Q Year End Profits

Transcription

1 Third-Quarter Earnings Nov. 4, 2014

2 Investor Relations Information COMPANY INFORMATION Black Hills Corporation 625 9th Street Rapid City, SD NYSE Ticker: BKH Company Contacts Jerome E. Nichols Director of Investor Relations Brian G. Iverson Senior Vice President FORWARD LOOKING STATEMENTS This presentation includes forward-looking statements as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These include, without limitation, our 2014 and 2015 earnings guidance. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the risk factors described in Item 1A of Part I of our 2013 Annual Report on Form 10-K filed with the SEC, and other reports that we file with the SEC from time to time, and the following: The accuracy of our assumptions on which our earnings guidance is based; Our ability to meet our strategic objectives, listed on slide 23; Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and favorable rulings in periodic applications to recover costs for capital additions, plant retirements and decommissioning, fuel, transmission, purchased power, and other operating costs, and the timing in which new rates would go into effect; Our ability to obtain regulatory approval to include additional generation in rate base in the future, and to implement a Cost of Service Gas program; Our ability to receive regulatory approvals for announced acquisitions and to successfully close and implement the transactions; Our ability to complete our capital program in a cost-effective and timely manner, including our ability to successfully develop our Mancos Shale gas reserves located in the San Juan and southern Piceance Basins; Our ability to provide accurate estimates of proved crude oil and gas reserves and future production and associated costs; and Other factors discussed from time to time in our filings with the SEC. New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time-to-time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise. Note: Minor differences in charts may occur due to rounding 2

3 Discussion Agenda Third-Quarter Review Financial Update David Emery Chairman, President and Chief Executive Officer Tony Cleberg Executive Vice President and Chief Financial Officer Strategic Overview David Emery Chairman, President and Chief Executive Officer Q&A 3

4 Q3 Review Cheyenne Prairie Generating Station Cheyenne, WY 4

5 Q Highlights Business Environment Cooler weather in utility service territories compared to same period last year benefited natural gas utilities but tempered results at electric utilities Utilities Announced agreement to acquire natural gas utility with 6,700 customers in northwestern WY and certain pipeline assets for approximately $17 million Black Hills Power filed for a certificate of public convenience and necessity in WY and an application for a permit in SD seeking approval to construct a new 144-mile, $54 million electric transmission line from northeastern WY to Rapid City, SD Cheyenne Prairie Generating Station new $222 million, 132 MW natural gas-fired power plant placed in commercial operation on Oct. 1 - on time and on budget New rates for Black Hills Power and Cheyenne Light customers in WY and interim rates for Black Hills Power customers in SD effective Oct. 1 Black Hills Power and Cheyenne Light closed the sale of $160 million of first mortgage bonds on Oct. 1 in a private placement to finance Cheyenne Prairie; Black Hills Power proceeds also used for early redemption of 5.35% $12 million pollution control revenue bonds 5

6 Q Highlights Utilities continued Cheyenne Light recorded new all-time peak load of 198 MW on July 21 Colorado Electric issued request on May 5 for approximately 42 MW of seasonal firm summer capacity for 2017, 2018 and 2019, and up to 60 MW of renewables Power Generation submitted solar and wind bids on July 31 in response to the request; Colorado Public Utilities Commission decision expected by end of February 2015 Colorado Electric filed request on April 30 with Colorado Public Utilities Commission to increase revenues to recover increased operating expenses and infrastructure investments, including Busch Ranch Wind Farm, placed in service late 2012; filing also seeks to implement rider to recover a return on construction costs for new $65 million combustion turbine that will replace retired W. N. Clark power plant On Oct. 28, administrative law judge recommended decision incorporating $2 million revenue increase, 9.83% return on equity and capital structure of 49.8% equity and 50.2% debt o o Recommended decision approves implementation of plant construction rider Decision subject to exceptions and final commission approval with rates effective by end of

7 Q Highlights Utilities continued On Oct. 24, Kansas Gas reached settlement agreement that increases base rates by $5.2 million; hearing scheduled for Nov. 12 with Kansas Corporation Commission and order expected by Jan. 6, 2015, with new rates effective by mid-january Power Generation Sold 40 MW natural gas-fired combustion turbine to City of Gillette, WY, for $22 million; includes 20-year economy energy agreement with revenue potential to Black Hills from sharing of Gillette s energy cost savings Coal Mining Completed negotiations for coal price reopener related to Wyodak power plant; coal price of $18.25 per ton, an increase of approximately $4.75 per ton, effective July 1 Oil and Gas Drilled, cased and cemented two Mancos Shale wells in southern Piceance Basin and currently drilling third well; completion activities for these wells and commencement of drilling for next three Mancos Shale wells expected to start in December 7

8 Q Highlights Corporate Activities Declared quarterly dividend of $0.39 per share, equivalent to an annual dividend rate of $1.56 per share Quarter included approximately $1.3 million income tax benefit Announced executive leadership changes on Oct. 29: Tony Cleberg, current executive vice president and chief financial officer, will retire at the end of March 2015 Rich Kinzley, current vice president and controller, appointed as senior vice present and chief financial officer effective Jan. 1, 2015 Brian Iverson, current vice president and treasurer, appointed as senior vice president of regulatory, government affairs and assistant general counsel effective Nov. 1, 2014 Kinzley and Iverson will report directly to David Emery, chairman, president and chief executive officer; both will retain responsibilities for their current roles until replacements are announced Kinzley Iverson 8

9 Q Financial Highlights 28% Growth in EPS, as adjusted (in millions) $27 Earnings, as adjusted* (per share) $0.60 $0.47 $21 Key Earnings Drivers Higher residential and commercial natural gas demand (cooler weather) Higher industrial and commercial electric demand (CLFP) CPGS financing riders Lower electric O&M Higher natural gas and NGL volumes sold Lower interest and income tax expense Q Q Q Q * Non-GAAP measures reconciled to GAAP on slide 12 and in Appendix Lower residential electric volumes (cooler weather) Higher Gas Utilities uncollectible expense Lower crude oil and natural gas prices Higher depletion 9

10 Q Financial Highlights Change in Net Income, as adjusted*, from Prior Year Q $21.1 $3.0 $3.0 Electric Utilities Gas Utilities $1.1 $0.5 Power Generation Coal Mining ($1.4) ($0.5) Oil & Gas Corporate Q $26.8 ($5) $0 $5 $10 $15 $20 $25 (in millions) * Non-GAAP measures reconciled to GAAP in Appendix 10

11 Financial Update Elmo Bailey & Ebi Kazemi prepare for pole line installation in the mountains near Victor, CO 11

12 Earnings Per Share Analysis Q Q Q Q Q Net Income (loss) (GAAP) $ 0.60 $ 0.44 $ 1.08 $ 0.41 $ 0.52 Loss (income) from discontinued operations (GAAP) Income (loss) from continuing operations (GAAP) $ 0.60 $ 0.44 $ 1.08 $ 0.43 $ 0.52 Add back unique loss/subtract (gain) items (Non-GAAP) Interest rate swaps - unrealized (gain) (0.01) (0.05) Costs associated with prepayment of BHW project financing (net of interest savings) Financing costs, net of interest savings ($250M bond payoff)* Rounding Income from continuing ops, as adjusted (Non-GAAP) $ 0.60 $ 0.44 $ 1.08 $ 0.70 $ 0.47 * Includes make-whole premium, write-off of deferred financing costs and interest on new debt 12

13 Q3 Revenue/Op Income Total Revenue, as adjusted* (in millions) Total Operating Income, as adjusted* (in millions) $272 $260 $54.4 $55.6 Q Q Q Q Electric Util $175 $171 Electric Util $40.9 $40.8 Gas Util $79 $68 Gas Util $3.9 $3.1 Power Gen $23 $22 Q Power Gen $10.9 $11.7 Q Coal Mining $16 $15 Q Coal Mining $3.2 $2.2 Q Oil & Gas $14 $14 ($4.5) ($2.4) Oil & Gas ($33) ($31) Corporate, including I/C Eliminations $0.0 $0.2 Corporate, including I/C Eliminations * Non-GAAP measures, reconciled to GAAP in Appendix 13

14 Income Statement (in millions, except earnings per share) 3rd Qtr Revenue $ $ Gross margin* $ $ Operating expense (95.5) (96.7) DD&A (37.5) (36.1) Operating Income Interest expense (16.8) (22.7) Interest rate swap - MTM Other income Income before income tax Income tax (11.3) (13.3) Net Income $ 26.8 $ 23.1 Non-GAAP adjustments - (2.0) Net Income, as adjusted* $ 26.8 $ 21.1 EPS $ 0.60 $ 0.52 EPS, as adjusted* $ 0.60 $ 0.47 Diluted Shares Outstanding EBITDA* $ 92.4 $ 92.1 * Non-GAAP measures, defined and/or reconciled to GAAP in Appendix and slide 12 14

15 Q3 Utilities - Revenue/Op Income Electric Utilities (in millions) Gas Utilities (in millions) $174.6 $171.4 Q Q $78.7 $67.8 Q Q $40.9 $40.8 $3.9 $3.1 Revenue Operating Income, as adjusted* Revenue Operating Income, as adjusted* Higher MWh sold to commercial and industrial customers Financing riders Lower O&M and G&A expenses Higher distribution volumes sold up 13% due to 73% increase in heating degree days Residential customer count growth up 1% Lower residential MWh sold due to 26% decrease in cooling degree days Decrease in wholesale MWh sold due to unplanned outages Higher O&M expenses uncollectibles, property taxes * Non-GAAP measures, reconciled to GAAP in Appendix 15

16 Q3 Non-Regulated Energy - Revenue/Op Income Power Generation (in millions) Coal Mining (in millions) $22.5 $22.4 Q Q $15.6 $15.3 Q Q $10.9 $11.7 $3.2 $2.2 Revenue* Operating Income, as adjusted* Revenue Operating Income, as adjusted* Higher MWh delivered under power purchase agreements Coal price increases Lower O&M Lower depreciation Lower Wygen I off-system sales Higher O&M due to property taxes and repairs and maintenance at Colorado IPP Decrease in tons sold due to unplanned power plant outages and closure of Neil Simpson I * Non-GAAP measures, reconciled to GAAP in Appendix 16

17 Q3 Non-Regulated Energy - Revenue/Op Income Oil & Gas (in millions) $13.5 $14.4 Q Q ($4.5) ($2.4) Revenue Operating Income, as adjusted * Higher volumes sold Higher average prices for NGLs Lower O&M Lower average prices for natural gas and crude oil Higher depletion expense * Non-GAAP measures, reconciled to GAAP in Appendix 17

18 Capital Structure (In millions, except for ratios) Sept. 30, June 30, March 31, Dec. 31, Sept. 30, Capitalization Short-term Debt $ 459 $ 408 $ 100 $ 83 $ 394 Long-term Debt 1,108 1,122 1,397 1, Total Debt 1,567 1,530 1,497 1,479 1,350 Equity 1,357 1,341 1,337 1,308 1,291 Total Capitalization $ 2,924 $ 2,871 $ 2,834 $ 2,787 $ 2,641 Net Debt to Net Capitalization Debt $ 1,567 $ 1,530 $ 1,497 $ 1,479 $ 1,350 Cash and Cash Equivalents (12) (15) (18) (8) (14) Net Debt 1,555 1,515 1,479 1,472 1,336 Net Capitalization $ 2,912 $ 2,856 $ 2,817 $ 2,779 $ 2,627 Debt to Capitalization Net Debt to Capitalization (Net of Cash) Long-term Debt to Total Debt 53.6% 53.3% 52.8% 53.1% 51.1% 53.4% 53.0% 52.5% 52.9% 50.9% 70.7% 73.3% 93.3% 94.4% 70.8% 18

19 Earnings Guidance 2014 Black Hills raised its guidance for 2014 earnings, as adjusted, to $2.80 to $2.95 per share from $2.65 to $2.85 per share 2015 Black Hills initiated guidance for 2015 earnings, as adjusted, of $2.90 to $3.10 per share (see assumptions on following page) 19

20 2015 Earnings Guidance Assumptions Capital spending of $432 million, including oil and gas capital expenditures of $123 million; Normal operations and weather conditions within our utility service territories that impact customer usage, and planned construction, maintenance and/or capital investment projects; Successful completion of rate cases for electric and gas utilities; No significant unplanned outages at any of our power generation facilities; Oil and natural gas production in the range of 13.5 to 15.0 billion cubic feet equivalent; Oil and natural gas annual average NYMEX prices of $3.85 per million British thermal units for natural gas and $82.00 per barrel for oil; production-weighted average wellhead prices of $2.47 per MMBtu and $72.00 per Bbl of oil, and average hedged prices received of $2.60 per MMBtu and $73.99 per Bbl; Oil and natural gas depletion expense in the range of $2.35 to $2.55 per million cubic feet equivalent; No equity financing in 2015 except for approximately $3 million from the dividend reinvestment program; and No significant acquisitions or divestitures. 20

21 Operating Income and EPS, as Adjusted $400 $2.88** $3.00*** $3.20 $ EPS CAGR = 13.8% $2.45 $2.80 $300 $2.09 $2.40 (in millions) $250 $200 $150 $1.38 $19.9 $1.67 $1.69 $19.0 $5.2 $36.2 $36.1 $2.00 $1.60 $1.20 (per share) $100 $50 $126.2 $159.3 $185.0 $210.4 $219.8 $0.80 $0.40 $ Operating Income, as Adjusted* EPS - Cont Ops, as Adj* - Utilities - Non-regulated Energy - Consolidated * Non-GAAP measures, reconciled to GAAP in Appendix (Operating Income, as adjusted, graph does not include Corporate activity) ** Midpoint of 2014 earnings guidance range of $2.80 to $2.95 per share, issued on Nov. 3, 2014 *** Midpoint of 2015 earnings guidance range of $2.90 to $3.10 per share, issued on Nov. 3, 2014 $- 21

22 Strategic Overview Busch Ranch Wind Farm near Pueblo, CO 22

23 Strategic Objectives Utility-centered energy company well positioned to build upon a track record of successful utility growth EARNINGS: Lead industry peers in earnings growth EARNINGS UPSIDE: Capture value upside through Mancos shale and other strategic oil and gas development DIVIDEND: Increase annual dividend, extending industry-leading dividend history CREDIT RATING: Maintain BBB senior unsecured credit rating BUSINESS DEVELOPMENT: Grow our core energy businesses through investments in organic business expansions and acquisitions that exceed our established hurdle rates and are accretive to earnings CUSTOMER: Provide quality products and services that cost effectively meet or exceed customer expectations with increased use of technology; effectively market these products and services to customers; and, share information to create understanding of energy-related issues COMMUNITIES: Be a partner in growing the economies of the communities we serve OPERATIONAL PERFORMANCE: Achieve top-tier operational performance in a culture of continuous improvement EFFICIENCY: Continuously engage BHC employees to identify and pursue efficiencies, and to simplify or eliminate unnecessary processes. Sustain annual improvements to metrics comparing costs as a percent of gross margin EFFECTIVENESS: Identify the right projects and tools that allow employees to work effectively every day MEASUREMENT: Benchmark our costs and processes with meaningful metrics to assist with real-time business management assessment of results and accountability ENGAGEMENT: Achieve status as one of the 100 Great Places to Work as measured by the Great Places to Work Institute DIVERSITY: Increase workforce diversity (as measured as a percent of total workforce) to achieve improved performance and the innovations that come from inclusiveness EMPLOYEE DEVELOPMENT: Establish robust development options enabling increased performance while preparing employees for additional career opportunities TEAM WORK: Maintain top quartile results within a professional, and productive work environment 23

24 Capital Expenditures $490 $205 $416 $199 Historical and Forecasted Capital Expenditures (in millions)* $340 $127 $369 $84 $410 $423 $127 $138 $401 $130 $285 $217 $213 $285 $283 $285 $ F 2015F 2016F * Excludes Corporate and discontinued ops Regulated Non-Regulated Regulated Cap-Ex vs. DD&A (in millions) Non-Reg Cap-Ex vs. DD&A (in millions) $300 $300 $250 $250 $200 $200 $150 $100 $50 3.9x 2.8x 2.4x 3.1x $150 $100 $50 3.8x 3.4x 1.9x 1.7x $ $ Cap-Ex DD&A^ Cap-Ex DD&A^ ^ Non-GAAP measure, reconciled to GAAP in Appendix 24

25 Capital Investment by Segment (in millions) F 2015F 2016F Generation $168 $146 $85 $72 $130 $76 $62 $72 Transmission Other Subtotal Electric Utilities Gas Utilities Total Utilities Power Generation Coal Oil and Gas Total Non-Reg Subtotal Utilities and Non Reg Corporate Total* $348 $497 $429 $347 $379 $418 $432 $408 * Excludes any forecasted capital expenditures for Cost of Service Gas program; excludes discontinued ops Note: differences due to rounding 25

26 Select Major Utility Projects Estimated Capital Expenditures * Excludes routine capital expenditures for maintenance of assets (in millions) Utilities Projected In-service Date 2014E 2015E 2016E E Total ** Cheyenne Light one 37 MW simple cycle unit and 95 MW combined cycle unit shared with Black Hills Power (includes transmission) Black Hills Power one 95 MW combined cycle unit shared with Cheyenne Light Colorado Electric proposed 40 MW simple-cycle unit to replace W.N. Clark Q $38 $132 Q $19 $ $6 $19 $39 $65 Black Hills Power Teckla / Osage / Lange 230 kv 2016 $7 $46 $1 $54 Black Hills Power Rapid City to Hot Springs 230 kv (rebuild) 2018 $29 $29 Colorado Electric two significant transmission projects 2017 $28 $28 Nebraska Gas Northeast Nebraska Line (pipeline) 2016 $11 $11 Retired power plant decommissioning n/a $6 $7 $2 $15 Power plant environmental upgrades n/a $7 $26 $33 * Above projects are a subset of the forecasted capital expenditures by utility segment on the previous slide ** Includes capital expenditures prior to 2014, if applicable 26

27 Cheyenne Prairie Generating Station New Generation Helps Meet Growing Demand and New Environmental Regulations Overview: Construction completed on time and on budget for new $222 million, 132 MW generating plant in Cheyenne, WY; plant jointly owned by Cheyenne Light and Black Hills Power Milestones: Commercial operations began October 1, 2014 Safety: Construction completed with TCIR of 0.86 and DART of zero 132 MW Electric Utility Power Generation Project In Service October 1,

28 Utility Growth Opportunity Cost of Service Gas Program - potential for direct investment in natural gas reserves provides longer-term price stability for customers, while providing opportunities for increased earnings Establishing Regulatory dialogue Initial Regulator and Consumer Advocate meetings held spring 2014 Technical workshops with Regulators and consumer advocate staffs started in Sept.; IA, KS, NE and SD meetings completed and CO and WY planned Evaluating natural gas reserves for inclusion in program Targeting 50% (39 bcf) of annual demand for our electric and gas utilities Estimating potential capital investment of $1.00 to $2.00 per mcfe delivered as Cost of Service Gas to our utility customers 28

29 Oil and Gas Strategy Prove up and capture value of existing oil and gas properties Prove up probable and possible reserves Capture value through optionality Pursue disciplined oil exploration, appraisal and development program Focus on oil plays to balance inventory Reserve potential should be impactful Execute Mancos Shale drilling program 94,000 net acres with net resource potential of 2-4 Tcf (dependent upon well spacing) Drill and complete six wells each in 2014 and 2015 Consider strategic options after 2015 Select property divestitures Joint venture drilling programs Utility cost-of-service gas program Other options Oil & Gas operations near De Beque, Colo. 29

30 Oil and Gas Strategy Complete 2014 Program Drill and complete up to six Mancos Shale wells in southern Piceance Basin Drilled, cased, cemented two wells and third well being drilled After third well cased and cemented, moving drilling rig to another pad to drill next three wells Will also start completing first three wells, which we expect to place on production in first quarter 2015 Continue Mancos Shale infrastructure improvements Continue participation in non-operated Bakken drilling program Pursue selective oil well exploration Continue to identify, acquire and develop oil resource potential reserves/acreage 30

31 Annual Dividend Per Share Dividend Growth Dividend Increased for 44 Consecutive Years $1.60 $1.55 Dividend yield 3.0% on Oct. 24, 2014 $1.52 $1.56 $1.50 $1.45 $1.42 $1.44 $1.46 $1.48 $1.40 $1.35 $1.30 $1.25 $ Board of Directors on October 28 declared quarterly dividend of $0.39 per share, equivalent to an annual rate of $1.56 per share 31

32 Credit Rating Moody s Investors Service on Oct. 1 affirmed its corporate credit ratings of Black Hills Corp. at Baa1 with a stable outlook and Black Hills Power at A3 with a stable outlook Standard & Poor s on July 31 affirmed its corporate credit ratings of Black Hills Corp. at BBB with a stable outlook Black Hills Corporation S&P Moody s Fitch Corporate Credit Rating BBB Baa1 BBB+ Senior Unsecured BBB Baa1 BBB+ Outlook Stable Stable Stable Black Hills Power S&P Moody s Fitch Corporate Credit Rating BBB A3 BBB+ Senior Secured Debt A- A1 A 32

33 Utilities Regulatory Update Utility & Filing Description* Filing Date Status BHP Rate case WY CPGS - $2.8MM request, 53%/47%, 10.25% ROE Q Approved ; $2.2MM, 53.32%/46.68%, 9.9% ROE Effective BHP Rate case SD CPGS - $14.6MM request, 53%/47%, 10.25% ROE Q Hearing Jan , 2015 Interim rates effective ; approval anticipated Q CLFP Rate cases WY COE ERP CPGS - $14.1MM request, 54%/46%, 10.25% ROE New 40 MW turbine and retirement of Pueblo 5 and 6 approved Q Approved ; $8.4MM Electric/$0.8MM Gas; 54%/46%, 9.9% ROE Effective Q Approved COE Rate case ALJ recommended $2.0MM, 9.83% ROE, 49.8%/50.2% Q Subject to exceptions and final commission approval; decision expected in Q4 KS Gas Rate case Settlement agreement for $5.2MM increase in base rates Q Hearing Nov. 12 and final order expected by Jan. 6 with new rates by mid- January * Equity / debt ratio 33

34 % of Generation by Fuel type Age in Years Operating Performance 100% Power Plant Fleet Availability^ by Fuel Type 100% Natural Gas Turbine Starting Reliability^^ BHC Industry BHC Industry 96% 96% 92% 92% 88% 88% 84% 84% 80% Coal Gas Diesel Wind 80% Starting Reliability 80% Generation Mix by Fuel Type 30 Combined Fleet Age 70% 60% 25 50% 20 40% 30% 20% 10% % F* Coal Gas Diesel Wind ^ From NERC GADS 2013 database ^^ From 2013 SPS ORAP (Operational Reliability Analysis Program) database * As of October 1, F* 34

35 Operating Performance Current as of Sept. 30,

36 Total Annual Outage in Minutes Operating Performance 2013 IEEE Reliability Benchmarking Study* 1 st Quartile < 93 minutes BHC 2013 SAIDI = 63 minutes BHC Utility * Represents average outage in minutes per customer, per year 36

37 Operating Performance Recognition Safety Performance Black Hills Energy named most trusted Midwest natural gas company by Market Strategies International. June 26, Wyoming Governor Matt Mead honored Black Hills Corp. s Wyodak Mine employees with a Governor s Workplace Safety Award Aug. 26, employees at the Wyodak Mine achieved no lost time injuries for five years and counting. Oct. 7, The Colorado Department of Public Health and Environment awarded Black Hills Energy with Gold Leader status recognizing the company for implementing environmental management systems achieving significant goals in environmental improvement and sustainability. 37

38 2014 Scorecard Strategy Construct cost effective rate-base generation and transmission to serve existing utility customers Acquire regulated utility properties in our geographic region Selectively grow Power Generation segment by contracting with other utilities Increase oil and gas production through development of existing acreage, selective exploration and limited acquisitions Construct additional utility infrastructure that supports growing demand, maintains reliability and enables improved customer satisfaction Balance integration of alternative and renewable energy with utility customer rate impacts Achieve top-tier operational performance in a culture of continuous improvement Improve efficiencies through continued deployment of technology Pursue power marketing and pipeline capacity release opportunities Efficiently use coal resources through mine-mouth generation Be the safest company in the energy industry Be one of the best places to work Improve the wellness of employees Become a workplace of choice for women and minorities 2014 Progress and Future Initiatives Complete Cheyenne Prairie Generating Station by Oct. 1 Deploy $136 million in electric and gas utility T&D system integrity projects Continue to evaluate utility acquisitions Close MGTC acquisition and acquire small natural gas systems Close CTII sale to City of Gillette Drill and complete 6 Mancos horizontal wells in Piceance Basin Drill and complete select oil exploration wells Increase annual dividend for 44 th consecutive year File application for approval of service territory for NW WY acquisition Finalize construction planning and permitting for utility s 40 MW natural gas-fired turbine to be located at Pueblo Airport Generating Station Finalize route selection and complete purchase of rights-of-ways for Northern Nebraska Gas Line (Norfolk) Complete rate cases for BHP and CLFP in WY related to CPGS Complete rate case for BHP in SD related to CPGS Finalize timing of CLFP s option to purchase Wygen I power plant Complete utility first mortgage bond financing for CPGS Complete PeopleSoft HR system upgrade Implement first phase of utility field service optimization project Improve coal margins by successfully renegotiating coal contract price reopener with PacifiCorp for Wyodak power plant Achieve safety TCIR of 1.3 Achieve third party recognition as a great employer Complete regular employee engagement survey Complete first annual biometric screening for all employees and spouses Fully establish gender diversity initiative and finish rollout of diversity training Legend Completed Planned in

39 Questions Pueblo Airport Generating Station near Pueblo, CO 39

40 Appendix Dory Batka and Jerry Likewise monitor the energy supply at our Neil Simpson Complex in Gillette, WY 40

41 Black Hills Corporation Overview A growth-oriented, vertically-integrated energy company with a tradition of exemplary service and a vision to be the energy partner of choice. Based in Rapid City, South Dakota, the company serves 777,000 electric and gas utility customers in Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The company generates wholesale electricity and produces natural gas, crude oil and coal. Employees partner to produce results that improve life with energy. Utilities, Power Generation & Fuel Production Utilities Electric Utilities Black Hills Power Cheyenne Light* Colorado Electric Gas Utilities Colorado Gas Iowa Gas Kansas Gas Nebraska Gas Non-Regulated Energy Power Generation Black Hills Electric Generation Coal Mining Wyodak Resources Oil and Gas Black Hills Exploration and Production * Utility supplies electric and gas service to Cheyenne, Wyoming and vicinity 41

42 Electric and Gas Utilities Cheyenne Light Colorado Electric Black Hills Power Black Hills Power Cheyenne Light Colorado Gas Nebraska Gas Kansas Gas Iowa Gas Electric Utilities* Generates, transmits and distributes electricity to approximately 204,000 customers and distributes natural gas to 35,000 customers Operations include Black Hills Power (SD, WY and MT), Cheyenne Light (WY) and Colorado Electric (CO) Includes 841 MW** of generation and 8,599 miles of transmission and distribution lines Total system high peak demand of 1,036 MW (2012) 100% of electric customers converted to AMI East-West interconnection located near Rapid City, SD optimizes the off-system sale of power and improves system reliability (1 of only 7 east-west ties) Natural Gas Utilities* Distributes natural gas to approximately 538,000 customers in CO, IA, KS, and NE Includes 604 miles of intrastate gas transmission pipelines and 19,998 miles of gas distribution mains and service lines Provides contract appliance repair service to approximately 62,000 customers through Service Guard Program Approximately 94% of gas meters have AMR / AMI technology * Information from 2013 Form 10-K, unless otherwise noted ** As of Oct. 1 42

43 Q Utilities Update Electric Utility Cooling Degree Days (Total for all electric service areas weighted by customer count) Electric Utility Total MWh Sales (in millions) Utility Customers Off-system Sales Electric Utility Generation Availability(%) Coal-fired plants Other plants Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Gas Utility Total Dth Sales (in millions) Gas Utility Heating Degree Days (Total for all gas service* areas weighted by customer count) 2,345 3, ,695 3, Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q * Excludes KS HDD data since state has weather normalization 43

44 Estimated Utility Rate Base Estimated Rate Base* by Utility Segment (in millions) Electric Utilities $901 $1,007 $1,272 $1,248 Gas Utilities $425 $443 $450 $454 Total $1,326 $1,450 $1,722 $1,702 * Estimated rate base determined at year-end and calculated using state specific requirements; includes capital expenditures through trackers but excludes construction work in-progress 44

45 Mitigating Regulatory Recovery Risk Mechanisms reduce regulatory lag and the risk of non-recovery Electric Utility Jurisdiction Environmental Cost DSM/ Energy Efficiency Transmission Cost Recovery Mechanisms Fuel Cost Transmission Cap-Ex Purchased Power Fixed Cost Recovery* Financing Cost Rider BHP - South Dakota BHP - Wyoming BHP - Montana BHP - FERC CLFP - Electric Customers CLFP - Gas Customers 52% BHE CO Electric Gas Utility Jurisdiction DSM/ Energy Efficiency Capital Additions Cost Recovery Mechanisms Bad Debt Weather Normal Fuel Cost Fixed Cost Recovery* BHE CO Gas 47% BHE IA Gas 70% BHE KS Gas 64% BHE NE Gas 55% Legend: Commission approved cost adjustment Pursuing * Residential customers 45

46 Non-Regulated Energy Power Generation* Owns interests in two power generation facilities totaling 269 MW Wygen I - 69 MW of a 90 MW coal-fired facility in Gillette, WY Pueblo Airport MW natural gas-fired facility in Pueblo, CO (co-located with regulated utility facility) Sells nearly all plant capacity and energy under long-term contracts to utility affiliates Oil and Gas* Operates wells in southern Piceance, Power River and San Juan Basins Owns interests in non-operated wells in Williston Basin (Bakken Shale) in North Dakota, and in California, Kansas, Montana, Oklahoma and Texas 87 Bcfe of reserves at year-end 2013; approximately 73% of reserves are natural gas and 27% crude oil Mancos shale opportunity of 94,000 acres offers upside potential with estimated resource potential of 2-4 Tcf (dependent on spacing) Coal Mining* Serves as fuel supply to adjacent mine mouth electric power generation customers Includes approximately 40-year supply of low-sulfur Powder River Basin coal reserves at expected production levels Forecasts production of approximately 4.2 million tons in 2014 Current low overburden expenses expected to increase for next several years Coal supply supports potential expansion of low-cost base load generation * Information from 2013 Form 10-K, unless otherwise noted 46

47 Units in millions Q Non-Regulated Update IPP Generation Contract Availability (%) Coal-fired plants Gas-fired plants Coal Production (Coal in millions of tons and overburden in millions of cubic yards) Coal Production Overburden Removed Revenue and Expense per Ton Sold (Units = tons sold plus cubic yards of overburden moved) OB Yards Coal Tons Rev/Ton Exp/Ton $ per ton Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Oil & Gas Bcf Equivalent Sales Gas Q Q4 2012* Oil Q Q Q Q Q Q * Sales volumes for Q and beyond reflect sale of most of our Williston Basin oil and gas assets Q Oil & Gas - Lease Operating Expenses (LOE per Mcfe) $0.99 Q $1.49 Q $1.08 Q $1.32 Q $1.26 Q $1.23 Q $1.19 Q $1.08 Q * $1.21 Q Average Nat Gas Price Received (per mmbtu) Price received (un-hedged) Price net of hedge settlement $5 $4 $3 $2 $1 $0 Q Q Q Q Q Q Q $2.70 $1.73 Q Q

48 Gillette Energy Complex Value proposition through integrated approach Coal production, generation, transmission utility and non-regulated assets Shared staff, facilities, land and infrastructure Wyodak Mine I-90 Wyodak Plant Wygen II & Wygen III Neil Simpson II & Wygen I 1 CT s 48

49 Coal Contracts Summary Approximately 50% of coal production sold under contracts that include price adjustments based on actual mining costs plus a return on mine capital investments Most of the remaining 50% of coal production sold under contracts where sales price changes are based on published indices but may lag actual mining costs Plant/Owner Existing Contracts Wyodak Plant (PacifiCorp) Production Tons (millions) 2014F Pricing Methodology Date Price Reopener or Adjustment Contract Expires Contract Quantity 1.5 Fixed with escalators July 1, 2019 Dec All plant usage Wygen III 0.6 Cost plus return Annual True-Up Life of plant All plant usage Other Black Hills Power coal plants 0.9 Cost plus return Annual True-Up Life of plant All plant usage Wygen I 0.5 Fixed with escalators July 1, 2018* Life of plant All plant usage Wygen II 0.5 Cost plus return Annual True-Up Life of plant All plant usage Other sales (truck) 0.2 Fixed 1-3 years Various Total 4.2 * Adjusts every 5 years 49

50 Oil & Gas Exploration & Development Program Note: approximate areas of geologic basins does not reflect BHEP acreage 50

51 Reserve Data and Net Present Value Reserve calculation at Dec. 31, 2013 Net Oil (MMBO)** Net Gas (BCF)** Net Equiv (BCFE)** PV10 (MM) Average Price Oil Per BBL ^ Average Price Nat Gas per MCF ^ PDP* $163.5 $89.88 $3.26 PNP* $9.8 $83.92 $5.22 PBP* $0.6 - $3.07 PUD* $0.5 $89.05 $4.61 Other $ Total** $184.4 $89.79 $3.45 ^ Average wellhead pricing used in determination of PV10 calculation (held constant for life of production) * PDP proved developed producing, PNP proved not producing, PBP proven behind pipe, PUD proved undeveloped ** Information from 2013 Year-End Reserves Study 51

52 Oil and Gas Mancos Shale Strategy Three successful test wells drilled in 2011 (4,000 5,000 foot horizontal laterals) affirmed potential in San Juan and southern Piceance Basins Two successful wells drilled in southern Piceance Basin in 2013 (8,000 9,000 foot horizontal laterals); earned approximately 20,000 acres of additional leasehold in southern Piceance Basin for completing wells Further delineation drilling required to fully assess value Plan to drill six additional wells in southern Piceance Basin in 2014; commenced drilling in June Plan to drill six additional wells in southern Piceance Basin in 2015 No material, near-term lease expiration deadlines Long-term, ongoing investment potential Manufacturing approach, predictable results Reserves expected at 6 to 9 Bcf per well based on 2011 and 2013 drilling results and performance of offset operators wells Targeted well costs of $ $1.50 per net Mcf Total Mancos opportunity 94,000 net acres Resource potential 2-4 Tcf (dependent upon well spacing) 52

53 Southern Piceance Basin Western Colorado 53

54 Southern Piceance Basin Mancos Drilling Program Questar White River Hub 1800 MMCF/day capacity 51 miles to the north H Questar White River Hub D-17 WT D 20D * 2011 Wells 2013 Wells 2014 Wells - Pipelines 2015 Wells - Pipelines Whittaker Flats Unit 4-28 Horseshoe Canyon Unit Black Hills Major Natural Gas Pipelines Rocky Mountain Trans Colorado Enterprise Chalk Mtn Unit Black Hills 550 MMCF/D capacity 248 miles to the south Kinder Morgan Blanco NM Hub 54

55 Gross Gas, Mcf/D Southern Piceance Basin Mancos Production 10,000 Piceance Basin Type Curve 10,000' Lateral Type Curve ~ 9.5 BCFE 1,000 5,000' Lateral Type Curve ~ 5.4 BCFE MONTHS Type 10,000' lateral Type 5,000' lateral WhF DHS3C-19 WhF DHS3C-20 55

56 San Juan Basin Mancos Shale WPX Rosa Unit Wells Rosa 634B (upper target) Produced 2.36 BCF Rosa 634A (lower target) Produced 2.07 BCF 16 miles BHGR Jicarilla Horizontal Well Jicarilla #724 (lower target) Produced 2.28 BCF 45 miles Southern Mancos (Gallup) Oil Field Activity Encana: 57 Gallup Mancos HZ wells spud of 122 permits, 51 producing Best IP 1600 BOPD WPX: 55 Gallup Mancos HZ wells spud of 80 permits, 19 producing Best IP 1400 BOPD 56

57 Gross Gas, Mcf/D San Juan Basin Mancos Production 100,000 Production Rates in Mcf/D 10,000 EUR 6.9 BCFE 1, MONTHS WPX - Rosa Unit 634A WPX - Rosa Unit 634B BHEP - Jicarilla #724 57

58 $75MM CLFP IR Bond CLFP IR Bond CLFP FMB BHP FMB $275MM Term Loan BHP FMB BHP FMB CLFP FMB In $ Millions $200MM 5.88% Note $525MM 4.25% Note Debt Maturities 600 Long-term Debt Maturities by Year - Sept

59 Use of Non-GAAP Financial Measures Gross Margin Our financial information includes the financial measure Gross Margin, which is considered a non-gaap financial measure. Generally, a non-gaap financial measure is a numerical measure of a company s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross Margin (Revenues less Cost of Sales) is a non-gaap financial measure due to the exclusion of depreciation from the measure. The presentation of Gross Margin is intended to supplement investors understanding of our operating performance. Gross Margin is calculated as operating revenue less cost of fuel, purchased power and cost of gas sold. Our Gross Margin is impacted by the fluctuations in power purchases and natural gas and other fuel supply costs. However, while these fluctuating costs impact Gross Margin as a percentage of revenue, they only impact total Gross Margin if the costs cannot be passed through to our customers. Our Gross Margin measure may not be comparable to other companies Gross Margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance. EBITDA and EBITDA, as adjusted We believe that our presentation of earnings before interest, income taxes, depreciation and amortization (EBITDA) and EBITDA, as adjusted (EBITDA adjusted for special items as defined by management), both non-gaap measures, are important supplemental measures of operating performance. We believe EBITDA and EBITDA, as adjusted, when considered with measures calculated in accordance with GAAP, give investors a more complete understanding of operating results before the impact of investing and financing transactions and income taxes. We have chosen to provide this information to investors to enable them to perform more meaningful comparisons of past and present operating results and as a means to evaluate the results of core on-going operations. Our presentation of EBITDA may be different from the presentation used by other companies and, therefore, comparability may be limited. Depreciation and amortization expense, interest expense, income taxes and other items have been and will be incurred and are not reflected in the presentation of EBITDA. Each of these items should also be considered in the overall evaluation of our results. Additionally, EBITDA does not consider capital expenditures and other investing activities and should not be considered a measure of our liquidity. We compensate for these limitations by providing relevant disclosure of our depreciation and amortization, interest and income taxes, capital expenditures and other items both in our reconciliation to the GAAP financial measures and in our consolidated financial statements, all of which should be considered when evaluating our performance. Note: continued on next page 59

60 Use of Non-GAAP Financial Measures Segment Revenue, Operating Income, Income from Continuing Operations and EPS, as adjusted We have provided non-gaap earnings data reflecting adjustments for special items as specified in the GAAP to non-gaap adjustment reconciliation table in this presentation. Segment Revenue, as adjusted, Operating Income (loss), as adjusted, Income (loss) from continuing operations, as adjusted, and Net income (loss), as adjusted, are defined as Segment Revenue, Operating Income (loss), Income (loss) from continuing operations and Net income (loss), adjusted for expenses, gains and losses that the company believes do not reflect the company s core operating performance. The company believes that non-gaap financial measures are useful to investors because the items excluded are not indicative of the company s continuing operating results. The company s management uses these non-gaap financial measures as an indicator for planning and forecasting future periods. Depreciation, Depletion and Amortization, as adjusted Depreciation, Depletion and Amortization (DD&A), as adjusted are defined as DD&A by segment adjusted for additional depreciation expense at our Utilities Group and reduced depreciation at our Non-regulated Group. We have provided this non-gaap measure to reflect adjustments by Business Group for the requirement under GAAP that the power purchase agreement between Colorado Electric and Colorado IPP be accounted for as a capital lease. The company believes that non-gaap measures are useful to investors because the lease accounting is not indicative of our rate recovery accounting. The company s management uses these non-gaap financial measures as an indicator for evaluating current periods and planning and forecasting future periods. Limitations on the Use of Non-GAAP Measures Non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our presentation of these non-gaap financial measures should not be construed as an inference that our future results will not be affected by unusual, non-routine, or non-recurring items. Non-GAAP measures should be used in addition to and in conjunction with results presented in accordance with GAAP. Non-GAAP measures should not be considered as an alternative to net income, operating income or any other operating performance measure prescribed by GAAP, nor should these measures be relied upon to the exclusion of GAAP financial measures. Our non-gaap measures reflect an additional way of viewing our operations that we believe, when viewed with our GAAP results and the reconciliation to the corresponding GAAP financial measures, provide a more complete understanding of factors and trends affecting our business than could be obtained absent this disclosure. Management strongly encourages investors to review our financial information in its entirety and not rely on a single financial measure. 60

61 Use of Non-GAAP Financial Measures Revenue, as adjusted (in thousands) QTD Sept 30, 2014 Utilities Electric Utilities Gas Utilities Non-Regulated Energy Power Generation Coal Mining Oil and Gas Corporate Total Revenue $ 171,395 $ 78,735 $ 1,602 $ 6,884 $ 13,471 $ - $ 272,087 Inter-company revenue 3,156 20,418 8,690 (32,264) Total revenue (GAAP) 174,551 78,735 22,020 15,574 13,471 (32,264) 272,087 Less: - Inter-company capital lease 533 (533) Revenue, as adjusted - (Non-GAAP) $ 174,551 $ 78,735 $ 22,553 $ 15,574 $ 13,471 $ (32,797) $ 272,087 QTD Sept 30, 2013 Utilities Electric Utilities Gas Utilities Non-Regulated Energy Power Generation Coal Mining Oil and Gas Corporate Total Revenue $ 169,401 $ 67,792 $ 1,575 $ 6,713 $ 14,426 $ - $ 259,907 Inter-company revenue 2,003 20,393 8,604 (31,000) Total revenue (GAAP) 171,404 67,792 21,968 15,317 14,426 (31,000) 259,907 Less: - Inter-company capital lease 469 (469) Revenue, as adjusted - (Non-GAAP) $ 171,404 $ 67,792 $ 22,437 $ 15,317 $ 14,426 $ (31,469) $ 259,907 61

62 Use of Non-GAAP Financial Measures Operating Income, as adjusted (in thousands, pre-tax) QTD Sept 30, 2014 Utilities Electric Utilities Gas Utilities Non-Regulated Energy Power Generation Coal Mining Oil and Gas Corporate Total Operating income (loss) (GAAP) $ 38,661 $ 3,945 $ 13,594 $ 3,156 $ (4,460) $ (491) $ 54,405 Capital lease adjustment 2,218 (2,680) 462 Operating income without capital lease (Non-GAAP) 40,879 3,945 10,914 3,156 (4,460) (29) 54,405 Significant Unique Items: Total Adjustments Operating income (loss), as adjusted (Non-GAAP) $ 40,879 $ 3,945 $ 10,914 $ 3,156 $ (4,460) $ (29) $ 54,405 QTD Sept 30, 2013 Utilities Electric Utilities Gas Utilities Non-Regulated Energy Power Generation Coal Mining Oil and Gas Corporate Total Operating income (loss) (GAAP) $ 38,453 $ 3,105 $ 14,329 $ 2,239 $ (2,393) $ (167) $ 55,566 Capital lease adjustment 2,338 (2,598) 260 Operating income without capital lease (Non-GAAP) 40,791 3,105 11,731 2,239 (2,393) 93 55,566 Significant Unique Items: Total Adjustments Operating income (loss), as adjusted (Non-GAAP) $ 40,791 $ 3,105 $ 11,731 $ 2,239 $ (2,393) $ 93 $ 55,566 62

63 Use of Non-GAAP Financial Measures Operating Income, as adjusted (in thousands, pre-tax) YTD Dec. 31, 2013 Electric Utilities Utilities Gas Utilities Non-Regulated Energy Power Generation Coal Mining Oil and Gas Corporate Total Operating income (loss) (GAAP) $ 133,595 $ 76,772 $ 47,760 $ 5,586 $ (7,251) $ (910) $ 255,552 Capital lease adjustment 9,413 (10,003) 590 Operating income without capital lease (Non-GAAP) 143,008 76,772 37,757 5,586 (7,251) (320) 255,552 Total adjustments Operating income (loss), as adjusted (Non-GAAP) $ 143,008 $ 76,772 $ 37,757 $ 5,586 $ (7,251) $ (320) $ 255,552 YTD Dec. 31, 2012 Electric Utilities Utilities Gas Utilities Non-Regulated Energy Power Generation Coal Mining Oil and Gas Corporate Total Operating income (loss) (GAAP) $ 131,721 $ 66,179 $ 44,799 $ 2,165 $ (428) $ (725) $ 243,711 Capital lease adjustment 9,820 (9,445) (375) Operating income without capital lease (Non-GAAP) 141,541 66,179 35,354 2,165 (428) (1,100) 243,711 Significant unique items: Gain on sale of Williston Basin assets (29,129) (29,129) Incentive compensation - Williston Basin asset sale 1,595 1, ,008 Impairment of Oil and Gas assets 26,868 26,868 Total adjustments 1,595 1, (1,294) 1,747 Operating income (loss), as adjusted (Non-GAAP) $ 143,136 $ 67,283 $ 35,459 $ 2,402 $ (1,722) $ (1,100) $ 245,458 63