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| EX-99.1 - EXHIBIT 99.1 RELEASE - NORTHWESTERN CORP | ex991pressreleaseq32015.htm |
| 8-K - 8-K 2015 3RD Q FINANCIAL RESULTS - NORTHWESTERN CORP | form8kearningsreleaseq32015.htm |
Third Quarter 2015 Earnings Webcast October 22, 2015 Beethoven Wind Farm
Presenting Today 2 Bob Rowe, President & CEO Brian Bird, Vice President & CFO
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 Form 10-K and 10-Q along with other public filings with the SEC.
Recent Significant Activities 4 • Net income of $23.8 million reported in the third quarter of 2015 as compared with $30.2 million the same period in 2014. • The decrease was primarily the result of a $16.9 million tax benefit recognized in the third quarter last year partially offset by the income from the November 2014 hydro acquisition. • Diluted EPS of $0.51 as compared to $0.77 in the third quarter 2014. • Adjusted Non-GAAP Diluted EPS of $0.51 as compared to $0.38 in the third quarter 2014. • Reached a settlement agreement in our South Dakota electric rate filing with the SDPUC staff and intervenors. • If approved by the SDPUC commission, the settlement will provide an increase in base rates of $20.2 million plus an additional $9.0 million related to the 80 megawatt Beethoven wind project. • On September 25th, we completed the Beethoven acquisition for approximately $143 million, from BayWa.r.e Wind LLC. • As compared to the 20 year Qualifying Facilities contracts previously in place, the acquisition is projected to benefit our South Dakota customers in excess of $44 million over the same period. • Acquisition was financed with the issuance of $70 million of 25 year First Mortgage Bonds with a coupon of 4.26% in September 2015, $57 million of equity (1.1M shares) in October 2015 and the remainder with available cash and short-term borrowings. • Narrowed full year 2015 adjusted guidance to $3.10 - $3.25 per diluted share. • Previously announced guidance was $3.10 - $3.30 • Board of Directors approved a $0.48 per share dividend payable December 31, 2015.
Summary Financial Results (Third Quarter) 5
6 Gross Margin (Third Quarter) (dollars in millions) Three Months Ended September 30, 2015 2014 Variance Electric $ 172.3 $ 127.7 $ 44.6 34.9% Natural Gas 26.8 29.6 (2.8) (9.5%) Gross Margin $ 199.1 $ 157.3 $ 41.8 26.6% Increase in gross margin due to the following factors: $ 40.4 Hydro operations $ 1.8 South Dakota electric interim rate increase (subject to refund) $ 1.3 Property tax tracker $ 1.1 Electric retail volumes $ (0.9) Electric transmission capacity $ (0.5) Natural gas retail volumes $ (0.4) Gas production deferral $ (1.0) Other $ 41.8
Weather (Third Quarter) 7 Maximum Temperature from Normal Minimum Temperature from Normal
Operating Expenses (Third Quarter) 8 Increase in operating expenses due mainly to the following factors: $11.2 million increase in OG&A $ 10.8 Hydro operations $ 3.5 Non-employee directors deferred compensation $ (0.6) Hydro transaction costs $ (0.5) Bad debt expense $ (2.0) Other $7.9 million increase in property and other taxes due primarily to plant additions and higher estimated property valuations in Montana, which includes an estimated $6.4 million from the hydro transaction. $5.2 million increase in depreciation and depletion expense primarily due to plant additions, including approximately $4.1 million of hydro related depreciation. (dollars in millions) Three Months Ended September 30, 2015 2014 Variance Operating, general & admin. $ 79.3 $ 68.1 $ 11.2 16.4% Property and other taxes 35.7 27.8 7.9 28.4% Depreciation and depletion 35.7 30.5 5.2 17.0% Operating Expenses $ 150.7 $ 126.4 $ 24.3 19.2%
Operating to Net Income (Third Quarter) 9 $3.2 million increase in interest expenses was primarily due to increased debt outstanding associated with the hydro transaction. $4.2 million increase in other income due primarily to a $3.5 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation (which has a offsetting increase to operating, general and administrative expenses) and higher capitalization of allowance for funds used during construction (AFUDC). $24.8 million increase in income tax expense due primarily to a $16.9 million benefit in the same period of 2014 and higher pretax income in the current period. The income tax benefit in 2014 included the release of approximately $12.6 million of previously unrecognized tax benefits and a $4.3 million benefit from the election of the safe harbor method related to the deductibility of repair costs. (dollars in millions) Three Months Ended September 30, 2015 2014 Variance Operating Income $ 48.5 $ 31.0 $ 17.5 56.5% Interest Expense (22.0) (18.8) (3.2) 17.0% Other Income/(Expense) 3.8 (0.4) 4.2 (1,050%) Income Before Taxes 30.2 11.8 18.4 156.5% Income Taxes/(Benefit) (6.4) 18.4 (24.8) (134.8%) Net Income $ 23.8 $ 30.2 $ (6.4) (21.2%)
EPS - GAAP to Non-GAAP (‘15 vs ’14) 10
Adjusted Earnings (Third Quarter ‘15 vs ’14) 11 The non-GAAP measures presented in the table above are being shown to reflect significant items that were not contemplated in our original guidance, however they should not be considered a substitute for financial results and measures determined or calculated in accordance with GAAP.
Adjusted Earnings (YTD ‘15 vs ’14) 12 The non-GAAP measures presented in the table above are being shown to reflect significant items that were not contemplated in our original guidance, however they should not be considered a substitute for financial results and measures determined or calculated in accordance with GAAP.
Updated 2015 Earnings Guidance 13 We narrowed the 2015 adjusted earnings guidance range to $3.10 - $3.25 (previously $3.10 - $3.30) per diluted share based upon, but not limited to, the following major assumptions and expectations: • Normal weather in our electric and natural gas service territories for 2015; • Successful integration and a full year earnings contribution from the hydro assets acquired in November 2014; • Excludes any potential additional impact as a result of the FERC decision regarding revenue allocation at our Dave Gates Generating Station; • A consolidated effective income tax rate of approximately 17% to 19% (previously 15% to 19%) of pre-tax income; and • Diluted average shares outstanding of approximately 47.6 million (previously 47.3 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. 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 $2.99 $- $1.50 $1.75 $2.00 $2.25 $2.50 $2.75 $3.00 $3.25 $3.50 2009 2010 2011 2012 2013 2014 2015E GAAP Diluted EPS Initial Guidance Range Non-GAAP "Adjusted" EPS Diluted Earnings Per Share $3.10 - $3.25
Balance Sheet 14
Cash Flow 15 Year-to-date Cash from Operations has increase by $100 million as compared to prior year primarily due to increased income and a reduction in the under collection of supply costs in our trackers.
South Dakota Rate Filing 16 Original Request (Docket EL14-106) $1.8 million revenue benefit recognized in the third quarter 2015 reflects increase for base electric delivery rates only. If the settlement agreement is approved, we anticipate a fourth quarter benefit from the acquisition of the Beethoven wind project (full quarter) and Big Stone air quality control systems (once placed into service, expected December 2015 or January 2016) Three major projects alone account for 96% of the requested $26.5M increase. Big Stone/Neal……..$15.2M Aberdeen Peaker……$7.4M Yankton Substation…$2.8M All other……………...$1.1M Total Request $26.5M In September 2015, we reached a settlement with the SDPUC staff and intervenors providing for an increase in base rates of approximately $20.2 million based on an overall rate of return of 7.24%. In addition, the settlement would allow us to collect approximately $9.0 million annually related to the Beethoven wind project. A hearing is scheduled for October 29th, 2015, and the SDPUC is expected to make a final determination in the case by the end of 2015. We have been collecting interim rates since July 1, 2015, based on our original filing. We are recognizing revenue consistent with the settlement and will refund any amounts overcollected by March 31, 2016. Settlement Agreement
17 Beethoven Wind Acquisition We reached an agreement with the SDPUC staff and intervenors to include $9.0 million of revenue annually into base rates. The commission is expected to make a final determination in the case by the end of 2015. Opportunity: In September 2015, we completed the purchase of the 80 MW Beethoven wind project, near Tripp, South Dakota, for approximately $143 million (subject to customary post closing adjustments) with BayWa r.e. Wind LLC. Prior to the acquisition, the energy and renewable energy credits associated with this 80 MW project were included in the company’s electricity supply portfolio under a Qualifying Facilities (QF) power purchase agreement (PPA). The QF PPA terminated upon closing and we are requesting the project be placed into rate base as part of our pending electric general rate filing as a known and measurable adjustment. The rate-based cost is expected to be lower than the PPA by $44 million ($25 million net present value), benefiting our customers’ bills over the long-term and providing shareholders an investment opportunity. Financing: • $70 million of South Dakota first mortgage bonds in September 2015 at a fixed interest rate of 4.26% maturing in 2040. • Approximately $57 million of equity, completed in October 2015, issuing 1,100,000 shares at $51.81 per share. • Remaining amount funded with available cash and short-term borrowing. Source: BayWa r.e. Wind, LLC Beethoven Wind Red areas in map is NWE’s electric service territory in SD
The Hydro Facilities 18 Overview of Hydro Facilities Black Eagle Despite the 2015 drought conditions in western Montana, the hydro assets have generated at targeted capacity (5 year historical average). Talen Energy’s recently announced sale of 292 MW of hydro generation for $860 million to Brookfield Renewables is significantly higher per MW than the 439 MW of hydro generation we purchased for $870 million. (1) Hydro Asset Integration • Montana Asset Optimization Study: With the acquisition of the hydros, we are modeling different scenarios in an attempt to optimize the integration and operation of our entire generation fleet and determine the most economic means of providing ancillary services. Kerr Dam • Upon the close of the hydro transaction, we assumed temporary ownership of the Kerr Project until it was conveyed to the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) on September 5, 2015, in accordance with the associated FERC license. Our purchase agreement for the hydro transaction included a $30 million reference price for the Kerr Project which was received on the conveyance date. (1) As of June 2013.
19 ‘Clean’ Owned & Contracted Supply Portfolio Base upon nameplate capacity approximately 54% of our total company owned and contracted supply portfolio is renewable or support renewables. Charts above are calculated using nameplate megawatts and include long-term contracts extending beyond 5 years. 25% Renewable 67% Renewable 54% Renewable * DGGS is a 150 MW regulating facility constructed to support the integration of wind generations variability on our system. Being a unique asset, DGGS is included in the above charts at the 7 average megawatts it provides to the energy supply portfolio and not its 150 MW nameplate..
Other Activity 20 • Dave Gates Generating Station (DGGS) • In April 2014, FERC issued a decision to allocate only a fraction of the costs to FERC jurisdictional customers. • In May 2014, we filed a request for rehearing, which remains pending (uncertain on the timeline for FERC to act). • Consistent with the FERC decision, we have deferred $27.3 million of revenue through September 30, 2015. • If unsuccessful in the rehearing, we may appeal to the U.S. Circuit Court of Appeals. • We do not believe an impairment loss is probable at this time; however, we will continue to evaluate as facts and circumstances change. • Big Stone Air Quality Projects • Coal Plant is subject to BART requirements of the Regional Haze Rule. • Must install and operate new system to reduce SO2, NOx and particulate emissions. • Our 23.4% portion of the project cost is $95-105 million. We have capitalized $95.1 million through September 30, 2015. • Expected to be placed into service in December 2015 or January 2016. • Distribution and Transmission System Investment • Distribution (DSIP) and Transmission (TSIP) Infrastructure Project to 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. • Total DSIP and TSIP capital expenditures expected to be approximately $340 million over the next 5 years. • Natural Gas Reserves • We currently own 25% of our Montana natural gas need (for both retail customers and owned gas powered electric generation) with approximately $100 million invested through September 2015. We target to own 50% of this need and estimate we would need to invest up to $100 million to reach our ownership goal.
Capital Spending Forecast 21 Current estimated cumulative capital spending for 2015 through 2019 is $1.45 billion. We anticipate funding the capital projects with a combination of cash flows (aided by NOLs) and long-term debt. If other opportunities arise that are not in the above projections (natural gas reserves, peaking generation, Beethoven, and other acquisitions, etc.), new equity funding may be necessary. * In the chart below, 2015 excludes $143 million of capital related to the Beethoven acquisition completed in September 2015. Appendix
22
23 2014 to 2015 Reconciliation (3rd Qtr & YTD) Appendix
24 Segment Results (Third Quarter) Net Income from our electric segment is approximately $5M better than 2014. This was primarily a result of the addition of hydro offset by income tax benefit in the third quarter of 2014. Also, in our Other segment, we recognized a tax benefit in 2014 from the release of approximately $12.6M of previously unrecognized tax benefits. Appendix
25 Electric Segment (Third Quarter) Appendix
26 Natural Gas Segment (Third Quarter) Appendix
Income Tax Reconciliation (Third Quarter) 27 Appendix
28 Segment Results (YTD thru Qtr 3) YTD the net Income from our electric segment is approximately $24M better than 2014. This was primarily a result of the addition of hydro offset by income tax benefit in the third quarter of 2014. Natural gas is down about $9M compared to 2014, largely due to warmer weather in the first quarter of 2015. Also our Other segment is approximately $8M better in 2015 vs. 2014 larger due to the insurance recovery in Q2 2015 offset by a tax benefit in 2014 from the release of approximately $12.6M of previously unrecognized tax benefits. Appendix
29 Electric Segment (YTD thru Qtr 3) Appendix
30 Natural Gas Segment (YTD thru Qtr 3) Appendix
Income Tax Reconciliation (YTD thru Qtr 3) 31 Appendix
32 Heating and Cooling Degree Days Appendix
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 and depletion 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 33 Appendix