8-K March 21, 2018
Williams Capital - West Coast Utilities Conference
March 21-22, 2018
Sunrise - Anaconda, MT
2
Forward Looking Statements
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 most recent Form 10-K and 10-Q
along with other public filings with the SEC.
NorthWestern Corporation
dba: NorthWestern Energy
Ticker: NWE
Trading on the NYSE
www.northwesternenergy.com
Corporate Office
3010 West 69th Street
Sioux Falls, SD 57108
(605) 978-2900
Investor Relations Officer
Travis Meyer
605-978-2967
travis.meyer@northwestern.com
Company Information
About NorthWestern
3
Montana Operations
Electric
369,100 customers
24,495 miles – transmission & distribution lines
809 MW nameplate owned power generation
Natural Gas
196,700 customers
7,287 miles of transmission and distribution pipeline
17.75 Bcf of gas storage capacity
Own 55.9 Bcf of proven natural gas reserves
Nebraska Operations
Natural Gas
42,400 customers
790 miles of distribution pipeline
South Dakota Operations
Electric
63,600 customers
3,560 miles – transmission & distribution lines
440 MW nameplate owned power generation
Natural Gas
46,500 customers
1,681 miles of transmission and distribution pipeline
Data as of 12/31/2017
NWE - An Investment for the Long Term
4
• 100% regulated electric & natural gas utility business
with over 100 years of operating history
• Solid economic indicators in service territory
• Diverse electric supply portfolio ~56% hydro & wind
Black Eagle dam
Pure Electric &
Gas Utility
Solid Utility
Foundation
Strong
Earnings &
Cash Flow
Attractive
Future Growth
Prospects
Financial Goals
& Metrics
Best Practices
Corporate
Governance
• Residential electric & gas rates below national average
• Solid system reliability (EEI 2nd quartile)
• Low leaks per 100 miles of pipe (AGA 1st quartile)
• Solid JD Power Overall Customer Satisfaction scores
• Disciplined maintenance capital investment program to ensure safety and reliability
• Significant investment in renewable resources (hydro & wind) will provide long-term
energy supply pricing stability for the benefit of customers for many years to come
• Further opportunity for energy supply investment to meet significant capacity shortfalls
• Consistent track record of earnings & dividend growth
• Strong cash flows aided by net operating loss carry-
forwards anticipated to be available into 2020
• Strong balance sheet & investment grade credit ratings
• Debt to total capitalization ratio of 50%-55% with liquidity of $100 million or greater
• Targeted 6%-9% long-term total shareholder return (eps growth plus dividend yield)
• Targeted dividend payout ratio of 60%-70%
A Diversified Electric and Gas Utility
5
NorthWestern’s ‘80/20’ rules:
Approximately 80% Electric, 80% Residential and 80% Montana
Over $3.5 billion of rate base investment to serve our customersData as of 12/31/2017.
6
Highly Carbon-Free Supply Portfolio
Based upon 2017 MWH’s of owned and long-term
contracted resources. Approximately 56% of our total
company owned and contracted supply is carbon-free.
NorthWestern does not own all the renewable energy certificates (RECs) generated by
contracted wind, and periodically sells its own RECs with proceeds benefiting retail
customers. Accordingly, we cannot represent that 100% of carbon-free energy in the
portfolio was delivered to our customers.
Strong Utility Foundation
7
Solid and improving JD Power Overall Customer Satisfaction Scores
Residential electric and natural gas rates below national average
Solid electric system reliability and low gas leaks per mile
Solid Economic Indicators
8
• Customer growth rates historically exceed National Averages.
• Unemployment rates in all three of our states are meaningfully below National Average.
Source: NorthWestern customer growth - 2008-2016 Forms 10-K
Unemployment Rate: US Department of Labor via SNL Database 2/21/17
Electric: EEI Statistical Yearbook (published December 2015, table 7.2)
Natural Gas: EIA.gov (Data table "Number of Natural Gas Consumers")
Source: Company 10K’s, 2015/2016 EEI Statistical Yearbook – Table 7.2 and EIA.gov
Black Eagle Power House
A History of Growth
9
2008-2017 CAGR’s: GAAP EPS: 7.3% - Non-GAAP EPS: 6.8% - Dividend: 5.3%
See appendix for “Non-GAAP Financial Measures”
$2.60 - $2.75
$3.10 - $3.30
$3. 0-$3.40
$3.30-$3.50
Track Record of Delivering Results
10
Return on Equity on GAAP Earnings within 9.5% - 11.0% band over the last 6 years with average of 9.9%.
See appendix for “Non-GAAP Financial Measures”
Total Shareholder Return is better than our 13 peer average for the 10 year period
but lags in the 1, 3 & 5 year periods, due primarily to concerns over Montana regulatory decisions.
* Peer Group: ALE, AVA, BKH, EE, GXP, IDA, MGEE, OGE, OTTR, PNM, POR, VVC, WR
Investment for Our Customers’ Benefit
11
Over the past 8 years we have been reintegrating our Montana energy supply portfolio and making additional investments across
our entire service territory to enhance system safety, reliability and capacity.
We have made these enhancements with minimal impact to customers’ bills while maintaining bills lower than the US average.
As a result we have also been able to deliver solid earnings growth for our investors.
2008-2017 CAGRs Estimated Rate Base: 13.3% GAAP Diluted EPS: 7.3%
2008-2017 CAGRs NWE typical electric bill: 2.1% NWE typical natural gas bill: (6.1%)
2008-2016 CAGRs US average electric bill: 1.7%* US average natural gas bill: (4.0%)**
Balance Sheet Strength and Liquidity
12
Investment grade credit ratings, generally liquidity in excess of $100 million target,
and debt to cap within our targeted 50%-55% range.
In early November 2017, we redeemed $250 million, 6.34% Montana First Mortgage Bonds
(MFMB) due in 2019 with the issuance of $250 million of MFMB
at a fixed rate of 4.03% maturing in 2047.
While maintenance capex and total dividend payments have continued to grow since 2011 (12.9% and 13.0% CAGR
respectively), Cash Flow from Operations (CFO) has, on average, exceeded maintenance capex and dividend payments by
approximately $24 million per year. 2016 CFO is less than 2015 largely due to $30.8M refund to customers related to FERC/DGGS ruling and
$7.2M refund to customers for difference in SD Electric interim & final rates.
With the addition of production tax credits from the Beethoven Wind project and continued flow-through tax benefits, we
anticipate our effective tax rate approaching 10% by 2022.
Additionally, we expect NOLs to be available into 2020, and Alternative Minimum Tax credits (ATM) / Production Tax Credits (PTC)
to be available into 2022 to reduce cash taxes.
(See appendix for “Non-GAAP Financial Measures” relating to free cash flow and disclaimer on NOL’s)
Strong Cash Flows
13
Experienced Leadership & Solid Corp. Governance
14
Board of Directors (left to right)
Executive Management Team (left to right)
Linda G. Sullivan – Independent Director since April 27, 2017 – Audit Committee
Dana J. Dykhouse – Independent Director since January 30, 2009 – Human
Resources (chair) and Audit Committees
Britt E. Ide – Independent Director since April 27, 2017 – Governance &
Innovation Committee
Jan R. Horsfall – Independent Director since April 23, 2015 – Audit and Governance &
Innovation Committees
Anthony T. Clark – Independent Director since December 6, 2016 – Governance &
Innovation Committee
Robert C. Rowe - CEO & President – Director since August 13, 2008
Dr. E. Linn Draper Jr. -Chairman of the Board – Independent Director since
November 1, 2004
Julia L. Johnson – Independent Director since November 1, 2004 – Governance &
Innovation (chair) and Human Resources Committees
Stephan P. Adik – Independent Director since November 1, 2004 – Audit (chair) and
Human Resources Committees
Patrick R. Corcoran – VP Gov’t & Regulatory Affairs – retired January 2018
Crystal D. Lail – VP & Controller – current position since 2015
Curtis T. Pohl – VP Distribution – current position since 2003
Bobbi L. Schroeppel – VP Customer Care, Communications & Human Resources –
current position since 2002
Brian B. Bird – VP & CFO – current position since 2003
Heather H. Grahame – VP & General Counsel – current position since 2010
Robert C. Rowe - President & CEO – current position since 2008
John D. Hines – VP Supply – current position since 2011
Michael R. Cashell – VP Transmission – current position since 2011
Strong year for safety at NorthWestern
• Continue to be a top performer among Edison Electric
Institute member companies.
Record best customer satisfaction scores
with JD Power & Associates
• Once again received our best JD Powers overall
satisfaction survey score in 2017.
Corporate Governance Finalist
• In 2017 NorthWestern’s proxy statement was again
recognized as a finalist for “Best Proxy Statement
(Small to Mid Cap)” by Corporate Secretary
Magazine. We won the award in 2014.
Board Diversity Recognition
• Recognized for gender diversity on its
board of directors by 2020 Women on
Boards. Three of the company’s eight
independent directors are female.
Second Annual Environmental Report
• Published in December 2017, this report highlights
our commitment to the stewardship of natural
resources and our sustainable business practices.
Recent Significant Achievements
15
Echo Lake Nordic Trail
Looking Forward
16
Regulatory
• Regulatory treatment of tax reform - determine best way
to provide long-term benefit to customers and system
while keeping investors ‘whole’.
• Working toward successful implementation of new
Power Cost and Credit Adjustment Mechanism
• Anticipate filing an electric rate case by September 2018
(based on a 2017 test year).
Cost Control Efforts
• Continue to monitor costs, including labor, benefits and
property tax valuations to mitigate increases
Continue to Invest in our T&D infrastructure
• Transition from DSIP/TSIP to overall infrastructure
capital investment plan
• Natural gas pipeline investment (Integrity Verification
Process and PHMSA1 Requirements)
• Grid modernization, advanced distribution management
system and advanced metering infrastructure investment
Update Electricity Resource Procurement Plans in Montana & South Dakota
• Montana: Least cost / lowest risk approach to address intermittent capacity and reserve margin needs
• South Dakota: Generation fleet assessment to evaluate economic retirement / replacement opportunities
Natural Gas Reserve Acquisition Opportunities
• Acquisitions at a price that benefits both customers and shareholders
1. Pipeline & Hazardous Materials Safety Administration (PHMSA)
Much of our focus in the next year will be on
the electric rate case in Montana and
controlling our costs to benefit all
stakeholders while continuing to invest in
our core business to provide safe and
reliable energy for our all of our
customers.
Black Eagle Power House
Financing Activities
17
Big Sky Substation
Long-Term Debt Refinancing
• In October 2017, we priced $250 million
principal, 4.03% - 30 year Montana First
Mortgage Bonds
• We closed the transaction in early
November 2017.
• Proceeds used to redeem existing
$250 million – 6.34% Montana First
Mortgage Bonds due in 2019
$100 million At-The-Market
Equity Distribution Program
• Initiated in September 2017
• Proceeds to repay or refinance debt (including
short-term debt), fund capital expenditures
and other general corporate purposes
• During the third & fourth quarters of 2017
we sold 888,938 shares of common stock
at an average price of $60.68 per share, for
a total of approximately $54 million of
proceeds.
Expect annual interest expense savings of
over $5 million net of make-whole
amortization
We anticipate issuing the remaining $46 million
under the current distribution agreement by the
end of 2018.
18
Regulatory & Legal Update
Montana Property Tax Tracker Filing
• On January 29th the MPSC issued an order in our 2017 property tax tracker filing by further reducing our recovery of Montana
property taxes by a total of $3.5 million impacting both 2017 and 2018 (approximately $1.75 million each year). This change
was a result of applying an alternate allocation methodology that lowers the property tax allocation to our electric retail
customers (with a higher allocation to FERC customers for which we do not have a tracking mechanism).
• On February 8th we filed a motion for reconsideration with the MPSC. We expect a decision by the end of March 2018.
Tax Cuts and Jobs Act
• The MPSC and SDPUC have initiated dockets to determine the impacts of tax reform and have requested proposals for how to
apply the benefits, starting January 1, 2018 resulting from the change in law.
• We filed our initial proposal with the SDPUC in January (with an additional filing due in March) and will make a
comprehensive filing with the MPSC by the end of March.
Power Cost and Credit Adjustment Mechanism (PCCAM)
• In April 2017, the Montana legislature passed House Bill 193, amending the statute that provided for mandatory recovery of our
prudently incurred electric supply costs. The revised statute gives the MPSC additional discretion. The MPSC initiated a
process to develop a replacement mechanism. In July 2017 we filed a proposed electric PCCAM that was in line with
commissioner testimony provided to the legislature in support of HB193. Intervenor testimony was filed in November 2017. In
December 2017 the MPSC issued a Notice of Additional Issues stating that the range of options proposed by the parties was
not sufficient and directed parties to consider alternatives incorporating risk-sharing features.
• On February 7th we filed rebuttal testimony and addressed the MPSC’s additional issues. Intervenor additional issues
testimony is due March 23rd and a hearing is scheduled to begin May 31, 2018.
• The MPSC decision may apply to variable costs on a retroactive basis to July 1, 2017 (the effective date of HB193).
FERC / Dave Gates Generation Station (DGGS)
• We received an order from FERC in April 2014 regarding DGGS cost allocation between retail & wholesale customers.
• FERC denied our request for rehearing in May 2016 and required us to make refunds in June 2016 totaling $30.8 million.
• We filed a petition for review with the US Circuit Court of Appeals for the District of Columbia Circuit in June 2016 and oral
argument was held on December 1, 2017. We expect a decision by the end of the second quarter of 2018.
Colstrip Unit 4 - Disallowance of Replacement Power Costs
• In May 2016, the MPSC issued a final order disallowing recovery of certain costs related to a 2013 outage at Colstrip.
• In September 2016 we appealed the order to the Montana District Court arguing the decision was arbitrary and capricious and
violated Montana law. We expect a decision on this appeal within the next 12 months.
19
Estimated Impacts of the Tax Cuts & Jobs Act
Tax reform had no impact on our net income in 2017. As a result of
the reduction in the federal corporate tax rate, we reduced our
deferred tax liability by approximately $321 million. This reduction
was offset in regulatory assets and liabilities.
• Our current electric and gas rates are expected to
remain unchanged until recalculated in our next
general rate proceedings.
• However, dockets have been initiated in Montana and
South Dakota to provide the income tax benefit to
customers effective January 1st.
• As a result, we began deferring the recognition of
revenue (estimated to be $15-20 million in 2018 on a
consolidated basis) into a regulatory liability account.
The reduction in revenue recognized is anticipated to
be offset by an equal reduction in income tax expense
- with no impact to net income.
• Utilization of the deferred revenue (regulatory liability)
will be determined in the pending dockets.
• As a result of tax reform, we are updating our effective
tax rate assumption included in 2018 guidance to
0% - 5% (previously 8% - 12%). NOLs are now
anticipated to be available into 2020 (previously 2021).
• We currently believe our debt coverage ratios will be
adequate to maintain existing credit ratings. However,
further negative regulatory actions will likely lead to
credit downgrades.
The illustration above is based on current consolidated company
estimates. Actual impact will ultimately be subject to regulatory approval.
The $15-$20 million range shown includes $2-$4 million of annual amortization of excess
deferred taxes subject to the average rate assumption method (ARAM).
Critical Capacity Shortfall
20
NorthWestern’s current planning reserve margin is negative 28%
and projected to grow to negative 50% by 2035 without the addition of
incremental owned or contracted portfolio resources.
• The resource initiatives and actions developed in our
Montana 2015 Electricity Resource Procurement
Plan (ERPP) identify the critical future needs of our
portfolio, including solutions to resolve our current
negative planning reserve margin.
• On February 7, 2018 we terminated a competitive
solicitation process for up to 150 MW of dispatchable
generation as a result of a July 2017 decision by the
MPSC regarding maximum 15 year contract length
for all new generation. On December 22, 2017 we
filed a petition for judicial review of this decision in
Montana District Court, primarily based on the
Commission’s violation of Montana Administrative
Procedures Act (MAPA).
• The 2018 ERPP, expected by December, will
address issues raised by the MPSC and will identify
the lowest-cost / least-risk approach for addressing
our intermittent capacity and reserve margin needs
in Montana.
Capital Spending Forecast
21
The updated current estimated cumulative 5 year capital spending for is $1.596 billion
(previously $1.582 billion).
We anticipate funding the expenditures with a combination of cash flows (aided by NOLs available into
2020), the remainder of our current equity distribution program and long-term debt issuances.
If other significant opportunities arise that are not in the above projections,
additional equity funding may be necessary.
2018 Significant Updates
Out: Approximately $123 million of
previously included investment in
capacity generation has been
removed pending update of
Integrated Resource Plans in both
Montana and South Dakota
(expected to be completed by
year-end 2018).
In: Approximately $126 million of
incremental investment related to
grid modernization and automated
meter infrastructure for Montana.
South Dakota and Nebraska AMI
investment spend was previously
included ($28M).
2018 Earnings Guidance
22
See appendix for additional disclosures regarding “Non-GAAP Financial Measures”
$2.60 - $2.75
$3.10 - $3.30
$3.30-$3.45
NorthWestern’s 2018 earnings guidance range of $3.35 - $3.50 per diluted share is based upon,
but not limited to, the following major assumptions and expectations:
• Normal weather in our electric and natural gas service territories;
• Equitable regulatory treatment in the process of passing Tax Cuts and Jobs Act benefits on to customers;
• Recovery of Montana energy supply costs as proposed in our pending Power Cost & Credit Adjustment Mechanism (PCCAM);
• A consolidated income tax rate of approximately 0% to 5% of pre-tax income (previously 8% to12%); and
• Issuance of the remaining $46 million of equity under our current distribution agreement resulting in diluted average shares outstanding
ranging between approximately 50.0 million to 50.2 million.
Continued investment in our system to serve our customers and communities is expected to provide
a targeted long term 6-9% total return (previously 7-10%) to our investors through a combination of
earnings growth and dividend yield. However, negative outcomes in upcoming regulatory
proceedings may result in near-term returns below our 6-9% targeted range. Generation investment
to reduce or eliminate our capacity shortfall could allow us to achieve the higher-end of our range
over the long term.
See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP “Adjusted EPS”.
Preliminary 2017 to 2018 Bridge
23
2017 Non-GAAP → 2018 Midpoint
Prior to ATM Equity Dilution: $3.30 → $3.53 = 7.0% Increase
After anticipated ATM Equity Dilution: $3.30 → $3.43 = 3.9% Increase
Dividend Growth
$2.10 → $2.20 = 4.8% increase
NorthWestern’s 2018 earnings guidance range
of $3.35 - $3.50 per diluted share is based
upon, but not limited to, the following major
assumptions and expectations:
• Normal weather in our electric and natural gas
service territories;
• Equitable regulatory treatment in the process of
passing Tax Cuts and Jobs Act benefits on to
customers;
• Recovery of Montana energy supply costs as
proposed in our pending Power Cost & Credit
Adjustment Mechanism (PCCAM);
• A consolidated income tax rate of approximately
0% to 5% of pre-tax income
(previously 8% to12%); and
• Issuance of the remaining $46 million of equity
under our current distribution agreement resulting
in diluted average shares outstanding ranging
between approximately 50.0 million to 50.2 million.
* 2018 earnings drivers above are calculated using an updated 25.3% federal and state composite statutory rate (38.5% prior to the Tax Cuts and Jobs Act). The
"Incremental tax benefit" line reflects the remaining benefit of the lower tax rate not otherwise captured in the individual earnings drivers listed. Since this tax benefit will
ultimately accrue to the benefit of customers for the full year of 2018, gross margin includes an offsetting impact reflecting the anticipated deferral of revenues collected
during the year that will be subject to commission approved spending plans or refund.
Conclusion
24
Best
Practices
Corporate
Governance
Pure Electric
& Gas Utility
Solid Utility
Foundation
Strong
Earnings &
Cash Flows
Attractive
Future
Growth
Prospects
25
Summary Financial Results (Fourth Quarter)
26
(1) Gross Margin is a non-GAAP Measure. See appendix for additional disclosure.
(1)
(dollars in millions) Three Months Ended December 31,
2017 2016 Variance
Electric $ 175.0 $ 167.9 $ 7.1 4.2%
Natural Gas 60.5 55.0 5.5 10.0%
Gross Margin $ 235.5 $ 222.9 $ 12.6 5.7%
27
Gross Margin (Fourth Quarter)
(1) Gross Margin is a non-GAAP Measure. See appendix for additional disclosure.
(1)
Increase in gross margin due to the following factors:
$ 3.4 Electric retail volumes
3.1 Natural gas retail volumes
1.7 Montana natural gas rates
1.5 2016 Hydro generation rates
0.6 Electric transmission
1.1 Other
$ 11.4 Change in Gross Margin Impacting Net Income
$ 1.3 Property taxes recovered in trackers
0.5 Operating expenses recovered in trackers
(0.4) Production tax credits flowed through trackers
(0.2) Gas production gathering fees
$ 1.2 Change in Gross Margin Offset Within Net Income
$ 12.6 Increase in Consolidated Gross Margin
Weather (Fourth Quarter)
28
Mean
Temperature
from Normal
Oct.-Dec.
2017
Favorable
weather has
contributed
approximately
$1.8 million
pretax benefit for
the quarter as
compared to
normal, and
$2.8 million
pretax benefit as
compared to
same period in
the prior year.
Operating Expenses (Fourth Quarter)
29
(dollars in millions) Three Months Ended December 31,
2017 2016 Variance
Operating, general & admin. $ 78.7 $ 82.2 $ (3.5) (4.3%)
Property and other taxes 44.1 36.8 7.3 19.8%
Depreciation and depletion 41.7 39.7 2.0 5.0%
Operating Expenses $ 164.5 $ 158.7 $ 5.8 3.7%
Increase in operating expenses due mainly to the following factors:
$3.5 million decrease in OG&A
$ (3.7) Employee benefits and compensation costs
$ (0.4) Bad debt expense
$ (0.2) Maintenance costs
$ (0.2) Natural gas production gathering expense
$ 1.0 Non-employee directors deferred compensation
$ 0.5 Operating expense recovered in trackers
$ (0.5) Other
$7.3 million increase in property and other taxes due primarily to plant additions and
higher estimated property valuations in Montana.
$2.0 million increase in depreciation and depletion expense primarily due to plant
additions.
(dollars in millions) Three Months Ended December 31,
2017 2016 Variance
Operating Income $ 71.0 $ 64.2 $ 6.8 10.6%
Interest Expense (22.3) (23.0) 0.7 3.0%
Other Income 2.5 1.3 1.2 92.3%
Income Before Taxes 51.2 42.5 8.7 20.5%
Income Tax (Expense) / Credit (3.3) 1.6 (4.9) (312.9%)
Net Income $ 47.9 $ 44.1 $ 3.8 8.6%
Operating Income to Net Income (Fourth Quarter)
30
$0.7 million decrease in interest expense was primarily due to refinancing of debt in
November 2017.
$1.2 million increase in other income due primarily to higher capitalization of allowance
for funds used during construction (AFUDC) and a $1.0 million increase of deferred shares
held in trust for non-employee directors deferred compensation (which had a corresponding
increase to operating, general and administrative expenses).
$4.9 million increase in income tax expense due primarily to higher pre-tax income in
2017 and lower plant and depreciation of flow-through items.
Balance Sheet
31
Debt to total
capitalization
decreased to
53.7% and now
within targeted
50%-55% range.
Cash Flow
32
Improvement in
cash from
operations is
primarily due to
refunds in 2016
associated with
the DGGS FERC
ruling and interim
rates in our
South Dakota
electric rate case
of approximately
$30.8 million and
7.2 million,
respectively.
Income Tax Reconciliation (Fourth Quarter)
33
Our income taxes are higher in fourth quarter 2017 versus the prior year largely due to
higher pre-tax income and lower plant and depreciation of flow through items.
Adjusted Earnings (Fourth Quarter ‘17 vs ’16)
34
The non-GAAP measures presented in the table 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.
Last quarter we
indicated we needed
$0.95 to $1.10 in the fourth
quarter 2017 to meet our
guidance for the year. While the
$0.96 Non-GAAP earnings we
delivered during the quarter was
at the low end of the range, it was
a 4.3% improvement over 2016.
(1) Note: Fourth quarter net income and EPS last year (2016) was originally reported as $45.9M and $0.95, respectively. As a result of adopting Accounting Standards
Update No. 2016-09 during the fourth quarter of 2016, excess tax benefits of $1.8 million related to vested share-based compensation awards were recorded as a decrease
in income tax expense in the Consolidated Statement of Income. In accordance with the guidance, the $1.8 million impact of this adoption is reflected as of January 1, 2016
and included in first quarter 2016 results.
Summary Financial Results (Full Year)
35
(1) Gross Margin is a non-GAAP Measure. See appendix for additional disclosure.
(1)
Gross Margin (Full Year)
36
(dollars in millions) Twelve Months Ended December 31,
2017 2016 Variance
Electric $ 703.1 $ 678.8 $ 24.3 3.6%
Natural Gas 192.3 177.5 14.8 8.3%
Gross Margin $ 895.4 $ 856.3 $ 39.1 4.6%
Increase in gross margin due to the following factors:
$ 15.7 Electric retail volumes
10.5 Natural gas retail volumes
9.5 2016 Montana Public Service Commission (MPSC) disallowance
1.8 Montana natural gas rates
1.5 2016 Hydro generation rates
1.2 South Dakota generation rates
0.6 Electric transmission
0.4 Electric QF adjustment
(14.2) 2016 Lost revenue adjustment mechanism
3.9 Other
$ 30.9 Change in Gross Margin Impacting Net Income
$ 6.7 Property taxes recovered in trackers
1.5 Operating expenses recovered in trackers
$ 8.2 Change in Gross Margin Offset Within Net Income
$ 39.1 Increase in Consolidated Gross Margin
Weather (Full Year)
37
Heating Degree Days Cooling Degree Days
We estimate favorable weather in 2017 contributed approximately
$3.4 million pretax benefit as compared to normal and
$18.6 million pretax benefit as compared to 2016.
Source: National Centers for Environmental Information
Operating Expenses (Full Year)
38
Increase in operating expenses due mainly to the following factors:
$2.2 million increase in OG&A
$ 1.9 Bad debt expense
1.5 Operating expenses recovered in trackers
1.2 Maintenance costs
(1.5) Employee benefits and compensation costs
(1.0) Insurance reserves
0.1 Other
$14.5 million increase in property and other taxes due primarily to plant
additions and higher estimated property valuations in Montana.
$6.8 million increase in depreciation and depletion expense primarily
due to plant additions.
(dollars in millions) Twelve Months Ended December 31,
2017 2016 Variance
Operating, general & admin. $ 305.1 $ 302.9 $ 2.2 0.7%
Property and other taxes 162.6 148.1 14.5 9.8%
Depreciation and depletion 166.1 159.3 6.8 4.3%
Operating Expenses $ 633.8 $ 610.3 $ 23.5 3.9%
Operating Income to Net Income (Full Year)
39
$2.7 million decrease in interest expense was primarily due to refinancing
$250 million of debt in November 2017 and $2.9 million of interest included in
our 2016 results associated with an MPSC disallowance offset partially by higher
interest expense on short-term borrowings.
$1.4 million increase in other income due primarily to higher capitalization of
allowance for funds used during constructions (AFUDC).
$21.0 million increase in income tax expense due primarily to the inclusion in our
2016 results of a $17.0 million income tax benefit due to the adoption of a tax
accounting method change related to the cost to repair generation assets (of which
$12.5 million related to periods prior to 2016), and higher pre-tax income.
(dollars in millions) Twelve Months Ended December 31,
2017 2016 Variance
Operating Income $ 261.4 $ 245.9 $ 15.6 6.3%
Interest Expense (92.3) (95.0) 2.7 2.9%
Other Income 6.9 5.5 1.4 25.4%
Income Before Taxes 176.1 156.5 19.6 12.5%
Income Tax (Expense) Benefit (13.4) 7.6 (21.0) (276.8%)
Net Income $ 162.7 $ 164.2 ($ 1.5) (0.9%)
Income Tax Reconciliation (Full Year)
40
The increase in income tax expense was primarily due to higher pretax income
and the inclusion in our 2016 results of a $17.0 million income tax benefit due to
the adoption of a tax accounting method change related to the costs to repair
generation assets (of which $12.5 million related to periods prior to 2016), and
higher pre-tax income.
Non-GAAP Adjusted Earnings (Full Year ‘17 vs ’16)
41
The non-GAAP
measures
presented in
the table are
being shown to
reflect
significant items
that were not
contemplated in
our original
guidance,
however they
should not be
considered a
substitute for
financial results
and measures
determined or
calculated in
accordance
with GAAP.
Montana Natural Gas Rate Filing
42
Montana PSC Docket D2016.9.68
Derivation of Rate Increase ($Millions)
Revenue Request in Initial Application ..... $10.9
Property Tax (adjustment to actual) ….….. ($2.0)
Income Tax correction and other misc. ..... 0.5
Rebuttal Revenue Request …………….. $9.4
1st Stipulation with MCC
ROE Reduction (10.35% to 9.55%) ...... (2.6)
Deprec. Reserve and other misc. …...... (0.2)
1st Stipulation Revenue Request …...... $6.6
2nd Stipulation with MCC / LCG
A&G Concession ………………………. (0.8)
2nd Stipulation Revenue Request …...… $5.7
July 20, 2017 MPSC Work Session
Remove A&G Concession ……………… 0.8
Accumulated depletion adjustment ……. (1.4)
MPSC Settlement ………………..……..… $5.1*
$5.1M
6.96%
$430.2M
9.55% 4.47%
* Parties did not object to MPSC’s work session final order.
NorthWestern Energy Profile
43
2017 System Statistics
44
Note: Statistics above are as of 12/31/2017 except for Electric Transmission for Others
(1) Nebraska is a natural gas only jurisdiction
(2) Dave Gates Generating Station (DGGS) in Montana is a 150 MW nameplate facility but consider it a 105 MW
(60 MW FERC & 45MW MPSC jurisdictions) peaker
(1)
(2)
Our Commissioners
45
DGGS Update – Denied Rehearing Request
46
Note: Please see Regulatory Matters footnote and Risk Factors section of our recent Form 10-K and Form 10-Q for additional disclosures.
Non-GAAP Financial Measures (1 of 3)
47
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 (2 of 3)
48
Disclaimer on Net
Operating Net
Operating Losses
(NOL’s):
The expected tax rate
and the expected
availability of NOLs are
subject to significant
business, economic,
regulatory and
competitive uncertainties
and contingencies, many
of which are beyond the
control of the Company
and its management, and
are based upon
assumptions with respect
to future decisions, which
are subject to
change. Actual results
will vary and those
variations may be
material. For discussion
of some of the important
factors that could cause
these variations, please
consult the “Risk Factors”
section of the preliminary
prospectus. Nothing in
this presentation should
be regarded as a
representation by any
person that these
objectives will be
achieved and the
Company undertakes no
duty to update its
objectives.
Non-GAAP Financial Measures (3 of 3)
49
The data presented in this presentation
includes financial information prepared in
accordance with GAAP, as well as other Non-
GAAP financial measures such as Gross
Margin (Revenues less Cost of Sales), Free
Cash Flows (Cash flows from operations less
maintenance capex and dividends) and Net
Debt (Total debt less capital leases), 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. The
presentation of Gross Margin, Free Cash
Flows and Net Debt is intended to supplement
investors’ understanding of our operating
performance. 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. Net Debt is used by our company to
determine whether we are properly levered to
our Total Capitalization (Net Debt plus Equity).
Our Gross Margin, Free Cash Flows and Net
Debt measures may not be comparable to
other companies’ similarly labeled measures.
Furthermore, these measures are not
intended to replace measures as determined
in accordance with GAAP as an indicator of
operating performance.
50