1 2013 Earnings Webcast 2/19/2014

On the Call Today 2 • Bob Rowe, President & CEO • Brian Bird, VP & CFO • Heather Grahame, VP & General Counsel • Kendall Kliewer, VP & Controller • John Hines, VP Energy Supply • Travis Meyer, Director of Investor Relations

3 Forward Looking Statements During the course of this presentation, there will be forward-looking statements within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address our expected future business and financial performance, and often contain words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” or “will.” The information in this presentation is based upon our current expectations as of the date hereof unless otherwise noted. Our actual future business and financial performance may differ materially and adversely from our expectations expressed in any forward-looking statements. We undertake no obligation to revise or publicly update our forward-looking statements or this presentation for any reason. Although our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. The factors that may affect our results are listed in certain of our press releases and disclosed in the Company’s public filings with the SEC.

• Proposed hydro acquisition announcement in September 2013 – $900 million purchase of 11 hydro facilities and a storage reservoir • Natural gas acquisition in December 2013 – Acquired additional natural gas production interest in Montana for $68.7 million • Placed Aberdeen Generating Station into service – Aberdeen 60 MW natural gas peaking facility, with a constructed cost of $54.3 million was placed into service in early 2013 • Natural gas delivery rate adjustment – Received approval from the MPSC to increase rates effective April 1, 2013 in our natural gas distribution rate case • Successfully accessed capital markets to fund growth projects and extend debt maturities – Received $56.8 million in proceeds from the sale of equity in 2013 – Extended the maturity date of our revolving credit facility to November 2018 – Issued $100MM in 15 and 30 year First Mortgage Bonds in December 2013 • Moody’s upgrade in January 2014 – Secured: A2 to A1 and Unsecured from Baa1 to A3 • Board declared an increase in quarterly stock dividend payable March 31, 2014 – A 5.3% increase from $0.38 cents to $0.40 cents per share Significant Activities 4 2013 2014

Summary Financial Results 5 (in millions except EPS) 2013 2012 Variance Operating Revenues 1,154.5$ 1,070.3$ 84.2$ Cost of Sales (Gain on CELP arbitration decision) - (47.9) 47.9 Cost of Sales (Other) 479.6 443.3 36.3 Gross Margin 674.9 674.9 0.0 Operating Expenses Operating, general & administrative 285.6 270.0 15.6 MSTI impairment - 24.0 (24.0) Property and other taxes 105.5 97.7 7.9 Depreciation 112.8 106.0 6.8 Total Operating Expenses 503.9 497.7 6.2 Operating Income 171.0 177.2 (6.2) Interest Expense (70.5) (65.1) (5.4) Other Income 7.7 4.4 3.4 Income Before Taxes 108.3 116.5 (8.2) Income Taxes (14.3) (18.1) 3.8 Net Income 94.0$ 98.4$ (4.4)$ Average Common Share Outstanding 38.1 36.8 Basic Earnings Per Average Common Share 2.46$ 2.67$ (0.21)$ Diluted Earnings Per Average Common Share 2.46$ 2.66$ (0.20)$ Twelve Months Ended December 31,

_______________________________________ 6 $ 11.9 Natural gas and electric retail volumes $ 8.1 Natural gas production $ 6.6 Montana natural gas rate increase $ 5.6 Spion Kop revenue $ 5.1 DGGS revenues $ 3.8 Property tax trackers $ 3.7 Electric transmission $ 1.3 Natural gas transportation $ 1.0 Electric QF supply costs $(47.9) Gain on CELP arbitration decision $ (2.0) Operating expenses recovered in trackers $ (0.3) Demand Side Management (DSM) lost revenues $ 3.1 Other $ 0.0 Net variance ($millions) 2013 2012 Variance Electric Margin $506.5 $479.9 $ 26.6 5.5% Natural Gas Margin 166.7 145.8 20.9 14.3% Gain on CELP arbitration decision 0.0 47.9 (47.9) Other 1.7 1.3 0.4 30.8% Gross Margin $674.9 $674.9 $ 0.0 0.0% Gross Margin (excluding CELP arbitration) $674.9 $627.0 $47.9 7.6% Variances in gross margin due to the following factors: Twelve Months Ended December 31, Gross Margin

___________________________________ Operating Expenses 7 Twelve Months Ended December 31, ($millions) 2013 2012 Variance MTSI $ 0.0 $ 24.0 $(24.0) Operating, General & Administrative 285.6 270.0 15.6 5.8% Prop. & other taxes 105.5 97.7 7.8 8.0% Depreciation 112.8 106.0 6.8 6.4% Operating Expenses $503.9 $497.7 $ 6.2 1.2% Operating Expenses (excluding MSTI Impairment) $503.9 $473.7 $ 30.2 6.4% Increase due mainly to the following factors: • $(24.0) million decrease due to MSTI Impairment in 2012 • $15.6 million increase in OG&A $ 12.4 Distribution System Infrastructure Project expense $ 4.4 Hydro Transaction costs $ 4.4 Labor $ 4.2 Plant operator costs $ 3.0 Natural gas production $ 2.6 Nonemployee directors deferred compensation $ 1.4 Bad debt expense $(15.4) Pension and employee benefits $ (2.0) Operating expenses recovered in trackers $ 0.6 Other • $7.8 million increase in property and other taxes due primarily to higher assessed property valuations in Montana and plant additions. • $6.8 million increase in depreciation expense due to plant additions offset in part by a reduction in depreciation rates.

Operating to Net Income 8 (in millions) 2013 2012 Variance Primarily due to: Operating Income $171.0 $177.2 ($6.2) Items discussed previously Interest Expense (70.5) (65.1) (5.4) Interest expense increase in 2013 due to $1.9 million expenses associated with bridge credit facility related to the Hydro Transaction, higher interest from the issuance of long- term debt, and interest accrued on amounts subject to refund. Other Income 7.7 4.4 3.4 Other income increased primarily due to a $2.6 million gain on deferred shares held in trust for non-employee directors deferred compensation and higher capitalization of AFUDC. Income Before Taxes 108.3 116.5 (8.2) Income Tax Expense (14.3) (18.1) 3.8 Lower pre-tax income and effective tax rate Net Income $94.0 $98.4 ($4.4) Twelve Months Ended

Balance Sheet 9 (in millions) 2013 2012 Cash 16.6$ 9.8$ Restricted cash 6.9 6.7 Accounts receivable, net 174.9 143.7 Inventories 55.6 54.2 Other current assets 67.0 88.8 Goodwill 355.1 355.1 PP&E and other non-current assets 3,039.2 2,827.3 Total Assets 3,715.3$ 3,485.5$ Payables 93.0 83.7 Current maturities of long-term debt & capital leases 1.7 1.6 Short-term borrowings 141.0 122.9 Other current liabilities 228.0 241.0 Long-term debt & capital leases 1,185.0 1,086.6 Other non-current liabilities 1,036.0 1,015.6 Shareholders' equity 1,030.7 934.0 Total Liabilities and Equity 3,715.3$ 3,485.5$ Capitalization: Current maturities of long-term debt & capital leases 1.7 1.6 Short Term borrowings 141.0 122.9 Long Term Debt & Capital Leases 1,185.0 1,086.6 Less: Basin Creek Capital Lease (31.4) (32.9) Shareholders' Equity 1,030.7 934.0 Total Capitalization 2,326.8$ 2,112.3$ Ratio of Debt to Total Capitalization 55.7% 55.8% As of December 31,

Cash Flow 10 This $57.5 million decrease in operating cash flows is primarily due to a decrease in collection of receivables from customers of approximately $34.2 million, which includes approximately $20 million associated with billing delays as a result of a new customer information system implemented in September 2013, as compared to 2012. We expect these billing delays to be resolved during the first half of 2014. Also contributing to the decrease in operating cash flows were a $16.9 million increase in the under collection of supply costs in our trackers and higher interest payments of approximately $6.5 million. (in millions) 2013 2012 Operating Activities Net Income 94.0$ 98.4$ Non-Cash adjustments to net income 166.1 132.0 Changes in working capital (30.4) 47.1 Other (36.0) (26.3) Cash provided by operating activities 193.7 251.2 Investing Activities PP&E additions (230.5) (219.2) Asset acquisition (68.7) (103.2) Other 3.8 0.3 Cash used in investing activities (295.4) (322.2) Financing Activities Proceeds from issuance of common stock, net 55.8 28.0 Issuances of long-term debt, net 99.9 146.1 (Repayments) issuance of short-term borrowings, net 18.0 (44.0) Dividends on common stock (57.7) (54.2) Financing Costs (7.6) (0.9) Cash used in financing activities 108.4 74.9 Increase in Cash a d Cash Equivalents 6.7 3.9 Beginning Cash 9.8 5.9 Ending Cash 16.6$ 9.8$ Twelve Months Ending December 31,

Adjusted EPS Schedule 11 Q1 Q2 Q3 Q4 2013 2013 Reported GAAP diluted EPS $1.01 $0.37 $0.40 $0.68 $2.46 Non-GAAP Adjustments: Weather (0.02) (0.02) (0.01) (0.05)$ Hydro Transaction professional fees and bridge financing 0.05 0.06 0.11$ Prior period DSM lost revenue (including accrued interest) (0.04) 0.02 (0.02)$ 2013 Adjusted diluted EPS $1.01 $0.35 $0.39 $0.75 $2.50 Q1 Q2 Q3 Q4 2012 2012 Reported GAAP diluted EPS $0.88 $0.31 ($0.10) $1.57 $2.66 Non-GAAP Adjustments: Weather 0.09 0.05 (0.06) 0.06 0.14$ Release of MPSC DGGS deferral (0.05) (0.05)$ DSM Lost rev nue recovery related to 2010/2011 (0.05) (0.05)$ DGGS FERC ALJ initial decision - portion related to 2011 0.12 0.12$ MSTI Impairment 0.40 0.40$ Favorable CELP arbitration decision (0.79) (0.79)$ Income tax adjustment - benefit from MT NOL (0.06) (0.06)$ 2012 Adjusted diluted EPS $0.92 $0.31 $0.36 $0.78 $2.37$2.66 $2.46 $2.20 $2.30 $2.40 $2.50 $2.60 $2.70 $2.80 2012 2013 GAAP EPS $2.37 $2.50 $2.20 $2.30 $2.40 $2.50 $2.60 $2.70 $2.80 2012 2013 Non-GAAP Adjusted EPS

2014 Earnings Guidance 12 Continued investment in our system to serve our customers and communities is expected to provide a targeted 7-10% total return to our investors through a combination of earnings growth and dividend yield. 2014 guidance range of $2.60-$2.75 and a midpoint of $2.68 based upon, but not limited to, the following major assumptions and expectations: • Normal weather in our electric and natural gas service territories for 2014; • Excludes any hydro related transaction fees (including legal and bridge financing) and any potential income generated from the operation of the hydro assets post – closing, assuming regulatory approval; • Excludes any potential additional impact as a result of the FERC decision regarding revenue allocation at our Dave Gates Generation Station; • A consolidated income tax rate of approximately 14% to 16% of pre-tax income; and • Diluted average shares outstanding of 39.3 million. 2014 broad earnings drivers 2014 guidance affirmed Bridge 2013 Reported GAAP 2.46$ 2013 Non-GAAP adjustments: Weather (favorable) (0.05)$ Hydro Transaction professional fees and bridge financing 0.11$ Prior period DSM lost revenue (including accrued interest) (0.02)$ 2013 adjustments to 2013 GAAP earnings 0.04$ Low High 2013 Non-GAAP Earnings 2.50$ 2.50$ 2014 Expectations/Assumptions Bear Paw South acquisition 0.07$ 0.09$ Full year MT Nat. Gas relief 0.09$ 0.11$ Other Gross Margin increases 0.23$ 0.27$ OA&G increases (0.09)$ (0.06)$ Property Tax increases (0.07)$ (0.06)$ Depreciation increase (0.04)$ (0.03)$ Interest / Other I come (0.02)$ (0.01)$ Dilution-existing quity dribble (0.07)$ (0.06)$ 2014 Expectation /Assumptions 0.10$ 0.25$ 2014 EPS Range 2.60$ 2.75$

Investment for our Customers’ Benefit Over the past 5 years, we have been adding to our Montana energy supply portfolio and making additional investments to enhance system safety, reliability and capacity. We have made these enhancements with minimal impact to customers’ bills while delivering solid earnings growth for our investors. 2008-2013 CAGRs Estimated Rate Base: 12.9% GAAP Diluted EPS: 6.7% Elec. retail rev./ MWh : 2.5% Nat. Gas retail rev./Dkt: (6.1%) 13 $1.00 $1.25 $1.50 $1.75 $2.00 $2.25 $2.50 $2.75 $3.00 $1,000 $1,250 $1,500 $1,750 $2,000 $2,250 $2,500 $2,750 2008 2009 2010 2011 2012 2013 Rate Base and Earnings per Share Estimated Rate Base (Millions) GAAP Diluted EPS Rate Bas e -M illion s EPS -Dollars $69.57 $68.78 $70.03 $73.26 $74.95 $78.74 $60 $70 $80 $90 20 8 2009 2010 2011 2012 2013 Retail Electric Revenu per Megawatt hour (MWh) $11.20 $9.80 $9.11 $8.92 $8.66 $8.19 $- $3 $6 $9 $12 $15 2008 2009 2010 2011 2012 2013 Retail Natural Gas Revenue per Dekatherm (Dkt)

FERC / DGGS 14 • The Issue: FERC Administrative Law Judge issued a nonbinding decision to allocate only a fraction of the amount of revenue we believe should be allocated based on past practice to FERC customers for our Dave Gates Generating Station. – FERC is not obligated to follow any of the ALJ’s findings – Timing uncertain as to when FERC will issue its decision. • Once decision is issued and if we disagree, we may pursue full appellate rights through rehearing and appeal to the US Circuit Court of Appeals, which could extend into 2015 or beyond. • We have cumulative deferred revenue of $24.5 million as of December 31, 2013 and we continue to defer revenue of approximately $700K per month. • We continue to bill FERC jurisdictional customers interim rates that have been in effect since January 2011. These interim rates are subject to refund plus interest. • The facility continues to operate as designed. – From May 2012 through December 2013, the two-unit availability has been 98.3% with the facility meeting NorthWestern’s Balancing Authority’s Control Performance Standard 2 (CPS2) compliance requirement of 90.0%.

Big Stone and Neal Air Quality Projects 15 Big Stone Power Plant Neal Power Plant Big Stone Neal Location Northeast South Dakota Northwest Iowa Ownership 23.4% of 475 MW coal plant 8.7% of 644 MW coal plant Project Subject to Best Available Retrofit Technology (BART) requirements of the Regional Haze Rule and are installing an Air Quality Control System (AQCS) to reduce SO2, NOx and particulates Subject to comply with national ambient air quality standards and Mercury & Air Toxics Standards (MATS) and are installing a scrubber, a baghouse, activated carbon and a selective non-catalytic reduction system Capital Outlay Capitalized approximately $40M through 12/31/13. Estimated total share of project is expected to be $95M-$110M including AFUDC and overheads Capitalized approximately $22M through 12/31/13, which is our total share of this project including AFUDC and overheads Timeline Project is on time and expected to be completed in 2016 Project was substantially completed in 2013, ahead of schedule, and is currently in service

Southern Bear Paw Transaction 16 • Finalized acquisition of Bear Paw South – On December 2, 2013, we finalized the purchase of 63 Bcf proven reserves and 82% interest in Havre Pipeline Company for $68.7 million. – Our largest natural gas reserves acquisition to date adding 29 employees to our 14 existing gas production employees. – The Montana PSC approved the structure of the transaction in October 2013 – With this transaction, we now manage an additional 900 wells and 82 miles of transmission in the Bear Paw Basin. – We will utilize our natural gas tracker to recover cost of gas similar to Battle Creek initially and Bear Paw North currently. • 20 Year levelized price of approximately $4.10 per dekatherm – Based upon 2014 estimates, this transaction increased owned supply for our Montana retail customers from approximately 8% to 32%. – Owned total supply estimate of 32% for 2014 is lower than the estimated 37%, as previously communicated for 2013, due to decline in annual production as anticipated. Blaine County Montana Compressor Station

Natural Gas Reserves Opportunity 17 We continue to pursue opportunities to secure low cost gas reserves for our customers. • Remaining 18% unfilled position to reach our targeted 50% owned supply. • Other potential opportunities to procure reserves to provide up to 50% (3-4 Bcf of natural gas annually) for Dave Gates Generating Station and our leased Basin Creek facility to also ensure fuel price stability for our electric customers. $- $20 $40 $60 $80 $100 $120 $140 $160 Transmission, Distribution & Storage Costs Natural Gas Supply Costs 10 Year Fluctuation in a 100 Therm Bill (Montana Residential Customers of NorthWestern) As we continue to add to our natural gas reserves portfolio, we anticipate a reduction in supply costs volatility for our customers. Battle Creek Bear Paw North Bear Paw South Announcement 9/22/2010 9/4/2012 5/28/2013 Purchase Price ($M) $12.4 $19.5 $68.7 Assets 8.4 Bcf of proven producing reserves plus gathering sy tem 13.4 Bcf of proven producing reserves plus gathering system 63 Bcf of proven producing reserves plus gathering and 82 mile transmission line Recovery Status Rate Based Tracker Tracker (s tarted Dec. 2013)

Distribution System Infrastructure Project 18 • Montana Distribution System Infrastructure Project (DSIP) to maintain a safe and reliable electric and natural gas distribution system. – The primary goals: reverse the trend in aging infrastructure, maintain reliability, proactively manage safety, build capacity into the system, and prepare our network for the adoption of new technologies. – Based on our current plans, along with the MPSC's approval of the accounting order, we believe DSIP-related expenses and capital expenditures will be recovered in base rates through future general rate cases. ($millions) CAPEX O&M CAPEX O&M CAPEX O&M CAPEX O&M Electric Utility Total $59 $17 $45 $7 $127 $32 $231 $56 Natural Gas Utility Total 18 2 7 1 27 14 52 17 Other Total 4 6 - 1 0 9 4 16 Project Total $81 $25 $52 $9 $154 $55 $287 $89 Accounting Order ($13) $3 $10 $0 Estimated P&L Impact $12 $12 $65 $89 BudgetActual 2011 - 2013 2014 2015 - 2017 2011-17 Total Estimated Cost w/inflation

Pending Hydro Transaction Our Vision Statement: Working together to deliver safe, reliable and innovative energy solutions that create value for our customers, communities, employees and investors. The acquisition of these highly valuable assets should allow NorthWestern to further our mission statement for the benefit of all stakeholders for multiple generations to come. • Opportunity to acquire clean, reliable, long-lived generation assets near the bottom of commodity price cycle • Provides multiple generations of customers with long-term energy certainty and locks in rate stability with modest impact of ~5% increase from Sept. 2013 rates to total residential bills • Transaction helps match owned generation with load requirements • Increases fuel-type diversity of generation fleet with significant increase in sustainable generation • Consistent with focus on our existing regulated utility business and all of our customers Customers • Reinforces and expands NorthWestern’s commitment to Montana, its people and its environment • Evolving environmental regulation may make Montana hydro assets even more valuable • Allows NorthWestern to increase its commitment to charitable giving throughout Montana Communities • Combination of existing NorthWestern employees with extensive hydroelectric backgrounds and at least 70 PPL employees • Increased opportunity for professional growth for both existing employees and employees who transfer when the sale closes • NorthWestern remains committed to competitive pay and benefits Employees • Inclusion of assets in regulated rate base • Expected to be accretive in first full year of operations • Expected to maintain or enhance credit strength Investors 19

• Financing Plans – Plan to close into permanent financing up to $500 million of debt, up to $400 million of equity, and up to $50 million of free cash flows. – If capital market access is limited, we have the option of closing into the $900 million committed Bridge Facility with Credit Suisse and Bank of America Merrill Lynch. Hydro Financing Strategy 20 Black Eagle

• Announced the transaction on September 26, 2013 • Pre-filing informational meeting with the Montana PSC on October 18, 2013 • Bridge facility – entered into a $900 million 364-day senior bridge credit facility on November 12, 2013 • Filed Application for Approval to Purchase and Operate the Hydro Electric Facilities with the Montana PSC on December 20, 2013 [Docket: D2013.12.85] • Filed required applications with FERC on January 10, 2014 to transfer licenses from PPL Montana to NorthWestern Energy [Docket: FERC-2014-0151] • Anticipate seeking antitrust approval of the transaction in the second quarter of 2014 • Montana PSC hearing set for July 8, 2014 • Final day for Montana PSC to issue an order on September 16, 2014 – MPSC can extend timeline for final order if it determines that extraordinary circumstances require additional time. • For additional information visit: http://www.northwesternenergy.com/hydroelectric-facilities Hydro – Process and Timeline 21

Other Significant Achievements in 2013 22 • Record best year for safety at NorthWestern – Fewest lost time incidents and OSHA recordable events of any year on record. • Record best customer satisfaction scores – Received our best JD Powers overall satisfaction survey score in 2013. • Continue to provide high electric reliability, 1st quartile in SD & 2nd quartile overall • Completed first full year of DSIP investment and on track with 5 year plan • Cost effectively implemented new customer information system (eCIS) with minimal interruptions to our business • Named to the Forbes “Americas Most Trustworthy Companies” for the 3rd consecutive time – Recognition identifies the most transparent and trustworthy businesses that trade on American exchanges. NorthWestern was one of only three utilities selected in 2013. • Fortnightly 40 company – Recognized as one of the top 40 best energy companies in the United States by Fortnightly 40 in 2013. • Cordpedia – NYSE Ethics – NorthWestern Energy earned an “A” from the New York Stock Exchange’s Corpedia, for its Code of Conduct and Ethics, putting it in the top 2 percent of all energy and utility companies reviewed..

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24 APPENDIX Consolidated pretax income for the quarter ended December 31, 2013 was $31.4 million as compared to $74.8 million for the same period in 2012. This $43.4 million decrease in pretax income is due primarily to a $47.9 million gain on an arbitration decision recorded in the fourth quarter of last year and increased operating expenses, depreciation and interest in 2013. These reductions to year-over-year pretax income are partially offset by improved gross margin related to increased retail electric and natural gas volumes, increased Montana natural gas delivery rates and the addition of new energy supply assets (Spion Kop wind and Bear Paw natural gas reserves). Consolidated net income for the quarter ended December 31, 2013 was $26.1 million, or $0.68 per diluted share, as compared with $58.7 million, or $1.57 per diluted share, for the same period in 2012. (in millions except EPS) 2013 2012 Variance Operating Revenues 319.1$ 280.8$ 38.3$ Cost of Sales (Gain on CELP arbitration decision) - (47.9) 47.9 Cost of Sales (Other) 136.1 115.4 20.7 Gross Margin 183.0 213.3 (30.3) Operating Expenses Operating, general & administrative 76.8 74.2 2.6 Property and other taxes 28.0 23.3 4.7 Depreciation 28.1 26.7 1.4 Total Operating Expenses 133.0 124.2 8.7 Operating Income 50.0 89.1 (39.0) Interest Expense (19.5) (15.5) (4.0) Other Income 1.0 1.2 (0.3) Income Before Taxes 31.4 74.8 (43.4) Income Taxes (5.3) (16.1) 10.8 Net Income 26.1$ 58.7$ (32.6)$ Average Common Share Outstanding 38.6 37.2 Basic Earnings Per Average Common Share 0.67$ 1.58$ (0.91)$ Diluted Earnings Per Average Common Share 0.68$ 1.57$ (0.89)$ Three Months Ended December 31,

25 APPENDIX NORTHWESTERN CORPORATION Twelve Months Ended December 31, 2013 ($millions, except EPS) Tw elv e M on ths En de d, De c 3 1, 201 2 Na tur al g as pro duc tion Mo nta na nat ura l ga s r ate inc rea se Na tur al g as ret ail vol um es Sp ion Ko p r eve nue Ele ctr ic r eta il v olu me s DG GS re ven ues Pro per ty tax tra cke rs Ele ctr ic t ran sm iss ion Na tur al g as tra nsp ort atio n c apa city Ele ctr ic Q F s upp ly c ost s Ga in o n C EL P a rbit rat ion de cis ion in 201 2 Op era ting ex pen ses re cov ere d in tra cke rs De ma nd Sid e M ana gem ent (D SM ) lo st rev enu es DS IP exp ens es Hy dro Tr ans act ion co sts Lab or Pla nt ope rat or cos ts Na tur al g as pro duc tion No nem plo yee dir ect ors de fer red com pen sat ion Ba d d ebt ex pen se Pe nsi on and em plo yee be nef its Op era ting ex pen ses re cov ere d in tra cke rs Sta te inc om e, net of fe der al p rov isio ns Flo w t hro ugh re pai rs ded uct ion s Pro duc tion ta x c red its Pla nt and de pre cia tion of flo w t hro ugh ite ms Re cog niti on of sta te NO L b ene fit Pri or yea r p erm ane nt ret urn to ac cru al adj ust me nts Oth er per ma nen t o r fl ow th rou gh adj ust me nts , Ne t Im pac t o f h igh er sha re cou nt (m ain ly e qui ty she lf p rog ram ) All ot her , n et Tw elv e M on ths En de d, De c 3 1, 201 3 Gross Margin 674.9$ 8.1 6.6 6.5 5.6 5.4 5.1 3.8 3.7 1.3 1.0 (47.9) (2.0) (0.3) 3.1 674.9$ Operating Expenses Op.,Gen., & Administrative 270.0 12.4 4.4 4.4 4.2 3.0 2.6 1.4 (15.4) (2.0) 0.6 285.6 MSTI Impairment in 2012 24.0 (24.0) - Prop. & other taxes 97.7 7.8 105.5 Depreciation 106.0 6.8 112.8 Total Operating Expense 497.7 - - - - - - - - - - - - - 12.4 4.4 4.4 4.2 3.0 2.6 1.4 (15.4) (2.0) - - - - - - - (8.8) 503.9 Operating Income 177.2 8.1 6.6 6.5 5.6 5.4 5.1 3.8 3.7 1.3 1.0 (47.9) (2.0) (0.3) (12.4) (4.4) (4.4) (4.2) (3.0) (2.6) (1.4) 15.4 2.0 - - - - - - - 11.9 171.0 Interest Expense (65.1) (5.4) (70.5) Other Income (Expense) 4.4 3.3 7.7 Income Before Inc. Taxes 116.5 8.1 6.6 6.5 5.6 5.4 5.1 3.8 3.7 1.3 1.0 (47.9) (2.0) (0.3) (12.4) (4.4) (4.4) (4.2) (3.0) (2.6) (1.4) 15.4 2.0 - - - - - - 9.9 108.3 Income Tax Benefit (Expense)1 (18.1) (3.1) (2.5) (2.5) (2.2) (2.1) (2.0) (1.5) (1.4) (0.5) (0.4) 18.4 0.8 0.1 4.8 1.7 1.7 1.6 1.2 1.0 0.5 (5.9) (0.8) 4.2 1.4 3.2 (0.7) (2.4) (2.4) (2.4) (4.1) (14.3) Net Income (Loss) 98.4$ 5.0 4.1 4.0 3.4 3.3 3.1 2.3 2.3 0.8 0.6 (29.5) (1.2) (0.2) (7.6) (2.7) (2.7) (2.6) (1.8) (1.6) (0.9) 9.5 1.2 4.2 1.4 3.2 (0.7) (2.4) (2.4) (2.4) - 5.9 94.0$ Fully Diluted Shares 37.04 1.19 - 38.23 Fully Diluted EPS 2.66$ 0.13 0.11 0.10 0.09 0.09 0.08 0.06 0.06 0.02 0.02 (0.77) (0.03) (0.01) (0.20) (0.07) (0.07) (0.07) (0.05) (0.04) (0.02) 0.25 0.03 0.11 0.04 0.08 (0.02) (0.06) (0.06) (0.06) (0.08) 0.14 2.46$ 1.) Income Tax Benefit (Expense) calculation on reconciling items assumes effective tax rate of 38.5%.

APPENDIX 26 (in millions) 2013 2012 Variance Income Before Income Taxes $108.3 $116.5 ($8.2) Income tax calculated at 35% federal statutory rate 37.9 40.8 (2.9) Permanent or flow through adjustments: State income, net of federal provisions (3.1) 1.1 (4.2) Flow through repairs deductions (17.8) (16.4) (1.4) Production tax credits (3.2) - (3.2) Plant and depreciation of flow through items (0.6) (1.3) 0.7 Recognition of state net operating loss benefit - (2.4) 2.4 Proir year permanent return to accrual adjustments 0.5 (1.9) 2.4 Other permanent or flow through adjustments, net 0.6 (1.8) 2.4 (23.6) (22.7) (0.9) Income tax expense $14.3 $18.1 ($3.8) Twelve Months Ended December 31,

These materials include financial information prepared in accordance with GAAP, as well as other financial measures, such as Gross Margin and Adjusted Diluted EPS, that are considered “non-GAAP financial measures.” Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that exclude (or include) 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. Gross Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs. Adjusted Diluted EPS is another non-GAAP measure. The Company believes the presentation of Adjusted Diluted EPS is more representative of our normal earnings than the GAAP EPS due to the exclusion (or inclusion) of certain impacts that are not reflective of ongoing earnings. The presentation of these non-GAAP measures is intended to supplement investors' understanding of our financial performance and not to replace other GAAP measures as an indicator of actual operating performance. Our measures may not be comparable to other companies' similarly titled measures. Non-GAAP Financial Measures 27