Empire Resorts Inc. Annual Report 2015

Plain-text annual report

-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 n e d i s e r P e h t m o r f r e t t e L 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. 81 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). 82 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 83 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 84 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. 85 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. 86 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 88 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 89 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 $9,712 119 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. This page intentionally left blank This page intentionally left blank This page intentionally left blank 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

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