8-K May 17, 2017
Investor Update
May 17-18, 2017
Spion Kop Wind Farm - near Geyser, 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.
Company Information
NorthWestern Corporation
dba: NorthWestern Energy
www.northwesternenergy.com
Corporate Support Office
3010 West 69th Street
Sioux Falls, SD 57106
(605) 978-2900
Montana Operational Support Office
11 East Park
Butte, MT 59701
(406) 497-1000
SD/NE Operational Support Office
600 Market Street West
Huron, SD 57350
(605) 353-7478
Investor Relations Officer
Travis Meyer
605-978-2945
travis.meyer@northwestern.com
NWE - An Investment for the Long Term
3
• 100% Regulated electric & natural gas utility business
• 100 year history of competitive customer rates, system reliability and customer satisfaction
• Solid economic indicators in service territory
• A diverse electric supply portfolio that is approximately 54% hydro and wind (combined MT & SD)
• Solid & improving JP Power Overall Customer Satisfaction scores
• Residential electric and natural gas rates below the national average
• Solid system reliability (EEI 2nd quartile)
• Low leaks per 100 miles of pipe (AGA 1st quartile)
• Named a “Utility Customer Champion” by Cogent Reports (top trusted utility brand in the West region)
• Consistent track record of earnings and dividend growth
• Strong cash flows aided by net operating loss carry-forwards
• Strong balance sheet and solid investment grade credit ratings
• Recent hydro & wind transactions provide additional long-term energy supply pricing stability
• Disciplined maintenance capital investment program
• Further opportunity to reintegrate energy supply portfolio to meet capacity shortfalls
• Significant future investment in a comprehensive transmission, distribution, and substation
infrastructure project to address asset lives, safety, capacity and grid modernization
Pure Electric
& Gas Utility
Solid Utility
Foundation
Strong
Earnings &
Cash Flows
Attractive
Future Growth
Prospects
(NYSE Ethics)
Best Practices
Corporate
Governance
About NorthWestern
4
Montana Operations
Electric
363,800 customers
24,450 miles – transmission & distribution lines
809 MW nameplate owned power generation
Natural Gas
194,100 customers
7,250 miles of transmission and distribution pipeline
18 Bcf of gas storage capacity
Own 61 Bcf of proven natural gas reserves Nebraska Operations
Natural Gas
42,300 customers
787 miles of distribution pipeline
South Dakota Operations
Electric
63,200 customers
3,550 miles – transmission & distribution lines
440 MW nameplate owned power generation
Natural Gas
46,200 customers
1,673 miles of transmission and distribution pipeline
A Diversified Electric and Gas Utility
5
Gross Margin in 2016:
Electric: $679M
Natural Gas: $177M
Gross Margin in 2016:
Montana: $718M
South Dakota: $128M
Nebraska: $ 10M
Average Customers in 2016:
Residential: 586k
Commercial: 112k
Industrial: 7k
NorthWestern‟s „80/20‟ rules:
Approximately 80% Electric, 80% Residential and
80% Montana jurisdictional
Above data reflects full year 2016 results.
NorthWestern Energy Profile
6
Financial and Company Statistics
7
Based upon 2016 MWH‟s of owned and long-term
contracted resources. Approximately 54% of our total
company owned and contracted supply is carbon-free.
Highly Carbon-Free Supply Portfolio
Strong Utility Foundation
8
Electric source: Edison Electric Institute Typical Bills and Average Rates Report, 1/1/16
Natural gas source: US EIA - Monthly residential supply and delivery rates as of 1/29/16
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
System Average Interruption Duration Index (SAIDI)
NWE versus EEI System Reliability Quartiles
Solid Economic Indicators
9
• Unemployment rates in all three of our
states are meaningfully below National
Average.
• Customer growth rates historically exceed
National Averages.
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")
2017 Earnings Guidance
10
NorthWestern reaffirms 2017 earnings guidance range of $3.30 - $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;
• A consolidated income tax rate of approximately 7% to 11% of pre-tax income; and
• Diluted average shares outstanding of approximately 48.5 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. However in light of recent regulatory
headwinds and reduced & delayed generation spending, we anticipate in the near-term to
be at the lower end of the 7-10% range.
See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP “Adjusted EPS”.
$2.60 - $2.75
$3.10 - $3.30 $3. 0-$3.40
$3.30-$3.50
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 and
lower than the US average bills,
while delivering solid earnings
growth for our investors.
2008-2016 CAGRs
Estimated Rate Base: 14.8%
GAAP Diluted EPS: 8.4%
NWE typical electric bill: 2.2%
NWE typical natural gas bill: (7.5%)
US average electric bill: * 2.0%
US avg. natural gas bill ** (4.1%)
Note: US avg. natural gas bill CAGR is from
2008-2015
Track Record of Delivering Results
12
Notes: - ROE in 2011, 2012 , 2013, 2014, 2015 & 2016 on a Non-GAAP Adjusted basis, would be 10.5%, 9.8%, 9.6% ,9.4%, 9.9% and 9.8% respectively.
- 2017 ROAE and 2017 Dividend payout ratio estimate based on midpoint of our guidance range of $3.30-$3.50.
- Details regarding Non-GAAP Adjusted EPS can be found in the “Adjusted EPS Schedule” page of the appendix
Return on Equity within
9.5% - 11.0% band over
the last 6 years.
Annual dividend increases
since emergence in 2004.
6 Year (2011-2016) Avg.
Return on Equity: 10.4%
5 Year (2011-2016) CAGR
Dividend Growth: 6.8%
Current Dividend Yield
Approximately 3.7%
(based on $2.10 annual dividend)
Total Shareholder Return
13 • 13 member peer group: ALE (ALLETE), AVA (Avista), BKH (Black Hills Corp), EE (El Paso Electric), GXP (Great Plains Energy), IDA (IDACORP), MGEE (MGE Energy), OGE (OGE Energy), OTTR (Otter Tail Power), PNM (PNM Resources), POR (Portland General Electric), VVC (Vectren) and WR (Westar)
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 continued to
outpace maintenance capex and
averaged approximately $29 million of
positive Free Cash Flow 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 rising into the low-twenties by
2020. Additionally, we expect NOLs to
be available into 2021 to reduce cash
taxes.
Strong Cash Flows
14
See “Non-GAAP Financial Measure” slide in appendix for Free Cash Flows reconciliation.
This 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.
Net Opera ing Loss (NOL) Carryforward Balance
(2)
(1)
(2)
(1)
Components of Free Cash Flow
Balance Sheet Strength and Liquidity
15
Credit Ratings
16
Moody’s: A2
Fitch: A
S&P: A-
Moody‟s downgraded our senior secured and unsecured credit rating on
March 10, 2017 and has us on a Negative Outlook. However, even after
the downgrade, Moody‟s rating is in line with Fitch and above S&P on a
secured basis (and between them on an unsecured basis).
Recent Significant Achievements
17
Strong year for safety in 2016
• Fewest OSHA recordable events of any year.
• Best year for lost time incidents.
Record best customer satisfaction scores
• Received our best Overall Customer Satisfaction
scores in the JD Power residential utility survey in
2016.
Corporate Governance Finalist
• NorthWestern‟s 2016 proxy statement was
recognized as a finalist in 2016 by Corporate
Secretary magazine for Best Proxy Statement (Small
to Mid Cap). We won the award in 2014.
Echo Lake Nordic Trail
Recognized for Strong Dividend
• In March 2016, NorthWestern Corporation was added to the NASDAQ US Broad Dividend
AchieversTM Index, which aims to represent the country‟s leading stocks by dividend yield in addition
to Dow Jones US Dividend Select TM Index in 2015.
New Board Members
• December 2016: Anthony Clark, senior advisor at Wilkenson Barker Knauer LLP and former
FERC commissioner and ND Public Service Commissioner.
• April 2017: Britt Ide, president of Ide Energy & Strategy
• April 2017: Linda Sullivan, executive vice president and chief financial officer of
American Water.
What we are working on in 2017
18
Natural Gas Rate Case in Montana
• A Hearing was held May 9-11 with a decision expected in mid 2017.
Cost control efforts
• Continue to monitor costs, especially labor and benefits
• Monitor property tax valuations in Montana
Continue to invest in our existing transmission and
distribution infrastructure.
• Transition from DSIP/TSIP to overall infrastructure capital plan
• Natural gas pipeline investment (Integrity Verification Process
and PHMSA Requirements)
• Advanced Metering Infrastructure (AMI) investment
Refining our Supply Plan in Montana
• Capacity generation additions
• Continue to work with MPSC and other stakeholder groups to
refine energy supply plans
Continue to search for natural gas reserve acquisition opportunities
• Acquisitions at a price that benefits both customers and shareholders
19
Regulatory Update
Regulatory Item Current / Anticipated Action
FERC / DGGS: April 2014 order
regarding cost allocation at DGGS
between retail and wholesale
customers.
• FERC denied our request for rehearing and required us to make
refunds in June 2016.
• We filed a petition for review with the US Circuit Court of Appeals
for the District of Columbia Circuit in June 2016.
• We do not expect a decision until the fourth quarter of 2017, at
the earliest.
Colstrip: In May 2016, the MPSC
issued a final order disallowing
recovery of certain costs included
in the electric supply tracker related
to a 2013 outage at Colstrip Unit 4.
• Appeals have been filed in two Montana district courts regarding
disallowance.
• We believe we are likely to receive orders from the courts in
these matters by the end of 2017 or in early 2018.
Hydro Compliance Filing: In
December 2016, the MPSC issued
a final order reducing the annual
amount we are allowed to recover
in hydro generation rates by
approximately $1.2 million and
required us to indicate our
intentions to file a Montana electric
rate case with a 2016 test year.
On April 26, 2017, we filed our required annual report with the MPSC
regarding 2016 results, which indicates we earned less than our
authorized rate of return. At the same time, we also submitted a filing
to the MPSC responsive to the hydro compliance order, indicating we
do not expect to file an electric rate case in 2017 based on a
2016 test year. However, we expect to file a general electric rate
case in 2018 based on a 2017 test year. The MPSC may require
an additional filing that would facilitate their assessment of just and
reasonable rates.
• 2016 Schedule 27 ROE:
9.76% Actual, 9.38% Normalized vs 10.05% wt. avg. authorized.
20
Montana Natural Gas Rate Filing: • On May 5th a proposed Stipulation and Settlement Agreement was
reached with the MCC. If approved, the settlement would result
in a $6.6 million revenue increase and 9.55% ROE.
• Hearing was held May 9-11 with a decision expected in mid 2017.
Montana House Bill 193: Passed
by Montana legislature in April 2017.
• This bill revises the current tracker related legislation, which
mandated that the MPSC use an electric cost recovery mechanism
that provides for full cost recovery of prudently incurred electric
supply costs. HB193 increases the discretion the MPSC may
exercise with regard to costs included in tracker filings. While
the text of HB193 does not address the specifics of changes in cost
recovery, testimony provided by the MPSC in support of HB193
indicates our tracker filings would be handled similarly to Montana-
Dakota Utilities (MDU) mechanism. The MDU mechanism allows for
recovery of 90 percent of the increases or decreases in fuel and
purchased power costs from an established baseline. However, due
to the discretion allowed in HB193, we can not guarantee how the
MPSC may apply the stature to our electric tracker filings. HB193 is
expected to go into effect on July 1, 2017.
Property Tax Tracker Rules: In
March 2017, the MPSC proposed
new rules to establish minimum
filing requirements for property tax
trackers.
• Current MT Property tax tracker rules allows recovery of 60 percent
of the change in state and local taxes and fees. Some of the
proposed rules would enable MPSC to challenge amounts and
allocation to customers
• A work session was held on May 4th in which the Commission
instructed staff to move forward finalizing the rules. It is
unclear if the rules will remain exactly as proposed or modified
before they are finalized in mid 2017.
Regulatory Update (continued)
Montana Natural Gas Rate Filing
21
Montana PSC Docket D2016.9.68
On May 5th a proposed Stipulation and Settlement
Agreement was reached with the MCC. If
approved, the settlement would result in a $6.6
million* revenue increase, 9.55% ROE and the
46.79% equity capital structure as originally filed.
The Large Customer Group did not join in the
settlement but indicated that it supports the
agreement other than provisions relating to the
allocation of common plant and administrative &
general expenses.
A Hearing was held May 9-11 with the decision
expected mid-2017.
* The Initial Application requested a $10.9 million increase. This
amount was updated in Rebuttal to $9.4 million primarily as a
result of $2.0 million lower actual property tax expense a $0.5
million offsetting increase for an income tax adjustment.
$6.6M
6.96%
$430.2M
$76.06
9.55% 4.47%
Capital Spending Forecast
22
The current estimated 5 year capital spending is $1.58 billion. We anticipate managing capital expenditures
to provide a more levelized annual spend (including spending on generation assets) and anticipate funding
the expenditures with a combination of cash flows, aided by NOLs now anticipated to be available into 2021,
and long-term debt. If other opportunities arise that are not in the above projections (natural gas reserves,
acquisitions, etc.), new equity funding may be necessary.
*
Montana 2015 Electric Supply Resource Plan
23
The resource initiatives and
actions developed in 2015
Electricity Supply Resource
Procurement Plan identify the
critical future needs of our
portfolio, including solutions to
resolve our current negative
planning reserve margin.
The plan identifies how to co-
optimize hydro, wind and thermal
resources to best meet the
anticipated large capacity needs
with the least-cost, lowest-risk
resources.
On February 2, 2017 the Montana
Public Service Commission
issued a press release
acknowledging the need for
additional capacity but identified
specific concerns with the plan. A
constructive workshop, to clarify
the technical underpinnings of the
plan, was held on February 27
with the MPSC and staff.
Spending on the generation assets will be
subject to the development of a plan for
clear regulatory recovery.
Source: Company’s IRP or other publications
Montana 2015 Electric Supply Resource Plan
24
On February 13, 2017 we issued a
Request for Proposal (RFP) to
partially address NorthWestern‟s
negative reserve margin.
Pacific Northwest planning bodies
(PNUCC & NWPPC*) have
reaffirmed the expected growing
capacity need.
NorthWestern is addressing this risk
through a deliberate and
incremental approach that will
include subsequent RFP‟s to lessen
the risk of a large reliance on
markets that are vulnerable to price
spikes during capacity shortages.
* Pacific Northwest Utilities Conference
Committee & Northwest Power and
Conservation Council
Current Capacity Economically Optimal Portfolio
(Current capacity plus identified generation additions)
Owned
Owned
Target
Total Annual Need
Natural Gas Reserves Opportunity
25
Current gas prices are very
attractive for buyers but it is
difficult to find sellers willing to
transact at these low rates.
First ~6 Bcf annual
production acquired
for ~$100M
Remaining 6-7 Bcf
annual production
needed to meet target.
Estimated cost of $50M to $100M
We continue to pursue opportunities to secure
low cost gas reserves for our customers.
• Three acquisitions totaling approximately $100 million since
September 2010:
• 84.6 Bcf of natural gas reserves and associated gathering
systems along with 82 miles of transmission.
• Provides approximately 5.3 Bcf of annual production.
• Target to own 50% of our 25 Bcf total annual need
• Retail customers (20 Bcf)
• DGGS & Basin Creek generation facilities (5 Bcf)
• As we continue to add to our natural gas reserves portfolio,
we anticipate a reduction in supply cost volatility for our
customers.
Conclusion
26
Pure Electric
and Gas
Utility
Solid Utility
Foundation
Strong
Earnings and
Cash Flows
Attractive
Future
Growth
Prospects
Best
Practices
Corporate
Governance
27
Summary Financial Results (First Quarter)
28
Note: During the fourth quarter of 2016, we early adopted the provisions of Accounting Standards Update No. 2016-09 (ASU 2016-09), Improvements to Employee
Share-Based Payment Accounting, revising certain elements of the accounting for share-based payments. As a result of this adoption, 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. The guidance also
requires that in future filings that include the previously issued interim financial information, the interim financial information is presented on a recast basis to reflect
the adoption of ASU 2016-09 as of January 1, 2016. The Condensed Consolidated Statement of Income and Condensed Consolidated Statement of Cash Flow for
the period ended March 31, 2016, have been recast to reflect this adoption, resulting in an increase in net income and earnings per share.
29
Gross Margin (First Quarter)
(dollars in millions) Three Months Ended March 31,
2017 2016 Variance
Electric $ 180.8 $ 157.7 $ 23.1 14.6%
Natural Gas 66.7 59.4 7.3 12.3%
Gross Margin $ 247.5 $ 217.1 $ 30.4 14.0%
Increase in gross margin due to the following factors:
$ 10.3 MPSC disallowance (2016)
8.6 Electric retail volumes
6.0 Natural gas retail volumes
1.2 South Dakota electric rate increase
(0.6) Natural gas production
1.8 Other
$ 27.3 Change in Gross Margin Impacting Net Income
$ 3.1_ Property taxes recovered in trackers
$ 3.1 Change in Gross Margin Offset Within Net Income
$ 30.4 Increase in Consolidated Gross Margin
Weather (First Quarter)
30
Mean Temperature from Normal
Our Montana service territory benefited from a colder than normal January offset partially by warmer
than normal February and March in all three states we serve. Our service territory also experienced
colder winter weather than the prior year.
Operating Expenses (First Quarter)
31
Increase in operating expenses due mainly to the following factors:
$1.1 million increase in OG&A
$ 1.5 Maintenance costs
$ 1.3 Bad debt expense
$ 0.5 Labor
$ (1.7) Non-employee directors deferred compensation
$ (1.0) Insurance reserves
$ 0.5 Other
$4.5 million increase in property and other taxes due primarily to plant additions and
higher estimated property valuations in Montana.
$1.6 million increase in depreciation and depletion expense primarily due to plant
additions.
(dollars in millions) Three Months Ended March 31,
2017 2016 Variance
Operating, general & admin. $ 81.0 $ 79.9 $ 1.1 1.4%
Property and other taxes 39.9 35.4 4.5 12.7%
Depreciation and depletion 41.5 39.9 1.6 4.0%
Operating Expenses $ 162.4 $ 155.2 $ 7.2 4.6%
Operating to Net Income (First Quarter)
32
$1.1 million decrease in interest expenses was primarily due to debt refinancing at a
lower interest rate of the Pollution Control Revenue Refunding Bonds during the third
quarter of 2016.
$1.6 million decrease in other income due primarily to a $1.7 million decrease in the
value of deferred shares held in trust for non-employee directors deferred compensation
(which had a corresponding increase to operating, general and administrative
expenses).
$5.9 million increase in income tax expense due primarily to higher pre-tax income,
offset by lower flow-through repairs deductions.
(dollars in millions) Three Months Ended March 31,
2017 2016 Variance
Operating Income $ 85.1 $ 61.9 $ 23.2 37.5%
Interest Expense (23.4) (24.5) 1.1 (4.5%)
Other Income 1.5 3.1 (1.6) (51.6%)
Income Before Taxes 63.2 40.6 22.6 55.7%
Income Tax Expense (6.6) (0.7) (5.9) (842.9%)
Net Income $ 56.6 $ 39.9 $ 16.7 41.9%
Balance Sheet
33
Cash Flow
34
Income Tax Reconciliation
35
Adjusted Earnings (First Quarter „17 vs ‟16)
36
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.
(1) Note: First quarter net income and EPS last year (2016) was originally reported as $38.1M and $0.79, 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.
Non-GAAP Adjusted EPS
37
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.
(in millions, except EPS)
2016 to 2017 EPS & Dividend Bridge
2016 Non-GAAP EPS to 2017 Midpoint
$3.30 → $3.40 = 3.0% increase
2016 to 2017 Dividend Growth
$2.00 → $2.10 = 5.0% increase
Slower near-term EPS growth along with
slightly lower capital investment
projections than previously provided, led
us to a 5% (or 10 cents annualized)
dividend increase rather than the 4% (or
8 cents annualized) targeted dividend
increase we had last indicated in
December 2016.
NWE’s 2017 earnings guidance range of $3.30-$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
• A consolidated income tax rate of approximately
7% to 11% of pre-tax income; and
• Diluted average shares outstanding of
approximately $48.5 million.
38
* 2017 earnings drivers shown above are calculated using a 38.5% effective tax rate. The anticipated
"Incremental tax detriment" shown above is primarily due to lower anticipated tax-repairs eligible capital
spending in 2017.
2016 System Statistics
39
Note: Statistics above are as of 12/31/2016
(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)
Experienced & Engaged Board of Directors
40
Dr. E. Linn Draper Jr.
• Chairman of the Board
• Independent
• Director since
November 1, 2004
Stephan P. Adik
• Committees: Audit
(chair), Human
Resources
• Independent
• Director since
November 1, 2004
Anthony T. Clark
• Committees:
Governance and
Innovation
• Independent
• Director since
December 6, 2016
Julia L. Johnson
• Committees:
Governance and
Innovation, Human
Resources
• Independent
• Director since
November 1, 2004
Robert C. Rowe
• Committees: None
• CEO and President
• Director since
August 13, 2008
Linda G. Sullivan
• Committees: Audit
• Independent
• Director since
April 27, 2017
Dana J. Dykhouse
• Committees: Human
Resources (chair),
Audit
• Independent
• Director since
January 30, 2009
Jan R. Horsfall
• Committees: Audit,
Governance and
Innovation
• Independent
• Director since
April 23, 2015
Britt E. Ide
• Committees:
Governance and
Innovation
• Independent
• Director since
April 27, 2017
Strong Executive Team
41
Robert C. Rowe
• President and
Chief Executive Officer
• Current position since
2008
Brian B. Bird
• Vice President and
Chief Financial Officer
• Current position since
2003
Michael R. Cashell
• Vice President -
Transmission
• Current Position since
2011
Patrick R. Corcoran
• Vice President –
Government and
Regulatory Affairs
• Current position since
2001
Heather H. Grahame
• Vice President and
General Counsel
• Current position since
2010
John D. Hines
• Vice President - Supply
• Current Position since
2011
Crystal D. Lail
• Vice President and
Controller
• Current position since
2015
Curtis T. Pohl
• Vice President -
Distribution
• Current position since
2003
Bobbi L. Schroeppel
• Vice President –
Customer Care,
Communications and
Human Resources
• Current Position since
2002
Our Commissioners
42
The Hydro Facilities
43
Overview of Hydro Facilities
Black Eagle
Hydro Asset Integration
• Montana Asset Optimization Study: As part of reintegrating the
hydro facilities into our generation portfolio, we initiated an
asset optimization study to maximize the value of our diverse
generation portfolio. The study was recently completed and
we are in the process of implementing new operating
procedures that we anticipate will reduce both operating cost
and market risk.
Kerr Dam Conveyance / Hydro Compliance Filing
• In accordance with the 1985 FERC relicensing, the facility was
conveyed to the Confederated Salish and Kootenai Tribes
(CSKT) on September 5, 2015.
• As required by the MPSC order approving the hydro
transaction, we filed a compliance filing in December 2015 to
remove the Kerr project from the hydros cost of service and to
adjust for actual revenue credits and property taxes. In
January „16, the MPSC approved an interim adjustment and
opened a separate contested docket requesting additional
detail. A hearing was held in September 2016. The only
contested issue at the hearing was the level of administrative
& general expenses that should be deducted due to the
transfer of the Kerr Project. We expect a final order during the
fourth quarter of 2016.
(1) As of June 2013.
Despite the 2015 drought conditions in western Montana, the hydro
assets generated at targeted capacity (5 year historical average).
Talen Energy‟s recently announced sale of 292 MW of hydro
generation for $860 million (or $2,945 per KW) to Brookfield
Renewables is significantly higher cost (49%) than the 439 MW of
hydro generation we purchased for $870 million (or $1,982 per KW).
44
Colstrip Unit 4 / Sierra Club Litigation
Background
• On March 6, 2013, the Sierra Club and the Montana Environmental Information Center (MEIC)
(both are plaintiffs) filed suit in the United States District Court for the District of Montana (court)
against the six individual Owners of the Colstrip Generating Station (Colstrip)
• Colstrip consists of four coal fired generating units – units 1 & 2 are older than units 3 & 4.
• NWE has a 30% joint interest in unit 4 and a risk sharing agreement with Talen Montana
regarding the operation of units 3 & 4, which each party receives 15% of the combined output and
respective operating and construction costs.
• Original suit was for alleged violations of the Clean Air Act and the Montana State Implementation
Plan.
Current Results
• On July 12, 2016 the parties lodged a consent decree with the Court.
• The Court entered the consent decree on September 6, 2016.
• Decree provides the following
• Dismisses all of the claims against all Colstrip units
• Provides no shut down date for Units 3 & 4
• Provides that Units 1 & 2 must be shut down by July 1, 2022 (NWE has no ownership or
role in Units 1 & 2 shut down)
• Permits parties to petition the Court for costs and attorneys‟ fees
• The consent decree gave the Plaintiffs and Defendants the right to seek recovery of attorneys‟ fees and costs from the
other party by filing a motion with the Court by October 6, 2016. Each party filed such a motion on a timely basis. On
January 30, 2017 the United States Magistrate Judge (Magistrate) issued his Findings and Recommendation on the
competing fee applications. The Magistrate recommended the Defendants‟ fee request be denied and the Plaintiffs‟ fee
request should be granted, but only to the extent of fifty percent of their request. The 50% reduction was due to the
Plaintiffs‟ limited success in the case, citing failure of Plaintiffs to obtain civil penalties and failure to achieve any relief as to
Units 3 and 4. As a result, while the Plaintiffs had requested approximately $3.1 million in fees and costs, the Magistrate
recommended that they recover approximately $1.6 million. Our share of this amount would be approximately $0.2 million.
The parties had 14 days following issuance of the Magistrate‟s Findings and Recommendation in which to object. Neither
Plaintiffs or Defendants filed an objection. On February 15, 2017, the District Court adopted the
Magistrate‟s Findings and Recommendation, and dismissed the case.
DGGS Update – Denied Rehearing Request
45 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
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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.
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