41
54
President and Chief Executive Officer (2011).
2001
2001
Executive Vice President (2011)
Vice President — Finance and Chief Financial
2002
2005
Officer, (2011)
Vice President and Chief Operating Officer —
2001
2006
Electric (2011)
Vice President and Chief Operating Officer — Gas
2001
2001
(2006)
Vice President — Energy Supply and Delivery
Operations (2015), Vice President — Energy
Supply (2011)
Vice President — Customer Service, Transmission
and Engineering (2015), Director of Customer
Service (2011)
2001
2011
2003
2015
Controller, Assistant Secretary, Assistant Treasurer
2006
2011
and Principal Accounting Officer (2011)
Corporate Secretary and Director of Investor
Relations (2015), Director of Investor Relations
and Assistant Secretary (2014), Director of
Investor Relations (2014), Director of Financial
Services (2011)
2002
2014
Mark T. Timpe(3)
. . . . . .
56
Treasurer (2014), Director of Financial Services
2014
2014
(2014)
(1) Brent A. Baker was elected Vice-President — Customer Service, Transmission and Engineering
effective March 1, 2015, succeeding Martin O. Penning who retired from his position as
Vice-President — Commercial Operations effective February 28, 2015.
(2) Dale W. Harrington was elected Secretary effective May 1, 2015, succeeding Janet S. Watson who
retired from her position as Secretary effective April 30, 2015.
(3) Mark T. Timpe was elected Treasurer effective October 30, 2014. He joined Empire on August 18,
2014, as Director of Financial Services. Prior to employment with Empire, Mr. Timpe spent over
21 years with Con-Way Truckload/CFI in Joplin where he served as CFI’s Treasurer for 16 years, and,
most recently, as Assistant Treasurer from 2008 to 2014 and Director of Billing and Credit from 2011
to 2014 for Conway Truckload after their acquisition of CFI in 2007.
Regulation
Electric Segment
General. As a public utility, our electric segment operations are subject to the jurisdiction of the
Missouri Public Service Commission (MPSC), the State Corporation Commission of the State of Kansas
(KCC), the Corporation Commission of Oklahoma (OCC) and the Arkansas Public Service Commission
(APSC) with respect to services and facilities, rates and charges, regulatory accounting, valuation of
14
property, depreciation and various other matters. Each such Commission has jurisdiction over the creation
of liens on property located in its state to secure bonds or other securities. The KCC also has jurisdiction
over the issuance of all securities because we are a regulated utility incorporated in Kansas. Our
transmission and sale at wholesale of electric energy in interstate commerce and our facilities are also
subject to the jurisdiction of the FERC, under the Federal Power Act. FERC jurisdiction extends to,
among other things, rates and charges in connection with such transmission and sale; the sale, lease or
other disposition of such facilities and accounting matters. See discussion in Item 7, ‘‘Management’s
Discussion and Analysis of Financial Condition and Results of Operations — Markets and Transmission.’’
Electric operating revenues received during 2015 were comprised of the following:
Retail customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales subject to FERC jurisdiction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPP market revenues (not allocated to the jurisdictions) . . . . . . . . . . . . . . . . .
Miscellaneous sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
91.5%
5.1
2.7
0.7
The percentage of retail regulated revenues derived from each state follows:
Missouri
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
89.0%
4.8
2.8
3.4
Rates. See Item 7, ‘‘Management’s Discussion and Analysis of Financial Condition and Results of
Operations — Rate Matters’’ for information concerning recent electric rate proceedings.
Fuel Adjustment Clauses. Typical fuel adjustment clauses permit the distribution to customers of
changes in fuel costs, subject to routine regulatory review, without the need for a general rate proceeding.
Fuel adjustment clauses are presently applicable to our retail electric sales in Missouri, Oklahoma and
Kansas and system wholesale kilowatt-hour sales under FERC jurisdiction. We have an Energy Cost
Recovery Rider in Arkansas that adjusts for changing fuel and purchased power costs on an annual basis.
Gas Segment
General. As a public utility, our gas segment operations are subject to the jurisdiction of the MPSC
with respect to services and facilities, rates and charges, regulatory accounting, valuation of property,
depreciation and various other matters. The MPSC also has jurisdiction over the creation of liens on
property to secure bonds or other securities.
Purchased Gas Adjustment (PGA). The PGA clause allows EDG to recover from our customers,
subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage costs,
including costs associated with our use of natural gas financial instruments to hedge the purchase price of
natural gas and related carrying costs. This PGA clause allows us to make rate changes periodically (up to
four times) throughout the year in response to weather conditions and supply demands, rather than in one
possibly extreme change per year.
Environmental Matters
See Note 11 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8 for information regarding
environmental matters.
15
Conditions Respecting Financing
Our EDE Indenture of Mortgage and Deed of Trust, dated as of September 1, 1944, as amended and
supplemented (the EDE Mortgage), and our Restated Articles of Incorporation (Restated Articles),
specify earnings coverage and other conditions which must be complied with in connection with the
issuance of additional first mortgage bonds or cumulative preferred stock, or the incurrence of unsecured
indebtedness. Substantially all of the property, plant and equipment of The Empire District Electric
Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE
mortgage bond indenture could affect our liquidity. The principal amount of all series of first mortgage
bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to
$1.0 billion. Based on the $1.0 billion limit, and our current level of outstanding first mortgage bonds, we
are limited to the issuance of $297.0 million of new first mortgage bonds. The EDE Mortgage contains a
requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE
Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two
times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then
outstanding and on the prospective issue of new first mortgage bonds. In addition to the interest coverage
requirement, the EDE Mortgage provides that new bonds must be issued against, among other things,
retired bonds or 60% of net property additions. The annual interest coverage requirement and retired
bonds or 60% of net property additions tests would permit the issuance of more than $297.0 million of new
first mortgage bonds; however, as discussed above, we are otherwise limited to the issuance of no more
than $297.0 million of new first mortgage bonds. As of December 31, 2015, we are in compliance with all
restrictive covenants of the EDE Mortgage.
Under our Restated Articles, (a) cumulative preferred stock may be issued only if our net income
available for interest and dividends (as defined in our Restated Articles) for a specified twelve-month
period is at least 11⁄2 times the sum of the annual interest requirements on all indebtedness and the annual
dividend requirements on all cumulative preferred stock to be outstanding immediately after the issuance
of such additional shares of cumulative preferred stock, and (b) so long as any preferred stock is
outstanding, the amount of unsecured indebtedness outstanding may not exceed 20% of the sum of the
outstanding secured indebtedness plus our capital and surplus. We have no outstanding preferred stock.
Accordingly, the restriction in our Restated Articles does not currently restrict the amount of unsecured
indebtedness that we may have outstanding.
The principal amount of all series of first mortgage bonds outstanding at any one time under the
Indenture of Mortgage and Deed of Trust of The Empire District Gas Company, dated as of June 1, 2006,
as amended and supplemented (the EDG Mortgage) is limited by terms of the mortgage to $300.0 million.
Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to
the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage
bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of
property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a
limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt
incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance,
EDG’s ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain
other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1.0. As
of December 31, 2015, this test would allow us to issue approximately $19.5 million principal amount of
new first mortgage bonds at an assumed interest rate of 5.5%. As of December 31, 2015, we are in
compliance with all restrictive covenants of the EDG Mortgage.
See Item 7, ‘‘Management’s Discussion and Analysis of Financial Condition and Results of
Operations — Liquidity and Capital Resources.’’
16
Our Web Site
We maintain a web site at www.empiredistrict.com. Our annual report on Form 10-K, quarterly
reports on Form 10-Q, current reports on form 8-K and related amendments are available free of charge
through our web site as soon as reasonably practicable after such reports are filed with or furnished to the
SEC electronically. Our Corporate Governance Guidelines, our Code of Business Conduct and Ethics, our
Code of Ethics for the Chief Executive Officer and Senior Financial Officers, the charters for our Audit
Committee, Compensation Committee and Nominating/Corporate Governance Committee, our
Procedures for Reporting Complaints on Accounting, Internal Accounting Controls and Auditing Matters,
our Procedures for Communicating with Non-Management Directors and our Policy and Procedures with
Respect to Related Person Transactions can also be found on our web site. All of these documents are
available in print to any interested party who requests them. Our web site and the information contained in
it and connected to it shall not be deemed incorporated by reference into this Form 10-K.
ITEM 1A. RISK FACTORS
Investors should review carefully the following risk factors and the other information contained in this
Form 10-K. The risks we face are not limited to those in this section. There may be additional risks and
uncertainties (either currently unknown or not currently believed to be material) that could adversely
affect our financial position, results of operations and liquidity.
Readers are cautioned that the risks and uncertainties described in this Form 10-K are not the only
ones facing Empire. Additional risks and uncertainties that we are not presently aware of, or that we
currently consider immaterial, may also affect our business operations. Our business, financial condition or
results of operations (including our ability to pay dividends on our common stock) could suffer if the
concerns set forth below are realized.
We are exposed to reductions in revenue and increases in costs which we cannot control and which
may adversely affect our business, financial condition and results of operations.
The primary drivers of our electric operating margin (defined as electric revenues less fuel and
purchased power costs) in any period are: (1) rates we can charge our customers, including timing of new
rates, (2) weather, (3) customer growth and usage and (4) general economic conditions. Of the factors
driving margin, weather has the greatest short-term effect on the demand for electricity for our regulated
business. Mild weather reduces demand and, as a result, our electric operating revenues. In addition,
changes in customer demand due to downturns in the economy, energy efficiency or increased use of
self-generation and distributed energy technologies could reduce our revenues.
The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power
expenses, (2) operating, maintenance and repairs expense, including repairs following severe weather and
plant outages, (3) taxes and (4) non-cash items such as depreciation and amortization expense. Although
we generally recover these expenses through our rates, there can be no assurance that we will recover all,
or any part of, such increased costs in future rate cases.
The primary drivers of our gas operating revenues in any period are: (1) rates we can charge our
customers, (2) weather, (3) customer growth, (4) the cost of natural gas and interstate pipeline
transportation charges and (5) general economic conditions. Because natural gas is heavily used for
residential and commercial heating, the demand for this product depends heavily upon weather patterns
throughout our natural gas service territory and a significant amount of our natural gas revenues are
recognized in the first and fourth quarters related to the heating seasons. Accordingly, our natural gas
operations have historically generated less revenues and income when weather conditions are warmer in
the winter.
The primary driver of our gas operating expense in any period is the price of natural gas.
17
Significant increases in electric and gas operating expenses or reductions in electric and gas operating
revenues may occur and result in a material adverse effect on our business, financial condition and results
of operations.
Energy conservation, energy efficiency, distributed generation and other factors that reduce energy
demand could adversely affect our business, financial condition and results of operations.
Regulatory and legislative bodies have proposed or introduced requirements and incentives to reduce
energy consumption. Conservation and energy efficiency programs are designed to reduce energy demand.
Unless there is a regulatory solution ensuring recovery, declining usage will result in an under-recovery of
our fixed costs. Macroeconomic factors resulting in low economic growth or contraction within our service
territories could also reduce energy demand. Any such reductions in energy demand could adversely affect
our business, financial condition and results of operations
In addition, significant technological advancements are taking place in the electric industry, including
advancements related to self-generation and distributed energy technologies such as fuel cells, micro
turbines, wind turbines and solar cells. Adoption of these technologies may increase because of
advancements or government subsidies reducing the cost of generating electricity through these
technologies to a level that is competitive with our current methods of generating electricity. There is also
a perception that generating electricity through these technologies is more environmentally friendly than
generating electricity with fossil fuels. Increased adoption of these technologies would reduce demand for
our electricity but would not necessarily reduce our investment and operating requirements due to our
obligation to serve customers, including those self-generation customers whose equipment has failed for
any reason to provide the power they need. In addition, self-generating customers do not currently pay a
share of the costs necessary to operate our transmission and distribution system. As a result, the pool of
customers from whom fixed costs are recovered would be reduced, potentially resulting in under-recovery
of our fixed costs and upward price pressure on our remaining customers. If we were unable to adjust our
prices to reflect such reduced electricity demand and any related use of net energy metering (which allows
self-generating customers to receive bill credits for surplus power), our business, financial condition and
results of operations could be adversely affected. In addition, since a portion of our costs are recovered
through charges based upon the volume of power delivered, reductions in electricity deliveries will affect
the timing of our recovery of those costs and may require changes to our rate structures.
We are subject to environmental laws and the incurrence of environmental liabilities which may
adversely affect our business, financial condition and results of operations.
We are subject to extensive federal, state and local regulation with regard to air and other
environmental matters. Failure to comply with these laws and regulations could have a material adverse
effect on our results of operations and financial position. In addition, new environmental laws and
regulations, and new interpretations of existing environmental laws and regulations, have been adopted
and may in the future be adopted which may substantially increase our future environmental expenditures
for both new facilities and our existing facilities. Compliance with current and potential future air emission
standards (such as those limiting emission levels of sulfur dioxide (SO2), emissions of mercury, other
hazardous pollutants (HAPS), nitrogen oxide (NOx), and carbon dioxide (CO2)) has required, and may in
the future require, significant environmental expenditures. Although we have historically recovered such
costs through our rates, there can be no assurance that we will recover all, or any part of, such increased
costs in future rate cases. The incurrence of additional material environmental costs which are not
recovered in our rates may result in a material adverse effect on our business, financial condition and
results of operations.
18
We are exposed to factors that can increase our fuel and purchased power expenditures, including
disruption in deliveries of coal or natural gas, decreased output from our power plants, failure of
performance by purchased power counterparties and market risk in our fuel procurement strategy.
Fuel and purchased power costs are our largest expenditures. Increases in the price of coal, natural
gas or the cost of purchased power will result in increased electric operating expenditures. Given we have a
fuel cost recovery mechanism in all of our jurisdictions, our net income exposure to the impact of the risks
discussed above is significantly reduced. However, cash flow could still be impacted by these increased
expenditures. We are also subject to prudency reviews which could negatively impact our net income if a
regulatory commission would conclude our costs were incurred imprudently.
We depend upon regular deliveries of coal as fuel for our Asbury, Iatan and Plum Point plants.
Substantially all of this coal comes from mines in the Powder River Basin of Wyoming and is delivered to
the plants by train. Production problems in these mines, railroad transportation or congestion problems, or
unavailability of trains could affect delivery cycle times required to maintain plant inventory levels, causing
us to implement coal conservation and supply replacement measures to retain adequate reserve inventories
at our facilities. These measures could include some or all of the following: reducing the output of our coal
plants, increasing the utilization of our gas-fired generation facilities, purchasing power from other
suppliers, adding additional leased trains to our supply system and purchasing locally mined coal which can
be delivered without using the railroads. Such measures could result in increased fuel and purchased power
expenditures.
Natural gas is delivered to our generation fleet at Riverton, State Line, and Energy Center via
Southern Star Central Gas Pipeline. Although we have firm transportation contracts in place for a limited
volume of daily natural gas deliveries, the actual delivery of natural gas can still be uncertain during winter
peaking weather. The inability to procure commodity or pipeline commitments for non-firm delivery
causes us to either rely on fuel oil as a back-up fuel for generation at State Line unit 1 or Energy Center
units, and/or limit the generation offered into the SPP IM from State Line Combined Cycle and Riverton.
As a result, we could incur higher fuel and purchased power costs than if the units were available for full
commitment and dispatch.
We have also established a risk management practice of purchasing contracts for future fuel needs to
meet underlying customer needs and manage cost and pricing uncertainty. Within this activity, we may
incur losses from these contracts. By using physical and financial instruments, we are exposed to credit risk
and market risk. Market risk is the exposure to a change in the value of commodities caused by fluctuations
in market variables, such as price. The fair value of derivative financial instruments we hold is adjusted
cumulatively on a monthly basis until prescribed determination periods. At the end of each determination
period, which is the last day of each calendar month in the period, any realized gain or loss for that period
related to the contract will be reclassified to fuel expense and recovered or refunded to the customer
through our fuel adjustment mechanisms. Credit risk is the risk that the counterparty might fail to fulfill its
obligations under contractual terms.
We are subject to regulation in the jurisdictions in which we operate, including the rates that we can
charge customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, which
significantly influences our operating environment and our ability to recover our costs from utility
customers. The utility commissions in the states where we operate regulate many aspects of our utility
operations, including the rates that we can charge customers, siting and construction of facilities, pipeline
safety and compliance, customer service and our ability to recover costs we incur, including capital
expenditures and fuel and purchased power costs.
19
The FERC has jurisdiction over wholesale rates for electric transmission service and electric energy
sold in interstate commerce. Federal, state and local agencies also have jurisdiction over many of our other
activities.
Information concerning recent filings requesting increases in rates and related matters is set forth
‘‘Management’s Discussion and Analysis of Financial Condition and Results of
under Item 7,
Operations — Rate Matters.’’
We are also subject to prudency and similar reviews by regulators of costs we incur, including capital
expenditures, fuel and purchased power costs and other operating costs.
We are unable to predict the impact on our operating results from the regulatory activities of any of
these agencies, including any regulatory disallowances that could result from prudency reviews. Despite
our requests, these regulatory commissions have sole discretion to leave rates unchanged, grant increases
or order decreases in the base rates we charge our utility customers. They have similar authority with
respect to our recovery of increases in our fuel and purchased power costs. Rate proceedings through
which our prices and terms of service are determined typically involve numerous parties including
customers, consumer advocates and governmental entities, some of whom take positions adverse to us. In
addition, regulators’ decisions may be appealed to the courts by us or other parties to the proceedings.
These factors may lead to uncertainty and delays in implementing changes to our prices or terms of service.
If our costs increase and we are unable to recover increased costs through base rates or fuel adjustment
clauses, or if we are unable to fully recover our investments in new facilities, our results of operations could
be materially adversely affected. Changes in regulations or the imposition of additional regulations could
also have a material adverse effect on our results of operations.
In addition, although the current rate making process provides recovery of some future changes in
rate base and operating costs, it does not reflect all changes in costs for the period in which new retail rates
will be in place. This results in a lag (commonly referred to as ‘‘regulatory lag’’) between the time we incur
costs and the time when we can start recovering the costs through rates. This may result in under-recovery
of costs, failure to earn the authorized return on investment, or both.
Operations risks may adversely affect our business and financial results.
The operation of our electric generation, and electric and gas transmission and distribution systems
involves many risks, including breakdown or failure of expensive and sophisticated equipment, processes
and personnel performance; inability to attract and retain management and other key personnel;
workplace and public safety; operating limitations that may be imposed by workforce issues, equipment
conditions, environmental or other regulatory requirements; fuel supply or fuel transportation reductions
or interruptions; transmission scheduling constraints; unauthorized physical access to our facilities; and
catastrophic events such as fires, explosions, severe weather (including tornadoes and ice storms), acts of
terrorism or other similar occurrences.
We have implemented training and preventive maintenance programs and have security systems and
related protective infrastructure in place, but there is no assurance that these programs will prevent or
minimize future breakdowns, outages or failures of our generation facilities or related business processes.
In those cases, we would need to either produce replacement power from our other facilities or purchase
power from other suppliers at potentially volatile and higher cost in order to meet our sales obligations, or
implement emergency back-up business system processing procedures. In addition, certain catastrophic
events can inflict extensive damage to our equipment and facilities which can require us to incur additional
operating and maintenance expense and additional capital expenditures. Our prices may not always be
adjusted timely and adequately to reflect these higher costs.
These and other operating events and conditions may reduce our revenues, increase costs, or both,
and may materially affect our results of operations, financial position and cash flows.
20
The regional power market in which we operate has changing market and transmission structures,
which could have an adverse effect on our results of operations, financial position and cash flows.
The SPP RTO is mandated by the FERC to ensure a reliable power supply, an adequate transmission
infrastructure and competitive wholesale electricity prices. The SPP RTO functions as reliability
coordinator, tariff administrator and regional scheduler for its member utilities, including us. Essentially,
the SPP RTO independently operates our transmission system as it interfaces and coordinates with the
regional power grid. SPP RTO activities directly impact our control of owned generating assets and the
development and cost of transmission infrastructure projects within the SPP RTO region. The cost
allocation methodology applied to these transmission infrastructure projects will increase our operating
expenses.
The SPP RTO implemented a Day-Ahead Market, or IM, in March 2014. The SPP IM functions as a
centralized dispatch, where we and other members submit offers to sell power and bids to purchase power.
The SPP matches offers and bids based upon operating and reliability considerations. The SPP reports that
approximately 90% – 95% of all next day generation needed throughout the SPP territory is being cleared
through the IM. This change could impact our fuel costs, however, the net financial effect of these IM
transactions will be processed through our fuel adjustment mechanisms.
Information concerning recent and pending SPP RTO and other FERC activities can be found under
Note 3 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8.
Security breaches, criminal activity, terrorist attacks and other disruptions to our information
technology infrastructure could directly or indirectly interfere with our operations, could expose us
or our customers or employees to a risk of loss, and could expose us to liability, regulatory penalties,
reputational damage and other harm to our business.
We rely upon information technology networks and systems to process, transmit and store electronic
information, and to manage or support a variety of business processes and activities, including the
generation, transmission and distribution of electricity, supply chain functions, and the invoicing and
collection of payments from our customers. We also use information technology systems to record, process
and summarize financial information and results of operations for internal reporting purposes and to
comply with financial reporting, legal and tax requirements. Our technology networks and systems collect
and store sensitive data including system operating information, proprietary business information
belonging to us and third parties, and personal information belonging to our customers and employees.
Our information technology networks and infrastructure may be vulnerable to damage, disruptions or
shutdowns due to attacks by hackers or breaches due to employee error or malfeasance, or other
disruptions during software or hardware upgrades, telecommunication failures or natural disasters or other
catastrophic events. The occurrence of any of these events could impact the reliability of our generation,
transmission and distribution systems; could expose us, our customers or our employees to a risk of loss or
misuse of information; and could result in legal claims or proceedings, liability or regulatory penalties
against us, damage our reputation or otherwise harm our business. We cannot accurately assess the
probability that a security breach may occur, despite the measures that we take to prevent such a breach,
and we are unable to quantify the potential impact of such an event. We can provide no assurance that we
will identify and remedy all security or system vulnerabilities or that unauthorized access or error will be
identified and remedied.
Additionally, we cannot predict the impact that any future information technology or terrorist attack
may have on the energy industry in general. Our wholly and jointly owned facilities, and those of the SPP
and other SPP member companies, could be direct targets or indirect casualties of such attacks. The effects
of such attacks could include disruption to our generation, transmission and distribution systems or to the
electrical grid in general, and could increase the cost of insurance coverage or result in a decline in the
U.S. economy.
21
We may be unable to recover increases in the cost of natural gas from our natural gas utility
customers, or may lose customers as a result of any price increases.
In our natural gas utility business, we are permitted to recover the cost of gas directly from our
customers through the use of a purchased gas adjustment provision. Our purchased gas adjustment
provision is regularly reviewed by the MPSC. In addition to reviewing our adjustments to customer rates,
the MPSC reviews our costs for prudency as well. To the extent the MPSC may determine certain costs
were not incurred prudently, it could adversely affect our gas segment earnings and cash flows. In addition,
increases in natural gas costs affect total prices to our customers and, therefore, the competitive position of
gas relative to electricity and other forms of energy. Increases in natural gas costs may also result in lower
usage by customers unable to switch to alternate fuels. Such disallowed costs or customer losses could have
a material adverse effect on our business, financial condition and results of operations.
Any reduction in our credit ratings could materially and adversely affect our business, financial
condition and results of operations.
Currently, our corporate credit ratings and the ratings for our securities are as follows:
Moody’s
Standard & Poor’s
Corporate Credit Rating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EDE First Mortgage Bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial Paper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Baa1
A2
Baa1
P-2
Stable
BBB
A-
BBB
A-2
Negative
The ratings indicate the agencies’ assessment of our ability to pay the interest and principal of these
securities. A rating is not a recommendation to purchase, sell or hold securities and each rating should be
evaluated independently of any other rating. The lower the rating, the higher the interest cost of the
securities when they are sold. In addition, a downgrade in our senior unsecured long-term debt rating
would result in an increase in our borrowing costs under our commercial paper program or bank credit
facility. If any of our ratings fall below investment grade (investment grade is defined as Baa3 or above for
Moody’s and BBB- or above for Standard & Poor’s), our ability to issue short-term debt, commercial paper
or other securities or to market those securities would be impaired or made more difficult or expensive.
Therefore, any such downgrades could have a material adverse effect on our business, financial condition
and results of operations. To the extent we are unable to issue commercial paper, we will need to meet our
short-term debt needs through borrowings under our revolving credit facilities, which may result in higher
costs.
We cannot assure you that any of our current ratings will remain in effect for any given period of time
or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment,
circumstances in the future so warrant.
The cost and schedule of construction projects may materially change.
Our capital expenditure budget for the next three years is estimated to be $380.8 million. This includes
expenditures for environmental upgrades to our existing facilities and additions to our transmission and
distribution systems. There are risks that actual costs may exceed budget estimates, delays may occur in
obtaining permits and materials, suppliers and contractors may not perform as required under their
contracts, there may be inadequate availability, productivity or increased cost of qualified craft labor,
start-up activities may take longer than planned, the scope and timing of projects may change, and other
events beyond our control may occur that may materially affect the schedule, budget, cost and
performance of projects. To the extent the completion of projects is delayed, we expect that the timing of
receipt of increases in base rates reflecting our investment in such projects will be correspondingly delayed.
22
Costs associated with these projects will also be subject to prudency review by regulators as part of future
rate case filings and all costs may not be allowed recovery.
Financial market disruptions may increase financing costs, limit access to the credit markets or cause
reductions in investment values in our pension plan assets.
We estimate our capital expenditures to be $115.1 million in 2016. Although we believe it is unlikely
we will have difficulty accessing the markets for the capital needed to complete these projects (if such a
need arises), financing costs could fluctuate. Financial market disruptions and volatility in discount rates
could lead to increased funding obligations due to reduced asset values and increased benefit obligations.
During 2015, our net pension and OPEB liability decreased $12.4 million. Our funding policy is to
contribute annually an amount at least equal to the actuarial cost of postretirement benefits. The actual
minimum pension funding requirements will be determined based on the results of the actuarial valuations
and the performance of our pension assets during the current year. Future market changes could result in
increased pension and OPEB liabilities and funding obligations.
Failure to attract and retain an appropriately qualified workforce could adversely affect our business,
financial condition and results of operations.
Certain events, such as an aging workforce, mismatch of skill set or complement to future needs, or
unavailability of contract resources may lead to operating challenges and increased costs. The challenges
include lack of resources, loss of knowledge base and the lengthy time required for skill development. In
this case, costs, including costs for contractors to replace employees, productivity costs and safety costs,
may rise. Failure to hire and adequately train replacement employees, including the transfer of significant
internal historical knowledge and expertise to new employees, or future availability and cost of contract
labor may adversely affect the ability to manage and operate the business. If we are unable to successfully
attract and retain an appropriately qualified workforce, our business, financial condition and results of
operations could be adversely affected.
We are subject to adverse publicity and reputational risks, which makes us vulnerable to negative
customer perception and increased regulatory oversight or other sanctions.
Like other utility companies, we have a large consumer customer base and, as a result, are subject to
public criticism focused on the reliability of our distribution services and the speed with which we are able
to respond to outages caused by storm damage or other unanticipated events. Adverse publicity of this
nature may render legislatures, public utility commissions and other regulatory authorities and government
officials, less likely to view public utility companies in a favorable light, and may cause us to be susceptible
to less favorable legislative and regulatory outcomes or increased regulatory oversight. Unfavorable
regulatory outcomes can include more stringent laws and regulations governing our operations, such as
reliability and customer service quality standards or vegetation management requirements, as well as fines,
penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material
adverse effect on our business, financial condition and results of operations.
Empire and its subsidiaries will be subject to business uncertainties and contractual restrictions while
the Merger is pending that could adversely affect our financial results.
Uncertainty about the effect of the Merger on employees or vendors and others may have an adverse
effect on us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties
may impair Empire and its subsidiaries’ ability to attract, retain and motivate key personnel until the
Merger is completed, and could cause vendors and others that deal with us to seek to change existing
business relationships. Employee retention and recruitment may be particularly challenging prior to the
completion of the Merger, as current employees and prospective employees may experience uncertainty
about their future roles with the combined company. If, despite our retention and recruiting efforts, key
23
employees depart or fail to accept employment with Empire or its subsidiaries due to the uncertainty and
difficulty of integration or a desire not to remain with the combined company, our business operations and
financial results could be adversely affected.
We expect that matters relating to the Merger, including cooperation with APUC’s financing and
integration-related issues will place a significant burden on management, employees and internal
resources, which could otherwise have been devoted to other business opportunities. The diversion of
management time on Merger-related issues could materially affect our financial results.
In addition, the Merger Agreement restricts Empire and its subsidiaries, without Liberty’s prior
written consent, from taking specified actions until the Merger occurs or the Merger Agreement is
terminated, including, without limitation: (i) making certain material acquisitions and dispositions of assets
or businesses; (ii) making any capital expenditures in excess of specified amounts; (iii) incurring
indebtedness, subject to certain exceptions; (iv) issuing equity or equity equivalents; and (v) paying
quarterly cash dividends in excess of current levels. These restrictions may prevent us from pursuing
otherwise attractive business opportunities and making other changes to our business prior to
consummation of the Merger or termination of the Merger Agreement.
Failure to complete the Merger could negatively impact Empire and/or the market price of our
common stock.
There can be no assurance that the Merger will occur. Failure to complete the Merger may negatively
impact the future trading price of our common stock. If the Merger is not completed, the market price of
our common stock may decline to the extent that the current market price of our common stock reflects a
market assumption that there is a high probability that the Merger will be completed. Additionally, if the
Merger is not completed, we will have incurred significant costs, as well as the diversion of the time and
attention of management. A failure to complete the Merger may also result in negative publicity, litigation
against Empire or our directors and officers, and a negative impression of us in the investment community.
The occurrence of any of these events individually or in combination could have a material adverse effect
on our financial condition, results of operations and our stock price.
Empire and Liberty may be unable to obtain the required shareholder, governmental, regulatory, and
other consents and approvals required to complete the Merger or, in order to receive such consents
or approvals, the governmental or regulatory entities may impose restrictions or conditions that
could cause a termination of the Merger Agreement.
The closing of the Merger is subject to certain conditions, including, among others, (i) approval of
Empire shareholders representing a majority of the outstanding shares of Empire common stock,
(ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period and receipt of all
required regulatory approvals and consents, including from the Federal Energy Regulatory Commission,
the Federal Communications Commission, the Arkansas Public Service Commission, the Kansas
Corporation Commission, the Missouri Public Service Commission, the Oklahoma Corporation
Commission and the Committee on Foreign Investment in the United States, which approvals and
consents shall not, individually or in the aggregate, have or be reasonably likely to have a material adverse
effect on the business, properties, financial condition or results of operations of Liberty Utilities Co. and
its subsidiaries (including for such purpose, Empire and its subsidiaries), taken as a whole, (iii) the absence
of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (iv) the absence
of any material adverse effect with respect to Empire and (v) subject to certain exceptions, the accuracy of
the representations and warranties of, and compliance with covenants by, each of the parties to the Merger
Agreement. The shareholder, governmental, regulatory, and other consents and approvals required to
consummate the Merger may not be obtained at all, or may not be obtained on the proposed terms and
schedules as contemplated by the parties. A substantial delay in obtaining the required shareholder,
governmental, regulatory, and other consents and approvals or the imposition of unfavorable terms,
24
conditions or restrictions contained in such approvals or consents could prevent or delay the completion of
the Merger. Additionally, if certain closing conditions are not satisfied prior to the outside date specified in
the Merger Agreement, either Empire or Liberty could be permitted to terminate the Merger Agreement
and not consummate the Merger.
In the event that the Merger Agreement is terminated prior to the completion of the Merger, we could
incur significant transaction costs that could materially impact our financial performance and
results of operations.
In connection with entering into the Merger Agreement, Empire has incurred approximately
$0.2 million of transaction costs as of December 31, 2015. We expect that the total transaction costs will be
approximately $15 to $17 million, with approximately 50% payable in 2016 (assuming a 2017 closing date),
of which approximately $4.5 million will be incurred in the first quarter of 2016. The Merger Agreement
provides that upon termination of the Merger Agreement under certain specified circumstances, we will be
required to pay Liberty a termination fee of $53.0 million. Any fees due as a result of termination could
have a material adverse effect on our results of operations, financial condition, and our stock price.
Potential future litigation against Empire and our directors challenging the Merger may prevent the
Merger from being completed within the anticipated timeframe.
Empire and/or our directors may potentially be named as defendants in lawsuits filed on behalf of
public shareholders challenging the Merger and potentially seeking, among other things, to enjoin the
defendants from consummating the Merger on the agreed-upon terms. We will incur significant transaction
costs, including legal, filing, printing, and other costs relating to any litigation. If a plaintiff in a potential
lawsuit or any other litigation that may be filed is successful in obtaining an injunction prohibiting the
parties from completing the Merger on the terms contemplated by the Merger Agreement, the injunction
will cause us to incur significant expense and may prevent the completion of the Merger in the expected
timeframe or altogether.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
Electric Segment Facilities
Our generating facilities consist of three coal-fired generating plants, four natural gas generating
plants and one hydroelectric generating plant. At December 31, 2015, we owned generating facilities with
an aggregate generating capacity of 1,280 megawatts, reflecting the retirement of Riverton Unit 7 on
June 30, 2014 and the retirement of Riverton Unit 8 and Unit 9 on June 30, 2015, but not including the
combined cycle portion of Riverton Unit 12, which was not yet in operation as of December 31, 2015.
The Asbury Plant, located near Asbury, Missouri, is a coal-fired generating station with a current
generating capacity of 198 megawatts. In 2015, the plant accounted for approximately 15.5% of our owned
generating capacity and accounted for approximately 28.1% of the energy generated by us. As part of our
environmental Compliance Plan, discussed in Note 11 of ‘‘Notes to Consolidated Financial Statements’’
under Item 8, we installed a scrubber, fabric filter and powder activated carbon injection system at our
Asbury plant in 2014. The addition of this air quality control system (AQCS) equipment was completed in
December 2014. Routine plant maintenance, during which the entire plant is taken out of service, is
scheduled annually, normally for approximately three to four weeks in the spring. Approximately every
fifth year, the maintenance outage is scheduled to be extended to approximately six weeks to permit
inspection of the Unit No. 1 turbine. When the Asbury Plant is out of service, we typically experience
25
increased purchased power and fuel expenditures associated with replacement energy, which is likely to be
recovered through our fuel adjustment clauses.
We own a 12% undivided interest in the coal-fired Unit No. 1 and Unit No. 2 at the Iatan Generating
Station located near Weston, Missouri, 35 miles northwest of Kansas City, Missouri, as well as a 3%
interest in the site and a 12% interest in certain common facilities. We are entitled to 12% of the units’
available capacity, currently 85 megawatts for Unit No. 1 and 106 megawatts for Unit No. 2, and are
obligated to pay for that percentage of the operating costs of the units. KCP&L operates the units for the
joint owners.
We own a 7.52% undivided interest in the coal-fired Plum Point Energy Station located near Osceola,
Arkansas. We are entitled to 50 megawatts, or 7.52% of the unit’s available capacity.
Our generating plant located at Riverton, Kansas, has three gas-fired combustion turbine units (Units
10, 11 and 12) with an aggregate generating capacity of 177 megawatts. As part of our environmental
Compliance Plan, discussed in Note 11 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8, we
are currently completing the conversion of Riverton Unit 12 from a simple cycle combustion turbine to a
combined cycle unit. The tie-in outage for the Riverton Unit 12 Combined Cycle Project was completed in
October 2015 and mechanical completion was achieved on December 15, 2015. Start-up and
commissioning of the unit is currently in progress with contractual substantial completion expected by
June 1, 2016. Riverton Unit 7 was permanently removed from service on June 30, 2014, and Unit 8 and
Unit 9 were retired on June 30, 2015.
Our State Line Power Plant, which is located west of Joplin, Missouri, consists of Unit No. 1, a
combustion turbine unit with generating capacity of 96 megawatts and a Combined Cycle Unit with
generating capacity of 495 megawatts of which we are entitled to 60%, or 295 megawatts. The Combined
Cycle Unit consists of the combination of two combustion turbines, two heat recovery steam generators, a
steam turbine and auxiliary equipment. The Combined Cycle Unit is jointly owned with Westar
Generating Inc., a subsidiary of Westar Energy, Inc., which owns the remaining 40% of the unit. We are
the operator of the Combined Cycle Unit and Westar reimburses us for a percentage of the operating costs
per our joint ownership agreement. All units at our State Line Power Plant burn natural gas as a primary
fuel with Unit No. 1 having the additional capability of burning oil.
We have four combustion turbine peaking units at the Empire Energy Center in Jasper County,
Missouri, with an aggregate generating capacity of 257 megawatts. These peaking units operate on natural
gas, as well as oil.
Our hydroelectric generating plant (FERC Project No. 2221), located on the White River at Ozark
Beach, Missouri, has a generating capacity of 16 megawatts. We have a thirty -year license, effective
March 1, 1992, from the FERC to operate this plant which forms Lake Taneycomo in southwestern
Missouri. We are about to start the renewal process on this license, which expires in 2022.
At December 31, 2015, our transmission system consisted of approximately 22 miles of 345 kV lines,
405 miles of 161 kV lines, 745 miles of 69 kV lines and 82 miles of 34.5 kV lines. Our distribution system
consisted of approximately 6,932 miles of line at December 31, 2015 and 6,911 miles as of December 31,
2014.
Our electric generation stations, other than Plum Point Energy Station, are located on land owned in
fee. We own a 3% undivided interest as tenant in common in the land for the Iatan Generating Station. We
own a similar interest in 60% of the land used for the State Line Combined Cycle Unit. Substantially all of
our electric transmission and distribution facilities are located either (1) on property leased or owned in
fee; (2) over streets, alleys, highways and other public places, under franchises or other rights; or (3) over
private property by virtue of easements obtained from the record holders of title. Substantially all of our
electric segment property, plant and equipment are subject to the EDE Mortgage.
26
We also own and operate water pumping facilities and distribution systems consisting of a total of
approximately 96 miles of water mains in three communities in Missouri.
Gas Segment Facilities
At December 31, 2015, our principal gas utility properties consisted of approximately 87 miles of
transmission mains and approximately 1,189 miles of distribution mains.
Substantially all of our gas transmission and distribution facilities are located either (1) on property
leased or owned in fee; (2) under streets, alleys, highways and other public places, under franchises or
other rights; or (3) under private property by virtue of easements obtained from the record holders of title.
Substantially all of our gas segment property, plant and equipment are subject to the EDG Mortgage.
Other Segment
Our other segment consists of our leasing of fiber optics cable and equipment (which we also use in
our own utility operations).
ITEM 3. LEGAL PROCEEDINGS
See Note 11 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8, which description is
incorporated herein by reference.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
27
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed on the New York Stock Exchange (ticker symbol: EDE). On February 1,
2016, there were 4,048 record holders and 26,258 individual participants in security position listings. The
following table presents the high and low sales prices (and quarter end closing sales prices) for our
common stock as reported by the New York Stock Exchange for composite transactions, and the amount
per share of quarterly dividends declared and paid on the common stock for each quarter during 2015 and
2014.
High
Low
Close
Dividends Paid
Per Share
2015 Quarter Ended:
March 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 Quarter Ended:
March 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$31.49
25.41
23.99
29.41
$24.50
25.70
26.00
31.20
$23.67
21.56
20.69
21.40
$22.04
23.23
24.00
24.09
$24.82
21.80
22.03
28.07
$24.32
25.68
24.15
29.74
$0.260
0.260
0.260
0.260
$0.255
0.255
0.255
0.260
Holders of our common stock are entitled to dividends, if, as, and when declared by the Board of
Directors, out of funds legally available therefore subject to the prior rights of holders of any outstanding
cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of
Directors after considering all relevant factors, including the amount of our retained earnings (which is
essentially our accumulated net income less dividend payouts).
In the first quarter of 2016, the Board of Directors declared a quarterly dividend of $0.26 per share on
common stock payable on March 15, 2016 to holders of record as of March 1, 2016. As of December 31,
2015, our retained earnings balance was $101.4 million, compared to $90.3 million at December 31, 2014.
A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common
stock price.
See Item 7, ‘‘Management’s Discussion and Analysis of Financial Condition and Results of
Operation — Dividends’’ for information on limitations on our ability to pay dividends on our common
stock.
During 2015, no purchases of our common stock were made by us or on our behalf.
Participants in our Dividend Reinvestment and Direct Stock Purchase Plan may acquire newly issued
common shares with reinvested dividends. Participants may also purchase, at an averaged market price,
newly issued common shares with optional cash payments, subject to certain restrictions. We also offer
participants the option of safekeeping for their stock certificates.
Our By-laws provide that K.S.A. Sections 17-1286 through 17-1298, the Kansas Control Share
Acquisitions Act, will not apply to control share acquisitions of our capital stock.
See Note 8 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8 for additional information
regarding our common stock and equity compensation plans.
28
The following graph and table indicates the value at the end of the specified years of a $100
investment made on December 31, 2010, in our common stock and similar investments made in the
securities of the companies in the Standard & Poor’s 500 Composite Index (S&P 500 Index) and the
Standard & Poor’s Electric Utilities Index (S&P Electric Utility). The graph and table assume that
dividends were reinvested when received.
Total Return Performance
Empire District Electric Company
S&P Electric Utilities Index
S&P 500
190
175
160
145
130
115
100
e
u
l
a
V
x
e
d
n
I
85
12/31/10
12/31/11
12/31/12
12/31/13
12/31/14
12/31/15
20FEB201622433203
Total Return Analysis
12/31/2010 12/31/2011 12/31/2012 12/31/2013 12/31/2014 12/31/2015
The Empire District Electric Company . . . . . $100.00 $ 98.06 $ 99.50 $115.97 $158.30 $156.20
S&P Electric Utilities Index . . . . . . . . . . . . . $100.00 $120.97 $120.30 $129.68 $170.15 $160.95
S&P 500 Index . . . . . . . . . . . . . . . . . . . . . . . $100.00 $102.11 $118.45 $156.82 $178.28 $180.75
29
ITEM 6. SELECTED FINANCIAL DATA
(in thousands, except per share amounts)
2015
2014
2013
2012
2011
Operating revenues(1) . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . .
Total allowance for funds used during
$ 605,573
96,301
$
$ 652,330
99,999
$
$ 594,330
99,663
$
$ 557,097
96,221
$
$ 576,870
96,934
$
construction . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . .
$
$
7,695
56,597
$
$
9,917
67,103
$
$
5,940
63,445
$
$
1,928
55,681
$
$
512
54,971
Weighted average number of common
shares outstanding — basic . . . . . . .
Weighted average number of common
shares outstanding — diluted . . . . .
Total earnings per weighted average
share of common stock — basic . . .
Total earnings per weighted average
share of common stock — diluted . .
Cash dividends per share . . . . . . . . . .
Common dividends paid as a
43,671
43,291
42,781
42,257
41,852
43,718
43,314
42,803
42,284
41,887
$
$
$
1.30
1.29
1.04
$
$
$
1.55
1.55
1.025
$
$
$
1.48
1.48
1.005
$
$
$
1.32
1.32
1.00
$
$
$
1.31
1.31
0.64
percentage of net income . . . . . . . .
80.3%
66.1%
67.8%
75.9%
48.6%
Allowance for funds used during
construction as a percentage of net
income . . . . . . . . . . . . . . . . . . . . .
Book value per common share (actual)
outstanding at end of year . . . . . . .
Capitalization:
Common equity . . . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . .
Ratio of earnings to fixed charges . . . .
Total assets . . . . . . . . . . . . . . . . . . . .
Plant in service at original cost . . . . . .
Capital expenditures (including
13.6%
14.8%
9.4%
3.5%
0.9%
$
18.32
$
18.02
$
17.43
$
16.90
$
16.53
$ 802,730
$ 837,947
2.65X
$2,455,303
$2,601,592
$ 783,298
$ 803,189
3.02X
$2,371,056
$2,541,582
$ 750,123
$ 743,428
2.97X
$2,145,045
$2,332,341
$ 717,798
$ 691,626
2.89X
$2,126,369
$2,284,022
$ 693,989
$ 692,259
2.87X
$2,021,835
$2,176,650
AFUDC) . . . . . . . . . . . . . . . . . . . .
$ 176,525
$ 222,852
$ 160,196
$ 146,287
$ 101,177
(1) Includes SPP IM net revenues of $15.0 million and $41.9 million in 2015 and 2014, respectively.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
Electric Segment
As a vertically integrated regulated utility, the primary drivers of our electric operating margin
(defined as electric revenues less fuel and purchased power costs) in any period are: (1) rates we can
charge our customers, including timing of new rates, (2) weather, (3) customer growth and usage and
(4) general economic conditions. The utility commissions in the states in which we operate, as well as the
Federal Energy Regulatory Commission (FERC), set the rates which we can charge our customers. In
order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs
(primarily fuel and purchased power and construction costs) and/or rate relief. We assess the need for rate
relief in all of the jurisdictions we serve and file for such relief when necessary. The regulatory lag that
30
occurs between the time we incur costs and the time when we can start recovering the costs through rates
has a negative impact on earnings. The effects of timing of rate relief are discussed in detail in Note 3 of
‘‘Notes to the Consolidated Financial Statements’’ under Item 8. Of the factors driving electric operating
margin, weather has the greatest short-term effect on the demand for electricity for our regulated business.
Very hot summers and very cold winters increase electric demand, while mild weather reduces demand.
Residential and commercial sales are impacted more by weather than industrial sales, which are mostly
affected by business needs for electricity and by general economic conditions.
Customer growth, which is the growth in the number of customers, contributes to the demand for
electricity. We expect our electric customer and sales growth to be less than 1.0% annually over the next
several years. Our electric customer growth for the year ended December 31, 2015 was 0.5%. We define
electric sales growth to be growth in kWh sales period over period excluding the estimated impact of
weather. The primary drivers of electric sales growth are customer growth, customer usage and general
economic conditions.
The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power
expense, (2) operating maintenance and repairs expense, including repairs following severe weather and
plant outages, (3) taxes and (4) non-cash items such as depreciation and amortization expense. We have a
fuel cost recovery mechanism in all of our jurisdictions, which significantly reduces the impact of
fluctuating fuel and purchased power costs on our net income.
Gas Segment
The primary drivers of our gas operating revenues in any period are: (1) rates we can charge our
customers, (2) weather, (3) customer growth and usage, (4) the cost of natural gas and interstate pipeline
transportation charges and (5) general economic conditions. The MPSC sets the rates which we can charge
our customers. In order to offset expenses, we depend on our ability to receive adequate and timely
recovery of our costs (primarily commodity natural gas) and/or rate relief. We assess the need for rate
relief and file for such relief when necessary. A Purchased Gas Adjustment (PGA) clause is included in our
gas rates, which allows us to recover our actual cost of natural gas from customers through rate changes,
which are made periodically (up to four times) throughout the year in response to weather conditions,
natural gas costs and supply demands. Weather affects the demand for natural gas. Very cold winters
increase demand for gas, while mild weather reduces demand. Due to the seasonal nature of the gas
business, revenues and earnings are typically concentrated in the November through March period, which
generally corresponds with the heating season.
Customer growth, which is the growth in the number of customers, contributes to the demand for gas.
Our annual customer growth is calculated by comparing the number of customers at the end of a year to
the number of customers at the end of the prior year. Our gas segment customer count decreased 0.5% for
the year ended December 31, 2015, which we believe was due to population losses in the rural communities
we serve. We expect gas customer growth to be flat during the next several years. We define gas sales
growth to be growth in mcf sales excluding the impact of weather. The primary drivers of gas sales growth
are customer growth and general economic conditions.
The primary driver of our gas operating expense in any period is the price of natural gas. However,
because gas purchase costs for our gas utility operations are normally recovered from our customers, any
change in gas prices does not have a corresponding impact on income unless such costs are deemed
imprudent or cause customers to reduce usage.
Earnings
For the year ended December 31, 2015, basic earnings per weighted average share of common stock
were $1.30 and diluted earnings per weighted average share of common stock were $1.29 on $56.6 million
of net income. For the year ended December 31, 2014, basic and diluted earnings per weighted average
31
share of common stock were $1.55 on $67.1 million of net income. Increased electric gross margin
positively impacted net income for 2015 as compared to 2014 mainly due to increased electric rates for our
Missouri customers effective July 26, 2015 and improved customer counts. The impact of mild weather
during the 2015 heating season, as well as increased regulatory operating and maintenance expense,
property taxes, and depreciation and amortization expense negatively impacted 2015 results. These
increased expenses were driven in large part by the completion of the Asbury Air Quality Control System
(AQCS) environmental upgrade that went into service December 14, 2014. Due to regulatory lag, however,
these higher costs did not begin to be recovered in electric rates until new Missouri rates took effect on
July 26, 2015.
The table below sets forth a reconciliation of basic and diluted earnings per share (EPS) between 2014
and 2015, which is a non-GAAP presentation. The economic substance behind our non-GAAP earnings
per share measure is to present the after tax impact of significant items and components of the statement
of income on a per share basis before the impact of additional stock issuances. The dilutive effect of
additional shares issued included in the table reflects the estimated impact of all shares issued during the
period.
We believe this presentation is useful to investors because the statement of income does not readily
show the EPS impact of the various components, including the effect of new stock issuances. This could
limit the readers’ understanding of the reasons for the EPS change from the previous year’s EPS. This
information is useful to management, and we believe this information is useful to investors, to better
understand the reasons for the fluctuation in EPS between the prior and current years on a per share basis.
In addition, although a non-GAAP presentation, we believe the presentation of gross margin (in the
table below and elsewhere in this report) is useful to investors and others in understanding and analyzing
changes in our electric operating performance from one period to the next, and have included the analysis
as a complement to the financial information we provide in accordance with GAAP. This reconciliation and
margin information may not be comparable to other companies’ presentations or more useful than the
GAAP presentation included in the statements of income or elsewhere in this report. We also note that
this presentation does not purport to be an alternative to EPS determined in accordance with GAAP as a
measure of operating performance or any other measure of financial performance presented in accordance
with GAAP. Management compensates for the limitations of using non-GAAP financial measures by using
32
them to supplement GAAP results to provide a more complete understanding of the factors and trends
affecting the business than GAAP results alone.
Earnings Per Share — 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1.55
Gross Margins
Electric segment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Gross Margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses — electric segment . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses — gas segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses — other segment . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maintenance and repairs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AFUDC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in effective income tax rates . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income and deductions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dilutive effect on additional shares issues . . . . . . . . . . . . . . . . . . . . . . . .
0.12
(0.04)
0.01
0.09
(0.04)
0.00
0.00
(0.03)
(0.11)
(0.03)
(0.03)
(0.05)
(0.01)
(0.03)
(0.01)
Earnings Per Share — 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1.30
Fourth Quarter Results
Earnings for the fourth quarter of 2015 were $9.9 million, or $0.23 per share, as compared to
$11.1 million, or $0.26 per share, in the fourth quarter of 2014. Electric segment gross margin increased
during the quarter ending December 31, 2015 compared to the 2014 quarter, reflecting increased electric
rates for our Missouri customers effective July 26, 2015 and improved customer counts. The impact of mild
weather, as well as increased regulatory operating expense, property taxes, and depreciation and
amortization expense and reduced AFUDC, negatively impacted 2015 fourth quarter results.
2015 Activities
Riverton Unit 12 Combined Cycle Project
As part of our environmental Compliance Plan, discussed in Note 11 of ‘‘Notes to Consolidated
Financial Statements’’ under Item 8, we are currently completing the conversion of Riverton Unit 12 from
a simple cycle combustion turbine to a combined cycle unit. The tie-in outage for the Riverton Unit 12
Combined Cycle Project was completed in October 2015 and mechanical completion was achieved on
December 15, 2015. Start-up and commissioning of the unit is currently in progress with contractual
substantial completion by June 1, 2016.
Regulatory Matters
On October 16, 2015, we filed a request with the Missouri Public Service Commission (MPSC) for
changes in rates for our Missouri electric customers. We are seeking an annual increase in total revenue of
approximately $33.4 million, or approximately 7.3%. The most significant factor driving the rate request is
the cost associated with the conversion of the Riverton Unit 12 natural gas combustion turbine to
combined cycle operation. (See Note 11 — New Construction of ‘‘Notes to Consolidated Financial
Statements’’ under Item 8).
33
On June 24, 2015, the MPSC granted new rates for Missouri customers for our rate case filed on
August 29, 2014. Rates were effective July 26, 2015. The order approved an annual increase in base
revenues of about $17.1 million or 3.90%, which included a net reduction in base fuel and purchased power
of $1.60 per MWh, and other items consistent with the non-unanimous stipulation and agreement filed
April 8, 2015.
On January 22, 2015, we filed an Application with the Kansas Corporation Commission (KCC)
requesting approval of our Ad Valorem Tax Surcharge (AVTS). The request sought approval for an annual
increase of $0.27 million related to increases in Ad Valorem taxes which exceed amounts currently
included in base rates. On February 19, 2015, the KCC approved the request. The new rate was effective on
and after February 23, 2015. On January 21, 2016, we filed an Application with the KCC requesting
approval for a revision to the AVTS. The request sought approval for an annual increase of an additional
$0.20 million related to increases in Ad Valorem taxes which exceed amounts currently included in our
AVTS rider currently in effect.
On June 8, 2015, the governor of the state of Oklahoma approved an administrative ruling that
provides customer rate reciprocity to electric companies who serve less than 10% of total customers within
the state of Oklahoma. As a result, future increases in Missouri customer rates approved by the MPSC will
be effective for our Oklahoma customers, subject to Oklahoma Corporation Commission (OCC) approval.
On October 26, 2015, we filed a request with the OCC to adopt the Missouri customer electric rates
requested in our October 16, 2015 Missouri rate filing discussed above for our Oklahoma customers once
approval is granted by the MPSC.
On October 29, 2013, we filed an application with the MPSC seeking approval, pursuant to the
Missouri Energy Efficiency Investment Act (MEEIA), of a new Missouri demand-side management
(DSM) portfolio, including four new DSM programs, and for the authority to establish a Demand Side
Management Investment Mechanism (DSIM). On July 24, 2015, we filed a motion to withdraw our
MEEIA filing. We will continue our current portfolio of Energy Efficiency programs, with recovery
through base rates. We will review the need for a future MEEIA filing in conjunction with our 2016
Integrated Resource Plan (IRP).
On July 31, 2015, we filed a notice updating our most recent IRP, with the MPSC. In the notice we
indicated that Riverton Units 8 and 9 were retired on June 30, 2015. The notice also provides additional
information on our MEEIA application withdrawal mentioned above.
On May 6, 2015, the MPSC approved tariffs we filed on May 5, 2015 to establish solar rebate payment
procedures and revise our net metering tariffs to accommodate the payment of solar rebates mandated by
the Missouri Clean Energy Initiative. The law provides a number of methods that may be utilized to
recover the associated expenses. We expect these costs to be recoverable in rates. See Note 11 —
Renewable Energy of ‘‘Notes to Consolidated Financial Statements’’ under Item 8 for information
regarding the Clean Energy Initiative.
On February 23, 2015, we filed a notice with the Arkansas Public Service Commission (APSC) to
implement the Alternative Generation Environmental Recovery Rider (GER) pursuant to the provision of
Act 310 of 1981. The GER recovers reasonably incurred costs and expenditures as a direct result of
legislative or regulatory requirements relating to the protection of the public health, safety, or the
environment. Our implemented GER recovers our Arkansas jurisdictional share of investment associated
with the Asbury AQCS. The new GER was effective upon notice (February 23, 2015) subject to refund. On
August 5, 2015, the APSC approved the GER.
For additional information on all these cases, see Note 3 of ‘‘Notes to Consolidated Financial
Statements’’ under Item 8 for information regarding regulatory matters.
34
Financing Activities
On June 11, 2015, we entered into a Bond Purchase Agreement for a private placement of
$60.0 million of 3.59% First Mortgage Bonds due 2030. A delayed settlement occurred on August 20, 2015.
Interest is payable semi-annually on the bonds on each February 20 and August 20, commencing
February 20, 2016. We utilized the proceeds from the sale of the bonds for the Riverton combined cycle
project and for general corporate purposes.
For additional information, see Note 6 of ‘‘Notes to Consolidated Financial Statements’’ under
Item 8.
Subsequent Events
Pending Acquisition of Empire by Liberty Utilities (Central) Co.
On February 9, 2016, Empire entered into an Agreement and Plan of Merger (the Merger
Agreement) with Liberty Utilities (Central) Co., a Delaware corporation (Liberty), and Liberty Sub Corp.,
a Kansas corporation (Merger Sub), providing for the merger of Merger Sub with and into Empire, with
Empire surviving the Merger as a wholly-owned subsidiary of Liberty (the Merger). Pursuant to the
Merger Agreement, at the effective time of the Merger, each issued and outstanding share of Empire
common stock (other than any shares owned by Empire or Algonquin Power & Utilities Corp. (APUC)) or
any of their respective subsidiaries or any shares for which appraisal rights have been perfected) will be
cancelled and converted automatically into the right to receive $34.00 in cash, without interest.
The closing of the Merger is subject to certain conditions, including, among others, approval of
Empire shareholders, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period
and receipt of all required regulatory approvals and consents, including from the Federal Energy
Regulatory Commission, the Federal Communications Commission, the Arkansas Public Service
Commission, the Kansas Corporation Commission, the Missouri Public Service Commission, the
Oklahoma Corporation Commission and the Committee on Foreign Investment in the United States,
which approvals and consents shall not, individually or in the aggregate, have or be reasonably likely to
have a material adverse effect on the business, properties, financial condition or results of operations of
Liberty Utilities Co. and its subsidiaries (including Empire and its subsidiaries), taken as a whole.
If Empire shareholders do not approve the Merger, or the Merger is not consummated by February 9,
2017, the Merger Agreement may terminate, although it may be extended six months in order to obtain
certain required regulatory approvals. The Merger Agreement also provides for certain other termination
rights for both Empire and Liberty. If either party terminates the Merger Agreement because Empire’s
board of directors changes its recommendation, or, if within nine months after the termination of the
Merger Agreement under certain circumstances, Empire shall have entered into a definitive agreement
with respect to, or consummated, an alternative transaction, Empire must pay Liberty a termination fee of
$53.0 million. If the Merger Agreement is terminated under certain other circumstances, including the
failure to obtain required regulatory approvals, failure to consummate the Merger after all closing
conditions have been satisfied and a financing failure has occurred or a breach by Liberty of its regulatory
cooperation covenants, Liberty must pay Empire a termination fee of $65.0 million.
Simultaneously with the execution of the Merger Agreement, Liberty delivered to Empire a guarantee
agreement (the Guarantee Agreement) executed by APUC, the parent of Liberty Utilities Co. The
Guarantee Agreement provides for an unconditional and irrevocable guarantee by APUC of the full and
prompt payment and performance, when due, of all obligations of Liberty and Merger Sub under the
Merger Agreement.
In connection with entering into the Merger Agreement, Empire has incurred approximately
$0.2 million of transaction costs as of December 31, 2015. We expect that the total transaction costs will be
approximately $15 to $17 million, with approximately 50% payable in 2016 (assuming a 2017 closing date),
35
of which approximately $4.5 million will be incurred in the first quarter of 2016. The foregoing description
of the Merger, the Merger Agreement and the Guarantee is not a complete description thereof and is
qualified in its entirety by reference to the full text of the Merger Agreement and the Guarantee. For more
information regarding the terms of the Merger, including copies of the Merger Agreement and the
Guarantee, see Empire’s Current Report on Form 8-K filed with the SEC on February 9, 2016.
RESULTS OF OPERATIONS
The following discussion analyzes significant changes in the results of operations for the years 2015,
2014 and 2013.
The following table represents our results of operations by operating segment for the applicable years
ended December 31 (in millions):
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$52.2
1.3
3.1
$61.5
2.9
2.7
$58.6
2.3
2.5
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$56.6
$67.1
$63.4
2015
2014
2013
Electric Segment
Overview
Our electric segment income for 2015 was $52.2 million as compared to $61.5 million and
$58.6 million for 2014 and 2013, respectively.
Electric on-system operating revenues for 2015, 2014, and 2013 were comprised of the following
customer classes:
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
Industrial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale on-system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous sources* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other electric revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015
2014
2013
42.9% 43.4% 43.9%
31.6
31.9
15.5
16.4
4.1
3.3
2.8
2.9
2.6
2.6
31.3
15.5
3.9
2.9
2.5
*
Primarily other public authorities
36
Sales, Revenues and Gross Margin
KWh Sales
The amounts and percentage changes from the prior periods in kilowatt-hour (‘‘kWh’’) sales by major
customer class for on-system (native load) sales were as follows (in millions):
kWh Sales
Customer Class
2015
2014
% Change(1)
2014
2013
% Change(1)
Residential . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . .
Wholesale on-system . . . . . . . . . . . . . . .
Other(2)
. . . . . . . . . . . . . . . . . . . . . . . .
1,836.2
1,577.4
1,064.5
330.8
131.1
1,950.4
1,583.8
1,031.6
336.3
128.0
(5.9)% 1,950.4
1,583.8
(0.4)
1,031.6
3.2
336.3
(1.6)
128.0
2.4
1,936.6
1,541.7
1,015.5
343.1
129.4
0.7%
2.7
1.6
(2.0)
(1.1)
Total on-system sales . . . . . . . . . . . . .
4,940.0
5,030.1
(1.8)
5,030.1
4,966.3
1.3
(1) Percentage changes are based on actual kWh sales and may not agree to the rounded amounts shown
above.
(2) Other kWh sales include street lighting, other public authorities and interdepartmental usage.
KWh sales for our on-system customers decreased during 2015 as compared to 2014 primarily due to
decreased demand due to weather impacts. Residential kWh sales, the more weather sensitive class,
decreased 5.9% primarily due to the impacts of milder weather during the 2015 heating season as
compared to 2014. Commercial kWh sales decreased only 0.4% due to increased customer growth
offsetting the impact of mild weather. Industrial sales increased 3.2% during 2015 as compared to 2014
mainly due to increased usage. Total heating degree days (the sum of the number of degrees that the daily
average temperature for each day during that period was below 65(cid:4) F) for 2015 were 16.6% less than 2014
and 11.3% less than the 30-year average. Total cooling degree days (the cumulative number of degrees that
the average temperature for each day during that period was above 65(cid:4) F) for 2015 were 5.8% more than
2014 and 12.0% more than the 30-year average.
KWh sales for our on-system customers increased during 2014 as compared to 2013 primarily due to
increased demand due to weather impacts, increased commercial demand and increased customer counts.
Residential and commercial kWh sales increased 0.7% and 2.7%, respectively, primarily due to these
weather impacts and increased customer counts. Industrial sales increased 1.6% during 2014 as compared
to 2013 due to increased usage. On-system wholesale kWh sales decreased during 2014 as compared to
2013 reflecting the closure of a large dairy facility in Monett, Missouri during the second half of 2013. Total
heating degree days for 2014 were 1.2% more than 2013 and 6.3% more than the 30-year average. Total
cooling degree days for 2014 were 3.7% more than 2013 and 5.8% more than the 30-year average.
Revenues and Gross Margin
As shown in the Electric Segment Operating Revenues and Gross Margin table below, electric
segment gross margin, defined as electric revenues less fuel and purchased power costs, increased
approximately $7.8 million during 2015 as compared to 2014. Electric segment gross margin was positively
impacted by the new Missouri retail on-system rate increase effective July 26, 2015 and an increase in
average electric customer counts. Electric segment gross margin increased approximately $16.4 million
during 2014 as compared to 2013 due to a full twelve months of increased Missouri electric rates that were
effective April 1, 2013, increased demand resulting from weather impacts, higher commercial demand and
an increase in average electric customer counts.
The amounts and percentage changes from the prior period’s electric segment operating revenues by
major customer class for on-system and off-system sales, and the associated fuel and purchased power
37
expense (including a reconciliation of our actual fuel and purchased power expenditures to the fuel and
purchased power expense shown on our statements of income) were as follows (dollars in millions):
Customer Class
Electric Segment Operating Revenues and Gross Margin
2015
2014
% Change(1)
2014
2013
% Change(1)
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . $230.6 $236.5
172.3
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . .
84.7
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . .
22.3
Wholesale on-system . . . . . . . . . . . . . . . . . . . .
Other(2)
15.2
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
171.7
88.2
18.0
15.7
(2.5)% $236.5 $227.7
162.4
172.3
(0.3)
80.5
84.7
4.1
20.0
22.3
(19.2)
15.0
15.2
3.1
3.9%
6.1
5.3
11.4
2.1
Total on-system revenues . . . . . . . . . . . . . . .
Off-system wholesale(3)
. . . . . . . . . . . . . . . . . .
SPP IM net revenues(3) . . . . . . . . . . . . . . . . . .
Total revenues from KWh sales . . . . . . . . . . . .
Miscellaneous revenues(4)
. . . . . . . . . . . . . . . .
524.2
—
15.0
539.2
13.8
531.0
3.2
41.9
576.1
14.3
Total electric operating revenues . . . . . . . . . . . $553.0 $590.4
2.1
Water revenues . . . . . . . . . . . . . . . . . . . . . . . .
2.1
Total electric segment operating revenues . . . . . $555.1 $592.5
Actual fuel and purchased power expenditures . $141.0 $165.2
SPP IM net purchases(3)
55.9
. . . . . . . . . . . . . . . . .
(3.8)
Net fuel recovery and deferral . . . . . . . . . . . . .
SWPA amortization(5)
(2.6)
. . . . . . . . . . . . . . . . . . .
0.4
Unrealized (gain)/loss on derivatives . . . . . . . .
22.6
8.9
(2.5)
(0.1)
(1.3)
(100.0)
(64.1)
(6.4)
(3.9)
(6.3)
(0.3)
(6.3)
(14.7)
(59.6)
(332.9)
(4.9)
(113.3)
Total fuel and purchased power expense per
505.6
15.5
5.0
(79.2)
— 100.0
10.6
8.2
10.5
(3.3)
531.0
3.2
41.9
576.1
14.3
521.1
13.2
$590.4 $534.3
2.1
2.1
$592.5 $536.4
$165.2 $182.1
10.5
(9.3)
— 100.0
6.2
(5.4)
(237.4)
(3.6)
(2.8)
(0.3)
55.9
(3.8)
(2.6)
0.4
income statement . . . . . . . . . . . . . . . . . . .
169.9
215.1
(21.0)
215.1
175.4
Total Gross Margin . . . . . . . . . . . . . . . . . . . . $385.2 $377.4
2.1
$377.4 $361.0
22.6
4.5
(1) Slight differences from actual results, including percentage changes, may occur which may not agree
to the rounded amounts shown above due to rounding to millions and percentage change based on
actual, not rounded amounts shown.
(2) Other operating revenues include street lighting, other public authorities and interdepartmental
usage.
(3) The SPP IM was implemented on March 1, 2014. As of December 31, 2014, off-system revenues were
effectively replaced by SPP IM activity. See ‘‘— Markets and Transmission’’ below for more
information.
(4) Miscellaneous revenues include transmission service revenues, late payment fees, renewable energy
credit sales, rent, etc.
(5) Missouri ten year amortization of the $26.6 million payment received from the SWPA in September,
2010, of which $10.6 million of the Missouri portion remains to be amortized as of December 31, 2015.
Revenues for our on-system customers decreased approximately $6.8 million (1.3%) during 2015 as
compared to 2014. Increased revenues of $10.4 million, primarily due to the July 2015 increase in Missouri
electric rates mentioned above, net of a $3.3 million decrease resulting from a lowering of Missouri base
fuel recovery, contributed an estimated $7.1 million to revenues. Improved customer counts increased
revenues an estimated $2.3 million. Weather and other volumetric related factors decreased revenues an
estimated $10.3 million in 2015 as compared to 2014. Also negatively impacting revenues was a $1.3 million
decrease in Missouri non-base fuel recovery revenue and a $3.2 million decrease in non-Missouri fuel
38
recovery revenue (both of which were offset by a corresponding change in fuel expenses, resulting in no net
effect on gross margin). Also decreasing revenues was a $1.4 million January 2015 refund to FERC
wholesale customers, reflecting lower fuel costs from the SPP IM.
Revenues for our on-system customers increased approximately $25.5 million (5.0%) during 2014 as
compared to 2013. Rate changes, primarily the April 2013 Missouri rate increase, contributed an estimated
$12.5 million to revenues. Weather and other volumetric related factors increased revenues an estimated
$4.6 million in 2014 as compared to 2013. Improved customer counts increased revenues an estimated
$1.6 million. A $6.8 million increase in fuel recovery revenue (offset by a corresponding change included in
fuel expenses, resulting in no net effect on gross margin) from Missouri customers during 2014 as
compared to 2013, positively impacted revenues.
SPP Integrated Marketplace (IM) and Off-System Electric Transactions.
In the past, in addition to sales to our own customers, we also sold power to other utilities as available,
including (since 2007) through the SPP Energy Imbalance Services (EIS) market. However, on March 1,
2014, the SPP RTO implemented a Day-Ahead Market, or Integrated Marketplace (IM), which replaces
the real-time EIS market. SPP IM activity is settled for each market participant in various time increments.
When we sell more generation to the market than we purchase, based on the prescribed time increments,
the net sale and corresponding net revenue is included as part of electric revenues. When we purchase
more generation from the market than we sell, based on the prescribed time increments, the net purchase
cost is recorded as a component of fuel and purchased power on the financial statements. See the Electric
Segment Operating Revenues and Gross Margin table (SPP IM net purchases) above and ‘‘— Markets and
Transmission’’ below. The majority of our market activity sales margin is included as a component of the
fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and our transmission rider in
our Arkansas jurisdiction. As a result, nearly all of the market activity sales margin flows back to the
customer and has little effect on gross margin or net income.
Operating Expenses — Other Than Fuel and Purchased Power
The table below shows regulated operating expense increases/(decreases) during 2015 as compared to
2014 and during 2014 as compared to 2013 (in millions):
2015 vs. 2014
2014 vs. 2013
Regulated operating expense:
Transmission expense(1) . . . . . . . . . . . . . . . . . . . . . . . . . .
Distribution expense . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power operation expense(2)
. . . . . . . . . . . . . . . . . . . . . . .
Customer accounts and assistance expense . . . . . . . . . . . .
Employee pension expense . . . . . . . . . . . . . . . . . . . . . . .
Employee health care expense . . . . . . . . . . . . . . . . . . . . .
General office supplies and expense . . . . . . . . . . . . . . . . .
Administrative and general expense . . . . . . . . . . . . . . . . .
Allowance for uncollectible accounts . . . . . . . . . . . . . . . .
Regulatory reversal of gain on sale of assets . . . . . . . . . . .
Other miscellaneous accounts (netted) . . . . . . . . . . . . . . .
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1.2
(0.2)
2.2
0.0
(0.2)
1.0
(0.5)
0.4
(1.1)
0.0
0.0
$ 2.8
$ 5.0
1.1
0.4
0.4
(0.1)
(1.0)
2.2
(0.4)
(0.1)
(1.2)
(2.5)
$ 3.8
(1) Mainly due to increased SPP transmission charges.
(2) Mainly due to a $1.0 million increase in power operation expense for the Asbury plant.
39
The table below shows maintenance and repairs expense increases/(decreases) during 2015 as
compared to 2014 and during 2014 as compared to 2013(in millions):
Maintenance and repairs expense:
Transmission and distribution maintenance expense . . . . . .
Maintenance and repairs expense at:
Energy Center . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asbury plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SLCC(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State Line plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Iatan plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plum Point plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Riverton plant(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Water plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other miscellaneous accounts (netted) . . . . . . . . . . . . . . .
2015 vs. 2014
2014 vs. 2013
$(1.5)
$ 3.1
(1.1)
0.0
3.1
(0.2)
0.5
(0.9)
2.0
(0.2)
0.0
1.3
1.2
(0.6)
(0.3)
0.3
(0.1)
0.8
0.2
0.0
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1.7
$ 5.9
(1) Mainly due to a planned maintenance outage.
(2) Mainly due to a new maintenance contract for the Riverton facility.
Depreciation and amortization expense increased approximately $7.2 million (10.7%) during 2015 as
compared to 2014 primarily due to increased plant in service reflecting the completion of the Asbury
AQCS project and other additions to plant in service. Depreciation and amortization expense increased
approximately $3.9 million (6.1%) during 2014 as compared to 2013, primarily due to increased
depreciation rates resulting from our 2013 Missouri electric rate case settlement and increased plant in
service.
Other taxes increased approximately $2.3 million in 2015 and $1.8 million in 2014 due to increased
property tax (reflecting our additions to plant in service) and increased municipal franchise taxes.
Gas Segment
Gas Operating Revenues and Sales
The following table details our natural gas sales for the years ended December 31:
(bcf sales)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Residential
Commercial(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation sales(1)
. . . . . . . . . . . . . . . . . . . . . . . .
Total gas operating sales . . . . . . . . . . . . . . . . . . . . . . .
Total Gas Delivered to Customers
2015
2014
% Change
2014
2013
% Change
2.22
1.04
0.04
0.03
3.33
4.45
7.78
2.76
1.27
0.06
0.04
4.13
4.92
9.05
(19.6)% 2.76
1.27
(18.1)
0.06
(38.8)
0.04
(19.6)
(19.4)
(9.5)
(14.0)
4.13
4.92
9.05
2.74
1.35
0.07
0.04
4.20
4.53
8.73
0.6%
(5.5)
(13.5)
3.1
(1.6)
8.6
3.7
(1) Several commercial customers transferred to transportation customers during 2014, reflecting the
decrease in commercial sales and the increase in transportation sales during 2014 compared to 2013.
(2) Other includes other public authorities and interdepartmental usage.
40
The following table details our natural gas revenues for the years ended December 31:
Operating Revenues and Cost of Gas Sold
2015
2014
% Change
2014
2013
% Change
($ in millions)
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial(1) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail revenues . . . . . . . . . . . . . . . . . . . . . .
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation revenues(1)
. . . . . . . . . . . . . . . . . .
Total gas operating revenues . . . . . . . . . . . . . . . .
Cost of gas sold . . . . . . . . . . . . . . . . . . . . . . . . .
$26.3
10.7
0.3
0.3
$37.6
0.4
3.7
$41.7
19.5
$32.9
13.6
0.5
0.4
$47.4
0.4
4.0
$51.8
27.0
(20.1)% $32.9
13.6
(21.6)
0.5
(41.2)
0.4
(21.6)
$47.4
0.4
4.0
$51.8
27.0
(20.7)
(7.0)
(6.8)
(19.6)
(27.8)
(10.5)
$31.6
13.7
0.5
0.3
$46.1
0.4
3.5
$50.0
25.8
4.2%
(0.2)
4.2
6.8
2.9
5.0
12.9
3.6
4.8
2.4
Gas segment gross margin . . . . . . . . . . . . . . . . . .
$22.2
$24.8
$24.8
$24.2
(1) Several commercial customers transferred to transportation customers during 2014, reflecting the
decrease in commercial revenues and the increase in transportation revenues during 2014 compared
to 2013.
(2) Other includes other public authorities and interdepartmental usage.
Gas retail sales decreased 19.4% and gas retail revenues decreased 20.7% during 2015 as compared to
2014 primarily due to decreased demand from the impacts of milder weather during the 2015 heating
season as compared to 2014. Weather in our gas territory in the fourth quarter of 2015 was the mildest in
34 years. Heating degree days were 19.1% lower in 2015 than 2014 and 10.8% lower than the 30-year
average. Our gas segment gross margin (defined as gas operating revenues less cost of gas in rates) for
2015 decreased $2.6 million compared to 2014.
Gas retail sales decreased 1.6% during 2014 as compared to 2013 due to commercial and industrial
customers transferring to transportation service. Gas retail revenues increased 2.9% reflecting increased
usage by the weather sensitive residential class due to colder weather in 2014 as compared to 2013 and
higher gas costs recovered in revenues. Heating degree days were 1.7% higher in 2014 than 2013 and
10.2% higher than the 30-year average. Our gas segment gross margin (defined as gas operating revenues
less cost of gas in rates) for 2014 increased $0.6 million compared to 2013.
We have a PGA clause in place that allows us to recover from our customers, subject to routine
regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated
with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions
of the PGA clause, the difference between actual costs incurred and costs recovered through the
application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is
recovered from or credited to customers.
41
Operating Revenue Deductions
The table below shows regulated operating expense increases/(decreases) for the years ended
December 31:
(in millions)
Distribution operation expense . . . . . . . . . . . . . . . . . . . .
Transmission operation expense . . . . . . . . . . . . . . . . . . . .
Customer accounts expense . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 vs. 2014
2014 vs. 2013
$ 0.3
0.1
(0.5)
0.2
$ 0.1
$(0.2)
0.1
(0.6)
(0.1)
$(0.8)
Our gas segment had net income of $1.3 million in 2015 as compared to $2.9 million in 2014 and
$2.3 million in 2013.
Consolidated Company
Income Taxes
The following table shows our consolidated provision for income taxes (in millions) and our
consolidated effective federal and state income tax rates for the applicable years ended December 31:
2015
2014
2013
Consolidated provision for income taxes . . . . . . . . . . . . . . . .
Consolidated effective federal and state income tax rates . . . .
$39.2
$33.8
37.4% 36.9% 37.1%
$37.5
The effective tax rate for 2015 is higher than 2014 primarily due to lower equity AFUDC income in
2015 compared with 2014. The effective tax rate for 2014 is lower than 2013 primarily due to higher equity
AFUDC income in 2014 compared with 2013.
See Note 9 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8 for information and
discussion concerning our income tax provision and effective tax rates.
Nonoperating Items
The following table shows the total allowance for funds used during construction (AFUDC) for the
applicable periods ended December 31. AFUDC decreased in 2015 as compared to 2014 reflecting the
completion of the environmental retrofit project at our Asbury plant in December 2014. AFUDC
increased in 2014 as compared to 2013 reflecting construction for the environmental retrofit project at our
Asbury plant and the Riverton 12 combined cycle project. See Note 1 of ‘‘Notes to Consolidated Financial
Statements’’ under Item 8.
($ in millions)
Allowance for equity funds used during construction . . . . . . . . . .
Allowance for borrowed funds used during construction . . . . . . .
Total AFUDC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015
2014
2013
$4.9
2.8
$7.7
$6.4
3.5
$9.9
$3.8
2.1
$5.9
Total interest charges on long-term and short-term debt for 2015, 2014 and 2013 are shown below. The
change in long-term debt interest for 2015 compared to 2014 reflects the issuance on December 1, 2014, of
$60.0 million of 4.27% First Mortgage Bonds due 2044 and the issuance of $60.0 million of 3.59% First
Mortgage Bonds due 2030 on August 20, 2015. The proceeds from both bond issuances were used to
refinance existing short-term indebtedness and for general corporate purposes.
42
The change in long-term debt interest for 2014 compared to 2013 reflects the issuance, on May 30,
2013, of $30.0 million of 3.73% First Mortgage Bonds due May 30, 2033 and $120.0 million of 4.32% First
Mortgage Bonds due May 30, 2043. We used a portion of the proceeds from the sale of these bonds to
redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013.
Interest Charges
($ in millions)
2015
2014
Change
2014
2013
Change
Long-term debt interest . . . . . . . . . . . . . . . . . . . . . .
Short-term debt interest . . . . . . . . . . . . . . . . . . . . . .
Other interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$43.8
0.3
1.0
$40.6
0.1 >100.0
4.6
1.0
7.8% $40.6
0.1
1.0
$40.3
0.1
1.1
0.7%
90.5
(7.1)
Total interest charges . . . . . . . . . . . . . . . . . . . . . . . .
$45.1
$41.7
8.1
$41.7
$41.5
0.6
RATE MATTERS
We routinely assess the need for rate relief in all of the jurisdictions we serve and file for such relief
when necessary.
Our rates for retail electric and natural gas services (other than specially negotiated retail rates for
industrial or large commercial customers, which are subject to regulatory review and approval) are
determined on a ‘‘cost of service’’ basis. Rates are designed to provide, after recovery of allowable
operating expenses, an opportunity for us to earn a reasonable return on ‘‘rate base.’’ ‘‘Rate base’’ is
generally determined by reference to the original cost (net of accumulated depreciation and amortization)
of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate
base is increased by additions to utility plant in service and reduced by depreciation, amortization and
retirement of utility plant or write-off’s as ordered by the utility commissions. In general, a request of new
rates is made on the basis of a ‘‘rate base’’ as of a date prior to the date of the request and allowable
operating expenses for a 12-month test period ended prior to the date of the request. Although the current
rate making process provides recovery of some future changes in rate base and operating costs, it does not
reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag
(commonly referred to as ‘‘regulatory lag’’) between the time we incur costs and the time when we can start
recovering the costs through rates.
The following table sets forth information regarding electric and water rate increases since January 1,
2013:
Jurisdiction
Date
Requested
Annual
Increase
Granted
Percent
Increase
Granted
Date
Effective
August 29, 2014
Missouri — Electric . . . . . . . . . . . .
Kansas — Electric . . . . . . . . . . . . . . December 5, 2014
February 23, 2015
Arkansas — Electric . . . . . . . . . . . .
Kansas — Electric . . . . . . . . . . . . . .
January 22, 2015
Arkansas — Electric . . . . . . . . . . . . December 3, 2013
Missouri — Electric . . . . . . . . . . . .
July 6, 2012
$17,125,000
782,479
$
457,000
$
$
273,455
$ 1,366,809
$27,500,000
July 26, 2015
June 1, 2015
3.90%
4.71%
3.35% February 23, 2015
1.08% February 23, 2015
11.34% September 26, 2014
6.78%
April 1, 2013
See Note 3 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8 for additional information
regarding rate matters.
43
MARKETS AND TRANSMISSION
Electric Segment
Day Ahead Market: On March 1, 2014, the SPP RTO implemented its Integrated Marketplace (IM)
(or Day-Ahead Market), which replaced the Energy Imbalance Services (EIS) market. The SPP RTO
created a single NERC-approved balancing authority (BA) that took over balancing authority
responsibilities for its members, including Empire.
As part of the IM, we and other SPP members submit generation offers to sell our power and bids to
purchase power into the SPP market, with the SPP serving as a centralized commitment and dispatch of
SPP members’ generation resources. The SPP matches offers and bids based upon operating and reliability
considerations. The SPP reports that approximately 90% – 95% of all next day generation needed
throughout the SPP territory is being cleared through the IM. We also acquire Transmission Congestion
Rights (TCR) through annual and monthly processes in an attempt to mitigate congestion costs associated
with the power we purchase from the IM. When we sell more generation to the market than we purchase
for a given settlement period, the net sale is included as part of electric revenues. When we purchase more
generation from the market than we sell, the net purchase is recorded as a component of fuel and
purchased power on our financial statements. The net financial effect of these IM transactions is included
in our fuel adjustment mechanisms and therefore has little impact on gross margin.
SPP/Midcontinent Independent System Operator (MISO) Joint Operating Agreement and Plum
Point Delivery: Due to Plum Point’s physical location and interconnection, transmission service from
Entergy/MISO is required for delivery. On December 19, 2013, Entergy voluntarily integrated its
generation, transmission, and load into the MISO regional transmission organization. Based on the current
terms and conditions of MISO membership, Entergy’s participation in MISO has increased transmission
delivery costs for our Plum Point power station as well as utilizes our transmission system without
compensation.
As a result, we have participated with the SPP members and other impacted utilities in two separate
FERC settlement proceedings in an effort to reduce the costs to our customers. On October 13, 2015, SPP
members, SPP, MISO and MISO members filed a settlement at the FERC regarding MISO’s unreserved
and uncompensated use of the SPP members’ systems. If approved by the FERC, the agreement will
provide compensation and governance for the continued shared use of the transmission system among
MISO, SPP and others impacted. However, the regional through and out transmission delivery rate
(RTOR) dispute regarding Plum Point will go to hearing at the FERC. On May 20, 2015, we along with
KCPL-GMO, AECI, and Southern Company filed a formal 206 complaint at the FERC that the ROTR
rate was unjust and unreasonable. A procedural schedule was issued by the FERC on October 8, 2015 with
hearings to commence on April 25, 2016 and an initial decision scheduled for August 10, 2016.
Information concerning recent and pending SPP RTO and other FERC activities can be found under
Note 3 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8.
LIQUIDITY AND CAPITAL RESOURCES
Overview. Our primary sources of liquidity are cash provided by operating activities, short-term
borrowings under our commercial paper program (which is supported by our unsecured revolving credit
facility) and borrowings from our unsecured revolving credit facility. Historically, we have also successfully
raised funds, as needed, from the debt and equity capital markets to fund our liquidity and capital resource
needs.
Our issuance of various securities, including equity, long-term and short-term debt, is subject to
customary approval or authorization by state and federal regulatory bodies including state public service
commissions and the SEC. We believe the cash provided by operating activities, together with the amounts
available to us under our credit facilities and the issuance of debt and equity securities, will allow us to
44
meet our needs for working capital, pension contributions, our continuing construction expenditures,
anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash
needs through the next several years. See ‘‘— Capital Requirements and Investing Activities’’ below for
further information.
We will continue to evaluate our need to increase available liquidity based on our view of working
capital requirements, including the timing of our construction programs and other factors. See Item 1A,
‘‘Risk Factors’’ for additional information on items that could impact our liquidity and capital resource
requirements. The following table provides a summary of our operating, investing and financing activities
for the last three years.
Summary of Cash Flows
(in millions)
Cash provided by/(used in):
Fiscal Year
2015
2014
2013
Operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 184.8
(185.5)
0.3
$ 151.2
(215.3)
62.7
$ 157.5
(153.3)
(4.1)
Net change in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . .
$
(0.4) $
(1.4) $
0.1
Cash flow from Operating Activities
We prepare our statement of cash flows using the indirect method. Under this method, we reconcile
net income to cash flows from operating activities by adjusting net income for those items that impact net
income but may not result in actual cash receipts or payments during the period. These reconciling items
include depreciation and amortization, pension costs, deferred income taxes, equity AFUDC, changes in
commodity risk management assets and liabilities and changes in the consolidated balance sheet for
working capital from the beginning to the end of the period.
Year-over-year changes in our operating cash flows are attributable primarily to working capital
changes resulting from the impact of weather, the timing of customer collections, payments for natural gas
and coal purchases, the effects of deferred fuel recoveries and the size and timing of pension contributions.
The increase or decrease in natural gas prices directly impacts the cost of gas stored in inventory.
2015 compared to 2014.
In 2015, our net cash flows provided from operating activities was
$184.8 million, an increase of $33.6 million, or 22.2%, from 2014. This change was primarily a result of:
(cid:127) Increased plant depreciation based on additions — $7.7 million.
(cid:127) Working capital changes for collections of accounts receivable and estimated unbilled revenues —
$40.6 million.
(cid:127) Regulatory fuel adjustment mechanism liabilities increased — $7.9 million.
(cid:127) Adjustments to recognize non-cash losses for derivatives increased — $5.7 million.
(cid:127) Lower refunds of customer advances in 2015 increased cash — $2.5 million.
(cid:127) Decrease in net income — $(10.5) million.
(cid:127) Changes in fuel related and other regulatory amortizations — $(2.3) million.
(cid:127) Additional pension funding over last year — $(8.7) million.
(cid:127) Tax timing differences lower during 2015 mostly related to bonus depreciation partially offset by
expected utilization of 2014 tax net operating losses — $(5.1) million.
(cid:127) Changes related to inventories, prepaid assets and accounts payable, net — $(3.0) million.
45
2014 compared to 2013.
In 2014, our net cash flows provided from operating activities was
$151.2 million, a decrease of $6.2 million, or 4.0%, from 2013. This change was primarily a result of:
(cid:127) Increase in net income — $3.7 million.
(cid:127) Increased plant depreciation — $3.4 million due to additions.
(cid:127) Changes in fuel adjustments and other regulatory amortizations — $8.4 million.
(cid:127) Changes in pension amortizations — $3.9 million.
(cid:127) Tax timing differences as a result of bonus depreciation being reinstated and tangible property
regulation changes — $13.4 million.
(cid:127) Working capital changes for accounts receivable, accounts payable and other current assets and
liabilities — $(33.6) million.
(cid:127) Increase in equity AFUDC mostly attributable to higher construction work in progress balances —
$(2.6) million.
Capital Requirements and Investing Activities
Our net cash flows used in investing activities decreased $29.8 million from 2014 to 2015. The
decrease was due to a $28.0 million decrease in total cash outlay for capital expenditures and a $1.8 million
decrease in restricted cash.
Our net cash flows used in investing activities increased $62.0 million from 2013 to 2014. The increase
was primarily the result of an increase in new generation capital expenditures related to the Riverton 12
combined cycle construction.
Our capital expenditures totaled approximately $176.0 million, $222.8 million, and $160.2 million in
2015, 2014 and 2013, respectively.
A breakdown of these capital expenditures for 2015, 2014 and 2013 is as follows:
(in millions)
Distribution and transmission system additions . . . . . . . . . . . . . . . . . . . . . .
New generation — Riverton 12 combined cycle . . . . . . . . . . . . . . . . . . . . . .
Additions and replacements — electric plant
. . . . . . . . . . . . . . . . . . . . . . .
Storms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas segment additions and replacements . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (including retirements and salvage — net)(1)
. . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-regulated capital expenditures (primarily fiber optics) . . . . . . . . . . . . . .
Subtotal capital expenditures incurred(2)
Adjusted for capital expenditures payable(3)
. . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . .
Capital Expenditures
2015
2014
2013
$ 65.3
75.8
14.7
0.0
3.8
4.8
9.9
$174.3
2.2
$ 57.7
77.5
61.4
2.3
3.6
7.1
11.0
$220.6
2.2
$ 58.5
13.2
61.8
1.0
4.5
4.1
14.7
$157.8
2.4
$176.5
$222.8
$160.2
8.9
(9.4)
(5.4)
Total cash outlay . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$185.4
$213.4
$154.8
(1) Other includes equity AFUDC of $(4.9) million, $(6.4) million and $(3.9) million for 2015, 2014 and
2013, respectively. Also included are insurance proceeds of $(7.8) million for 2013.
46
(2) Expenditures incurred represent the total cost for work completed for the projects during the year.
Discussion of capital expenditures throughout this 10-K is presented on this basis. These capital
expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.
(3) The amount of expenditures unpaid at the end of the year to adjust to actual cash outlay reflected in
the Investing Activities section of the Statement of Cash Flows.
Approximately 75%, 50% and 74% of our cash requirements for capital expenditures for 2015, 2014
and 2013, respectively, were satisfied from internally generated funds (funds provided by operating
activities less dividends paid). The remaining amounts of such requirements were satisfied from short-term
borrowings and proceeds from our sales of common stock and debt securities discussed below.
Our estimated capital expenditures (excluding AFUDC) for 2016, 2017 and 2018 are detailed below.
See Item 1, ‘‘Business — Construction Program.’’ We anticipate that we will spend the following amounts
over the next three years for the following projects:
Project
2016
2017
2018
Total
Riverton Unit 12 combined cycle conversion . . . . . . . . . . . . . . . . .
Electric distribution system additions . . . . . . . . . . . . . . . . . . . . . . .
Electric transmission facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additions and replacements — electric plant . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 11.7
46.7
23.3
16.4
17.0
$
0.0
40.5
29.6
21.7
14.5
$
0.0
62.0
26.2
35.2
36.0
$ 11.7
149.2
79.1
73.3
67.5
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$115.1
$106.3
$159.4
$380.8
Customer reliability, communication and efficiency projects comprise $15 million of the 2018 other
estimate above. Our estimated total capital expenditures (excluding AFUDC) for 2019 and 2020 are
$150.9 million and $114.1 million, respectively.
We estimate that internally generated funds will provide approximately 100% of the funds required in
2016 for our budgeted capital expenditures. We intend to utilize short-term debt to finance any additional
amounts needed beyond those provided by operating activities for such capital expenditures. If additional
financing is needed, we intend to utilize a combination of debt and equity securities. The estimates herein
may be changed because of changes we make in our construction program, unforeseen construction costs,
our ability to obtain financing, regulation and for other reasons. See further discussion under ‘‘Financing
Activities’’ below.
Financing Activities
2015 compared to 2014.
Our net cash flows provided by financing activities was $0.3 million in 2015 as compared to
$62.7 million in 2014, a decrease of $62.4 million, primarily due to the following:
(cid:127) Net short-term repayments of $19.0 million in 2015 as compared to net short-term borrowings of
$40.0 million in 2014.
(cid:127) Proceeds from issuance of common stock of $5.5 million in 2015 as compared to $8.0 million in
2014.
(cid:127) Dividends paid of $45.4 million in 2015 as compared to $44.4 million in 2014.
47
2014 compared to 2013.
Our net cash flows provided by financing activities was $62.7 million in 2014 as compared to
$4.1 million used in financing activities in 2013, an increase of $66.7 million, primarily due to the following:
(cid:127) Issuance of $40.0 million in short-term debt in 2014 as compared to repayment of $20.0 million in
short-term debt in 2013.
(cid:127) Issuance of $60.0 million of first mortgage bonds in 2014 compared to $150.0 million issued in 2013.
(cid:127) No repayment of senior notes in 2014 compared to $98.0 million of senior notes repaid in 2013.
Shelf Registration.
We have a $200.0 million shelf registration statement with the SEC, effective December 13, 2013,
covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. As of
December 31, 2015, $200.0 million remains available for issuance under this shelf registration statement.
However, as a result of our regulatory approvals, we may only issue up to $150.0 million of such securities
in the form of first mortgage bonds, of which $30.0 million remains available after the issuance of
$60.0 million in first mortgage bonds on August 20, 2015 and $60 million on December 1, 2014. Any
proceeds from offerings made pursuant to this shelf would be used to fund capital expenditures, refinance
existing debt or general corporate needs during the effective period through December 2016.
Credit Agreements.
We have in place a $200 million 5-year Credit Agreement which expires in October 2019. This
agreement replaced the former $150 million Third Amended and Restated Unsecured Credit Agreement
that had a January 2017 expiration date. This agreement may be used for working capital, commercial
paper back-up and general corporate purposes. The credit facility includes a $20 million swingline loan
sublimit, a $20 million sublimit for letters of credit issuance and, subject to bank approval, a $75 million
accordion feature and two one-year extensions of the credit facility’s maturity date. See Note 6 of ‘‘Notes
to Consolidated Financial Statements’’ under Item 8 for additional information regarding this agreement
and our unsecured line of credit.
EDE Mortgage Indenture.
Substantially all of the property, plant and equipment of The Empire District Electric Company (but
not its subsidiaries) are subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond
indenture could affect our liquidity. The principal amount of all series of first mortgage bonds outstanding
at any one time under the Indenture of Mortgage and Deed of Trust of The Empire District Electric
Company (EDE Mortgage) is limited by terms of the mortgage to $1.0 billion. Based on the $1.0 billion
limit, and our current level of outstanding first mortgage bonds, we are limited to the issuance of
$297.0 million of new first mortgage bonds. The EDE Mortgage contains a requirement that for new first
mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve
consecutive months within the fifteen months preceding issuance must be two times the annual interest
requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the
prospective issue of new first mortgage bonds. In addition to the interest coverage requirement, the EDE
Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net
property additions. The annual interest coverage requirement and retired bonds or 60% of net property
additions tests would permit the issuance of more than $297.0 million of new first mortgage bonds;
however, as discussed above, we are otherwise limited to the issuance of no more than $297.0 million of
new first mortgage bonds. As of December 31, 2015, we are in compliance with all restrictive covenants of
the EDE Mortgage.
48
EDG Mortgage Indenture.
The principal amount of all series of first mortgage bonds outstanding at any one time under the
Indenture of Mortgage and Deed of Trust of The Empire District Gas Company (EDG Mortgage) is
limited by terms of the mortgage to $300.0 million. Substantially all of the property, plant and equipment
of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage
contains a requirement that for new first mortgage bonds to be issued, the amount of such new first
mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the
Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt
(including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under
working capital facilities) unless, after giving effect to such issuance, EDG’s ratio of EBITDA (defined as
net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest
charges for the most recent four fiscal quarters is at least 2.0 to 1.0. As of December 31, 2015, this test
would allow us to issue approximately $19.5 million principal amount of new first mortgage bonds at an
assumed interest rate of 5.5%. As of December 31, 2015, we are in compliance with all restrictive
covenants of the EDG Mortgage.
Credit Ratings
Corporate credit ratings and the ratings for our securities are as follows:
Moody’s
Standard & Poor’s
Corporate Credit Rating . . . . . . . . . . . . . . . . . . . . . . . . . Baa1
EDE First Mortgage Bonds
Senior Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Baa1
Commercial Paper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . P-2
Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . A2
BBB
A(cid:5)
BBB
A-2
Stable Negative
On March 6, 2015, Moody’s reaffirmed our credit ratings and outlook. On December 15, 2015,
Standard & Poor’s reaffirmed our credit ratings and revised our outlook to developing from stable in light
of the December 13, 2015 announcement regarding our exploration of strategic alternatives. On
February 10, 2016, Standard & Poor’s reaffirmed our credit ratings and revised our outlook to negative
from developing in light of the February 9, 2016 announcement regarding the proposed merger.
On December 1, 2015, we cancelled our relationship with Fitch Ratings. At that time, Fitch’s ratings
for our securities were as follows: First Mortgage Bonds, BBB+; Senior Notes, BBB; Commercial Paper,
F3; Outlook, Stable. Fitch did not provide a Corporate Credit Rating. They last affirmed the ratings
described above on June 12, 2015.
A security rating is not a recommendation to buy, sell or hold securities. Each rating is subject to
revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its
own methodology for assigning ratings, and, accordingly, each rating should be considered independently
of all other ratings.
49
CONTRACTUAL OBLIGATIONS
Set forth below is information summarizing our contractual obligations as of December 31, 2015.
Other pension and postretirement benefit plans are funded on an ongoing basis to match their
corresponding costs, per regulatory requirements, and have been estimated for 2016 – 2020 as noted below.
Contractual Obligations(1)
Payments Due By Period
(in millions)
Total
Less Than
1 Year
1 – 3 Years 3 – 5 Years
More Than
5 Years
Long-term debt (w/o discount) . . . . . . . . . . . . . . . . . $ 860.0
713.7
Interest on long-term debt . . . . . . . . . . . . . . . . . . . .
25.0
Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.2
Capital lease obligations . . . . . . . . . . . . . . . . . . . . . .
Operating lease obligations(2)
2.5
. . . . . . . . . . . . . . . . . .
Electric purchase obligations(3) . . . . . . . . . . . . . . . . .
426.5
Gas purchase obligations(4) . . . . . . . . . . . . . . . . . . . .
87.8
130.9
Open purchase orders . . . . . . . . . . . . . . . . . . . . . . .
10.8
Postretirement benefit obligation funding . . . . . . . . .
35.5
Pension benefit funding . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities(5) . . . . . . . . . . . . . . . . . . .
2.9
$ 25.0
44.8
25.0
0.5
0.7
47.1
10.6
129.5
3.1
10.4
0.1
$ 90.0
82.3
—
1.1
1.3
70.1
19.3
0.1
4.7
14.5
0.3
$100.0
72.0
—
1.1
0.5
45.3
19.3
0.1
3.0
10.6
0.3
$ 645.0
514.6
—
2.5
—
264.0
38.6
1.2
—
—
2.2
TOTAL CONTRACTUAL OBLIGATIONS . . . . . . . . . $2,300.8
$296.8
$283.7
$252.2
$1,468.1
(1) Some of our contractual obligations have price escalations based on economic indices, but we do not
anticipate these escalations to be significant.
(2) Excludes payments under our Elk River Wind Farm, LLC and Cloud County Wind Farm, LLC
agreements, as payments are contingent upon output of the facilities. For additional information, see
Note 11 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8.
Payments under the Elk River Wind Farm, LLC agreement can run from zero up to a maximum of
approximately $16.9 million per year based on a 20 year average cost and an annual output of 550,000
megawatt hours. Payments under the Meridian Way Wind Farm agreement can range from zero to a
maximum of approximately $14.6 million per year based on a 20-year average cost.
(3) Includes a water usage contract for our SLCC facility, fuel and purchased power contracts and
associated transportation costs, as well as purchased power for 2016 through 2039 for Plum Point.
(4) Represents fuel contracts and associated transportation costs of our gas segment.
(5) Other long-term liabilities primarily represent electric facilities charges paid to City Utilities of
Springfield, Missouri of $11,000 per month over 30 years.
DIVIDENDS
Holders of our common stock are entitled to dividends if, as, and when declared by the Board of
Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding
cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of
Directors after considering all relevant factors, including the amount of our retained earnings (which is
essentially our accumulated net income less dividend payouts). A reduction of our dividend per share,
partially or in whole, could have an adverse effect on our common stock price.
50
The following table shows our diluted earnings per share, dividends paid per share, total dividends
paid and retained earnings balance for the years ended December 31, 2015, 2014 and 2013:
(in millions, except per share amounts)
2015
2014
2013
Diluted earnings per share . . . . . . . . . . . . . . . . . . . . . . .
Dividends paid per share . . . . . . . . . . . . . . . . . . . . . . . .
Total dividends paid . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings year-end balance . . . . . . . . . . . . . . . . .
$ 1.29
$ 1.04
$ 45.4
$101.4
$ 1.55
$1.025
$ 44.4
$ 90.3
$ 1.48
$1.005
$ 43.0
$ 67.6
Under Kansas corporate law, our Board of Directors may only declare and pay dividends out of our
surplus or, if there is no surplus, out of our net profits for the fiscal year in which the dividend is declared
or the preceding fiscal year, or both. Our surplus, under Kansas law, is equal to our retained earnings plus
accumulated other comprehensive income/(loss), net of income tax. However, Kansas law does permit,
under certain circumstances, our Board of Directors to transfer amounts from capital in excess of par value
to surplus. In addition, Section 305(a) of the Federal Power Act (FPA) prohibits the payment by a utility of
dividends from any funds ‘‘properly included in capital account’’. There are no additional rules or
regulations issued by the FERC under the FPA clarifying the meaning of this limitation. However, several
decisions by the FERC on specific dividend proposals suggest that any determination would be based on a
fact-intensive analysis of the specific facts and circumstances surrounding the utility and the dividend in
question, with particular focus on the impact of the proposed dividend on the liquidity and financial
condition of the utility.
In addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The
most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay
any dividends (other than dividends payable in shares of our common stock) or make any other
distribution on, or purchase (other than with the proceeds of additional common stock financing) any
shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive
of the first quarterly dividend of $98,000 paid after said date) would exceed the sum of $10.75 million and
the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the
date of succession in the event that another corporation succeeds to our rights and liabilities by a merger
or consolidation. The EDE Mortgage permits the payment of any dividend or distribution on, or purchase
of, shares of our common stock within 60 days after the related date of declaration or notice of such
dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or
purchase would have complied with the provisions of the EDE Mortgage and (ii) as of the last day of the
calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to
total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or
purchase) was not more than 0.625 to 1.
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements that have or are reasonably likely to have a current or
future effect on our financial condition, changes in financial condition, revenues or expenses, results of
operations, liquidity, capital expenditures or capital resources, other than operating leases entered into in
the normal course of business.
CRITICAL ACCOUNTING POLICIES
Set forth below are certain accounting policies that are considered by management to be critical and
that typically require difficult, subjective or complex judgments, often as a result of the need to make
estimates about the effect of matters that are inherently uncertain (other accounting policies may also
require assumptions that could cause actual results to be different than anticipated results). A change in
assumptions or judgments applied in determining the following matters, among others, could have a
material impact on future financial results.
51
Pensions and Other Postretirement Benefits (OPEB). We recognize expense related to pension and other
postretirement benefits as earned during the employee’s period of service. Related assets and liabilities are
established based upon the funded status of the plan compared to the accumulated benefit obligation. Our
pension and OPEB expense or benefit includes amortization of previously unrecognized net gains or
losses. Additional income or expense may be recognized when our unrecognized gains or losses as of the
most recent measurement date exceed 10% of our postretirement benefit obligation or fair value of plan
assets, whichever is greater. For pension benefits and OPEB benefits, unrecognized net gains or losses as
of the measurement date are amortized into actuarial expense over ten years. See Note 1 and Note 7 of
‘‘Notes to Consolidated Financial Statements’’ under Item 8 for further information.
Based on the regulatory treatment of pension and OPEB recovery afforded in our jurisdictions, we
record the amount of unfunded defined benefit pension and postretirement plan obligations as regulatory
assets on our balance sheet rather than as reductions of equity through comprehensive income.
Our funding policy is to contribute annually an amount at least equal to the actuarial cost of
postretirement benefits. The actual minimum pension funding requirements will be determined based on
the results of the actuarial valuations and the performance of our pension assets during the current year.
See Note 7 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8.
Risks and uncertainties affecting the application of our pension accounting policy include: future rate
of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount rates), demographic
assumptions (i.e. mortality and retirement rates) and employee compensation trend rates. Factors that
could result in additional pension expense and/or funding include: a lower discount rate than estimated,
higher compensation rate increases, lower return on plan assets, and longer retirement periods.
Risks and uncertainties affecting the application of our OPEB accounting policy and related funding
include: future rate of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount
rates), healthcare cost trend rates, Medicare prescription drug costs and demographic assumptions
(i.e. mortality and retirement rates). See Note 1 and Note 7 of ‘‘Notes to Consolidated Financial
Statements’’ under Item 8 for further information. We expect future pension and OPEB expense or
benefits are probable of full recovery in our rates, thus lowering our sensitivity to accounting risks and
uncertainties.
Regulatory Assets and Liabilities.
In accordance with the ASC accounting guidance for regulated
activities, our financial statements reflect ratemaking policies prescribed by the regulatory commissions
having jurisdiction over us (Missouri, Kansas, Arkansas, Oklahoma and the FERC).
In accordance with accounting guidance for regulated activities, we record a regulatory asset for all or
part of an incurred cost that would otherwise be charged to expense in accordance with the accounting
guidance, which requires that an asset be recorded if it is probable that future revenue in an amount at
least equal to the capitalized cost will be allowable for costs for rate making purposes and the current
available evidence indicates that future revenue will be provided to permit recovery of the cost.
Additionally, we follow the accounting guidance for regulated activities which says that a liability should be
recorded when a regulator has provided current recovery for a cost that is expected to be incurred in the
future. We follow this guidance for incurred costs or credits that are subject to future recovery from or
refund to our customers in accordance with the orders of our regulators.
Historically, all costs of this nature, which are determined by our regulators to have been prudently
incurred, have been recoverable through rates in the course of normal ratemaking procedures. Regulatory
assets and liabilities are ratably eliminated through a charge or credit, respectively, to earnings while being
recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be
recovered through future revenues. We continually assess the recoverability of our regulatory assets.
Although we believe it unlikely, should retail electric competition legislation be passed in the states we
serve, we may determine that we no longer meet the criteria set forth in the ASC accounting guidance for
52
regulated activities with respect to continued recognition of some or all of the regulatory assets and
liabilities. Any regulatory changes that would require us to discontinue application of ASC accounting
guidance for regulated activities based upon competitive or other events may also impact the valuation of
certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a
material adverse effect on our financial condition and results of operations.
As of December 31, 2015, we have recorded $216.8 million in regulatory assets and $141.1 million as
regulatory liabilities. See Note 3 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8 for
detailed information regarding our regulatory assets and liabilities.
Risks and uncertainties affecting the application of this accounting policy include: regulatory
environment, external regulatory decisions and requirements, anticipated future regulatory decisions and
their impact of deregulation and competition on ratemaking process, unexpected disallowances, possible
changes in accounting standards (including as a result of adoption of IFRS) and the ability to recover costs.
Fuel Adjustment Clause. Typical fuel adjustment clauses permit the distribution to customers of
changes in fuel costs, subject to routine regulatory review, without the need for a general rate proceeding.
Fuel adjustment clauses are presently applicable to our retail electric sales in Missouri, Oklahoma and
Kansas and system wholesale kilowatt-hour sales under FERC jurisdiction. We have an Energy Cost
Recovery Rider in Arkansas that adjusts for changing fuel and purchased power costs on an annual basis.
The MPSC established a base cost in rates for the recovery of fuel and purchased power expenses
used to supply energy. The fuel adjustment clause permits the distribution to our Missouri customers of
95% of the changes in fuel and purchased power costs prudently incurred above or below the base cost.
Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result,
nearly all of the off-system sales margin flows back to the customer.
Unbilled Revenue. At the end of each period we estimate, based on expected usage, the amount of
revenue to record for energy and natural gas that has been provided to customers but not billed. Risks and
uncertainties affecting the application of this accounting policy include: projecting customer energy usage,
estimating the impact of weather and other factors that affect usage (such as line losses) for the unbilled
period and estimating loss of energy during transmission and delivery. Assumptions such as electrical load
requirements, customer billing rates, and line loss factors are used in the estimation process and are
evaluated periodically. Changes to certain assumptions during the evaluation process can lead to a change
in the estimate.
Contingent Liabilities. We are a party to various claims and legal proceedings arising in the ordinary
course of our business, which are primarily related to workers’ compensation and public liability. We
regularly assess our insurance deductibles, analyze litigation information with our attorneys and evaluate
our loss experience. Based on our evaluation as of the end of 2015, we believe that we have accrued
liabilities in accordance with ASC accounting guidance sufficient to meet potential liabilities that could
result from these claims. This liability at December 31, 2015 and 2014 was 3.7 million and $3.6 million,
respectively.
Risks and uncertainties affecting these assumptions include: changes in estimates on potential
outcomes of litigation and potential litigation yet unidentified in which we might be named as a defendant.
Goodwill. As of December 31, 2015, the consolidated balance sheet included $39.5 million of
goodwill. All of this goodwill was derived from our gas business acquisition and recorded in our gas
segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to
test goodwill for impairment on an annual basis or whenever events or circumstances indicate possible
impairment. Absent an indication of fair value from a potential buyer or a similar specific transaction, a
combination of the market and income approaches is used to estimate the fair value of goodwill.
53
Our annual test performed as of October 2015 indicated the estimated fair market value of the gas
reporting unit to be $18 – $22 million higher than its carrying value at that time. While we believe the
assumptions utilized in our analysis were reasonable, adverse developments in future periods could
negatively impact goodwill impairment considerations, which could adversely impact earnings. Specifically,
the quantitative assumptions, such as an increase to the discount rate or decline in the terminal value
calculation could lead to an impairment charge in the future. See Note 1 of ‘‘Notes to Consolidated
Financial Statements’’ under Item 8 for further information.
Use of Management’s Estimates. The preparation of our consolidated financial statements in
conformity with generally accepted accounting principles (GAAP) requires management to make
estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses,
and related disclosure of contingent assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an
on-going basis, including those related to unbilled utility revenues, collectibility of accounts receivable,
depreciable lives, asset impairment and goodwill evaluations, employee benefit obligations, contingent
liabilities, asset retirement obligations, the fair value of stock based compensation and tax provisions.
Actual amounts could differ from those estimates.
RECENTLY ISSUED ACCOUNTING STANDARDS
See Note 1 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8 for further information
regarding Recently Issued and Proposed Accounting Standards.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our fuel procurement activities involve primary market risk exposures, including commodity price risk
and credit risk. Commodity price risk is the potential adverse price impact related to the fuel procurement
for our generating units. Credit risk is the potential adverse financial impact resulting from
non-performance by a counterparty of its contractual obligations. Additionally, we are exposed to interest
rate risk which is the potential adverse financial impact related to changes in interest rates.
Market Risk and Hedging Activities. Prices in the wholesale power markets can be extremely volatile.
This volatility impacts our cost of power purchased and our participation in energy trades. In addition,
congestion on the transmission system can limit our ability to make purchases from (or sell into) the
wholesale markets.
We engage in physical and financial trading activities with the goals of reducing risk from market
fluctuations. In accordance with our established Energy Risk Management Policy, which typically includes
entering into various derivative transactions, we attempt to mitigate our commodity market risk.
Derivatives are utilized to manage our gas commodity market risk. We also acquire Transmission
Congestion Rights (TCR) in an attempt to lessen the cost of power we will purchase from the SPP IM due
to congestion costs. See Note 14 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8 for further
information.
Commodity Price Risk. We are exposed to the impact of market fluctuations in the price and
transportation costs of coal, natural gas, and electricity and employ established policies and procedures to
manage the risks associated with these market fluctuations, including utilizing derivatives.
We satisfied 65.0% of our 2015 generation fuel supply need through coal. Approximately 97% of our
2015 coal supply was Western coal. We have contracts and binding proposals to supply a portion of the fuel
for our coal plants through 2017. These contracts satisfy approximately 100% of our anticipated fuel
requirements for 2016, 46% for 2017 and 23% for 2018 for our Asbury coal plants. In order to manage our
exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and
long-term contracts.
54
We are exposed to changes in market prices for natural gas we must purchase to run our combustion
turbine generators. Our natural gas procurement program is designed to manage our costs to avoid volatile
natural gas prices. We enter into physical forward and financial derivative contracts with counterparties
relating to our future natural gas requirements that lock in prices (with respect to predetermined
percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel
expenditures and improve predictability. As of December 31, 2015, 61%, or 8.6 million Dths, of our
anticipated volume of natural gas usage for our electric operations for 2016 is hedged. See Note 14 of
‘‘Notes to Consolidated Financial Statements’’ under Item 8 for further information.
Based on our expected natural gas purchases for our electric operations for 2016, if average natural
gas prices should increase 10% more in 2016 than the price at December 31, 2015, our natural gas
expenditures would increase by approximately $1.1 million based on our December 31, 2015 total hedged
positions for the next twelve months. However, such an increase would be probable of recovery through
fuel adjustment mechanisms in all of our jurisdictions, which significantly reduces the impact of fluctuating
fuel costs.
We attempt to mitigate a portion of our natural gas price risk associated with our gas segment using
physical forward purchase agreements, storage and derivative contracts. As of December 31, 2015, we have
1.4 million Dths in storage on the three pipelines that serve our customers. This represents 70% of our
storage capacity. We have an additional 0.4 million Dths hedged through financial derivatives and physical
contracts for the balance of the 2015-2016 winter season.
See Note 14 of ‘‘Notes to Consolidated Financial Statements’’ under Item 8 for further information.
Credit Risk.
In order to minimize overall credit risk, we maintain credit policies, including the
evaluation of counterparty financial condition and the use of standardized agreements that facilitate the
netting of cash flows associated with a single counterparty. See Note 14 of ‘‘Notes to Consolidated
Financial Statements’’ under Item 8 regarding agreements containing credit risk contingent features. In
addition, certain counterparties make available collateral in the form of cash held as margin deposits as a
result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction.
Conversely, we are required to post collateral with counterparties at certain thresholds, which is typically
the result of changes in commodity prices. Amounts reported as margin deposit liabilities represent
counterparty funds we hold that result from various trading counterparties exceeding agreed-upon credit
exposure thresholds. Amounts reported as margin deposit assets represent our funds held on deposit for
our NYMEX contracts with our broker and other financial contracts with other counterparties that
resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table
depicts our margin deposit assets at December 31, 2015 and December 31, 2014 (in millions).
Margin deposit assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$11.2
$9.1
There were no margin deposit liabilities at these dates.
Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we
transact with a smaller, less diverse group of counterparties and transactions may involve large notional
volumes and potentially volatile commodity prices. Below is a table showing our net credit exposure at
December 31, 2015, reflecting that our counterparties are exposed to Empire for the net unrealized
2015
2014
55
mark-to-market losses for physical forward and financial natural gas contracts carried at fair value (in
millions).
Net unrealized mark-to-market losses for physical forward natural gas
contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net unrealized mark-to-market losses for financial natural gas contracts . . . .
$ 4.4
8.6
Net credit exposure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$13.0
The $8.6 million net unrealized mark-to-market loss for financial natural gas contracts is comprised
entirely of $8.6 million that our counterparties are exposed to Empire for unrealized losses. We are holding
no collateral from any counterparty since we are below the $10 million mark-to-market collateral threshold
in our agreements. As noted above, as of December 31, 2015, we have $11.2 million on deposit for
NYMEX contract exposure to Empire, of which $10.0 million represents our collateral requirement. If
NYMEX gas prices decreased 25% from their December 31, 2015 levels, our collateral requirement would
increase $8.0 million. If these prices increased 25%, our collateral requirement would decrease
$8.3 million. Our other counterparties would not be required to post collateral with Empire.
We sell electricity and gas and provide distribution and transmission services to a diverse group of
customers, including residential, commercial and industrial customers. Credit risk associated with trade
accounts receivable from energy customers is limited due to the large number of customers. In addition, we
enter into contracts with various companies in the energy industry for purchases of energy-related
commodities, including natural gas in our fuel procurement process.
Interest Rate Risk. We are exposed to changes in interest rates as a result of financing through our
issuance of commercial paper and other short-term debt. We manage our interest rate exposure by limiting
our variable-rate exposure (applicable to commercial paper and borrowings under our unsecured credit
agreement) to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of
market changes in interest rates. See Note 6 of ‘‘Notes to Consolidated Financial Statements’’ under
Item 8 for further information.
If market interest rates average 1% more in 2016 than in 2015, our interest expense would increase,
and income before taxes would decrease by less than $1.0 million. This amount has been determined by
considering the impact of the hypothetical interest rates on our highest month-end commercial paper
balance for 2015. These analyses do not consider the effects of the reduced level of overall economic
activity that could exist in such an environment. In the event of a significant change in interest rates,
management would likely take actions to further mitigate its exposure to the change. However, due to the
uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis
assumes no changes in our financial structure.
56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
of the Empire District Electric Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15
present fairly, in all material respects, the financial position of The Empire District Electric Company and
its subsidiaries at December 31, 2015 and December 31, 2014, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2015 in conformity with
accounting principles generally accepted in the United States of America. In addition, in our opinion, the
financial statement schedule listed in the index appearing under Item 15 presents fairly, in all material
respects, the information set forth therein when read in conjunction with the related consolidated financial
statements. Also in our opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2015, based on criteria established in Internal
Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company’s management is responsible for these financial statements
and financial statement schedule, for maintaining effective internal control over financial reporting and for
its assessment of the effectiveness of internal control over financial reporting, included in the
accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is
to express opinions on these financial statements, on the financial statement schedule, and on the
Company’s internal control over financial reporting based on our integrated audits. We conducted our
audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audits to obtain reasonable assurance about
whether the financial statements are free of material misstatement and whether effective internal control
over financial reporting was maintained in all material respects. Our audits of the financial statements
included examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. Our audit of internal control over financial
reporting included obtaining an understanding of internal control over financial reporting, assessing the
risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audits also included performing such other procedures as
we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for
our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that (i) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the
assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles,
and that receipts and expenditures of the company are being made only in accordance with authorizations
of management and directors of the company; and (iii) provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have
a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk
that controls may become inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2016
57
THE EMPIRE DISTRICT ELECTRIC COMPANY
Consolidated Balance Sheets
December 31,
2015
2014
($-000’s)
Assets
Plant and property, at original cost:
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Construction work in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,473,927
83,402
44,263
183,689
$2,420,824
79,364
41,394
112,097
Accumulated depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . .
2,785,281
764,895
2,653,679
743,407
2,020,386
1,910,272
Current assets:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable — trade, net of allowance of $623 and $1,021,
respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued unbilled revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable — other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel, materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized gain in fair value of derivative contracts . . . . . . . . . . . . . . . .
Regulatory assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,753
4,726
40,162
20,653
28,320
60,950
8,835
1,295
7,052
2,105
4,726
45,444
25,945
41,256
57,799
8,679
3,901
10,752
Noncurrent assets and deferred charges:
Regulatory assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized gain in fair value of derivative contracts . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
173,746
200,607
209,708
39,492
8,658
16
3,297
261,171
209,717
39,492
8,821
—
2,147
260,177
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,455,303
$2,371,056
(Continued)
The accompanying notes are an integral part of these consolidated financial statements.
58
THE EMPIRE DISTRICT ELECTRIC COMPANY
Consolidated Balance Sheets (Continued)
December 31,
2015
2014
($-000’s)
Capitalization and liabilities
Common stock, $1 par value, 100,000,000 shares authorized, 43,820,726 and
43,479,186 shares issued and outstanding, respectively . . . . . . . . . . . . . .
Capital in excess of par value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total common stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
43,821
657,466
101,443
802,730
$
43,479
649,543
90,276
783,298
Long-term debt (net of current portion)
Obligations under capital lease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
First mortgage bonds and secured debt . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unsecured debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,580
732,653
101,714
837,947
3,875
697,615
101,699
803,189
Total long-term debt and common stockholders’ equity . . . . . . . . . . . . . . .
1,640,677
1,586,487
Current liabilities:
Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . .
Current maturities of long-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest accrued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized loss in fair value of derivative contracts . . . . . . . . . . . . . . . . . .
Taxes accrued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
66,946
25,310
25,000
8,615
14,623
7,348
4,472
2,832
323
83,420
292
44,000
7,898
13,747
6,565
6,469
3,380
206
Commitments and contingencies (Note 11)
Noncurrent liabilities and deferred credits:
Regulatory liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized investment tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension and other postretirement benefit obligations . . . . . . . . . . . . . . . . .
Unrealized loss in fair value of derivative contracts . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
155,469
165,977
132,457
396,542
18,487
82,144
3,696
25,831
659,157
128,471
358,252
18,517
93,863
3,243
16,246
618,592
Total capitalization and liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,455,303
$2,371,056
The accompanying notes are an integral part of these consolidated financial statements.
59
THE EMPIRE DISTRICT ELECTRIC COMPANY
Consolidated Statements of Income
Year Ended December 31,
2015
2014
2013
(000’s, except per share amounts)
Operating revenues:
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$555,085
41,702
8,786
$592,491
51,842
7,997
$536,413
50,041
7,876
605,573
652,330
594,330
Operating revenue deductions:
Fuel and purchased power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of natural gas sold and transported . . . . . . . . . . . . . . . . . . . .
Regulated operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maintenance and repairs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on plant disallowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
169,860
19,502
113,551
3,309
48,522
—
80,550
34,800
39,178
215,086
27,025
110,691
2,987
46,775
86
73,185
39,398
37,098
175,406
25,795
105,333
3,142
40,873
2,409
69,306
37,465
34,938
509,272
552,331
494,667
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
96,301
99,999
99,663
Other income and (deductions):
Allowance for equity funds used during construction . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefit/(provision) for other income taxes . . . . . . . . . . . . . . . . . . .
Other — non-operating expense, net . . . . . . . . . . . . . . . . . . . . . . .
Interest charges:
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for borrowed funds used during construction . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,850
145
988
(3,429)
2,554
43,802
266
(2,845)
1,035
6,420
51
178
(1,302)
5,347
40,637
113
(3,497)
990
3,853
566
(27)
(1,218)
3,174
40,354
60
(2,087)
1,065
42,258
38,243
39,392
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 56,597
$ 67,103
$ 63,445
Weighted average number of common shares outstanding — basic . . .
Weighted average number of common shares outstanding — diluted .
Total earnings per weighted average share of common stock — basic .
Total earnings per weighted average share of common stock —
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends declared per share of common stock . . . . . . . . . . . . . . . . .
43,671
43,718
1.30
1.29
1.04
$
$
$
43,291
43,314
1.55
1.55
1.025
$
$
$
42,781
42,803
1.48
1.48
1.005
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
60
THE EMPIRE DISTRICT ELECTRIC COMPANY
Consolidated Statements of Common Stockholders’ Equity
Balance at December 31, 2012 . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock/stock units issued through:
Stock purchase and reinvestment plans . . . . . . . . . . .
Dividends declared . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at December 31, 2013 . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock/stock units issued through:
Stock purchase and reinvestment plans . . . . . . . . . . .
Dividends declared . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at December 31, 2014 . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock/stock units issued through:
Stock purchase and reinvestment plans . . . . . . . . . . .
Dividends declared . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common
Stock
Capital in
excess of Par
Retained
earnings
Total
($-000’s)
$42,484
$628,199
$ 47,115
63,445
$717,798
63,445
560
11,326
43,044
639,525
435
10,018
43,479
649,543
342
7,923
(43,006)
67,554
67,103
(44,381)
90,276
56,597
(45,430)
11,886
(43,006)
750,123
67,103
10,453
(44,381)
783,298
56,597
8,265
(45,430)
Balance at December 31, 2015 . . . . . . . . . . . . . . . . . . . .
$43,821
$657,466
$101,443
$802,730
The accompanying notes are an integral part of these consolidated financial statements.
61
THE EMPIRE DISTRICT ELECTRIC COMPANY
Consolidated Statements of Cash Flows
Year Ended December 31,
2015
2014
($-000’s)
2013
Operating activities:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 56,597
$ 67,103
$ 63,445
Adjustments to reconcile net income to cash flows from operating
activities:
Depreciation and amortization including regulatory items . . . . . . . .
Pension and other postretirement benefit costs, net of contributions
Deferred income taxes and unamortized investment tax credit, net .
Allowance for equity funds used during construction . . . . . . . . . . .
Stock compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on plant disallowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash loss on derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory reversal of gain on sale of assets . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues . . . . . . . . . . . .
Fuel, materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses, other current assets and deferred charges . . . . . .
Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest, taxes accrued and customer deposits . . . . . . . . . . . . . . . .
Other liabilities and other deferred credits . . . . . . . . . . . . . . . . . .
88,801
(9,184)
36,617
(4,850)
4,082
—
6,994
—
(625)
16,514
(3,151)
(4,863)
(8,630)
(73)
1,111
5,492
82,754
1,973
41,693
(6,420)
4,057
86
1,245
44
—
(24,174)
(8,121)
(6,051)
1,141
(1,326)
1,411
(4,192)
71,734
(1,888)
28,272
(3,853)
2,984
2,409
14
1,236
—
(14,312)
10,891
689
(880)
(734)
1,386
(3,942)
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . .
184,832
151,223
157,451
(Continued)
The accompanying notes are an integral part of these consolidated financial statements.
62
THE EMPIRE DISTRICT ELECTRIC COMPANY
Consolidated Statements of Cash Flows (Continued)
Year Ended December 31,
2015
2014
($-000’s)
2013
Investing activities:
Capital expenditures — regulated . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures and other investments — non-regulated . . .
Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(183,206) $(211,429) $(152,524)
(2,259)
1,485
(1,998)
(1,854)
(2,243)
—
Total net cash used in investing activities . . . . . . . . . . . . . . . . . . .
(185,449)
(215,281)
(153,298)
Financing activities:
Proceeds from first mortgage bonds, net . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt issuance costs
Proceeds from issuance of common stock, net of issuance costs
.
Redemption of senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net short-term borrowings (repayments) . . . . . . . . . . . . . . . . . .
Dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by / (used) in financing activities . . . . . . . . . . .
Net increase (decrease) in cash and cash equivalents . . . . . . . . . .
Cash and cash equivalents, beginning of year . . . . . . . . . . . . . . . .
60,000
(818)
5,513
—
(19,000)
(45,430)
—
265
(352)
2,105
60,000
(651)
7,994
—
40,000
(44,381)
(274)
62,688
(1,370)
3,475
Cash and cash equivalents, end of year . . . . . . . . . . . . . . . . . . . .
$
1,753
$
2,105
$
150,000
(1,879)
9,546
(98,000)
(20,000)
(43,006)
(714)
(4,053)
100
3,375
3,475
2015
2014
2013
Supplemental cash flow information:
Interest paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (refunded) paid, net of refund . . . . . . . . . . . . . . .
$ 42,858
(17,256)
$ 40,127
23,103
$ 39,033
10,584
Supplementary non-cash investing activities:
Change in accrued additions to property, plant and equipment
not reported above . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . .
Capital lease obligations for purchase of new equipment
$
$
(8,924) $
17
9,427
—
$
5,420
—
The accompanying notes are an integral part of these consolidated financial statements.
63
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
We operate our businesses as three segments: electric, gas and other. The Empire District Electric
Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the
generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas,
Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in
Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary engaged in the
distribution of natural gas in Missouri. Our other segment consists of our fiber optics business. See
Note 12. Our gross operating revenues in 2015 were derived as follows:
Electric segment sales* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
On-system revenues
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPP IM revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas segment sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other segment sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
86.6%
2.5
2.3
91.7%
6.9
1.4
*
Sales from our electric segment include 0.3% from the sale of water.
The utility portions of our business are subject to regulation by the Missouri Public Service
Commission (MPSC), the State Corporation Commission of the State of Kansas (KCC), the Corporation
Commission of Oklahoma (OCC), the Arkansas Public Service Commission (APSC) and the Federal
Energy Regulatory Commission (FERC). Our accounting policies are in accordance with the ratemaking
practices of the regulatory authorities and conform to generally accepted accounting principles as applied
to regulated public utilities.
Our electric operations serve approximately 170,000 customers as of December 31, 2015, and the 2015
electric operating revenues were derived as follows:
Customer Class
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale on-system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale off-system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous sources, primarily public authorities . . . . . . . . . . . . . . . .
Other electric revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Our retail electric revenues for 2015 by jurisdiction were as follows:
Jurisdiction
Missouri . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
% of revenue
41.7%
31.1
15.9
3.3
2.7
2.8
2.5
% of revenue
89.0%
4.8
2.8
3.4
64
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Our gas operations serve approximately 43,200 customers as of December 31, 2015, and the 2015 gas
operating revenues were derived as follows:
Customer Class
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
% of revenue
63.0%
25.6
0.8
8.9
1.7
Basis of Presentation
The consolidated financial statements include the accounts of EDE, EDG, and our other subsidiaries.
The consolidated entity is referred to throughout as ‘‘we’’ or the ‘‘Company’’. All intercompany balances
and transactions have been eliminated in consolidation. See Note 12 for additional information regarding
our three segments. Certain immaterial reclassifications have been made to prior year information to
conform to the current year presentation.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles
(GAAP) requires management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial
statements. Estimates also affect the reported amounts of revenues and expenses during the period. Areas
in the financial statements significantly affected by estimates and assumptions include unbilled utility
revenues, collectability of accounts receivable, depreciable lives, asset impairment and goodwill
impairment evaluations, employee benefit obligations, contingent liabilities, asset retirement obligations,
the fair value of stock based compensation, and tax provisions. Actual amounts could differ from those
estimates.
Accounting for the Effects of Regulation
In accordance with the Accounting Standard Codification (ASC) guidance for regulated operations,
our financial statements reflect ratemaking policies prescribed by the regulatory commissions having
jurisdiction over our regulated generation and other utility operations (the MPSC, the KCC, the OCC, the
APSC and the FERC).
We record a regulatory asset for all or part of an incurred cost that would otherwise be charged to
expense in accordance with the ASC guidance for regulated operations which says that an asset should be
recorded if it is probable that future revenue in an amount at least equal to the capitalized cost will be
allowable for costs for rate making purposes and the current available evidence indicates that future
revenue will be provided to permit recovery of the cost. This guidance also indicates that a liability should
be recorded when a regulator has provided current recovery for a cost that is expected to be incurred in the
future. We follow this guidance for incurred costs or credits that are subject to future recovery from or
refund to our customers in accordance with the orders of our regulators.
Historically, all costs of this nature, which are determined by our regulators to have been prudently
incurred, have been recoverable through rates in the course of normal ratemaking procedures. Regulatory
assets and liabilities are ratably amortized through a charge or credit, respectively, to earnings while being
recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be
65
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
recovered through future revenues. We generally include amortization of regulatory assets and liabilities in
the depreciation and amortization line of our statement of cash flows. We continually assess the
recoverability of our regulatory assets. Although we believe it unlikely, should retail electric competition
legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth
in the ASC guidance for regulated operations with respect to continued recognition of some or all of the
regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of
this guidance based upon competitive or other events may also impact the valuation of certain utility plant
investments. Impairment of regulatory assets or utility plant investments could have a material adverse
effect on our financial condition and results of operations. (See Note 3 for further discussion of regulatory
assets and liabilities)
Revenue Recognition
For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for services
provided between the last bill date and the period end date. Unbilled revenues represent the estimate of
receivables for energy and natural gas services delivered, but not yet billed to customers. The accuracy of
our unbilled revenue estimate is affected by factors including fluctuations in energy demands, weather, line
losses and changes in the composition of customer classes.
Municipal Franchise Taxes
Municipal franchise taxes are collected for and remitted to their respective entities and are included in
operating revenues and other taxes in the Consolidated Statements of Income. Municipal franchise taxes
of $11.4 million, $11.8 million and $11.2 million were recorded for each of the years ended December 31,
2015, 2014 and 2013, respectively.
Accounts Receivable
Accounts receivable are recorded at the tariffed rates for customer usage, including applicable taxes
and fees and do not bear interest. We review the outstanding accounts receivable monthly, as well as the
bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account
balances are charged off against the allowance when management determines it is probable the receivable
will not be recovered.
Property, Plant & Equipment
The costs of additions to utility property and replacements for retired property units are capitalized.
Costs include labor, material, an allocation of general and administrative costs, and an allowance for funds
used during construction (AFUDC). The original cost of units retired or disposed of and the costs of
removal are charged to accumulated depreciation, unless the removed property constitutes an operating
unit or system. In this case a gain or loss is recognized upon the disposal of the asset. Maintenance
expenditures and the removal of minor property items are charged to income as incurred. A liability is
created for any additions to electric or gas utility property that are paid for by advances from developers.
For a period of five years we refund to the developer a pro rata amount of the original cost of the extension
for each new customer added to the extension. Nonrefundable payments at the end of the five year period
are applied as a reduction to the cost of the plant in service. The liability as of December 31, 2015 and 2014
was $2.1 million and $1.9 million, respectively.
66
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Depreciation
Provisions for depreciation are computed at straight-line rates in accordance with GAAP consistent
with rates approved by regulatory authorities. These rates are applied to the various classes of utility assets
on a composite basis. Provisions for depreciation for our other segment are computed at straight-line rates
over the estimated useful life of the properties (See Note 2 for additional details regarding depreciation
rates).
As of December 31, 2015 and 2014, we had recorded accrued cost of removal of $85.4 million and
$82.8 million, respectively, for our electric operating segment. This represents an estimated cost of
dismantling and removing plant from service upon retirement, accrued as part of our depreciation rates.
We accrue cost of removal in depreciation rates for mass property (including transmission, distribution and
general plant assets). These accruals are not considered an asset retirement obligation under the guidance
provided on asset retirement obligations within the ASC. We reclassify the accrued cost of dismantling and
removing plant from service upon retirement from accumulated depreciation to a regulatory liability. We
have a similar cost of removal regulatory liability for our gas operating segment. This amount at
December 31, 2015 and 2014 was $8.8 million and $7.7 million, respectively. These amounts are net of our
actual cost of removal expenditures.
Asset Retirement Obligation
We record the estimated fair value of legal obligations associated with the retirement of tangible
long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as
part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset
retirement obligations based on changes in estimated fair value, and the corresponding increases in asset
book values are depreciated over the useful life of the related asset. Uncertainties as to the probability,
timing or cash flows associated with an asset retirement obligation affect our estimate of fair value.
We have identified asset retirement obligations associated with the future removal of certain river
water intake structures and equipment at the Iatan Power Plant, in which we have a 12% ownership. We
also have a solid waste land fill at the Plum Point Energy Station, and asset retirement obligations
associated with the removal of asbestos located at the Riverton and Asbury Plants. As a result of the fuel
use transition from coal to natural gas at the Riverton Power Plant, the closure of the Riverton ash landfill
was completed, and the related asset retirement obligation was settled during 2014 (Note 11). During 2015
the EPA established a final rule to regulate the disposal of coal combustion residuals (CCRs). As a result
of these new rules, an asset retirement obligation of $5.4 million has been recorded for the final closure of
the existing ash impoundment at our Asbury Power Plant. Separately, an asset retirement obligation of
$4.4 million has been recorded for our interest in the coal ash impoundment at the Iatan Generating
Station.
In addition, we have a liability for the removal and disposal of Polychlorinated Biphenyls (PCB)
contaminants associated with our transformers and substation equipment. These liabilities have been
estimated based upon either third party costs or historical review of expenditures for the removal of similar
past liabilities. The potential costs of these future expenditures are based on engineering estimates of third
party costs to remove the assets in satisfaction of the associated obligations. This liability will be accreted
over the period up to the estimated settlement date.
All of our recorded asset retirement obligations have been estimated as of the expected retirement
date, or settlement date, and have been discounted using a credit adjusted risk-free rate ranging from 4.5%
to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the
cost estimates, anticipated timing of settlement or federal or state regulatory requirements. During 2014
67
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
the liability for asbestos at the Riverton Power Plant was re-evaluated. Changes in the cost estimates and
timing resulted in cash flow revisions for these liabilities.
The balances at the end of 2015 and 2014 are shown below.
(000’s)
Liability
Balance
12/31/14
Liabilities
Recognized
Liabilities
Settled
Accretion
Cash Flow
Revisions
Liability
Balance at
12/31/15
Asset Retirement Obligation . . . . . . . .
$4,847
$9,812
$(73)
$486
$ —
$15,072
(000’s)
Liability
Balance
12/31/13
Liabilities
Recognized
Liabilities
Settled
Accretion
Cash Flow
Revisions
Liability
Balance at
12/31/14
Asset Retirement Obligation . . . . . . . .
$4,190
$ —
$(1,175)
$172
$1,660
$4,847
Upon adoption of the standards on the retirement of long lived assets and conditional asset
retirement obligations, we recorded a liability and regulatory asset because we expect to recover these costs
of removal in electric and gas rates either through depreciation accruals or direct expenses. We also defer
the liability accretion and depreciation expense as a regulatory asset. At December 31, 2015 and 2014, our
regulatory assets relating to asset retirement obligations totaled $7.7 million and $5.1 million, respectively.
Also as noted previously under property, plant and equipment, we reclassify the accrued cost of
dismantling and removing plant from service upon retirement, which is not considered an asset retirement
obligation under this guidance, from accumulated depreciation to a regulatory liability. This balance sheet
reclassification has no impact on results of operations.
Allowance for Funds Used During Construction
As provided in the FERC regulatory Uniform System of Accounts, utility plant is recorded at original
cost, including an allowance for funds used during construction (AFUDC) when first placed in service. The
AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity
funds applicable to construction programs are capitalized as a cost of construction. This accounting
practice offsets the effect on earnings of the cost of financing current construction, and treats such
financing costs in the same manner as construction charges for labor and materials.
AFUDC does not represent current cash income. Recognition of this item as a cost of utility plant is
in accordance with regulatory rate practice under which such plant costs are permitted as a component of
rate base and the provision for depreciation.
In accordance with the methodology prescribed by the FERC, we utilized aggregate rates (on a
before-tax basis) of 5.5% for 2015, 6.6% for 2014, and 7.3% for 2013, compounded semiannually.
Asset Impairments (excluding goodwill)
We review long-lived assets for impairment whenever events or changes in circumstances indicate that
the carrying amount of an asset may not be recoverable. To the extent that certain assets may be impaired,
analysis is performed based on undiscounted forecasted cash flows to assess the recoverability of the assets
and, if necessary, the fair value is determined to measure the impairment amount. None of our assets were
impaired as of December 31, 2015 and 2014.
68
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Goodwill
As of December 31, 2015, the consolidated balance sheet included $39.5 million of goodwill. All of
this goodwill was derived from our gas acquisition and recorded in our gas segment, which is also the
reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for
impairment on an annual basis or whenever events or circumstances indicate possible impairment. Absent
an indication of fair value from a potential buyer or a similar specific transaction, a combination of the
market and income approaches is used to estimate the fair value of goodwill.
We use the market approach which estimates fair value of the gas reporting unit by comparing certain
financial metrics to comparable companies. Comparable companies whose securities are actively traded in
the public market are judgmentally selected by management based on operational and economic
similarities. We utilize EBITDA (earnings before interest, taxes, depreciation, and amortization) multiples
of the comparable companies in relation to the EBITDA results of the gas reporting unit to determine an
estimate of fair value.
We also utilize a valuation technique under the income approach which estimates the discounted
future cash flows of operations. Our procedures include developing a baseline test and performing
sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived from altering
those assumptions which are subjective in nature and inherent to a discounted cash flows calculation.
Other qualitative factors and comparisons to industry peers are also used to further support the
assumptions and ultimately the overall evaluation. A key qualitative assumption considered in our
evaluation is the impact of regulation, including rate regulation and cost recovery for the gas reporting
unit. Some of the key quantitative assumptions included in our tests involve: regulatory rate design and
results; the discount rate; the growth rate; capital spending rates and terminal value calculations. If
negative changes occurred to one or more key assumptions, an impairment charge could result. With the
exception of the capital spending rate, the key assumptions noted are significantly determined by market
factors and significant changes in market factors that impact the gas reporting unit would somewhat be
mitigated by our current and future regulatory rate design. Other risks and uncertainties affecting these
assumptions include: changes in business, industry, laws, technology and economic conditions. Actual
results for the gas reporting unit indicate a slight decline in gas customer count and demand. A continued
decline in customer count or demand coupled with an increase in the discount rate would have adverse
impacts on the valuation and could result in an impairment charge in the future. Our forecasts anticipate
relatively flat customer counts over the next several years.
We weight the results of the two approaches discussed above in order to estimate the fair value of the
gas reporting unit. Our annual test performed as of October 2015 indicated the estimated fair market value
of the gas reporting unit to be $18 – $22 million higher than its carrying value at that time. While we
believe the assumptions utilized in our analysis were reasonable, adverse developments in future periods
could negatively impact goodwill impairment considerations, which could adversely impact earnings.
Specifically, the quantitative assumptions noted previously, such as an increase to the discount rate or
decline in the terminal value calculation could lead to an impairment charge in the future.
Fuel and Purchased Power
Electric Segment
Fuel and purchased power costs are recorded at the time the fuel is used, or the power purchased.
SPP Integrated Marketplace purchased power is also included in fuel and purchased power costs. The net
effects of our SPP IM activity, including SPP IM net revenue and net purchased power costs, flow through
our fuel recovery mechanisms in each state.
69
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
In our Missouri jurisdiction, the MPSC establishes a base cost for the recovery of fuel and purchased
power expenses used to supply energy for our fuel adjustment clause (FAC). Beginning with our 2015 rate
order, certain transmission costs are also included in the base cost. The FAC permits the distribution to
customers of 95% of the changes in fuel and purchased power costs prudently incurred above or below the
base cost. Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a
result, nearly the entire off-system sales margin flows back to the customer. Rates related to the fuel
adjustment clause are modified twice a year subject to the review and approval by the MPSC. In
accordance with the ASC guidance for regulated operations, 95% of the difference between the actual
costs of fuel and purchased power and the base cost of fuel and purchased power recovered from our
customers is recorded as an adjustment to fuel and purchased power expense with a corresponding
regulatory asset or regulatory liability. If the actual fuel and purchased power costs are higher or lower
than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered
from or refunded to our customers when the fuel adjustment clause is modified.
In our Kansas jurisdiction, the costs of fuel are recovered from customers through a fuel adjustment
clause, based upon estimated fuel costs and purchased power. The adjustments are subject to audit and
final determination by regulators. The difference between the costs of fuel used and the cost of fuel
recovered from our Kansas customers is recorded as a regulatory asset or a regulatory liability if the actual
costs are higher or lower than the costs billed to customers, in accordance with the ASC guidance for
regulated operations.
Similar fuel recovery mechanisms are in place for our Oklahoma, Arkansas and FERC jurisdictions.
At December 31, 2015 and 2014, our Missouri, Kansas and Oklahoma fuel and purchased power costs
were in a net over-recovered position by $5.9 million and a net under-recovered position of $3.1 million,
respectively, which are reflected in our regulatory assets and liabilities.
We receive the renewable attributes associated with the power purchased through our purchased
power agreements with Elk River Windfarm LLC and Cloud County Windfarm, LLC. These renewable
attributes are converted into renewable energy credits (REC), which are considered inventory, and
recorded at zero cost (See Note 11). Revenue from the sale of RECs reduces fuel and purchased power
expense.
We have a Stipulation and Agreement with the MPSC granting us authority to manage our emissions
allowance inventory in accordance with our Plan for Purchasing and Selling Emissions Allowances
(PPSEMA). The PPSEMA allows us to purchase allowances needed for compliance, exchange banked
allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell
allowances outright for monetary value. For compliance year 2015 we did not exchange or sell any
allowances, and for compliance year 2014 we purchased 69 NOx annual allowances for compliance. We
classify our allowances as inventory and they are recorded at cost, with allocated allowances being recorded
at zero cost. The allowances are removed from inventory on a FIFO basis, and used allowances are
considered to be a part of fuel expense (See Note 11). We had the following emissions allowances in
inventory at December 31, 2015 and 2014:
Emission Allowances in Inventory
Acid Rain SO2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CSAPR SO2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CSAPR NOx (annual) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CSAPR NOx (seasonal) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015
2014
872
11,443
5,861 —
500 —
241 —
70
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Gas Segment
Fuel expense for our gas segment is recognized when the natural gas is delivered to our customers,
based on the current cost recovery allowed in rates. A Purchased Gas Adjustment (PGA) clause allows
EDG to recover from our customers, subject to audit and final determination by regulators, the cost of
purchased gas supplies and related carrying costs associated with the Company’s use of natural gas
financial instruments to hedge the purchase price of natural gas. This PGA clause allows us to make rate
changes periodically (up to four times) throughout the year in response to weather conditions and supply
demands, rather than in one possibly extreme change per year.
We calculate the PGA factor based on our best estimate of our annual gas costs and volumes
purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the MPSC.
Elements considered part of the PGA factor include cost of gas supply, storage costs, hedging contracts,
revenue and refunds, prior period adjustments and transportation costs.
Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs
recovered through the application of the PGA (including costs, cost reductions and carrying costs
associated with the use of financial instruments) are reflected as a regulatory asset or liability. The balance
is amortized as amounts are reflected in customer billings.
Derivatives
We utilize derivatives to help manage our natural gas commodity market risk resulting from
purchasing natural gas, to be used as fuel in our electric business or sold in our natural gas business, on the
spot market and to manage certain interest rate exposure. We also acquire Transmission Congestion Rights
(TCR) in an attempt to mitigate congestion costs associated with the power we purchase from the SPP
Integrated Marketplace (see Note 14).
Electric Segment
Pursuant to the ASC guidance on accounting for derivative instruments and hedging activities,
derivatives are required to be recognized on the balance sheet at their fair value. On the date a derivative
contract is entered into, the derivative is designated as (1) a hedge of a forecasted transaction or of the
variability of cash flows to be received or paid related to a recognized asset or liability (‘‘cash-flow’’ hedge);
or (2) an instrument that is held for non-hedging purposes (a ‘‘non-hedging’’ instrument). We record the
mark-to-market gains or losses on derivatives used to hedge our fuel and congestion costs as regulatory
assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those
regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism.
We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and
purchased power. These contracts, if they meet the definition of a derivative, are not subject to derivative
accounting because they are considered to be normal purchase normal sales (NPNS) transactions. If these
transactions don’t qualify for NPNS treatment, they would be marked to market for each reporting period
through regulatory assets or liabilities.
Gas Segment
Financial hedges for our natural gas business are recorded at fair value on our balance sheet. Because
we have a commission approved natural gas cost recovery mechanism (PGA), we record the
mark-to-market gain/loss on natural gas financial hedges each reporting period to a regulatory asset/
liability account. The regulatory asset/liability account tracks the difference between revenues billed to
71
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
customers for natural gas costs and actual natural gas expense which is trued up at the end of August each
year and included in the Actual Cost Adjustment (ACA) factor to be billed to customers during the next
year. This is consistent with the ASC guidance on regulated operations, in that we will be recovering our
costs after the annual true up period (subject to a prudency review by the MPSC).
Cash flows from hedges for both electric and gas segments are classified within cash flows from
operations.
Pension and Other Postretirement Benefits
We recognize expense related to pension and other postretirement benefits (OPEB) as earned during
the employee’s period of service. Related assets and liabilities are established based upon the funded status
of the plan compared to the projected benefit obligation. Our pension and OPEB expense or benefit
includes amortization of previously unrecognized net gains or losses. Additional income or expense may be
recognized when our unrecognized gains or losses as of the most recent measurement date exceed 10% of
our postretirement benefit obligation or fair value of plan assets, whichever is greater. For pension benefits
and OPEB benefits, unrecognized net gains or losses as of the measurement date are amortized into
actuarial expense over ten years.
Pensions
We have rate orders with Missouri, Kansas and Oklahoma that allow us to recover pension costs
consistent with our GAAP policy noted above. In accordance with the rate orders, we prospectively
calculate the value of plan assets using a market-related value method as allowed by the ASC guidance on
pension benefits. As a result, we are allowed to record the Missouri, Kansas and Oklahoma portion of any
costs above or below the amount included in rates as a regulatory asset or liability, respectively. The MPSC
has allowed us to adopt this pension cost recovery methodology for EDG as well.
Other Postretirement Benefits (OPEB)
We have regulatory treatment for our OPEB costs similar to the treatment described above for
pension costs. This includes the use of a market-related value of assets, the amortization of unrecognized
gains or losses into actuarial expense over ten years and the recognition of regulatory assets and liabilities
as described above.
Additional guidance in the ASC on employers’ accounting for defined benefit pension and other
postretirement plans requires an employer to recognize the over funded or underfunded status of a
defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its
statement of financial position and to recognize changes in that funded status in the year in which the
changes occur through comprehensive income of a business entity. The guidance also requires an employer
to measure the funded status of a plan as of the date of its year-end statement of financial position, with
limited exceptions. Pension and other postretirement employee benefits tracking mechanisms are utilized
to allow for future rate recovery of these obligations. We record these as regulatory assets on the balance
sheet rather than as reductions of equity through comprehensive income (See Note 7).
Unamortized Debt Discount, Premium and Expense
Discount, premium and expense associated with long-term debt are amortized over the lives of the
related issues. Costs, including gains and losses, related to refunded long-term debt are amortized over the
lives of the related new debt issues, in accordance with regulatory rate practices.
72
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Liability Insurance
We are primarily self-insured for workers’ compensation claims, general liabilities, benefits paid under
employee healthcare programs and long-term disability benefits. Accruals are primarily based on the
estimated undiscounted cost of claims. We self-insure up to certain limits that vary by segment and type of
risk. Periodically, we evaluate the level of insurance coverage over the self-insured limits and adjust
insurance levels based on risk tolerance and premium expense. We carry excess liability insurance for
workers’ compensation and public liability claims for our electric segment. In order to provide for the cost
of losses not covered by insurance, an allowance for injuries and damages is maintained based on our loss
experience. Our gas segment is covered by excess liability insurance for public liability claims, and workers’
compensation claims are covered by a guaranteed cost policy (See Note 11).
Other Noncurrent Liabilities
Other noncurrent liabilities are comprised of accruals and other accounting estimates not sufficiently
large enough to merit individual disclosure. At December 31, 2015, the balance of other noncurrent
liabilities is primarily comprised of accruals for self-insurance, customer advances for construction and
asset retirement obligations.
Cash & Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments purchased with an initial
maturity of three months or less. It also includes checks and electronic funds transfers that have been
issued but have not cleared the bank, which are also reflected in current accrued liabilities and were
$23.2 million and $28.3 million at December 31, 2015 and 2014, respectively.
Restricted Cash
As part of our Plum Point ownership agreement, we are required to have funds available in an escrow
account which guarantees payment of certain operating costs. The cash is held at a financial institution and
restricted as to withdrawal or use. The amounts restricted, which were $1.8 million at December 31, 2015
and 2014, may increase or decrease based on an annual review.
We are required to post cash collateral with Southwest Power Pool (SPP) to participate in
Transmission Congestion Rights (TCR) auctions. The cash is held at a financial institution and restricted
as to withdrawal or use. The amounts of such restricted cash were $2.5 million at December 31, 2015 and
2014.
Due to our Plum Point energy station interconnection with Midcontinent Independent System
Operator (MISO), we participate in Financial Transmission Rights (FTR) auctions which require us to
post cash collateral. The cash is held at a financial institution and restricted as to withdrawal or use. The
amounts of such restricted cash were $0.5 million at December 31, 2015 and 2014.
73
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Fuel, Materials and Supplies
Fuel, materials and supplies consist primarily of coal, natural gas in storage and materials and
supplies, which are reported at average cost. These balances are as follows (in thousands):
Electric fuel inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$30,185
3,868
26,897
$26,454
5,040
26,305
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$60,950
$57,799
2015
2014
Income Taxes
Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have
been treated differently for financial reporting and tax return purposes; measured using statutory tax rates
(See Note 9).
Investment tax credits utilized in prior years were deferred and are being amortized over the useful
lives of the properties to which they relate. The longest remaining amortization period for investment tax
credits is approximately 55 years.
Accounting for Uncertainty in Income Taxes
In 2006, the FASB issued guidance which clarifies the accounting for uncertainty in income taxes
recognized in an enterprise’s financial statements in accordance with the ASC guidance on accounting for
income taxes. We file consolidated income tax returns in the U.S. federal and state jurisdictions. With few
exceptions, we are no longer subject to U.S. federal, state and local income tax examinations by tax
authorities for years before 2010. At December 31, 2015 and 2014, our balance sheet did not include any
unrecognized tax benefits. We do not expect any material changes to unrecognized tax benefits within the
next twelve months. We recognize interest and penalties, if any, related to unrecognized tax benefits in
other expenses.
Computations of Earnings Per Share
The ASC guidance on earnings per share requires dual presentation of basic and diluted earnings per
share. Basic earnings per share does not include potentially dilutive securities and is computed by dividing
net income by the weighted average number of common shares outstanding. Diluted earnings per share
assumes the issuance of common shares pursuant to the Company’s stock-based compensation plans at the
74
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
beginning of each respective period, or at the date of grant or award if later. Shares attributable to stock
options are excluded from the calculation of diluted earnings per share if the effect would be antidilutive.
Weighted Average Number Of Shares
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dilutive Securities:
Performance-based restricted stock awards .
Employee stock purchase plan . . . . . . . . . .
Stock options . . . . . . . . . . . . . . . . . . . . . .
Time-based restricted stock awards . . . . . . .
Total dilutive securities . . . . . . . . . . . . . .
2015
2014
2013
43,670,908
43,291,031
42,781,382
19,890
1,249
—
25,523
46,662
8,809
3,422
—
10,666
22,897
12,142
1,729
61
7,907
21,839
Diluted weighted average number of shares . .
43,717,570
43,313,928
42,803,221
Antidilutive Shares . . . . . . . . . . . . . . . . . . . .
20,289
25,259
107,100
Potentially dilutive shares are not expected to have a material impact unless significant appreciation of
the Company’s stock price occurs.
Stock-Based Compensation
We have several stock-based compensation plans, which are described in more detail in Note 8. In
accordance with the ASC guidance on stock-based compensation, we recognize compensation expense
over the requisite service period of all stock-based compensation awards based upon the fair-value of the
award as of the date of issuance.
Recently Issued and Proposed Accounting Standards
Revenue from contracts with customers:
In June 2014, the FASB issued new guidance governing
revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that
depicts the transfer of promised goods or services to customers in an amount that reflects the
consideration to which the entity expects to be entitled in exchange for those goods or services. In July
2015, the FASB approved a one year delay in the standard’s effective date. The new standard is now
effective for interim and annual reporting periods beginning after December 15, 2017. We are evaluating
the impact of the adoption of this standard.
Extraordinary and unusual items:
In January 2015, the FASB issued revised guidance that eliminates
from GAAP the concept of extraordinary items. Under the revised guidance, an entity will no longer be
required to separately classify, present and disclose events or transactions that are determined to be both
unusual in nature and infrequent in occurrence. The revised guidance is effective for interim and annual
reporting periods beginning after December 15, 2015. The application of this standard is not expected to
have a material impact on our results of operations, financial position or liquidity.
Presentation of debt issuance costs:
In April 2015, the FASB issued revised guidance addressing the
presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue
debt are to be presented in the balance sheet as a direct deduction from the carrying amount of that debt
liability. The revised guidance is effective for interim and annual reporting periods beginning after
December 15, 2015. As of December 31, 2015, we expect that the implementation of this standard would
75
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
reduce both assets and liabilities by approximately $8.7 million. The application of this standard is not
expected to have a material impact on our results of operations or liquidity.
Balance sheet classification of deferred taxes:
In November 2015, the FASB issued revised guidance
addressing the classification of deferred taxes. Under the revised guidance all deferred tax assets and
liabilities will be classified as noncurrent in a classified statement of financial position. The revised
guidance is effective for interim and annual periods beginning after December 15, 2016, however early
adoption is permitted. As of December 31, 2015, we have retrospectively adopted this standard. The
application of this guidance resulted in $19.2 million in current deferred tax assets being reclassified from
prepaid expenses and other to deferred income taxes (noncurrent) on the December 31, 2014
Consolidated Balance Sheet.
Recognition and measurement of financial assets and financial liabilities:
In January 2016, the FASB
issued revised guidance addressing the recognition, measurement, presentation and disclosure of financial
instruments. Under the revised guidance all equity investments (except those accounted for under the
equity method of accounting or those that result in consolidation of the investee) are to be measured at
fair value with the changes in fair value recognized in net income. The amended guidance also addresses
the impairment assessment of some equity investments, as well as disclosure requirements. The revised
guidance is effective for interim and annual periods beginning after December 15, 2017. The application of
this standard is not expected to have a material impact on our results of operations, financial position or
liquidity.
76
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
2.
PROPERTY, PLANT AND EQUIPMENT
Our total property, plant and equipment are summarized below (in thousands).
December 31,
2015
2014
Electric plant
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electric plant
Less accumulated depreciation and amortization(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . .
Electric plant net of depreciation and amortization . . . . . . . . . . . . . . . . . .
Construction work in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,151,395
316,038
870,047
123,338
2,460,818
721,883
1,738,935
182,585
$1,159,140
288,542
840,761
119,572
2,408,015
704,596
1,703,419
110,500
Net electric plant
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,921,520
1,813,919
Water plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated depreciation and amortization . . . . . . . . . . . . . . . . . . . .
Water plant net of depreciation and amortization . . . . . . . . . . . . . . . . . . .
Construction work in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net water plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13,109
5,281
7,828
75
7,903
12,809
5,102
7,707
146
7,853
Net electric segment plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,929,423
1,821,772
Gas plant
Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated depreciation and amortization . . . . . . . . . . . . . . . . . . . .
Gas plant net of accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . .
Construction work in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net gas plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other
Fiber . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated depreciation and amortization . . . . . . . . . . . . . . . . . . . .
Non-regulated net of depreciation and amortization . . . . . . . . . . . . . . . . .
Construction work in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net non-regulated property . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,498
66,588
8,316
83,402
18,557
64,845
627
65,472
44,263
19,174
25,089
402
25,491
8,269
63,319
7,776
79,364
16,405
62,959
379
63,338
41,394
17,304
24,090
1,072
25,162
TOTAL NET PLANT AND PROPERTY . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,020,386
$1,910,272
(1) Includes intangible property of $39.8 and $41.2 million as of December 31, 2015 and 2014,
respectively, primarily related to capitalized software and investments in facility upgrades owned by
77
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
other utilities. Accumulated amortization related to this property in 2015 and 2014 was $15.6 and
$15.7 million, respectively.
(2) As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant
from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from
accumulated depreciation to a regulatory liability. These reclassified amounts are not reflected here.
See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail.
(3) Includes intangible property of $0.9 and $0.7 million as of December 31, 2015 and 2014, respectively,
primarily related to capitalized software and investments in facility upgrades owned by other utilities.
Accumulated amortization related to this property in 2015 and 2014 was $0.6 million and $0.5 million,
respectively.
The table below summarizes the total provision for depreciation and the depreciation rates for
continuing operations, both capitalized and expensed, for the years ended December 31 (in thousands):
2015
2014
2013
Provision for depreciation
Regulated — Electric and Water(1)
. . . . . . . . . . . . .
Regulated — Gas(1)
. . . . . . . . . . . . . . . . . . . . . . . .
Non-Regulated . . . . . . . . . . . . . . . . . . . . . . . . . . . .
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$73,885
4,036
4,895
82,816
2,858
$66,600
3,851
1,891
72,342
2,692
$63,192
3,763
1,938
68,893
2,492
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$85,674
$75,034
$71,385
(1) A portion of this amount is reclassified to a regulatory liability for the cost of removal. See
the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail.
Annual depreciation rates
Electric and water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-Regulated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
TOTAL COMPANY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.1% 3.0% 3.0%
5.1% 5.2% 5.4%
4.4% 4.7% 5.0%
3.2% 3.0% 3.1%
2015
2014
2013
The table below sets forth the average depreciation rate for each class of assets for each period
presented:
2015
2014
2013
Annual Weighted Average Depreciation Rate
Electric fixed assets:
Production plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission plant
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distribution plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-regulated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.8% 2.4% 2.4%
2.4% 2.4% 2.4%
3.5% 3.6% 3.6%
5.9% 5.8% 5.8%
2.8% 2.7% 2.8%
5.1% 5.2% 5.4%
4.4% 4.7% 5.0%
78
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
3. REGULATORY MATTERS
Regulatory Assets and Liabilities and Other Deferred Credits
Changes
Changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives
from December 31, 2014 to December 31, 2015 resulted from our 2014 Missouri rate case, which was
effective July 26, 2015. As a result of this case, a new tracking mechanism related to our Riverton Unit 12
Long Term Maintenance Agreement was established. The tracking mechanisms related to Iatan 2, Iatan
Common and Plum Point operating and maintenance costs were discontinued. The balances accumulated
through August 2014 from these tracking mechanisms are to be amortized over three years. The tracking
mechanism related to vegetation management was also discontinued. Balances accumulated through
August 2014 will be amortized over five years. The balances accumulated in these discontinued tracking
mechanisms after August 2014 will be addressed during the next rate case. In addition to these changes,
the order also included the continuation of tracking mechanisms for expenses related to employee pension
and retiree health care. There were no changes to regulatory assets and liabilities with regards to their rate
base inclusion or amortizable lives from December 31, 2013 to December 31, 2014.
79
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
The following table sets forth the components of our regulatory assets and regulatory liabilities on our
consolidated balance sheet (in thousands).
December 31,
2015
2014
Regulatory Assets:
Current:
Under recovered fuel costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current portion of long-term regulatory assets . . . . . . . . . . . . . . . . . . . . . . . .
$
Regulatory assets, current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
196
6,856
7,052
$ 2,618
8,134
10,752
Long-term:
Pension and other postretirement benefits(1) . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred construction accounting costs(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized loss on reacquired debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unsettled derivative losses — electric segment . . . . . . . . . . . . . . . . . . . . . . . .
System reliability — vegetation management . . . . . . . . . . . . . . . . . . . . . . . . .
Storm costs(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Missouri solar initiative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current portion of long-term regulatory assets . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
108,273
48,613
14,977
9,731
7,775
3,604
3,531
7,722
5,942
3,504
(6,856)
2,892
111,121
47,177
15,521
10,405
9,037
5,337
4,183
5,145
5,253
—
(8,134)
4,672
Regulatory assets, long-term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
209,708
209,717
Total Regulatory Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$216,760
$220,469
Regulatory Liabilities
Current:
Over recovered fuel costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current portion of long-term regulatory liabilities . . . . . . . . . . . . . . . . . . . . . .
$ 5,280
3,335
$
Regulatory liabilities, current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,615
Long-term:
Costs of removal(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SWPA payment for Ozark Beach lost generation . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred construction accounting costs — fuel(5)
. . . . . . . . . . . . . . . . . . . . . .
Unamortized gain on interest rate derivative . . . . . . . . . . . . . . . . . . . . . . . . .
Pension and other postretirement benefits . . . . . . . . . . . . . . . . . . . . . . . . . . .
Over recovered fuel costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
System reliability — vegetation management . . . . . . . . . . . . . . . . . . . . . . . . .
Current portion of long-term regulatory liabilities . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
94,193
14,213
11,244
7,690
3,031
1,745
2,300
1,320
(3,335)
56
4,227
3,671
7,898
90,527
16,744
11,451
7,849
3,201
2,369
1
—
(3,671)
—
Regulatory liabilities, long-term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
132,457
128,471
Total Regulatory Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$141,072
$136,369
(1) Primarily consists of unfunded pension and OPEB liability. See Note 7.
(2) Reflects deferrals resulting from 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point.
These amounts are being recovered over the life of the plants.
80
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
(3) Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado
including an accrued carrying charge and deferred depreciation totaling $2.9 million at December 31,
2015.
(4) As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant
from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from
accumulated depreciation to a regulatory liability. These reclassified amounts are reflected here. See
the depreciation discussion under Note 1 and Note 2 Property, Plant and Equipment for more detail.
(5) Resulting from regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.
Unamortized losses on debt and losses on interest rate derivatives are not included in rate base, but
are included in our capital structure for rate base purposes. The remainder of our regulatory assets are not
included in rate base, generally because they are not cash items. However, as of December 31, 2015, the
costs of all of our regulatory assets are currently being recovered except for approximately $99.0 million of
pension and other postretirement costs primarily related to the unfunded liabilities for future pension and
OPEB costs. The amount and timing of recovery of this item will be based on the changing funded status of
the pension and OPEB plans in future periods.
The regulatory income tax assets and liabilities are generally amortized over the average depreciable
life of the related assets. The loss on reacquired debt and the loss and gain on interest rate derivatives are
amortized over the life of the related new debt issue, which currently ranges from 4 to 25 years. The
unrecovered fuel costs are generally recovered within a year following their recognition. Severe storm costs
and the Asbury maintenance outage costs are recovered over five years. Pension and other postretirement
benefit tracking mechanisms are recovered over a five year period. The cost of removal regulatory liability
is amortized as removal costs are incurred.
RATE MATTERS
We routinely assess the need for rate relief in all of the jurisdictions we serve and file for such relief
when necessary.
Our rates for retail electric and natural gas services (other than specially negotiated retail rates for
industrial or large commercial customers, which are subject to regulatory review and approval) are
determined on a ‘‘cost of service’’ basis. Rates are designed to provide, after recovery of allowable
operating expenses, an opportunity to earn a reasonable return on ‘‘rate base.’’ ‘‘Rate base’’ is generally
determined by reference to the original cost (net of accumulated depreciation and amortization) of utility
plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is
increased by additions to utility plant in service and reduced by depreciation, amortization and retirement
of utility plant or write-off’s as ordered by the utility commissions. In general, a request of new rates is
made on the basis of a ‘‘rate base’’ as of a date prior to the date of the request and allowable operating
expenses for a 12-month test period ended prior to the date of the request. Although the current rate
making process provides recovery of some future changes in rate base and operating costs, it does not
reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag
(commonly referred to as ‘‘regulatory lag’’) between the time we incur costs and the time when we can start
recovering the costs through rates.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
The following table sets forth information regarding electric and water rate increases since January 1,
2013:
Jurisdiction
Date Requested
Annual
Increase
Granted
Percent
Increase
Granted
Date Effective
Missouri — Electric . . . . . . . . . . . .
August 29, 2014
Kansas — Electric . . . . . . . . . . . . . December 5, 2014
February 23, 2015
Arkansas — Electric . . . . . . . . . . . .
Kansas — Electric . . . . . . . . . . . . .
January 22, 2015
Arkansas — Electric . . . . . . . . . . . . December 3, 2013
Missouri — Electric . . . . . . . . . . . .
July 6, 2012
$17,125,000
782,479
$
457,000
$
$
273,455
$ 1,366,809
$27,500,000
Electric Segment
Missouri
Rate Activity
July 26, 2015
June 1, 2015
3.90%
4.71%
3.35% February 23, 2015
1.08% February 23, 2015
11.34% September 26, 2014
6.78%
April 1, 2013
2015 Rate Case: On October 16, 2015, we filed a request with the Missouri Public Service
Commission (MPSC) for changes in rates for our Missouri electric customers. We are seeking an annual
increase in total revenue of approximately $33.4 million, or approximately 7.3%. The most significant
factor driving the rate request is the cost associated with the conversion of the Riverton Unit 12 natural gas
combustion turbine to combined cycle operation.
2014 Rate Case: On August 29, 2014, we filed a request with the MPSC for changes in rates for our
Missouri electric customers. We requested an annual increase in total revenue of approximately
$24.3 million, or approximately 5.5%. The main cost drivers in the rate increase are the costs associated
with our investment in Air Quality Control Facilities at our Asbury power plant (See Note 11 — New
Construction of ‘‘Notes to Consolidated Financial Statements (Unaudited)’’) that were incurred to comply
with the Environmental Protection Agency’s (EPA) rules governing the continued operation of the plant,
increases in property taxes, increases in ongoing maintenance expenses and increases in Regional
Transmission Organization transmission fees. On June 24, 2015, the MPSC granted new rates for Missouri
customers, effective on July 26, 2015. The order approved an annual increase in base revenues of about
$17.1 million or 3.90%, which included a net reduction in base fuel and purchased power of $1.60 per
MWh, consistent with the non-unanimous stipulation and agreement filed April 8, 2015. The order
establishes a tracking mechanism for expenses related to the Riverton 12 long-term maintenance contract;
continues tracking of pension and other post-employment benefit expenses; and discontinues tracking of
vegetation management expenses and Iatan 2, Iatan Common and Plum Point operating and maintenance
costs. In addition, the order provides for the tracking and recovery of certain future changes in total
transmission expense through the Fuel Adjustment Charge, which we estimate at approximately 34% of
such changes.
2015 Missouri Energy Efficiency Investment Act and Integrated Resource Plan
On October 29, 2013 we filed an application with the Missouri Public Service Commission seeking
approval, pursuant to the Missouri Energy Efficiency Investment Act (MEEIA), of a new Missouri
demand-side management (DSM) portfolio, including four new DSM programs, and for the authority to
establish a Demand Side Management Investment Mechanism (DSIM). On July 24, 2015, we filed a
motion to withdraw our MEEIA filing. We will continue our current portfolio of Energy Efficiency
programs, with recovery through base rates. We will review the need for a future MEEIA filing in
conjunction with our 2016 Integrated Resource Plan (IRP).
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THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
On July 31, 2015, we filed a notice updating our most recent IRP, with the MPSC. In the notice we
indicated that Riverton Units 8 and 9 were retired on June 30, 2015. The notice also provides additional
information on our MEEIA application withdrawal mentioned above.
2015 Solar Rebate Tariff
On May 5, 2015, we filed a proposed solar rebate tariff with the MPSC and requested expedited
treatment. On May 6, 2015, the MPSC ordered our request for expedited treatment of our tariff filing be
granted and approved the tariff, effective May 16, 2015. The law provides a number of methods that may
be utilized to recover the associated expenses. We expect these costs to be recoverable in rates.
Kansas
2015 Ad Valorem Tax Surcharge
On January 22, 2015, we filed an Application with the KCC requesting approval of our Ad Valorem
Tax Surcharge (AVTS). The request sought approval for an annual increase of $0.27 million related to
increases in Ad Valorem taxes which exceed amounts currently included in base rates. On February 19,
2015, the KCC approved the request. The new rate was effective on and after February 23, 2015. On
January 21, 2016, we filed an Application with the KCC requesting approval for a revision to the AVTS.
The request sought approval for an annual increase of an additional $0.20 million related to increases in
Ad Valorem taxes which exceed amounts currently included in our AVTS rider currently in effect.
2014 Environmental Cost Recovery Rider
On December 5, 2014, we filed an Application with the KCC requesting approval of our proposed
Asbury Environmental Cost Recovery (AECR) tariff rider. The request sought approval for recovery of
our jurisdictional portion of annual carrying costs (rate of return, income taxes, and depreciation) of
approximately $0.86 million, associated with investment in the Asbury AQCS. A Commission Order was
received April 15, 2015 approving the rider in the amount of $0.78 million effective June 1, 2015.
Oklahoma
On June 8, 2015, the governor of the state of Oklahoma approved an administrative ruling that
provides customer rate reciprocity to electric companies who serve less than 10% of total customers within
the state of Oklahoma. As a result, future increases in Missouri customer rates approved by the MPSC will
be effective for our Oklahoma customers, subject to Oklahoma Corporation Commission (OCC) approval.
On October 26, 2015, we filed a request with the OCC to adopt the Missouri customer electric rates
requested in our October 16, 2015 Missouri rate filing discussed above for our Oklahoma customers once
approval is granted by the MPSC.
Arkansas
2015 Tariff Rider
On February 23, 2015, we filed a notice with the Arkansas Public Service Commission (APSC) to
implement the Alternative Generation Environmental Recovery Rider (GER) pursuant to the provision of
Act 310 of 1981. The GER recovers reasonably incurred costs and expenditures as a direct result of
legislative or regulatory requirements relating to the protection of the public health, safety, or the
environment. Our implemented GER recovers our Arkansas jurisdictional share of investment associated
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THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
with the Asbury AQCS. The new GER was effective upon notice (February 23, 2015) subject to refund. On
August 5, 2015, the APSC approved the GER.
2014 Rate Case
On May 20, 2014, we filed a settlement agreement with the Arkansas Public Service Commission
(APSC) for an increase of $1.375 million, or approximately 11%. A hearing was held on the settlement
agreement on July 22, 2014. On September 16, 2014, the APSC issued an order approving the settlement
with a modification that reduced the overall revenue increase to $1.367 million. The new rates were
effective September 26, 2014. We had filed a request on December 3, 2013, with the APSC seeking an
annual increase in total revenue of approximately $2.2 million, or approximately 18%. The rate increase
was requested to recover costs incurred to ensure continued reliable service for our customers, including
capital investments, operating systems replacement costs and ongoing increases in other operation and
maintenance expenses and capital costs.
FERC
We have in place a cost-based transmission formula rate (TFR). On June 13, 2013, we, the Kansas
Corporation Commission and the cities of Monett, Mt. Vernon and Lockwood, Missouri and Chetopa,
Kansas, filed a unanimous Settlement Agreement (Agreement) with the FERC. The Agreement included a
TFR that would establish an ROE of 10.0%. The Agreement calls for the TFR to be updated annually with
the new updated TFR rates effective on July 1 of each year. FERC conditionally approved the Agreement
on November 18, 2013, and we made a compliance filing with FERC on December 18, 2013 in connection
with this conditional approval. The FERC approved our compliance filing on June 12, 2014.
We have in place a cost-based generation formula rate (GFR). Our GFR requires an update to be
completed annually for rates effective June 1. On October 29, 2014, Empire made a ‘‘limited’’ Section 205
filing to request some minor changes in the existing GFR formula to incorporate the impact of the recent
implementation of the Southwest Power Pool Integrated Marketplace (IM). As a result of this filing, our
customers’ share of the margins we receive from sales into the IM will be passed on to them through the
monthly fuel and purchased power cost adjustment mechanism rather than making one-time adjustments
at each annual update. This filing was approved by FERC on January 13, 2015.
MARKETS AND TRANSMISSION
Electric Segment
Day Ahead Market: On March 1, 2014, the SPP RTO implemented its Integrated Marketplace (IM)
(or Day-Ahead Market), which replaced the Energy Imbalance Services (EIS) market. The SPP RTO
created a single NERC-approved balancing authority (BA) that took over balancing authority
responsibilities for its members, including Empire.
As part of the IM, we and other SPP members submit generation offers to sell our power and bids to
purchase power into the SPP market, with the SPP serving as a centralized commitment and dispatch of
SPP members’ generation resources. The SPP matches offers and bids based upon operating and reliability
considerations. The SPP reports that approximately 90% – 95% of all next day generation needed
throughout the SPP territory is being cleared through the IM. We also acquire Transmission Congestion
Rights (TCR) through annual and monthly processes in an attempt to mitigate congestion costs associated
with the power we purchase from the IM. When we sell more generation to the market than we purchase
for a given settlement period, the net sale is included as part of electric revenues. When we purchase more
generation from the market than we sell, the net purchase is recorded as a component of fuel and
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THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
purchased power on our financial statements. The net financial effect of these IM transactions is included
in our fuel adjustment mechanisms and therefore has little impact on gross margin
FERC Order No. 1000:
In July 2011, the FERC issued Order No. 1000 (Transmission Planning and
Cost Allocation by Transmission Owning and Operating Public Utilities) which requires all public utility
transmission providers to allow transmission developers outside their retail distribution service territory to
participate in regional transmission planning. Order No. 1000 eliminates the federal right of first refusal
for entities that develop transmission projects within their own retail distribution service territories to
construct transmission facilities selected in a regional transmission plan. This order will directly affect our
rights to build 161kV and above transmission facilities within our retail service territory.
Order No. 1000 also directed transmission providers to develop policy and procedures for regional
and interregional transmission planning as well as regional and interregional transmission cost allocation
(see ‘‘SPP Regional Transmission Development’’ below) for approved transmission projects. We continue
to participate in the SPP processes to understand the impact of these FERC orders on our ability to
construct new facilities within our service territory as well as their influence on promoting construction of
transmission projects on or near our borders with our neighbors. SPP completed and filed with the FERC a
required interregional policy and procedure compliance filing, and while FERC partially approved SPP’s
compliance filing, remaining issues have been addressed in a subsequent filing that is currently waiting
FERC approval.
SPP Regional Transmission Development:
In 2010, SPP received FERC approval to implement a new
highway/byway cost allocation methodology for new SPP approved transmission projects. We actively
monitor SPP’s policy to allocate the costs of transmission projects to its members. 2015 net SPP
transmission expenses were approximately $1.3 million above 2014 levels. Our Arkansas and Oklahoma
jurisdictions have cost recovery mechanisms in place to fully recover additional transmission costs outside
the traditional rate making process, and Missouri has a mechanism in place to recover a portion of
transmission expense above the amount in base fuel. See ‘‘Rate Matters’’ above for more information.
The highway/byway allocation methodology requires the costs of SPP approved transmission projects
to be allocated to 1) members across the entire SPP region; 2) members within certain localized service
territories or zones; or 3) a combination of both regional and zonal allocation. The allocation is based on
project voltage, as follows:
Transmission Project Voltage
Regional Funding Percentage
Zonal Funding Percentage
300 kV and Above . . . . . . . . . . . .
100kV to 299kV . . . . . . . . . . . . . .
Below 100 kV . . . . . . . . . . . . . . . .
100.0%
33.3%
0.0%
0.0%
66.7%
100.0%
SPP’s formal regional cost allocation review and benefit to cost imbalance analysis process is ongoing.
A filing to outline several possible remedies for entities not receiving adequate benefits from projects
regionally funded was rejected by FERC and discussion continues in stakeholder groups to develop
alternatives.
SPP/Midcontinent Independent System Operator (MISO) Joint Operating Agreement and Plum Point
Delivery: Due to Plum Point’s physical location and interconnection, transmission service from Entergy/
MISO is required for delivery. On December 19, 2013, Entergy voluntarily integrated its generation,
transmission, and load into the MISO regional transmission organization. Based on the current terms and
conditions of MISO membership, Entergy’s participation in MISO has increased transmission delivery
costs for our Plum Point power station as well as utilizes our transmission system without compensation.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
As a result, we have participated with the SPP members and other impacted utilities in two separate
FERC settlement proceedings in an effort to reduce the costs to our customers. On October 13, 2015,
SPP members, SPP, MISO and MISO members filed a settlement at the FERC regarding MISO’s
unreserved and uncompensated use of the SPP members’ systems. If approved by the FERC, the
agreement will provide compensation and governance for the continued shared use of the transmission
system among MISO, SPP and others impacted. However, the regional through and out transmission
delivery rate (RTOR) dispute regarding Plum Point will go to hearing at the FERC. On May 20, 2015, we
along with KCPL-GMO, AECI, and Southern Company filed a formal 206 complaint at the FERC that the
ROTR rate was unjust and unreasonable. A procedural schedule was issued by the FERC on October 8,
2015 with hearings to commence on April 25, 2016 and an initial decision scheduled for August 10, 2016.
Gas Segment
Non-residential gas customers whose annual usage exceeds certain amounts may purchase natural gas
from a source other than EDG. EDG does not have a non-regulated energy marketing service that sells
natural gas in competition with outside sources. EDG continues to receive non-gas related revenues for
distribution and other services if natural gas is purchased from another source by our eligible customers.
Other — Rate Matters
In accordance with ASC guidance on regulated operations, we currently have deferred approximately
$0.4 million of expense related to rate cases under other non-current assets and deferred charges. These
amounts will be amortized over varying periods based upon the completion of the specific cases. Based on
past history, we expect all these expenses to be recovered in rates.
4.
SHAREHOLDERS’ EQUITY
Shelf Registration
We have a $200.0 million shelf registration statement with the SEC, effective December 13, 2013,
covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. As of
December 31, 2015, $200.0 million remains available for issuance under this shelf registration statement.
However, as a result of our regulatory approvals, we may only issue up to $150.0 million of such securities
in the form of first mortgage bonds, of which $30 million remains available after the issuance of $60 million
in first mortgage bonds on August 20, 2015, and $60 million on December 1, 2014. Any proceeds from
offerings made pursuant to this shelf would be used to fund capital expenditures, refinance existing debt or
general corporate needs during the effective period through December 2016.
Employee Benefit Plans
Our Employee Stock Purchase Plan permits the grant to eligible employees of options to purchase our
common stock at a discounted price. As of December 31, 2015 there were 764,645 shares available for
issuance in this plan. Under our Employee 401(k) Plan and ESOP we match a percentage of each
employee’s deferrals by contributing shares of our common stock. At December 31, 2015 there were
129,616 shares available to be issued. (See Note 7 for further discussion of these plans).
Equity Based Compensation
We have several stock-based awards programs, which are described in Note 8. Our 2015 Stock
Incentive Plan provides for grants of up to 500,000 shares of common stock through January 2025. At
December 31, 2015 there were 496,766 shares available to be issued.
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THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Dividends
Holders of our common stock are entitled to dividends if, as and when declared by the Board of
Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding
cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of
Directors after considering all relevant factors, including the amount of our retained earnings (which is
essentially our accumulated net income less dividend payouts). A reduction of our dividend per share,
partially or in whole, could have an adverse effect on our common stock price.
The following table shows our diluted earnings per share, dividends paid per share, total dividends
paid and retained earnings balance for the years ended December 31, 2015, 2014 and 2013:
(in millions, except per share amounts)
2015
2014
2013
Diluted earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends paid per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total dividends paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings year-end balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1.29
$ 1.04
$ 45.4
$101.4
$ 1.55
$1.025
$ 44.4
$ 90.3
$ 1.48
$1.005
$ 43.0
$ 67.6
Under Kansas corporate law, our Board of Directors may only declare and pay dividends out of our
surplus or, if there is no surplus, out of our net profits for the fiscal year in which the dividend is declared
or the preceding fiscal year, or both. Our surplus, under Kansas law, is equal to our retained earnings plus
accumulated other comprehensive income/(loss), net of income tax. However, Kansas law does permit,
under certain circumstances, our Board of Directors to transfer amounts from capital in excess of par value
to surplus. In addition, Section 305(a) of the Federal Power Act (FPA) prohibits the payment by a utility of
dividends from any funds ‘‘properly included in capital account’’. There are no additional rules or
regulations issued by the FERC under the FPA clarifying the meaning of this limitation. However, several
decisions by the FERC on specific dividend proposals suggest that any determination would be based on a
fact-intensive analysis of the specific facts and circumstances surrounding the utility and the dividend in
question, with particular focus on the impact of the proposed dividend on the liquidity and financial
condition of the utility.
In addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The
most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay
any dividends (other than dividends payable in shares of our common stock) or make any other
distribution on, or purchase (other than with the proceeds of additional common stock financing) any
shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive
of the first quarterly dividend of $98,000 paid after said date) would exceed the sum of $10.75 million and
the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the
date of succession in the event that another corporation succeeds to our rights and liabilities by a merger
or consolidation. The EDE Mortgage permits the payment of any dividend or distribution on, or purchase
of, shares of our common stock within 60 days after the related date of declaration or notice of such
dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or
purchase would have complied with the provisions of the EDE Mortgage and (ii) as of the last day of the
calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to
total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or
purchase) was not more than 0.625 to 1.
87
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Preferred and Preference Stock
We have 2.5 million shares of preference stock authorized, including 0.5 million shares of Series A
Participating Preference Stock, none of which have been issued. We have 5 million shares of $10.00 par
value cumulative preferred stock authorized. There was no preferred stock issued and outstanding at
December 31, 2015 or 2014.
5. LONG-TERM DEBT
At December 31, 2015 and 2014, the balance of long-term debt outstanding was as follows
(in thousands):
First mortgage bonds (EDE):
2015
2014
7.20% Series due 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.375% Series due 2018(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.65% Series due 2020(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.58% Series due 2027(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.59% Series due 2030(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.73% Series due 2033(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.875% Series due 2037(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.20% Series due 2040(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.32% Series due 2043(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.27% Series due 2044(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 25,000
90,000
100,000
88,000
60,000
30,000
80,000
50,000
120,000
60,000
$ 25,000
90,000
100,000
88,000
—
30,000
80,000
50,000
120,000
60,000
First mortgage bonds (EDG):
6.82% Series due 2036(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
55,000
55,000
Senior Notes, 6.70% Series due 2033(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior Notes, 5.80% Series due 2035(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less unamortized net discount
Less current obligations of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less current obligations under capital lease . . . . . . . . . . . . . . . . . . . . . . . . . .
758,000
698,000
62,000
40,000
3,890
(633)
62,000
40,000
4,167
(686)
863,257
(25,000)
(310)
803,481
—
(292)
TOTAL LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$837,947
$803,189
(1) We may redeem some or all of the notes at any time at 100% of their principal amount, plus a
make-whole premium, plus accrued and unpaid interest to the redemption date.
Debt Financing Activities
On June 11, 2015, we entered into a Bond Purchase Agreement for a private placement of
$60.0 million of 3.59% First Mortgage Bonds due 2030. A delayed settlement occurred on August 20, 2015.
Interest is payable semi-annually on the bonds on each February 20 and August 20, commencing
February 20, 2016. The bonds are prepayable at our option at any time prior to maturity, at par plus a
make whole premium, together with accrued and unpaid interest, if any, to the prepayment date. The
proceeds from the sale of the bonds were used to refinance existing short-term indebtedness and for
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THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
general corporate purposes. The bonds have not been and will not be registered under the Securities Act
of 1933, as amended. The bonds were issued under the EDE Mortgage.
On October 15, 2014, we entered into a Bond Purchase Agreement for a private placement of
$60.0 million of 4.27% First Mortgage Bonds due December 1, 2044. A delayed settlement occurred on
December 1, 2014. Interest is payable semi-annually on the bonds on each December 1 and June 1,
commencing June 1, 2015. The bonds may be redeemed at our option, at any time prior to maturity, at par
plus a make whole premium, together with accrued and unpaid interest, if any, to the redemption date.
The proceeds from the sale of the bonds were used to refinance existing short-term indebtedness and for
general corporate purposes. The bonds have not been, and will not be, registered under the Securities Act
of 1933, as amended. The bonds were issued under the EDE Mortgage.
Shelf Registration
We have a $200 million shelf registration statement with the SEC that is effective for three years from
December 13, 2013. See Note 4.
EDE Mortgage Indenture
Substantially all of the property, plant and equipment of The Empire District Electric Company (but
not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond
indenture could affect our liquidity. The principal amount of all series of first mortgage bonds outstanding
at any one time under the Indenture of Mortgage and Deed of Trust of The Empire District Electric
Company (EDE Mortgage) is limited by terms of the mortgage to $1.0 billion. Based on the $1.0 billion
limit, and our current level of outstanding first mortgage bonds, we are limited to the issuance of
$297 million of new first mortgage bonds. The EDE Mortgage contains a requirement that for new first
mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve
consecutive months within the fifteen months preceding issuance must be two times the annual interest
requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the
prospective issue of new first mortgage bonds. In addition to the interest coverage requirement, the EDE
Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net
property additions. The annual interest coverage requirement and retired bonds or 60% of net property
additions test would permit the issuance of more than $297.0 million of first mortgage bonds; however, as
discussed above, we are otherwise limited to the issuance of no more than $297.0 million of new first
mortgage bonds. As of December 31, 2015, we are in compliance with all restrictive covenants of the EDE
Mortgage.
EDG Mortgage Indenture
The principal amount of all series of first mortgage bonds outstanding at any one time under the
Indenture of Mortgage and Deed of Trust of The Empire District Gas Company (EDG Mortgage) is
limited by terms of the mortgage to $300.0 million. Substantially all of the property, plant and equipment
of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage
contains a requirement that for new first mortgage bonds to be issued, the amount of such new first
mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the
Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt
(including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under
working capital facilities) unless, after giving effect to such issuance, EDG’s ratio of EBITDA (defined as
net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest
charges for the most recent four fiscal quarters is at least 2.0 to 1.0. As of December 31, 2015, this test
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THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
would allow us to issue approximately $19.5 million principal amount of new first mortgage bonds at an
assumed interest rate of 5.5%. As of December 31, 2015, we are in compliance with all restrictive
covenants of the EDG Mortgage.
Our long-term debt obligations over the next five years are as follows (in thousands):
Payments Due By Period
Long-Term Debt Payout Schedule
(Excluding Unamortized Discount)
(in thousands)
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
$ 25,310
329
90,351
375
100,396
647,129
Regulated
Entity Debt
Obligations
$ 25,000
—
90,000
—
100,000
645,000
Total long-term debt obligations . . . . . . . . . . . . . . . . . . . . . . . . .
863,890
$860,000
Less current obligations and unamortized discount . . . . . . . . . .
25,943
TOTAL LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . . . . . . . .
$837,947
Capital Lease
Obligations
$ 310
329
351
375
396
2,129
$3,890
6.
SHORT-TERM BORROWINGS
At December 31, 2015, total short-term borrowings consisted of $25.0 million in commercial paper
and no borrowings under our line of credit. During 2015 and 2014 our short-term borrowings outstanding
averaged (in millions)
Average borrowings outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Highest month end balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$48.9
$97.0
$30.0
$77.0
2015
2014
The weighted average interest rates and the weighted average interest rate of borrowings outstanding
at December 31, 2015 and 2014 were:.
Weighted average interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average interest rate of borrowings outstanding . . . . . . . . . .
0.54% 0.38%
0.84% 0.44%
2015
2014
We have in place a $200 million 5-year Credit Agreement which expires in October 2019. This
agreement replaced the former $150 million Third Amended and Restated Unsecured Credit Agreement
that had a January 2017 expiration date. This agreement may be used for working capital, commercial
paper back-up and general corporate purposes. The credit facility includes a $20 million swingline loan
sublimit, a $20 million sublimit for letters of credit issuance and, subject to bank approval, a $75 million
accordion feature and two one-year extensions of the credit facility’s maturity date.
Interest on borrowings under the new facility accrues at a rate equal to, at our option, (i) the highest
of (A) the agent prime rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus
1.0%, in each case, plus a margin or (ii) one month, two month, three month or six month LIBOR, in each
case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the
facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the
90
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
facility is 1.025%. A facility fee is payable quarterly on the full amount of the commitments under the
facility based on our current credit ratings, which is currently 0.175%. In addition, upon entering into the
new credit facility, we paid upfront fees to the revolving credit banks of $0.3 million in the aggregate.
The new credit facility requires our total indebtedness to be less than 65.0% of our total capitalization
at the end of each fiscal quarter and a failure to maintain this ratio will result in an event of default under
the credit facility and will prohibit us from borrowing funds thereunder. As of December 31, 2015, we were
in compliance with this covenant as our ratio of total indebtedness to total capitalization was 0.53 to 1.0.
The new credit facility is also subject to cross-default if we default on more than $25 million in the
aggregate on our other indebtedness. As of December 31, 2015, we were not in default under any of our
debt obligations.
The new credit agreement does not legally restrict the use of our cash in the normal course of
operations. There were no outstanding borrowings under the agreement at December 31, 2015; however,
$25.0 million was used to back up our outstanding commercial paper.
7. RETIREMENT AND OTHER EMPLOYEE BENEFITS
We record retirement benefits in accordance with the ASC guidance on accounting for pension and
other postretirement benefits, and have recorded the appropriate liabilities to reflect the unfunded status
of our benefit plans, with offsetting entries to a regulatory asset, because we believe it is probable the
unfunded amount of these plans will be afforded rate recovery. Additionally, the MPSC agreed that the
effects of purchase accounting entries related to pension and other post-retirement benefits would be
recoverable in future rate proceedings. These amounts, which are related to EDG, were recorded as
regulatory assets and are being amortized. The tax effects of these entries are reflected as deferred tax
assets and liabilities and regulatory liabilities.
Annually we evaluate the discount rate, retirement age, compensation rate increases, expected return
on plan assets, healthcare cost trend rate, and other actuarial assumptions related to pension benefit and
post-retirement medical plan. We utilize an interest rate yield curve to determine an appropriate discount
rate. The yield curve is constructed based on the yields on over 500 high-quality, non-callable corporate
bonds with maturities between zero and thirty years. A theoretical spot rate curve constructed from this
yield curve is then used to discount the annual benefit cash flows of the Empire pension plan and develop a
single point discount rate matching the plan’s payout structure. In evaluating these assumptions, many
factors are considered, including, current market conditions, asset allocations, changes in demographics
and the views of leading financial advisors and economists. In evaluating the expected retirement age
assumption, we consider the retirement ages of past employees eligible for pension and medical benefits
together with expectations of future retirement ages. It is reasonably possible that changes in these
assumptions will occur in the near term and, due to the uncertainties inherent in setting assumptions, the
effect of such changes could be material to the Company’s consolidated financial statements. A roll
forward technique is used to value the year ending pension obligations. The roll forward technique values
the year-end obligation by rolling forward the beginning-of-year obligation using the demographic
assumptions disclosed below. The economic assumptions are updated as of the end of the year. All of the
benefit plans have been measured as of December 31, 2015, consistent with previous years. See Note 1.
91
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Pensions
Our noncontributory defined benefit pension plan includes all employees meeting minimum age and
service requirements. Effective on January 1, 2014, the plan was amended to include a cash balance benefit
formula. Employees hired on or after January 1, 2014 will accrue benefits based on a cash balance
methodology. Employees hired prior to January 1, 2014 were given a one-time option to convert to the
cash balance methodology, or remain with our traditional average annual basic earnings formula, by
December 31, 2014. Both benefit formulas allow for a lump sum distribution of vested benefits. Lump sum
distributions totaled approximately $15.3 million and $9.0 million during 2015 and 2014, respectively, and
did not require settlement accounting according to ASC 715.
Annual contributions to the plan are at least equal to the greater of either minimum funding
requirements of ERISA or the accrued cost of the Plan, as required by the Missouri Public Service
Commission.
Our net pension liability decreased $2.4 million in 2015, which was recorded as a decrease in
regulatory assets as we believe it is probable of recovery through customer rates based on rate orders
received in our jurisdictions. The decrease in the liability is primarily due to an increase in discount rates.
Our contribution is estimated to be approximately $13.6 million for 2016. We expect future pension
funding commitments to continue at least at the level of our accrued cost, as required by our regulator.
The actual minimum funding requirements will be determined based on the results of the actuarial
valuations and, in the case of 2017, the performance of our pension assets during 2016.
We also have a supplemental retirement program (‘‘SERP’’) for designated officers of the Company,
which we fund from Company funds as the benefits are paid. The liability for this plan increased
$0.7 million in 2015.
Expected benefit payments are as follows (in millions):
Year
Payments from
Trust
Payments from
Company Funds
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 – 2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$22.5
22.8
21.5
20.0
20.9
97.4
$0.5
0.6
0.5
0.5
0.8
2.9
Other Postretirement Benefits (OPEB)
We provide certain healthcare and life insurance benefits to eligible retired employees, their
dependents and survivors through trusts we have established. Participants generally become eligible for
retiree healthcare benefits after reaching age 55 with 5 years of service. Employees hired after January 1,
2014 will be offered unsubsidized retiree healthcare benefits upon retirement.
Our net liability decreased $10.0 million in 2015, which was recorded as a decrease in regulatory assets
as we believe it is probable of recovery through customer rates based on rate orders received in our
jurisdictions. The decrease in the liability is primarily due to a significant actuarial gain resulting from
increases in discount rates, the adoption of a new mortality table and positive claims trends. Our funding
policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits.
We expect to be required to fund approximately $4.9 million in 2016.
92
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Estimated benefit payments are as follows (in millions):
Payments from Expected Federal
Year
2016 . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . .
2021 – 2025 . . . . . . . . . . . . . . . . . . . .
Trust
$ 2.8
3.2
3.5
3.8
4.1
25.0
Subsidy
$0.4
0.4
0.5
0.5
0.6
3.7
Payments from
Company Funds
$0.2
0.2
0.2
0.2
0.2
0.8
The following tables set forth the Company’s benefit plans’ projected benefit obligations, the fair
value of the plans’ assets and the funded status (in thousands).
Pension
SERP
OPEB
Reconciliation of Projected Benefit Obligations:
2015
2014
2015
2014
2015
2014
Benefit obligation at beginning of year .
Service cost . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . .
Amendments . . . . . . . . . . . . . . . . . . . .
Net actuarial (gain)/loss . . . . . . . . . . . .
Plan participant’s contribution . . . . . . . .
Benefits and expenses paid . . . . . . . . . .
Federal subsidy . . . . . . . . . . . . . . . . . .
$251,879
7,442
10,278
—
(708)
—
(25,201)
—
$225,131
6,467
10,819
(7,753)
36,742
—
(19,527)
—
$9,155
158
382
—
557
—
(366)
—
$7,108
153
387
(45)
1,890
—
(338)
—
$109,899
3,713
4,670
—
(14,358)
963
(3,839)
419
$ 85,332
2,601
4,360
—
20,347
850
(3,897)
306
Benefit obligation at end of year . . . . . .
$243,690
$251,879
$9,886
$9,155
$101,467
$109,899
Pension
SERP
OPEB
Reconciliation of Fair Value of Plan Assets:
2015
2014
2015
2014
2015
2014
Fair value of plan assets at beginning of year . .
Actual return on plan assets — gain/(loss) . . . .
Employer contribution . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . .
Plan participant’s contribution . . . . . . . . . . . .
Federal subsidy . . . . . . . . . . . . . . . . . . . . . . .
$192,674
(1,978)
21,350
(25,201)
—
—
$186,547
14,319
—
—
11,335
(19,527) —
—
—
—
—
$ — $ — $83,776
—
(955)
4,903
—
— (3,670)
912
—
403
—
$79,098
5,030
2,258
(3,707)
804
293
Fair value of plan assets at end of year . . . . . .
$186,845
$192,674
$ — $ — $85,369
$83,776
Pension
SERP
OPEB
Reconciliation of Funded Status:
2015
2014
2015
2014
2015
2014
Fair value of plan assets . . . . . . . .
Projected benefit obligations . . . . .
$ 186,845
(243,690)
$ 192,674
(251,879)
$ — $ — $ 85,369
(101,467)
(9155)
(9,886)
$ 83,776
(109,899)
Funded status . . . . . . . . . . . . . . . .
$ (56,845) $ (59,205) $(9,886) $(9,155) $ (16,098) $ (26,123)
93
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
The employee pension plan accumulated benefit obligation at December 31, 2015 and 2014 is
presented in the following table (in thousands):
Accumulated benefit obligation . . . . . . . . . .
$221,481
$227,928
$8,609
$7,160
Amounts recognized in the balance sheet consist of (in thousands):
Pension Benefits
SERP
2015
2014
2015
2014
Accounts Payable and Accrued Liabilities . . .
Pension and other postretirement benefit
Pension
SERP
OPEB
2015
2014
2015
2014
2015
2014
$ — $ — $ 534
$ 481
$
151
$
139
obligation . . . . . . . . . . . . . . . . . . . . . . . .
$56,845
$59,205
$9,352
$8,674
$15,947
$25,984
Net periodic benefit pension cost for 2015, 2014 and 2013, some of which is capitalized as a
component of labor cost and some of which is deferred as a regulatory asset (see Note 3), is comprised of
the following components (in thousands):
Net Periodic Pension Benefit Cost:
2015
Pension
2014
2013
2015
OPEB
2014
2013
Service cost
. . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . .
Amortization of prior service cost/
(benefit)(1) . . . . . . . . . . . . . . . . . . . . .
Amortization of actuarial loss(1) . . . . . . .
$ 7,442
10,278
(13,567)
$ 6,467
10,819
(13,105)
$ 7,454
10,063
(12,428)
$ 3,713
4,670
(5,197)
$ 2,601
4,360
(4,801)
$ 2,941
3,827
(4,353)
(630)
10,033
418
6,611
532
10,445
(1,011)
2,747
(1,011)
967
(1,011)
2,261
Net periodic benefit cost . . . . . . . . . . . .
$ 13,556
$ 11,210
$ 16,066
$ 4,922
$ 2,116
$ 3,665
Net Periodic Pension Benefit Cost:
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . .
Amortization of prior service cost/(benefit)t(1)
. . . . . . . . .
Amortization of actuarial loss(1) . . . . . . . . . . . . . . . . . . . .
2015
$ 158
382
—
(42)
597
SERP
2014
$ 153
387
—
(8)
504
2013
$ 135
315
—
(8)
567
Net periodic benefit cost . . . . . . . . . . . . . . . . . . . . . . . . .
$1,095
$1,036
$1,009
(1) Amounts are amortized from our regulatory asset originally recorded upon recognizing our
net pension liability on the balance sheet.
94
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
The tables below present other changes in plan assets and benefit obligations recognized in the
regulatory asset accounts for the year (in thousands).
Amount Recognized
Regulatory Assets
Beginning
Balance
Current Year
12/31/14 Actuarial Loss
Amortization Current Year Amortization of Ending
Balance
of Actuarial Prior Service
12/31/15
Prior Service
(Cost)/Credit
Credit
Loss
Pension . . . . . . . . . . . . . . . . . . . . $77,456
SERP . . . . . . . . . . . . . . . . . . . . . $ 5,537
OPEB . . . . . . . . . . . . . . . . . . . . . $20,446
14,836
557
(8,208)
(10,033)
(597)
(2,747)
—
—
—
630
42
1,011
$82,889
$ 5,539
$10,502
Regulatory Assets
Pension . . . . . . . . . . . . . .
SERP . . . . . . . . . . . . . . .
OPEB . . . . . . . . . . . . . . .
Beginning
Balance
12/31/13
$56,709
$ 4,188
285
$
Amount Recognized
Current Year
Actuarial Loss
Amortization
of Actuarial
Loss
Current Year
Prior Service
Credit
Amortization of
Prior Service
(Cost)/Credit
35,529
1,890
20,117
(6,611)
(504)
(967)
(7,753)
(45)
—
(418)
8
1,011
Ending
Balance
12/31/14
$77,456
$ 5,537
$20,446
The following table presents the amount of net actuarial gains / losses, transition obligations / assets
and prior period service costs in regulatory assets not yet recognized as a component of net periodic
benefit cost. It also shows the amounts expected to be recognized in the subsequent year. The following
table presents those items for the employee pension plan and other benefits plan at December 31, 2015,
and the subsequent twelve-month period (in thousands):
Pension Benefits
SERP
OPEB
2015
Subsequent
Period
2015
Subsequent
Period
2015
Subsequent
Period
Net actuarial loss . . . . . . . . . . . . . . . . . . . . . . $88,981
(6,092)
Prior service cost (benefit) . . . . . . . . . . . . . . .
$8,426
(630)
$5,555
(16)
$555
(14)
$12,075
(1,573)
$ 1,030
(1,011)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $82,889
$7,796
$5,539
$541
$10,502
$
19
The measurement date used to determine the pension and other postretirement benefits is
December 31. The assumptions used to determine the benefit obligation and the periodic costs are as
follows:
Weighted-average assumptions used to determine the benefit obligation as of December 31:
Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rate of compensation increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.40% 4.06% 4.48% 4.15%
3.50% 3.50% 3.50% 3.50%
Pension
Benefits
OPEB
2015
2014
2015
2014
95
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Weighted-average assumptions used to determine the net benefit cost (income) as of January 1:
Pension Benefits
OPEB
2015
2014
2013
2015
2014
2013
Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . .
Rate of compensation increase . . . . . . . . . . . . . . . . . . . . . .
4.06% 4.90% 4.00% 4.15% 5.00% 4.11%
7.75% 7.75% 7.75% 6.52% 6.52% 6.52%
3.50% 3.50% 3.50% 3.50% 3.50% 3.50%
The expected long-term rate of return assumption was based on historical return and adjusted to
estimate the potential range of returns for the current asset allocation. The assumed 2015 cost trend rate
used to measure the expected cost of healthcare benefits and benefit obligation is 7.0%. Each trend rate
decreases 0.50% through 2020 to an ultimate rate of 5.0% in 2020 and subsequent years.
The healthcare cost trend rate affects projected benefit obligations. A 1% change in assumed
healthcare cost growth rates would have the following effects (in thousands):
Effect on total of service and interest cost
. . . . . . . . . . . . .
Effect on post-retirement benefit obligation . . . . . . . . . . . .
$ 2,051
$17,473
$ (1,530)
$(13,794)
1% Increase
1% Decrease
Fair value measurements of plan assets
See Note 15 for a discussion of fair value measurements. The Company believes that it is appropriate
for the pension fund to assume a moderate degree of investment risk with diversification of fund assets
among different classes (or types) of investments, as appropriate, as a means of reducing risk. Although the
pension fund can and will tolerate some variability in market value and rates of return in order to achieve a
greater long-term rate of return, primary emphasis is placed on preserving the pension fund’s principal.
Full discretion is delegated to the investment managers to carry out investment policy within stated
guidelines. The guidelines and performance of the managers are monitored by the Company’s Investment
Committee. The following is a description of the valuation methodologies used for assets measured at fair
value using significant other observable, or significant unobservable inputs.
Short-term investments: Valued at cost, which approximates fair value.
Common/Collective trusts: Valued at the fair value based on audited financials of the trusts.
U.S. corporate and foreign issue debt: Valued at quoted market prices when available in an active
market. If quoted market prices are not available, then fair values are estimated by using pricing models,
quoted prices of securities with similar characteristics, or discounted cash flows.
Equity long/short hedge funds: Valued at the net asset value reported in the annual audited financial
statements and updated monthly based on changes in the value of the underlying funds reported by the
fund manager.
Pension plan assets
We utilize fair value in determining the market-related values for the different classes of our pension
plan assets. The market-related value is determined based on smoothing actual asset returns in excess of
(or less than) expected return on assets over a 5-year period.
96
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
The Company’s primary investment goals for pension fund assets are based around four basic
elements:
1.
Preserve capital,
2. Maintain a minimum level of return equal to the actuarial interest rate assumption,
3. Maintain a high degree of flexibility and a low degree of volatility, and
4. Maximize the rate of return while operating within the confines of prudence and safety.
Asset Allocation
We have adopted an investment strategy referred to as a de-risking glide path to increase the fixed
income allocation as the plan’s funded status improves. As the pension plan reaches set funded status
milestones, the plan’s assets will be rebalanced to shift more assets from equity to fixed income. Based on
the plan’s progress with this strategy, the target investment allocation for pension fund assets is
approximately 72% equities and 28% fixed income securities. However, these allocations are permitted to
vary within the following ranges: 60% – 80% for equities and 20% – 40% for fixed income securities.
Money market funds are permitted within the fixed income category. Investment managers may generally
hold up to 10% cash in their portfolios although this limit may be exceeded if market conditions warrant.
The following fair value hierarchy table presents information about the pension fund assets measured
at fair value as of December 31, 2015 and December 31, 2014 (in thousands):
Short term investments . . . . . . . . . . . . . .
Equity securities
Common collective trusts — domestic .
Common collective trusts —
international . . . . . . . . . . . . . . . . . .
Fixed income
Common collective trust . . . . . . . . . . .
Other types of investments
Equity long/short hedge funds . . . . . . .
Fair Value Measurements as of December 31, 2015
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Percentage
of Plan
Assets
Total
$ —
$
71
$ — $
71
0.0%
—
—
—
46,182
41,928
60,694
—
46,182
24.7%
41,928
22.5%
—
60,694
32.5%
—
37,970
37,970
20.3%
$ —
$148,875
$37,970
$186,845
100.0%
97
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Short term investments . . . . . . . . . . . . . .
Equity securities
Common collective trusts — domestic .
Common collective trusts —
international . . . . . . . . . . . . . . . . . .
Fixed income
Common collective trust . . . . . . . . . . .
Other types of investments
Equity long/short hedge funds . . . . . . .
Fair Value Measurements as of December 31, 2014
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Percentage
of Plan
Assets
Total
$ —
$
70
$ — $
70
0.0%
—
—
—
48,760
42,770
62,646
—
48,760
25.3%
42,770
22.2%
—
62,646
32.5%
—
38,428
38,428
20.0%
$ —
$154,246
$38,428
$192,674
100.0%
Fair Value Measurements Using Significant Unobservable Inputs (Level 3) — December 31,
Beginning Balance, January 1, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actual return on plan assets:
Relating to assets still held at the reporting date . . . . . . . . . . . . . . .
Relating to assets sold during the period . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers into and (out of) Level 3 . . . . . . . . . . . . . . . . . . . . . . . . . .
2015
2014
Equity long/short
hedge funds
Equity long/short
hedge funds
$38,428
$ 36,729
(458)
—
—
—
—
—
1,382
1,491
9,700
(10,874)
—
—
Ending Balance, December 31, . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$37,970
$ 38,428
98
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Permissible Investments
Listed below are the investment vehicles specifically permitted:
Permissible Investments
Equity Oriented
(cid:6) Common Stocks
(cid:6) Preferred Stocks (minimum ‘‘A-rated’’ by
Moody’s or S&P)
(cid:6) American Depository Receipts
(cid:6) Convertible Preferred Stocks
(cid:6) Convertible Bonds
(cid:6) Covered Options
(cid:6) Hedged Equity Funds of Funds
Fixed Income Oriented and Real Estate
(cid:6) Bonds (including US Government and
Agencies)
(cid:6) Corporate Bonds (minimum quality rating
of Baa by Moody’s or BBB by S&P)
(cid:6) Comingled bond funds (25% max.
allocation to high yield)
(cid:6) Foreign Government Bonds
(cid:6) GIC’s, BIC’s
(cid:6) Commercial Paper (rated A1 by S&P or P1
by Moody’s)
(cid:6) Certificates of Deposit in institutions with
FDIC/FSLIC protection
(cid:6) Money Market Funds/Bank STIF Funds
(cid:6) Real Estate — Publicly Traded
The above assets can be held in commingled (mutual) funds as well as privately managed separate
accounts.
Those investments prohibited by the Investment Committee without prior approval are:
Prohibited Investments Requiring Pre-approval
(cid:6) Privately Placed Securities
(cid:6) Commodities Futures
(cid:6) Securities of Empire District (except in the
hedged equity funds of funds or
commingled funds)
(cid:6) Restricted Stock
(cid:6) Warrants
(cid:6) Short Sales
(cid:6) Index Options
(cid:6) Letter Stock
OPEB plan assets
The Company’s primary investment goals for the component of the OPEB fund used to pay current
benefits are liquidity and safety. The primary investment goals for the component of the OPEB fund used
to accumulate funds to provide for payment of benefits after the retirement of plan participants are
preservation of the fund with a reasonable rate of return. The target allocation for plan assets is 60%
equities and 40% fixed income, although, at any given time, up to 10% of either category may be invested
in cash equivalents. The 10% cash limitation may be exceeded if market conditions warrant. Allocations
may also vary within the following ranges: 44% – 76% equities and 36% – 44% fixed income securities. The
99
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
following fair value hierarchy table presents information about the OPEB fund assets measured at fair
value as of December 31, 2014 and December 31, 2013 (in thousands):
Fair Value Measurements as of December 31, 2015
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Percentage
of Plan
Assets
Total
Equity securities
Common collective trusts . . . . . . . . . . .
$ —
$48,553
$ —
$48,553
56.9%
Fixed income
Common collective trusts . . . . . . . . . . .
Other types of investments
Common collective trusts . . . . . . . . . . .
Payable for securities purchased . . . . . . . .
—
—
$ —
34,395
2,556
$85,504
—
—
$ —
34,395
40.3%
2,556
85,504
3.0%
(135) (cid:5)0.2%
100.0%
$85,369
Fair Value Measurements as of December 31, 2014
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Percentage
of Plan
Assets
Total
Equity securities
Common collective trusts . . . . . . . . . . .
$ —
$47,690
$ —
$47,690
56.9%
Fixed income
Common collective trusts . . . . . . . . . . .
Other types of investments
Common collective trusts . . . . . . . . . . .
Payable for securities purchased . . . . . . . .
—
—
$ —
33,708
2,453
$83,851
—
—
$ —
33,708
40.2%
2,453
$83,851
2.9%
(75)
0.0%
$83,776
100.0%
The Company’s guideline in the management of this fund is to endorse a long-term approach, but not
expose the fund to levels of volatility that might adversely affect the value of the assets. Full discretion is
delegated to the investment managers to carry out investment policy within stated guidelines. The
guidelines and performance of the managers are monitored by the Company’s Investment Committee.
100
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Permissible Investments
Listed below are the investment vehicles specifically permitted:
Permissible Investments
Equity
(cid:6) Common Stocks
(cid:6) Preferred Stocks
Fixed Income
(cid:6) Cash-Equivalent Securities with a maturity
of one-year or less, including: money
market funds, US Government and Agency
securities, certificates of deposit or banker’s
acceptances issued by domestic banks with
FDIC protection and commercial paper
rated A1 by S&P or P1 by Moody’s
(cid:6) Government Bonds
(cid:6) Money Market Funds / Bank STIF Funds
(cid:6) Certificates of Deposit in institutions with
FDIC protection
(cid:6) Corporate Bonds (minimum quality rating
of A Baa by Moody’s or BBB by S&P at
time of issuance)
The above assets can be held in commingled (mutual) funds as well as privately managed separate
accounts.
Listed below are those investments prohibited by the Investment Committee:
Prohibited Investments
(cid:6) Privately Placed Securities
(cid:6) Securities of Empire District
(cid:6) Derivatives
(cid:6) Instrumentalities in violation of the
Prohibited Transactions Standards of
ERISA
(cid:6) Margin Transactions
(cid:6) Options (other than ‘‘covered call options’’)
(cid:6) Lettered or Restricted Stock
(cid:6) Any other investment security which, in the
opinion of the investment manager
produces an imprudent risk to the fund
Employee Stock Purchase Plan
Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to
purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The
look-back feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the
101
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
maximum subscription price. As of December 31, 2015 there were 764,645 shares available for issuance in
this plan.
Subscriptions outstanding at December 31,
. . . . . . . . .
Maximum subscription price . . . . . . . . . . . . . . . . . . . .
Shares of stock issued . . . . . . . . . . . . . . . . . . . . . . . .
Stock issuance price . . . . . . . . . . . . . . . . . . . . . . . . . .
58,742
57,369
$ 21.09(1) $ 21.43
56,942
56,193
$ 19.58
$ 21.01
60,413
$ 19.58
68,099
$ 17.95
2015
2014
2013
(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2015
to May 31, 2016.
Assumptions for valuation of these shares are shown in the table below.
2015
2014
2013
Weighted average fair value of grants . . . . . . . . .
Risk-free interest rate . . . . . . . . . . . . . . . . . . . .
Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected volatility(1) . . . . . . . . . . . . . . . . . . . . . .
Expected life in months . . . . . . . . . . . . . . . . . . .
Grant date . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
3.58
0.26%
4.40%
21.00%
12
6/1/2015
$
3.07
0.10%
4.30%
14.00%
12
6/2/2014
$
2.78
0.14%
4.60%
14.00%
12
6/1/2013
(1) One-year historic volatility
401(k) Plan and ESOP
Our Employee 401(k) Plan and ESOP (the 401(k) Plan) allows participating employees to defer up to
25% of their annual compensation up to an Internal Revenue Service specified limit. For employees
participating in the cash balance formula of the pension plan, discussed above, we match 100% of their
deferrals, not to exceed 6% of the employee’s eligible compensation. The first 3% of the matching
contribution is made in shares of our common stock with the remaining portion made by contributing cash.
For employees remaining with the traditional average annual basic earnings formula of the pension plan,
we match 50% of their deferrals by contributing shares of our common stock, with such matching
contributions not to exceed 3% of the employee’s eligible compensation. We record the compensation
expense at the time the quarterly matching contributions are made to the plan. At December 31, 2015
there were 129,616 shares available to be issued.
Shares contributed . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
66,783
60,049
64,128
2015
2014
2013
Deferred Compensation
Effective January 2015, we established a non-qualified Deferred Compensation Plan for the purpose
of allowing executive officers who elect to participate in the qualifying cash balance option of the Pension
plan to obtain retirement savings that are not available to them under the 401(k) plan.
102
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
8. EQUITY COMPENSATION
We have several stock-based awards and programs, which are described below. Performance-based
restricted stock awards, time-vested restricted stock and stock options are valued as liability awards, in
accordance with fair value guidelines. We allow employees to elect to have taxes in excess of the minimum
statutory requirements withheld from their awards and, therefore, the awards are classified as liability
instruments under the ASC guidance on share based payment. Awards treated as liability instruments must
be revalued each period until settled, and cost is accrued over the requisite service period and adjusted to
fair value at each reporting period until settlement or expiration of the award.
We recognized the following amounts in compensation expense and tax benefits for all of our stock-
based awards and programs for the applicable years ended December 31 (in thousands):
Compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax benefit recognized . . . . . . . . . . . . . . . . . . . . . . . . . .
$4,279
1,576
$3,688
1,359
$2,577
929
2015
2014
2013
Stock Incentive Plans
Our 2006 Stock Incentive Plan (the 2006 Incentive Plan), which expired on December 31, 2015, was
replaced by the 2015 Stock Incentive Plan (the 2015 Incentive Plan). The 2015 Incentive Plan was adopted
by shareholders at the annual meeting on May 1, 2014 and provides for grants of up to 500,000 shares of
common stock through January 2025. At December 31, 2015 there were 496,766 shares available to be
issued. The 2015 Stock Incentive Plan permits (and the 2006 Incentive Plan permitted) grants of stock
options and restricted stock to qualified employees and permits Directors and, if approved by the
Compensation Committee of the Board of Directors, qualified employees to receive common stock in lieu
of cash. Certain executive officers and other senior managers applied to receive annual incentive awards
related to 2013, 2014 and 2015 performance in the form of Empire common stock rather than cash. These
requests were granted by the Compensation Committee of the Board of Directors under the terms of our
2006 and 2015 Stock Incentive Plans. The terms and conditions of any option or stock grant are
determined by the Board of Directors Compensation Committee, within the provisions of these Stock
Incentive Plans.
Time-Vested Restricted Stock Awards
Beginning in 2011, we began granting, to qualified individuals, time-vested restricted stock awards that
vest after a three-year period, in lieu of stock options. No dividend rights accumulate during the vesting
period. Time-vested restricted stock is valued at an amount equal to the fair market value of our common
stock on the date of grant. If employment terminates during the vesting period because of death,
retirement or disability, the participant is entitled to a pro-rata portion of the time-vested restricted stock
awards such participant would otherwise have earned, which is distributed following the date of
termination, with the remainder of the award forfeited. If employment is terminated during the vesting
period for reasons other than those listed above, the time-vested restricted stock awards will be forfeited
on the date of the termination, unless the Board of Directors’ Compensation Committee determines, in its
sole discretion, that the participant is entitled to a pro-rata portion of the award. In addition, if a change in
control occurs during the vesting period, a pro-rata portion of the time-vested restricted stock awards will
vest upon such change in control, and any portion of such awards that remains unvested immediately after
the change in control will be forfeited.
103
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
The fair value measurements for each grant year are noted in the following table:
Fair Value of Grants Outstanding at
December 31
2015
2014
Total unrecognized compensation cost (in millions) . . . .
Recognition period . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$0.4
0.1 years to 2.1 years
$25.17
$0.4
1.1 years to 2.1 years
$26.82
A summary of time-vested restricted stock activity under the plan for 2015, 2014 and 2013 is presented
in the table below:
2015
2014
2013
Weighted
Average
Weighted
Average
Weighted
Average
Number of Grant Date
Fair Value
Shares
Number of Grant Date
Fair Value
Shares
Number Of Grant Date
Fair Value
Shares
Outstanding at January 1, . . . . . .
Granted . . . . . . . . . . . . . . . . . . .
Distributed . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . .
41,000
19,000
(1,654)
(2,746)
Outstanding at December 31,
. . .
55,600
$21.89
$30.40
$21.92
$25.91
$24.60
24,900
22,600
(4,010)
(2,490)
41,000
$21.42
$22.40
$21.77
$21.99
$21.89
3,300
21,600
—
—
24,900
$21.84
$21.36
—
—
$21.42
Performance-Based Restricted Stock Awards
Performance-based restricted stock awards are granted to qualified individuals consisting of the right
to receive a number of shares of common stock at the end of the restricted period assuming performance
criteria are met. The performance measure for the award is the total return to our shareholders over a
three-year period compared with an investor-owned utility peer group. The threshold level of performance
under the 2013, 2014 and 2015 grants was set at the 20th percentile level of the peer group, target at the
50th percentile level, and the maximum at the 80th percentile level. Shares would be earned at the end of
the three-year performance period as follows: 100% of the target number of shares if the target level of
performance is reached, 50% if the threshold is reached, and 200% if the percentile ranking is at or above
the maximum, with the number of shares interpolated between these levels. However, no shares would be
payable if the threshold level is not reached.
If employment terminates during the performance period because of death, retirement, or disability,
the individual is entitled to a pro-rata portion of the performance-based restricted stock awards such
individual would otherwise have earned. If employment is terminated during the performance period for
reasons other than those listed above, the performance-based restricted stock awards will be forfeited on
the date of the termination unless the Compensation Committee of the Board of Directors determines, in
its sole discretion, that the individual is entitled to a pro-rata portion of such award. In addition, if a
change
in control occurs during the performance period, a pro-rata portion of the target
performance-based restricted stock awards will vest and be distributed upon such change in control. At the
end of the performance period, the number of shares earned, determined without regard to the special
change in control vesting provisions will be determined and such amount, less the number of shares
distributed upon the change in control, shall be distributed. In connection with the Agreement and Plan of
Merger dated February 9, 2016, by and among the Company, Liberty Utilities (Central) Co. and Liberty
Sub Corp. (the ‘‘Merger Agreement’’), we amended outstanding performance-based restricted stock
awards to provide that, effective upon and subject to the occurrence of the merger under the Merger
104
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Agreement, each performance-based restricted stock award outstanding immediately prior to the effective
time of the merger will be converted into the right to receive a lump sum in cash equal to the merger
consideration under the merger agreement, multiplied by the target number of shares under the award.
(See Note 17 for further discussion of the Merger Agreement).
The fair value of the outstanding restricted stock awards was estimated as of December 31, 2015, 2014
and 2013 using a Monte Carlo option valuation model. The assumptions used in the model for each grant
year are noted in the following table:
Risk-free interest rate . . . . . . . . . . . . .
Expected volatility of Empire stock . . .
Expected volatility of peer group stock .
Expected dividend yield on Empire
stock . . . . . . . . . . . . . . . . . . . . . . . .
Expected forfeiture rates . . . . . . . . . . .
Plan cycle . . . . . . . . . . . . . . . . . . . . . .
Fair value percentage . . . . . . . . . . . . .
Weighted average fair value per share .
Fair Value of Grants Outstanding at December 31,
2015
2014
2013
0.65% to 1.06%
18.7%
14.5% to 34.4%
0.25% to 0.67%
14.5%
12.4% to 24.8%
0.13% to 0.38%
20.2%
12.3% to 27.5%
3.7%
3%
3 years
115.0% to 182.0%
$41.73
3.5%
3%
3 years
140.0% to 157.0%
$43.80
4.5%
3%
3 years
0.0% to 108.0%
$18.47
Non-vested performance-based restricted stock awards (based on target number) as of December 31,
2015, 2014 and 2013 and changes during the year ended December 31, 2015, 2014 and 2013 were as
follows:
2015
2014
2013
Weighted
Average
Weighted
Average
Weighted
Average
Number of Grant Date
Fair Value
Shares
Number of Grant Date
Fair Value
Shares
Number Of Grant Date
Fair Value
Shares
Outstanding at January 1, . . . . . .
Target shares granted . . . . . . . . .
Shares issued in excess of target .
Shares awarded . . . . . . . . . . . . .
Forfeited shares . . . . . . . . . . . . .
Target shares not awarded . . . . . .
63,300
21,800
3,653
(13,653)
(6,079)
—
Nonvested at December 31,
. . . .
69,021
$21.74
$30.40
$20.97
$20.97
$24.10
—
$24.38
47,200
27,000
—
—
—
(10,900)
63,300
$21.39
$22.40
—
—
—
$21.84
$21.74
33,900
26,300
—
(4,460)
—
(8,540)
47,200
$20.25
$21.36
—
$18.36
$18.36
$21.39
At December 31, 2015 and 2014, unrecognized compensation expense related to estimated
outstanding awards was $0.7 million and $1.1 million, respectively.
Stock Options
Beginning in 2011, we began issuing time-vested restricted stock in lieu of stock options and dividend
equivalents. Prior to 2011 stock options were issued with an exercise price equal to the fair market value of
the shares on the date of grant. They became exercisable after three years and expired ten years after the
date granted. Dividend equivalent awards, under which dividend equivalents accumulated during the
vesting period, were also issued to recipients of the stock options. Participants’ options and dividend
equivalents that were not vested were forfeited when participants left Empire, except for terminations of
employment under certain specified circumstances. There were no stock options or dividend equivalents
granted in 2015, 2014, or 2013, and all outstanding options were exercised prior to December 31, 2014.
105
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally
recognized over the requisite (explicit) service period. There were no outstanding options at December 31,
2015 and 2014. The fair value of the outstanding options was estimated as of December 31, 2013, under a
Black-Scholes methodology. The assumptions used in the valuations are shown below:
Risk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected life in months . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Market value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average fair value per option . . . . . . . . . . . . . . . . . . . .
Fair Value of Grants
Outstanding at
December 31, 2013
0.10% to 0.38%
4.5%
24.0%
6.5 to 24.5
$22.69
$1.57
A summary of option activity under the plan during the years ended December 31, 2014 and 2013 is
presented below:
. . . . . . . . . . . . . .
Outstanding at January 1,
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding at December 31, . . . . . . . . . . . .
Exercisable, end of year . . . . . . . . . . . . . . . .
2014
2013
Weighted
Average
Exercise
Price
$23.27
—
$24.58
Weighted
Average
Exercise
Price
$22.13
$ —
$21.78
Options
163,300
(50,800)
112,500
$23.27
112,500
$23.27
Options
112,500
—
112,500
—
—
The intrinsic value of the unexercised options is the difference between the Company’s closing stock
price on the last day of the period and the exercise price multiplied by the number of in-the-money
options, had all option holders exercised their options on the last day of the period. The intrinsic value is
zero if such closing price is less than the exercise price. The table below shows the aggregate intrinsic
values at December 31, 2013:
Aggregate intrinsic value (in millions) . . . . . . . . . . . . . . . . . . . . .
Weighted-average remaining contractual life of outstanding
options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Range of exercise prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total unrecognized compensation expense (in millions) related to
non-vested options and related dividend equivalents granted
under the plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recognition period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013
Less than $0.1
2.1 years
$21.92 to $23.81
—
—
Stock Unit Plan for Directors
Our Stock Unit Plan for directors (Stock Unit Plan) provides a stock-based compensation program for
directors. This plan enhances our ability to attract and retain competent and experienced directors and
106
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
allows the directors the opportunity to accumulate compensation in the form of common stock units. The
Stock Unit Plan also provides directors the opportunity to convert previously earned cash retirement
benefits to common stock units. All eligible directors who had benefits under the prior cash retirement
plan converted their cash retirement benefits to common stock units.
As of December 31, 2015, a total of 900,000 shares were authorized under this plan. Each common
stock unit earns dividends in the form of common stock units and can be redeemed for shares of common
stock. In connection with the Merger Agreement, we amended the Stock Unit Plan to provide that,
effective upon and subject to the occurrence of the merger under the Merger Agreement, each stock unit
outstanding immediately prior to the effective time of the merger will be converted into the right to receive
in cash the merger consideration under the Merger Agreement, with interest at the prime rate from the
effective time of the merger until the payment date under the plan. (See Note 17 for further discussion of
the Merger Agreement).
The number of units granted annually is computed by dividing an annual credit (determined by the
Compensation Committee) by the fair market value of our common stock on January 1 of the year the
units are granted. Common stock unit dividends are computed based on the fair market value of our stock
on the dividend’s record date. We record the related compensation expense at the time we make the
accrual for the directors’ benefits as the directors provide services. Shares accrued to directors’ accounts
and shares available for issuance under this plan at December 31 are shown in the table below:
Shares accrued to directors’ accounts . . . . . . . . . . . . . . . . . . . . .
Shares available for issuance . . . . . . . . . . . . . . . . . . . . . . . . . . .
157,672
677,980
164,085
714,978
2015
2014
Units accrued for service and dividends as well as units redeemed for common stock at December 31
are shown in the table below:
Units accrued for service and dividends . . . . . . . . . . . . . .
Units redeemed for common stock . . . . . . . . . . . . . . . . .
30,595
37,008
30,765
21,083
34,252
22,908
2015
2014
2013
9.
INCOME TAXES
Income tax expense components for the years ended December 31 are as follows (in thousands):
2015
2014
2013
Current income taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ — $ (2,350) $ 6,726
2,495
(123)
—
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
— (2,473)
9,221
Deferred income taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
29,722
4,233
33,955
36,620
5,216
41,836
24,954
3,554
28,508
Investment tax credit amortization . . . . . . . . . . . . . . .
(143)
(143)
(237)
TOTAL INCOME TAX EXPENSE . . . . . . . . . . . . . . .
$33,812
$39,220
$37,492
107
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Deferred Income Taxes
Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows
(in thousands):
Deferred Income Taxes
December 31,
2015
2014
NET DEFERRED TAX LIABILITIES . . . . . . . . . . . . . . . . . . .
$396,542
$358,252
Temporary differences related to deferred tax assets and deferred tax liabilities are summarized as
follows (in thousands):
Temporary Differences
Deferred tax assets:
December 31,
2015
2014
Plant related basis differences . . . . . . . . . . . . . . . . . . . . . . .
Net operating loss (NOL) . . . . . . . . . . . . . . . . . . . . . . . . .
Regulated liabilities related to income taxes . . . . . . . . . . . .
Disallowed plant costs . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gains on hedging transactions . . . . . . . . . . . . . . . . . . . . . .
Pensions and other post-retirement benefits . . . . . . . . . . . . .
Carry forward of income tax credit . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 27,347
9,055
13,142
1,699
1,195
—
8,675
1,550
$ 25,349
22,000
13,350
1,754
1,260
1,175
6,367
1,633
Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 62,663
$ 72,888
Deferred tax liabilities:
Depreciation, amortization and other plant related
differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulated assets related to income . . . . . . . . . . . . . . . . . . .
Loss on reacquired debt . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of intangibles . . . . . . . . . . . . . . . . . . . . . . . .
Pensions and other post-retirement benefits . . . . . . . . . . . . .
Deferred construction accounting costs . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$382,897
38,615
3,572
10,248
7,112
5,711
11,050
$363,337
37,180
3,828
9,168
—
6,082
11,545
Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . .
459,205
431,140
NET DEFERRED TAX LIABILITIES . . . . . . . . . . . . . . . . . . .
$396,542
$358,252
108
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Effective Income Tax Rates
The difference between income taxes and amounts calculated by applying the federal legal rate to
income tax expense for continuing operations were as follows:
Effective Income Tax Rates
Federal statutory income tax rate . . . . . . . . . . . . . . . . . . . . . . . .
Increase (decrease) in income tax rate resulting from:
2015
2014
2015
35.0% 35.0% 35.0%
State income tax (net of federal benefit) . . . . . . . . . . . . . . . . .
Investment tax credit amortization . . . . . . . . . . . . . . . . . . . . .
Effect of ratemaking on property related differences . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.1
(0.2)
(1.4)
0.9
3.1
(0.1)
(1.7)
0.6
3.1
(0.2)
(1.1)
0.3
EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . . . . . . . . .
37.4% 36.9% 37.1%
We do not have any unrecognized tax benefits as of December 31, 2015. We did not recognize any
significant interest or penalties in any of the periods presented. We do not expect any significant changes to
our unrecognized tax benefits over the next twelve months.
The ‘‘Protecting Americans from Tax Hikes’’ Act (the ‘‘Act’’) was signed into law on December 18,
2015. The Act restored several expired business tax provisions, including bonus depreciation for 2015.
Because of the reinstatement of bonus depreciation, we anticipate making no material income tax
payments in 2016.
We generated $74.1 million of tax NOLs during 2014, mainly due to bonus depreciation. We intend to
carry forward these tax NOLs, which, if unused, will expire in 2034. We estimate that we will utilize
approximately $38.0 million of the 2014 tax NOLs on our 2015 return when filed. As of December 31,
2015, we estimate there is $13.5 million of deferred tax assets remaining to be utilized related to the tax
NOLs. A portion of the deferred tax assets related to the tax NOLs is recorded as a receivable on the
balance sheet in anticipation of income tax payment refunds.
In 2010, we received $17.7 million of investment tax credits based on our investment in Iatan 2, which,
if unused, will expire in 2030. We utilized $9.0 million of these credits on our 2013 tax return. Due to the
passage of the Act, we estimate we will not be able to use the remaining credits on our 2015 tax return, but
expect to use them to offset future income tax liabilities. The tax credits will have no significant income
statement impact because they will flow to our customers as we amortize the tax credits over the life of the
plant.
On September 13, 2013, the IRS and the Treasury Department released final regulations under
Sections 162(a) and 263(a) on the deduction and capitalization of expenditures related to tangible
property. These regulations applied to tax years beginning on or after January 1, 2014, and we filed a
Form 3115 with the IRS to change our tax accounting method to comply with the regulations. As a result,
we deducted approximately $29 million on our 2014 income tax return under IRS Code Section 481(a) as
an adjustment required by the change in tax accounting method.
Our 2014 income tax return included another tax accounting method change regarding the
deductibility of the Voluntary Employee Benefit Association (VEBA) plan activity. As a result, we
deducted approximately $14 million as an adjustment required by the change in tax method of accounting.
These changes did not have a material impact on the effective tax rate.
109
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
10. COMMONLY OWNED FACILITIES
Iatan
We own a 12% undivided interest in the coal-fired Units No. 1 and No. 2 at the Iatan Generating
Station located near Weston, Missouri, 35 miles northwest of Kansas City, Missouri, as well as a 3%
interest in the site and a 12% interest in certain common facilities. We are entitled to 12% of each unit’s
available capacity and are obligated to pay for a like percentage of the operating costs of the units. KCP&L
and KCP&L Greater Missouri Operations Co. own 70% and 18% respectively, of Unit 1, and 54% and
18%, respectively, of Unit 2. KCP&L operates the units for the joint owners.
At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in
the following chart (in millions):
Iatan
2015
2014
Cost of ownership in plant in service . . . . . . . . . . . . . . . . . . . . . .
Accumulated Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expenditures(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$380.2
$105.3
$ 26.9
$373.3
$ 99.1
$ 27.8
(1) Recognized in operating, maintenance, and fuel expenditures excluding depreciation
expense.
State Line Combined Cycle Unit
We and Westar Generating, Inc, (‘‘WGI’’), a subsidiary of Westar Energy, Inc., share joint ownership
of a nominal 500-megawatt combined cycle unit at the State Line Power Plant (the ‘‘State Line Combined
Cycle Unit’’). We are responsible for the operation and maintenance of the State Line Combined Cycle
Unit, and are entitled to 60% of the available capacity and are responsible for approximately 60% of its
costs.
At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in
the following chart (in millions):
State Line Combined Cycle Unit
2015
2014
Cost of ownership in plant in service . . . . . . . . . . . . . . . . . . . . . .
Accumulated Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expenditures(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$163.0
$ 43.5
$ 40.7
$161.5
$ 40.0
$ 47.1
(1) Recognized in operating, maintenance, and fuel expenditures excluding depreciation
expense.
Plum Point Energy Station
We own a 7.52% undivided interest in the coal-fired Plum Point Energy Station located near Osceola,
Arkansas. We are entitled to 7.52% of the station’s capacity, and are obligated to pay for a like percentage
of the station’s operating costs.
110
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
At December 31, 2015 and 2014, our property, plant and equipment accounts included the amounts in
the following chart (in millions):
Plum Point Energy Station
2015
2014
Cost of ownership in plant in service . . . . . . . . . . . . . . . . . . . . . .
Accumulated Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expenditures(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$109.1
$ 11.9
9.6
$
$108.3
9.4
$
8.1
$
(1) Recognized in operating, maintenance and fuel expenditures excluding depreciation
expense.
All of the dollar amounts listed above represent our ownership share of costs.
11. COMMITMENTS AND CONTINGENCIES
We are a party to various claims and legal proceedings arising out of the normal course of our
business. We regularly analyze this information, and provide accruals for any liabilities, in accordance with
the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is
not probable, given the company’s defenses, that the ultimate outcome of these claims and lawsuits will
have a material adverse effect upon our financial condition, or results of operations or cash flows.
Coal, Natural Gas and Transportation Contracts
The following table sets forth our firm physical gas, coal and transportation contracts for the periods
indicated as of December 31, 2015 (in millions).
Firm physical gas
and transportation
contracts
Coal and coal
transportation
contracts
January 1, 2016 through December 31, 2016 . . . . . . .
January 1, 2017 through December 31, 2018 . . . . . . .
January 1, 2019 through December 31, 2020 . . . . . . .
January 1, 2021 and beyond . . . . . . . . . . . . . . . . . . .
$26.7
37.4
28.8
45.7
$18.0
27.5
10.8
—
We have entered into long and short-term agreements to purchase coal and natural gas for our energy
supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm
physical commitments and derivatives that are used to hedge future purchases. In the event that this gas
cannot be used at our plants, the gas would be placed in storage. The firm physical gas and transportation
commitments are detailed in the table above.
We have coal supply agreements and transportation contracts in place to provide for the delivery of
coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce
tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical
maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This
reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The
minimum requirements for our coal and coal transportation contracts as of December 31, 2015 are
detailed in the table above.
111
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Purchased Power
We currently supplement our on-system (native load) generating capacity with purchases of capacity
and energy from other entities in order to meet the demands of our customers and the capacity margins
applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules.
The Plum Point Energy Station (Plum Point) is a 670-megawatt, coal-fired generating facility near
Osceola, Arkansas. We own, through an undivided interest, 50 megawatts of the unit’s capacity. We also
have a long-term agreement for the purchase of an additional 50 megawatts of capacity from Plum Point.
Commitments under this agreement are approximately $277.6 million through August 31, 2039, the end
date of the agreement. We had the option to purchase an undivided ownership interest in the 50 megawatts
covered by the purchased power agreement. We evaluated this purchase option as part of our Integrated
Resource Plan (IRP), which was filed with the MPSC on July 1, 2013. We did not exercise this option by
the March 2015 notification deadline in the contract.
We have a long-term purchased power agreement, which expires in 2028, with Cloud County
Windfarm, LLC, owned by EDP Renewables North America LLC, Houston, Texas to purchase the energy
generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County,
Kansas. We do not own any portion of the windfarm. Annual payments are contingent upon output of the
facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average
cost.
We also have a long-term contract, which expires in 2025, with Elk River Windfarm, LLC, owned by
IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River
Windfarm located in Butler County, Kansas. We do not own any portion of the windfarm. Annual
payments are contingent upon output of the facility and can range from zero to a maximum of
approximately $16.9 million based on a 20-year average cost.
Payments for these agreements are recorded as purchased power expenses, and, because of the
contingent nature of these payments, are not included in the operating lease obligations shown below.
New Construction
We have in place a contract with a third party vendor to complete engineering, procurement, and
construction activities at our Riverton plant to convert Riverton Unit 12 from a simple cycle combustion
turbine to a combined cycle unit. The conversion includes the installation of a heat recovery steam
generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary
equipment. The Air Emission Source Construction Permit necessary for this project was issued by Kansas
Department of Health and Environment on July 11, 2013. This conversion is currently scheduled to be
completed in early to mid-2016 at a cost estimated to range from $165 million to $175 million, excluding
allowance for funds used during construction (AFUDC). Construction costs, consisting of pre-engineering,
site preparation activities and contract costs incurred project to date through December 31, 2015 were
$159.6 million, excluding AFUDC.
In December 2014 we completed an environmental retrofit at our Asbury plant. The retrofit project
included the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder
activated carbon injection system. This new equipment enables us to comply with the Mercury and Air
Toxics Standard (MATS). Final costs were approximately $112.1 million, excluding AFUDC.
112
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Leases
We have purchased power agreements with Cloud County Windfarm, LLC and Elk River
Windfarm, LLC, which are considered operating leases for GAAP purposes. Details of these agreements
are disclosed in the Purchased Power section of this note.
We also currently have short-term operating leases for two unit trains to meet coal delivery demands,
for garage and office facilities for our electric segment and for one office facility related to our gas
segment. In addition, we have capital leases for certain office equipment and 108 railcars to provide coal
delivery for our ownership and purchased power agreement shares of the Plum Point generating facility.
The gross amount of assets recorded under capital leases total $5.3 million at December 31, 2015.
Our lease obligations over the next five years are as follows (in thousands):
Capital
Leases
Operating
Leases
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total minimum payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less amount representing interest . . . . . . . . . . . . . . . . . . . . . . .
$ 554
551
551
550
546
2,460
5,212
1,322
$ 734
689
648
484
—
—
$2,555
Present value of net minimum lease payments . . . . . . . . . . . . . .
$3,890
Expenses incurred related to operating leases were $0.8 million, $0.8 million and $0.8 million for 2015,
2014, and 2013, respectively, excluding payments for wind generated purchased power agreements. The
accumulated amount of amortization for our capital leases was $1.9 million and $1.5 million at
December 31, 2015 and 2014, respectively.
Environmental Matters
We are subject to various federal, state, and local laws and regulations with respect to air and water
quality and with respect to hazardous and toxic materials and hazardous and other wastes, including their
identification, transportation, disposal, record-keeping and reporting, as well as remediation of
contaminated sites and other environmental matters. We believe that our operations are in material
compliance with present environmental laws and regulations. While we are not in a position to accurately
estimate compliance costs for any new requirements, we expect these costs to be material, although
recoverable in rates.
Compliance Plan
In order to comply with current and forthcoming environmental regulations, we continue to
implement our compliance plan and strategy (Compliance Plan), which largely follows our Integrated
Resource Plan (IRP) filed with MPSC in mid-2013. The Mercury Air Toxic Standards (MATS) and the
Clean Air Interstate Rule (CAIR), replaced by the Cross State Air Pollution Rule (CSAPR), are the
drivers behind our Compliance Plan and its implementation schedule. We anticipate compliance costs
associated with the MATS, CAIR and CSAPR regulations to continue to be recoverable in our rates.
113
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
The following list summarizes the most significant environmental regulations affecting our operations:
Regulations
Air Emissions — NOx and SO2
CAIR (Clean Air Interstate Rule)
CSAPR (Cross State Air Pollution Rule)
MATS (Mercury Air Toxic Standards)
NAAQS (National Ambient Air Quality Standards)
Greenhouse Gases (GHGs) — CO2
Surface Impoundments
Coal Ash Impoundments:
Asbury Power Plant
Riverton (capped and closed in 2014 as industrial (coal combustion waste) landfill)
Water Discharges
MATS:
In June 2015, the U.S. Supreme Court remanded the MATS back to the D.C. Circuit Court,
holding that the EPA must consider cost (including cost of compliance) before deciding whether a
regulation is appropriate and necessary. The court noted that it will be up to the EPA to decide within the
limits of reasonable interpretation how to account for cost. MATS remains in effect until the D.C. Circuit
Court acts.
Greenhouse Gases: On August 3, 2015, the EPA released the final rule for limiting carbon emissions
from existing power plants. The ‘‘Clean Power Plan’’ (CPP) requires a 32% carbon emission reduction
from 2005 baseline levels by 2030 and requires fossil fuel-fired power plants across the nation, including
those in Empire’s fleet, to meet state-specific goals to lower carbon levels. States will choose between two
plan types to meet their goals: an emission standards plan which includes source-specific requirements
impacting affected power plants or a state measures plan which includes a mixture of measures
implemented by the state.
By September 6, 2016, each state must either submit to the EPA its initial plan with a request for an
extension or a final plan. If the state receives an extension, the final plan must be submitted by
September 6, 2018. States will then implement plans to achieve the progressive CO2 emissions
performance rates over the period of 2022 to 2029 with the final CO2 goal accountability by 2030. Empire
continues to evaluate potential paths forward on the final rule released by the EPA. As of January 26, 2016,
twenty-five states have initiated legal challenges to the CPP which by and large seek to invalidate the rule.
The ultimate cost of compliance cannot be determined at this time because of the uncertainties regarding
the final outcome of the GHG regulations, including the legal challenges thereto, and the compliance
methods yet to be chosen by the jurisdictions in which we operate. In any case, we expect the cost of
complying with any such regulations to be recoverable in our rates.
Surface Impoundments: On September 30, 2015, the EPA finalized a revision of the Clean Water
Act (CWA) Steam Electric Effluent Limitation Guidelines (ELGs) for coal-fired power plants. The new
rule sets technology-based ELGs based on the nature of the pollutants being discharged and the facilities
involved. As published, beginning in November 2018, the EPA and states would incorporate the new
standards into all wastewater discharge permits, including permits for coal ash impoundments. We do not
have sufficient information at this time to estimate additional costs at each facility that will result from the
new standards to be in effect no later than December 2023.
114
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Effective October 19, 2015, the EPA established a final rule to regulate the disposal of coal
combustion residuals (CCRs) as a non-hazardous solid waste under subtitle D of the Resource
Conservation and Recovery Act (RCRA). We expect compliance with both the CCR and ELG rule to
result in the need to construct a new landfill and the conversion of existing bottom ash handling from a wet
to a dry system at a potential cost of up to $15 million at our Asbury Power Plant. We expect resulting costs
to be recoverable in our rates. Final closure of the existing ash impoundment, for which an asset retirement
obligation of $5.4 million has been recorded, is anticipated after the new landfill is operational. Separately,
an asset retirement obligation of $4.4 million has been recorded for our interest in the coal ash
impoundment at the Iatan Generating Station.
We have received preliminary permit approval in Missouri for a new utility waste landfill adjacent to
the Asbury plant. A technical review of our Detailed Site Investigation (DSI) for the specific site has been
completed and was approved by the Missouri Department of Natural Resources on June 29, 2015. Receipt
of the final construction permit for the CCR waste landfill is expected in January 2017.
Water Discharges: We operate under the Kansas and Missouri Water Pollution Plans pursuant to the
Federal Clean Water Act (CWA). Our plants are in material compliance with applicable regulations and
have received all necessary discharge permits.
The EPA final rule under the CWA Section 316(b) for existing cooling water intake structures became
effective on October 14, 2014. An industry coalition has filed an appeal of the rule in the Fifth Circuit and
additional court challenges are expected. We expect the regulations to have no future impact at Riverton
as the new intake structure design and installed cooling tower, as part of the Unit 12 conversion, meets the
regulatory requirement for aquatic life protections. Impacts at Iatan 1 could range from flow velocity
reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower
retrofit. Iatan Unit 2 and Plum Point Unit 1 are covered by the regulation, but were constructed with
cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally
affected by the final rule.
Renewable Energy
On November 4, 2008 Missouri voters approved the Clean Energy Initiative (Proposition C) which
currently requires Empire and other investor-owned utilities in Missouri to generate or purchase electricity
from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase Renewable
Energy Credits (RECs), in amounts equal to at least 5% of retail sales in 2014, increasing to at least 15%
by 2021. We are currently in compliance with this regulatory requirement as a result of generation from
our Ozark Beach Hydroelectric Project and purchased power agreements with Cloud County
Windfarm, LLC and Elk River Windfarm, LLC. Proposition C also requires that 2% of the energy from
renewable energy sources must be solar; however, we believed that we were exempted by statute from the
solar requirement. On January 20, 2013 the Earth Island Institute, d/b/a Renew Missouri, and others
challenged our solar exemption by filing a complaint with the MPSC. The MPSC dismissed the complaint
and Renew Missouri filed a notice of appeal seeking review by the Missouri Supreme Court. On
February 10, 2015 the Missouri Supreme Court issued an opinion holding that the legislature had the
authority to adopt the statute providing the exemption but reversed the MPSC’s holding that the two laws
could be harmonized. The statute providing the exemption (which was enacted in August 2008) was
impliedly repealed by the adoption of Proposition C because it conflicted with the latter law. On May 6,
2015, the MPSC approved tariffs we filed on May 5, 2015 to establish solar rebate payment procedures and
revise our net metering tariffs to accommodate the payment of solar rebates. As of December 31, 2015, we
had processed 262 solar rebate applications resulting in solar rebate-related costs totaling approximately
$3.5 million under the new tariff. We have recorded the $3.5 million as a regulatory asset
115
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
(See Note 3 — Regulatory Matters). The law provides a number of methods that may be utilized to recover
the associated expenses. We expect any costs to be recoverable in rates.
Legislation was recently adopted that altered the Kansas renewable portfolio standard (RPS), ending
all mandatory requirements in 2015. The mandate, which required 20% of our Kansas retail customer peak
capacity requirements to be sourced from renewables by 2020, has been changed to a voluntary goal. We
are currently in compliance as a result of purchased power agreements with Cloud County Windfarm, LLC
and Elk River Windfarm, LLC.
12. SEGMENT INFORMATION
We operate our business as three segments: electric, gas and other. As part of our electric segment, we
also provide water service to three towns in Missouri. The Empire District Gas Company is our wholly
owned subsidiary formed to provide gas distribution service in Missouri. The other segment consists of our
non-regulated businesses which is primarily our fiber optics business.
The tables below present statement of income information, balance sheet information and capital
expenditures of our business segments.
For the year ended December 31,
2015
Electric
Gas
Other
Eliminations
Total
Statement of Income Information:
Operating Revenues(1)
. . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . .
Federal and state income taxes . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . .
Income from AFUDC (debt and equity) . . . .
Income from continuing operations . . . . . . . .
$555,085
74,732
31,123
88,124
133
41,307
7,681
$ 52,240
$41,702
3,923
800
5,153
36
3,867
14
$ 1,287
$10,165
1,895
1,889
3,024
47
—
—
$ 3,070
$(1,379)
—
—
—
(71)
(71)
—
$605,573
80,550
33,812
96,301
145
45,103
7,695
$ — $ 56,597
Capital Expenditures . . . . . . . . . . . . . . . . . . . .
$169,111
$ 5,190
$ 2,223
$ — $176,524
(1) The Electric Segment includes SPP Integrated Marketplace net revenues of $15.0 million.
Electric
Gas
Other
Eliminations
Total
2014
Statement of Income Information:
Operating Revenues(1)
. . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . .
Federal and state income taxes . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . .
Income from AFUDC (debt and equity) . . . . .
Income from continuing operations . . . . . . . .
$592,491
67,534
35,737
90,488
37
37,911
9,833
$ 61,467
$51,842
3,760
1,840
6,775
25
3,861
84
$ 2,965
$9,302
1,891
1,643
2,736
21
—
—
$2,671
$(1,305)
—
—
—
(32)
(32)
—
$652,330
73,185
39,220
99,999
51
41,740
9,917
$ — $ 67,103
Capital Expenditures . . . . . . . . . . . . . . . . . . . .
$212,866
$ 7,836
$2,151
$ — $222,853
(1) The Electric Segment includes SPP Integrated Marketplace net revenues of $41.9 million.
116
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Electric
Gas
Other
Eliminations
Total
2013
Statement of Income Information:
Operating Revenues . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . .
Federal and state income taxes . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . .
Income from AFUDC (debt and equity) . . . . .
Income from continuing operations . . . . . . . .
$536,413
63,659
34,478
90,984
537
37,683
5,910
$ 58,603
$50,041
3,709
1,484
6,194
115
3,890
30
$ 2,355
$9,147
1,938
1,530
2,485
8
—
—
$2,487
$(1,271)
—
—
—
(94)
(94)
—
$594,330
69,306
37,492
99,663
566
41,479
5,940
$ — $ 63,445
Capital Expenditures . . . . . . . . . . . . . . . . . . . .
$153,401
$ 4,419
$2,388
$ — $160,208
Electric
Gas(1)
Other
Eliminations
Total
December 31, 2015
Balance Sheet Information:
Total assets . . . . . . . . . . . . . . . . . . . . . . .
$2,339,850
$127,871
$38,300
$(50,718)
$2,455,303
Electric
Gas(1)
Other
Eliminations
Total
December 31, 2014
Balance Sheet Information:
Total assets . . . . . . . . . . . . . . . . . . . . . . .
$2,252,339
$130,856
$34,655
$(46,794)
$2,371,056
(1) Includes goodwill of $39,492 at December 31, 2015 and 2014.
117
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
13. SELECTED QUARTERLY INFORMATION (UNAUDITED)
The following is a summary of quarterly results for 2015 and 2014 (dollars in thousands except per
share amounts):
Quarterly Results for 2015
First
Second
Third
Fourth
Operating revenues(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$164,544
$ 24,713
$134,557
$ 16,047
$169,714
$ 35,783
$136,758
$ 19,757
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 14,637
Basic Earnings Per Share . . . . . . . . . . . . . . . . . . . . . . . .
Diluted Earnings Per Share . . . . . . . . . . . . . . . . . . . . . .
$
$
0.34
0.34
$
$
$
6,770
$ 25,285
0.16
0.15
$
$
0.58
0.58
$
$
$
9,905
0.23
0.23
Quarters
(1) Operating revenue for the first, second, third and fourth quarters of 2015 include SPP IM net
revenues of $4.7 million, $3.4 million, $4.0 million, and $2.9 million, respectively.
Quarterly Results for 2014
First
Second
Third
Fourth
Operating revenues(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$179,673
$ 29,488
$149,782
$ 19,502
$171,512
$ 31,709
$151,363
$ 19,300
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 20,905
$ 11,194
$ 23,892
$ 11,112
Basic and Diluted Earnings Per Share . . . . . . . . . . . . . . .
$
0.48
$
0.26
$
0.55
$
0.26
Quarters
(1) Operating revenue for the first, second, third and fourth quarters of 2014 include SPP IM net
revenues of $6.2 million, $16.5 million, $11.5 million, and $7.5 million, respectively.
The sum of the net income and quarterly earnings per share of common stock may not equal the net
income and earnings per share of common stock as computed on an annual basis due to rounding.
14. RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS
We engage in hedging activities in an effort to minimize our risk from the volatility of natural gas
prices and power cost risk associated with exposure to congestion costs. We enter into both physical and
financial contracts with counterparties relating to our future natural gas requirements that lock in prices
(with respect to a range of predetermined percentages of our expected future natural gas needs) in an
attempt to lessen the volatility in our fuel expenditures and gain cost predictability.
We began acquiring Transmission Congestion Rights (TCR) in 2013 in an effort to mitigate the cost of
power we purchase from the SPP IM due to congestion exposure. TCRs entitle the holder to a stream of
revenues (or charges) based on the day-ahead congestion on the transmission path. TCRs can be
purchased or self-converted using rights allocated based on prior investments made in the transmission
system. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform
contractual obligations, actual results could differ materially from intended results.
All derivative instruments are recognized at fair value on the balance sheet. The unrealized losses or
gains from derivatives used to hedge our fuel and purchased power costs in our electric segment are
recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment
are also recorded in regulatory assets or liabilities. This is in accordance with the ASC guidance on
118
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
regulated operations, given that those gains or losses are probable of refund or recovery, respectively,
through our fuel adjustment mechanisms.
Risks and uncertainties affecting the determination of fair value include: market conditions in the
energy industry, especially the effects of price volatility, regulatory and global political environments and
requirements, fair value estimations on longer term contracts, the effectiveness of the derivative
instruments in hedging the change in fair value of the hedged item, estimating underlying fuel demand and
counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or
loss on the overhedged portion will be recognized immediately as fuel and purchased power expense in our
Consolidated Statement of Income and subject to our fuel adjustment mechanism.
As of December 31, 2015 and 2014, we have recorded the following assets and liabilities representing
the fair value of derivative financial instruments held as of December 31, (in thousands):
Non-designated hedging instruments due to regulatory accounting
ASSET DERIVATIVES
Natural gas contracts, gas segment
Natural gas contracts, electric segment
Balance Sheet Classification
Current assets . . . . . . . . . . . . . . . . . . . .
Non-current assets and deferred
charges — Other . . . . . . . . . . . . . . . .
Current assets . . . . . . . . . . . . . . . . . . . .
Non-current assets and deferred
charges — Other . . . . . . . . . . . . . . . .
2015
Fair
Value
2014
Fair
Value
$
2
$ —
16
—
—
—
1
—
Transmission congestion rights, electric
segment
Current assets . . . . . . . . . . . . . . . . . . . .
1,293
3,900
Total derivatives assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,311
$3,901
LIABILITY DERIVATIVES
Non-designated as hedging instruments due to regulatory accounting
Natural gas contracts, gas segment
Balance Sheet Classification
Current liabilities . . . . . . . . . . . . . . . . . .
Non-current liabilities and deferred
2015
Fair
Value
2014
Fair
Value
$ 282
$ 476
credits . . . . . . . . . . . . . . . . . . . . . . . .
66
—
Natural gas contracts, electric segment . Current liabilities . . . . . . . . . . . . . . . . . .
4,190
5,993
Non-current liabilities and deferred
credits . . . . . . . . . . . . . . . . . . . . . . . .
3,630
3,243
Transmission congestion rights, electric
segment . . . . . . . . . . . . . . . . . . . . . Current liabilities . . . . . . . . . . . . . . . . . .
—
—
Total derivatives liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$8,168
$9,712
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THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Electric
At December 31, 2015, approximately $4.2 million of unrealized losses are applicable to financial
instruments which will settle within the next twelve months.
There were no ‘‘mark-to-market’’ pre-tax gains/ (losses) from ineffective portions of our hedging
activities for the electric segment for the years ended December 31, 2015 and 2014, respectively.
The following tables set forth ‘‘mark-to-market’’ pre-tax gains/ (losses) from non-designated derivative
instruments for the electric segment for each of the years ended December 31 (in thousands):
Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment
Balance Sheet Classification
of Gain/(Loss) on Derivative
Amount of
Gain/(Loss)
Recognized on
Balance Sheet
2015
2014
Commodity contracts — electric
segment
Transmission congestion rights —
electric segment
Regulatory (assets)/liabilities . . . . . . . . .
$(6,853) $ (6,780)
Regulatory (assets)/liabilities . . . . . . . . .
4,970
12,958
Total — Electric Segment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(1,883) $ 6,178
Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment
Statement of Operations Classification
of Loss on Derivative
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
2015
2014
Commodity contracts
Transmission congestion rights —
electric segment
Fuel and purchased power expense . . . .
$(8,115) $ (1,659)
Fuel and purchased power expense . . . .
7,468
11,106
Total — Electric Segment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (647) $ 9,447
We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and
purchased power. These contracts are not subject to fair value accounting because they qualify for the
normal purchase normal sale exemption. We have a process in place to determine if any future executed
contracts that otherwise qualify for the normal purchase normal sale exception contain a price adjustment
feature and will account for these contracts accordingly.
120
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
At December 31, 2015, the following volumes and percentages of our anticipated volume of natural
gas usage for our electric operations for 2016 and the next four years are hedged at the following average
prices per Dekatherm (Dth):
Year
% Hedged
Dth Hedged
Physical
Dth Hedged
Financial
Average Price
2016 . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . .
61% 2,706,000
782,900
41%
20%
565,000
10%
0%
5,940,000
5,210,000
2,460,000
— 1,460,000
—
—
$3.372
$3.347
$3.334
$2.955
—
We utilize the following procurement guidelines for our electric segment, allowing the flexibility to
hedge up to 100% of the current year’s and 80% of any future year’s expected requirements while being
cognizant of volume risk. The 80% guideline is an annual target and volumes up to 100% can be hedged in
any given month. For years beyond year four, additional factors of long term uncertainty (including with
respect to required volumes and counterparty credit) are also considered.
Year
End of Year
Minimum % Hedged
Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Up to 100%
60%
40%
20%
10%
At December 31, 2015, the following transmission congestion rights (TCR) have been obtained from
TCR auctions to hedge congestion costs in the SPP Integrated Marketplace:
Year
Monthly
MWH
Hedged
$ Value
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,212
$1,292,943
Gas
We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting
natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts
and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by
November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from
storage to serve our customers. As of December 31, 2015 we had 1.4 million Dths in storage on the three
pipelines that serve our customers. This represents 70% of our storage capacity.
The following table sets forth our long-term hedge strategy of mitigating price volatility for our
customers by hedging a minimum of expected gas usage for the current winter season and the next two
121
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
winter seasons by the beginning of the ACA year at September 1 and illustrates our hedged position as of
December 31, 2015 (Dth in thousands).
Season
Minimum % Dth Hedged
Hedged
Financial
Dth Hedged
Physical
Dth in
Storage
Actual %
Hedged
. . . . . . . . . . . . . . . . . . . . . . . . . .
50% 400,000
Current
Second . . . . . . . . . . . . . . . . . . . . . . . . . . . Up to 50% 200,000
Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . Up to 20% 280,000
—
—
—
1,419,752
—
—
93%
6%
9%
A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations,
therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to
financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.
The following table sets forth ‘‘mark-to-market’’ pre-tax gains/ (losses) from derivatives not
designated as hedging instruments for the gas segment for the years ended December 31 (in thousands):
Non-Designated Hedging Instruments Due to Regulatory Accounting — Gas Segment
Amount of
Loss
Recognized on
Balance Sheet
Commodity contracts
Regulatory assets . . . . . . . . . . . . . . . . . .
$(447) $(511)
—
Total — Gas Segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(447) $(511)
Balance Sheet Classification of Loss on Derivative
2015
2014
Contingent Features
Certain of our derivative instruments contain provisions that are triggered if we fail to maintain an
investment grade credit rating with any relevant credit rating agency. If our debt were to fall below
investment grade, the counterparties to the derivative instruments could request increased collateralization
on derivative instruments in net liability positions. We had no derivative instruments with the
credit-risk-related contingent features in a net liability position on December 31, 2015 and have posted no
collateral in the normal course of business. Amounts reported as margin deposit assets represent our funds
held on deposit for our NYMEX contracts with our broker and other financial contracts with other
counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties.
The following table depicts our margin deposit assets at the dates shown. There were no margin deposit
liabilities at these dates.
(in millions)
Margin deposit assets . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31,
2015
December 31,
2014
$11.2
$9.1
Offsetting of derivative assets and liabilities
We believe that entering into master trading and netting agreements mitigates the level of financial
loss that could result from a default under derivatives agreements by allowing net settlement of derivative
assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the
International Swaps and Derivatives Association Agreement, a standardized financial natural gas and
122
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
electric contract; and (2) the North American Energy Standards Board Inc. Agreement, a standardized
contract for the purchase and sale of natural gas. These master trading and netting agreements allow the
counterparties to net settle sale and purchase transactions. Collateral requirements are calculated at the
master trading and netting agreement level by the counterparty.
As shown above, our asset and liability commodity contract derivatives are reported at gross on the
balance sheet. ASC guidance permits companies to offset fair value amounts recognized for the right to
reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair
value amounts recognized for derivative instruments that are executed with the same counterparty under
the same master netting arrangement. For the years ended December 31, 2015 and December 31, 2014, we
did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin
deposit assets described above. We have elected not to offset our margin deposit assets against any of our
eligible commodity contracts.
15. FAIR VALUE MEASUREMENTS
The accounting guidance on fair value measurements establishes a three-tier fair value hierarchy,
which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted
prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in
active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable
inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.
Our Level 2 fair value measurements consist of both quoted price inputs and inputs that are derived
principally from or corroborated by observable market data.
The guidance also requires that the fair value measurement of assets and liabilities reflect the
nonperformance risk of counterparties and the reporting entity, as applicable. Therefore, using credit
default spreads, we factored the impact of our own credit standing and the credit standing of our
counterparties, as well as any potential credit enhancements (e.g. collateral) into the consideration of
nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material
to the financial statements.
Our TCR positions, which are acquired on the SPP Integrated Marketplace, are valued using the most
recent monthly auction clearing prices. Our commodity contracts are valued using the market value
123
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
approach on a recurring basis. The following fair value hierarchy table presents information about our
TCR and commodity contracts measured at fair value as of December 31:
Fair Value Measurements at Reporting Date Using
($ in 000’s)
Description
December 31, 2015
Derivative assets . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities . . . . . . . . . . . . . . . . . . . .
December 31, 2014
Derivative assets . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities . . . . . . . . . . . . . . . . . . . .
Quoted Prices
in Active
Markets
for Identical
Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Assets/(Liabilities)
at Fair Value
$ 1,311
$(8,168)
$ 3,901
$(9,712)
$
18
$(8,168)
1
$
$(9,712)
$1,293
$ —
$3,900
$ —
$ —
$ —
$ —
$ —
*
The only recurring measurements are derivative related.
Other fair value considerations
Our cash and cash equivalents approximate fair value because of the short-term nature of these
instruments, and are classified as Level 1 in the fair value hierarchy. The carrying amount of our
short-term debt, which is composed of Empire issued commercial paper or revolving credit borrowings,
also approximates fair value because of their short-term nature. These instruments are classified as Level 2
in the fair value hierarchy as they are valued based on market rates for similar market transactions.
The carrying amount of our total long-term debt exclusive of capital leases at December 31, 2015 and
2014 was $859 million and $799 million, compared to a fair market value of approximately $815 million
and $829 million, respectively. These estimates were based on a bond pricing model, utilizing inputs
classified as Level 2 in the fair value hierarchy, which include the quoted market prices for the same or
similar issues or on the current rates offered to us for debt of the same remaining maturities. The
estimated fair market value may not represent the actual value that could have been realized as of
December 31, 2015 or that will be realizable in the future.
124
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
16. REGULATED OPERATING EXPENSE
The following table sets forth the major components comprising ‘‘regulated operating expenses’’
under ‘‘Operating Revenue Deductions’’ on our consolidated statements of income for the years ended (in
thousands):
December 31,
2015
2014
2013
Power operation expense (other than fuel) . . . . . . . . . . . . . . . . . . . .
Electric transmission and distribution expense . . . . . . . . . . . . . . . . . .
Natural gas transmission and distribution expense . . . . . . . . . . . . . . .
Customer accounts & assistance expense . . . . . . . . . . . . . . . . . . . . .
Employee pension expense(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employee healthcare plan(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General office supplies and expense . . . . . . . . . . . . . . . . . . . . . . . . .
Administrative and general expense . . . . . . . . . . . . . . . . . . . . . . . . .
Bad debt expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory reversal of gain on sale of assets . . . . . . . . . . . . . . . . . . .
Miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 18,263
28,893
2,699
10,937
10,786
10,162
14,438
14,863
2,080
—
430
$ 16,089
27,919
2,362
11,239
10,590
9,147
15,024
14,385
3,420
44
472
$ 15,643
21,863
2,498
11,180
10,736
10,190
12,850
14,800
3,665
1,236
672
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$113,551
$110,691
$105,333
(1) Does not include the capitalized portion of actuarially calculated costs, but reflects the GAAP
expensed portion of these costs plus or minus costs deferred to a regulatory asset or recognized as a
regulatory liability for Missouri and Kansas jurisdictions.
17. SUBSEQUENT EVENT — AGREEMENT AND PLAN OF MERGER
On February 9, 2016, Empire entered into an Agreement and Plan of Merger (the Merger
Agreement) with Liberty Utilities (Central) Co., a Delaware corporation (Liberty), and Liberty Sub Corp.,
a Kansas corporation (Merger Sub), providing for the merger of Merger Sub with and into Empire, with
Empire surviving the Merger as a wholly-owned subsidiary of Liberty (the Merger). Pursuant to the
Merger Agreement, at the effective time of the Merger, each issued and outstanding share of Empire
common stock (other than any shares owned by Empire or Algonquin Power & Utilities Corp. (APUC)) or
any of their respective subsidiaries or any shares for which appraisal rights have been perfected) will be
cancelled and converted automatically into the right to receive $34.00 in cash, without interest.
The closing of the Merger is subject to certain conditions, including, among others, approval of
Empire shareholders, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period
and receipt of all required regulatory approvals and consents, including from the Federal Energy
Regulatory Commission, the Federal Communications Commission, the Arkansas Public Service
Commission, the Kansas Corporation Commission, the Missouri Public Service Commission, the
Oklahoma Corporation Commission and the Committee on Foreign Investment in the United States,
which approvals and consents shall not, individually or in the aggregate, have or be reasonably likely to
have a material adverse effect on the business, properties, financial condition or results of operations of
Liberty Utilities Co. and its subsidiaries (including Empire and its subsidiaries), taken as a whole.
If Empire shareholders do not approve the Merger, or the Merger is not consummated by February 9,
2017, the Merger Agreement may terminate, although it may be extended six months in order to obtain
certain required regulatory approvals. The Merger Agreement also provides for certain other termination
125
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
rights for both Empire and Liberty. If either party terminates the Merger Agreement because Empire’s
board of directors changes its recommendation, or, if within nine months after the termination of the
Merger Agreement under certain circumstances, Empire shall have entered into a definitive agreement
with respect to, or consummated, an alternative transaction, Empire must pay Liberty a termination fee of
$53.0 million. If the Merger Agreement is terminated under certain other circumstances, including the
failure to obtain required regulatory approvals, failure to consummate the Merger after all closing
conditions have been satisfied and a financing failure has occurred or a breach by Liberty of its regulatory
cooperation covenants, Liberty must pay Empire a termination fee of $65.0 million.
Simultaneously with the execution of the Merger Agreement, Liberty delivered to Empire a guarantee
agreement (the Guarantee Agreement) executed by APUC, the parent of Liberty Utilities Co. The
Guarantee Agreement provides for an unconditional and irrevocable guarantee by APUC of the full and
prompt payment and performance, when due, of all obligations of Liberty and Merger Sub under the
Merger Agreement.
In connection with entering into the Merger Agreement, Empire has incurred approximately
$0.2 million of transaction costs as of December 31, 2015. We expect that the total transaction costs will be
approximately $15 to $17 million, with approximately 50% payable in 2016 (assuming a 2017 closing date),
of which approximately $4.5 million will be incurred in the first quarter of 2016. The foregoing description
of the Merger, the Merger Agreement and the Guarantee is not a complete description thereof and is
qualified in its entirety by reference to the full text of the Merger Agreement and the Guarantee. For more
information regarding the terms of the Merger, including copies of the Merger Agreement and the
Guarantee, see Empire’s Current Report on Form 8-K filed with the SEC on February 9, 2016.
126
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation was carried out, under the
supervision and with the participation of our management, including our Chief Executive Officer and
Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and
procedures (as such term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon
that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure
controls and procedures were effective as of December 31, 2015.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and
with the participation of our management, including our Chief Executive Officer and Chief Financial
Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting
based on the framework in the Internal Control — Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation,
management concluded that our internal control over financial reporting was effective as of December 31,
2015.
Audit of Internal Control Over Financial Reporting
The effectiveness of our internal control over financial reporting as of December 31, 2015, has been
audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in
their report which appears herein.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting that occurred during the
fourth quarter of 2015 that have materially affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
127
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Except as set forth below, the information required by this Item may be found in our proxy statement
for our Annual Meeting of Stockholders to be held April 28, 2016, which is incorporated herein by
reference.
Pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, the information required by
this Item with respect to executive officers is set forth in Item 1 of Part I of this Form 10-K under
‘‘Executive Officers and Other Officers of Empire.’’
We have adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers. A
copy of the code is available on our website at www.empiredistrict.com. Any future amendments or waivers
to the code will be posted on our website at www.empiredistrict.com.
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item may be found in our proxy statement for our Annual Meeting of
Stockholders to be held April 28, 2016, which is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Except as set forth below, information required by this item may be found in our proxy statement for
our Annual Meeting of Stockholders to be held April 28, 2016, which is incorporated herein by reference.
Securities Authorized For Issuance Under Equity Compensation Plans
We have four equity compensation plans, all of which have been approved by shareholders, namely
the 2006 Stock Incentive Plan, the 2015 Stock Incentive Plan (which replaces the 2006 Stock Incentive Plan
for new grants effective January 1, 2015), the Employee Stock Purchase Plan (ESPP) and the Stock Unit
Plan for Directors.
The following table summarizes information about our equity compensation plans as of December 31,
2015:
Plan Category
(a) Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights.
(b) Weighted-average
exercise price of
outstanding options,
warrants and rights(1)
(c) Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column (a))
Equity compensation plans approved
by security holders . . . . . . . . . . . . .
422,214
Equity compensation plans not
approved by security holders . . . . .
—
TOTAL . . . . . . . . . . . . . . . . . . . .
422,214
$N/A
—
$N/A
2,023,019
—
2,023,019
(1) There is no exercise price for 150,200 performance-based stock awards and 55,600 time-vested
restricted stock awards awarded under the 2006and 2015 Stock Incentive Plan or for 157,672 units
awarded under the Stock Unit Plan for Directors
(2) Includes 764,645 shares available for issuance under the ESPP of which 58,742 shares are subject to
purchase under the current purchase period.
128
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information required by this Item may be found in our proxy statement for our Annual Meeting
of Stockholders to be held April 28, 2016 which is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item may be found in our proxy statement for our Annual Meeting
of Stockholders to be held April 28, 2016 which is incorporated herein by reference.
129
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
PART IV
Index to Financial Statements and Financial Statement Schedule Covered by Report of
Independent Registered Public Accounting Firm
Consolidated balance sheets at December 31, 2015 and 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of income for each of the three years in the period ended December 31,
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of common stockholders’ equity for each of the three years in the
period ended December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of cash flows for each of the three years in the period ended
December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to consolidated financial statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Schedule for the years ended December 31, 2015, 2014 and 2013:
Schedule II — Valuation and qualifying accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
58
60
61
62
64
135
All other schedules are omitted as the required information is either not present, is not present in
sufficient amounts, or the information required therein is included in the financial statements or notes
thereto.
List of Exhibits
(2)(a) Agreement and Plan of Merger, dated as of February 9, 2016, by and among The Empire
District Electric Company, Liberty Utilities (Central) Co. and Liberty Sub Corp. (Incorporated
by reference to Exhibit 2.1 to Current Report on Form 8-K dated February 9, 2016 and filed
February 9, 2016, File No. 1-3368).
(3)(a) The Restated Articles of Incorporation of Empire (Incorporated by reference to Exhibit 4(a) to
Registration Statement No. 33-54539 on Form S-3).
(b) Amended and Restated By-Laws of The Empire District Electric Company, effective
February 9, 2016 (Incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K
dated February 9, 2016 and filed February 9, 2016, File No. 1-3368).
(4)(a)
Indenture of Mortgage and Deed of Trust dated as of September 1, 1944 and First
Supplemental Indenture thereto among The Empire District Electric Company, The Bank of
New York Mellon Trust Company, N.A. and UMB Bank, N.A., (Incorporated by reference to
Exhibits B(1) and B(2) to Form 10, File No. 1-3368).
(b) Third Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by
reference to Exhibit 2(c) to Form S-7, File No. 2-59924).
(c)
Sixth through Eighth Supplemental Indentures to Indenture of Mortgage and Deed of Trust
(Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924).
(d) Fourteenth Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated
by reference to Exhibit 4(f) to Registration Statement No. 33-56635 on Form S-3).
(e) Twenty-Fourth Supplemental Indenture dated as of March 1, 1994 to Indenture of Mortgage
and Deed of Trust (Incorporated by reference to Exhibit 4(m) to Annual Report on Form 10-K
for the year ended December 31, 1993, File No. 1-3368).
130
(f) Twenty-Eighth Supplemental Indenture dated as of December 1, 1996 to Indenture of Mortgage
and Deed of Trust (Incorporated by reference to Exhibit 4(g) to Annual Report on Form 10-K
for the year ended December 31, 1996, File No. 1-3368).
(g) Thirty-First Supplemental Indenture dated as of March 26, 2007 to Indenture of Mortgage and
Deed of Trust (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated
March 26, 2007 and filed March 28, 2007, File No. 1-3368).
(h) Thirty-Second Supplemental Indenture dated as of March 11, 2008 to Indenture of Mortgage
and Deed of Trust (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K
dated March 11, 2008 and filed March 12, 2008, File No. 1-3368).
(i) Thirty-Third Supplemental Indenture dated as of May 16, 2008 to Indenture of Mortgage and
Deed of Trust (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated
May 16, 2008 and filed May 16, 2008, File No. 1-3368).
(j) Thirty-Fifth Supplemental Indenture, dated as of May 28, 2010, to Indenture of Mortgage and
Deed of Trust (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated
May 28, 2010 and filed May 28, 2010, File No. 1-3368).
(k) Thirty-Sixth Supplemental Indenture, dated as of August 25, 2010, to Indenture of Mortgage
and Deed of Trust (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K
dated August 25, 2010 and filed August 26, 2010, File No. 1-3368).
(l) Thirty-Seventh Supplemental Indenture, dated as of June 9, 2011, to Indenture of Mortgage and
Deed of Trust (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated
June 9, 2011 and filed June 10, 2011, File No. 1-3368).
(m) Thirty-Eighth Supplemental Indenture, dated as of April 2, 2012, to Indenture of Mortgage and
Deed of Trust (Incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K dated
April 2, 2012 and filed April 2, 2012, File No. 1-3368).
(n) Thirty-Ninth Supplemental Indenture, dated as of May 30, 2013, to Indenture of Mortgage and
Deed of Trust (Incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K dated
May 30, 2013 and filed May 30, 2013, File No. 1-3368).
(o) Fortieth Supplemental Indenture, dated as of December 1, 2014, to the Indenture of Mortgage
and Deed of Trust (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K
dated December 1, 2014 and filed December 2, 2014, File No. 1-3368).
(p) Forty-first Supplemental Indenture, dated as of August 20, 2015, to the Indenture of Mortgage
and Deed of Trust (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K
dated August 20, 2015 and filed August 21, 2015, File No. 1-3368).
(q) Bond Purchase Agreement, dated as of April 2, 2012, by and among the Company and the
Purchasers named therein (Incorporated by reference to Exhibit 4.1 to Current Report on
Form 8-K dated April 2, 2012 and filed April 2, 2012, File No. 1-3368).
(r) Bond Purchase Agreement, dated as of October 30, 2012, by and among the Company and the
Purchasers named therein (Incorporated by reference to Exhibit 4.1 to Current Report on
Form 8-K dated October 30, 2012 and filed November 2, 2012, File No. 1-3368).
(s) Bond Purchase Agreement, dated as of October 15, 2014, by and among the Company and the
Purchasers named therein (Incorporated by reference to Exhibit 4.1 to Current Report on
Form 8-K dated October 15, 2014 and filed October 16, 2014, File No. 1-3368).
131
(t) Bond Purchase Agreement, dated as of June 11, 2015, by and among the Company and the
Purchasers named therein (Incorporated by reference to Exhibit 4.1 to Current Report on
Form 8-K dated June 11, 2015 and filed June 12, 2015, File No. 1-3368).
(u)
(v)
(w)
Indenture for Unsecured Debt Securities, dated as of September 10, 1999 between Empire and
Wells Fargo Bank, National Association (Incorporated by reference to Exhibit 4(v) to
Registration Statement No. 333-87015 on Form S-3).
Securities Resolution No. 5, dated as of October 29, 2003, of Empire under the Indenture for
Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Quarterly Report on
Form 10-Q for quarter ended September 30, 2003), File No. 1-3368).
Securities Resolution No. 6, dated as of June 27, 2005, of Empire under the Indenture for
Unsecured Debt Securities (Incorporated by reference to Exhibit 4.1 to Current Report on
Form 8-K dated June 27, 2005 and filed June 28, 2005, File No. 1-3368).
(x) Bond Purchase Agreement dated June 1, 2006 among The Empire District Gas Company and
the purchasers party thereto (Incorporated by reference to Exhibit 4.1 to Current Report on
Form 8-K dated June 1, 2006 and filed June 6, 2006, File No. 1-3368).
(y)
Indenture of Mortgage and Deed of Trust dated as of June 1, 2006 by The Empire District Gas
Company, as Grantor, to Spencer R. Thomson, Deed of Trust Trustee for the Benefit of The
Bank of New York Trust Company, N.A., Bond Trustee, as Grantee (Incorporated by reference
to Exhibit 4.2 to Current Report on Form 8-K dated June 1, 2006 and filed June 6, 2006, File
No. 1-3368).
(z) First Supplemental Indenture of Mortgage and Deed of Trust dated as of June 1, 2006 by The
Empire District Gas Company, as Grantor, to Spencer R. Thomson, Deed of Trust Trustee for
the Benefit of The Bank of New York Trust Company, N.A., Bond Trustee, as Grantee
(Incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K dated June 1, 2006
and filed June 6, 2006, File No. 1-3368).
(10)(a)
2006 Stock Incentive Plan (Incorporated by reference to Exhibit 4(u) to Form S-8, File
No. 333-130075).†
(b) First Amendment to 2006 Stock Incentive Plan. (Incorporated by reference to Exhibit 10(d) to
Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-3368).†
(c)
(d)
Second Amendment to 2006 Stock Incentive Plan (Incorporated by reference to Exhibit 10(e) to
Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-3368).†
2015 Stock Incentive Plan (incorporated by reference to Appendix B to the definitive proxy
statement filed pursuant to Regulation 14A on March 19, 2014, File No. 1-3368).
(e) Deferred Compensation Plan for Directors as amended and restated effective January 1, 2008.
(Incorporated by reference to Exhibit 10(e) to Annual Report on Form 10-K for the year ended
December 31, 2007).†
(f) Deferred Compensation Plan for Officers effective January 1, 2015, (Incorporated by reference
to Exhibit 10(f) to Annual Report on Form 10-K for the year ended December 31, 2014, File
No. 001-03368).†*
(g) The Empire District Electric Company Change in Control Severance Pay Plan as amended and
restated effective January 1, 2008. (Incorporated by reference to Exhibit 10(f) to Annual Report
on Form 10-K for the year ended December 31, 2007, File No. 1-3368).†
132
(h) Form of Severance Pay Agreement under The Empire District Electric Company Change in
Control Severance Pay Plan. (Incorporated by reference to Exhibit 10(g) to Annual Report on
Form 10-K for the year ended December 31, 2007, File No. 1-3368).†
(i) The Empire District Electric Company Supplemental Executive Retirement Plan as amended
and restated effective January 1, 2014 (Incorporated by reference to Exhibit 10(i) to Annual
Report on Form 10-K for the year ended December 31, 2014, File No. 001-03368).†*
(j) Retirement Plan for Directors as amended August 1, 1998 (Incorporated by reference to
Exhibit 10(a) to Form 10-Q for the quarter ended September 30, 1998, File No. 1-3368).†
(k)
Stock Unit Plan for Directors of The Empire District Electric Company (Incorporated by
reference to Exhibit 10(i) to Annual Report on Form 10-K for the year ended December 31,
2005, File No. 1-3368).†
(l) First Amendment to Stock Unit Plan for Directors. (Incorporated by reference to Exhibit 10(k)
to Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-3368).†
(m) Amended and Restated Stock Unit Plan for Directors (incorporated by reference to
Appendix C to the definitive proxy statement filed pursuant to Regulation 14A on March 19,
2014, File No. 1-3368).
(n) Amendment to the Amended and Restated Stock Unit Plan for Directors.†*
(o)
Summary of Annual Incentive Plan (Incorporated by reference to Exhibit 10(n) to Annual
Report on Form 10-K for the year ended December 31, 2014, File No. 001-03368).†
(p) Form of Notice of Award of Performance-Based Restricted Stock. (Incorporated by reference to
Exhibit 10(p) to Annual Report on Form 10-K for the year ended December 31, 2008, File
No. 1-3368).†
(q) Form of Amendment to Performance-Based Restricted Stock Award.†*
(r) Form of Notice of Award of Time-Vested Restricted Stock.†*
(s)
Summary of Compensation of Non-Employee Directors.† (Incorporated by reference to
Exhibit 10(r) to Annual Report on Form 10-K for the year ended December 31, 2012, File
No. 1-3368).
(t) Form of Indemnity Agreement (Incorporated by reference to Exhibit 10.1 to Current Report on
Form 8-K dated February 5, 2009 and filed February 10, 2009, File No. 1-3368).†
(u) Credit Agreement, dated as of October 20, 2014, among The Empire District Electric Company,
Wells Fargo Bank, as Administrative Agent, Swingline Lender and Issuing Bank, and the lenders
named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated
October 20, 2014 and filed October 22, 2014, File No. 1-3368).
(v) Guarantee Agreement, dated as of February 9, 2016, made by Algonquin Power and Utilities
Corp. in favor of The Empire District Electric Company (Incorporated by reference to
Exhibit 10.1 to Current Report on Form 8-K dated February 9, 2016 and filed February 9, 2016,
File No. 1-3368).
(12) Computation of Ratios of Earnings to Fixed Charges.*
(21)
Subsidiaries of Empire.*
(23) Consent of PricewaterhouseCoopers LLP.*
(24) Powers of Attorney.*
133
(31)(a) Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.*
(31)(b) Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.*
(32)(a) Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*~
(32)(b) Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.*~
(101) The following financial information from The Empire District Electric Company’s Annual
Report on Form 10-K for the period ended December 31, 2015, filed with the SEC on
February 26, 2016, formatted in Extensible Business Reporting Language (XBRL): (i) the
Consolidated Statements of Income for 2015, 2014 and 2013, (ii) the Consolidated Balance
Sheets at December 31, 2015 and December 31, 2014, (iii) the Consolidated Statements of Cash
Flows for 2015, 2014 and 2013, and (iv) Notes to Consolidated Financial Statements.**
†
*
This exhibit is a compensatory plan or arrangement as contemplated by Item 15(a)(3) of Form 10-K.
Filed herewith.
** Pursuant to Rule 406T of Regulation S-T, the XBRL related information in Exhibit 101 to this Annual
Report on Form 10-K shall not be deemed to be ‘‘filed’’ by the Company for purposes of Section 18 of
the Exchange Act of 1934, as amended, or otherwise subject to the liability of that section, and shall
not be deemed incorporated by reference into, or part of a registration statement, prospectus or other
document filed under the Securities Act of 1933, as amended or the Exchange Act except as shall be
expressly set forth by specific reference in such filings.
~ This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
and shall not be deemed filed by the Company for purposes of Section 18 or any other provision of the
Securities Exchange Act of 1934, as amended.
134
SCHEDULE II
Valuation and Qualifying Accounts
Years ended December 31, 2015, 2014 and 2013:
Additions Charged to Other Accounts
Deductions From
Reserve
Balance At
Beginning Charged
Of Period To Income
Description
Amount Description Amount
Balance At
Close of
Period
Year ended December 31, 2015:
Reserve deducted from assets:
accumulated provision for
uncollectible accounts.
Year ended December 31, 2014:
Reserve deducted from assets:
accumulated provision for
uncollectible accounts.
Year ended December 31, 2013:
Reserve deducted from assets:
accumulated provision for
uncollectible accounts.
$1,020,637 $2,266,976
$1,025,177 $3,463,797
$1,387,673 $2,213,988
Recovery of
amounts previously
written off
Recovery of
amounts previously
written off
Recovery of
amounts previously
written off
Accounts
$2,079,751 written off
$4,744,648 $ 622,716
Accounts
$2,128,325 written off
$5,596,662 $1,020,637
Accounts
$2,013,959 written off
$4,590,443 $1,025,177
135
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
SIGNATURES
THE EMPIRE DISTRICT ELECTRIC COMPANY
Date: February 26, 2016
By /s/ BRADLEY P. BEECHER
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Bradley P. Beecher, President and
Chief Executive Officer
Date: February 26, 2016
/s/ BRADLEY P. BEECHER
Bradley P. Beecher, President,
Chief Executive Officer, Director
(Principal Executive Officer)
/s/ LAURIE A. DELANO
Laurie A. Delano, Vice President-Finance
(Principal Financial Officer)
/s/ ROBERT W. SAGER
Robert W. Sager, Controller, Assistant
Secretary and Assistant Treasurer
(Principal Accounting Officer)
D. RANDY LANEY*
D. Randy Laney, Director
KENNETH R. ALLEN*
Kenneth R. Allen, Director
PAUL R. PORTNEY*
Paul R. Portney, Director
ROSS C. HARTLEY*
Ross C. Hartley, Director
HERBERT J. SCHMIDT*
Herbert J. Schmidt, Director
THOMAS OHLMACHER*
Thomas Ohlmacher, Director
B. THOMAS MUELLER*
B. Thomas Mueller, Director
C. JAMES SULLIVAN*
C. James Sullivan, Director
BONNIE C. LIND*
Bonnie C. Lind, Director
/s/ LAURIE A. DELANO
*By (Laurie A. Delano, as attorney in fact for
each of the persons indicated)
136
Computation of Ratios of Earnings to Fixed Charges
Year ended December 31,
2015
2014
2013
2012
2011
EXHIBIT (12)
Income before provision
for income taxes and
fixed charges (Note A) . .
Fixed Charges:
Interest on long-term debt .
Interest on short-term debt
Other interest . . . . . . . . . .
Rental expense
representative of an
interest factor (Note B) .
TOTAL FIXED
$145,179,076
$158,919,435
$152,117,322
$137,251,581
$136,980,092
$ 43,801,555
265,523
1,035,399
$ 40,636,896
113,333
989,627
$ 40,354,153
59,504
1,064,869
$ 40,192,347
187,132
1,087,719
$ 42,580,987
86,406
(1,147,472)
9,667,300
10,855,975
9,700,747
5,944,675
6,190,709
CHARGES . . . . . . . . . .
$ 54,769,777
$ 52,595,831
$ 51,179,273
$ 47,411,873
$ 47,710,630
Ratio of earnings to fixed
charges . . . . . . . . . . . . .
2.65
3.02
2.97
2.89
2.87
NOTE A: For the purpose of determining earnings in the calculation of the ratio, net income has
been increased by the provision for income taxes, non-operating income taxes and by the sum of fixed
charges as shown above.
NOTE B: One-third of rental expense (which approximates the interest factor).
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
EXHIBIT (31)(a)
I, Bradley P. Beecher, certify that:
1.
I have reviewed this annual report on Form 10-K of The Empire District Electric Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this
report, fairly present in all material respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the
registrant and we have:
a.
b.
c.
d.
designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information
relating to the registrant, including its consolidated subsidiaries, is made known to us by
others within those entities, particularly during the period in which this report is being
prepared;
designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
evaluated the effectiveness of the registrant’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this report based on such evaluation;
and
disclosed in this report any change in the registrant’s internal control over financial reporting
that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal
quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee
of the registrant’s board of directors (or persons performing the equivalent functions):
a.
b.
all significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting which are reasonably likely to adversely affect the
registrant’s ability to record, process, summarize and report financial information; and
any fraud, whether or not material, that involves management or other employees who have
a significant role in the registrant’s internal control over financial reporting.
Date: February 26, 2016
By: /s/ Bradley P. Beecher
Name: Bradley P. Beecher
Title: President and Chief Executive Officer
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
EXHIBIT (31)(b)
I, Laurie A. Delano, certify that:
1.
I have reviewed this annual report on Form 10-K of The Empire District Electric Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this
report, fairly present in all material respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the
registrant and we have:
a.
b.
c.
d.
designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information
relating to the registrant, including its consolidated subsidiaries, is made known to us by
others within those entities, particularly during the period in which this report is being
prepared;
designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
evaluated the effectiveness of the registrant’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this report based on such evaluation;
and
disclosed in this report any change in the registrant’s internal control over financial reporting
that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal
quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee
of the registrant’s board of directors (or persons performing the equivalent functions):
a.
b.
all significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting which are reasonably likely to adversely affect the
registrant’s ability to record, process, summarize and report financial information; and
any fraud, whether or not material, that involves management or other employees who have
a significant role in the registrant’s internal control over financial reporting.
Date: February 26, 2016
By: /s/ Laurie A. Delano
Name: Laurie A. Delano
Title: Vice President — Finance and Chief Financial Officer
EXHIBIT (32)(a)
Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350,
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
In connection with the Annual Report of The Empire District Electric Company (the ‘‘Company’’) on
Form 10-K for the period ending December 31, 2015 as filed with the Securities and Exchange
Commission on the date hereof (the ‘‘Report’’), Bradley P. Beecher, as Chief Executive Officer of the
Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, that:
1. The Report fully complies with the requirements of section 13(a) of the Securities Exchange Act
of 1934; and
2. The information contained in the Report fairly presents, in all material respects, the financial
condition and result of operations of the Company.
By: /s/ Bradley P. Beecher
Name: Bradley P. Beecher
Title: President and Chief Executive Officer
Date: February 26, 2016
A signed original of this written statement required by Section 906 or other document authenticating,
acknowledging or otherwise adopting the signature that appears in typed form within the electronic version
of this written statement required by Section 906, has been provided to The Empire District Electric
Company and will be retained by The Empire District Electric Company and furnished to the Securities
and Exchange Commission or its staff upon request.
EXHIBIT (32)(b)
Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350,
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
In connection with the Annual Report of The Empire District Electric Company (the ‘‘Company’’) on
Form 10-K for the period ending December 31, 2015 as filed with the Securities and Exchange
Commission on the date hereof (the ‘‘Report’’), Laurie A. Delano, as Chief Financial Officer of the
Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, that:
1. The Report fully complies with the requirements of section 13(a) of the Securities Exchange Act
of 1934; and
2. The information contained in the Report fairly presents, in all material respects, the financial
condition and result of operations of the Company.
By: /s/ Laurie A. Delano
Name: Laurie A. Delano
Title: Vice President — Finance and Chief Financial Officer
Date: February 26, 2016
A signed original of this written statement required by Section 906 or other document authenticating,
acknowledging or otherwise adopting the signature that appears in typed form within the electronic version
of this written statement required by Section 906, has been provided to The Empire District Electric
Company and will be retained by The Empire District Electric Company and furnished to the Securities
and Exchange Commission or its staff upon request.
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Annual Meeting
The annual meeting of shareholders will be held Thursday,
April 28, 2016, at 10:30 a.m., CDT, at the Joplin Convention &
Trade Center, 3535 Hammons Blvd. Joplin, Missouri.
Company Headquarters
The Empire District Electric Company
602 S. Joplin Avenue
P.O. Box 127
Joplin, Missouri 64802-0127
Telephone (417) 625-5100
Independent Registered Public Accounting Firm
PricewaterhouseCoopers LLP
St. Louis, Missouri
Registrar, Transfer Agent and Dividend Agent
Wells Fargo Bank, N.A.
Shareowner Services
P.O. Box 64854
St. Paul, Minnesota 55164-0854
(800) 468-9716 (toll free in the United States)
(651) 450-4064 (outside the United States)
www.shareowneronline.com (for registered shareholders &
general inquiries)
Stock Trading
As of December 31, 2015, there were 4,073 common
shareholders of record. Empire common stock is listed on the
New York Stock Exchange under the ticker symbol EDE.
Stock Prices and Dividends
2015
2014
Quarter High
$31.49
First
$25.41
Second
$23.99
Third
$29.41
Fourth
Low
$23.67
$21.56
$20.69
$21.40
Quarter High
First
Second
Third
Fourth
$24.50
$25.70
$26.00
$31.20
Low
$22.04
$23.23
$24.00
$24.09
Dividend
Paid
$0.26
$0.26
$0.26
$0.26
Dividend
Paid
$0.255
$0.255
$0.255
$0.26
Credit Ratings
Standard & Poor’s
Moody’s
BBB
Corporate
Credit Rating
First Mortgage
Bonds
Commercial Paper A-2
BBB
Senior Notes
Developing
Outlook
A-
Baa1
A2
P-2
Baa1
Stable
Direct Registration
Empire is a participant in the Direct Registration System
(“DRS”). This system allows us to issue shares to our
registered shareholders
form called
Direct Registration. All transfers or issuances of shares will
(cid:69)(cid:72)(cid:3) (cid:76)(cid:86)(cid:86)(cid:88)(cid:72)(cid:71)(cid:3) (cid:76)(cid:81)(cid:3) (cid:39)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:3) (cid:53)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3) (cid:88)(cid:81)(cid:79)(cid:72)(cid:86)(cid:86)(cid:3) (cid:68)(cid:3) (cid:86)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3) (cid:70)(cid:72)(cid:85)(cid:87)(cid:76)(cid:180)(cid:70)(cid:68)(cid:87)(cid:72)(cid:3) (cid:76)(cid:86)(cid:3)
(cid:86)(cid:83)(cid:72)(cid:70)(cid:76)(cid:180)(cid:70)(cid:68)(cid:79)(cid:79)(cid:92)(cid:3)(cid:85)(cid:72)(cid:84)(cid:88)(cid:72)(cid:86)(cid:87)(cid:72)(cid:71)(cid:17)
in a book-entry
Dividend Reinvestment and Direct
Stock Purchase Plan
The Dividend Reinvestment and Direct Stock Purchase Plan
offers a variety of convenient, low-cost services to make it
easier for you to invest in our common stock. It is designed
for long-term investors who wish to invest and build their
share ownership over time. All registered holders of Empire
common stock may participate in the Plan. If you are a
(cid:69)(cid:72)(cid:81)(cid:72)(cid:180)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:82)(cid:90)(cid:81)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:68)(cid:3)(cid:69)(cid:85)(cid:82)(cid:78)(cid:72)(cid:85)(cid:68)(cid:74)(cid:72)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:90)(cid:76)(cid:86)(cid:75)(cid:3)
to reinvest your dividends, you can request that your shares
become registered or make arrangements with your broker
or nominee to participate on your behalf.
• New investors may join the plan by making an initial
purchase of common stock in a minimum amount of $250;
• Additional cash purchases, for registered owners, with
$25 minimum per transaction up to $250,000 per year;
• Automatic deduction from your bank account for
additional cash purchases;
(cid:135)(cid:3)(cid:3) (cid:54)(cid:68)(cid:73)(cid:72)(cid:78)(cid:72)(cid:72)(cid:83)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:73)(cid:3)(cid:92)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:72)(cid:85)(cid:87)(cid:76)(cid:180)(cid:70)(cid:68)(cid:87)(cid:72)(cid:86)(cid:30)
• Participation in the Plan with full, partial or no
reinvestment of dividends; and
• Sale of shares through the Plan.
The Plan Administrator may be contacted as follows to re-
quest a prospectus describing the Plan, an enrollment form
or to make an optional cash investment:
Wells Fargo Bank, N.A.
Shareowner Services
P.O. Box 64856
St. Paul, Minnesota 55164-0856
(800) 468-9716 (toll free in the United States and Canada)
(651) 450-4064 (outside the United States)
www.shareowneronline.com (for registered shareholders &
general inquiries)
Financial Report – Form 10-K
Copies of this report which includes the Annual Report
(cid:82)(cid:81)(cid:3) (cid:41)(cid:82)(cid:85)(cid:80)(cid:3) (cid:20)(cid:19)(cid:16)(cid:46)(cid:3) (cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3) (cid:180)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3) (cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:15)(cid:3) (cid:68)(cid:86)(cid:3) (cid:180)(cid:79)(cid:72)(cid:71)(cid:3)
with the Securities and Exchange Commission, are
available without charge upon written request to Dale
W. Harrington, The Empire District Electric Company,
P.O. Box
Joplin, Missouri 64802-0127. This
report may also be accessed via our website,
www.empiredistrict.com. This report is not intended to
induce any securities’ sale or purchase.
127,
Sarbanes-Oxley Certifications
(cid:40)(cid:80)(cid:83)(cid:76)(cid:85)(cid:72)(cid:3) (cid:180)(cid:79)(cid:72)(cid:71)(cid:3) (cid:87)(cid:75)(cid:72)(cid:3) (cid:38)(cid:40)(cid:50)(cid:3) (cid:68)(cid:81)(cid:71)(cid:3) (cid:38)(cid:41)(cid:50)(cid:3) (cid:70)(cid:72)(cid:85)(cid:87)(cid:76)(cid:180)(cid:70)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3) (cid:85)(cid:72)(cid:84)(cid:88)(cid:76)(cid:85)(cid:72)(cid:71)(cid:3) (cid:69)(cid:92)(cid:3)
Section 302 of the Sarbanes-Oxley Act as exhibits to its
Annual Report on Form 10-K for the year ended December
31, 2015.
Inquiries
(cid:44)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:82)(cid:85)(cid:15)(cid:3) (cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:3) (cid:68)(cid:81)(cid:71)(cid:3) (cid:180)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)
available from:
(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)
(cid:76)(cid:86)(cid:3) (cid:68)(cid:79)(cid:86)(cid:82)(cid:3)
The Empire District Electric Company
Dale W. Harrington, Secretary and Director of Investor Relations
P.O. Box 127
Joplin, Missouri 64802-0127
Telephone (417) 625-4222
investor.relations@empiredistrict.com
Internet
We invite you to learn more about our Company by
connecting with us at: www.empiredistrict.com.
Back Cover Photo: Welch, Oklahoma - System Reliability Project
The Empire District Electric Company
602 S. Joplin Avenue (cid:91) PO Box 127 (cid:91) Joplin, MO 64802-0127
www.empiredistrict.com