EDE Empire District Electric Company (The)

The Empire District Electric Company First Quarter 5/06/2016 2016 Investor Update SERVICES YOU COUNT ON

Forward Looking Statements Certain matters discussed in this presentation are “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Statements that are not historical facts, including statements about beliefs, expectations, estimates, projections, goals, forecasts, assumptions, risks and uncertainties, are forward-looking statements. Forward-looking statements are often characterized by the use of words such as “believes,” “estimates,” “expects,” “projects,” “may,” “intends,” “plans,” “anticipates,” “pro forma,” “predicts,” “seeks,” “could,” “would,” “will,” “can,” “continue” or “potential” and the negative of these terms or other comparable or similar terminology or expressions. The forward-looking statements in this presentation include, without limitation, statements relating to Liberty Utilities proposed acquisition of Empire, shareholder and regulatory approvals, and the completion of the proposed transaction. These statements reflect Empire’s management’s current beliefs and are based on information currently available to Empire management. Forward-looking statements involve significant risk, uncertainties and assumptions. Certain factors or assumptions have been applied in drawing the conclusions contained in the forward-looking statements (some of which may prove to be incorrect). Empire cautions readers that a number of factors could cause actual results, performance or achievement to differ materially from the results discussed or implied in the forward-looking statements. Important factors that could cause actual results, performance and results to differ materially from those indicated by any such forward-looking statements include risks and uncertainties relating to the following: (i) the risk that Empire may be unable to obtain shareholder approval for the proposed transaction or that Liberty Utilities 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; (ii) 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; (iii) the risk that a condition to the closing of the proposed transaction may not be satisfied; (iv) the failure to obtain any financing necessary to complete the merger; (v) the outcome of any legal proceedings, regulatory proceedings or enforcement matters that may be instituted against Empire and others relating to the merger agreement; (vi) the receipt of an unsolicited offer from another party to acquire assets or capital stock of Empire that could interfere with the proposed merger; (vii) the timing to consummate the proposed transaction; (viii) disruption from the proposed transaction making it more difficult to maintain relationships with customers, employees, regulators or suppliers; (ix) the diversion of management time and attention on the transaction; (x) general worldwide economic conditions and related uncertainties; (xi) the effect and timing of changes in laws or in governmental regulations (including environmental laws and regulations); (xii) the timing and extent of changes in interest rates, commodity prices and demand and market prices for gas and electricity; and (xiii) other factors discussed or referred to in the “Risk Factors” or “Forward Looking Statements” sections of Empire’s most recent Annual Report on Form 10-K filed with the Securities and Exchange Commission (the SEC) and in subsequently filed Forms 10-Q and 8-K. 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 proposed transaction. There can be no assurance that the proposed transaction will be completed, or if it is completed, that it will close within the anticipated time period. These factors should be considered carefully and undue reliance should not be placed on the forward-looking statements. Each forward-looking statement in this presentation speaks only as of the date of the particular statement. For additional information with respect to certain of the risks or factors, reference should be made to Empire’s filings with the SEC. Except as required by law, Empire disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. 1

Algonquin Power & Utilities Corp. to Acquire The Empire District Electric Company “Algonquin Power & Utilities Corp. (“APUC”) and The Empire District Electric Company (“Empire”) announced that a subsidiary of Liberty Utilities Co. (“Liberty Utilities”), APUC’s wholly owned regulated utility business, has entered into an agreement and plan of merger pursuant to which Liberty Utilities will indirectly acquire Empire and its subsidiaries. Under the terms of the all-cash transaction, which has been unanimously approved by the Board of Directors of each company, Empire’s shareholders will receive $34.00 per common share, representing an aggregate purchase price of approximately $2.4 billion, including the assumption of approximately $0.9 billion of debt as of September 30, 2015. The purchase price represents a 21% premium to the closing price on February 8, 2016 and a 50% premium to Empire’s unaffected share price on December 10, 2015.” – Press Release dated February 11, 2016 SERVICES YOU COUNT ON Merger Update 3

Tentative Transaction Approval Timeline Obtain approvals from state regulatory commissions in Missouri (procedural schedule approved), filed with State and authorizing transaction received) and other Federal agencies (1) agencies 1 Missouri procedural schedule sets technical conferences to begin May 16, position statements due August 18, and evidentiary hearing to be held August 29-31, 2016. Expecting Oklahoma approval order in near future. Establishing procedural schedules in Kansas and Arkansas. FERC order authorizing proposed transaction received May 6, 2016. 4 1Q 2016 2Q 2016 3Q 2016 4Q 2016 1Q 2017 2/9/2016 Transaction announced Missouri rate case proceeding in progress (Docket No. ER-2016-0023) Merger applications Federal regulatory Kansas, Oklahoma (approval recommended by ALJ) and Arkansas, and FERC (order Proxy Statement Empire Shareholder Filed May 3Meeting for Transaction Approval June 16 Develop and initiate transition and integration plans (in progress ) Expected Transaction close

Transaction Highlights Y $34.00 purchase price • Represents 50% premium to unaffected December 10, 2015 closing price of $22.65 Y Joplin headquarters for Liberty Utilities Central Region (“Liberty Central”) • • Subsidiary of Liberty Utilities Liberty Central will serve approximately 338,000 customers on close Y Empire senior management team to lead Liberty Central • Brad Beecher to assume role of President and CEO of Liberty Central Y Empire branding maintained for no less than 5 years Y Commitment to retain Empire employees Y Current Empire customer rates remain unaffected Y Continuing level of community support and involvement 5

Overview of Liberty Utilities Central Region Empire’s service area complements Algonquin’s Omaha IA NE IL IN Kansas City Jefferson City KS St. Louis MO KY Joplin OK AR TN Oklahoma City 6

Elk River Wind Farm – Meeting renewable energy standards First Quarter Update 7

First Quarter Highlights 8 •Quarter Drivers: oIncreased Missouri customer rates oMild weather oIncreased depreciation and amortization, interest expense and AFUDC oMerger related costs •Twelve Month Ended Drivers: oIncreased Missouri customer rates oCustomer growth oMilder weather and other volumetric changes oFuel deferral timing oIncreased operating and maintenance expense, depreciation and amortization, property, interest and other non-operating expenses oReduced AFUDC levels •Riverton 12 Combined Cycle placed in service May 1, 2016 1st Quarter 2016 1st Quarter 2015 TME March, 2016 TME March, 2015 Net Income (millions) $14.0 $14.6 $56.0 $60.8 Earnings Per Share - including merger costs $0.32 $0.34 $1.28 $1.40 Earnings Per Share - exclusive of merger costs $0.38 $0.34 $1.34 $1.40 Dividends Per Share $0.26 $0.26 $1.04 $1.04

Electric Rates $ 0.11 Electric Weather & Other (0.10) Electric Customer Growth 0.01 Fuel & Other 0.02 Gas Segment (0.01) TOTAL $ 0.03 Production Operations $ 0.02 General Labor Costs (0.02) All Other 0.01 TOTAL $ 0.01 First Quarter Highlights Quarter ended March 31, 2016: Consolidated Basic EPS After Tax Increase (Decrease) $0.45 $0.40 $0.03 $0.35 $(0.06) $0.30 $(0.01) $(0.00) $0.32 $0.25 $0.20 $0.15 $0.10 $0.05 $-Period Ended 3/31/2015 Margin O&M Merger Costs Depreciation & Amortization Property & Other Taxes Interest AFUDC Other Income & Deductions Period Ended 3/31/2016 9 $0.01 $0.34$0.02$0.00 $(0.01)

Electric Rates $ 0.26 Electric Weather & Other (0.15) Electric Customer Growth 0.02 Fuel & Other 0.07 Nonregulated Segment 0.01 Gas Segment (0.03) TOTAL $ 0.18 Production Maintenance $ (0.05) General Labor Costs (0.04) Transmission Operations (0.01) Healthcare (0.01) Distribution Maintenance 0.02 Customer Accounts 0.02 Production Operations 0.01 All other 0.01 TOTAL $ (0.05) First Quarter Highlights Twelve Months Ended March 31, 2016: Consolidated Basic EPS After Tax Increase (Decrease) $1.80 $0.18 $1.60 $(0.06) $1.40 $(0.05) $(0.01) $(0.01) $(0.01) $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $-Period Ended 3/31/2015 Margin O&M Merger Costs Depreciation & Amortization Property & Other Taxes Interest AFUDC Other Income & Deductions Dilution of Common Stock Period Ended 3/31/2016 10 $(0.05) $1.40$(0.08) $(0.03) $1.28

2016 Earnings Drivers Earnings Per Share $1.60 $1.50 Guidance Range $1.38 to $1.54 $1.40 Range adjusted 2/26/16 (1) 1.44 $1.30 $1.20 $1.10 $1.00 2015 Actual 2016 Guidance Range Estimate 2016 • • Guidance: Full year of Asbury AQCS cost recovery in customer rates Rates in effect late September 2016 for Missouri case filed October 16, 2015 to recover Riverton Unit 12 Combined Cycle project costs Riverton lag effect until project costs recovered in customer rates in September 2016 • • Riverton 12 depreciation rate approximately 2% • Adjusted to include estimated merger costs of $15 to $17 million, with approximately 50% payable in 2016 (assuming 2017 closing) (1) $1.29 Diluted 11 $1.30(2/4/16) to $1.26 to $ 

Return on Equity 10.0% Quarterly ROE* – Trailing 12-Month Basis 9.0% 8.0% 7.0% 6.0% 5.0% 4.0% 3.0% 2.0% 1.0% 0.0% Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 2009 2009 2009 2010 2010 2010 2010 2011 2011 2011 2011 2012 2012 2012 2012 2013 2013 2013 2013 2014 2014 2014 2014 2015 2015 2015 2015 2016 * Not weather adjusted 12 Q1 2009 ROE 8.3% 8.8% 7.3% 6.9% 6.2% 6.0% 7.1% 7.2% 7.7% 8.0% 8.0% 7.9% 7.6% 7.8% 7.6% 7.8% 8.1% 8.2% 7.8% 8.5% 9.4% 9.3% 9.1% 8.6% 7.7% 7.2% 7.2% 7.1% 6.9%

Leading by example – adopting electric plug-in technologies for vehicle fleet Regulatory Update 13

Missouri Rate Case Projected Timeline(1) (Docket No. ER-2016-0023) March 31 d Hearings Rates Mid-1 Assumes customary 11-month Missouri procedural schedule 14 4Q 2015 1Q 2016 2Q 2016 3Q 2016 4Q 2016 Riverton 12 Combined Cycle Conversion Filed October 2015 Riverton 12 Rates Realized True-Up Date Testimony and Depreciation Lag Riverton 12 CC In-Service May 1 New Sept 2016

Missouri Rate Case Highlights (Docket No. ER-2016-0023) • • • • • • • • • Requested increase of $33.4 million, or 7.3% above current rates Test year ending June 30, 2015; expense true up through March 31, 2016 Seeks recovery of Riverton 12 Combined Cycle Conversion investment Requested Return on Equity – 9.9% Missouri jurisdictional Rate Base – $1.368 billion; overall Rate of Return – 7.58% Increased transmission, administrative and maintenance expenses Recovery of mandated solar program costs Revised depreciation rates; lower average interest costs Continuation of Fuel Adjustment Clause 15 Cost Driver Revenue Requirement ($ in millions) Riverton Unit 12 Combined Cycle Conversion$27.4 Asbury True-Up 2.1 Effect of New Depreciation Rates (1.0) Other Normal Plant Additions 6.0 Administrative Costs 2.1 Capital Structure and Other (3.2) Total Base Rates $33.4

Other Regulatory • Missouri o o Kansas o Filed Integrated Resource Plan (IRP) April 1, 2016 Solar Rebates; at March 31, 2016, received over $10M in rebate applications; Deferred on Balance Sheet $6.2M • Asbury Cost Recovery Tariff Rider approved April 15, 2015, increasing annual base revenues $0.78 million; effective June 1, 2015 • Arkansas Alternative Generation Environmental Rider (GER) approved August 5, 2015, increasing annual base revenues $0.46M; effective February 23, 2015 Oklahoma o • Filed request with Oklahoma Corporation Commission to adopt Missouri customer electric rates requested in Docket No. ER-2016-0023 once approval is granted by the Missouri Public Service Commission o 1 Regulatory Research Associates – RRA maintains three principal rating categories; Above Average, Average, and Below Average, each indicative of the constructiveness of the regulatory environment from an investor point of view. 16 Commission Profiles Missouri Kansas Oklahoma Arkansas FERC % Operations 85.9 4.7 2.7 3.3 3.4 Commissioners (current/allowed) 5 / 5 3 / 3 3 / 3 3 / 3 5 / 5 Elected/Appointed Appointed Appointed Elected Appointed Appointed Test Year Historical Historical Historical Historical Historical Recovery mechanisms Yes Yes Yes Yes Yes RRA ranking 1 Average/2 Average/2 Average/2 Average/3 N/A

Asbury Generating Station – environmentally compliant base-load generation Supplemental Materials • • • • • Who We Are Growth Financial Operations Contacts 17

• • • • • • 100% Regulated Electric and Gas Utility Over 100 years of operation Operations in four states: MO, KS, OK, AR plus FERC 218,000 customers 10,000 square mile service territory NYSE Ticker: EDE Kansas, 4.7% Arkansas, 3.3% Oklahoma, 2.7% Missouri, 85.9% FERC, 3.4% 2015 On-System Electric Revenues by Jurisdiction 18 Who We Are

Who We Are Board of Directors • Experienced Management Team Brad Beecher President & CEO Laurie Delano VP - Finance & CFO Kelly Walters VP & COO - Electric Ron Gatz VP & COO - Gas Robert Sager Controller, Asst. Sec. & Asst. Treasurer Blake Mertens VP – Energy Supply & Delivery Operations • Executive Management • Officers average nearly 20 years utility experience with Empire Dale Harrington Corp Secretary & Dir – Investor Relations Brent Baker VP – Customer Service, Transmission & Engineering • Independent Board of Directors • Non-executive chairman • All directors other than CEO are independent Mark Timpe Treasurer 19

Growth Capacity, Peak Demand & Total System Input1 5,584 1,600 5,494 6,000 5,486 5,452 5,371 5,330 5,315 5,282 5,263 5,233 1,400 62 5,000 177 169 162 86 86 1,200 4,000 1,162 1,159 1,152 1,149 1,142 1,000 3,000 1,085 1,080 800 2,000 600 1,000 1,100 1,255 1,255 1,257 1,409 1,392 1,391 1,377 1,326 1,280 400 0 1 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Total System Input Owned Capacity Purchased Power Capacity Peak Demand 1 Measure of customer usage, excluding losses Capital Expenditures ($ millions) 250 2,500 2,136 2,048 2,033 200 2,000 1,738 1,722 1,662 150 1,500 100 1,000 124 120110 117 108 105 50 101 97 0 500 2010 2011 20122013 2014 20152016E 2017E 2018E 2019E 2020E Capex Depreciation Net Plant in Service (Less CWIP) Rate Base (Net Plant less CWIP and Deferred Taxes) Includes effect of Bonus Depreciation through 2019 Actuals include AFUDC, projections exclude AFUDC; Net Plant excludes depreciation recorded as a Cost of Removal regulatory liability 20 Net Plant in Service and Rate Base 000’s MWh Demand Annual Capital Expenditures 2,1992,208 1,798 1,837 1,510 1,540 1,601 1,600 1,598 1,586 1,440 1,440 1,321 1,298 1,321 1,295 223 146160176168161 5964606973818692 1

Growth Electric Customer Growth 2.5 2 1.5 1 0.5 0 -0.5 -1 -1.5 -2 Note: Impact of EF-5 tornado 2015 2 20042005 2006 2007 2008 2009 2010 2011 2012 2013 2014 1 Source EIA 2 2015 EIA not yet available Industry Average 1 EDE Average Residential Rates 12.0 10.0 8.0 6.0 4.0 2.0 0.0 2015 2 2008 1 Source: EIA 2009 2010 EDE 2011 2012 2013 2014 1 Industry Average 2 2015 EIA Not yet available 21 Cents per kWh Percent Change

Financial Historical Performance ($ in millions, except EPS and Book Value) TME 3-31-16 2015 2014 2013 2012 Gross Margin2 $418.0 $416.2 $410.2 $393.1 $359.6 Net Income $56.0 $56.6 $67.1 $63.4 $55.7 Return on Average Common Equity 7.0% 7.2% 8.6% 8.7% 7.9% Cash from Operations $181.5 $184.8 $151.2 $157.5 $159.1 Debt – Short Term $44.3 $50.3 $44.3 $4.3 $24.7 Equity – Retained Earnings $104.0 $101.4 $90.3 $67.6 $47.1 Total Equity $808.3 $802.7 $783.3 $750.1 $717.8 1 Operating Revenues include revenues for fuel recovery and, effective March 1, 2014, SPP Integrated Market (IM) activity ($13.4M for TME March 31, 2016; $15.0M in 2015; $41.9M in 2014) 2 Operating revenues less fuel and purchased power and cost of natural gas sold and transported 22 Book Value$18.41$18.32$18.02$17.43$16.90 Equity – Other$704.3$701.3$693.0$682.5$670.7 Debt – Long Term$829.4$837.9$803.2$743.4$691.6 Capital Structure EBITDA$210.1$211.7$212.6$206.4$190.8 Earnings Per Share$1.28$1.30$1.55$1.48$1.32 Operating Income$94.6$96.3$100.0$99.7$96.2 Operating Revenues1$592.3$605.6$652.3$594.3$557.1

Financial Earnings and Dividends Per Share 1.55 $1.60 1.48 1.32 1.31 1.30 2 1.28 1.28 1.28 1.17 1.17 1.18 $1.20 1.025 1.04 1.00 1.005 $0.80 0.64 $0.40 $0.00 1 2008 2009 2010 2011 2012 2013 2014 2015 EPS Dividends Per Share 1 Dividend suspended for Q3 and Q4 in 2011 following EF-5 tornado on May 22, 2011 2 Basic EPS 23 Per Share Amount

Financial 24 Index Value Index Period Ending 12/31/10 12/31/11 12/31/12 12/31/13 12/31/14 12/31/15 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$ 100.00$ 102.11$ 118.45$ 156.82$ 178.28$ 180.75 Total Return Performance 190 175 160 145 130 115 100 85 12/31/1012/31/1112/31/1212/31/1312/31/1412/31/15 Empire District Electric Company S&P Electric Utilities Index S&P 500

Financial • • • • Strong Investment Grade Credit Target 50/50 capital structure March 2016 Moody’s reaffirmed credit ratings February 2016 Standard & Poor’s reaffirmed debt ratings; outlook changed to negative following merger announcement; re-affirmed debt ratings and outlook on April 29, 2016 25 Standard & Moody’s Poor’s Corporate Issuer Baa1 BBB First Mortgage Bonds A2 A-Commercial Paper P-2 A-2 Outlook Stable Negative

Financial • Well-spaced debt maturities, upcoming maturity of $25M in late-2016 with expectation to pay off at maturity • $200M five-year revolving credit facility maturing October 19, 2019; $75M accordion Debt Maturities Credit Facility – $200M matures 10/2019 120 120 100 92 90 88 80 90 60 60 55 50 60 40 (1) 25 30 0 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 Average cost of debt: 5.2% 1 Not being refinanced 26 Debt Maturity ($ millions)

Financial Revenue Source (LTM 12/31/15) Gas 7% Other 1% Electric 92% Total: $606 Million(1) (2) Gas Revenues by Customer (LTM 12/31/15) Electric Revenues by Customer (LTM 12/31/15) Industrial 1% Other 9% Industrial 16% Commercial 25% Commercial 31% Public Other 8% Wholesale On-system 3% Authorities 2% Residential 63% Residential 42% Total: $553 Million Total: $42 Million 27 1 Includes $15 Million of SPP IM revenues 2 Excludes $2 Million of water revenues

Operations 1 2 3 4 4 5 6 8 3 9 Kansas Missouri 1 5 7 2 6 4 8 Oklahoma Arkansas 7 8 9 Wind Coal Natural Gas Hydro Notes: 1 2 3 4 5 Includes Riverton Unit 12 combined cycle unit placed in service May 1, 2016 Does not include 40% owned by Westar Elk River contracted through December 2025 Plum Point contracted through December 2036 Cloud County contracted through December 2028 28 Net Capacity Energy Supply Primary Fuel (MW) Status Asbury Coal 198 Owned Riverton Natural Gas 271 Owned1 Iatan (12% owner, Units 1 &2) Coal 191 Owned State Line Combined Cycle Natural Gas 295 Owned2 State Line Unit 1 Natural Gas 96 Owned Empire Energy Center Natural Gas 257 Owned Ozark Beach Hydro 16 Owned Plum Point Energy Station (7.5% owner) Coal 50 Owned Owned Capacity (MW) 1,374 Elk River Windfarm PPAWind17Contracted3 Plum Point Energy Station PPACoal50Contracted4 Cloud County Windfarm PPAWind19Contracted5 Purchased Power Capacity (MW) 86 Total Capacity (MW) 1,460

Operations • Diverse Generation/Balanced Mix of Resources 2016 Capacity Mix (1) 2015 Energy Mix 1% 39% 4% 17% 22% 6% 24% 30% 1% 3% 3% 50% Coal-fired Coal-fired Coal PPA Wind PPA Hydro Gas-fired Simple Cycle Gas-fired Combined Cycle Coal PPA Wind PPA Hydro Gas-fired Simple Cycle Gas-fired Combined Cycle 1,374 Net MW Owned Capacity 86 MW Purchased Power Capacity Total: 4,936 GWh 29 1 Includes Riverton 12 combined cycle placed in service May 1, 2016

Executive Management and Investor Relations Team Brad Beecher, President and CEO Laurie Delano, Vice President – Finance and CFO Dale Harrington, Corporate Secretary and Director of Investor Relations The Empire District Electric Company 602 S. Joplin Avenue Joplin, MO 64801 www.empiredistrict.com Dale Harrington Office: 417-625-4222 Mobile: 417-825-8281 dharrington@empiredistrict.com Laurie Delano Office: 417-625-5127 Mobile: 417-291-4397 ldelano@empiredistrict.com 30