Second Quarter 2014 Earnings Webcast 7/24/2014
On the Call Today 2 • Bob Rowe, President & CEO • Brian Bird, VP & CFO • Mike Cashell, VP Transmission • Heather Grahame, VP & General Counsel • John Hines, VP Energy Supply • Kendall Kliewer, VP & Controller • 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 10-Q which we filed with the SEC on July 24, 2014 and our other public filings with the SEC.
• 3% improvement in gross margin, despite slightly milder weather, as compared to the same quarter last year. • In April 2014, the FERC issued an order affirming a FERC Administrative Law Judge’s initial decision in September 2012, regarding cost allocation at DGGS between retail and wholesale customers. On May 19, 2014 a request for rehearing was filed and is pending before the FERC. • On July 18, 2014 we completed a robust and nearly two week regulatory hearing requesting approval of the purchase of hydro generating assets from PPL Montana. • Our board of directors declared a quarterly stock dividend of 40 cents per share payable September 30, 2014. Recent Significant Activities 4
Summary Financial Results 5 (in millions, except per share) 2014 2013 2014 2013 Operating Revenues $270.3 $260.2 $640.0 $573.2 Cost of Sales 112.5 106.9 279.9 239.1 Gross Margin 157.8 153.2 360.1 334.1 Operating Expenses Operating, general & administrative 74.4 67.4 146.4 136.2 Property and other taxes 28.0 25.8 56.5 51.6 Depreciation and depletion 30.4 27.4 60.7 56.6 Total Operating Expenses 132.7 120.6 263.7 244.4 Operating Income 25.1 32.7 96.4 89.7 Interest Expense (19.1) (17.1) (39.1) (33.9) Other Income 3.0 0.9 5.2 3.6 Income Before Taxes 9.0 16.4 62.5 59.4 Income Tax Expense (1.2) (2.1) (9.2) (7.2) Net Income $7.7 $14.3 $53.3 $52.2 Average Common Shares Outstanding 39.1 38.1 39.0 37.7 Basic Earnings per Average Common Share $0.20 $0.37 $1.37 $1.38 Diluted Earnings per Average Common Share $0.20 $0.37 $1.37 $1.38 Three Months Ended June 30, Six Months Ended June 30,
Second Quarter Financial Results 6 (in millions except per share amounts) 2014 2013 Variance Operating Revenues $270.3 $260.2 $10.1 Cost of Sales 112.5 106.9 5.6 Gross Margin 157.8 153.2 4.6 Operating Expenses Operating, general & administrative 74.4 67.4 7.0 Property and other taxes 28.0 25.8 2.2 Depreciation and depletion 30.4 27.4 3.0 Total Operating Expenses 132.7 120.6 12.1 Operating Income 25.1 32.7 (7.6) Interest Expense (19.1) (17.1) (2.0) Other Income 3.0 0.9 2.1 Income Before Taxes 9.0 16.4 (7.5) Income T xes (1.2) (2.1) 0.9 Net Income $7.7 $14.3 ($6.6) Average Common Share Outstanding 39.1 38.1 1.0 Basic Earnings Per Average Common Share $0.20 $0.37 ($0.17) Diluted Earnings Per Average Common Share $0.20 $0.37 ($0.17) Three Months Ended June 30,
7 Gross Margin (dollars in millions) Three Months Ended June 30, 2014 2013 Variance Electric $118.6 $118.0 $0.6 0.5% Natural gas 39.3 35.0 4.3 12.3% Other - 0.3 (0.3) (100.0%) Gross Margin $157.9 $153.3 4.6 3.0% Increase in gross margin due to the following factors: $ 5.1 Natural gas production $ 1.0 Demand side management lost revenue recovery $ (0.9) Natural gas retail volumes $ (0.6) Other $ 4.6
Operating Expenses 8 Increase in operating expenses due mainly to the following factors: $7.0 million increase in OG&A $ 2.9 Natural gas production $ 2.2 Bad debt expense $ 1.5 Nonemployee directors deferred compensation $ 0.9 Hydro Transaction costs $ (0.5) Other $2.2 million increase in property and other taxes due primarily to plant additions and higher estimated property valuations in Montana. $3.0 million increase in depreciation and depletion expense primarily due to plant additions, including approximately $1.2 million related to the acquisition of natural gas production assets. (dollars in millions) Three Months Ended June 30, 2014 2013 Variance Operating, general & admin. $74.4 $67.4 $7.0 10.4% Property and other taxes 28.0 25.8 2.2 8.5% Depreciation and depletion 30.4 27.4 3.0 10.9% Operating Expenses $132.8 $120.6 $12.2 10.1%
Operating Income to Net Income 9 (dollars in millions) 2014 2013 Variance Primarily due to: Operating Income $25.1 $32.7 ($7.6) Items discussed previously Interest Expense (19.1) (17.1) (2.0) Interest expense increase includes $1.9 million of expense associated with bridge credit facility related to the hydro transaction and higher interest from the issuance in December 2013 of $100 million of long-term debt unrelated to the Hydro Transaction, partially offset by lower interest accrued on revenues subject to refund and higher capitalization of AFUDC. Other Income 3.0 0.9 2.1 This increase was primarily due to a $1.5 million gain on deferred shares held in trust for non-employee directors deferred compensation, discussed in OA&G expenses, and higher capitalization of AFUDC. Income Before Taxes 9.0 16.4 (7.5) Income Tax Expense (1.2) (2.1) 0.9 Due primarily to lower pre-tax income Net Income $7.7 $14.3 ($6.6) Three Months Ended June 30,
(dollars in millions) As of June 30, As of December 31, 2014 2013 Cash 16.9$ 16.6$ Restricted cash 15.6 6.9 Accounts receivable, net 130.3 174.9 Inventories 52.9 55.6 Other current assets 74.9 67.0 Goodwill 355.1 355.1 PP&E and other non-current assets 3,146.0 3,039.2 Total Assets 3,791.8$ 3,715.3$ Payables 64.0 93.0 Current maturities of long-term debt & capital leases 1.7 1.7 Short-term borrowings 146.0 141.0 Other current liabilities 219.3 228.0 Long-term debt & capital leases 1,211.1 1,185.0 Other non-current liabilities 1,082.6 1,035.9 Shareholders' equity 1,067.2 1,030.7 Total Liabilities and Equity 3,791.8$ 3,715.3$ Capitalization: Current maturities of long-term debt & capital leases 1.7 1.7 Short Term borrowings 146.0 141.0 Long Term Debt & Capital Leases 1,211.1 1,185.0 Less: Basin Creek Capital Lease (30.7) (31.4) Shareholders' Equity 1,067.2 1,030.7 Total Capitalization 2,395.2$ 2,327.0$ Ratio of Debt to Total Capitalization 55.4% 55.7% Balance Sheet 10
Cash Flow 11 (dollars in millions) 2014 2013 Operating Activities Net Income 53.3$ 52.2$ Non-Cash adjustments to net income 95.4 87.6 Changes in working capital (6.4) 4.6 Other (17.8) (14.6) Cash provided by operating activities 124.6 129.8 Investing Activities PP&E additions (112.0) (88.5) Asset acquisition 1.5 - Other 0.1 0.7 Cash used in investing activities (110.4) (87.8) Financing Activities Proceeds from issuance of common stock, net 13.3 43.8 Issuance (Repayments) of long and short-term borrowings, net 4.9 (58.0) Dividends on common stock (30.9) (28.6) Other (1.1) (1.2) Cash used in financing activities (13.8) (44.0) Increase (Decrease) in Cash and Cash Equivalents 0.4 (2.0) Beginning Cash 16.5 9.8 Ending Cash 16.9$ 7.8$ Six Months Ending June 30,
Adjusted EPS Schedule 12 The first half of the year typically provides approximately 50% of our annual EPS contribution (with the second quarter only representing about 13%). Based upon midpoint of our $2.60 - $2.75 guidance range, our first half 2014 adjusted earnings of $1.41 represents approximately 53% of our 2014 earnings expectations. Q1 Q2 Q3 Q4 YTD 2014 2014 Reported GAAP diluted EPS $1.17 $0.20 $1.37 Non-GAAP Adjustments: Weather (0.05) 0.01 (0.04)$ Hydro transaction professional fees and bridge financing 0.04 0.04 0.08$ 2014 Adjusted diluted EPS $1.16 $0.25 $1.41 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 $1.38 $1.37 $- $0.25 $0.50 $0.75 $1.00 $1.25 $1.50 2013 2014 GAAP EPS - YTD thru Qtr 2 $1.36 $1.41 $- $0.25 $0.50 $0.75 $1.00 $1.25 $1.50 2013 2014 Non-GAAP Adjusted EPS - YTD thru Qtr 2
Reaffirmed 2014 Earnings Guidance 13 We are reaffirming our 2014 guidance range of $2.60-$2.75 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 Generating Station; • A consolidated income tax rate of approximately 14% to 16% of pre-tax income; and • Diluted average shares outstanding of 39.3 million. 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. $2.60-$2.75 See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP “Adjusted EPS”. $2.60-$2.75 $2.02 $2.14 $2.53 $2.66 $2.46 $- $1.50 $1.75 $2.0 $2.25 $2.50 $2.75 $3.00 2009 2010 2011 2012 2013 2014E GAAP Diluted EPS Initial Guidance Range Non-GAAP "Adjusted" EPS Diluted Earnings Per Share $2.60 - $2.75
Dave Gates Generating Station Update (DGGS) 14 • We operate a transmission system and balancing authority within Montana and are responsible for providing safe and reliable electric services to both retail and wholesale customers, or face stiff penalties for non-compliance. • DGGS was designed and constructed to provide NorthWestern with a resource to meet this important obligation. • Montana Public Service Commission provided pre-approval of the project in March 2009 with the groundbreaking in August. • Necessity of the plant has never been in question with the parties, including FERC Staff, agreeing through stipulation to a total revenue requirement. • The facility was completed on time and nearly $20 million under budget in December 2010 and is operating precisely as intended. • On September 21, 2012, a FERC Administrative Law Judge (ALJ) Initial Decision concluded that a significant portion of DGGS costs could not be allocated to wholesale customers, deviating from the previously approved allocation methodology. We have been recognizing revenue consistent with the initial decision and have $27.3 million reserved and subject to refund as of 6/30/14. • On April 17, 2014, nearly three and a half years after plant completion and almost 20 months after the ALJ’s initial decision, FERC issued an order affirming the initial decision. • In May 2014, we filed a request for rehearing, which remains pending. Included in our request we have argued that no refunds are due even if the cost allocation method is modified prospectively. The timing for FERC to act on our rehearing petition is uncertain, but could occur during the second half of 2014. Customer refunds, if any, will not be due until 30 days after a FERC order on rehearing. If unsuccessful on rehearing, we may appeal to a United States Circuit Court of Appeals. The time line for any such appeal could, depending on when the FERC issues a rehearing order extend into 2016 or beyond.
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 $56M through 6/30/14. Estimated total share of project is expected to be $95M-$105M including AFUDC and overheads Capitalized approximately $23M through 6/30/14, which is our total share of this project including AFUDC and overheads Timeline Project is on time and expected to be completed by April 2016 deadline Project was substantially completed in 2013, ahead of schedule, and is currently in service
Natural Gas Reserves Opportunity 16 We continue to pursue opportunities to secure low cost gas reserves for our customers. • Remaining 18% unfilled position to reach our targeted 50% owned supply. • Other potential opportunities to procure reserves to provide up to 50% (or 3-4 Bcf of natural gas annually) for Dave Gates Generating Station and our leased Basin Creek facility to also ensure fuel price stability for our electric customers. As we continue to add to our natural gas reserves portfolio, we anticipate a reduction in supply costs volatility for our customers. Battle Creek Bear Paw North Bear Paw South Announcement 9/22/2010 9/4/2012 5/28/2013 Purchase Pri ($M) $12.4 $19.5 $68.7 Ass ts 8.4 Bcf of proven producing reserves plus gathe ing system 13.4 Bcf of proven producing rese ves plus gathering system 63 Bcf of proven producing reserves lus gathering a d 82 mile transmissi line Recovery Statu Rate Based Tracker Track r (s tarted Dec. 2013) $- $20 $40 $60 $80 $100 $120 $140 $160 Transmission, Distribution & Storage Costs Natural Gas Supply Costs 10 Year Fluctuation in a 100 Therm Bill (Montana Residential Customers of NorthWestern)
Distribution System Infrastructure Project 17 • Montana Distribution System Infrastructure Project (DSIP) to maintain a safe and reliable electric and natural gas distribution system. – The primary goals: reverse the trend in aging infrastructure, maintain reliability, proactively manage safety, build capacity into the system, and prepare our network for the adoption of new technologies. – Based on our current plans, along with the MPSC's approval of the accounting order, we believe DSIP-related expenses and capital expenditures will be recovered in base rates through future general rate cases. ($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. With the addition of these assets, we anticipate over 50% of our owned and contracted generation in Montana will come from hydro and wind. • 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 18
Anticipated Hydro - Process and Timeline 19 • July 8-18, 2014 regulatory hearing with the Montana Public Service Commission (MPSC). • Post-hearing briefs due August 1st for NorthWestern and August 15th for intervenors • NorthWestern’s post-hearing reply brief due August 25th • September 16th, 2004 final day for MPSC to issue an order – MPSC can extend timeline for final order if it determines that extraordinary circumstances require additional time. • If we receive a satisfactory approval from the MPSC we will be seeking authority from FERC to issue securities in connection with the transaction. We anticipate a FERC approval to take 30 to 60 days from the date of a MPSC approval. • If we receive both MPSC and FERC approvals, we plan to close into permanent financing of up to $450 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 $900 million committed Bridge Facility with Credit Suisse and Bank of America Merrill Lynch. • For additional information visit: http://www.northwesternenergy.com/hydroelectric-facilities Mystic Dam
20 Appendix
21 Second Quarter - Reconciliation ($millions, except EPS) Th re e M on th s En de d, Ju ne 3 0, 2 01 3 N at ur al g as p ro du ct io n M ar gi n D SM lo st re ve nu e re co ve rie s N at ur al g as re ta il v ol um es N at ur al g as p ro du ct io n ex pe ns e Ba d de bt e xp en se N on em pl oy ee d ire ct or s de fe rre d co m pe ns at io n H yd ro T ra ns ac tio n co st s Pe rm an en t a nd fl ow -th ro ug h ad ju st m en ts to in co m e ta x Im pa ct o f h ig he r s ha re c ou nt Al l o th er Th re e M on th s En de d, Ju ne 3 0, 2 01 4 Gross Margin 153.3$ 5.1 1.0 (0.9) (0.6) 157.9 Operating Expenses Op.,Gen., & Administrative 67.4 2.9 2.2 1.5 0.9 (0.5) 74.4 Prop. & other taxes 25.8 2.2 28.0 Depreciation and depletion 27.4 3.0 30.4 Total Operating Expense 120.6 - - - 2.9 2.2 1.5 0.9 - - 4.7 132.8 Operating Income 32.7 5.1 1.0 (0.9) (2.9) (2.2) (1.5) (0.9) - - (5.3) 25.1 Interest Expense (17.1) (1.9) (0.1) (19.1) Other Income (Expense) 0.9 1.5 0.6 3.0 Income Before Inc. Taxes 16.4 5.1 1.0 (0.9) (2.9) (2.2) - (2.8) - - (4.7) 9.0 Income Tax Benefit (Expense)1 (2.1) (2.0) (0.4) 0.3 1.1 0.8 - 1.1 (1.8) 1.7 (1.2) Net Income (Loss) 14.3$ 3.1 0.6 (0.6) (1.8) (1.4) - (1.7) (1.8) - (3.0) 7.8 Fully Diluted Shares 38.22 0.99 - 39.21 Fully Diluted EPS 0.37$ 0.08$ 0.02$ (0.02)$ (0.05)$ (0.04)$ -$ (0.04)$ (0.05)$ (0.00)$ (0.07)$ 0.20$ 1.) Income Tax Benefit (Expense) calculation on reconciling items assumes normal effective tax rate of 38.5%.
22 Year-to-Date - Reconciliation ($millions, except EPS) S ix M on th s E nd ed , Ju ne 3 0, 2 01 3 N at ur al g as p ro du ct io n N at ur al g as a nd e le ct ric re ta il vo lu m es M on ta na n at ur al g as ra te in cr ea se D S M lo st re ve nu e re co ve rie s N at ur al g as p ro du ct io n B ad d eb t e xp en se H yd ro T ra ns ac tio n co st s N on em pl oy ee d ire ct or s de fe rr ed co m pe ns at io n P er m an en t a nd fl ow -th ro ug h ad ju st m en ts to in co m e ta x Im pa ct o f h ig he r s ha re c ou nt A ll ot he r, ne t S ix M on th s E nd ed , Ju ne 3 0, 2 01 4 Gross Margin 334.1$ 14.6 7.0 4.9 1.5 (2.0) 360.1 Operating Expenses Op.,Gen., & Administrative 136.2 5.0 3.1 1.7 1.3 (0.9) 146.4 Prop. & other taxes 51.6 4.9 56.5 Depreciation and depletion 56.6 4.1 60.7 Total Operating Expense 244.4 - - - - 5.0 3.1 1.7 1.3 - - 8.1 263.6 Operating Income 89.6 14.6 7.0 4.9 1.5 (5.0) (3.1) (1.7) (1.3) - - (10.1) 96.5 Interest Expense (33.9) (3.8) (1.4) (39.1) Other Income (Expense) 3.6 1.3 0.3 5.2 Income Before Inc. Taxes 59.4 14.6 7.0 4.9 1.5 (5.0) (3.1) (5.5) - - - (11.3) 62.5 Income Tax Benefit (Expense)1 (7.2) (5.6) (2.7) (1.9) (0.6) 1.9 1.2 2.1 - (1.0) - 4.5 (9.2) Net Inc me (Loss) 52.2$ 9.0 4.3 3.0 0.9 (3.1) (1.9) (3.4) - (1.0) - (6.8) 53.3 Fully Diluted Shares 37.87 1.20 - 39.07 Fully Diluted EPS 1.38$ 0.23 0.11 0.08 0.02 (0.08) (0.05) (0.08) - (0.03) (0.04) (0.17) 1.37$ 1.) Income Tax Benefit (Expense) calculation on reconciling items assumes normal effective tax rate of 38.5%.
Effective Tax Reconciliation 23 (in millions) 2014 2013 Variance 2014 2013 Variance Income Before Income Taxes $9.0 $16.4 ($7.5) $62.5 $59.4 $3.1 Income tax calculated at 35% federal statutory rate 3.1 5.8 (2.7) 21.9 20.8 1.1 Permanent or flow through adjustments: State income, net of federal provisions - (0.6) 0.6 0.4 (1.9) 2.3 Flow through repairs deductions (1.8) (2.1) 0.3 (11.5) (9.8) (1.7) Production tax credits (0.3) (0.5) 0.2 (1.8) (1.7) (0.1) Prior year permanent return to accrual adjustments - 0.5 (0.5) - 0.5 (0.5) Plant and depreciation of flow through items 0.1 (0.8) 0.9 0.5 - 0.5 Other, net 0.1 (0.2) 0.3 (0.3) (0.8) 0.5 (1.9) (3.7) 1.8 (12.7) (13.7) 1.0 Income tax expense $1.2 $2.1 ($0.9) $9.2 $7.1 $2.1 Effective tax rate 13.5% 12.8% 0.7% 14.7% 12.0% 2.7% Six Months Ended June 30, Three Months Ended June 30,
24 Second Quarter - Electric Segment (dollars in millions) 2014 2013 Change % Change Retail revenues 176.4$ 179.9$ (3.5)$ -1.9% Regulatory amortization 14.6 5.9 8.7 147.5 Total retail revenue 191.0 185.8 5.2 2.8 Transmission 12.7 12.5 0.2 1.6 Ancillary services 0.5 0.4 0.1 25.0 Wholesale 0.8 0.7 0.1 14.3 Other 1.0 1.1 (0.1) (9.1) Total Revenues 206.0 200.5 5.5 2.7 Total Cost of Sales 87.4 82.5 4.9 5.9 Gross Margin 118.6$ 118.0$ 0.6$ 0.5% 2014 2013 2014 2013 2014 2013 Retail Electric Montana 52,951$ 56,915$ 497 495 282,840 280,217 South Dakota 11,126 10,628 121 123 49,504 49,222 Residential 64,077 67,543 618 618 332,344 329,439 Montana 76,744 77,086 770 753 63,589 63,070 South Dakota 17,801 16,163 231 222 12,350 12,290 Commercial 94,545 93,249 1,001 975 75,939 75,360 Industrial 10,093 10,583 722 709 75 74 Other 7,667 8,561 47 54 6,104 6,065 Total Retail Electric 176,382$ 179,936$ 2,388 2,356 414,462 410,938 Total Wholesale Electric 773$ 670$ 49 35 - - (in thousands) Results Megawatt Hours (MWH) Avg. Customer CountRevenues
25 Year-to-Date - Electric Segment (dollars in millions) 2014 2013 Change % Change Retail revenues 385.8$ 379.9$ 5.9$ 1.6% Regulatory amortization 23.9 0.1 23.8 23,800.0 Total retail revenue 409.7 380.0 29.7 7.8 Transmission 26.1 26.1 — — Ancillary services 0.9 0.8 0.1 12.5 Wholesale 1.0 1.2 (0.2) (16.7) Other 2.8 2.5 0.3 12.0 Total Revenues 440.5 410.6 29.9 7.3 Total Cost of Sales 189.0 165.6 23.4 14.1 Gross Margin 251.5$ 245.0$ 6.5$ 2.7% 2014 2013 2014 2013 2014 2013 Retail Electric Montana 132,759$ 132,921$ 1,229 1,177 282,546 280,029 South Dakota 26,522 24,452 321 301 49,532 49,198 Residential 159,281 157,373 1,550 1,478 332,078 329,227 Montana 157,548 154,858 1,583 1,533 63,534 63,047 South Dakota 36,380 33,508 487 467 12,258 12,175 Commercial 193,928 188,366 2,070 2,000 75,792 75,222 Industrial 20,283 20,984 1,395 1,456 75 74 Other 12,349 13,221 70 77 5,375 5,288 Total Retail Electric 385,841$ 379,944$ 5,085 5,011 413,320 409,811 Total Wholesale Electric 1,017$ 1,177$ 60 58 - - (in thousands) Revenues Megawatt Hours (MWH) Avg. Customer Count Results
26 Second Quarter - Natural Gas Segment (dollars in millions) 2014 2013 Change % Change Retail revenues 55.6$ 49.1$ 6.5$ 13.2% Regulatory amortization (1.9) 1.0 (2.9) (290.0) Total retail revenue 53.7 50.1 3.6 7.2 Wholesale and other 10.6 9.3 1.3 14.0 Total Revenues 64.3 59.4 4.9 8.2 Total Cost of Sales 25.0 24.4 0.6 2.5 Gross Margin 39.3$ 35.0$ 4.3$ 12.3% 2014 2013 2014 2013 2014 2013 Retail Gas Montana 23,762$ 19,537$ 1,985 2,046 163,868 162,561 South Dakota 6,369 6,432 639 719 38,478 38,131 Nebraska 5,156 5,604 512 579 36,759 36,624 Residential 35,287 31,573 3,136 3,344 239,105 237,316 Montana 12,214 9,757 1,040 1,049 22,790 22,684 South Dakota 4,893 4,384 641 677 6,128 6,029 Nebraska 2,612 2,958 365 440 4,616 4,594 Commercial 19,719 17,099 2,046 2,166 33,534 33,307 Industrial 288 171 26 19 261 265 Other 274 209 29 29 153 158 Total Retail Gas 55,568$ 49,052$ 5,237 5,558 273,053 271,046 (in thousands) Revenues Dekatherms (Dkt) Avg. Customer Count Results
27 Year-to-Date - Natural Gas Segment (dollars in millions) 2014 2013 Change % Change Retail revenues 177.3$ 150.7$ 26.6$ 17.7% Regulatory amortization (0.3) (9.5) 9.2 (96.8) Total retail revenue 177.0 141.2 35.8 25.4 Wholesale and other 22.5 20.7 1.8 8.7 Total Revenues 199.5 161.9 37.6 23.2 Total Cost of Sales 90.9 73.5 17.4 23.7 Gross Margin 108.6$ 88.4$ 20.2$ 22.9% 2014 2013 2014 2013 2014 2013 Retail Gas Montana 75,129$ 62,401$ 7,556 7,207 163,754 162,549 South Dakota 20,769 18,310 2,436 2,230 38,637 38,296 Nebraska 17,228 16,517 1,962 1,855 36,941 36,826 Residential 113,126 97,228 11,954 11,292 239,332 237,671 Montana 38,302 31,296 4,244 3,671 22,771 22,691 South Dakota 14,944 12,202 2,113 1,948 6,155 6,056 Nebraska 9,405 8,735 1,385 1,311 4,643 4,624 Commercial 62,651 52,233 7,742 6,930 33,569 33,371 Industrial 785 631 83 76 263 266 Other 754 626 94 87 153 158 Total Retail Gas 177,316$ 150,718$ 19,873 18,385 273,317 271,466 (in thousands) Results Revenues Dekatherms (Dkt) Avg. Customer Count
28 Heating and Cooling Degree Days 3 Months ending June 30 2014 Cooling Degree-Days 2014 2013 Historic Average 2013 Historic Average M ntana 8 45 41 82% cooler 80% cooler South Dakota 77 50 63 54% warm r 22% warm r Degree Days 4 as compared with: Heating Degree-Days 2014 2013 Historic Average 2013 Historic Average Montana 1,244 1,267 1,306 % warmer 5% warmer S uth Dakota ,532 ,89 ,421 19 r r 8% cold r Nebrask 1,1 4 1,365 1,162 7% warmer 2% warmer Degree Days 4 as compared with: 6 Months ending June 30 2014 Cooling Degree-Days 2014 2013 Historic Average 2013 Historic Average M ntana 8 45 41 82% cooler 80% cooler South Dakota 77 50 63 54% warm r 22% warm r Degree Days 4 as compared with: Heating Degree-Days 2014 2013 Historic Average 2013 Historic Average Montana 4,719 4,490 4,581 5% cooler 3% cooler S uth Dakota 6,158 6,114 5, 19 1 c l r 12 c l r Nebrask 4,712 4,720 4,562 remained flat 3% cooler Degree Days 4 as compared with:
29 Second Quarter - Segment Results (Unaudited) (in thousands) Three Months Ending June 30, 2014 Electric Gas Other Total Operating revenues 206,010$ 64,271$ -$ 270,281$ Cost of sales 87,438 25,036 - 112,474 Gross margin 118,572 39,235 - 157,807 Operating, general and administrative 49,269 22,653 2,445 74,367 Property and other taxes 20,326 7,645 3 27,974 Depreciation 23,119 7,241 9 30,369 Operating Income (Loss) 25,858 1,696 (2,457) 25,097 Interest expense (14,469) (2,595) (2,063) (19,127) Other income 1,055 415 1,510 2,980 Income tax (expense) benefit (1,673) 65 404 (1,204) Net income (loss) 10,771$ (419)$ (2,606)$ 7,746$ Three Months Ending June 30, 2013 Electric Gas Other Total Operating revenues 200,472$ 59,362$ 327$ 260,161$ Cost of sales 82,520 24,393 - 106,913 Gross margin 117,952 34,969 327 153,248 Operating, general and administrative 47,721 18,483 1,160 67,364 Property and other taxes 19,016 6,792 2 25,810 Depreciation 21,693 5,712 9 27,414 Operating Income (Loss) 29,522 3,982 (844) 32,660 Interest expense (14,411) (2,567) (163) (17,141) Other income 702 198 28 928 Income tax (expense) benefit (76) (1,901) (129) (2,106) Net income (loss) 15,737$ (288)$ (1,108)$ 14,341$
30 Year-to-Date - Segment Results (Unaudited) (in thousands) Six Months Ending June 30, 2014 Electric Gas Other Total Operating revenues 440,521$ 199,483$ -$ 640,004$ Cost of sales 189,034 90,868 - 279,902 Gross margin 251,487 108,615 - 360,102 Operating, general and administrative 96,405 45,249 4,795 146,449 Property and other taxes 40,909 15,604 6 56,519 Depreciation 46,224 14,446 17 60,687 Operating Income (Loss) 67,949 33,316 (4,818) 96,447 Interest expense (29,638) (5,352) (4,103) (39,093) Other income 1,867 540 2,762 5,169 Income tax (expense) benefit (5,810) (4,260) 873 (9,197) Net income (loss) 34,368$ 24,244$ (5,286)$ 53,326$ Six Months Ending June 30, 2013 Electric Gas Other Total Operating revenues 410,564$ 161,880$ 737$ 573,181$ Cost of sales 165,615 73,494 - 239,109 Gross margin 244,949 88,386 737 334,072 Operating, general and administrative 93,439 38,378 4,384 136,201 Property and other taxes 38,168 13,396 5 51,569 Depreciation 45,304 11,311 17 56,632 Operating Income (Loss) 68,038 25,301 (3,669) 89,670 Interest expense (28,538) (4,993) (389) (33,920) Other income 2,713 875 55 3,643 Income tax (expense) benefit (4,380) (3,673) 903 (7,150) Net income (loss) 37,833$ 17,510$ (3,100)$ 52,243$
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 31 (in thousands) 2009 2010 2011 2012 2013 Reported GAAP diluted EPS 2.02$ 2.14$ 2.53$ 2.66$ 2.46$ Non-GAAP Adjustments Weather - 0.06 (0.05) 0.14 (0.05) Rate adjustments - (0.05) - - - Insurance recoveries - (0.08) - - - In me tax djustments - - (0.17) (0.06) - Tran mis ion r venue - low hydro - - 0.05 - - Dispute with f rmer employee - - 0.05 - - DGGS FERC ALJ initial decision (2011 portion) - - - 0.12 - Release of MPSC DGGS deferral - - - (0.05) - DSM Lost Revenue recovery - - - (0.05) (0.02) CELP arbitration decision - - - (0.79) - MSTI Impairment - - - 0.40 - Hydro Transaction costs - - - - 0.11 Adjusted Non-GAAP diluted EPS 2.02$ 2.07$ 2.41$ 2.37$ 2.50$ Use of Non-GAAP Financial Measures - Reconcile to Non-GAAP diluted EPS
32