Form 8-K NORTHWESTERN CORP For: Oct 21
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): October 22, 2015
NorthWestern Corporation
(Exact name of registrant as specified in its charter)
Delaware (State or other jurisdiction of incorporation) | 1-10499 (Commission File Number) | 46-0172280 (IRS Employer Identification No.) | ||
3010 W. 69th Street Sioux Falls, South Dakota (Address of principal executive offices) | 57108 (Zip Code) | |||
(605) 978-2900 (Registrant's telephone number, including area code) | ||||
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Item 2.02 | Results of Operations and Financial Condition |
On October 22, 2015, NorthWestern Corporation d/b/a NorthWestern Energy (NYSE: NWE) (the “Company”) issued a press release (the “Press Release”) discussing financial results for the three-month period ended September 30, 2015, and narrowing earnings guidance for 2015 to $3.10 to $3.25 per diluted share from the previously announced range of $3.10 to $3.30 per diluted share. The Press Release is furnished as Exhibit 99.1 hereto and is incorporated herein by reference.
The information in this Current Report on Form 8-K provided under Item 2.02 shall not be deemed “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that Section. The information provided under Item 2.02 in this Current Report shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, as amended, except as shall be expressly set forth by specific reference in such filing.
Item 7.01 Regulation FD Disclosure.
As previously announced and as stated in the Press Release, the Company will host an investor conference call and webcast on October 22, 2015, at 3:30 p.m. Eastern time to review its financial results. During the conference call, Robert C. Rowe, president and chief executive officer, and Brian B. Bird, vice president and chief financial officer of the Company will make a slide presentation (the "Investor Call Presentation") concerning the Company's financial results.
A live webcast of the investor conference call can be accessed from the Company’s website at www.northwesternenergy.com under the "Our Company / Investor Relations / Presentations and Webcasts" heading or by visiting https://www.webcaster4.com/Webcast/Page/1050/10920. To listen and view the slideshow presentation, please go to the site at least 10 minutes in advance of the call to register. An archived webcast will be available shortly after the call and will be available for one year. A telephonic replay of the call will be available for one month beginning at 6:00 p.m. Eastern Time on October 22, 2015, at (888) 203-1112 access code 4283628.
A copy of the Investor Call Presentation is being furnished pursuant to Regulation FD as Exhibit 99.2 to this Current Report on Form 8-K and is incorporated herein by reference. The information in the presentation shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. Furthermore, the presentations shall not be deemed to be incorporated by reference into the Company's filings under the Securities Act of 1933, as amended, or under the Securities Exchange Act of 1934, as amended, except as set forth with respect thereto in any such filing.
Item 9.01 | Financial Statements and Exhibits. |
EXHIBIT NO. | DESCRIPTION OF DOCUMENT |
99.1* | Press Release dated October 22, 2015 |
99.2* | Investor Call Presentation, dated October 22, 2015 |
* filed herewith
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
NORTHWESTERN CORPORATION | |||
By: | /s/ Timothy P. Olson | ||
Timothy P. Olson | |||
Corporate Secretary | |||
Date: October 22, 2015
Index to Exhibits
EXHIBIT NO. | DESCRIPTION OF DOCUMENT |
99.1* | Press Release dated October 22, 2015 |
99.2* | Investor Call Presentation, dated October 22, 2015 |
* filed herewith
NorthWestern Corporation d/b/a NorthWestern Energy 3010 W. 69th Street Sioux Falls, SD 57108 www.northwesternenergy.com |
NYSE: NWE
FOR IMMEDIATE RELEASE
NORTHWESTERN ENERGY REPORTS THIRD QUARTER 2015 FINANCIAL RESULTS
Company reports diluted earnings per share of $0.51 for the third quarter 2015
Narrows full year 2015 guidance to $3.10 - $3.25 per diluted share from the previously announced $3.10 - $3.30
Declares a quarterly dividend of $0.48 per share, payable December 31, 2015
SIOUX FALLS, S.D. - October 22, 2015 - NorthWestern Corporation d/b/a NorthWestern Energy (NYSE: NWE) reported financial results for the quarter ended September 30, 2015. Net income for the quarter was $23.8 million, or $0.51 per diluted share, as compared with net income of $30.2 million, or $0.77 per diluted share, for the same period in 2014. This $6.4 million or 21% decrease in net income is primarily the result of a $16.9 million income tax benefit recognized in the third quarter last year partially offset by income from the November 2014 hydro acquisition. Earnings per share decreased by $0.26 or 34% as a result of the decrease in net income as discussed above and dilution due to the equity issued in November 2014 to fund the hydro acquisition.
Non-GAAP diluted earnings per share for the quarter was $0.51 as compared with $0.38 per diluted share for the same period in 2014. Non-GAAP adjustments reflect the removal of 2014 hydro acquisition related transaction costs and the $16.9 million income tax benefit recognized in the third quarter last year. (For additional information and reconciliation to non-GAAP earnings see "Significant Items Not Contemplated in Guidance" and "Non-GAAP Financial Measures" sections below.)
“We are very pleased with the successful acquisition and financing of the Beethoven Wind Project in South Dakota and reaching a settlement with the South Dakota Public Utilities Commission Staff and intervenors in our first general electric rate case in 34 years in South Dakota. The settlement will be presented to the Commission next week to request their approval. Unfortunately, we also experienced headwinds that caused us to narrow our earnings guidance range toward the lower end of our initial guidance,” said Bob Rowe, President and Chief Executive Officer. “Upward pressure on property and income taxes along with recent regulatory decisions in Montana made it evident that we wouldn’t reach the top end of our initial guidance.”
NorthWestern Reports Third Quarter 2015 Financial Results
October 22, 2015
Page 2
Summary Financial Results
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in thousands, except per share amounts) | 2015 | 2014 | 2015 | 2014 | |||||||||||
Revenues | $ | 272,739 | $ | 251,912 | $ | 889,310 | $ | 891,916 | |||||||
Cost of Sales | 73,577 | 94,592 | 265,495 | 374,494 | |||||||||||
Gross Margin | 199,162 | 157,320 | 623,815 | 517,422 | |||||||||||
Operating, general and administrative expense | 79,296 | 68,108 | 222,139 | 214,557 | |||||||||||
Property and other taxes | 35,712 | 27,773 | 100,953 | 84,292 | |||||||||||
Depreciation and depletion | 35,693 | 30,452 | 107,239 | 91,139 | |||||||||||
Total Operating Expenses | 150,701 | 126,333 | 430,331 | 389,988 | |||||||||||
Operating Income | 48,461 | 30,987 | 193,484 | 127,434 | |||||||||||
Interest Expense, net | (22,043 | ) | (18,794 | ) | (68,101 | ) | (57,887 | ) | |||||||
Other Income/(Expense) | 3,769 | (439 | ) | 5,429 | 4,730 | ||||||||||
Income Before Income Taxes | 30,187 | 11,754 | 130,812 | 74,277 | |||||||||||
Income Tax (Expense)/Benefit | (6,389 | ) | 18,437 | (24,616 | ) | 9,240 | |||||||||
Net Income | $ | 23,798 | $ | 30,191 | $ | 106,196 | $ | 83,517 | |||||||
Average Common Shares Outstanding | 47,065 | 39,141 | 47,029 | 39,046 | |||||||||||
Basic Earnings per Average Common Share | $ | 0.51 | $ | 0.77 | $ | 2.26 | $ | 2.14 | |||||||
Diluted Earnings per Average Common Share | $ | 0.51 | $ | 0.77 | $ | 2.25 | $ | 2.13 | |||||||
Dividends Declared per Common Share | $ | 0.48 | $ | 0.40 | $ | 1.44 | $ | 1.20 | |||||||
Significant items during the quarter include:
• | Completed the purchase of the 80 MW Beethoven wind project near Tripp, South Dakota, for approximately $143 million (subject to customary post closing adjustments). We financed the Beethoven wind project acquisition with a combination of $70 million of South Dakota first mortgage bonds, approximately $57 million of equity and the remainder with short-term borrowings. The $70 million of South Dakota first mortgage bonds were issued in September 2015 at a fixed interest rate of 4.26% maturing in 2040. The equity transaction was completed in October 2015 through the issuance of 1,100,000 shares of our common stock at $51.81 per share. |
• | Reached a settlement in our South Dakota electric rate filing 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, if approved by the SDPUC, the settlement will allow us to collect approximately $9.0 million annually related to the Beethoven wind project. |
Significant Earnings Drivers
Gross Margin
Consolidated gross margin for the three months ended September 30, 2015 was $199.1 million compared with $157.3 million for the same period in 2014. The $41.8 million increase was primarily due to:
• | $40.4 million increase in generation margin from the hydro acquisition; |
• | $1.8 million increase in South Dakota electric rates implemented on an interim basis in July 2015; |
• | $1.3 million increase in property taxes included in trackers; and |
• | $1.1 million increase in electric retail volumes due primarily to customer growth in the residential and commercial categories. |
NorthWestern Reports Third Quarter 2015 Financial Results
October 22, 2015
Page 3
These increases were partially offset by:
• | $0.9 million lower demand to transmit energy across our transmission lines due to market pricing and other conditions; |
• | $0.5 million decrease in natural gas residential and commercial retail volumes; |
• | $0.4 million deferral of initial interim gas production rate revenue based on actual costs in accordance with the final order in the natural gas consolidated 2013/2014 and 2012/2013 tracker docket received in October 2015; and |
• | $1.0 million decrease in all other miscellaneous margin. |
Consolidated gross margin for the nine months ended September 30, 2015 was $623.8 million compared with $517.4 million for the same period of 2014.
Operating, General and Administrative Expenses
Consolidated operating, general and administrative expenses for the three months ended September 30, 2015 were $79.3 million compared with $68.1 million for the same period in 2014. The $11.2 million increase was primarily due to:
• | $10.8 million hydro operating costs associated with the November 2014 hydro transaction; and |
• | $3.5 million decrease in non-employee directors deferred compensation as compared to the prior year, primarily due to an increase in our stock price during the three months ended September 30, 2015. Directors may defer their board fees into deferred shares held in a rabbi trust. If the market value of our stock goes up, deferred compensation expense increases; however, we account for the deferred shares as trading securities and their change in value is also reflected in other income with no impact on net income. |
These increases were partly offset by:
• | $0.6 million lower legal and professional fees due to hydro transaction costs incurred in the prior period; |
• | $0.5 million lower bad debt expense, due to improved collection of receivable from customers; and |
• | $2.0 million decreased miscellaneous other expense. |
Consolidated operating, general and administrative expenses for the nine months ended September 30, 2015 was $222.1 million compared with $214.6 million for the same period of 2014.
Property and Other Taxes
Property and other taxes were $35.7 million for the three months ended September 30, 2015, as compared with $27.8 million in the same period of 2014. This increase was primarily due to plant additions and higher estimated property valuations in Montana, which includes an estimated $6.4 million from the hydro acquisition. We estimate property taxes throughout each year and update to the actual expense when we receive our Montana property tax bills in November.
Property and other taxes for the nine months ended September 30, 2015 were $101.0 million compared with $84.3 million for the same period of 2014.
NorthWestern Reports Third Quarter 2015 Financial Results
October 22, 2015
Page 4
Depreciation and Depletion Expense
Depreciation and depletion expense was $35.7 million for the three months ended September 30, 2015, as compared with $30.5 million in the same period of 2014. This increase was primarily due to plant additions, including approximately $4.1 million of depreciation related to the hydro acquisition.
Depreciation and depletion expense for the nine months ended September 30, 2015 was $107.2 million compared with $91.1 million for the same period of 2014.
Operating Income
Consolidated operating income for the three months ended September 30, 2015 was $48.5 million, as compared with $31.0 million in the same period of 2014. This increase was primarily due to the impacts of our hydro acquisition.
Consolidated operating income for the nine months ended September 30, 2015 was $193.5 million compared with $127.4 million for the same period of 2014.
Interest Expense
Consolidated interest expense for the three months ended September 30, 2015 was $22.0 million, as compared with $18.8 million in the same period of 2014. This increase was primarily due to increased debt outstanding associated with the hydro acquisition.
Consolidated interest expense for the nine months ended September 30, 2015 was $68.1 million compared with $57.9 million for the same period of 2014.
Other Expense and Income
Consolidated other income for the three months ended September 30, 2015, was $3.8 million, as compared with an expense of $0.4 million in the same period of 2014. This increase was primarily due to a $3.5 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation (which, as discussed above, had a corresponding increase to operating, general and administrative expenses) and higher capitalization of allowance for funds used during construction.
Consolidated other income for the nine months ended September 30, 2015 was $5.4 million compared with $4.7 million for the same period of 2014.
Income Tax
Consolidated income tax expense for the three months ended September 30, 2015 was $6.4 million, as compared with an income tax benefit of $18.4 million in the same period of 2014. Our effective tax rate for the three months ended September 30, 2015 was 21.2% as compared with (156.9)% for the same period in 2014. The income tax benefit in 2014 included the release of approximately $12.6 million of previously unrecognized tax benefits due to the lapse of statutes of limitation in the third quarter of 2014. In addition, during the third quarter of 2014, we elected the safe harbor method related to the deductibility of repair costs. This resulted in an income tax benefit of approximately $4.3 million for the cumulative adjustment for years prior to 2014, which is included in the prior year permanent return to accrual adjustments. We currently expect our effective tax rate to range between 17%-19% for 2015.
NorthWestern Reports Third Quarter 2015 Financial Results
October 22, 2015
Page 5
We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. The following table summarizes the differences between our effective tax rate and the federal statutory rate:
(in millions) | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||||||||||||
Income Before Income Taxes | $ | 30.2 | $ | 11.8 | $ | 130.8 | $ | 74.3 | |||||||||||||||||
Income tax calculated at 35% federal statutory rate | 10.6 | 35.0 | % | 4.1 | 35.0 | % | 45.8 | 35.0 | % | 26.0 | 35.0 | % | |||||||||||||
Permanent or flow-through adjustments: | |||||||||||||||||||||||||
State income, net of federal provisions | (0.9 | ) | (2.8 | )% | (0.1 | ) | (0.9 | )% | (0.3 | ) | (0.3 | )% | 0.3 | 0.3 | % | ||||||||||
Release of unrecognized tax benefit | — | — | % | (12.6 | ) | (107.3 | )% | — | — | % | (12.6 | ) | (17.0 | )% | |||||||||||
Prior year permanent return to accrual adjustments | 1.0 | 3.4 | % | (5.2 | ) | (44.0 | )% | 1.0 | 0.8 | % | (5.2 | ) | (7.0 | )% | |||||||||||
Flow-through repairs deductions | (2.8 | ) | (9.2 | )% | (3.4 | ) | (29.0 | )% | (17.2 | ) | (13.2 | )% | (14.9 | ) | (20.0 | )% | |||||||||
Production tax credits | (0.7 | ) | (2.4 | )% | (0.3 | ) | (2.6 | )% | (2.6 | ) | (2.0 | )% | (2.1 | ) | (2.8 | )% | |||||||||
Plant and depreciation of flow-through items | (0.4 | ) | (1.2 | )% | (0.7 | ) | (5.8 | )% | (1.0 | ) | (0.8 | )% | (0.2 | ) | (0.2 | )% | |||||||||
Other, net | (0.4 | ) | (1.6 | )% | (0.2 | ) | (2.3 | )% | (1.1 | ) | (0.7 | )% | (0.5 | ) | (0.7 | )% | |||||||||
Subtotal | (4.2 | ) | (13.8 | )% | (22.5 | ) | (191.9 | )% | (21.2 | ) | (16.2 | )% | (35.2 | ) | (47.4 | )% | |||||||||
Income tax expense | $ | 6.4 | 21.2 | % | $ | (18.4 | ) | (156.9 | )% | $ | 24.6 | 18.8 | % | $ | (9.2 | ) | (12.4 | )% | |||||||
Net Income
Consolidated net income for the three months ended September 30, 2015 was $23.8 million as compared with $30.2 million for the same period in 2014. This decrease was primarily due to an income tax benefit included in our 2014 results due to the release of previously unrecognized tax benefits, partly offset by the favorable impacts of our hydro acquisition.
Consolidated net income for the nine months ended September 30, 2015 was $106.2 million as compared with $83.5 million for the same period in 2014.
NorthWestern Reports Third Quarter 2015 Financial Results
October 22, 2015
Page 6
Reconciliation of Primary Changes from 2014 to 2015
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
Pre-tax | Net | Diluted | Pre-tax | Net | Diluted | ||||||||||
($millions, except EPS) | Income | Income(1) | EPS | Income | Income(1) | EPS | |||||||||
2014 reported | $11.8 | $30.2 | $0.77 | $74.3 | $83.5 | $2.13 | |||||||||
Gross Margin | |||||||||||||||
Hydro operations | 40.4 | 24.8 | 0.52 | 120.8 | 74.3 | 1.57 | |||||||||
So. Dakota electric interim rate increase (subject to refund) | 1.8 | 1.1 | 0.02 | 1.8 | 1.1 | 0.02 | |||||||||
Property tax tracker | 1.3 | 0.8 | 0.02 | 2.3 | 1.4 | 0.03 | |||||||||
Electric retail volumes | 1.1 | 0.7 | 0.01 | (1.7 | ) | (1.0 | ) | (0.02 | ) | ||||||
Electric transmission capacity | (0.9 | ) | (0.6 | ) | (0.01 | ) | — | — | — | ||||||
Natural gas retail volumes | (0.5 | ) | (0.3 | ) | (0.01 | ) | (8.7 | ) | (5.4 | ) | (0.11 | ) | |||
Gas production deferral | (0.4 | ) | (0.2 | ) | — | (1.6 | ) | (1.0 | ) | (0.02 | ) | ||||
Electric QF adjustment | — | — | — | (4.3 | ) | (2.6 | ) | (0.06 | ) | ||||||
Operating expense recovered in trackers | — | — | — | (1.4 | ) | (0.9 | ) | (0.02 | ) | ||||||
Other | (1.0 | ) | (0.6 | ) | (0.01 | ) | (0.9 | ) | (0.6 | ) | (0.01 | ) | |||
Subtotal - Gross Margin | 41.8 | 25.7 | 0.54 | 106.3 | 65.3 | 1.38 | |||||||||
OG&A Expense | |||||||||||||||
Hydro Operations | (10.8 | ) | (6.6 | ) | (0.14 | ) | (32.7 | ) | (20.1 | ) | (0.43 | ) | |||
Non-employee directors deferred compensation | (3.5 | ) | (2.2 | ) | (0.05 | ) | 1.4 | 0.9 | 0.02 | ||||||
Bad debt expense | 0.5 | 0.3 | 0.01 | 3.3 | 2.0 | 0.04 | |||||||||
Hydro transaction costs | 0.6 | 0.4 | 0.01 | 2.3 | 1.4 | 0.03 | |||||||||
Employee benefit and compensation costs | — | — | — | (3.6 | ) | (2.2 | ) | (0.05 | ) | ||||||
Insurance recovery, net | — | — | — | 20.8 | 12.8 | 0.27 | |||||||||
Operating expense recovered in trackers | — | — | — | 1.4 | 0.9 | 0.02 | |||||||||
Other | 2.0 | 1.2 | 0.03 | (0.4 | ) | (0.2 | ) | — | |||||||
Subtotal - OG&A Expense | (11.2 | ) | (6.9 | ) | (0.14 | ) | (7.5 | ) | (4.5 | ) | (0.10 | ) | |||
Other items | |||||||||||||||
Depreciation and depletion expense | (5.2 | ) | (3.2 | ) | (0.07 | ) | (16.1 | ) | (9.9 | ) | (0.21 | ) | |||
Property and other taxes | (7.9 | ) | (4.9 | ) | (0.10 | ) | (16.7 | ) | (10.3 | ) | (0.22 | ) | |||
Interest expense | (3.2 | ) | (2.0 | ) | (0.04 | ) | (10.2 | ) | (6.3 | ) | (0.13 | ) | |||
Other income (incl. offset to non-employee deferred comp above) | 4.2 | 2.6 | 0.05 | 0.7 | 0.4 | 0.01 | |||||||||
Permanent and flow-through adjustments to income tax | (17.7 | ) | (0.37 | ) | (12.0 | ) | (0.25 | ) | |||||||
Impact of higher share count | — | — | (0.13 | ) | — | — | (0.36 | ) | |||||||
Subtotal - Other items | (12.1 | ) | (25.2 | ) | (0.66 | ) | (42.3 | ) | (38.1 | ) | (1.16 | ) | |||
Total impact of above items | 18.4 | (6.4 | ) | (0.26 | ) | 56.5 | 22.7 | 0.12 | |||||||
2015 reported | $30.2 | $23.8 | $0.51 | $130.8 | $106.2 | $2.25 | |||||||||
(1) Income Tax Benefit (Expense) calculation on reconciling items assumes effective tax rate of 38.5%. | |||||||||||||||
Liquidity and Capital Resources
As of September 30, 2015, our total net liquidity was approximately $142.2 million, including $10.1 million of cash and $132.1 million of revolving credit facility availability. This compares to total net liquidity at December 31, 2014 of $102.5 million.
Dividend Declared
NorthWestern's Board of Directors declared a quarterly common stock dividend of $0.48 per share, payable December 31, 2015 to common shareholders of record as of December 15, 2015.
NorthWestern Reports Third Quarter 2015 Financial Results
October 22, 2015
Page 7
Significant Items Not Contemplated in Guidance
A reconciliation of items not factored into our updated 2015 and final 2014 earnings guidance of $3.10 - $3.25 and $2.60 - $2.75 per diluted share, respectively, are summarized below. The amount below represents an after-tax (using a 38.5% effective tax rate) non-GAAP measure that may provide users of this financial information with additional meaningful information regarding the impact of certain items on our expected earnings. More information on this measure can be found in the "Non-GAAP Financial Measures" section below.
ESTIMATED TO MEET GUIDANCE | |||||||||||||
2015 | Q1 '15 | Q2 '15 | Q3 '15 | YTD '15 | Q4 '15 | Full Year '15 | |||||||
Low | High | Low | High | ||||||||||
Reported GAAP diluted EPS | $1.09 | $0.65 | $0.51 | $2.25 | $0.93 | $1.08 | $3.18 | $3.33 | |||||
Non-GAAP Adjustments: | |||||||||||||
Weather - unfavorable | 0.09 | 0.02 | — | 0.11 | ? | 0.11 | |||||||
Insurance settlement | — | (0.27 | ) | — | (0.27 | ) | ? | (0.27) | |||||
QF liability adjustment | — | 0.08 | — | 0.08 | ? | 0.08 | |||||||
Adjusted diluted EPS | $1.18 | $0.48 | $0.51 | $2.17 | $0.93 | $1.08 | $3.10 | $3.25 | |||||
2014 | Q1 '14 | Q2 '14 | Q3 '14 | YTD '14 | Q4 '14 | Full Year '14 | |||||||
Reported GAAP diluted EPS | $1.17 | $0.20 | $0.77 | $2.13 | $0.85 | $2.99 | |||||||
Non-GAAP Adjustments: | |||||||||||||
Weather (favorable) / unfavorable | (0.05 | ) | 0.01 | — | (0.04 | ) | 0.02 | (0.02) | |||||
Hydro transaction (prof. fees & bridge financing) | 0.04 | 0.04 | 0.04 | 0.12 | 0.12 | 0.24 | |||||||
Hydro operations (Nov.18 - Dec. 31) | — | — | — | — | (0.14) | (0.14) | |||||||
Hydro equity dilution (1) | — | — | — | — | 0.08 | 0.08 | |||||||
Income tax adjustments (2) | — | — | (0.43 | ) | (0.43 | ) | (0.04) | (0.47) | |||||
Adjusted diluted EPS | $1.16 | $0.25 | $0.38 | $1.78 | $0.89 | $2.68 | |||||||
1) 2014 Guidance excluded all earnings impacts from the hydro acquisition (transaction expense and income from operations) and assumed 39.3 million diluted shares outstanding (i.e. our share count absent the shares issued in November 2014 to fund the hydro acquisition). | |||||||||||||
2) Adjustment to income tax expense to remove the flow through benefit related to the release of unrecognized tax benefits, 2014 bonus depreciation (bonus benefit was a current year item but not originally contemplated in guidance) and other tax items related to prior years. | |||||||||||||
2015 Earnings Guidance Updated
NorthWestern's updated the 2015 adjusted earnings guidance range of $3.10 - $3.25 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; |
• | 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%-19% (previously 15%-19%) of pre-tax income; and |
• | Diluted average shares outstanding of approximately 47.6 million (previously 47.3 million). |
NorthWestern Reports Third Quarter 2015 Financial Results
October 22, 2015
Page 8
Company Hosting Investor Conference Call
NorthWestern will host an investor conference call and webcast today, October 22, at 3:30 pm Eastern Time to review its financial results. The conference call will be webcast live on the Internet at http://www.northwesternenergy.com under the “Our Company / Investor Relations / Presentations and Webcasts” heading or by visiting www.webcaster4.com/Webcast/Page/1050/10920. To listen, please go to the site at least 10 minutes in advance of the call to register. An archived webcast will be available shortly after the call and will be available for one year.
A telephonic replay of the call will be available for one month beginning at 6:00 p.m. Eastern today at (888) 203-1112 access code 4283628.
About NorthWestern Energy
NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 692,600 customers in Montana, South Dakota and Nebraska. More information on NorthWestern Energy is available on the Company's website at www.northwesternenergy.com.
Non-GAAP Financial Measures
This press release includes 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.
Special Note Regarding Forward-Looking Statements
This press release contains forward-looking statements within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, including, without limitation, the information under "Significant Items Not Contemplated in Guidance" and “2015 Earnings Guidance Updated”. 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.” These statements are based upon our current expectations and speak only as of the date hereof. Our actual future business and financial performance may differ materially and adversely from those expressed in any forward-looking statements as a result of various factors and uncertainties, including, but not limited to:
NorthWestern Reports Third Quarter 2015 Financial Results
October 22, 2015
Page 9
• | adverse determinations by regulators, as well as potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, could have a material effect on our liquidity, results of operations and financial condition; |
• | changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations; |
• | unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase cost of sales or may require additional capital expenditures or other increased operating costs; and |
• | adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories. |
Our 2014 Annual Report on Form 10-K, third quarter 2015 and forthcoming Quarterly Reports on Form 10-Q, recent reports on Form 8-K and other Securities and Exchange Commission filings discuss some of the important risk factors that may affect our business, results of operations and financial condition. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Investor Relations Contact:
Travis Meyer (605) 978-2967
[email protected]
[email protected]
Media Contact:
Claudia Rapkoch (866) 622-8081
[email protected]
[email protected]
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