Otter Tail Annual Report 2017

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FY2017 Annual Report · Otter Tail

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Otter Tail Corporation

Internal Audit Manager

Janelle Johnson evaluates

and improves effectiveness

of critical company processes.

She completed an internal audit

at BTD’s Lakeville facility in 2017.

Northern Pipe Products Yard Lift

Operator Jesus Guajardo (cover) and

Customer Service Representative Andrew

Stockinger provide customers with high

quality service and PVC pipe. Together

with Vinyltech, Northern Pipe successfully

managed accelerated production and

shipping surrounding the 2017 hurricanes.

ABOUT THE

COV R

Otter Tail Power Company Energy

Management Representative Roger Garton

(cover with our electric vehicle and left)

helps customers with rebates and programs.

Our Commercial Design Assistance program

determined energy savings opportunities for

Leech Lake Band of Ojibwe’s new Tribal Justice Center.

SHAREHOLDER SERVICES

215 S. Cascade St., P.O. Box 496

Fergus Falls, MN 56538-0496

Phone: 800-664-1259

or 218-739-8479

Email: sharesvc@ottertail.com

www.ottertail.com

NASDAQ: OTTR

GROW

OUR BUSIN ESSES

ACHIEVE

OP ERATI ONAL AND COMM ERC I AL EXCE LLEN CE

DEVELOP OUR TA LENT

2 0 1 7 A N N U A L R E P O R T

DRIVEN TO
EXCELLENCE

G
N
R
U
T
C
A
F
U
N
A
M

Our manufacturing
companies supply
valued products to
customers in various
markets. In 2017
custom metal
fabricator BTD
continued to deliver
key customer
orders, including
ﬁ xtures used for
transporting wind
turbine blades.

C
R
T
C
E
L
E

Otter Tail Power
Company’s mix of
energy resources
allows for some of
the lowest rates in the
nation. Renewable
Energy Construction
and Operations
Manager Harvey
McMahon (left) and
Wind Farm Supervisor
Craig Burchill oversee
our wind power
resources—a least-
cost option for our
customers—which
produce some of the
highest capacity
factors in the region.

Otter Tail Corporation delivers value by building strong electric utility and manufacturing platforms.
For our shareholders we deliver above-average returns through operational excellence and
growing our businesses.
For our customers we commit to quality and value in everything we do.
For our employees we provide an environment of opportunity with accountability where
people are valued and empowered to do their best work.

MISSION

INTEGRITY: We conduct business responsibly and honestly.
SAFETY: We provide safe workplaces and require safe work practices.
PEOPLE: We build respectful relationships and create an environment where people thrive.
PERFORMANCE: We strive for excellence, act on opportunity, and deliver on commitments.
COMMUNITY: We improve the communities where we work and live.

VALUES

VISION

WE WILL BUILD A STRONG AND FOCUSED
DIVERSIFIED ORGANIZATION WITH AN
ELECTRIC UTILITY AS OUR FOUNDATION.

DIR CTORS

DNP Select Income Fund, Inc.

TIMOTHY J. O’KEEFE

NATHAN I. PARTAIN

Chairman of the Board

of Directors

Chicago, Illinois

President and

Chief Investment Ofﬁ cer,

Duff & Phelps Investment

Management Co.; President,

Chief Executive Ofﬁ cer and

Chief Investment Ofﬁ cer,

(closed-end utility fund)

KAREN M. BOHN

A/CG–Edina, Minnesota

JOHN D. ERICKSON

Fergus Falls, Minnesota

Former President and

Chief Executive Ofﬁ cer,

KATHRYN O. JOHNSON

C/CG—Hill City, South Dakota

Owner/Principal, Johnson Environmental

Concepts (geochemical consulting ﬁ rm)

CHARLES S. MACFARLANE

Fergus Falls, Minnesota

President and Chief Executive Ofﬁ cer,

Otter Tail Corporation

C/CG—Grand Forks, North Dakota

Retired Executive Vice President,

University of North Dakota

Alumni Association;

University of North Dakota

Foundation (nonproﬁ t)

JOYCE NELSON SCHUETTE

A/C—Walker, Minnesota

Retired Managing Director and

Otter Tail Corporation (utility

and diversiﬁ ed businesses)

Investment Banker, Piper Jaffray & Co.

(ﬁ nancial services)

STEVEN L. FRITZE

A/CG—Eagan, Minnesota

Retired Chief Financial Ofﬁ cer,

Ecolab Inc. (diversiﬁ ed

manufacturing)

JAMES B. STAKE

A/C—Edina, Minnesota

Retired Executive Vice President,

Enterprise Services, 3M Company

(diversiﬁ ed manufacturing)

Committees: A—Audit C—Compensation CG—Corporate Governance

CHARLES S. MACFARLANE

President and

Chief Executive Ofﬁ cer

KEVIN G. MOUG

Chief Financial Ofﬁ cer and

Senior Vice President

GEORGE A. KOECK

Senior Vice President,

General Counsel,

and Corporate Secretary

JENNIFER SMESTAD

Succeeding George Koeck

TIMOTHY J. ROGELSTAD

Senior Vice President,

Electric Platform;

President, Otter Tail

Power Company

JOHN S. ABBOTT

Senior Vice President,

Manufacturing Platform;

President, Varistar

CRIS M. OEHLER

Vice President,

Corporate Communication

PAUL L. KNUTSON

Vice President,

Human Resources

as Vice President, General Counsel,

President, Galeo Group, LLC

Retired Chief Executive Ofﬁ cer,

and Corporate Secretary

(management consulting ﬁ rm)

EX CUTIVE

EX CUTIVE LEADERSHIP

EX CUTIVE

NATHAN PARTAIN

KAREN BOHN

JOHN ERICKSON

STEVEN FRITZE

KATHRYN JOHNSON

CHARLES MACFARLANE

TIMOTHY O’KEEFE

JOYCE SCHUETTE

Left to right: George Koeck, Cris Oehler, John Abbott, Paul Knutson,

Tim Rogelstad, Chuck MacFarlane, Kevin Moug, and Jennifer Smestad

JAMES STAKE

SUMMARY
OF THE Y

CONSOLIDATED OPERATIONS

($ in thousands, except share amounts)

2017

2016

PERCENT
CHANGE

Operating Revenues
Net Income from Continuing Operations
Net Income
Diluted Earnings per Share from Continuing Operations
Diluted Earnings per Share
Dividends per Common Share
Return on Average Common Equity
Book Value per Common Share
Cash Flow from Continuing Operations
Number of Common Shares Outstanding
Number of Common Shareholders
Closing Stock Price
Total Return (share price appreciation plus dividends)
Total Market Value of Common Stock
Total Full-time Employees

$
$
$
$
$
$

849,350
72,119
72,439
1.81
1.82
1.28
10.6%

$
$
$
$
$
$

803,539
62,037
62,321
1.60
1.61
1.25

9.8%

17.62
$
$
173,603
39,557,491
13,053
44.45

17.03
$
$
163,541
39,348,136
13,805
40.80

12.1%

57.9%

$ 1,758,330
2,097

$ 1,605,404
2,054

ELECTRIC PLATFORM ($ in thousands)

Operating Revenues
Total Retail Electric Sales (MWH)
Operating Income
Customers
Gross Plant Investment
Total Assets
Capital Expenditures
Full-time Employees

434,506
4,814,984
90,392
132,146
$ 2,113,574
$ 1,690,224
118,444
$
668

427,349
4,750,421
90,131
131,546
$ 2,010,354
$ 1,622,231
149,648
$
682

5.7
16.3
16.2
13.1
13.0
2.4
8.2
3.5
6.2
0.5
(5.4)
8.9
(79.1)
9.5
2.1

1.7
1.4
0.3
0.5
5.1
4.2
(20.9)
(2.1)

MANUFACTURING PLATFORM (Continuing Operations, $ in thousands)

Operating Revenues
Operating Income
Total Assets
Capital Expenditures
Full-time Employees

$
$
$
$

414,844
43,745
254,253
14,348
1,390

$
$
$
$

376,190
29,911
251,117
11,514
1,331

10.3
46.3
1.2
24.6
4.4

LETTER TO SHAREHOLDERS ORGANIZATION CHART FINANCIAL INFORMATION 10-K FINANCIAL REPORT DIRECTORS AND LEADERSHIP

22 44 55 77 9999

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

CHARLES S. MACFARL ANE

PR ESI DEN T A ND CEO

WE DELIVER SHAREHOLDER VALUE

UTILITY PROVIDES STRENGTH AND GROWTH

Otter Tail Corporation continues to deliver shareholder value

Otter Tail Power Company grew rate base by 5.4 percent in

through two platforms: electric and manufacturing. Both

2017 with major investments in regional transmission projects.

contributed to our excellent 2017 ﬁ nancial results. Both have

Our utility is a 50 percent owner with neighboring utilities

promising futures.

in each of two 345-kilovolt transmission projects that will

We have built our capabilities through important investments—

improve regional reliability and support renewable energy. Both

in rate base, systems, locations, and people. That is why we

lines are designated multi-value projects by the Midcontinent

chose “Driven to Excellence” as the theme for this year’s report.

Independent System Operator, Inc. (MISO), allowing cost

It highlights employee dedication to pursuing quality and

recovery from all customers in MISO’s Upper Midwest footprint.

exceeding customer expectations.

The 70-mile line that extends from Brookings, South Dakota,

Our combined efforts resulted in consolidated net income

to a new substation near Big Stone City, South Dakota, was

and diluted earnings per share from continuing operations

completed on schedule in 2017. The 160-mile line that will

of $72.1 million and $1.81 respectively, compared with

run northwest from the Big Stone Substation to Ellendale,

$62 million and $1.60 in 2016. Earnings per share for 2017

North Dakota, is on schedule for completion in 2019. These

include a reduction of $0.05 related to the Tax Cuts and Jobs

two transmission projects have a combined Otter Tail

Act of 2017. Return on equity was 10.6 percent.

investment of approximately $200 million. Otter Tail Power

Our stock also performed well in 2017. Total return was

Company is managing the Big Stone South-Ellendale project.

12.1 percent, and the dividend yield at year-end was 2.9 percent.

We are pursuing $901 million in capital investments at the

Shareholder value has grown at a compounded annual rate of

utility between 2018 and 2022 that are expected to produce

16.7 percent over the past ﬁ ve years. We have paid dividends

compounded annual rate base growth of 9 percent between

on common stock for 79 years, or 317 consecutive quarters.

2017 and 2022. They include the above-mentioned Big Stone

Our annual indicated dividend rate per share for 2018 is $1.34,

South-Ellendale project and regulated investments in renewable

an increase of 4.7 percent.

and natural gas-ﬁ red generation.

Collectively, employees and leadership remain focused on three

In April 2017 the Minnesota Public Utilities Commission

strategic objectives: Grow our businesses, achieve operational

approved Otter Tail Power Company’s resource plan that

and commercial excellence, and develop our talent. This ongoing

identiﬁ es the most cost-effective combination of resources for

emphasis creates energy that positions us for long-term success.

meeting customers’ needs for reliable service during the next

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

SHAR

TO OUR
HOLDERS

15 years. The plan includes adding wind, natural gas-ﬁ red, and
solar generation. Our aging Hoot Lake coal plant’s planned

Otter Tail Power Company ﬁ led a rate case with the
North Dakota Public Service Commission in November 2017,

retirement, expiring purchased capacity agreements, and load

requesting to increase non-fuel base rates by 8.7 percent, or

growth are driving the resource needs.

approximately $13 million annually. The commission established

As part of implementing our resource plan, our utility has

current rates in 2009 based on 2007 costs. Our proposal

entered into deﬁ nitive agreements to purchase a 150-megawatt

reﬂ ects increased costs to serve customers and investments

wind farm to be built in southeastern North Dakota near

in environmental technologies, wind energy projects, and

Merricourt in 2019. At an estimated cost of approximately

transmission lines that will improve reliability and facilitate

$270 million, it will be the largest capital project in company

efﬁ cient energy markets. The commission granted an interim

history. With this addition, the amount of renewable energy

rate increase of 8.64 percent effective January 2018. We expect

that supplies customers’ electricity needs will be nearly

a ﬁ nal order in the fall of 2018.

30 percent. We continue to be pleased with the performance

Even with the Minnesota rate increase and a potential increase

of our existing wind farms. We expect this new wind farm to

in North Dakota, Otter Tail Power Company’s rates remain

have a low delivered energy price.

among the lowest in the nation. Regulatory Research Associates

We also will construct a 250-megawatt simple-cycle natural

recognized Otter Tail Power Company in May 2017 as one of the

gas-ﬁ red plant near Astoria, South Dakota. We expect the

ﬁ ve lowest price providers among utility operating companies.

project to cost $165 million and to be in service in 2021 with

Throughout its progress on diverse projects, Otter Tail

three to ﬁ ve full-time employees.

Power Company continues to effectively manage day-to-day

The Merricourt and Astoria projects passed several

operations. In 2017 the utility continued to earn high customer

milestones in 2017. Both received advance determination of

satisfaction scores and achieved its lowest number of OSHA

prudence from the North Dakota Public Service Commission.

recordable injuries—thanks to dedicated employees and

The decisions included cost caps that, if exceeded, would

experienced management. We are especially proud that

require approval of any amount over the cap. The Merricourt

the Edison Electric Institute presented Otter Tail Power

project also received its revised North Dakota site permit related

Company with the association’s 2017 Emergency Recovery

to design changes and approval in Minnesota for rider recovery

Award for outstanding restoration efforts related to a 2016

with a cost cap. The Astoria project team ﬁ led applications for

Christmas ice storm.

all major permits in South Dakota. Both projects are proceeding

through MISO’s interconnection process.

MANUFACTURING COMPANIES ARE FOCUSED

Otter Tail Power Company continues to evaluate solar

ON CUSTOMERS, POISED FOR GROWTH

additions of up to 30 megawatts that will meet requirements

The dedication to operational and commercial excellence

in all three state jurisdictions.

in each of our manufacturing platform companies is as

The Minnesota Public Utilities Commission granted Otter Tail

encouraging as it is beneﬁ cial.

Power Company a revenue increase of 5.3 percent based on an

BTD Manufacturing, Inc., contract metal fabricator and our

authorized 9.41 percent return on equity, effective November 2017,

largest manufacturing business, achieved year-over-year net

concluding the rate case we ﬁ led in 2016.

earnings improvement in 2017.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

The company’s customer base in agriculture, energy,

and recreational utility vehicles began to show economic

recovery. Revenue growth coupled with continued operational

improvement allowed BTD to deliver a 22 percent increase in

operating income over 2016.

Our investments in BTD Manufacturing’s Minnesota facilities

are complete, providing additional capabilities and capacity,

and BTD’s expansion to the Southeast is creating new

opportunities.

The Fabricator, a leading industry publication, recognized

BTD with its Industry Award, highlighting BTD’s shop ﬂ oor

improvements, safety, customer satisfaction, new products

and services, and philanthropic activities.

T.O. Plastics, our plastics thermoforming manufacturer,

achieved 8 percent overall sales growth and a 14 percent

increase in operating income compared with 2016. The

company accomplished this through deeper penetration into

its primary market, horticulture containers, and a renewed

focus on the life sciences market.

Northern Pipe Products and Vinyltech, PVC pipe

manufacturing companies in our plastics segment, continued

their exceptional operational performance in 2017. Both

maintained supply continuity and strong customer service

G
N
R
U
T
C
A
F
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A
M

C
R
T
C
E
L
E

OTTER TAIL
POWER COMPANY
Electric utility
Fergus Falls, MN | 1907
Tim Rogelstad
668 employees
www.otpco.com

throughout historic hurricanes and market aftereffects.

LEGEND

Company name
Company description
Headquarters
Year acquired
President
Full-time employees
Website

These unpredictable events, in addition to improved market

conditions, led to 7 percent pipe sales volume growth in 2017.

The increased volume and better pricing environment drove

an $11.5 million year-over-year operating income improvement,

approximately half of which we do not expect to repeat in 2018.

WE ARE DRIVEN TO EXCELLENCE

We remain steadfast in our dedication to enhancing

shareholder value. We work hard to understand where the

world is going, deﬁ ne our role within it, and be clear about

our impact on the people we serve and employ.

We are proud of the year we had in 2017 and are optimistic
about our future. As we keep a close watch on ﬁ nancial and

operational performance, we know success depends on

people with a shared purpose. Thank you to our customers

for working with us. Thank you to our employees for putting

quality into every interaction. And, on behalf of our Board of

Directors and more than 2,000 employees, thank you to our

shareholders for placing your investment and conﬁ dence in us.

Charles S. MacFarlane

President and Chief Executive Ofﬁ cer

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

BTD MANUFACTURING, INC.
Metal fabricator
Detroit Lakes, MN | 1995
Paul Gintner
1,092 employees
www.btdmfg.com

T.O. PLASTICS, INC.
Custom plastic
parts manufacturer
Clearwater, MN | 2001
Mike Vallafskey
137 employees
www.toplastics.com

NORTHERN PIPE
PRODUCTS, INC.
PVC pipe manufacturer
Fargo, ND | 1995
Steve Laskey
95 employees
www.northernpipe.com

VINYLTECH CORPORATION
PVC pipe manufacturer
Phoenix, AZ | 2000
Steve Laskey
66 employees
www.vtpipe.com

REVENUE BY PLATFORM (millions)

NET INCOME FROM CONTINUING
OPERATIONS BY PLATFORM (millions)

MARKET CAPITALIZATION
(millions)

0
5
8
$

9
9
7
3 $
4
7
$

4
0
8
$

0
8
7
$

0
1
7
$

5
9
5
$

3
1
6
$

6
5
6
4 $
8
5
4 $
1
5
$

$1,000

$750

$500

$250

$80

$60

$40

$20

7
5
$

4
4
$

3
1
$

9
4
$

8
3
$

1
1
$

9
5
$

9
4
$

2
6
$

0
5
$

0
1
$

2
1
$

2
7
$

9
4
$

3
2
$

8
5
7
,
1
$

5
0
6
,
1
$

2
5
1
,
1
$

8
0
0
,
1
$

2
6
0
,
1
4 $
0
9
$

$2,000

$1,500

$1,000

$500

07 08 09 10 11

12 13 14 15 16 17

Electric

Manufacturing

Total Continuing Operations
Electric
Manufacturing (including unallocated corporate costs)

GROWTH OF $1,000 INVESTMENT IN OTTER TAIL
COMMON STOCK MADE DECEMBER 31, 2007
(with dividends reinvested)

$2,500

$2,000

$1,500

$1,000

0
0
0
,
1
$

$500

3
2
0
2
0 $
0
8
,
1
$

8
5
2
,
1
$

2
3
1
,
1
$

2
4
1
,
1
5 $
3
9
$

8
8
7
$

7
5
7
$

3
8
7
$

1
0
7
$

DIVIDEND PAYMENT HISTORY

DIVIDEND PAYOUT RATIO

$1.25

$1.00

$0.75

$0.50

$0.25

8
2
.
1
$

$2.00

%
6
8

%
7
7

%
8
7

100%

%
0
7

75%

$1.50

$1.00

$0.50

1
2
.
1
$

3
2
.
1
$

5
2
.
1
$

8
2
.
1
$

9
1
.
1
$

50%

25%

07 08 09 10 11

12 13 14 15 16 17

38 42 47 52 57 62 67 72 77 82 87 92 97 02 07 12 17

13 14 15 16 17

Dividend

Payout Ratio

6
2
1
$

9
0
1
$

1
1
1
$

0
9
$

7
8
$

0
0
1
$

6
7
$

6
3
$

4
2
$

2
2
$

1
2
$

OPERATING INCOME BY PLATFORM (millions, pre-tax)

$120

$90

$60

$30

4
9
$

1
6
$

2
6
$

3
3
$

2
3
$

5
7
$

3
6
$

5
6
$

0
6
$

6
4
$

7
5
$

5
5
$

0
5
$

7
3
$

4
1
$

2
$

0
$

2
1
$

)
3
1
$
(

Consolidated

Electric

Manufacturing (including unallocated corporate costs)

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

SELECTED COMMON SHARE DATA

Market Price:
High
Low
Common Price/Earnings Ratio:
High
Low
Book Value per Common Share

SELECTED DATA AND RATIOS

$
$

Interest Coverage before Taxes (1)
Effective Income Tax Rate (percent) (2)
Return on Capitalization Including Short-term Debt (percent)
Return on Average Common Equity (percent) (3)
Dividend Payout Ratio (percent)
Capital Ratio (percent):
Short-term and Long-term Debt
Preferred Stock and Other Equity
Common Equity

2017

48.65
35.65

26.7
19.6
17.62

2017

4.2x
27
7.8
10.6
70

46.4
—
53.6
100.0

2016

2015

2014

2013

2012

$
$

42.55
25.80

26.4
16.0
17.03

2016

3.5x
24
7.5
9.8
78

46.5
—
53.5
100.0

$
$

33.44
24.82

21.2
15.7
15.98

2015

3.5x
27
7.6
10.1
78

48.8
—
51.2
100.0

$
$

32.72
26.53

20.8
16.9
15.39

2014

3.4x
23
8.0
10.4
77

47.0
—
53.0
100.0

31.88
25.17

22.9
18.1
14.75

2013

3.1x
20
7.7
9.5
86

45.1
—
54.9
100.0

25.25
20.70

—
—
14.43

2012

2.6x
13
8.1
(1.1)
—

43.8
1.6
54.6
100.0

Notes: (1) Continuing Operations.

(2) Continuing Operations; see note 13 to consolidated financial statements in 2017 Annual Report on Form 10-K.
(3) Earnings available for common shares divided by the 13-month average of month-end common equity balances.

SELECTED ELECTRIC OPERATING DATA

2017

2016

2015

2014

2013

2012

Revenues (thousands)
Residential
Commercial and Farms
Industrial
Sales for Resale
Other Electric
Total Electric
Kilowatt-hours Sold (thousands)
Residential
Commercial and Farms
Industrial
Other
Total Retail
Sales for Resale
Total
Annual Retail Kilowatt-hour Sales Growth (percent)
Heating Degree Days (4)
Cooling Degree Days (5)
Average Revenue per Kilowatt-hour
Residential
Commercial and Farms
Industrial
All Retail
Customers
Residential
Commercial and Farms
Industrial
Other
Total Electric Customers
Residential Sales
Average Kilowatt-hours per Customer (6)
Average Revenue per Residential Customer
Depreciation Reserve (thousands)
Electric Plant in Service
Depreciation Reserve
Reserve to Electric Plant (percent)
Composite Depreciation Rate (percent)
Peak Demand and Net Generating Capability
Peak Demand (kilowatts)
Net Generating Capability (kilowatts): (7)
Steam
Wind
Combustion Turbines
Hydro
Total Owned Generating Capability

$ 117,438
132,677
120,171
5,173
59,078
$ 434,537

1,243,194
1,586,225
1,920,482
65,083
4,814,984
203,397
5,018,381
1.4
5,931
380

9.45¢
8.36¢
6.26¢
7.73¢

104,038
27,062
51
995
132,146

$ 115,782
135,813
116,561
4,584
54,643
$ 427,383

1,220,946
1,598,668
1,866,726
64,081
4,750,421
190,288
4,940,709
3.4
5,314
451

9.48¢
8.50¢
6.24¢
7.82¢

103,570
26,919
44
1,013
131,546

$ 116,279
128,406
108,331
2,685
51,430
$ 407,131

1,272,912
1,585,037
1,668,958
66,697
4,593,604
113,057
4,706,661
(2.2)
5,633
483

9.13¢
8.11¢
6.49¢
7.83¢

103,307
26,777
47
1,018
131,149

$ 119,730
138,126
93,841
12,191
43,855
$ 407,743

1,386,104
1,708,570
1,531,684
68,704
4,695,062
290,757
4,985,819
4.6
7,205
367

8.64¢
8.08¢
6.13¢
7.63¢

102,771
26,672
47
1,000
130,490

$ 113,434
125,965
78,998
16,461
38,682
$ 373,540

1,378,859
1,685,046
1,357,026
66,610
4,487,541
643,878
5,131,419
5.8
7,344
510

8.23¢
7.48¢
5.82¢
7.23¢

102,510
26,629
45
1,004
130,188

$ 104,145
115,299
79,969
14,377
36,975
$ 350,765

1,253,567
1,566,747
1,355,876
64,599
4,240,789
565,274
4,806,063
(1.2)
5,356
648

8.31¢
7.36¢
5.90¢
7.20¢

102,204
26,522
42
1,018
129,786

11,962
$ 1,161.25

11,895
$ 1,128.22

12,460
$ 1,175.08

13,714
$ 1,197.87

13,488
$ 1,116.22

12,293
$ 1,050.25

$ 1,981,018
$ 662,431
33.4
2.74

$ 1,860,357
$ 622,657
33.5
2.88

$ 1,820,763
$ 592,001
32.5
2.61

$ 1,545,112
$ 584,956
37.9
2.89

$ 1,460,884
$ 554,818
38.0
2.96

$ 1,423,303
$ 526,467

37.0
2.98

906,917

903,462

896,706

873,842

863,561

823,591

547,600
138,000
109,900
2,800
798,300

545,700
138,000
108,100
2,500
794,300

546,300
138,000
108,500
2,500
795,300

556,400
138,000
107,800
2,500
804,700

554,600
138,000
104,900
2,600
800,100

547,300
138,000
108,000
2,800
796,100

Notes: (4) Based on 55 degrees Fahrenheit base and average method.
(5) Based on 65 degrees Fahrenheit base and average method.
(6) Based on average number of customers during the year.
(7) Measurement of summer net dependable capacity under MISO.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2017

Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from _____________________to_____________________

Commission File Number 0-53713

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

MINNESOTA
(State or other jurisdiction of incorporation or organization)

27-0383995
(I.R.S. Employer Identification No.)

215 SOUTH CASCADE STREET, BOX 496, FERGUS FALLS, MINNESOTA

(Address of principal executive offices)

56538-0496
(Zip Code)

Registrant’s telephone number, including area code: 866-410-8780

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Name of each exchange on which registered

COMMON SHARES, par value $5.00 per share

The NASDAQ Stock Market LLC

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File
required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained,
to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting com-
pany. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in
Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer
Non-Accelerated Filer
(Do not check if a smaller reporting company)

Accelerated Filer
Smaller Reporting Company

Emerging Growth Company

If an emerging growth company, indicate by checkmark if the registrant has elected not to use the extended transition period for complying with
any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes

The aggregate market value of common stock held by non-affiliates, computed by reference to the last sales price on June 30, 2017 was
$1,500,154,049.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 39,626,594
Common Shares ($5 par value) as of February 8, 2018.

Documents Incorporated by Reference: Proxy Statement for the 2018 Annual Meeting-Portions incorporated by reference into Part III

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

FORM
10-K

TABLE OF CONTENTS

DESCRIPTION

PAGE
Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

PART I

ITEM 1.

ITEM 1A.

ITEM 1B.

ITEM 2.

ITEM 3.

Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Unresolved Staff Comments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

ITEM 3A.

Executive Officers of the Registrant (as of February 20, 2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

ITEM 4.

Mine Safety Disclosures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

PART II

ITEM 5.

ITEM 6.

ITEM 7.

Market for Registrant’s Common Equity, Related Stockholder Matters And Issuer Purchases of Equity Securities . . . . . . . 30

Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

ITEM 7A.

Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

ITEM 8.

Financial Statements and Supplementary Data:

Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Consolidated Statements of Income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Consolidated Statements of Comprehensive Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Consolidated Statements of Common Shareholders’ Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

Consolidated Statements of Capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Notes to Consolidated Financial Statements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Supplementary Financial Information—Quarterly Information. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

ITEM 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . 88

ITEM 9A.

Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

ITEM 9B.

Other Information. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

PART III

ITEM 10.

ITEM 11.

ITEM 12.

ITEM 13.

ITEM 14.

PART IV

ITEM 15.

ITEM 16.

Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. . . . . . . . . . . . . . . . . 89

Certain Relationships and Related Transactions and Director Independence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Principal Accountant Fees and Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

Form 10-K Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

Signatures

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

DEFINITIONS

The following abbreviations or acronyms are used in the text.
References in this report to “the Company”, “we”, “us” and “our” are to Otter Tail Corporation.

MNCIP
MNDOC
MPCA
MPU Act
MPUC
MRO
MVP
MW
NAAQS
NAEMA
NDPSC
NDRRA
NERC
NETOs
NPDES
Northern Pipe
NOx
NSPS
OTP
PACE
ppb
PSD
PTCs
PVC
ROE
RSG
RTO Adder

SDPUC
SEC
SF6
SO2
SPP
Standex
T.O. Plastics
TCR
TCJA
Varistar
VIE
Vinyltech
WIIN

Minnesota Conservation Improvement Program
Minnesota Department of Commerce
Minnesota Pollution Control Agency
The Minnesota Public Utilities Act
Minnesota Public Utilities Commission
Midwest Reliability Organization
Multi-Value Project
megawatts
National Ambient Air Quality Standards
North American Energy Marketers Association
North Dakota Public Service Commission
North Dakota Renewable Resource Adjustment
North American Electric Reliability Corporation
New England Transmission Owners
National Pollutant Discharge Elimination System
Northern Pipe Products, Inc.
nitrogen oxide
New Source Performance Standards
Otter Tail Power Company
Partnership in Assisting Community Expansion
parts per billion
Prevention of Significant Deterioration
Production Tax Credits
Polyvinyl Chloride
Return on Equity
Revenue Sufficiency Guarantee
Incentive of additional 50-basis points for Regional
Transmission Organization participation
South Dakota Public Utilities Commission
Securities and Exchange Commission
sulfur hexaflouride
sulfur dioxide
Southwest Power Pool
Standex International Corporation
T.O. Plastics, Inc.
Transmission Cost Recovery
2017 Tax Cuts and Jobs Act
Varistar Corporation
Variable Interest Entity
Vinyltech Corporation
Water Infrastructure Improvements for the Nation

ADP
AFUDC
ALJ
AQCS
ARO
ASC
ASC 606

ASC 718
ASC 820
ASC 980
ASM
ASU
BACT
BTD
Btu
CAA
CCMC
CCR
CIP
CO2
CON
CPEC
CPP
CSAPR
CWIP
D.C. Circuit

DRR
ECR
EDF
EEI
EEP
EPA
ESSRP
Exchange Act
FASB
FCA
FERC
Foley
GAAP

GHG
Impulse
IRP
JPMS
kV
kW
kwh
LSA
MATS
MISO
MISO Tariff

Advance Determination of Prudence
Allowance for Funds Used During Construction
Administrative Law Judge
Air Quality Control System
Accumulated Asset Retirement Obligation
Accounting Standards Codification
ASC Topic 606—Revenue from Contracts with
Customers
ASC Topic 718—Compensation—Stock Compensation
ASC Topic 820—Fair Value Measurement
ASC Topic 980—Regulated Operations
Ancillary Services Market
Accounting Standards Update
Best-Available Control Technology
BTD Manufacturing, Inc.
British Thermal Unit
Clean Air Act
Coyote Creek Mining Company, L.L.C.
Coal Combustion Residuals
Conservation Improvement Program
carbon dioxide
Certificate of Need
Central Power Electric Cooperative
Clean Power Plan
Cross-State Air Pollution Rule
Construction Work in Progress
United States Court of Appeals for the District
of Columbia
Data Requirement Rule
Environmental Cost Recovery
EDF Renewable Development, Inc.
Edison Electric Institute
Energy Efficiency Plan
Environmental Protection Agency
Executive Survivor and Supplemental Retirement Plan
The Securities Exchange Act of 1934
Financial Accounting Standards Board
Fuel Clause Adjustment
Federal Energy Regulatory Commission
Foley Company
Generally Accepted Accounting Principles in the
United States
Greenhouse Gas
Impulse Manufacturing, Inc.
Integrated Resource Plan
J.P. Morgan Securities LLC
kiloVolt
kiloWatt
kilowatt-hour
Lignite Sales Agreement
Mercury and Air Toxics Standards
Midcontinent Independent System Operator, Inc.
MISO Open Access Transmission, Energy and
Operating Reserve Markets Tariff

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

PART I

ITEM 1. Business

(a) General Development of Business

Otter Tail Power Company was incorporated in 1907 under the laws of
the State of Minnesota. In 2001, the name was changed to “Otter Tail
Corporation” to more accurately represent the broader scope of
consolidated operations and the name Otter Tail Power Company
(OTP) was retained for use by the electric utility. On July 1, 2009
Otter Tail Corporation completed a holding company reorganization
whereby OTP, which had previously been operated as a division of
Otter Tail Corporation, became a wholly owned subsidiary of the new
parent holding company named Otter Tail Corporation (the Company).
The new parent holding company was incorporated in June 2009
under the laws of the State of Minnesota in connection with the
holding company reorganization. The Company’s executive offices
are located at 215 South Cascade Street, P.O. Box 496, Fergus Falls,
Minnesota 56538-0496 and 4334 18th Avenue SW, Suite 200,
P.O. Box 9156, Fargo, North Dakota 58106-9156. The Company’s
telephone number is (866) 410-8780.

The Company makes available free of charge at its website

(www.ottertail.com) its annual reports on Form 10-K, quarterly reports
on Form 10-Q, current reports on Form 8-K, Forms 3, 4 and 5 filed on
behalf of directors and executive officers and any amendments to
these reports filed or furnished pursuant to Section 13(a) or 15(d) of
the Securities Exchange Act of 1934, as soon as reasonably practicable
after such material is electronically filed with or furnished to the
Securities and Exchange Commission (SEC). Information on the
Company’s website is not deemed to be incorporated by reference
into this Annual Report on Form 10-K.

Otter Tail Corporation and its subsidiaries conduct business primarily

in the United States. The Company had approximately 2,097 full-time
employees in its continuing operations at December 31, 2017. The
Company’s businesses have been classified in three segments to be
consistent with its business strategy and the reporting and review
process used by the Company’s chief operating decision maker.
The three segments are Electric, Manufacturing and Plastics.

From 2011 through 2015, the Company sold several businesses in

order to realign its business portfolio to reduce its risk profile and
dedicate a greater portion of its resources toward electric utility
operations. Recent divestitures include:
— In 2012 the Company completed the sale of the assets of its former

wind tower company.

— In 2013 the Company sold substantially all the assets of its former

dock and boatlift company.

— In 2015 the Company sold the assets of AEV, Inc., its former energy
and electrical construction contractor and the Company sold Foley
Company, its former water, wastewater, power and industrial
construction contractor. With the sale of these two companies the
Company eliminated its Construction segment.

On September 1, 2015 the Company acquired the assets of Impulse
Manufacturing Inc. (Impulse) of Dawsonville, Georgia, now operating
under the name BTD-Georgia, for $29.3 million. BTD-Georgia offers a
wide range of metal fabrication services ranging from simple laser
cutting services and high volume stamping to complex weldments
and assemblies for metal fabrication buyers and original equipment
manufacturers.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

The chart below indicates the companies included in each of the

Company’s reporting segments.

ELECTRIC

MANUFACTURING

PLASTICS

Otter Tail Power
Company

BTD
Manufacturing, Inc.

Northern Pipe
Products, Inc.

T.O. Plastics, Inc.

Vinyltech Corporation

— Electric includes the production, transmission, distribution and sale
of electric energy in Minnesota, North Dakota and South Dakota by
OTP. In addition, OTP is a participant in the Midcontinent Independent
System Operator, Inc. (MISO) markets. OTP’s operations have been
the Company’s primary business since 1907.

— Manufacturing consists of businesses in the following manufacturing
activities: contract machining, metal parts stamping, fabrication and
painting, and production of plastic thermoformed horticultural
containers, life science and industrial packaging, and material
handling components. These businesses have manufacturing facilities
in Georgia, Illinois and Minnesota and sell products primarily in the
United States.

— Plastics consists of businesses producing polyvinyl chloride (PVC)
pipe at plants in North Dakota and Arizona. The PVC pipe is sold
primarily in the upper Midwest and Southwest regions of the
United States.

OTP is a wholly owned subsidiary of the Company. The Company’s

manufacturing and plastic pipe businesses are owned by its wholly
owned subsidiary, Varistar Corporation (Varistar). The Company’s
corporate operating costs include items such as corporate staff and
overhead costs, the results of the Company’s captive insurance company
and other items excluded from the measurement of operating segment
performance that are not allocated to its subsidiary companies.
Corporate assets consist primarily of cash, prepaid expenses,
investments and fixed assets. Corporate is not an operating segment.
Rather, it is added to operating segment totals to reconcile to totals
on the Company’s consolidated financial statements.

The Company has lowered its overall risk by investing in rate base

growth opportunities in its Electric segment and divesting certain
nonelectric operating companies that no longer fit the Company’s
portfolio criteria. This strategy has provided a more predictable earnings
stream, improved the Company’s credit quality and preserved its ability
to fund the dividend. The Company’s goal is to deliver annual growth in
earnings per share between four to seven percent over the next several
years, using 2017 diluted earnings per share from continuing operations
as the base for measurement. The growth is expected to come from
the substantial increase in the Company’s regulated utility rate base
and from planned increased earnings from existing capacity in place
at the Company’s manufacturing and plastic pipe businesses, including
the 2015 acquisition of BTD-Georgia and the facilities expansion and
addition of paint services at BTD Manufacturing Inc.’s Minnesota
facilities completed in 2016. The Company will continue to review its
business portfolio to see where additional opportunities exist to
improve its risk profile, improve credit metrics and generate additional
sources of cash to support the growth opportunities in its electric utility.
The Company will also evaluate opportunities to allocate capital to
potential acquisitions in its Manufacturing and Plastics segments. Over
time, the Company expects the electric utility business will provide
approximately 75% to 85% of its overall earnings. The Company expects
its manufacturing and plastic pipe businesses will provide 15% to 25%
of its earnings, and will continue to be a fundamental part of its strategy.
The actual mix of earnings from continuing operations in 2017 was
69% from the electric utility and 31% from the manufacturing and
plastic pipe businesses, including unallocated corporate costs.

The Company maintains criteria in evaluating whether its operating

companies are a strategic fit. The operating company should:
— Maintain a threshold level of net earnings and a return on invested

capital in excess of the Company’s weighted average cost of capital.

— Have a strategic differentiation from competitors and a sustainable

cost advantage.

— Operate within a stable and growing industry and be able to quickly

adapt to changing economic cycles.

— Have a strong management team committed to operational excellence.

For a discussion of the Company’s results of operations, see
“Management’s Discussion and Analysis of Financial Condition and
Results of Operations,” on pages 31 through 46 of this Annual Report
on Form 10-K.

(b) Financial Information about Industry Segments

The Company is engaged in businesses classified into three segments:

Electric, Manufacturing and Plastics. Financial information about the
Company’s segments and geographic areas is included in note 2 of
“Notes to Consolidated Financial Statements” on pages 61 through 62
of this Annual Report on Form 10-K.

ELECTRIC

GENERAL
Electric includes OTP which is headquartered in Fergus Falls, Minnesota,
and provides electricity to more than 130,000 customers in a service
area encompassing 70,000 square miles of western Minnesota, eastern
North Dakota and northeastern South Dakota. The Company derived
51%, 53% and 52% of its consolidated operating revenues and 72%, 81%
and 80% of its consolidated operating income from its Electric segment
for the years ended December 31, 2017, 2016 and 2015, respectively.
The breakdown of retail electric revenues by state is as follows:

State

Minnesota
North Dakota
South Dakota

Total

2017

52.8%
38.5
8.7

2016

53.0%
38.4
8.6

100.0%

The territory served by OTP is predominantly agricultural. The

aggregate population of OTP’s retail electric service area is approximately
230,000. In this service area of 422 communities and adjacent rural
areas and farms, approximately 126,000 people live in communities
having a population of more than 1,000, according to the 2010 census.
The only communities served which have a population in excess of
10,000 are Jamestown, North Dakota (15,427); Bemidji, Minnesota
(13,431); and Fergus Falls, Minnesota (13,138). As of December 31, 2017
OTP served 132,146 customers. Although there are relatively few large
customers, sales to commercial and industrial customers are significant.
One customer accounted for 12% of the 2017 revenue from the Electric
segment.

The following table provides a breakdown of electric revenues by
customer category. All other sources include gross wholesale sales
from utility generation and sales to municipalities.

CAPACITY AND DEMAND
As of December 31, 2017 OTP’s owned net-plant dependable kilowatt
(kW) capacity was:

Baseload Plants

Big Stone Plant
Coyote Station
Hoot Lake Plant

Total Baseload Net Plant

Combustion Turbine and Small Diesel Units

Hydroelectric Facilities

Owned Wind Facilities (rated at nameplate)

Luverne Wind Farm (33 turbines)
Ashtabula Wind Center (32 turbines)
Langdon Wind Center (27 turbines)

Total Owned Wind Facilities

258,100 kW
149,800
139,700

547,600 kW

109,900 kW

2,800 kW

49,500 kW
48,000
40,500

138,000 kW

The baseload net plant capacity for Big Stone Plant and Coyote Station
constitutes OTP’s ownership percentages of 53.9% and 35%, respectively.
OTP owns 100% of the Hoot Lake Plant. During 2017, about 56% of OTP’s
retail kilowatt-hour (kwh) sales were supplied from OTP generating
plants with the balance supplied by purchased power.

In addition to the owned facilities described above, OTP had the
following purchased power agreements in place on December31, 2017:

Purchased Wind Power Agreements (rated at nameplate and greater than 2,000 kW)

Ashtabula Wind III
Edgeley
Langdon

Total Purchased Wind

Purchase of Capacity (in excess of 1 year and 500 kW)

Great River Energy (1)

(1) 80,000 kW through May 2019 and 50,000 kW June 2019—May 2021.

62,400 kW
21,000
19,500

102,900 kW

80,000 kW

OTP has a direct control load management system which provides

some flexibility to OTP to effect reductions of peak load. OTP also
offers rates to customers which encourage off-peak usage.

OTP’s capacity requirement is based on MISO Module E requirements.

OTP is required to have sufficient Zonal Resource Credits to meet
its monthly weather-normalized forecast demand, plus a reserve
obligation. OTP met its MISO obligation for the 2017-2018 MISO
planning year. OTP generating capacity combined with additional
capacity under purchased power agreements (as described above)
and load management control capabilities is expected to meet 2018
system demand and MISO reserve requirements.

FUEL SUPPLY
Coal is the principal fuel burned at the Big Stone, Coyote and Hoot
Lake generating plants. Coyote Station, a mine-mouth facility, burns
North Dakota lignite coal. Hoot Lake Plant and Big Stone Plant burn
western subbituminous coal.

The following table shows the sources of energy used to generate

OTP’s net output of electricity for 2017 and 2016:

2017

2016

Net kwhs % of Total
kwhs

Net kwhs % of Total
kwhs
(Thousands) Generated (Thousands) Generated

Generated

Customer Category

Commercial
Residential
Industrial
All Other Sources

Total

2017

2016

Sources

35.2%
31.1
31.8
1.9

36.1%
30.8
31.0
2.1

Subbituminous Coal
Lignite Coal
Wind and Hydro
Natural Gas and Oil

100.0%

Total

1,440,017
920,451
534,474
36,703

2,931,645

49.1% 1,419,901
844,225
31.4
517,396
18.2
40,257
1.3

50.3%
29.9
18.4
1.4

100.0% 2,821,779

100.0%

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

OTP has the following primary coal supply agreements:

Plant

Coal Supplier

Type of Coal

Expiration Date

Big Stone Plant Contura Coal

Sales, LLC

Big Stone Plant Peabody

COALSALES, LLC

Wyoming
subbituminous

December 31, 2019

December 31, 2018

Coyote Station

Coyote Creek Mining North Dakota
Company, L.L.C.

lignite

December 31, 2040

Hoot Lake Plant Cloud Peak Energy

Resources LLC

Montana
subbituminous

December 31, 2023

The above contracts for Big Stone Plant do not provide for 100% of

Big Stone Plant’s anticipated coal needs in 2018 and 2019.

In October 2012 the Coyote Station owners, including OTP, entered into
a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C.
(CCMC), a subsidiary of The North American Coal Corporation, for the
purchase of coal to meet the coal supply requirements of Coyote Station
for the period beginning in May 2016 and ending in December 2040.
The price per ton being paid by the Coyote Station owners under the
LSA reflects the cost of production, along with an agreed profit and
capital charge. The LSA provides for the Coyote Station owners to
purchase the membership interests in CCMC in the event of certain
early termination events and also at the end of the term of the LSA.
OTP’s coal supply requirements for Hoot Lake Plant are secured

under contract through December 2023.

Railroad transportation services to the Big Stone Plant and Hoot
Lake Plant are provided under a common carrier rate by the BNSF
Railway. The common carrier rate is subject to a mileage-based fuel
surcharge. The basis for the fuel surcharge is the U.S. average price of
retail on-highway diesel fuel. No coal transportation agreement is
needed for Coyote Station as a mine-mouth facility.

The average cost of fuel consumed (including handling charges to

the plant sites) per million British Thermal Units (Btu) for the years
2017, 2016, and 2015 was $2.224, $2.146 and $2.281, respectively.

GENERAL REGULATION
OTP is subject to regulation of rates and other matters in each of the
three states in which it operates and by the federal government for
certain interstate operations.

A breakdown of electric rate regulation by each jurisdiction follows:

Rates

Regulation

2017

2016

% of
Electric
Revenues

% of
% of
Electric
kwh
Sales Revenues

% of
kwh
Sales

MN Retail Sales MN Public Utilities

46.4% 54.0%

47.5% 54.0%

Commission

ND Retail Sales ND Public Service

33.9

37.1

34.4

37.1

Commission

SD Retail Sales SD Public Utilities

7.7

8.9

7.8

8.9

Commission
Federal Energy
Regulatory Commission

Transmission
& Wholesale

Total

12.0

—

10.3

—

100.0% 100.0%

OTP operates under approved retail electric tariffs in all three states

it serves. OTP has an obligation to serve any customer requesting
service within its assigned service territory. The pattern of electric
usage can vary dramatically during a 24-hour period and from season
to season. OTP’s tariffs are designed to recover the costs of providing
electric service. To the extent peak usage can be reduced or shifted to
periods of lower usage, the cost to serve all customers is reduced. In
order to shift usage from peak times, OTP has approved tariffs in all
three states for residential demand control, general service time of use
and time of day, real-time pricing, and controlled and interruptible
service. Each of these specialized rates is designed to improve efficient
use of OTP resources, while giving customers more control over their

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

electric bill. OTP also has approved tariffs in its three service territories
which allow qualifying customers to release and sell energy back to
OTP when wholesale energy prices make such transactions desirable.
With a few minor exceptions, OTP’s electric retail rate schedules
currently provide for adjustments in rates based on the cost of fuel
delivered to OTP’s generating plants, as well as for adjustments based
on the cost of electric energy purchased by OTP. OTP also credits
certain margins from wholesale sales to the fuel and purchased power
adjustment. The adjustments for fuel and purchased power costs are
presently based on a two month moving average in Minnesota and by
the Federal Energy Regulatory Commission (FERC), a three month
moving average in South Dakota and a four month moving average in
North Dakota. These adjustments are applied to the next billing period
after becoming applicable. These adjustments also include an over or
under recovery mechanism, which is calculated on an annual basis in
Minnesota and on a monthly basis in North Dakota and South Dakota.

2017 TAX CUTS AND JOBS ACT (TCJA)
The TCJA reduced the Federal Income Tax rate from 35% to 21%. Currently,
all OTP rates have been developed using a 35% tax rate. The Minnesota
Public Utilities Commission (MPUC), the North Dakota Public Service
Commission (NDPSC), the South Dakota Public Utilities Commission
(SDPUC) and the FERC have all initiated dockets or proceedings to
begin working with utilities to assess the impact of the lower income
tax rate under the TCJA on electric rates, and to develop regulatory
strategies to incorporate the tax change into future rates, if warranted.
The MPUC required its regulated utilities to make filings by January 30,
2018 and February 15, 2018, but has not made a determination on rate
treatment. OTP currently has an active rate case in North Dakota and
anticipates incorporating the impact of the tax changes to North Dakota
rates within that proceeding. The SDPUC required initial comments by
February 1, 2018 and indicated that revenues collected subsequent to
December 31, 2017 would be subject to refund, pending determination
of the impacts of the TCJA. OTP is still assessing these impacts and will
continue to work with the respective Commissions to determine if any
rate adjustments are necessary and, if so, to determine the appropriate
timing and approach for making those adjustments.

MAJOR CAPITAL EXPENDITURE PROJECTS
Below are descriptions of OTP’s major capital expenditure projects that
have had, or will have, a significant impact on OTP’s revenue requirements,
rates and alternative revenue recovery mechanisms, followed by
summaries of the material regulations of each jurisdiction applicable to
OTP’s electric operations, as well as any specific electric rate proceedings
during the last three years with the MPUC, the NDPSC, the SDPUC and
the FERC. The Company’s manufacturing and plastic pipe businesses
are not subject to direct regulation by any of these agencies.

Big Stone South–Ellendale Multi-Value Transmission Project (MVP)—
This is a 345 kiloVolt (kV) transmission line that will extend 163 miles
between a substation near Big Stone City, South Dakota and a substation
near Ellendale, North Dakota. OTP jointly developed this project with
Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc.,
and the parties will have equal ownership interest in the transmission
line portion of the project. MISO approved this project as an MVP under
the MISO Open Access Transmission, Energy and Operating Reserve
Markets Tariff (MISO Tariff) in December 2011. MVPs are designed to
enable the region to comply with energy policy mandates and to
address reliability and economic issues affecting multiple areas within
the MISO region. The cost allocation is designed to ensure the costs of
transmission projects with regional benefits are properly assigned to
those who benefit. Construction began on this line in the second quarter
of 2016 and is expected to be completed in 2019. OTP’s capitalized
costs on this project as of December 31, 2017 were approximately
$90 million, which includes assets that are 100% owned by OTP.

Big Stone South–Brookings MVP—This 345-kV transmission line
extends approximately 70 miles between a substation near Big Stone
City, South Dakota and the Brookings County Substation near Brookings,
South Dakota. OTP and Northern States Power—Minnesota, a subsidiary
of Xcel Energy Inc., jointly developed this project and the parties have
equal ownership interest in the transmission line portion of the project.
MISO approved this project as an MVP under the MISO Tariff in
December 2011. Construction began on this line in the third quarter of
2015 and the line was energized on September 8, 2017. OTP’s capitalized
costs on this project as of December 31, 2017 were approximately
$73 million, which includes assets that are 100% owned by OTP.

Fargo–Monticello 345-kV Project—OTP invested approximately
$81 million and has a 14.2% ownership interest in the jointly-owned
assets of this 240-mile transmission line, and owns 100% of certain
assets of the project. The final phase of this project was energized
on April 2, 2015.

Brookings–Southeast Twin Cities 345-kV Project—OTP invested
approximately $26 million and has a 4.8% ownership interest in this
250-mile transmission line. The MISO granted unconditional approval
of this project as an MVP under the MISO Tariff in December 2011.
The final segments of this line were energized on March 26, 2015.

Big Stone Plant Air Quality Control System (AQCS)—OTP completed
construction and testing of the Big Stone Plant AQCS in the fourth
quarter of 2015 and placed the AQCS into commercial operation on
December 29, 2015. OTP’s capitalized cost of the project, excluding
allowance for funds used during construction, was approximately
$200 million.

Recovery of OTP’s major transmission investments is through the
MISO Tariff (several as MVPs) and, currently, North Dakota and South
Dakota Transmission Cost Recovery (TCR) Riders.

MINNESOTA
Under the Minnesota Public Utilities Act (the MPU Act), OTP is subject to
the jurisdiction of the MPUC with respect to rates, issuance of securities,
depreciation rates, public utility services, construction of major utility
facilities, establishment of exclusive assigned service areas, contracts
and arrangements with subsidiaries and other affiliated interests, and
other matters. The MPUC has the authority to assess the need for large
energy facilities and to issue or deny certificates of need, after public
hearings, within one year of an application to construct such a facility.
Pursuant to the Minnesota Power Plant Siting Act, the MPUC has
authority to select or designate sites in Minnesota for new electric power
generating plants (50,000 kW or more) and routes for transmission
lines (100 kV or more) in an orderly manner compatible with
environmental preservation and the efficient use of resources, and to
certify such sites and routes as to environmental compatibility after
an environmental impact study has been conducted by the Minnesota
Department of Commerce (MNDOC) and the Office of Administrative
Hearings has conducted contested case hearings.

The Minnesota Division of Energy Resources, part of the MNDOC, is

responsible for investigating all matters subject to the jurisdiction of
the MNDOC or the MPUC, and for the enforcement of MPUC orders.
Among other things, the MNDOC is authorized to collect and analyze
data on energy including the consumption of energy, develop
recommendations as to energy policies for the governor and the
legislature of Minnesota and evaluate policies governing the
establishment of rates and prices for energy as related to energy
conservation. The MNDOC also has the power, in the event of energy
shortage or for a long-term basis, to prepare and adopt regulations
to conserve and allocate energy.

2016 General Rate Case—The MPUC rendered its final decision in
OTP’s 2016 general rate case in March 2017 and issued its written
order on May 1, 2017. Pursuant to the order, OTP’s allowed rate of
return on rate base decreased from 8.61% to 7.5056% and its allowed
rate of return on equity decreased from 10.74% to 9.41%. On July 6,
2017 the MPUC denied OTP’s request for reconsideration of certain of
the MPUC’s rulings in the rate case and confirmed its May 1, 2017 order.
The MPUC’s order also included: (1) the determination that all costs

(including FERC allocated costs and revenues) of the Big Stone
South–Brookings and Big Stone South–Ellendale MVP projects will be
included in the Minnesota TCR rider and jurisdictionally allocated to
OTP’s Minnesota customers, and (2) approval of OTP’s proposal to
transition rate base, expenses and revenues from Environmental Cost
Recovery (ECR) and TCR riders to base rate recovery, with the
transition occurring when final rates are implemented. The rate base
balances, expense levels and revenue levels existing in the riders at
the time of implementation of final rates were used to establish the
amounts transitioned to base rates. Certain MISO expenses and
revenues will remain in the TCR rider to allow for the ongoing refund
or recovery of these variable revenues and costs.

Information on interim and final rate increases and interim revenue

refunds accrued is detailed in the tables below:

($ in thousands)

Interim Rates Authorized
April 14, 2016

Final
Rates

Revenue Increase—Annualized based

on Test Year Data

Revenue Percent Increase
Return on Rate Base
Jurisdictional Rate Base based on Test Year Data
Return on Equity

Based on Equity to Total Capital of

Debt to Total Capital

16,816

$ 10,471

9.56%
8.07%

5.34%
7.5056%

$ 483,000

$ 471,000

10.40%
52.50%
47.50%

9.41%
52.50%
47.50%

Interim Revenue (in thousands)

April 16, 2016 through October 31, 2017

Billed
Accrued Refund
Net Interim Revenue
Interest on Refundable Amount
Final Refund

$ 23,289
$
8,779
$ 14,510
265
$
9,044
$

The final interim rate refund, including interest was applied as a credit

to Minnesota customers’ electric bills beginning November 17, 2017.

In addition to the interim rate refund, OTP will be required to refund
the difference between (1) amounts collected under its Minnesota ECR
and TCR riders based on the return on equity (ROE) approved in its most
recent rider update and (2) amounts that would have been collected
based on the lower 9.41% ROE approved in its 2016 general rate case
going back to April 16, 2016, the date interim rates were implemented.
As of October 31, 2017 the revenues collected under the Minnesota ECR
and TCR riders subject to refund due to the lower ROE rate and other
adjustments were $0.9 million and $1.4 million, respectively. These
amounts will be refunded to Minnesota customers over a 12-month
period through reductions in the Minnesota ECR and TCR rider rates in
effect November 1, 2017, as approved by the MPUC. The TCR rate is
provisional and subject to revision under a separate docket.

Integrated Resource Plan (IRP)—Minnesota law requires utilities to

submit to the MPUC for approval a 15-year advance IRP. A resource
plan is a set of resource options a utility could use to meet the service
needs of its customers over a forecast period, including an explanation
of the utility’s supply and demand circumstances, and the extent to
which each resource option would be used to meet those service
needs. The MPUC’s findings of fact and conclusions regarding resource
plans shall be considered prima facie evidence, subject to rebuttal, in

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

Certificate of Need (CON) hearings, rate reviews and other proceedings.
Typically, the filings are submitted every two years.

On April 26, 2017 the MPUC issued an order approving OTP’s 2017-

2031 IRP filing with modifications and setting requirements for the
next resource plan. The approved plan with modifications included the
following items:
— The addition of 200 megawatts (MW) of wind resources in the

2018 to 2020 timeframe.

— The addition of 30 MW of solar resources by 2020 to comply with

Minnesota’s Solar Energy Standard.

— The addition of up to 250 MW of peaking capacity in 2021.
— Average annual energy savings of 46.8 gigawatt-hours (1.6% of

retail sales).

— Modification of OTP’s IRP to include 100 MW to 200 MW of wind in

the 2022 to 2023 timeframe.

The MPUC ordered OTP to file its next IRP no later than June 3, 2019.

Fuel and Purchased Power Costs Recovery—On December 19, 2017,
the MPUC issued an order authorizing the implementation of a new fuel
clause adjustment mechanism to be implemented July 1, 2019. Prior to
implementation, OTP will be required to submit forecasted monthly fuel
cost rates for the twelve-month period beginning July 1, 2019. Upon
approval by the MPUC, those rates will be published in advance of
each year to give customers notice of the next years’ monthly fuel
rates, and those will be the rates OTP will charge per kwh to cover
fuel costs. OTP will track its actual costs throughout the year and then
file an annual report with the MPUC comparing the actual cost per
kwh to the billed cost per kwh to determine if any over or under
collection of costs occurred. OTP would refund any over-collections,
or in the case of an under-collection, need to show prudence of costs
before allowed recovery of under-collections. The refund of any
over-collection or recovery of any under-collection would be handled
through a true-up mechanism. OTP will be working with other
Minnesota utilities, the MNDOC and other stakeholders to address
questions and further develop the mechanism prior to implementation.
On implementation of the order, OTP will be required to reserve
revenues, accrue a liability and refund amounts of fuel and purchased
power and related costs collected in excess of amounts for which it
was granted recovery in its rate case or annual fuel cost adjustment
filing that preceded the annual period of recovery. OTP will no longer be
able to accrue revenue and a regulatory asset for fuel and purchased
power costs incurred in excess of amounts it was allowed to recover
unless and until recovery of those excess amounts has been granted
through a true-up mechanism that will be provided for in a subsequent
order to be issued by the MPUC. This mechanism for recovery of fuel
and purchased power and related costs incurred to serve Minnesota
customers could result in reductions in Electric segment operating
income margins and variability in the Company’s consolidated net
income in future periods if those costs exceed forecasted costs.

Renewable Energy Standards, Conservation, Renewable Resource
Riders—Minnesota law favors conservation over the addition of new
resources. In addition, Minnesota law requires the use of renewable
resources where new supplies are needed, unless the utility proves
that a renewable energy facility is not in the public interest. An existing
environmental externality law requires the MPUC, to the extent
practicable, to quantify the environmental costs associated with each
method of electricity generation, and to use such monetized values in
evaluating generation resources. The MPUC must disallow any
nonrenewable rate base additions (whether within or outside of the state)
or any related rate recovery, and may not approve any nonrenewable
energy facility in an IRP, unless the utility proves that a renewable
energy facility is not in the public interest. The state has prioritized the
acceptability of new generation with wind and solar ranked first, the

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

highest ranking and coal and nuclear ranked fifth, the lowest ranking.
The MPUC’s currently applicable estimate of the range of costs of future
carbon dioxide (CO2) regulation to be used in modeling analyses for
resource plans is $9.00 to $34.00 per ton of CO2 commencing in 2022.
The MPUC is required to annually update these estimates. The MNDOC
and the Minnesota Pollution Control Agency (MPCA) have recommended
the new range to be $5.00 to $25.00 per ton beginning in 2025. The
MPUC will likely rule on this docket during the second quarter of 2018.
Minnesota has a renewable energy standard which requires OTP to

generate or procure sufficient renewable generation such that the
following percentages of total retail electric sales to Minnesota
customers come from qualifying renewable sources: 17% by 2016; 20%
by 2020 and 25% by 2025. In addition, Minnesota law requires 1.5% of
total Minnesota electric sales by public utilities to be supplied by solar
energy by 2020. For a public utility with between 50,000 and 200,000
retail electric customers, such as OTP, at least 10% of the 1.5%
requirement must be met by solar energy generated by or procured
from solar photovoltaic devices with a nameplate capacity of 40 kWs
or less. If approved by the MPUC, individual customer subscriptions to
an OTP-operated community solar garden program of 40 kWs or less
could be applied toward the 10% requirement. OTP has purchased
enough utility-scale solar energy credits to meet its expected
2020 Minnesota obligation. Under certain circumstances and after
consideration of costs and reliability issues, the MPUC may modify or
delay implementation of the standards. OTP has acquired sufficient
renewable resources to currently comply with Minnesota renewable
energy standards. OTP is evaluating potential options for maintaining
compliance and meeting the solar energy standard. Projected capital
expenditures include $30 million for solar generation in 2021. OTP’s
compliance with the Minnesota renewable energy standard will be
measured through the Midwest Renewable Energy Tracking System.
Under the Next Generation Energy Act of 2007, an automatic
adjustment mechanism was established to allow Minnesota electric
utilities to recover investments and costs incurred to satisfy the
requirements of the renewable energy standard. The MPUC is authorized
to approve a rate schedule rider to enable utilities to recover the costs
of qualifying renewable energy projects that supply renewable energy
to Minnesota customers. Cost recovery for qualifying renewable energy
projects can be authorized outside of a rate case proceeding, provided
that such renewable projects have received previous MPUC approval.
Renewable resource costs eligible for recovery may include return on
investment, depreciation, operation and maintenance costs, taxes,
renewable energy delivery costs and other related expenses.

Minnesota Conservation Improvement Programs (MNCIP)—Under
Minnesota law, every regulated public utility that furnishes electric
service must make annual investments and expenditures in energy
conservation improvements, or make a contribution to the state’s
energy and conservation account, in an amount equal to at least
1.5% of its gross operating revenues from service provided in Minnesota.
On May 25, 2016 the MPUC adopted the MNDOC’s proposed changes
to the MNCIP financial incentive. The new model provides utilities an
incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and
10% of 2019 net benefits, assuming the utility achieves 1.7% savings
compared to retail sales. The new model will reduce the MNCIP
financial incentive by approximately 50% compared to the previous
incentive mechanism.

The MNDOC may require a utility to make investments and

expenditures in energy conservation improvements whenever it finds
that the improvement will result in energy savings at a total cost to
the utility less than the cost to the utility to produce or purchase an
equivalent amount of a new supply of energy. Such MNDOC orders
can be appealed to the MPUC. Investments made pursuant to such
orders generally are recoverable costs in rate cases, even though
ownership of the improvement may belong to the property owner

rather than the utility. OTP recovers conservation related costs not
included in base rates under the MNCIP through the use of an annual
recovery mechanism approved by the MPUC.

On July 9, 2015 the MPUC granted approval of OTP’s 2014 financial

incentive of $3.0 million along with an updated surcharge with an
effective date of October 1, 2015.

Based on results from the 2015 MNCIP program year, OTP recognized
a financial incentive of $4.2 million. The 2015 MNCIP program resulted
in an approximate 39% increase in energy savings compared to 2014
program results. On April 1, 2016 OTP requested approval for recovery of
its 2015 MNCIP program costs not included in base rates, a $4.3 million
financial incentive and an update to the MNCIP surcharge from the MPUC.
On July 19, 2016 the MPUC issued an order approving OTP’s request
with an effective date of October 1, 2016.

Based on results from the 2016 MNCIP program year, OTP recognized

MNCIP financial incentives of $5.1 million in 2016, which included a
$0.1 million true-up of 2015 financial incentives earned. The 2016
program resulted in an approximate 18% increase in energy savings
compared to 2015 program results. On March 31, 2017 OTP requested
approval for recovery of its 2016 MNCIP program costs not included in
base rates, $5.0 million in performance incentives and an update to the
MNCIP surcharge from the MPUC. On September 15, 2017 the MPUC
issued an order approving OTP’s request with an effective date of
October 1, 2017.

Based on results from the 2017 MNCIP program year, OTP recognized
a financial incentive of $2.6 million in 2017. The 2017 program resulted
in an approximate 10% decrease in energy savings compared to 2016
program results. OTP will request approval for recovery of its 2017
MNCIP program costs not included in base rates, a $2.6 million
financial incentive and an update to the MNCIP surcharge from the
MPUC by April 1, 2018.

In 2016 the MNDOC opened a docket to investigate how investor-
owned utilities calculate their avoided costs pertaining to transmission
and distribution. Avoided costs are the basis of MNCIP program benefits
which, going forward, will establish OTP’s financial incentive. On May 23,
2016 the MNDOC accepted OTP’s 2017 avoided costs calculation, but
is requiring Minnesota investor-owned utilities to undergo an analysis
of transmission and distribution avoided costs for 2018 and 2019. OTP
is participating in a stakeholder group with the MNDOC, Xcel Energy Inc.,
and Minnesota Power to determine the best method for calculating
avoided costs. On September 29, 2017, MNDOC issued a decision on
utilities’ transmission and distribution avoided costs. The decision did
not require OTP to update avoided costs or cost-effectiveness for the
2017-2019 MNCIP triennial plan. The decision directed OTP to use the
discrete approach methodology to calculate avoided transmission and
distribution costs as part of OTP’s 2020-2022 MNCIP triennial plans.

Transmission Cost Recovery Rider—The MPU Act provides a
mechanism for automatic adjustment outside of a general rate
proceeding to recover the costs of new transmission facilities that
have been previously approved by the MPUC in a CON proceeding,
certified by the MPUC as a Minnesota priority transmission project,
made to transmit the electricity generated from renewable generation
sources ultimately used to provide service to the utility’s retail customers,
or exempt from the requirement to obtain a Minnesota CON. The
MPUC may also authorize cost recovery via such TCR riders for charges
incurred by a utility under a federally approved tariff that accrue from
other transmission owners’ regionally planned transmission projects
that have been determined by the MISO to benefit the utility or
integrated transmission system. The MPU Act also authorizes TCR
riders to recover the costs of new transmission facilities approved by
the regulatory commission of the state in which the new transmission
facilities are to be constructed, to the extent approval is required by the
laws of that state, and determined by the MISO to benefit the utility or
integrated transmission system. Finally, under certain circumstances,

the MPU Act also authorizes TCR riders to recover the costs associated
with distribution planning and investments in distribution facilities to
modernize the utility grid. Such TCR riders allow a return on investment
at the level approved in a utility’s last general rate case. Additionally,
following approval of the rate schedule, the MPUC may approve annual
rate adjustments filed pursuant to the rate schedule. MISO regional
cost allocation allows OTP to recover some of the costs of its
transmission investment from other MISO customers.

On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider
annual update with an effective date of March 1, 2015. OTP filed an
annual update to its Minnesota TCR rider on September 30, 2015
requesting revenue recovery of approximately $7.8 million. A
supplemental filing to the update was made on December 21, 2015
to address an issue surrounding the proration of accumulated deferred
income taxes and, in an unrelated adjustment, the TCR rider update
revenue request was reduced to $7.2 million. On March 9, 2016 the
MPUC issued an order approving OTP’s annual update to its TCR rider,
with an effective date of April 1, 2016.

OTP filed an update to its TCR rider on April 29, 2016 to incorporate
the impact of bonus depreciation for income taxes, an adjusted rate of
return on rate base and allocation factors to align with its 2016 general
rate case request. On July 5, 2016 the MPUC issued an order approving
the proposed rates on a provisional basis, as recommended by the
MNDOC. The proposed rate changes went into effect on September 1,
2016. On October 30, 2017 the MPUC issued an order resetting OTP’s
Minnesota TCR rates in effect since September 1, 2016 to refund
$3.3 million previously collected under the rider, beginning November 1,
2017. The reset rates were approved on a provisional basis in the
Minnesota general rate case docket, subject to revision in a separate
docket.

In OTP’s 2016 general rate case order issued on May 1, 2017, the MPUC

ordered OTP to include, in the TCR rider retail rate base, Minnesota’s
jurisdictional share of OTP’s investment in the Big Stone South–Brookings
and Big Stone South–Ellendale MVP Projects and all revenues received
from other utilities under MISO’s tariffed rates as a credit in its TCR
revenue requirement calculations. In doing so, the MPUC’s order diverts
interstate wholesale revenues that have been approved by the FERC to
offset FERC-approved expenses, effectively reducing OTP’s recovery
of those FERC-approved expense levels. The MPUC-ordered treatment
will result in the projects being treated as retail investments for
Minnesota retail ratemaking purposes. Because the FERC’s revenue
requirements and authorized returns will vary from the MPUC revenue
requirements and authorized returns for the project investments over
the lives of the projects, the impact of this decision will vary over time
and be dependent on the differences between the revenue requirements
and returns in the two jurisdictions at any given time. On August 18, 2017
OTP filed an appeal of the MPUC order with the Minnesota Court of
Appeals to contest the portion of the order requiring OTP to allocate
costs between jurisdictions of the FERC MVP transmission projects in
the TCR rider. OTP believes the MPUC-ordered treatment conflicts with
federal authority over transmission of electricity in interstate commerce
and rates for the transmission of electricity subject to the jurisdiction
of the FERC as set forth in the Federal Power Act of 1935, as amended
(Federal Power Act). The decision is expected in late 2018.

Environmental Cost Recovery Rider—The Minnesota ECR rider provided
for recovery of OTP’s Minnesota jurisdictional share of the revenue
requirements of its investment in the Big Stone Plant AQCS. The ECR
rider provided for a return on the project’s construction work in progress
(CWIP) balance at the level approved in OTP’s 2010 general rate case.
OTP filed its 2015 annual update on July 31, 2015, with a request to
keep the 2014 annual update rate in place. On December 21, 2015 OTP
filed a supplemental filing with updated financial information. The MPUC
issued an order on March 9, 2016 approving OTP’s request to leave the
2014 annual update rate in place. OTP filed an update to its Minnesota

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

ECR rider on April 29, 2016 to incorporate the impact of bonus
depreciation for income taxes, an adjusted rate of return on rate base
and allocation factors to align with its 2016 general rate case request,
with an effective date of September 1, 2016. On July 5, 2016 the MPUC
issued an order approving the proposed rates on a provisional basis.
On October 30, 2017 the MPUC issued an order resetting OTP’s
Minnesota ECR rate in effect since September 1, 2016 to refund
$1.9 million previously collected under the rider, beginning November 1,
2017. In its 2016 general rate case order, the MPUC approved OTP’s
proposal to transition eligible rate base and expense recovery from
the ECR rider to base rate recovery, effective with implementation of
final rates in November 2017.

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a
request with the MPUC to revise its Fuel Clause Adjustment (FCA) rider
in Minnesota to include recovery of reagent and emission allowance
costs. On March 12, 2015 the MPUC denied OTP’s request to revise its
FCA rider to include recovery of these costs. These costs were included
in OTP’s 2016 general rate case in Minnesota and were considered for
recovery either through the FCA rider or general rates. In its 2016
general rate case order issued May 1, 2017 the MPUC again denied
OTP’s request for recovery of test-year reagent costs and emission
allowances in base fuel costs or through the FCA rider. Instead, the
test-year costs will be recovered in general rates and variability of
those costs in excess of amounts included in general rates will only be
recovered to the extent actual kwh sales exceed forecasted kwh sales
used to establish general rates.

Capital Structure Petition—Minnesota law requires an annual filing of
a capital structure petition with the MPUC. In this filing the MPUC
reviews and approves the capital structure for OTP. Once the petition
is approved, OTP may issue securities without further petition or
approval, provided the issuance is consistent with the purposes and
amounts set forth in the approved capital structure petition. The
MPUC approved OTP’s most recent capital structure petition on
September 1, 2017, allowing for an equity to total capitalization ratio
between 47.4% and 58.0%, with total capitalization not to exceed
$1,178,024,000 until the MPUC issues a new capital structure order for
2018. OTP is required to file its 2018 capital structure petition no later
than May 1, 2018.

NORTH DAKOTA
OTP is subject to the jurisdiction of the NDPSC with respect to rates,
services, certain issuances of securities, construction of major utility
facilities and other matters. The NDPSC periodically performs audits
of gas and electric utilities over which it has rate setting jurisdiction to
determine the reasonableness of overall rate levels. In the past, these
audits have occasionally resulted in settlement agreements adjusting
rate levels for OTP.

The North Dakota Energy Conversion and Transmission Facility
Siting Act grants the NDPSC the authority to approve sites in North
Dakota for large electric generating facilities and high voltage
transmission lines. This Act is similar to the Minnesota Power Plant
Siting Act described above and applies to proposed wind energy
electric power generating plants exceeding 500 kW of electricity,
non-wind energy electric power generating plants exceeding 50,000 kW
and transmission lines with a design in excess of 115 kV. OTP is required
to submit a ten-year plan to the NDPSC biennially.

The NDPSC reserves the right to review the issuance of stocks, bonds,
notes and other evidence of indebtedness of a public utility. However,
the issuance by a public utility of securities registered with the SEC is
expressly exempted from review by the NDPSC under North Dakota
state law.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

General Rates—On November 2, 2017 OTP filed a request with the
NDPSC for a rate review and an effective increase in annual revenues
from non-fuel base rates of $13.1 million or 8.72%. In the request, OTP
proposed an allowed return on rate base of 7.97% and an allowed rate
of return on equity of 10.30%. On December 20, 2017 the NDPSC
approved OTP’s request for interim rates to increase annual revenue
collections by $12.8 million, effective January 1, 2018. OTP used a lower
rate of return on equity in the calculation of interim rates based on the
rate of return on equity used in its 2018 test-year rate request.

OTP’s most recent general rate increase in North Dakota of $3.6 million,

or approximately 3.0%, was granted by the NDPSC in an order issued
on November 25, 2009 and effective December 2009. Pursuant to the
order, OTP’s allowed rate of return on rate base was set at 8.62%, and
its allowed rate of return on equity was set at 10.75%.

Renewable Resource Adjustment—OTP has a North Dakota Renewable
Resource Adjustment (NDRRA) which enables OTP to recover the
North Dakota share of its investments in renewable energy facilities it
owns in North Dakota. This rider allows OTP to recover costs associated
with new renewable energy projects as they are completed, along with
a return on investment. The NDPSC approved OTP’s 2014 annual update
to the NDRRA, including a change in rate design from an amount per
kwh consumed to a percentage of a customer’s bill, on March 25, 2015
with an effective date of April 1, 2015. OTP submitted its 2015 annual
update to the NDRRA rider rate on December 31, 2015 with a requested
implementation date of April 1, 2016. On February 25, 2016 OTP made
a supplemental filing to address the impact of bonus depreciation for
income taxes and related deferred tax assets on the NDRRA, as well as
an adjustment to the estimated amount of Federal Production Tax
Credits used. The NDPSC approved the NDRRA 2015 annual update
on June 22, 2016 with an effective date of July 1, 2016. The updated
NDRRA reflects a reduction in the ROE component of the rate from
10.75%, approved in OTP’s most recent general rate case, to 10.50%.
OTP submitted its 2016 annual update to the NDRRA rider rate on
December 30, 2016, requesting a decrease to the NDRRA rate from
7.573% to 7.005%. The NDPSC approved the NDRRA 2016 annual
update on March 15, 2017 with an effective date of April 1, 2017.

In conjunction with OTP’s November 2, 2017 general rate case filing,
OTP submitted an updated proposal to adjust the NDRRA rate to reflect
updated costs and collections, as well as reflect a rate of return and capital
structure level consistent with those proposed in the general rate case.
The NDPSC approved the update to the NDRRA rate in conjunction with
approving the rate case interim rates. The new NDRRA rate increased
from 7.005% to 7.756% with an effective date of January 1, 2018.

Transmission Cost Recovery Rider—North Dakota law provides
a mechanism for automatic adjustment outside of a general rate
proceeding to recover jurisdictional capital and operating costs
incurred by a public utility for new or modified electric transmission
facilities. For qualifying projects, the law authorizes a current return on
CWIP and a return on investment at the level approved in the utility’s
most recent general rate case.

On August 31, 2015 OTP filed its 2015 annual update to its North
Dakota TCR rider rate requesting recovery of approximately $10.2 million
for 2016 compared with $8.5 million for 2015, including costs assessed
by the MISO as well as costs from the Southwest Power Pool (SPP) that
OTP began incurring January 1, 2016. These costs are associated with
OTP’s load connected to the transmission system of Central Power
Electric Cooperative (CPEC). OTP’s load became subject to SPP
transmission-related charges when CPEC transmission assets were added
to the SPP. The NDPSC approved OTP’s 2015 annual update to its TCR
rider rate on December 16, 2015, with an effective date of January 1, 2016.
On September 1, 2016 OTP filed its annual update to the TCR rider

requesting a revenue requirement of $5.7 million, which includes a

reduction of $2.6 million for a projected over-collection for 2016. Primary
drivers of the decrease from the 2015 updated rider rate include the
impact of federal bonus depreciation and unresolved MISO ROE
complaint proceedings. OTP filed a supplemental filing on September 14,
2016, requesting that the over-collection balance be spread over the
next two years for purposes of reducing the volatility of the rates from
year to year. The NDPSC approved the update on December 14, 2016.
The new rates went into effect on January 1, 2017.

On August 31, 2017 OTP filed its annual update to the TCR rider

requesting a revenue requirement of $8.6 million. OTP filed a
supplemental filing on November 2, 2017, reducing its revenue
requirement request by $0.6 million to $8.0 million to reflect the rate
of return and allocation factors used in its submitted general rate case
also filed on November 2, 2017. The NDPSC approved the update for
recovery of the $8.0 million revenue requirement on November 29, 2017.
The new rates went into effect on January 1, 2018.

Environmental Cost Recovery Rider—OTP has an ECR rider in North
Dakota to recover its North Dakota jurisdictional share of the revenue
requirements associated with its investment in the Big Stone Plant AQCS
and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) projects.
The ECR rider provides for a return on investment at the level approved
in OTP’s most recent general rate case and for recovery of OTP’s North
Dakota share of reagent and emission allowance costs.

On March 31, 2015 OTP filed its annual update to the ECR. This update
included a request to increase the ECR rider rate from 7.531% to 9.193%
of base rates. The NDPSC approved the annual update on June 17, 2015
with an effective date of July 1, 2015, along with the approval of recovery
of OTP’s North Dakota jurisdictional share of Hoot Lake Plant MATS
project costs.

On March 31, 2016 OTP filed its annual update to the ECR rider

requesting a reduction in the rate from 9.193% to 7.904% of base rates,
or a revenue requirement reduction from $12.2 million to $10.4 million,
effective July 1, 2016. The rate reduction request was primarily due to
the Company’s 2015 bonus depreciation election for income taxes, which
reduces revenue requirements. The filing was approved on June 22, 2016.

On March 31, 2017 OTP filed its annual update to the ECR rider

requesting a reduction in the rate from 7.904% to 7.633% of base rates,
or a revenue requirement reduction from $10.4 million to $9.9 million,
effective July 1, 2016. The rate reduction request was primarily due to
a reduction in the projects’ unrecovered costs and lower net book values
as a result of depreciation. The filing was approved on July 12, 2017.

In conjunction with OTP’s November 2, 2017 general rate case filing,

OTP submitted an updated proposal to adjust the ECR rider rate to
reflect updated costs and collections, as well as reflect a rate of return
and capital structure level consistent with those proposed in the general
rate case. The NDPSC approved the update to the ECR rider rate in
conjunction with approving the general rate case interim rates. The
new ECR rate decreased from 7.633% to 6.629% with an effective date
of January 1, 2018.

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed
a request with the NDPSC to revise its FCA rider in North Dakota to
include recovery of new reagent and emission allowance costs. On
February 25, 2015 the NDPSC approved recovery of these costs
through modification of the ECR rider, instead of recovery through
the FCA as OTP had proposed. The ECR rider reagent and emissions
allowance charge became effective May 1, 2015.

SOUTH DAKOTA
Under the South Dakota Public Utilities Act, OTP is subject to the
jurisdiction of the SDPUC with respect to rates, public utility services,
construction of major utility facilities, establishment of assigned service
areas and other matters. Under the South Dakota Energy Facility Permit

Act, the SDPUC has the authority to approve sites in South Dakota for
large energy conversion facilities (100,000 kW or more) and most
transmission lines with a design of 115 kV or more.

2010 General Rate Case—OTP’s most recent general rate increase in
South Dakota of approximately $643,000 or approximately 2.32% was
granted by the SDPUC in an order issued on April 21, 2011 and effective
with bills rendered on and after June 1, 2011. Pursuant to the order,
OTP’s allowed rate of return on rate base was set at 8.50%.

Transmission Cost Recovery Rider—South Dakota law provides
a mechanism for automatic adjustment outside of a general rate
proceeding to recover jurisdictional capital and operating costs
incurred by a public utility for new or modified electric transmission
facilities. OTP has a TCR rider in South Dakota to recover its South
Dakota jurisdictional share of the revenue requirements associated
with its investment in new or modified electric transmission facilities.
The SDPUC approved OTP’s 2014 annual update on February 13, 2015
with an effective date of March 1, 2015. OTP filed its 2015 annual update
on October 30, 2015 with a proposed effective date of March 1, 2016. A
supplemental filing was made on February 3, 2016 to true-up the filing
to include the impact of bonus depreciation elected for 2015, the
inclusion of a deferred tax asset relating to a net operating loss and
the proration of accumulated deferred income taxes. This update included
the recovery of new SPP transmission costs OTP began to incur on
January 1, 2016. On February 12, 2016 the SDPUC approved OTP’s annual
update to its TCR rider, with an effective date of March 1, 2016. On
November 1, 2016 OTP filed the annual update to the South Dakota TCR
rider. OTP made a supplemental filing on January 20, 2017 to include
updated costs through December 2016 as well as updated forecast
information. On February 17, 2017 the SDPUC approved OTP’s annual
update to its TCR rider, with an effective date of March 1, 2017. On
November 1, 2017 OTP filed the annual update to the South Dakota
TCR rider with a requested annual revenue requirement of $1.8 million
and effective date of March 1, 2018. A supplemental filing was made
on January 29, 2018 to reflect updated costs and collections and
incorporate the impact of the reduction in the federal corporate
income tax rate from 35% to 21% effective January 1, 2018. The
updated revenue requirement requested is $1,778,992.

Environmental Cost Recovery Rider— OTP has an ECR rider in South
Dakota to recover its South Dakota jurisdictional share of the revenue
requirements associated with its investment in the Big Stone Plant
AQCS and Hoot Lake Plant MATS projects. On August 31, 2015 OTP
filed its annual update to the South Dakota ECR requesting recovery
of approximately $2.7 million in annual revenue. The SDPUC approved
the request on October 15, 2015 with an effective date of November 1,
2015. On August 31, 2016 OTP filed its 2016 update to the ECR rider,
requesting recovery of approximately $2.3 million in annual revenue.
The SDPUC approved the request on October 26, 2016 with an effective
date of November 1, 2016. The lower revenue requirement is a result of
the implementation of federal bonus depreciation taken on the Big Stone
Plant AQCS. On August 31, 2017 OTP filed its 2017 update to the ECR
rider, requesting recovery of approximately $2.1 million in annual revenue.
The SDPUC approved the request on October 13, 2017 with an effective
date of November 1, 2017.

Reagent Costs and Emission Allowances—OTP’s South Dakota
jurisdictional share of reagent costs and emission allowances is
currently being recovered in its South Dakota FCA rider.

Energy Efficiency Plan (EEP)—The SDPUC has encouraged all
investor-owned utilities in South Dakota to be part of an Energy
Efficiency Partnership to significantly reduce energy use. The plan is

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

being implemented with program costs, carrying costs and a financial
incentive being recovered through an approved rider.

On May 1, 2015 OTP filed its 2014 South Dakota EEP Status Report,
financial incentive and surcharge adjustment along with a request for
approval of an incentive of $105,000 and EEP surcharge increase to
$0.00152/kwh. On July 14, 2015 the SDPUC issued a written order
approving OTP’s 2014 EEP Status Report, incentive and surcharge
increases.

On April 29, 2016 OTP filed its 2015 South Dakota EEP Status Report,
financial incentive and surcharge adjustment with the SDPUC. The filing
requested approval of an incentive of $105,900 and a decrease in the
EEP surcharge from $0.00152/kwh to $0.00114/kwh effective July 1,
2016. The SDPUC approved the request. On April 29, 2016 OTP also
filed its 2017-2019 goals and budgets for its South Dakota EEP triennial
plan. For the 2017, 2018 and 2019 EEP planning years, OTP has proposed
energy savings goals and budgets of 3,804,094 kwh and $449,000 in
2017, 3,805,177 kwh and $449,000 in 2018 and 3,806,262 kwh and
$449,000 in 2019. On November 22, 2016 the SDPUC approved OTP’s
2017-2019 EEP triennial plan with certain conditions.

On May 1, 2017 OTP filed its 2016 South Dakota EEP Status Report,
financial incentive and surcharge adjustment with the SDPUC. The filing
requested approval of an incentive of $105,900 and an increase in the
EEP surcharge from $0.00114/kwh to $0.00138/kwh effective July 1,
2017. The SDPUC approved the request on June 21, 2017.

FERC
Wholesale power sales and transmission rates are subject to the
jurisdiction of the FERC under the Federal Power Act. The FERC is an
independent agency with jurisdiction over rates for wholesale electricity
sales, transmission and sale of electric energy in interstate commerce,
interconnection of facilities, and accounting policies and practices.
Filed rates are effective after a one day suspension period, subject to
ultimate approval by the FERC.

Multi-Value Transmission Projects—On December 16, 2010 the FERC
approved the cost allocation for a new classification of projects in the
MISO region called MVPs. MVPs are designed to enable the region to
comply with energy policy mandates and to address reliability and
economic issues affecting multiple transmission zones within the MISO
region. The cost allocation is designed to ensure that the costs of
transmission projects with regional benefits are properly assigned to
those who benefit. On October 20, 2011 the FERC reaffirmed the MVP
cost allocation on rehearing.

Effective January 1, 2012 the FERC authorized OTP to recover 100%

of prudently incurred CWIP and Abandoned Plant Recovery on two
projects approved by MISO as MVPs in MISO’s 2011 Transmission
Expansion Plan: the Big Stone South–Brookings MVP and the Big
Stone South–Ellendale MVP.

On November 12, 2013 a group of industrial customers and other
stakeholders filed a complaint with the FERC seeking to reduce the ROE
component of the transmission rates that MISO transmission owners,
including OTP, may collect under the MISO Tariff. The complainants
sought to reduce the 12.38% ROE used in MISO’s transmission rates to
a proposed 9.15%. The complaint established a 15-month refund period
from November 12, 2013 to February 11, 2015. A non-binding decision
by the presiding Administrative Law Judge (ALJ) was issued on
December 22, 2015 finding that the MISO transmission owners’ ROE
should be 10.32%, and the FERC issued an order on September 28, 2016
setting the base ROE at 10.32%. A number of parties requested
rehearing of the September 2016 order and the requests are pending
FERC action.

On November 6, 2014 a group of MISO transmission owners, including

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

the RTO Adder until the FERC issued its order in the ROE complaint
proceeding. Based on the FERC adjustment to the MISO Tariff ROE
resulting from the November 12, 2013 complaint and OTP’s incentive
rate filing, OTP’s ROE will be 10.82% (a 10.32% base ROE plus the
0.5% RTO Adder) effective September 28, 2016.

On February 12, 2015 another group of stakeholders filed a complaint
with the FERC seeking to reduce the ROE component of the transmission
rates that MISO transmission owners, including OTP, may collect under
the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint
established a second 15-month refund period from February 12, 2015
to May 11, 2016. The FERC issued an order on June 18, 2015 setting the
complaint for hearings before an ALJ, which were held the week of
February 16, 2016. A non-binding decision by the presiding ALJ was
issued on June 30, 2016 finding that the MISO transmission owners’
ROE should be 9.7%. OTP is currently waiting for the issuance of a
FERC order on the second complaint.

Based on the probable reduction by the FERC in the ROE component
of the MISO Tariff, OTP had a $2.7 million liability on its balance sheet as
of December 31, 2016, representing OTP’s best estimate of the refund
obligations that would arise, net of amounts that would be subject to
recovery under state jurisdictional TCR riders, based on a reduced ROE.
MISO processed the refund for the FERC-ordered reduction in the MISO
Tariff allowed ROE for the first 15-month refund period in its February
and June 2017 billings. The refund, in combination with a decision in
the 2016 Minnesota general rate case that affected the Minnesota TCR
rider, has resulted in a reduction in OTP’s accrued MISO Tariff ROE
refund liability from $2.7 million on December 31, 2016 to $1.6 million
as of December 31, 2017.

In June 2014, the FERC adopted a two-step ROE methodology for
electric utilities in an order issued in a complaint proceeding involving
New England Transmission Owners (NETOs). The issue of how to apply
the FERC ROE methodology has been contested in various complaint
proceedings, including the two ROE complaints involving MISO
transmission owners discussed above. In April 2017 the Court of Appeals
for the District of Columbia (D.C. Circuit) vacated and remanded the
FERC’s June 2014 ROE order in the NETOs’ complaint. The D.C. Circuit
found that the FERC had not properly determined that the ROE
authorized for NETOs prior to June 2014 was unjust and unreasonable.
The D.C. Circuit also found that the FERC failed to justify the new ROE
methodology. OTP will await the FERC response to the April 2017 action
of the D.C. Circuit before determining if an adjustment to its accrued
refund liability is required. On September 29, 2017 the MISO transmission
owners filed a motion to dismiss the second complaint based on the
D.C. Circuit decision in the NETO complaint. If the FERC were to act on
a motion to dismiss, it would eliminate the refund obligation from the
second complaint and the ROE from the first complaint would remain
in effect.

Together with as many as 200 utilities, generators and power

marketers, OTP participated in proceedings before the FERC regarding
the calculation, assessment and implementation of MISO Revenue
Sufficiency Guarantee (RSG) charges for entities participating in the
MISO wholesale energy market since that market’s start on April 1, 2005
until the conclusion of the proceedings on May 2, 2015. The proceedings
fundamentally concerned MISO’s application of its MISO RSG rate on
file with the FERC to market participants, revisions to the RSG rate
based on several FERC orders, and the FERC’s decision to not resettle
the markets based on MISO application of the RSG rate to market
participants. Several of the FERC’s orders are on review in a set of
consolidated cases before the D.C. Circuit. The consolidated petitions
at the D.C. Circuit involve multiple petitioners and intervenors. OTP is
an intervenor in these cases. Final briefs were filed in January 2018.
Oral arguments for this case are expected in the spring of 2018 with a
final decision expected late in 2018. MISO has not made available past
billing or resettlement data necessary for determining amounts that
might be payable if the FERC’s decisions are reversed. Therefore, the

Company cannot estimate OTP’s exposure at this time from a final
order reversing the relevant FERC orders, which could have an adverse
effect on the Company’s results of operations.

NAEMA
OTP is a member of the North American Energy Marketers Association
(NAEMA) which is an independent, non-profit trade association
representing entities involved in the marketing of energy or in providing
services to the energy industry. NAEMA has over 150 members with
operations in 48 states and Canada. Power pool sales are conducted
continuously through NAEMA in accordance with schedules filed by
NAEMA with the FERC.

NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION (NERC)
NERC is an international regulatory authority, subject to oversight by
the FERC and governmental authorities in Canada, whose mission is to
assure the reliability of the bulk power system in North America. As an
owner and operator within the bulk power system, OTP is required to
comply with NERC reliability standards, including standards on
cybersecurity and protection of critical infrastructure.

MIDWEST RELIABILITY ORGANIZATION (MRO)
OTP is a member of the MRO. The MRO is a non-profit organization
dedicated to ensuring the reliability and security of the bulk power
system in the north central region of North America, including parts of
both the United States and Canada. MRO began operations in 2005
and is one of eight regional entities in North America operating under
authority from regulators in the United States and Canada through a
delegation agreement with the NERC. The MRO is responsible for:
(1) developing and implementing reliability standards, (2) enforcing
compliance with those standards, (3) providing seasonal and long-term
assessments of the bulk power system’s ability to meet demand for
electricity, and (4) providing an appeals and dispute resolution process.
The MRO region covers roughly one million square miles spanning
the provinces of Saskatchewan and Manitoba, the states of North Dakota,
Minnesota, Nebraska and the majority of territory in the states of
South Dakota, Iowa and Wisconsin. The region includes more than
130 organizations that are involved in the production and delivery of
power to more than 20 million people. These organizations include
municipal utilities, cooperatives, investor-owned utilities, a federal
power marketing agency, Canadian Crown Corporations, independent
power producers and others who have interests in the reliability of the
bulk power system.

To ensure our compliance with NERC standards, the MRO periodically

audits OTP. OTP’s most recent audit began with a notification in
October 2015 and MRO audit staff conducted fieldwork in January
2016. On February 3, 2017 OTP received the final audit report from the
MRO audit team. The MRO found no potential violations at OTP. OTP’s
next audit will take place in the first quarter of 2019.

MISO
OTP is a member of the MISO. As the transmission provider and security
coordinator for the region, the MISO seeks to optimize the efficiency of the
interconnected system, provide regional solutions to regional planning
needs and minimize risk to reliability through its security coordination,
long-term regional planning, market monitoring, scheduling and tariff
administration functions. The MISO covers a broad region containing
all or parts of 15 states and the Canadian province of Manitoba. The
MISO has operational control of OTP’s transmission facilities above
100 kV, but OTP continues to own and maintain its transmission assets.
Through the MISO Energy Markets, MISO seeks to develop options
for energy supply, increase utilization of transmission assets, optimize
the use of energy resources across a wider region and provide greater
visibility of data. MISO aims to facilitate a more cost-effective and
efficient use of the wholesale bulk electric system.

The MISO Ancillary Services Market (ASM) facilitates the provision
of Regulation, Spinning Reserve and Supplemental Reserves. The ASM
integrates the procurement and use of regulation and contingency
reserves with the existing Energy Market. OTP has actively participated
in the market since its commencement.

OTHER
OTP is subject to various federal laws, including the Public Utility
Regulatory Policies Act of 1978 and the Energy Policy Act of 1992
(which are intended to promote the conservation of energy and the
development and use of alternative energy sources) and the Energy
Policy Act of 2005.

COMPETITION, DEREGULATION AND LEGISLATION
Electric sales are subject to competition in some areas from municipally
owned systems, rural electric cooperatives and, in certain respects, from
on-site generators and cogenerators. Electricity also competes with
other forms of energy. The degree of competition may vary from time to
time depending on relative costs and supplies of other forms of energy.
The Company believes OTP is well positioned to be successful in a
competitive environment. A comparison of OTP’s electric retail rates to
the rates of other investor-owned utilities, cooperatives and municipals
in the states OTP serves indicates OTP’s rates are competitive.

Legislative and regulatory activity could affect operations in the future.
OTP cannot predict the timing or substance of any future legislation or
regulation. The Company does not expect retail competition to come to
the states of Minnesota, North Dakota or South Dakota in the foreseeable
future. There has been no legislative action regarding electric retail choice
in any of the states where OTP operates. The Minnesota legislature has
in the past considered legislation that, if passed, would have limited
the Company’s ability to maintain and grow its nonelectric businesses.
OTP is unable to predict the impact on its operations resulting from
future regulatory activities, from future legislation or from future taxes
that may be imposed on the source or use of energy.

ENVIRONMENTAL REGULATION
Impact of Environmental Laws—OTP’s existing generating plants are
subject to stringent federal and state standards and regulations
regarding, among other things, air, water and solid waste pollution. In
the five years ended December 31, 2017 OTP invested approximately
$202 million in environmental control facilities. The 2018 and 2019
construction budgets include approximately $5 million and $4 million,
respectively, for environmental equipment for existing facilities.

Air Quality—Criteria Pollutants—Pursuant to the Clean Air Act (CAA),
the Environmental Protection Agency (EPA) has promulgated national
primary and secondary standards for certain air pollutants.

The primary fuels burned by OTP’s steam generating plants are
North Dakota lignite coal and western subbituminous coal. Hoot Lake
Plant, Big Stone Plant, and Coyote Station are currently operating
within all presently applicable federal and state air quality and
emission standards.

The CAA, in addressing acid deposition, imposed requirements on
power plants in an effort to reduce national emissions of sulfur dioxide
(SO2) and nitrogen oxides (NOx).

The national Acid Rain Program SO2 emission reduction goals are
achieved through a market based system under which power plants
are allocated “emissions allowances” that require plants to either reduce
their SO2 emissions or acquire allowances from others to achieve
compliance. Each allowance is an authorization to emit one ton of SO2.
SO2 emission requirements are currently being met by all of OTP’s
generating facilities without the need to acquire additional allowances
for compliance.

The national Acid Rain Program NOx emission reduction goals are
achieved by imposing mandatory emissions standards on individual

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sources. All of OTP’s generating facilities met the NOx standards
during 2017.

The Cross-State Air Pollution Rule (CSAPR) requires SO2 and NOx
emission reductions in primarily eastern states in order to allow down-
wind states to achieve national ambient air quality standards (NAAQS).
CSAPR’s Phase 1 emission budgets began on January 1, 2015 for the
annual SO2 and NOx programs, with stricter Phase 2 budgets beginning
in 2017.

The CSAPR rule applies to OTP’s Solway gas peaking plant and the

Hoot Lake coal-fired plant in Minnesota. Minnesota is considered a
Group 2 state for SO2 compliance. Any SO2 allowances that need to be
obtained for Hoot Lake Plant will need to be from an entity in a Group 2
state. The impact of the CSAPR rule is anticipated to be minimal due
to the sharp decline in Group 2 SO2 allowance prices since 2016 and
reduced dispatch of Hoot Lake Plant.

On September 7, 2016 the EPA finalized an update to the CSAPR to
address interstate emission transport with respect to the more recent
2008 ozone NAAQS. The updated CSAPR does not apply to Minnesota,
North Dakota and South Dakota.

On October 1, 2015 the EPA announced that it tightened the primary

and secondary NAAQS for ozone from 75 parts per billion (ppb) to
70 ppb. This was at the upper end of the range of which the EPA had
proposed, which was 65 to 70 ppb. On November 16, 2017 EPA issued
a final rule determining that all of the areas in the states in which OTP
operates will be designated as attainment/unclassifiable.

In June 2010, the EPA established a new primary NAAQS for SO2 at
a level of 75 ppb on a 1-hour average. Designations for this standard are
proceeding under several different pathways. For certain large sources
as defined by 2012 emissions, including Big Stone Plant and Coyote
Station, the EPA entered into a consent decree with the Sierra Club/
Natural Resources Defense Council that required the EPA to promulgate
final designations near those sources by July 2, 2016. On June 30, 2016,
the EPA signed a final rule that designated the areas around Big Stone
Plant and Coyote Station as being in attainment/unclassifiable with the
1-hour SO2 NAAQS. Numerous other sources, including Hoot Lake Plant,
are covered by the EPA’s final Data Requirements Rule (DRR) that was
finalized in August 2015. The DRR requires states to provide either
modeling or monitoring data to adequately characterize SO2 emissions
surrounding those sources. Based on modeling, in January 2018, the
EPA published a final determination of attainment/unclassifiable for
the county in which Hoot Lake Plant resides.

Air Quality—Hazardous Air Pollutants—On December 16, 2011 the EPA
signed a final rule to reduce mercury and other air toxics emissions
from power plants known as the MATS rule. With the installation of
new pollution control equipment in 2015, OTP’s affected units are
meeting current requirements. Emissions monitoring equipment and/or
stack testing is being used to verify compliance with the standards.
Litigation surrounding the MATS rule is ongoing despite the expiration
of the compliance deadlines, and the rule remains in effect while the
litigation continues. On April 15, 2016 the EPA issued a supplemental
finding that the MATS rule continues to be “appropriate and necessary”
when considering the costs of compliance. Litigation surrounding this
finding is being held in abeyance while EPA considers whether it
should be maintained, modified or otherwise reconsidered.

Air Quality—EPA New Source Review Enforcement Initiative—In 1998
the EPA announced its New Source Review Enforcement Initiative
targeting coal-fired power plants, petroleum refineries, pulp and paper
mills and other industries for alleged violations of the EPA’s New Source
Review rules. These rules require owners or operators that construct
new major sources or make major modifications to existing sources to
obtain permits and install air pollution control equipment at affected
facilities. Pursuant to the Initiative, the EPA has attempted to determine
if emission sources violated certain provisions of the CAA by making

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major modifications to their facilities without installing state-of-the-art
pollution controls. OTP has not received any recent requests from the
EPA, pursuant to Section 114(a) of the CAA, to provide information
relative to past operation and capital construction projects at its
coal-fired plants.

Air Quality—Regional Haze Program—The Regional Haze Rule requires
emissions reductions from certain sources that are deemed to contribute
to visibility impairment in Class I air quality areas. Based on the
South Dakota Department of Environment and Natural Resources’
determination and the final South Dakota Regional Haze State
Implementation Plan approved by the EPA on March 29, 2012, Big Stone
Plant was required to install Selective Catalytic Reduction and separated
over-fire air to reduce NOx emissions, dry flue gas desulfurization to
reduce SO2 emissions, and a new baghouse for particulate matter
control. The Big Stone Plant compliant AQCS equipment was placed
into commercial operation on December 29, 2015.

The North Dakota Regional Haze State Implementation Plan requires
that Coyote Station reduce its NOx emissions to 0.5 pounds per million
Btu as calculated on a 30-day rolling average basis beginning on July 1,
2018. The control equipment was installed during a spring 2016 outage.

Air Quality—Greenhouse Gas (GHG) Regulation—Combustion of fossil
fuels for the generation of electricity is a considerable stationary source
of CO2 emissions in the United States and globally. OTP is an owner or
part-owner of three baseload, coal-fired electricity generating plants
and three fuel-oil or natural gas-fired combustion turbine peaking
plants with a combined net dependable capacity of 650 MW. In 2017
these plants emitted approximately 2.9 million tons of CO2.

In April 2007, the U.S. Supreme Court issued a decision that

determined that the EPA has authority to regulate CO2 and other GHGs
from automobiles as “air pollutants” under the CAA. The EPA thereafter
conducted a rulemaking to determine whether GHG emissions contribute
to climate change “which may reasonably be anticipated to endanger
public health or welfare.” While this case addressed a provision of the
CAA related to emissions from motor vehicles, a parallel provision of
the CAA applies to stationary sources such as electric generators. The
EPA determined that parallel provision would be automatically triggered
once the EPA began regulating motor vehicle GHG emissions. The first
step in the EPA rulemaking process was the publication of an
endangerment finding in the December 15, 2009 Federal Register
where the EPA found that CO2 and five other GHGs—methane, nitrous
oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride
(SF6)—threaten public health and the environment.

The EPA’s endangerment finding for GHGs did not in and of itself
impose any emission reduction requirements but rather authorized the
EPA to finalize the GHG standards for new light-duty vehicles as part
of the joint rulemaking with the Department of Transportation. These
standards applied to motor vehicles as of January 2011, which the
EPA determined made GHGs “subject to regulation” under the CAA.
According to the EPA, this triggered the Prevention of Significant
Deterioration (PSD) and Title V operating permits programs for
stationary sources of GHGs.

On June 6, 2010 the EPA published a final “tailoring rule” that

phased in application of its PSD and Title V programs to GHG emission
sources, including power plants. The PSD program applies to existing
sources if there is a physical change or change in the method of
operation of the facility that results in a significant net emissions
increase of any pollutant. As a result, PSD does not apply on a set
timeline as is the case with other regulatory programs, but is triggered
when certain activities take place at a major source. If triggered, the
owner or operator of an affected facility must undergo a review which
requires, among other things, the identification and implementation
of best-available control technology (BACT) for the regulated air
pollutants for which there is a significant net emissions increase, and

an analysis of the ambient air quality impacts of the facility.

In June 2012 the United States Court of Appeals for the D.C. Circuit

upheld most of the EPA’s rules regarding the regulation of GHGs
under the CAA, including the tailoring rule. However, in October 2013
the U.S. Supreme Court granted a petition for a writ of certiorari to
review the question of whether the regulation of new motor vehicle
GHG emissions does in fact automatically trigger PSD and Title V
regulation of GHGs for stationary sources. On June 23, 2014 the U.S.
Supreme Court issued its decision that, in summary, held the EPA
exceeded its statutory authority and may not require a PSD or Title V
permit based solely on GHG emissions. However, the U.S. Supreme
Court also said the EPA could continue to require that PSD permits for
sources otherwise subject to PSD based on emissions of conventional
pollutants contain limitations on GHG emissions based on the
application of BACT. The EPA revised its regulations to implement this
ruling and in 2016 proposed a de minimis level of GHG emissions below
which PSD would not apply. OTP does not anticipate making
modifications that would trigger PSD requirements at any of its facilities
or undertaking construction of a new unit that might trigger PSD.

The EPA has developed New Source Performance Standards (NSPS)

for GHGs from new and existing fossil fuel-fired electric generating
units. On October 23, 2015 the EPA published the final NSPS under
section 111(b) of the CAA that requires certain new units (as well as
modified and reconstructed units) to meet CO2 emission standards.
New natural gas combustion turbines are required to meet a standard
of 1,000 lbs. of CO2 per gross megawatt hour averaged over a 12-month
period if they meet the definition of a baseload unit. New natural gas
combined cycle units are anticipated to fit into this category. Simple
cycle combustion turbines are regulated in a non-baseload category
that is required to meet a heat input based standard that can be met
by burning clean fuels such as natural gas. This rule was challenged
by a number of parties and litigation is pending. Therefore, there is
uncertainty regarding the future of the NSPS rules.

GHG performance standards for existing sources are being developed

under CAA Section 111(d) (111(d) Standard). A 111(d) Standard, unlike
those set under CAA Section 111(b), applies to existing sources of a
pollutant. Under Section 111(d), the EPA promulgates emission guidelines
and the states are then given a period of time to develop plans to
implement the standard. The EPA reviews each state-developed standard
and then approves it if the state’s plan comports with the federal
emission guidelines. If the state does not submit a plan or the EPA finds
that the plan is inadequate, the EPA will prescribe a plan for that state.
For both new and existing sources, the EPA must develop a “standard

of performance,” which is defined as:

…a standard for emissions of air pollutants which reflects the degree
of emission limitation achievable through the application of the best
system of emission reduction which (taking into account the cost
of achieving such reduction and any non-air quality health and
environmental impact and energy requirements) the [EPA]
Administrator determines has been adequately demonstrated.

For existing sources, Section 111(d) also requires the EPA to consider,

“among other factors, remaining useful lives of the sources in the
category of sources to which such standard applies.”

On October 23, 2015 the EPA published final Section 111(d) emission
guidelines for existing fossil fuel-fired power plants, termed the Clean
Power Plan (CPP). The final rule used a formula to calculate state goals
that relied on three building blocks: (1) a heat rate improvement at each
coal plant, (2) increased reliance on natural gas combined cycle units,
and (3) increased deployment of renewable energy. These building
blocks were applied to each grid interconnection that resulted in final
national uniform emission rate standards of 1,305 pounds of CO2 per
net megawatt hour for coal plants and 771 pounds of CO2 per net
megawatt hour for natural gas combined cycle plants. The EPA then

translated the rate goals into mass-based goals that can be applied to
existing sources or, if a state chooses, a mass-based goal that applies
to both existing sources and new sources.

A number of states, utilities, and trade groups filed petitions for
review with the D.C. Circuit seeking to overturn the rule, and also moved
to stay the rule. On January 14, 2016 the D.C. Circuit denied the stay
motions. Numerous petitioners then sought an emergency stay in the
U.S. Supreme Court. On February 9, 2016 the U.S. Supreme Court
granted a stay of the CPP, pending disposition of petitions for review
in the D.C. Circuit. The D.C. Circuit heard oral argument on challenges
to the CPP on September 27, 2016 before the full court, and a decision
was expected in the first half of 2017. However, pursuant to Executive
Order 13783, Promoting Energy Independence and Economic Growth,
the EPA was directed to consider suspending, revising or rescinding the
CO2 rules discussed above. Thereafter, the EPA issued notices of its
intent to review these rules pursuant to the Executive Order, and it filed
motions to stay the pending litigation. The D.C. Circuit subsequently
issued orders holding in abeyance the appeals of both the NSPS and
the CPP, pending EPA review. On October 16, 2017 the EPA published
a proposed rule to repeal the CPP, and on December 18, 2017, the EPA
announced an Advance Notice of Proposed Rulemaking to solicit
information in order to inform the EPA as the Agency considers proposing
a future 111(d) rule that is consistent with the legal interpretation
discussed in the proposed repeal rule. Therefore, there is uncertainty
regarding the future of regulation of CO2 under Section 111(d).

Several states and regional organizations have or will develop

state-specific or regional legislative initiatives to reduce GHG emissions
through mandatory programs. In 2007 the state of Minnesota passed
legislation regarding renewable energy portfolio standards that requires
retail electricity providers to obtain 25% of the electric energy sold
to Minnesota customers from renewable sources by the year 2025.
Additionally, in 2013 the state of Minnesota passed a provision that
requires public utilities to generate or procure sufficient electricity
generated by solar energy to serve its retail electricity customers in
Minnesota so that by the end of 2020, at least 1.5% of the utility’s total
retail electric sales to retail customers in Minnesota is generated by
solar energy. The Minnesota legislature set a January 1, 2008 deadline
for the MPUC to establish an estimate of the likely range of costs of
future CO2 regulation on electricity generation. The legislation also set
state targets for reducing fossil fuel use, included goals for reducing
the state’s output of GHGs, and restricted importing electricity that
would contribute to statewide power sector CO2 emission. The MPUC,
in its order dated December 21, 2007, established an estimate of future
CO2 regulation costs at between $4.00 per ton and $30.00 per ton
emitted in 2012 and after. Annual updates of the range are required. For
2017 the range is $9.05 to $43.06 per ton, and the applicable effective
date to begin using CO2 costs in resource planning decisions is 2020.
The MNDOC and MPCA have proposed a range of $5.00 to $25.00 per
ton beginning in 2025 to be used for 2018.

In 2013, Minnesota opened a new docket to investigate the

environmental and socioeconomic costs of externalities associated
with electricity generation. This docket studied the impact of CO2 and
certain criteria pollutants. A final order was issued on January 3, 2018.
The environmental cost values for CO2 range from a low of $8.44 per
ton and a high of $39.76 per ton in 2017 to a low of $15.20 per ton and
a high of $69.48 per ton in 2050. Low, medium, and high values were
also set for various criteria pollutants for rural, metropolitan fringe,
and urban areas in the state.

The states of North Dakota and South Dakota currently have no

proposed or pending legislation related to the regulation of GHG
emissions, but North Dakota and South Dakota have 10% renewable
energy objectives. OTP currently has sufficient renewable generation
to meet the renewable energy objectives in both North Dakota and
South Dakota.

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While the eventual outcome of GHG regulation is unknown, OTP is
taking steps to reduce its carbon footprint and mitigate levels of CO2
emitted in the process of generating electricity for its customers
through the following initiatives:
— Supply efficiency and reliability: Since 2005, SO2, NOx and mercury
emitted from OTP’s fossil fuel-fired plants have decreased 55%, 77%
and 83%, respectively. OTP’s efforts to increase plant efficiency and
add renewable energy to its resource mix have reduced its CO2
intensity. Between 2005 and 2017 OTP decreased its overall system
average CO2 emissions intensity by approximately 26%. Further
reductions are expected with the anticipated replacement of Hoot
Lake Plant generation with natural gas-fired generation in the
2021 timeframe.

— Conservation: Since 1992 OTP has helped its customers conserve more
than 4.3 million cumulative megawatt-hours of electricity, which is
roughly equivalent to the amount of electricity that 358,000 average
homes would use in a year and represents approximately 352% of
the annual energy sales of OTP’s entire residential customer base.
Additionally, OTP’s conservation programs contribute 113 MW of
load reduction to its system.

— Renewable energy: Since 2002, OTP’s customers have been able to
purchase 100% of their electricity from wind generation through
OTP’s Tail Winds program. OTP has access to 102.9 MW of wind
powered generation under power purchase agreements and owns
138 MW of wind powered generation. OTP is exploring options for
meeting a Minnesota legislative mandate requiring Minnesota’s
investor-owned utilities to serve 1.5% of their Minnesota retail
electric sales with solar power by 2020.

— Other: OTP is a participating member of the EPA’s SF6 Emission

Reduction Partnership for Electric Power Systems program, which
proactively is targeting a reduction in emissions of SF6, a potent GHG.
SF6 has a global-warming potential 23,900 times that of CO2. OTP
participates in carbon sequestration research through the Plains CO2
Reduction Partnership through the University of North Dakota’s
Energy and Environmental Research Center. This Partnership is a
collaborative effort of approximately 100 public and private sector
stakeholders working toward a better understanding of the technical
and economic feasibility of capturing and storing anthropogenic
CO2 emissions from stationary sources in central North America.

While the future financial impact of any proposed or pending

litigation or regulation of GHG emissions is unknown at this time, any
capital and operating costs incurred for additional pollution control
equipment or CO2 emission reduction measures, such as the cost of
sequestration or purchasing allowances, or offset credits, or the
imposition of a carbon tax or cap and trade program at the state or
federal level could materially adversely affect the Company’s future
results of operations, cash flows, and possibly financial condition,
unless such costs could be recovered through regulated rates and/or
future market prices for energy.

Water Quality—The Federal Water Pollution Control Act Amendments
of 1972 and amendments thereto, provide for, among other things, the
imposition of effluent limitations to regulate discharges of pollutants,
including thermal discharges, into the waters of the United States, and
the EPA has established effluent guidelines for the steam electric
power generating industry. Discharges must also comply with state
water quality standards.

Effluent limits specific to Hoot Lake Plant and Coyote Station are
incorporated into their National Pollutant Discharge Elimination System
(NPDES) permits. Big Stone Plant is a zero discharge facility and
therefore does not have a NPDES permit. On November 3, 2015 the EPA
published the final rule that sets technology-based effluent limitations
on certain types of discharges. Generally, the final rule establishes new
requirements for wastewater streams from wet flue gas desulfurization,

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fly ash transport, and bottom ash transport. This includes zero discharge
requirements for fly ash and bottom ash transport water. OTP’s facilities
either utilize dry ash handling or use transport water in a closed loop
manner. Therefore, OTP anticipates minimal impact from the rule.

On May 9, 2014 the EPA Administrator signed a final rule implementing
Section 316(b) of the Clean Water Act establishing standards for cooling
water intake structures for certain existing facilities. The final rule
includes seven compliance options, plus a potential “de minimis“ option
that is not well defined. Although the impact of the Hoot Lake Plant
intake structure has been extensively evaluated in two separate studies
both of which showed minimal impact, OTP will need to have state
agency discussions during the renewal of the Hoot Lake Plant NPDES
permit to determine the appropriate path forward. Coyote Station
provided various studies with their next NPDES permit renewal
application, but minimal impact is anticipated since Coyote Station
already uses closed-cycle cooling.

OTP has all federal and state water permits presently necessary for
the operation of the Coyote Station, the Big Stone Plant and the Hoot
Lake Plant.

OTP owns five small dams on the Otter Tail River, which are subject
to FERC licensing requirements. A license for all five dams was issued
on December 5, 1991. In June 2015 OTP notified the FERC of its intent
to relicense these dams. The current FERC license expires in 2021 and
the licensing process takes approximately 5 years. The FERC completed
the scoping meeting in the fall of 2016 and issued a study plan
determination in April 2017. OTP completed the first round of studies
in 2017 and will complete the second round in 2018. These studies will
be followed by the filing of the license application in 2019. OTP expects
the FERC to issue an order on the license application in 2021. Total
nameplate rating (manufacturer’s expected output) of the five dams
is 3,250 kW.

Solid Waste—Permits for disposal of ash and other solid wastes have
been issued for the Coyote Station, the Big Stone Plant and the Hoot
Lake Plant.

On December 19, 2014 the EPA announced a final rule regulating coal

combustion residuals (CCR) under the Resource Conservation and
Recovery Act regulating the disposal of coal ash generated from the
combustion of coal by electric utilities under Subtitle D’s nonhazardous
provisions. The final rule was published on April 17, 2015. The rule
requires OTP to complete certain actions, such as installing additional
groundwater monitoring wells and investigating whether existing
surface impoundments meet defined location restrictions, in order to
determine whether existing surface impoundments should be retired
or retrofitted with liners. The Big Stone Plant and Coyote Station surface
impoundments are currently planned to be replaced with new ash
handling technology in 2018 and 2019. Existing landfill cells can
continue to operate as designed, but future expansions may require
composite liner and leachate collection systems. On December 20, 2016
the Water Infrastructure Improvements for the Nation (WIIN) Act was
signed into law. The WIIN Act allows states to regulate CCR if the state
standards are at least as protective as the EPA CCR Rule. North Dakota
and South Dakota have indicated they plan to incorporate the CCR rule,
but that it will take a multi-year process.

At the request of the MPCA, OTP had an ongoing investigation at its
former, closed Hoot Lake Plant ash disposal sites. The MPCA continues
to monitor site activities under its Voluntary Investigation and Cleanup
Program. OTP completed projects in 2014 through 2017 that removed
the ash in its entirety from all four Voluntary Investigation and
Cleanup Program areas and placed it in OTP’s permitted disposal area.
In 1980 the United States enacted the Comprehensive Environmental
Response, Compensation and Liability Act, commonly known as CERCLA
or the Federal Superfund law, which was reauthorized and amended in
1986. In 1983 Minnesota adopted the Minnesota Environmental Response
and Liability Act, commonly known as the Minnesota Superfund law. In

1988 South Dakota enacted the Regulated Substance Discharges Act,
commonly known as the South Dakota Superfund law. In 1989, North
Dakota enacted the Environmental Emergency Cost Recovery Act.
Among other requirements, the federal and state acts establish
environmental response funds to pay for remedial actions associated
with the release or threatened release of certain regulated substances
into the environment. These federal and state Superfund laws also
establish liability for cleanup costs and damage to the environment
resulting from such release or threatened release of regulated
substances. The Minnesota Superfund law also creates liability for
personal injury and economic loss under certain circumstances. OTP
has not incurred any significant costs to date related to these laws.
OTP is not presently named as a potentially responsible party under
the federal or state Superfund laws.

CAPITAL EXPENDITURES
OTP is continually expanding, replacing and improving its electric
facilities. During 2017 approximately $119 million in cash was invested
for additions and replacements to its electric utility properties. During
the five years ended December 31, 2017 gross electric property
additions, including construction work in progress, were approximately
$699 million and gross retirements were approximately $84 million.
OTP estimates that during the five-year period 2018-2022 it will invest
approximately $901 million for electric construction, including:
— $302 million for renewable wind and solar energy generation projects.
— $161 million for natural gas-fired generation to replace Hoot Lake

Plant capacity.

— $136 million for numerous potential technology and infrastructure
projects to transform future operations, including automated
metering, telecommunications, geographic information systems,
work and asset management systems, financial information systems,
system infrastructure reliability improvements, outage management
systems, and storage projects.

— $35 million for OTP’s Big Stone South–Ellendale 345 kV

transmission line project.

The remainder of the 2018-2022 anticipated capital expenditures is for
asset replacements, additions and improvements across OTP’s generation,
transmission, distribution and general plant. See “Management’s
Discussion and Analysis of Financial Condition and Results of Operations—
Capital Requirements” section for further discussion.

FRANCHISES
At December 31, 2017 OTP had franchises to operate as an electric utility
in substantially all of the incorporated municipalities it serves. All
franchises are nonexclusive and generally were obtained for 20-year
terms, with varying expiration dates. No franchises are required to serve
unincorporated communities in any of the three states that OTP serves.
OTP believes that its franchises will be renewed prior to expiration.

EMPLOYEES
At December 31, 2017 OTP had 668 equivalent full-time employees.
A total of 390 OTP employees are represented by local unions of the
International Brotherhood of Electrical Workers under two separate
contracts expiring on August 31, 2020 and October 31, 2020. OTP has
not experienced any strike, work stoppage or strike vote, and considers
its present relations with employees to be good.

MANUFACTURING

GENERAL
Manufacturing consists of businesses engaged in the following activities:
contract machining, metal parts stamping, fabrication and painting,
and production of plastic thermoformed horticultural containers, life
science and industrial packaging, and material handling components.

The Company derived 27%, 28% and 28% of its consolidated

operating revenues and 11%, 11% and 9% of its consolidated operating
income from the Manufacturing segment for the years ended
December 31, 2017, 2016 and 2015, respectively. Following is a brief
description of each of these businesses:

BTD Manufacturing, Inc. (BTD), with headquarters located in Detroit
Lakes, Minnesota, is a metal stamping and tool and die manufacturer
that provides its services mainly to customers in the Midwest. BTD
stamps, fabricates, welds, paints and laser cuts metal components
according to manufacturers’ specifications primarily for the recreational
vehicle, agricultural, oil and gas, lawn and garden, industrial equipment,
health and fitness and enclosure industries in its facilities in Detroit
Lakes and Lakeville, Minnesota, Washington, Illinois and Dawsonville,
Georgia. BTD’s Illinois facility also manufactures and fabricates parts
for off-road equipment, mining machinery, oil fields and offshore oil rigs,
wind industry components, broadcast antennae and farm equipment.
BTD-Georgia offers a wide range of metal fabrication services ranging
from simple laser cutting services and high volume stamping to complex
weldments and assemblies for metal fabrication buyers and original
equipment manufacturers.

T.O. Plastics, Inc. (T.O. Plastics), located in Otsego and Clearwater,
Minnesota, manufactures and sells thermoformed products for the
horticulture industry throughout the United States. T.O. Plastics also
designs and manufactures quality thermoformed products and
packaging solutions for the medical and life sciences, industrial,
recreation and electronics industries. Examples of products produced
for these industries are clamshell packing, blister packs, returnable
pallets and handling trays for shipping and storing odd-shaped or
difficult-to-handle parts.

PRODUCT DISTRIBUTION
The principal method for distribution of the manufacturing companies’
products is by direct shipment to the customer by common carrier
ground transportation. No single customer or product of the Company’s
manufacturing companies accounted for 10% of the Company’s
consolidated revenue. However, two customers combined accounted
for 36% of the 2017 revenue of the Manufacturing segment.

COMPETITION
The various markets in which the Manufacturing segment entities
compete are characterized by intense competition from both foreign
and domestic manufacturers. These markets have many established
manufacturers with broader product lines, greater distribution
capabilities, greater capital resources, excess capacity, labor
advantages and larger marketing, research and development staffs
and facilities than the Company’s manufacturing entities.

The Company believes the principal competitive factors in its
Manufacturing segment are product performance, quality, price,
technical innovation, cost effectiveness, customer service and breadth
of product line. The Company’s manufacturing entities intend to continue
to compete on the basis of high-performance products, innovative
production technologies, cost-effective manufacturing techniques,
close customer relations and support, and increasing product offerings.

RAW MATERIALS SUPPLY
The companies in the Manufacturing segment use raw materials in the
products they manufacture, including steel, aluminum and polystyrene
and other plastics resins. Both pricing increases and availability of
these raw materials are concerns of companies in the Manufacturing
segment. The companies in the Manufacturing segment attempt to
pass increases in the costs of these raw materials on to their customers.
Increases in the costs of raw materials that cannot be passed on to
customers could have a negative effect on profit margins in the

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COMPETITION
The plastic pipe industry is fragmented and competitive due to the
number of producers, the small number of raw material suppliers and
the fungible nature of the product. Due to shipping costs, competition
is usually regional, instead of national, in scope. The principal factors
of competition are price, service, warranty, and product performance.
Northern Pipe and Vinyltech compete not only against other plastic
pipe manufacturers, but also ductile iron, steel and concrete pipe
producers. Pricing pressure will continue to affect our Plastics
segment operating margins in the future.

Northern Pipe and Vinyltech intend to continue to compete on
the basis of their high quality products, cost-effective production
techniques and close customer relations and support.

MANUFACTURING AND RESIN SUPPLY
PVC pipe is manufactured through a process known as extrusion.
During the production process, PVC compound (a dry powder-like
substance) is introduced into an extrusion machine, where it is heated
to a molten state and then forced through a sizing apparatus to produce
the pipe. The newly extruded pipe is then pulled through a series of
water cooling tanks, marked to identify the type of pipe and cut to
finished lengths. Warehouse and outdoor storage facilities are used
to store the finished product. Inventory is shipped from storage to
distributors and customers by common carrier.

The PVC resins are acquired in bulk and shipped to point of use by
rail car. There are four vendors that Northern Pipe and Vinyltech can
source to supply their PVC resin requirements. Two vendors provided
100% of total resin purchases in 2017 and 2016. The supply of PVC resin
may also be limited primarily due to manufacturing capacity and the
limited availability of raw material components. A majority of U.S. resin
production plants are located in the Gulf Coast region, which is subject
to risk of damage to the plants and potential shutdown of resin
production because of exposure to hurricanes that occur in that part
of the United States. The loss of a key vendor, or any interruption or
delay in the supply of PVC resin, could disrupt the ability of the Plastics
segment to manufacture products, cause customers to cancel orders
or require incurrence of additional expenses to obtain PVC resin from
alternative sources, if such sources were available. Both Northern Pipe
and Vinyltech believe they have good relationships with their key raw
material vendors.

Due to the commodity nature of PVC resin and PVC pipe and the
dynamic supply and demand factors worldwide, historically the markets
for both PVC resin and PVC pipe have been very cyclical with significant
fluctuations in prices and gross margins.

CAPITAL EXPENDITURES
Capital expenditures in the Plastics segment typically include
investments in extrusion machines and support equipment. During
2017, cash expenditures for capital additions in the Plastics segment
were approximately $4 million. Total capital expenditures for the
five-year period 2018-2022 are estimated to be approximately
$19 million to replace existing equipment.

EMPLOYEES
At December 31, 2017 the Plastics segment had 161 full-time employees.
Northern Pipe had 95 full-time employees and Vinyltech had 66 full-time
employees as of December 31, 2017.

Manufacturing segment. Additionally, a certain amount of residual
material (scrap) is a by-product of many of the manufacturing and
production processes used by the Company’s manufacturing companies.
Declines in commodity prices for these scrap materials due to weakened
demand or excess supply can negatively impact the profitability of the
Company’s manufacturing companies as it reduces their ability to
mitigate the cost associated with excess material.

BACKLOG
The Manufacturing segment has backlog in place to support 2018
revenues of approximately $166 million compared with $118 million
one year ago.

CAPITAL EXPENDITURES
Capital expenditures in the Manufacturing segment typically include
additional investments in new manufacturing equipment or expenditures
to replace worn-out manufacturing equipment. Capital expenditures may
also be made for the purchase of land and buildings for plant expansion
and for investments in management information systems. During 2017,
cash expenditures for capital additions in the Manufacturing segment
were approximately $10 million. Total capital expenditures for the
Manufacturing segment during the five-year period 2018-2022 are
estimated to be approximately $53 million.

EMPLOYEES
At December 31, 2017 the Manufacturing segment had 1,229 full-time
employees. There were 1,092 full-time employees at BTD and 137 full-
time employees at T.O. Plastics as of December 31, 2017.

PLASTICS

GENERAL
Plastics consists of businesses producing PVC pipe at plants in North
Dakota and Arizona. The Company derived 22%, 19% and 20% of its
consolidated operating revenues and 24%, 16% and 19% of its
consolidated operating income from the Plastics segment for the
years ended December 31, 2017, 2016 and 2015, respectively.
Following is a brief description of these businesses:

Northern Pipe Products, Inc. (Northern Pipe), located in Fargo, North
Dakota, manufactures and sells PVC pipe for municipal water, rural
water, wastewater, storm drainage systems and other uses in the
northern, midwestern, south-central and western regions of the
United States as well as central and western Canada.

Vinyltech Corporation (Vinyltech), located in Phoenix, Arizona,
manufactures and sells PVC pipe for municipal water, wastewater,
water reclamation systems and other uses in the western, northwestern
and south-central regions of the United States.

Together these companies have the current capacity to produce

approximately 300 million pounds of PVC pipe annually.

CUSTOMERS
PVC pipe products are marketed through a combination of independent
sales representatives, company salespersons and customer service
representatives. Customers for the PVC pipe products consist primarily
of wholesalers and distributors throughout the northern, midwestern,
south-central, western and northwest United States. The principal
method for distribution of the PVC pipe companies’ products is by
common carrier ground transportation. No single customer of the PVC
pipe companies accounts for over 10% of the Company’s consolidated
revenue. However, two customers combined accounted for 38% of the
2017 revenue of the Plastics segment.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

ITEM 1A. Risk Factors

RISK FACTORS AND CAUTIONARY STATEMENTS
Our businesses are subject to various risks and uncertainties. Any of
the risks described below or elsewhere in this Annual Report on Form
10-K or in our other SEC filings could materially adversely affect our
business, financial condition and results of operations.

GENERAL
Federal and state environmental regulation could require us to incur
substantial capital expenditures and increased operating costs.
We are subject to federal, state and local environmental laws and
regulations relating to air quality, water quality, waste management,
natural resources and health safety. These laws and regulations regulate
the modification and operation of existing facilities, the construction and
operation of new facilities and the proper storage, handling, cleanup
and disposal of hazardous waste and toxic substances. Compliance with
these legal requirements requires us to commit significant resources
and funds toward environmental monitoring, installation and operation
of pollution control equipment, payment of emission fees and securing
environmental permits. Obtaining environmental permits can entail
significant expense and cause substantial construction delays. Failure
to comply with environmental laws and regulations, even if caused by
factors beyond our control, may result in civil or criminal liabilities,
penalties and fines.

Existing environmental laws or regulations may be revised and new

laws or regulations may be adopted or become applicable to us.
Revised or additional regulations, which result in increased compliance
costs or additional operating restrictions, particularly if those costs are
not fully recoverable from customers, could have a material effect on
our results of operations.

Volatile financial markets and changes in our debt ratings could
restrict our ability to access capital and increase borrowing costs
and pension plan and postretirement health care expenses.
We rely on access to both short- and long-term capital markets as a
source of liquidity for capital requirements not satisfied by cash flows
from operations. If we are unable to access capital at competitive
rates, our ability to implement our business plans may be adversely
affected. Market disruptions or a downgrade of our credit ratings may
increase the cost of borrowing or adversely affect our ability to access
one or more financial markets.

Disruptions, uncertainty or volatility in the financial markets can also
adversely impact our results of operations, the ability of customers to
finance purchases of goods and services, and our financial condition,
as well as exert downward pressure on stock prices and/or limit our
ability to sustain our current common stock dividend level.

Changes in the U.S. capital markets could also have significant effects

on our pension plan. Our pension income or expense is affected by
factors including the market performance of the assets in the master
pension trust maintained for the pension plan for some of our employees,
the weighted average asset allocation and long-term rate of return of
our pension plan assets, the discount rate used to determine the service
and interest cost components of our net periodic pension cost and
assumed rates of increase in our employees’ future compensation. If
our pension plan assets do not achieve positive rates of return, or if
our estimates and assumed rates are not accurate, our earnings may
decrease because net periodic pension costs would rise and we could
be required to provide additional funds to cover our obligations to
employees under the pension plan.

We could be required to contribute additional capital to the pension
plan in the future if the market value of pension plan assets significantly
declines, plan assets do not earn in line with our long-term rate of
return assumptions or relief under the Pension Protection Act is no
longer granted.

Any significant impairment of our goodwill would cause a decrease
in our asset values and a reduction in our net operating income.
We had approximately $37.6 million of goodwill recorded on our
consolidated balance sheet as of December 31, 2017. We have recorded
goodwill for businesses in our Manufacturing and Plastics business
segments. If we make changes in our business strategy or if market or
other conditions adversely affect operations in any of these businesses,
we may be forced to record an impairment charge, which would lead
to decreased assets and a reduction in net operating performance.
Goodwill is tested for impairment annually or whenever events or
changes in circumstances indicate impairment may have occurred. If
the testing performed indicates that impairment has occurred, we are
required to record an impairment charge for the difference between the
carrying amount of the goodwill and the implied fair value of the goodwill
in the period the determination is made. The testing of goodwill for
impairment requires us to make significant estimates about our future
performance and cash flows, as well as other assumptions. These
estimates can be affected by numerous factors, including changes in
economic, industry or market conditions, changes in business operations,
future business operating performance, changes in competition or
changes in technologies. Any changes in key assumptions or actual
performance compared with key assumptions about our business and
its future prospects or other assumptions could affect the fair value of
one or more business segments, which may result in an impairment
charge. Declines in projected operating cash flows at BTD or the
Plastics segment may result in goodwill impairments that could
adversely affect our results of operations and financial position,
as well as financing agreement covenants.

The inability of our subsidiaries to provide sufficient earnings and
cash flows to allow us to meet our financial obligations and debt
covenants and pay dividends to our shareholders could have an
adverse effect on the Company.
Otter Tail Corporation is a holding company with no significant
operations of its own. The primary source of funds for payment of our
financial obligations and dividends to our shareholders is from cash
provided by our subsidiary companies. Our ability to meet our financial
obligations and pay dividends on our common stock principally depends
on the actual and projected earnings, cash flows, capital requirements
and general financial position of our subsidiary companies, as well as
regulatory factors, financial covenants, general business conditions
and other matters.

Under our $130 million revolving credit agreement we may not permit
the ratio of our Interest-bearing Debt to Total Capitalization to be greater
than 0.60 to 1.00. OTP may not permit the ratio of its Interest-bearing
Debt to Total Capitalization to be greater than 0.60 to 1.00 under its
$170 million revolving credit agreement. Both credit agreements contain
restrictions on the payment of cash dividends on a default or event of
default. As of December 31, 2017 we were in compliance with the debt
covenants.

Under the Federal Power Act, a public utility may not pay dividends
from any funds properly included in a capital account. What constitutes
“funds properly included in a capital account” is undefined in the
Federal Power Act or the related regulations; however, the FERC has
consistently interpreted the provision to allow dividends to be paid as
long as (1) the source of the dividends is clearly disclosed, (2) the
dividend is not excessive and (3) there is no self-dealing on the part of
corporate officials. The MPUC indirectly limits the amount of dividends
OTP can pay to us by requiring an equity-to-total-capitalization ratio
between 47.4% and 58.0% based on OTP’s 2017 capital structure
petition. OTP’s equity-to-total-capitalization ratio, including short-term
debt, was 48.6% as of December 31, 2017.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

While these restrictions are not expected to affect our ability to
pay dividends at the current level in the foreseeable future, there is no
assurance that adverse financial results would not reduce or eliminate
our ability to pay dividends.

We rely on our information systems to conduct our business, and
failure to protect these systems against security breaches or cyber-
attacks could adversely affect our business and results of operations.
Additionally, if these systems fail or become unavailable for any
significant period of time, our business could be harmed.
All of our businesses require us to collect and maintain sensitive
customer data, as well as confidential employee and shareholder
information, which is subject to electronic theft or loss. We also use
third-party vendors to electronically process certain of our business
transactions. The efficient operation of our business is dependent on
computer hardware and software systems. Information systems, both
ours and those of third-parties, are vulnerable to security breach by
computer hackers and cyber terrorists.

The breach of certain business systems could affect our ability to

correctly record, process and report financial information and
transactions. A major cyber incident could result in significant
expenses to investigate and repair security breaches or system
damage and could lead to litigation, fines, other remedial action,
heightened regulatory scrutiny and damage to our reputation. In addition,
the misappropriation, corruption or loss of personally identifiable
information and other confidential data could lead to significant
breach notification expenses and mitigation expenses such as credit
monitoring. We have cybersecurity insurance related to a breach event
covering expenses for notification, credit monitoring, investigation,
crisis management, public relations and legal advice. The policy also
provides coverage for regulatory action defense including fines and
penalties, potential payment card industry fines and penalties and
costs related to cyber extortion. We also maintain property and
casualty insurance that may cover restoration of data, certain physical
damage or third-party injuries caused by potential cybersecurity
incidents. However, damage and claims arising from such incidents may
not be covered or may exceed the amount of any insurance available.
We rely on industry accepted security measures and technology to
securely maintain confidential and proprietary information maintained
on our information systems. In an effort to reduce the likelihood and
severity of cyber intrusions, we have cybersecurity processes and
controls designed to protect and preserve the confidentiality, integrity
and availability of data and systems. However, all these measures and
technology may not adequately prevent security breaches or cyber-
attacks. In addition, the unavailability of the information systems or
failure of these systems to perform as anticipated for any reason could
disrupt our business and could result in decreased performance and
increased overhead costs, causing our business and results of
operations to suffer. Any significant interruption or failure of our
information systems or any significant breach of security due to
cyber-attacks, hacking or internal security breaches could adversely
affect our business and results of operations.

Economic conditions could negatively impact our businesses.
Our businesses are affected by local, national and worldwide economic
conditions. Tightening of credit in financial markets could adversely
affect the ability of customers to finance purchases of our goods and
services, resulting in decreased orders, cancelled or deferred orders,
slower payment cycles, and increased bad debt and customer
bankruptcies. Our businesses may also be adversely affected by
decreases in the general level of economic activity, such as decreases
in business and consumer spending. A decline in the level of economic
activity and uncertainty regarding energy and commodity prices could
adversely affect our results of operations and our future growth.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

If we are unable to achieve the organic growth we expect, our
financial performance may be adversely affected.
We expect much of our growth in the next few years will come from
major capital investment at existing companies. To achieve the organic
growth we expect, we must have access to the capital markets, be
successful with capital expansion programs related to organic growth,
develop new products and services, expand our markets and increase
efficiencies in our businesses. Competitive and economic factors could
adversely affect our ability to do this. If we are unable to achieve and
sustain consistent organic growth, we will be less likely to meet our
revenue growth targets, which, together with any resulting impact on
our net income growth, may adversely affect the market price of our
common shares.

Our plans to grow and realign our business mix through capital
projects, acquisitions and dispositions may not be successful, which
could result in poor financial performance.
As part of our business strategy, we intend to increase capital
expenditures in our existing businesses and to continually assess our
mix of businesses and potential strategic acquisitions or dispositions.
There are risks associated with capital expenditures including not being
granted timely or full recovery of rate base additions in our regulated
utility business, the inability to recover the cost of capital additions
due to an economic downturn, not being granted timely approval of
requested interconnections to the transmission system for planned
generation projects, lack of markets for new products, competition
from producers of lower cost or alternative products, product defects,
loss of customers or other factors. We may not be able to identify
appropriate acquisition candidates or successfully negotiate, finance
or integrate acquisitions. Future acquisitions could involve numerous
risks including: difficulties in integrating the operations, services,
products and personnel of the acquired business; and the potential
loss of key employees, customers and suppliers of the acquired
business. If we are unable to successfully manage these risks, we
could face reductions in net income in future periods.

We may, from time to time, sell assets to provide capital to fund
investments in our electric utility business or for other corporate
purposes, which could result in the recognition of a loss on the sale
of any assets sold and other potential liabilities. The sale of any of
our businesses also exposes us to additional risks associated with
indemnification obligations under the applicable sales agreements
and any related disputes.
As part of our business strategy, we continually assess our business
portfolio to determine if our operating companies continue to meet
our portfolio criteria. A loss on the sale of a business would be
recognized if a company is sold for less than its book value.

In certain transactions we retain obligations that have arisen, or
subsequently arise, out of our conduct of the business prior to the
sale. These obligations are sometimes direct or, in other cases, take
the form of an indemnification obligation to the buyer. These
obligations include such things as warranty, environmental, and the
collection of certain receivables. Unforeseen costs related to these
obligations could result in future losses related to the business sold.

Significant warranty claims and remediation costs in excess of
amounts normally reserved for such items could adversely affect
our results of operations and financial condition.
Depending on the specific product or service, we may provide certain
warranty terms against manufacturing defects and certain materials.
We reserve for warranty claims based on industry experience and
estimates made by management. For some of our products we
have limited history on which to base our warranty estimate. Our
assumptions could be materially different from any actual claim and
could exceed reserve balances.

Expenses associated with the remediation of warranty claims for our
manufacturing businesses, including our former wind tower manufacturer,
could be substantial. The potential exists for multiple claims based on
one defect repeated throughout the production process or for claims
where the cost to repair or replace the defective part is highly
disproportionate to the original cost of the part. If we are required to
cover remediation expenses in addition to our regular warranty
coverage, we could be required to accrue additional expenses and
experience additional unplanned cash expenditures which could
adversely affect our consolidated net income and financial condition.

We are subject to risks associated with energy markets.
Our businesses are subject to the risks associated with energy markets,
including market supply and increasing energy prices. If we are faced
with shortages in market supply, we may be unable to fulfill our
contractual obligations to our retail, wholesale and other customers at
previously anticipated costs. This could force us to obtain alternative
energy or fuel supplies at higher costs or suffer increased liability for
unfulfilled contractual obligations. Any significantly higher than expected
energy or fuel costs would negatively affect our financial performance.

Changes in tax laws, as well as judgments and estimates used in the
determination of tax-related asset and liability amounts, could
materially adversely affect our business, financial condition, results
of operations and prospects.
Our provision for income taxes and reporting of tax-related assets and
liabilities require significant judgments and the use of estimates. Amounts
of tax-related assets and liabilities involve judgments and estimates of
the timing and probability of recognition of income, deductions and tax
credits, including, but not limited to, estimates for potential adverse
outcomes regarding tax positions that have been taken and the ability
to utilize tax benefit carryforwards, such as net operating loss and tax
credit carryforwards. Actual income taxes could vary significantly from
estimated amounts due to the future impacts of, among other things,
changes in tax laws, regulations and interpretations, the financial
condition and results of operations of Otter Tail Corporation, and the
resolution of audit issues raised by taxing authorities. Ultimate resolution
of income tax matters may result in material adjustments to tax-related
assets and liabilities, which could materially adversely affect our
business, financial condition, results of operations and prospects.

Four of our operating companies have single customers that provide
a significant portion of the individual operating company’s and the
business segment’s revenue. The loss of, or significant reduction in
revenue from, any one of these customers would have a significant
negative financial impact on the operating company and its business
segment, and could have a significant negative financial impact on
the Company.
While no single customer of the Company provides more than 10%
of consolidated revenue, each of the Company’s segments have large
customers that provide over 10% of the operating company’s and its
segment’s revenue. In 2017 one customer accounted for 12% of Electric
segment revenue, two customers accounted for a total of 36% of
Manufacturing segment revenue and two customers accounted for
38% of Plastics segment revenue. The loss of any one of these
customers, or a significant decline in sales to these customers, would
have a significant negative impact on the operating company’s and
its business segment’s financial position and results of operations,
and could have a significant negative impact on the Company’s
consolidated financial position and results of operations.

ELECTRIC
We may experience fluctuations in revenues and expenses related
to our electric operations, which may cause our financial results to
fluctuate and could impair our ability to make distributions to

shareholders or scheduled payments on our debt obligations,
or to meet covenants under our borrowing agreements.
A number of factors, many of which are beyond our control, may
contribute to fluctuations in our revenues and expenses from electric
operations, causing our net income to fluctuate from period to period.
These risks include fluctuations in the volume and price of sales of
electricity to customers or other utilities, which may be affected by
factors such as mergers and acquisitions of other utilities, geographic
location of other utilities, transmission costs (including increased costs
related to operations of regional transmission organizations),
interconnection costs, changes in the manner in which wholesale power
is sold and purchased, unplanned interruptions at OTP’s generating
plants, the effects of regulation and legislation, demographic changes
in OTP’s customer base and changes in OTP’s customer demand or
load growth. Electric wholesale margins have been significantly and
adversely affected by increased efficiencies in the MISO market. Other
risks include weather conditions or changes in weather patterns
(including severe weather that could result in damage to OTP’s
assets), fuel and purchased power costs and the rate of economic
growth or decline in OTP’s service areas. A decrease in revenues or an
increase in expenses related to our electric operations may reduce the
amount of funds available for our existing and future businesses,
which could result in increased financing requirements, impair our
ability to make expected distributions to shareholders or impair our
ability to make scheduled payments on our debt obligations, or to
meet covenants under our borrowing agreements.

Actions by the regulators of our electric operations could result in
rate reductions, lower revenues and earnings or delays in recovering
capital expenditures.
We are subject to federal and state legislation, government regulations
and regulatory actions that may have a negative impact on our business
and results of operations. The electric rates that OTP is allowed to charge
for its electric services are one of the most important items influencing
our financial position, results of operations and liquidity. The rates that
OTP charges its electric customers are subject to review and
determination by state public utility commissions in Minnesota, North
Dakota and South Dakota. OTP is also regulated by the FERC. Our
ability to obtain rate adjustments to maintain reasonable rates of return
depends on regulatory action under applicable statutes and regulations
and we cannot provide assurance that rate adjustments will be obtained
or reasonable authorized rates of return on capital will be earned. OTP
will file rate cases with, or seek cost recovery authorization from, federal
and state regulatory authorities. On November 2, 2017 OTP filed a rate
request with the NDPSC, which is pending. OTP is also an intervenor in a
matter pending before the D.C. Circuit regarding FERC orders relating to
the refund of RSG charges. An adverse decision by one or more regulatory
commissions concerning the level or method of determining electric
utility rates, the authorized returns on equity, implementation of
enforceable federal reliability standards or other regulatory matters,
permitted business activities (such as ownership or operation of
nonelectric businesses) or any prolonged delay in rendering a decision
in a rate or other proceeding (including with respect to the recovery
of capital expenditures in rates) could result in lower revenues and
net income.

OTP’s operations are subject to an extensive legal and regulatory
framework under federal and state laws as well as regulations
imposed by other organizations that may have a negative impact
on our business and results of operations.
We are subject to an extensive legal and regulatory framework imposed
under federal and state law and regulatory agencies, including FERC
and NERC. We could be subject to potential financial penalties for
compliance violations. In addition, energy policy initiatives at the state
or federal level could increase incentives for distributed generation or

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

municipal utility ownership, or local initiatives could introduce generation
or distribution requirements, that could change the current integrated
utility model. Our transmission systems and electric generation facilities
are subject to the NERC mandatory reliability standards, including
cybersecurity standards. If a serious reliability incident did occur, it
could have a material effect on our operations or financial results.
Some states have the authority to impose substantial penalties in the
event of non-compliance. We attempt to mitigate the risk of regulatory
penalties through formal training. However, there is no guarantee our
compliance program will be sufficient to ensure against violations.
These laws and regulations significantly influence our operations
and may affect our ability to recover costs from our customers. We are
required to have numerous permits, licenses, approvals and certificates
from the agencies and other organizations that regulate our business.
We believe we have obtained the necessary approvals for our existing
operations and that our business is conducted in accordance with
applicable laws; however, we are unable to predict the impact on our
operating results from the future regulatory activities of any of these
agencies and other organizations. Changes in regulations or the
imposition of additional regulations could have a material adverse
impact on our results of operations.

OTP’s electric transmission and generation facilities could be
vulnerable to cyber and physical attack that could impair our ability
to provide electrical service to our customers or disrupt the U.S. bulk
power system.
OTP owns electric transmission and generation facilities subject to
mandatory and enforceable standards advanced by the NERC. These
bulk electric system facilities provide the framework for the electrical
infrastructure of OTP’s service territory and interconnected systems, the
operation of which is dependent on information technology systems.
Further, the information systems that operate OTP’s electric system are
interconnected to external networks. Parties that wish to disrupt the
U.S. bulk power system or OTP’s operations could view OTP’s computer
systems, software or networks as attractive targets for cyber-attack.
In addition, OTP’s generation and transmission facilities are spread
throughout a large service territory. These facilities could be subject to
physical attack or vandalism that could disrupt OTP’s operations or
conceivably the regional or U.S. bulk power system.

OTP is subject to mandatory cybersecurity and physical security
regulatory requirements. OTP implements the NERC standards for
operating its transmission and generation assets and stays abreast of
best practices within business and the utility industry to protect its
computers and computer controlled systems from outside attack. We
rely on industry accepted security measures and technology to securely
maintain confidential and proprietary information necessary for the
operation of our systems. In an effort to reduce the likelihood and
severity of cyber intrusions, we have cybersecurity processes and
controls designed to protect and preserve the confidentiality, integrity
and availability of data and systems. We also take prudent and
reasonable steps to protect the physical security of our generation and
transmission facilities. However, all these measures and technology
may not adequately prevent security breaches or cyber-attacks. Any
significant interruption or failure of our information systems or any
significant breach of security due to cyber-attacks, hacking or internal
security breaches or physical attack of our generation or transmission
facilities could adversely affect our business and results of operations.

OTP’s electric generating facilities are subject to operational risks that
could result in unscheduled plant outages, unanticipated operation
and maintenance expenses and increased power purchase costs.
Operation of electric generating facilities involves risks which can
adversely affect energy output and efficiency levels. Most of OTP’s
generating capacity is coal-fired. OTP relies on a limited number of

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

suppliers of coal, making it vulnerable to increased prices for fuel as
existing contracts expire or in the event of unanticipated interruptions
in fuel supply. OTP is a captive rail shipper of the BNSF Railway for
shipments of coal to its Big Stone and Hoot Lake plants, making it
vulnerable to increased prices for coal transportation from a sole
supplier and disruptions in coal deliveries due to rail line congestion
and constraints on the rail lines between the coal source mines and
the plants. Higher fuel prices result in higher electric rates for OTP’s
retail customers through fuel clause adjustments and could make it
less competitive in wholesale electric markets. Operational risks also
include facility shutdowns due to breakdown or failure of equipment
or processes, labor disputes, operator error and catastrophic events
such as fires, explosions, floods, intentional acts of destruction or
other similar occurrences affecting OTP’s electric generating facilities.
The loss of a major generating facility would require OTP to find other
sources of supply, if available, and expose it to higher purchased
power costs.

Changes to regulation of generating plant emissions, including but
not limited to CO2 emissions, could affect our operating costs and
the costs of supplying electricity to our customers.
Existing or new laws or regulations passed or issued by federal or
state authorities addressing climate change or reductions of GHG
emissions, such as mandated levels of renewable generation, mandatory
reductions in CO2 emission levels, taxes on CO2 emissions or cap and
trade regimes, could require us to incur significant new costs, which
could negatively impact our net income, financial position and operating
cash flows if such costs cannot be recovered through rates granted by
ratemaking authorities in the states where OTP provides service or
through increased market prices for electricity. Debate continues in
Congress and in the new administration on the direction and scope of
U.S. and international policy on climate change and regulation of GHGs.
Congress has considered but has not adopted GHG legislation which
would require a reduction in GHG emissions and there is no legislation
under active consideration at this time. The likelihood of any federal
mandatory CO2 emissions reduction program being adopted by Congress
in the near future, and the specific requirements of any such program,
are uncertain, as are the future of additional regulatory actions.

Under the previous presidential administration, the EPA published

final rules for the CPP, including NSPS regulations governing GHGs
from new and existing fossil fuel-fired electric generating units and
GHG performance and emissions standards for existing fossil fuel-fired
power plants. The U.S. Supreme Court granted a stay of the CPP. After
the new administration issued an executive order directing the EPA to
consider suspending, revising, or rescinding the NSPS rule and the
CPP, the D.C. Circuit issued orders holding the appellate challenges to
both rules in abeyance. In October 2017, the EPA published a proposed
rule to repeal the CPP and intends to solicit additional information
regarding climate change and GHG emissions. The fate of the former
administration’s GHG rules is uncertain, as is the outcome of EPA’s
potential GHG regulatory actions under the new administration. The
final outcome of this rulemaking process could have a material
adverse impact on our business and financial results.

MANUFACTURING
Competition from foreign and domestic manufacturers, the price and
availability of raw materials, prices and supply of scrap or recyclable
material and general economic conditions could affect the revenues
and earnings of our manufacturing businesses.
Our manufacturing businesses are subject to intense risks associated
with competition from foreign and domestic manufacturers, many of
whom have broader product lines, greater distribution capabilities,
greater capital resources, larger marketing, research and development
staffs and facilities and other capabilities that may place downward
pressure on margins and profitability. The companies in our

Manufacturing segment use a variety of raw materials in the products
they manufacture, including steel, aluminum and polystyrene and
other plastics resins. Costs for these items can fluctuate significantly.
If our manufacturing businesses are not able to pass on cost increases
to their customers, it could have a negative effect on profit margins in
our Manufacturing segment. Additionally, a certain amount of residual
material (scrap) is a by-product of many of the manufacturing and
production processes used by our manufacturing companies. Declines
in commodity prices for these scrap materials due to weakened
demand or excess supply, can negatively impact the profitability of
our manufacturing companies as it reduces their ability to mitigate
the cost associated with excess material. Changes in macroeconomic
conditions can negatively impact demand in the end-use markets for
products and parts that we manufacture, resulting in reduced sales
and profits. There is no assurance that the initiatives underway to
increase revenues and improve margins at our manufacturing
businesses will be successful.

PLASTICS
Our plastics operations are highly dependent on a limited number of
vendors for PVC resin and a limited supply of PVC resin. The loss of
a key vendor, or any interruption or delay in the supply of PVC resin,
could result in reduced sales or increased costs for our plastics business.
We rely on a limited number of vendors to supply the PVC resin used
in our plastics business. Two vendors accounted for 100% of our total
purchases of PVC resin in 2017 and 2016. In addition, the supply of
PVC resin may be limited primarily due to manufacturing capacity and
the limited availability of raw material components. A majority of
U.S. resin production plants are located in the Gulf Coast region, which
may increase the risk of a shortage of resin in the event of a hurricane
or other natural disaster in that region. The loss of a key vendor or any
interruption or delay in the availability or supply of PVC resin could
disrupt our ability to deliver our plastic products, cause customers to
cancel orders or require us to incur additional expenses to obtain PVC
resin from alternative sources, if such sources are available.

We compete against a large number of other manufacturers of PVC
pipe and manufacturers of alternative products. Customers may not
distinguish our products from those of our competitors.
The plastic pipe industry is fragmented and competitive due to the
number of producers and the fungible nature of the product. We
compete not only against other plastic pipe manufacturers, but also
against ductile iron, steel and concrete pipe manufacturers. Due to
shipping costs, competition is usually regional instead of national in
scope, and the principal areas of competition are a combination of
price, service, warranty, and product performance. Our inability to
compete effectively in each of these areas and to distinguish our
plastic pipe products from competing products may adversely affect
the financial performance of our plastics business.

Changes in PVC resin prices can negatively affect our plastics business.
The PVC pipe industry is highly sensitive to commodity raw material
pricing volatility. Historically, when resin prices are rising or stable,
margins and sales volume have been higher and when resin prices are
falling, sales volumes and margins have been lower. Changes in PVC
resin prices can negatively affect PVC pipe prices, profit margins on
PVC pipe sales and the value of our finished goods inventory.

ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties

The Coyote Station, which commenced operation in 1981, is a 414,000 kW
(nameplate rating) mine-mouth plant located in the lignite coal fields
near Beulah, North Dakota and is jointly owned by OTP, Northern
Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern
Public Service Company. OTP is the operating agent of the Coyote
Station and owns 35% of the plant.

OTP, jointly with Northwestern Public Service Company and

Montana-Dakota Utilities Co., owns the 414,000 kW (nameplate rating)
Big Stone Plant in northeastern South Dakota which commenced
operation in 1975. OTP is the operating agent of Big Stone Plant and
owns 53.9% of the plant.

Located near Fergus Falls, Minnesota, the Hoot Lake Plant is
comprised of two separate generating units: a unit built in 1959
(53,500 kW nameplate rating) and a unit added in 1964 (75,000 kW
nameplate rating) and modified in 1988 to provide cycling capability,
allowing this unit to be more efficiently brought online from a standby
mode. These two generating units have a combined nameplate rating
of 128,500 kW. Current plans are for both units to be retired from
service in 2021.

OTP owns 27 wind turbines at the Langdon, North Dakota Wind
Energy Center with a nameplate rating of 40,500 kW, 32 wind turbines
at the Ashtabula Wind Energy Center located in Barnes County, North
Dakota with a nameplate rating of 48,000 kW and 33 wind turbines at
the Luverne Wind Farm located in Steele County, North Dakota with a
nameplate rating of 49,500 kW.

As of December 31, 2017 OTP’s transmission facilities, which are
interconnected with lines of other public utilities, consisted of 606
pole-miles of jointly owned 345 kV lines; 494 pole-miles of 230 kV lines,
of which 70 miles are jointly owned; 879 pole-miles of 115 kV lines; and
3,973 pole-miles of lower voltage lines, principally 41.6 kV. OTP owns
the uprated portion of 48 pole-miles of the 345 kV lines, with Minnkota
Power Cooperative retaining title to the original 230 kV construction,
and OTP owns an undivided interest in the remaining 345 kV line miles.
OTP is a joint owner, with other regional utilities, in transmission lines
with the following ownership interests: 14.8% in the 70 mile Bemidji-
Grand Rapids 230 kV line, approximately 14.2% of 242 pole-miles of
energized line in the Fargo—Monticello 345 kV project, approximately
4.8% of 255 pole-miles of energized line in the Brookings to Southeast
Twin Cities 345 kV project, and 50.0% of 72 pole-miles of energized
line in the Big Stone South—Brookings 345 kV project.

In addition to the properties mentioned above, all of which are

utilized by the Electric segment, the Company owns and has investments
in offices and service buildings utilized by each of its manufacturing
and plastic pipe companies. The Company’s subsidiaries own facilities
and equipment used in: the manufacture of PVC pipe, thermoformed
products, heavy metal fabricated products, metal parts stamping,
fabricating, painting and contract machining.

Management of the Company believes the facilities and equipment
described above are adequate for the Company’s present businesses.

ITEM 3. Legal Proceedings

The Company is the subject of various pending or threatened legal
actions and proceedings in the ordinary course of its business. Such
matters are subject to many uncertainties and to outcomes that are
not predictable with assurance. The Company records a liability in its
consolidated financial statements for costs related to claims, including
future legal costs, settlements and judgments, where the Company
has assessed that a loss is probable and an amount can be reasonably
estimated. The Company believes the final resolution of currently
pending or threatened legal actions and proceedings, either individually
or in the aggregate, will not have a material adverse effect on its
consolidated financial position, results of operations or cash flows.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

ITEM 3A. Executive Officers of the Registrant (As of February 20, 2018)

Set forth below is a summary of the principal occupations and business experience during the past five years of the executive officers as defined
by rules of the SEC. Each of the executive officers, excluding John Abbott, has been employed by the Company for more than five years in an
executive or management position either with the Company or its wholly owned subsidiary, Otter Tail Power Company.

Name and Age

Date Elected to Office

Present Position and Business Experience

Charles S. MacFarlane (53)
Kevin G. Moug (58)
Timothy J. Rogelstad (51)
John Abbott (59)
Jennifer O. Smestad (47)

4/13/15
4/9/01
4/14/14
2/11/15
1/1/18

Present: President and Chief Executive Officer
Present: Chief Financial Officer and Senior Vice President
Present: Senior Vice President, Electric Platform
Present: Senior Vice President, Manufacturing Platform
Present: Vice President, General Counsel and Corporate Secretary

On April 13, 2015 Mr. MacFarlane was elected as the Company’s
President and Chief Executive Officer and as member of the Company’s
board of directors. On February 5, 2014 the Company’s board of
directors appointed Mr. MacFarlane, then President and Chief Executive
Officer of OTP and Senior Vice President, Electric Platform of the
Company, to the role of President and Chief Operating Officer of the
Company, effective April 14, 2014. Mr. MacFarlane joined OTP in 2001
and had served as its President from 2003 to 2014 and its Chief
Executive Officer from 2007 to 2014. He served as Senior Vice
President, Electric platform of the Company from 2012 to 2014. Prior
to joining OTP, Mr. MacFarlane served as Director of Electric Distribution
Planning and Engineering for Xcel Energy Inc.’s multi-state service
territory. He was also Director of Delivery Construction and Field
Operations for Northern States Power Company prior to its merger
with New Centuries Energy and becoming Xcel Energy.

Kevin G. Moug has held his present positions with the Company for

more than five years.

On April 14, 2014 Timothy J. Rogelstad was appointed to succeed
Mr. MacFarlane as President of OTP and Senior Vice President, Electric
Platform of the Company. Mr. Rogelstad joined OTP in June 1989 as an
engineer in the System Engineering Department and served as
Supervisor, Transmission Planning, and Manager, Delivery Planning,
before being named Vice President, Asset Management, in 2012. In the
role of Vice President, Asset Management at OTP, he was in charge of
OTP’s Delivery Planning, Delivery Maintenance, Delivery Engineering,
System Operations, and Project Management Departments.
Mr. Rogelstad is a registered professional engineer in the three states
where OTP serves, Minnesota, North Dakota, and South Dakota.

On February 5, 2015 John Abbott was selected to serve as Senior
Vice President, Manufacturing Platform, and President of Varistar. Prior
to coming to the Company, Mr. Abbott served as an officer and group
vice president for eight years at Standex International Corporation
(Standex), a group of restaurant equipment companies. During his last
five years at Standex, Mr. Abbott served as Group Vice President, Food
Service Equipment Group. In this role, Mr. Abbott was responsible for
all strategic and operational aspects of the Food Service Equipment
business. Prior to working at Standex, Mr. Abbott was with Pentair for
20 years, rising from product manager to president and global business
unit leader of its water filtration division.

On December 19, 2017 the Company’s board of directors appointed
Jennifer O. Smestad to the position of Vice President, General Counsel
and Corporate Secretary of the Company, effective January 1, 2018, to
succeed George A. Koeck, Senior Vice President, General Counsel
and Corporate Secretary who retired effective December 31, 2017.
Ms. Smestad joined the Company on May 14, 2001 as an Associate
General Counsel and has served in various legal capacities of increasing
responsibility at the Company and at OTP. She most recently served as
General Counsel for OTP from March 1, 2013 to the present.

The term of office for each of the executive officers is one year and

any executive officer elected may be removed by the vote of the
board of directors at any time during the term. There are no family
relationships between any of the executive officers or directors.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

ITEM 4. Mine Safety Disclosures

Not Applicable.

PART II

ITEM 5. Market for the Registrant’s Common
Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities

The Company’s common stock is traded on the NASDAQ Global Select
Market under the NASDAQ symbol “OTTR”. The information required
by this Item can be found on Page 31 of this Annual Report on Form
10-K under the heading “Selected Financial Data,” on Page 73 under
the heading “Retained Earnings and Dividend Restriction” and on
Page 87 under the heading “Supplementary Financial Information.”
The Company does not have a publicly announced stock repurchase
program. The Company did not repurchase any equity securities
during the three months ended December 31, 2017.

PERFORMANCE GRAPH
COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN
This graph compares the cumulative total shareholder return on the
Company’s common shares for the last five fiscal years with the
cumulative return of The NASDAQ Stock Market Index and the Edison
Electric Institute (EEI) Index over the same period (assuming the
investment of $100 in each vehicle on December 31, 2012, and
reinvestment of all dividends).

OTC

EEI

NASDAQ

$250

$200

$150

$100

$50

2012

2013

2014

2015

2016

2017

OTC
$ 100.00
EEI
$ 100.00
NASDAQ $ 100.00

$ 122.07
$ 113.01
$ 133.48

$ 134.51
$ 145.68
$ 150.12

$ 120.99
$ 139.99
$ 150.84

$ 192.46
$ 164.40
$ 170.46

$ 216.23
$ 183.66
$ 206.91

ITEM 6. Selected Financial Data

(thousands, except number of shareholders and per-share data)

2017

2016

2015

2014

2013

Revenues
Electric
Manufacturing
Plastics
Intersegment Eliminations

Total Operating Revenues

Net Income from Continuing Operations
Net Income from Discontinued Operations

Net Income

Operating Cash Flow from Continuing Operations
Operating Cash Flow—Continuing and Discontinued Operations
Capital Expenditures—Continuing Operations
Total Assets
Long-Term Debt
Basic Earnings Per Share—Continuing Operations (1)
Basic Earnings Per Share—Total (1)
Diluted Earnings Per Share—Continuing Operations (1)
Diluted Earnings Per Share—Total (1)
Return on Average Common Equity (2)
Dividends Declared Per Common Share
Dividend Payout Ratio
Common Shares Outstanding—Year End
Number of Common Shareholders (3)

$ 434,537
229,738
185,132
(57)

$ 427,383
221,289
154,901
(34)

$ 407,131
215,011
157,758
(96)

$ 407,743
219,583
172,050
(114)

$ 373,540
204,997
164,957
(80)

$ 849,350

$ 803,539

$ 779,804

$ 799,262

$ 743,414

72,119
320

72,439

$ 173,603
173,577
132,913
2,004,278
490,380
1.83
1.84
1.81
1.82
10.6%
1.28

70%

39,557
13,053

62,037
284

62,321

$ 163,541
163,386
161,259
1,912,385
505,341
1.61
1.62
1.60
1.61

9.8%

1.25

78%

39,348
13,805

58,589
756

59,345

$ 131,540
117,540
160,084
1,818,683
443,846
1.56
1.58
1.56
1.58
10.1%
1.23

56,883
840

57,723

$ 125,769
112,474
163,582
1,738,116
495,906
1.56
1.58
1.55
1.57
10.4%
1.21

78%

77%

37,857
14,062

37,218
14,134

48,595
2,270

50,865

$ 142,408
147,781
159,833
1,558,190
387,212
1.33
1.39
1.33
1.39

9.5%

1.19

86%

36,272
14,252

(1) Based on average number of shares outstanding.
(2) Earnings available for common shares divided by the 13-month average of month-end common equity balances.
(3) Holders of record at year end.

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

Otter Tail Corporation and its subsidiaries form a diverse group of
businesses with operations classified into three segments: Electric,
Manufacturing and Plastics. Our primary financial goals are to maximize
earnings and cash flows and to allocate capital profitably toward
growth opportunities that will increase shareholder value. Meeting
these objectives enables us to preserve and enhance our financial
capability by maintaining desired capitalization ratios and a strong
interest coverage position and preserving investment grade credit
ratings on outstanding securities, which, in the form of lower interest
rates, benefits both our customers and shareholders.

Our strategy is to continue to grow our largest business, the regulated
electric utility, which will lower our overall risk, create a more predictable
earnings stream, improve our credit quality and preserve our ability to
fund the dividend. Over time, we expect the electric utility business will
provide approximately 75% to 85% of our overall earnings. We expect
our manufacturing and plastic pipe businesses will provide 15% to
25% of our earnings, and will continue to be a fundamental part of our
strategy. The actual mix of earnings from continuing operations in 2017,
2016 and 2015 was 69%, 80% and 83%, respectively, from our electric
utility business and 31%, 20% and 17%, respectively, from our manufacturing
and plastic pipe businesses, including unallocated corporate costs.
Reliable utility performance along with rate base investment

opportunities over the next five years will provide us with a strong base
of revenues, earnings and cash flows. We also look to our manufacturing
and plastic pipe companies to provide organic growth as well. Organic,
internal growth comes from new products and services, market
expansion and increased efficiencies. We expect much of our growth in
these businesses in the next few years will come from utilizing expanded
plant capacity from capital investments made in previous years. We will

also evaluate opportunities to allocate capital to potential acquisitions
in our Manufacturing and Plastics segments. We are a committed
long-term owner and therefore we do not acquire companies in pursuit
of short-term gains. However, we will divest operating companies that
no longer fit into our strategy and risk profile over the long term. In
the period 2011 through 2015 we sold several businesses in execution
of our announced strategy to realign our portfolio of businesses and
refocus our capital investment in the electric utility.

Major growth strategies and initiatives in our future include:

— Planned capital budget expenditures of up to $973 million for the

years 2018 through 2022, of which $901 million are for capital projects
at Otter Tail Power Company (OTP), including:
• $302 million for renewable wind and solar energy generation

projects including the Merricourt Wind Project. In November 2016
OTP signed agreements to purchase this 150-megawatt (MW)
wind farm in southeastern North Dakota that EDF Renewable
Energy will design and build in 2019, subject to certain conditions.

• $161 million for natural gas-fired generation to replace Hoot Lake

Plant capacity.

• $136 million for transformative technology and infrastructure projects
including automated metering, telecommunications, geographic
information systems, work and asset management systems, financial
information systems, system infrastructure reliability improvements,
outage management systems, and storage projects.
• $35 million for a transmission project designated by the

Midcontinent Independent System Operator, Inc. (MISO) as a
Multi-Value Project (MVP).

— Continued investigation and evaluation of organic growth

opportunities and evaluation of opportunities to allocate capital to
potential acquisitions in our Manufacturing and Plastics segments.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

In 2017:
— Our Plastics segment net income increased 104.1% to $21.7 million

from $10.6 million in 2016.

— Our Manufacturing segment net income increased 94.1% to

$11.1 million from $5.7 million in 2016.

— Our Electric segment net income decreased 0.8% to $49.4 million

from $49.8 million in 2016.

— Our net cash from continuing operations was $173.6 million.
— Capital expenditures at OTP totaled $118.4 million as work was

completed on one major MISO-designated MVP and work continued
on another MISO-designated MVP.

— We raised net proceeds of $4.3 million from the issuance of
112,548 shares of common stock through our stock plans.
— We increased short-term borrowing by $69.5 million, retiring
long-term debt and funding a portion of OTP’s 2017 capital
expenditures. We paid $48.2 million to repay long-term debt,
including the retirement of $33.0 million of OTP’s 5.95% notes due
in August 2017 and the early repayment of $15.0 million of our
LIBOR plus 0.90% term loan due February 5, 2018.

— We paid out $50.6 million in common dividends in 2017.

— A $5.4 million increase in Manufacturing segment net income,

mainly due to increased sales to manufacturers of recreational and
lawn and garden equipment and life science and horticultural
products. BTD also benefited from the effect of the TCJA tax rate
reduction on its deferred tax liabilities.

offset by:
— A $0.4 million decrease in Electric segment net income due to

increases in fuel and purchased power costs and higher property
tax expenses, and a negative effect of the TCJA tax rate reduction
on Electric segment deferred tax assets related to a portion of
accrued postretirement benefit costs which are not recoverable in
regulated rates.

— A $6.0 million net-of-tax increase in Corporate net losses mainly as
a result of the negative effect of the TCJA tax rate reduction on
deferred tax assets at the holding company.

As a result of the tax rate reduction included in the TCJA, deferred
tax assets and liabilities were reduced in value. Following is the impact
by segment on income tax expense:

The following table summarizes our consolidated results of

operations for the years ended December 31:

(in thousands)

Operating Revenues:

Electric
Manufacturing
Plastics

Total Operating Revenues

2017

2016

$ 434,506
229,712
185,132

$ 427,349
221,289
154,901

$ 849,350

$ 803,539

(in thousands)

Electric
Manufacturing
Plastics
Corporate

Total

Decrease/(Increase)

(458)
2,637
3,263
(7,198)

(1,756)

These are provisional amounts based on reasonable estimates

Net Income (Loss) From Continuing Operations:

reflecting the anticipated impact of the TCJA.

Following is a more detailed analysis of our operating results by
business segment for the years ended December 31, 2017, 2016 and
2015, followed by a discussion of our financial position at the end of
2017 and our outlook for 2018.

RESULTS OF OPERATIONS

This discussion and analysis should be read in conjunction with our
consolidated financial statements and related notes. See note 2 to
consolidated financial statements for a complete description of our lines
of business, locations of operations and principal products and services.

Intersegment Eliminations—Amounts presented in the following
segment tables for 2017, 2016 and 2015 operating revenues, cost of
goods sold and other nonelectric operating expenses will not agree with
amounts presented in the consolidated statements of income due to the
elimination of intersegment transactions. The amounts of intersegment
eliminations by income statement line item are listed below:

Intersegment Eliminations (in thousands)

2017

2016

2015

Operating Revenues:

Electric
Product Sales

Cost of Products Sold
Other Nonelectric Expenses

31
26
18
39

34
—
6
28

92
4
9
87

Electric
Manufacturing
Plastics
Corporate

49,446
11,050
21,696
(10,073)

49,829
5,694
10,628
(4,114)

Total Net Income From Continuing Operations

72,119

62,037

Revenues in each of our business segments increased in 2017
compared with 2016. Major factors contributing to the $30.2 million
(19.5%) increase in Plastics segment revenues were a 7.2% increase in
pounds of polyvinyl chloride (PVC) pipe sold and 11.5% increase in PVC
pipe prices. Buying spurred by concerns of product shortages and
production delays related to 2017 hurricanes in the Gulf of Mexico
resulted in an estimated $3.4 million increase in segment net income
in 2017. Manufacturing segment revenues increased $8.4 million (3.8%).
Revenues at BTD Manufacturing, Inc. (BTD) showed a net increase of
$5.9 million, with revenue increases at BTD’s Minnesota and Georgia
facilities increasing by 4.0% and 8.2%, respectively, as a result of
increased product sales to manufacturers of recreational and lawn
and garden equipment. Revenues at T.O. Plastics, Inc. (T.O. Plastics)
increased $2.5 million as a result of significant increases in sales of life
science and horticultural products. Electric segment revenues increased
$7.2 million (1.7%) mainly as a result of increased transmission services
revenue driven by increased investment in regional transmission lines
with returns earned while the lines are under construction and increased
revenues earned from the use of energized lines by other electric
service providers.

The $10.1 million increase in net income from continuing operations

in 2017 compared with 2016 reflects the following:
— An $11.1 million increase in Plastics segment net income due to

hurricane related sales, the positive effect of the 2017 Tax Cuts and
Jobs Act (TCJA) tax rate reduction on the segment’s deferred tax
liabilities and increases in normal business sales.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

4,584

2,499

— A $3.7 million decrease in Minnesota Conservation Improvement

ELECTRIC
The following table summarizes the results of operations for our
Electric segment for the years ended December 31:

(in thousands)

2017 change

2016 change

2015

$ 374,931

— $ 376,610

3 $ 364,614

Retail Sales Revenues
Wholesale Revenues—
Company Generation

Net Revenue—

Energy Trading Activity

Other Revenues

5,173

—
54,433

—
18

— (100)
16

46,189

186
39,832

Total Operating Revenues
Production Fuel
Purchased Power—System Use
Other Operation and

$ 434,537
59,690
64,807

Maintenance Expenses

Depreciation and Amortization
Property Taxes

151,319
53,276
15,053

2 $ 427,383
54,792
9
63,226
3

5 $ 407,131
42,744
78,150

28
(19)

—
(1)
6

151,225
53,743
14,266

7
20
6

140,768
44,786
13,512

Operating Income

90,392

— $

90,131

3 $ 87,171

Electric kilowatt-hour (kwh) Sales (in thousands)

Retail kwh Sales
Wholesale kwh Sales—
Company Generation
Wholesale kwh Sales—

4,814,984

203,397

4,750,421

3 4,593,604

190,288

107,510

Purchased Power Resold

Heating Degree Days
Cooling Degree Days

—
5,931
380

—
12
(16)

— (100)
(6)
(7)

5,314
451

5,547
5,633
483

The following table shows heating and cooling degree days as a

percent of normal:

Heating Degree Days
Cooling Degree Days

2017

93.9%
82.1%

2016

84.1%
97.4%

2015

88.2%
103.4%

The following table summarizes the estimated effect on diluted
earnings per share of the difference in retail kwh sales under actual
weather conditions and expected retail kwh sales under normal
weather conditions in 2017, 2016 and 2015, and between years:

2017 vs
Normal

2017 vs
2016

2016 vs
Normal

2016 vs
2015

2015 vs
Normal

Effect on Diluted

Earnings Per Share

$(0.036)

$0.031 $(0.067)

$(0.023) $(0.044)

2017 Compared with 2016
The $1.7 million decrease in retail electric revenue includes:
— A $5.3 million increase in retail revenue related to the recovery of

increased fuel and purchased power costs due to a 1.4% increase in
kwhs sold and a 4.8% increase in fuel and purchased power costs
per kwh.

— A $4.2 million increase in Minnesota base rate revenue mainly due
to the transfer of recovery of environmental and transmission costs
and investments from riders to base rates.

— A $2.0 million increase in revenues due to increased consumption
related to colder weather in 2017 reflected in the 11.6% increase in
heating degree days between the years.

offset by:
— A $7.1 million reduction in Minnesota Environmental Cost Recovery
(ECR) rider and TCR rider revenues due to the transfer of recovery
of qualifying costs from rider recovery into base rates, and due to
declining revenue requirements related to lower asset values due to
accumulated depreciation. Additionally, a lower return on equity in
the MISO transmission tariff related to complaints currently under
judicial review resulted in lower TCR revenues in Minnesota.

Program (MNCIP) incentive and cost recovery revenues related to a
$2.5 million reduction in incentives earned due to lower incentive
rates and a $1.2 million reduction in spending on MNCIP programs.
In 2017 OTP began operating under a new MNCIP program that was
authorized by the Minnesota Public Utilities Commission. This new
program lowered the incentive payout by 50% in 2017. The $1.2 million
reduction in spending was due to a delay in regulatory approval for
the implementation of an LED streetlight project.

— A $1.9 million decrease in revenue due to a change in estimate that

reduced unbilled revenues.

— A $1.5 million decrease in North Dakota and South Dakota ECR rider
revenues resulting from lower values on qualifying assets due to
accumulated depreciation.

The $0.6 million increase in revenue from wholesale electric sales
from company-owned generation was mostly offset by a $0.4 million
increase in fuel costs for wholesale generation.

The $8.2 million increase in other electric revenues includes:

— A $7.8 million increase in MISO transmission tariff revenues, mainly
driven by increased investment in regional transmission lines and
revenues earned from the use of those lines by other electric
service providers.

— A $0.4 million increase in other revenues, mainly steam sales at

Big Stone Plant.

Production fuel costs increased $4.9 million due to a 4.0% increase
in kwhs generated. This was due to increase generation from Coyote
Station and Hoot Lake Plant because of Coyote Station’s greater
availability, increased demand due to colder weather in 2017 and
higher market prices for electricity that resulted in increased dispatch
of Hoot Lake Plant.

The cost of purchased power to serve retail customers increased
$1.6 million despite a 3.4% decrease in kwhs purchased. This was a
result of higher market prices for electricity driven by increased
demand in 2017 due, in part, to colder weather in 2017 than in 2016.

Electric operating and maintenance expenses increased $0.1 million

as a result of:
— A $3.2 million increase in labor and benefit costs due to increased

wages and higher medical benefit payments.

offset by:
— A $1.2 million decrease in transmission expenditures to independent

system operators in 2017.

— A $1.2 million decrease in MNCIP expenditures due to a delay in

regulatory approval of an LED streetlight project planned for 2017.

— A $0.7 million net reduction in other operating expenses.

— A $1.0 million increase in North Dakota Transmission Cost Recovery

Depreciation and amortization expense decreased $0.5 million due

(TCR) rider revenues as a result of increased investment in
transmission assets qualifying for revenue recovery through the
TCR rider.

to lower depreciation rates.

Property tax expense increased $0.8 million mainly due to

transmission line additions in South Dakota related to the construction
of the Big Stone South–Ellendale and Big Stone South–Brookings
345-kiloVolt (kV) transmission projects.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

The cost of purchased power to serve retail customers decreased
$14.9 million due to an 11.4% decrease in kwhs purchased in combination
with an 8.7% decrease in the cost per kwh purchased. Greater availability
of company-owned generation in 2016 reduced the need to purchase
electricity to serve retail load. The decreased cost per kwh purchased
was driven by lower market demand mainly resulting from milder
weather in 2016 compared with 2015.

Electric operating and maintenance expenses increased $10.5 million

as a result of:
— $3.7 million in transmission expenses from the SPP as a result of a

regional transmission cooperative terminating its integrated
transmission agreement with OTP and joining the SPP in 2016.
— A $1.9 million increase in pollution control reagent costs at Big
Stone Plant and Coyote Station related to compliance with the
Environmental Protection Agency power plant emission regulations.

— A $1.7 million increase in MNCIP program expenditures related to

additional MNCIP activities.

— A $1.3 million increase in MISO transmission service charges due to

increased transmission investment by other MISO members.
— A $1.1 million increase in storm repair expenses associated with
excessive storm damage in OTP’s Minnesota service area in July
2016 and in its North Dakota and South Dakota service areas in
December 2016.

— $0.8 million related to increases in other expense categories.

Depreciation and amortization expense increased $9.0 million
mainly due to the AQCS at Big Stone Plant being placed in service in
December 2015 along with increased investment in transmission assets
with the final phases of the Fargo-Monticello and Brookings-Southeast
Twin Cities 345-kV transmission lines placed in service near the end of
the first quarter of 2015.

The $0.8 million increase in property tax expense is related to

property additions in Minnesota and North Dakota in 2015.

MANUFACTURING
The following table summarizes the results of operations for our
Manufacturing segment for the years ended December 31:

(in thousands)

2017 change

2016 change

2015

Operating Revenues
Cost of Products Sold
Other Operating Expenses
Depreciation and Amortization

$ 229,738
176,473
23,785
15,379

4
3
8
(3)

$ 221,289
171,732
21,994
15,794

3 $ 215,011
— 171,956
21,116
4
11,853
33

Operating Income

$ 14,101

$ 11,769

17 $ 10,086

2017 Compared with 2016
The $8.4 million increase in revenues in our Manufacturing segment in
2017 compared with 2016 relates to the following:
— Revenues at BTD increased $5.9 million. This is due to a $3.3 million
increase in product sales to manufacturers of recreational and lawn
and garden equipment from BTD’s Minnesota and Georgia
manufacturing facilities, offset by lower sales in the energy end-use
market at the Illinois facility. Scrap revenues increased $2.6 million
due to increased volume and higher scrap-metal prices.

— Revenues at T.O. Plastics, Inc. (T.O. Plastics) increased $2.5 million,

including increases of $1.3 million from sales of life science products,
$1.0 million from sales of horticultural products and $0.2 million
from sales of industrial products.

2016 Compared with 2015
The $12.0 million increase in retail revenue includes:
— An $11.0 million increase in retail revenue related to a 9.56% interim
rate increase implemented in April 2016 in conjunction with OTP’s
2016 general rate increase request in Minnesota.

— A $4.4 million increase in ECR rider revenue due to the recovery of
additional investment and costs related to the operation of the air
quality control system (AQCS) at Big Stone Plant that was placed in
service in December 2015.

— A $4.3 million increase in revenue related to an increase in retail

kwh sales, mainly to pipeline customers.

— A $2.2 million increase in TCR rider revenues related to increased

investment in transmission plant.

— A $1.7 million increase in MNCIP cost recovery revenues directly

related to additional MNCIP activities.

offset by:
— A $5.7 million decrease in fuel and purchased power cost recovery

revenues mainly due to an 11.4% decrease in kwhs purchased
partially offset by a 19.7% kwh increase in generation.

— A $3.6 million reduction in interim rate revenues recorded to provide
for an estimated refund related to a modification in OTP’s original
request and other expected outcomes in the pending Minnesota
general rate case.

— A $1.6 million decrease in revenues related to decreased consumption
due to milder weather in 2016, evidenced by a 5.7% reduction in
heating-degree days and 6.6% reduction in cooling-degree days
between the years.

— A $0.6 million decrease in Renewable Resource Adjustment rider
revenues in North Dakota, which were down as a result of earning
more federal Production Tax Credits (PTCs) to pass back to
customers due to a 3.6% increase in kwhs generated from wind
turbines eligible for PTCs.

A $2.1 million increase in revenue from wholesale electric sales from

company-owned generation was partially offset by a $1.5 million
increase in fuel costs for wholesale generation, resulting in a $0.6 million
increase in wholesale revenue net of fuel costs as increased plant
availability in 2016 provided greater opportunity for OTP to respond
to market demand.

Other electric revenues increased $6.4 million as a result of:

— A $4.8 million increase in MISO transmission tariff revenues, mainly
driven by increased investment in regional transmission lines and
related returns on and recovery of Capacity Expansion 2020 and
MISO-designated MVP investment costs and operating expenses.
— A $3.0 million increase in MISO network integration transmission
service revenues due to a regional transmission cooperative
terminating its integrated transmission agreement with OTP and
joining the Southwest Power Pool (SPP) in 2016.

offset by:
— A $1.3 million decrease in revenue related to a reduction in integrated
transmission agreement revenues from two regional transmission
providers related to the curtailment of services under one agreement
and the discontinuance of another agreement.

Production fuel costs increased $12.0 million as a result of a 27.1%
increase in kwhs generated from our steam-powered and combustion
turbine generators related to Big Stone Plant being fully operational in
2016 after the tie in of the AQCS in 2015, as well as Coyote Station
being available to run at full load in 2016 after being restricted to half
load in 2015 because of boiler feed water pump problems.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

The $4.7 million increase in cost of products sold in our Manufacturing

Gross margins at BTD were positively impacted in 2016 by changes

segment includes the following:
— Cost of products sold at BTD increased $2.3 million as a result of

the increase in product sales.

— Costs of products sold at T.O. Plastics increased $2.4 million due to

the increase in sales.

in customer product mix between periods.

The $0.9 million increase in operating expenses in our Manufacturing

segment includes the following:
— Operating expenses at BTD increased $1.4 million, of which $1.2 million

was due to a full year of operations at BTD-Georgia in 2016.

— Operating expenses at T.O. Plastics decreased $0.4 million, primarily

The $1.8 million increase in Manufacturing segment operating

as a result of a $0.5 million decrease in selling expenses.

expenses includes the following:
— Operating expenses at BTD increased $1.9 million as a result of

the following:
• A $0.7 million increase in labor and benefit costs as a result of an

increase in employees in a growing business.

• A $0.4 million increase in contracted service expenditures for
consulting, software and telecommunications in response to
increased business needs.

• A $0.4 million increase in property taxes.
• A $0.4 million increase in insurance costs.

— Operating expenses at T.O. Plastics decreased $0.1 million between

the years.

The $0.4 million decrease in depreciation in our Manufacturing
segment includes decreases of $0.3 million at T.O. Plastics million due
to certain assets reaching the ends of their depreciable lives in 2017.
Depreciation expense at BTD was down $0.1 million year over year.

2016 Compared with 2015
The increase of $6.3 million in revenues in our Manufacturing segment
in 2016 compared with 2015 relates to the following:
— Revenues at BTD increased $9.8 million, including:

• A $15.4 million increase in revenues at BTD-Georgia as a result of
BTD owning and operating this plant for the entire year of 2016
compared to four months in 2015.

• A $9.6 million increase in revenues mainly related to the

production of wind tower components.

offset by:

• A $15.2 million decrease in revenues related to lower sales to

manufacturers of recreational and agricultural equipment due to
softness in end markets served by those manufacturers.
— Revenues at T.O. Plastics decreased $3.5 million, including:

• A $3.0 million decrease in revenue related to a continued decline

in sales to a customer insourcing product into its own
manufacturing facilities.

• A $0.6 million decrease in sales of horticultural products due to

sales execution challenges, including lower sales to a major
distributor.

offset by:

• A net $0.1 million increase in sales of other products in the

industrial and life sciences markets.

The $0.2 million decrease in cost of products sold in our

Manufacturing segment includes the following:
— Cost of products sold at BTD increased $1.7 million. This includes a
$15.5 million increase in cost of products sold at BTD-Georgia,
offset by a $13.8 million net decrease in cost of products sold at
BTD’s other facilities. The $13.8 million decrease is related to the
decrease in sales, partially offset by an increase in costs of products
sold at BTD’s Illinois plant as a result of the increase in the
production of wind tower components.

— Cost of products sold at T.O. Plastics decreased $1.9 million related

to the decrease in sales.

The $3.9 million increase in depreciation and amortization expenses

in our Manufacturing segment includes a $2.3 million increase at
BTD-Georgia and a $1.8 million increase at BTD’s other plants mainly
as a result of placing new assets in service in Minnesota in 2015 and
2016. Depreciation expense at T.O. Plastics decreased $0.2 million
between the years.

PLASTICS
The following table summarizes the results of operations for our
Plastics segment for the years ended December 31:

(in thousands)

2017 change

2016 change

2015

Operating Revenues
Cost of Products Sold
Other Operating Expenses
Depreciation and Amortization

$ 185,132
140,107
11,564
3,817

Operating Income

$ 29,644

20
13
23
(1)

$ 154,901
123,496
9,402
3,861

(2) $ 157,758
—
123,085
9,849
(5)
3,552
9

$ 18,142

(15) $ 21,272

2017 Compared with 2016
Plastics segment revenues increased $30.2 million as a result of a 7.2%
increase in pounds of PVC pipe sold and an 11.5% increase in PVC pipe
prices between the years. Reaction to the hurricanes in the Gulf Coast
region of the United States resulted in an estimated $12.5 million
increase in revenues. The majority of U.S. PVC resin production plants
are located in the Gulf Coast region. Major resin suppliers shut down
production facilities which impacted raw material availability.
Distributors and contractors became concerned about pipe availability.
This accelerated pipe demand and created positive sales price pressure in
the market. Year over year improvement in normal business operations
provided for the remainder of the revenue increase, along with increased
prices. The $16.6 million increase in Plastics segment costs of product
sold was due to the increase in sales volume and a 5.9% increase in the
cost per pound of PVC pipe sold. The $2.2 million increase in operating
expenses is mostly due to employee incentive pay related to the pipe
companies’ stronger financial results compared with 2016.

2016 Compared with 2015
The $2.9 million decrease in Plastics segment revenues is the result of
an 11.2% decrease in the price per pound of pipe sold, partially offset
by a 10.5% increase in pounds of pipe sold. The decline in sales price
per pound is related to lower raw material prices between the periods.
Increased pipe sales in the Colorado, Utah, and the South Central
and Northwest regions of the United States were partially offset by
decreased sales volumes in Montana, South Dakota and Minnesota.
Cost of products sold increased $0.4 million due to the increase in
sales volume, partly offset by a 9.2% decrease in the cost per pound of
PVC pipe sold, as sales prices declined more than raw material prices.
Lower margins have resulted in reduced incentive compensation,
which is the primary factor contributing to the $0.4 million decrease in
Plastics segment operating expenses.

The PVC pipe industry is highly sensitive to commodity raw material

pricing volatility. Historically, when resin prices are rising or stable,
margins and sales volume have been higher and when resin prices are
falling, sales volumes and margins have been lower.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

CORPORATE
Corporate includes items such as corporate staff and overhead costs,
the results of our captive insurance company and other items excluded
from the measurement of operating segment performance. Corporate
is not an operating segment. Rather, it is added to operating segment
totals to reconcile to totals on our consolidated statements of income.

(in thousands)

2017 change

2016 change

2015

Other Operating Expenses
Depreciation and Amortization

7,930 (11)
55

8,896
47

(3) $

(73)

9,143
172

Corporate operating expenses decreased $1.0 million mainly due to
a $0.6 million increase in the level of corporate costs allocated to the
corporation’s operating companies and a $0.5 million reduction in
labor costs due to a reduction in the number of corporate employees.
Corporate operating expenses decreased $0.2 million in 2016 as
compared to 2015 as a result of decreased expenditures for contracted
services and a decrease in claims at our captive insurance company,
partially offset by a decrease in expenses allocated to OTP.

CONSOLIDATED INTEREST CHARGES

(in thousands)

Interest Charges

2017 change

2016 change

2015

$ 29,604

(7)

$ 31,886

2 $ 31,160

The $2.3 million decrease in interest charges in 2017 compared with

2016 is related to lower cost debt resulting from the issuance of
$80.0 million of our 3.55% Guaranteed Senior Notes and the retirement
of our remaining $52.3 million outstanding 9.000% Notes in
December 2016 and the retirement of OTP’s $33.0 million outstanding
5.95%, Series A Senior Unsecured Notes at maturity on August 20,
2017. The average level of debt outstanding between the periods
increased by approximately $13.0 million with lower cost short-term
debt being issued to retire higher cost long-term debt and being used
to fund a portion of OTP’s 2017 capital expenditures.

The $0.7 million increase in interest charges in 2016 compared with

2015 is due to an increase in interest expense on short-term debt at
OTP as a result of a $24.7 million increase in OTP’s daily average
balance of short-term debt outstanding between the years and a
$0.2 million decrease in capitalized interest expense. The increase in
OTP’s use of short-term borrowing is related to its increasing investment
in two major MVP transmission line projects under construction.

CONSOLIDATED OTHER INCOME

(in thousands)

Other Income

2017 change

2016 change

2015

2,632

(9)

2,905

33 $

2,177

Other income decreased $0.3 million in 2017 compared with 2016,
mainly as a result of the receipt of $0.7 million in nontaxable corporate-
owned life insurance proceeds in 2016 while no similar proceeds were
received in 2017, offset by an increase in the cash surrender value of
the life insurance policies in 2017 that was $0.3 million more than the
increase in the cash surrender value in 2016.

The $0.7 million increase in other income in 2016 compared with
2015 is mainly due to proceeds from corporate-owned life insurance
received in 2016.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

CONSOLIDATED INCOME TAXES
Income tax expense—continuing operations was $27.0 million in 2017
compared with $20.1 million in 2016 and $21.6 million in 2015. Income
tax expense increased $6.9 million in 2017 compared with 2016 mainly
as a result of a $17.0 million increase in income from continuing
operations before income taxes.

The following table provides a reconciliation of income tax

expense—continuing operations calculated at the federal statutory
rate on income from continuing operations before income taxes
reported on our consolidated statements of income:

(in thousands)

Tax Computed at Federal Statutory Rate—

For the Year Ended December 31,

2017

2016

2015

Continuing Operations

$ 34,707

$ 28,741

$ 28,081

Increases (Decreases) in Tax from:

Federal PTCs
State Income Taxes Net of Federal

Income Tax Expense

Section 199 Domestic Production

(7,527)

(7,175)

(6,962)

4,341

2,848

4,945

Activities Deduction

(1,471)

(482)

—

North Dakota Wind Tax Credit Amortization—

Net of Federal Taxes

Corporate-owned Life Insurance
Excess Tax Deduction—Stock

Compensation Awards

Employee Stock Ownership Plan

Dividend Deduction

AFUDC—Equity
Investment Tax Credit Amortization
Differences Reversing in Excess of

Federal Rates

Permanent and Other Differences
Effect of TCJA Tax Rate Reduction on
Value of Net Deferred Tax Assets

Total Income Tax Expense—

Continuing Operations

Effective Income Tax Rate—

Continuing Operations

(850)
(845)

(751)

(509)
(322)
(164)

(850)
(680)

(850)
(167)

—

(537)
(280)
(350)

(560)
(426)
(571)

551
(1,873)

77
(1,231)

(1,143)
(705)

1,756

—

$ 27,043

$ 20,081

$ 21,642

27.3%

24.5%

27.0%

Federal PTCs are recognized as wind energy is generated based on

a per kwh rate prescribed in applicable federal statutes. OTP’s kwh
generation from its wind turbines eligible for PTCs increased 4.4% in
2017 compared with 2016 due to improved availability of the turbines
and more favorable wind and operating conditions in 2017. OTP’s kwh
generation from its wind turbines eligible for PTCs increased 3.6% in
2016 compared with 2015 primarily due to higher average wind speed
in 2016 compared with 2015. North Dakota wind energy credits are
based on dollars invested in qualifying facilities and are being
recognized on a straight-line basis over 25 years.

DISCONTINUED OPERATIONS
On April 30, 2015 we sold Foley Company (Foley) for $12.0 million in
cash, plus $6.3 million in adjustments for working capital and other
related items received in October 2015, less $1.0 million in selling
expenses. On February 28, 2015 we sold the assets of AEV, Inc. for
$22.3 million in cash, plus $0.6 million in adjustments for working
capital and fixed assets received in October 2015, less $0.8 million in
selling expenses. Foley and AEV, Inc were included in our Construction
segment. On February 8, 2013 we completed the sale of substantially
all the assets of our dock and boatlift company, formerly included in
our Manufacturing segment. On November 30, 2012 we completed the
sale of the assets of our wind tower manufacturing business, formerly
included in our Wind Energy segment. Our Construction and Wind
Energy segments were eliminated as a result of these sales.

The financial position, results of operations and cash flows of Foley, AEV, Inc., our wind tower manufacturing business and our dock and boatlift
company are reported as discontinued operations in our consolidated financial statements. Following are the results of discontinued operations by
entity for the years ended December 31, 2017, 2016 and 2015:

(in thousands)

2017 Net (Loss) Income
2016 Net (Loss) Income
2015 Net (Loss) Income

Foley

AEV, Inc.

(140)
$
$
(114)
$ (5,489)

$
$
$

—
(5)
6,216

Wind
Tower
Business

$
$
$

276
454
344

Dock and Intercompany
Boatlift Transactions
Adjustment

Business

$
$
$

184
(51)
(580)

$
$
$

—
—
265

$
$
$

Total

320
284
756

Foley and AEV, Inc. entered into fixed-price construction contracts. Revenues under these contracts were recognized on a percentage-of-

completion basis. The method used to determine the progress of completion was based on the ratio of costs incurred to total estimated costs on
construction projects. An increase in estimated costs on one large job in progress at Foley in excess of previous period cost estimates resulted in
pretax charges of $4.4 million in 2015.

IMPACT OF INFLATION
OTP operates under regulatory provisions that allow price changes in fuel and certain purchased power costs to be passed to most retail customers
through automatic adjustments to its rate schedules under fuel clause adjustments. Other increases in the cost of electric service must be recovered
through timely filings for electric rate increases with the appropriate regulatory agency.

Our Manufacturing and Plastics segments consist entirely of businesses whose revenues are not subject to regulation by ratemaking authorities.

Increased operating costs are reflected in product or services pricing with any limitations on price increases determined by the marketplace. Raw
material costs, labor costs, fuel and energy costs and interest rates are important components of costs for companies in these segments. Any or
all of these components could be impacted by inflation or other pricing pressures, with a possible adverse effect on our profitability, especially
where increases in these costs exceed price increases on finished products. In recent years, our operating companies have faced strong inflationary
and other pricing pressures with respect to steel, fuel, resin, and health care costs, which have been partially mitigated by pricing adjustments.

LIQUIDITY

The following table presents the status of our lines of credit as of December 31, 2017 and December 31, 2016:

(in thousands)

Otter Tail Corporation Credit Agreement
OTP Credit Agreement (1)

Total

Line Limit

130,000
170,000

300,000

In Use on
December 31, 2017

—
112,371

$ 112,371

Restricted due
to Outstanding
Letters of Credit

—
300

300

Available on
December 31, 2017

Available on
December 31, 2016

130,000
57,329

187,329

$ 130,000
127,067

$ 257,067

(1) $100 million in outstanding borrowings under the OTP Credit Agreement were repaid on February 7, 2018 with proceeds from the issuance of $100 million of OTP’s 4.07%

Series 2018A Notes due February 7, 2048.

We believe we have the necessary liquidity to effectively conduct
business operations for an extended period if needed. Our balance
sheet is strong and we are in compliance with our debt covenants.
Financial flexibility is provided by operating cash flows, unused lines
of credit, strong financial coverages, investment grade credit ratings
and alternative financing arrangements such as leasing.

We believe our financial condition is strong and our cash, other
liquid assets, operating cash flows, existing lines of credit, access to
capital markets and borrowing ability because of investment-grade
credit ratings, when taken together, provide adequate resources to
fund ongoing operating requirements and future capital expenditures
related to expansion of existing businesses and development of new
projects. On May 11, 2015 we filed a shelf registration statement with
the Securities and Exchange Commission (SEC) under which we may
offer for sale, from time to time, either separately or together in any
combination, equity, debt or other securities described in the shelf
registration statement, which expires on May 11, 2018. On May 11, 2015,
we entered into a Distribution Agreement with J.P. Morgan Securities LLC
(JPMS) under which we may offer and sell our common shares
from time to time through JPMS, as our distribution agent, up to an
aggregate sales price of $75 million through an At-the-Market offering
program. No shares were issued under this program in 2017.

Equity or debt financing will be required in the period 2018 through

2022 given the expansion plans related to our Electric segment to
fund construction of new rate base investments. Also, such financing
will be required should we decide to reduce borrowings under our
lines of credit or refund or retire early any of our presently outstanding
debt, to complete acquisitions or for other corporate purposes. Our
operating cash flows and access to capital markets can be impacted by
macroeconomic factors outside our control. In addition, our borrowing
costs can be impacted by changing interest rates on short-term and
long-term debt and ratings assigned to us by independent rating
agencies, which in part are based on certain credit measures such as
interest coverage and leverage ratios.

The determination of the amount of future cash dividends to be
declared and paid will depend on, among other things, our financial
condition, improvement in earnings per share, cash flows from
operations, the level of our capital expenditures and our future business
prospects. As a result of certain statutory limitations or regulatory or
financing agreements, restrictions could occur on the amount of
distributions allowed to be made by our subsidiaries. See note 7 to
consolidated financial statements for more information. The decision
to declare a dividend is reviewed quarterly by the board of directors.
On February 5, 2018 our board of directors increased the quarterly
dividend from $0.32 to $0.335 per common share.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

2017 Cash Flows Compared with 2016 Cash Flows
The $10.1 million increase in cash provided by continuing operations
between the years includes a $10.1 million increase in net income from
continuing operations, a $10.0 million reduction in discretionary
contributions to our pension plan. Changes in long-term assets and
liabilities, including deferred taxes, totaling $17.4 million were more
than offset by a $27.0 million increase in cash used for working capital
items. The increase in cash used for working capital between the
periods is primarily due to a $19.1 million increase in cash used for
payables and other current liabilities between the years at OTP related
to the timing of payments as cash use decreased $10.3 million in 2016
compared to an increase of $8.8 million in cash used for payables and
other current liabilities in 2017. Cash used for inventories increased
$6.2 million between the years primarily due to increased levels of
inventory in each of our business segments.

Net cash used in investing activities was $132.6 million in 2017
compared with $159.3 million in 2016. The $26.7 million decrease in
cash used for investing activities includes a $28.3 million decrease in
cash used for capital expenditures offset by $1.5 million in acquisition
purchase price adjustments. The decrease in cash used for capital
expenditures is mainly due to a $31.2 million reduction in cash used for
capital expenditures at OTP as work concluded on the Big Stone
South–Brookings 345 kV transmission line project which was energized
in September 2017. Capital expenditures increased $2.8 million in our
Manufacturing and Plastics segments.

Net cash used in financing activities was $24.8 million in 2017

compared with $4.1 million in 2016. Financing activities in 2017
included a $69.5 million increase in net short-term borrowings under
OTP’s credit agreement, of which $33.0 million was used to redeem
OTP’s 5.95% Senior Unsecured Series A Notes which matured on
August 20, 2017. The additional short-term borrowings were used to
fund a portion of OTP’s 2017 capital expenditures. Operating cash
flows from our Manufacturing and Plastic’s segments were used to
repay an additional $15.2 million in long-term debt related to those
operations. Financing activities in 2017 also included $2.4 million from
an increase in checks written in excess of cash and $4.3 million in net
proceeds from the issuance of common stock under our automatic
dividend reinvestment and share purchase plan, offset by $1.8 million
in stock repurchases related to tax withholding requirements for stock
incentive awards. See note 5 to the Company’s consolidated financial
statements for further information on stock issuances and retirements
in 2017. We paid common stock dividends of $50.6 million in 2017
compared with $48.2 million in 2016.

2016 Cash Flows Compared with 2015 Cash Flows
Cash provided by operating activities of continuing operations was
$163.5 million in 2016 compared with $131.5 million in 2015. The
$32.0 million increase in cash provided by continuing operations
between the years includes a $32.8 million reduction in cash used
for working capital items due to:
— An $18.2 million decrease in cash used for accounts payable and

other current liabilities at OTP, reflecting higher levels of payables in
December 2016 for coal deliveries and transmission services related
to the colder temperatures in December 2016 and the payment, in
January 2015, of large billings for coal transportation, coal and
power purchased in December 2014.

— A $10.7 million decrease in cash used for accounts payable and

other current liabilities at the plastic pipe companies related to an
increase in year-end resin purchases in 2016 compared to 2015.

— A $7.3 million decrease in cash used for interest payable and income
taxes receivable between the years, mainly related to having made
a $4.0 million estimated tax payment in December 2015 that was
refunded in the first quarter of 2016, as a five-year extension of
bonus depreciation for income taxes, approved on December 18,
2015, resulted in a lower federal income tax liability for the
Company in 2015.

offset by:
— A $2.3 million increase in unbilled revenues at OTP between the

years resulting from the 2016 increase in interim rates in Minnesota
and increased kwh sales due to colder weather in December 2016
compared with December 2015.

In continuing operations, net cash used in investing activities was

$159.3 million in 2016 compared with $193.6 million in 2015. The
$34.3 million decrease in cash used for investing activities includes a
$32.3 million decrease in cash used in acquisitions as we paid
$30.8 million to acquire the assets of BTD-Georgia in September 2015
and received a purchase price adjustment of $1.5 million in June 2016.
Net cash used in financing activities of continuing operations was

$4.1 million in 2016 compared with net cash provided by financing
activities of $38.1 million in 2015. Financing activities in 2016 included:
— $80.0 million in proceeds from the issuance of our 3.55% Guaranteed

Senior Notes due December 15, 2026 in December 2016.
— $50.0 million borrowed under our term loan agreement in

February 2016.

— $32.8 million in net proceeds from the issuance of 1,014,115 shares of
common stock under the Company’s At-the-Market offering program.
— $11.1 million in net proceeds from the issuance of 356,399 shares of

common stock under the Company’s automatic dividend reinvestment
and share purchase plan.

offset by:
— The repayment of the $52.3 million balance of our 9.000% notes

due in December 2016.

— A $41.2 million reduction of short-term borrowings and checks

written in excess of cash.

— The repayment of $35.0 million of funds borrowed in February 2016

under our term loan agreement.

— $48.2 million in common stock dividend payments.

The outstanding short-term borrowings that were paid down were,

in part, used to fund the expansion of BTD’s Minnesota facilities in
2015 and the September 1, 2015 acquisition of BTD-Georgia.

CASH REALIZATION (millions)

2.4x

4
7
1
$

2.6x

4
6
1
$

2.2x

2
3
1
$

9
5
$

2
6
$

2
7
$

$200

$150

$100

$50

INTEREST-BEARING DEBT AS A
PERCENT OF TOTAL CAPITAL
(millions)

$1,500

$1,000

$500

%
9
4

%
6
4

Cash flows from continuing operations

Total capital

Net income from continuing operations

Interest-bearing debt (includes short-term debt)

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

CAPITAL REQUIREMENTS

CAPITAL EXPENDITURES
We have a capital expenditure program for expanding, upgrading and
improving our plants and operating equipment. Typical uses of cash
for capital expenditures are investments in electric generation facilities
and environmental upgrades, transmission and distribution lines,
manufacturing facilities and upgrades, equipment used in the
manufacturing process, and computer hardware and information
systems. The capital expenditure program is subject to review and
is revised in light of changes in demands for energy, technology,
environmental laws, regulatory changes, business expansion
opportunities, the costs of labor, materials and equipment and our
consolidated financial condition.

Cash used for consolidated capital expenditures was $132.9 million

in 2017, $161.3 million in 2016 and $160 million in 2015. Estimated
capital expenditures for 2018 are $110 million. Total capital expenditures
for the five-year period 2018 through 2022 are estimated to be
approximately $973 million, including:
— $302 million for renewable wind and solar energy generation projects.
— $161 million for natural gas-fired generation to replace Hoot Lake

Plant capacity.

— $35 million for OTP’s Big Stone South–Ellendale 345 kV transmission

line project.

The breakdown of 2015, 2016 and 2017 actual cash used for capital
expenditures and 2018 through 2022 estimated capital expenditures
by segment is as follows:

(in millions)

2015 2016 2017 2018 2019 2020 2021 2022 2018-2022

Electric
Manufacturing
Plastics

$ 136 $ 150 $ 119 $ 95 $382 $185 $145 $ 94
11
11
3
4

10
4

11
4

10
4

20
4

8
3

Total

$ 160 $ 161 $ 133 $110 $396 $200 $159 $108

$ 901
53
19

$ 973

On November 16, 2016 OTP entered into an Asset Purchase Agreement
(the Purchase Agreement) with EDF Renewable Development, Inc. and
certain of its affiliated companies (EDF) to purchase and assume the
development assets associated with a 150-MW wind farm in south-
eastern North Dakota (the Merricourt Project) for a purchase price of
$34.7 million, subject to adjustments for interconnection costs. The
Purchase Agreement is currently expected to close no earlier than
mid-2018, pending regulatory reviews, satisfactory interconnection costs
and other conditions. On the same day, OTP entered into a Turnkey
Engineering, Procurement and Construction Services Agreement with
EDF that will be effective upon the closing of the Purchase Agreement
pursuant to which EDF will construct the wind farm with a targeted
completion date in 2019 for consideration of $200.5 million, subject to
certain adjustments, payable following the closing of the Purchase
Agreement in installments in connection with certain project construction
milestones. The agreements contain representations, warranties,
covenants and indemnities customary to transactions of this type and
include provisions for liquidated damages to be paid by EDF in the
event of certain occurrences described in the agreements. As of
December 31, 2017 OTP had capitalized approximately $4.5 million
in development costs associated with the Merricourt Project.

On April 10, 2017 OTP submitted an application for Advance
Determination of Prudence (ADP) and Certificate of Public Convenience
and Necessity to the North Dakota Public Service Commission (NDPSC)
for the Merricourt Project. A final order for the ADP, subject to
qualifications and compliance obligations, and the Certificate of Public
Convenience and Necessity was issued by the NDPSC on November 3,
2017. On October 26, 2017 the MNPUC approved the facility under
the Renewable Energy Standard making the project eligible for cost
recovery under the Minnesota Renewable Resource Recovery rider.
In addition to initiation of the Merricourt Project, OTP is moving
forward with plans for the development, construction and ownership
of a 250-MW simple-cycle natural gas-fired combustion turbine
generation facility near Astoria, South Dakota (Astoria Station) as part
of its plan to reliably meet customers’ electric needs, replace expiring
capacity purchase agreements and prepare for the planned retirement
of its Hoot Lake Plant in 2021. OTP expects the project will cost
approximately $165 million. As of December 31, 2017 OTP had
capitalized approximately $3.8 million in development costs associated
with Astoria Station. On April 10, 2017 OTP also submitted an
application for ADP to the NDPSC for the Astoria Station. A final
order for the ADP for Astoria Station was issued by the NDPSC on
November 3, 2017, subject to certain qualifications and compliance
obligations.

If a resource addition is determined to be prudent by the NDPSC, a
public utility may recover in its rates for North Dakota customers, and in
a timely manner consistent with the public utility’s financial obligations,
the jurisdictional share of amounts the public utility reasonably incurred
or obligated on a prudent resource addition, including accrued allowance
for funds used during construction, even though the resource addition
may never be fully operational or used by the public utility to serve
its North Dakota customers. The cost amortization period for a
discontinued resource addition may not exceed five years from the
date commencement of the recovery is approved by the NDPSC. No
return on amounts incurred or obligated by the public utility may be
authorized for the period after the resource addition is discontinued.

CONTRACTUAL OBLIGATIONS
The following table summarizes our contractual obligations at
December 31, 2017, plus our debt and interest obligations on the
$100 million in debt OTP issued on February 7, 2018, and the effect
these obligations are expected to have on our liquidity and cash flow
in future periods.

(in millions)

Less
than

1-3
1 Year Years

More
3-5 than 5
Years Years

Total

Coal Contracts (required minimums) $ 644 $
Debt Obligations
Interest on Debt Obligations
Capacity and Energy Requirements
Postretirement Benefit Obligations
Other Purchase Obligations
Operating Lease Obligations

593
433
253
112
48
34

26 $ 45
—
—
58
29
50
24
11
6
17
29
10
6

$ 45 $ 528
422
295
154
83
—
13

171
51
25
12
2
5

Total Contractual Cash Obligations

$ 2,117 $ 120 $ 191

$ 311 $1,495

Postretirement Benefit Obligations include estimated cash

expenditures for the payment of retiree medical and life insurance
benefits and supplemental pension benefits under our unfunded
Executive Survivor and Supplemental Retirement Plan, but do not
include amounts to fund our noncontributory funded pension plan,
as we are not currently required to make a contribution to that plan.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

CAPITAL RESOURCES

Financial flexibility is provided by operating cash flows, unused lines of credit, strong financial coverages, investment grade credit ratings, and
alternative financing arrangements such as leasing. Equity or debt financing will be required in the period 2018 through 2022 given the expansion
plans related to our Electric segment to fund construction of new rate base and transmission investments, in the event we decide to reduce
borrowings under our lines of credit, to refund or retire early any of our presently outstanding debt, to complete acquisitions or for other corporate
purposes. There can be no assurance that any additional required financing will be available through bank borrowings, debt or equity financing or
otherwise, or that if such financing is available, it will be available on terms acceptable to us. If adequate funds are not available on acceptable
terms, our businesses, results of operations and financial condition could be adversely affected.

Under our shelf registration statement filed with the SEC we may offer for sale, from time to time, either separately or together in any

combination, equity, debt or other securities described in the shelf registration statement, until May 11, 2018.

Under our At-the-Market offering program, we may offer and sell our common shares from time to time until May 11, 2018 through JPMS, as
our distribution agent, up to an aggregate sales price of $75 million, of which $39.2 million remained available at December 31, 2017. Under the
Distribution Agreement with JPMS, we will designate the minimum price and maximum number of shares to be sold through JPMS on any given
trading day or over a specified period of trading days, and JPMS will use commercially reasonable efforts to sell such shares on such days, subject
to certain conditions. We are not obligated to sell and JPMS is not obligated to buy or sell any of the shares under the Agreement.

SHORT-TERM DEBT
The following table presents the status of our lines of credit as of December 31, 2017 and December 31, 2016:

(in thousands)

Otter Tail Corporation Credit Agreement
OTP Credit Agreement (1)

Total

Line Limit

130,000
170,000

300,000

In Use on
December 31, 2017

—
112,371

$ 112,371

Restricted due
to Outstanding
Letters of Credit

—
300

300

Available on
December 31, 2017

Available on
December 31, 2016

130,000
57,329

187,329

$ 130,000
127,067

$ 257,067

(1) $100 million in outstanding borrowings under the OTP Credit Agreement were repaid on February 7, 2018 with proceeds from the issuance of $100 million of OTP’s 4.07% Series

2018A Notes due February 7, 2048.

Under the Otter Tail Corporation Credit Agreement (as defined below),
the maximum amount of debt outstanding in 2017 was $15,169,000 on
April 3, 2017 and the average daily balance of debt outstanding during
2017 was $2,305,000. The weighted average interest rate paid on debt
outstanding under the Otter Tail Corporation Credit Agreement during
2017 was 2.8% compared with 2.3% in 2016. Under the OTP Credit
Agreement (as defined below), the maximum amount of debt
outstanding in 2017 was $112,371,000 from December 29-31, 2017
and the average daily balance of debt outstanding during 2017 was
$69,391,000. The weighted average interest rate paid on debt
outstanding under the OTP Credit Agreement during 2017 was 2.4%
compared with 1.8% in 2016. The maximum amount of consolidated
short-term debt outstanding in 2017 was $112,371,000 from
December 29-31, 2017 and the average daily balance of consolidated
short-term debt outstanding during 2017 was $71,696,000. The
weighted average interest rate on consolidated short-term debt
outstanding on December 31, 2017 was 2.7%.

On October 29, 2012 we entered into a Third Amended and Restated
Credit Agreement (the Otter Tail Corporation Credit Agreement), which
is an unsecured $130 million revolving credit facility that may be increased
to $250 million on the terms and subject to the conditions described
in the Otter Tail Corporation Credit Agreement. On October 31, 2017
the Otter Tail Corporation Credit Agreement was amended to extend its
expiration date by one year from October 29, 2021 to October 31, 2022.
We can draw on this credit facility to refinance certain indebtedness
and support our operations and the operations of certain of our
subsidiaries. Borrowings under the Otter Tail Corporation Credit
Agreement bear interest at LIBOR plus 1.50%, subject to adjustment
based on our senior unsecured credit ratings or the issuer rating if a
rating is not provided for the senior unsecured credit. We are required
to pay commitment fees based on the average daily unused amount
available to be drawn under the revolving credit facility. The Otter Tail
Corporation Credit Agreement contains a number of restrictions on us
and the businesses of our wholly owned subsidiary, Varistar Corporation
(Varistar) and its subsidiaries, including restrictions on our and their

ability to merge, sell assets, make investments, create or incur liens on
assets, guarantee the obligations of certain other parties and engage
in transactions with related parties. The Otter Tail Corporation Credit
Agreement also contains affirmative covenants and events of default,
and financial covenants as described below under the heading
“Financial Covenants.” The Otter Tail Corporation Credit Agreement
does not include provisions for the termination of the agreement or
the acceleration of repayment of amounts outstanding due to changes
in our credit ratings. Our obligations under the Otter Tail Corporation
Credit Agreement are guaranteed by certain of our subsidiaries.
Outstanding letters of credit issued by us under the Otter Tail
Corporation Credit Agreement can reduce the amount available for
borrowing under the line by up to $40 million.

On October 29, 2012 OTP entered into a Second Amended and
Restated Credit Agreement (the OTP Credit Agreement), providing
for an unsecured $170 million revolving credit facility that may be
increased to $250 million on the terms and subject to the conditions
described in the OTP Credit Agreement. On October 31, 2017 the OTP
Credit Agreement was amended to extend its expiration date by one
year from October 29, 2021 to October 31, 2022. OTP can draw on this
credit facility to support the working capital needs and other capital
requirements of its operations, including letters of credit in an aggregate
amount not to exceed $50 million outstanding at any time. Borrowings
under this line of credit bear interest at LIBOR plus 1.25%, subject to
adjustment based on the ratings of OTP’s senior unsecured debt or
the issuer rating if a rating is not provided for the senior unsecured
debt. OTP is required to pay commitment fees based on the average
daily unused amount available to be drawn under the revolving credit
facility. The OTP Credit Agreement contains a number of restrictions on
the business of OTP, including restrictions on its ability to merge, sell
assets, make investments, create or incur liens on assets, guarantee
the obligations of any other party, and engage in transactions with
related parties. The OTP Credit Agreement also contains affirmative
covenants and events of default, and financial covenants as described
below under the heading “Financial Covenants.” The OTP Credit

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

Agreement does not include provisions for the termination of the
agreement or the acceleration of repayment of amounts outstanding
due to changes in OTP’s credit ratings. OTP’s obligations under the
OTP Credit Agreement are not guaranteed by any other party.

LONG-TERM DEBT
2018 Note Purchase Agreement
On November 14, 2017, OTP entered into a Note Purchase Agreement
(the 2018 Note Purchase Agreement) with the purchasers named
therein, pursuant to which OTP agreed to issue to the purchasers, in a
private placement transaction, $100 million aggregate principal amount
of OTP’s 4.07% Series 2018A Senior Unsecured Notes due February 7,
2048 (the 2018 Notes). The 2018 Notes were issued on February 7,
2018. Proceeds from the 2018 Notes were used to repay $100 million
in outstanding borrowings under the OTP Credit Agreement.

OTP may prepay all or any part of the 2018 Notes (in an amount not

less than 10% of the aggregate principal amount of the Notes then
outstanding in the case of a partial prepayment) at 100% of the principal
amount so prepaid, together with unpaid accrued interest and a
make-whole amount; provided that if no default or event of default
exists under the 2018 Note Purchase Agreement, any prepayment
made by OTP of all of the 2018 Notes then outstanding on or after
August 7, 2047 will be made without any make-whole amount. The
2018 Note Purchase Agreement also requires OTP to offer to prepay
all outstanding 2018 Notes at 100% of the principal amount together
with unpaid accrued interest in the event of a Change of Control
(as defined in the 2018 Note Purchase Agreement) of OTP.

The 2018 Note Purchase Agreement contains a number of restrictions
on the business of OTP. These include restrictions on OTP’s abilities to
merge, sell assets, create or incur liens on assets, guarantee the
obligations of any other party, and engage in transactions with related
parties. The 2018 Note Purchase Agreement also contains other
negative covenants and events of default, as well as certain financial
covenants as described below under the heading “Financial
Covenants.” The 2018 Note Purchase Agreement does not include
provisions for the termination of the agreement or the acceleration of
repayment of amounts outstanding due to changes in OTP’s credit
ratings. The 2018 Note Purchase Agreement includes a “most favored
lender” provision generally requiring that in the event the OTP Credit
Agreement or any renewal, extension or replacement thereof, at any
time contains any financial covenant or other provision providing for
limitations on interest expense and such a covenant is not contained
in the 2018 Note Purchase Agreement under substantially similar
terms or would be more beneficial to the holders of the 2018 Notes
than any analogous provision contained in the 2018 Note Purchase
Agreement (an Additional Covenant), then unless waived by the
Required Holders (as defined in the 2018 Note Purchase Agreement),
the Additional Covenant will be deemed to be incorporated into the
2018 Note Purchase Agreement. The 2018 Note Purchase Agreement
also provides for the amendment, modification or deletion of an
Additional Covenant if such Additional Covenant is amended or
modified under or deleted from the OTP Credit Agreement, provided
that no default or event of default has occurred and is continuing.

2016 Note Purchase Agreement
On September 23, 2016 we entered into a Note Purchase Agreement
(the 2016 Note Purchase Agreement) with the purchasers named
therein, pursuant to which we agreed to issue to the purchasers, in a
private placement transaction, $80 million aggregate principal amount
of our 3.55% Guaranteed Senior Notes due December 15, 2026 (the
2026 Notes). The 2026 Notes were issued on December 13, 2016. Our
obligations under the 2016 Note Purchase Agreement and the 2026
Notes are guaranteed by our Material Subsidiaries (as defined in the
2016 Note Purchase Agreement, but specifically excluding OTP). The

proceeds from the issuance of the 2026 Notes were used to repay the
remaining $52,330,000 of our 9.000% Senior Notes due December 15,
2016, and to pay down a portion of the $50 million in funds borrowed
in February 2016 under our Term Loan Agreement described below.

We may prepay all or any part of the 2026 Notes (in an amount not

less than 10% of the aggregate principal amount of the 2026 Notes
then outstanding in the case of a partial prepayment) at 100% of the
principal amount prepaid, together with unpaid accrued interest and
a make-whole amount; provided that if no default or event of default
exists under the 2016 Note Purchase Agreement, any optional
prepayment made by us of all of the 2026 Notes on or after
September 15, 2026 will be made without any make-whole amount.
We are required to offer to prepay all of the outstanding 2026 Notes
at 100% of the principal amount together with unpaid accrued interest
in the event of a Change of Control (as defined in the 2016 Note
Purchase Agreement) of the Company. In addition, if we and our
Material Subsidiaries sell a “substantial part” of our or their assets
and use the proceeds to prepay or retire senior Interest-bearing Debt
(as defined in the 2016 Note Purchase Agreement) of the Company
and/or a Material Subsidiary in accordance with the terms of the 2016
Note Purchase Agreement, we are required to offer to prepay a Ratable
Portion (as defined in the 2016 Note Purchase Agreement) of the
2026 Notes held by each holder of the 2026 Notes.

The 2016 Note Purchase Agreement contains a number of restrictions

on the business of the Company and our Material Subsidiaries. These
include restrictions on our and our Material Subsidiaries’ abilities to
merge, sell assets, create or incur liens on assets, guarantee the
obligations of any other party, engage in transactions with related
parties, redeem or pay dividends on our and our Material Subsidiaries’
shares of capital stock, and make investments. The 2016 Note Purchase
Agreement also contains other negative covenants and events of
default, as well as certain financial covenants as described below
under the heading “Financial Covenants.” The 2016 Note Purchase
Agreement does not include provisions for the termination of the
agreement or the acceleration of repayment of amounts outstanding
due to changes in our or our Material Subsidiaries’ credit ratings.

Term Loan Agreement
On February 5, 2016 we borrowed $50 million under an unsecured
Term Loan Agreement (the Term Loan Agreement) at an interest rate
based on the 30 day LIBOR plus 90 basis points. The proceeds from
the Term Loan Agreement were used to pay down borrowings under
the Otter Tail Corporation Credit Agreement that were used to fund
the expansion of BTD’s Minnesota facilities in 2015 and to fund the
September 1, 2015 acquisition of BTD-Georgia. We repaid $35 million
of the $50 million in the fourth quarter of 2016 and we repaid the
remaining $15 million during 2017. The Term Loan Agreement
terminated on February 5, 2018.

2013 Note Purchase Agreement
On August 14, 2013 OTP entered into a Note Purchase Agreement (the
2013 Note Purchase Agreement) with the purchasers named therein,
pursuant to which OTP agreed to issue to the purchasers, in a private
placement transaction, $60 million aggregate principal amount of
OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029
(the Series A Notes) and $90 million aggregate principal amount of
OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044
(the Series B Notes and, together with the Series A Notes, the Notes).
The notes were issued on February 27, 2014.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

or event of default under the 2013 Note Purchase Agreement exists,
any optional prepayment made by OTP of (i) all of the Series A Notes
then outstanding on or after November 27, 2028 or (ii) all of the Series B
Notes then outstanding on or after November 27, 2043, will be made
at 100% of the principal prepaid but without any make-whole amount.
In addition, the 2013 Note Purchase Agreement states OTP must offer
to prepay all of the outstanding Notes at 100% of the principal amount
together with unpaid accrued interest in the event of a Change of
Control (as defined in the 2013 Note Purchase Agreement) of OTP.

The 2013 Note Purchase Agreement contains a number of restrictions
on the business of OTP, including restrictions on OTP’s ability to merge,
sell assets, create or incur liens on assets, guarantee the obligations of
any other party, and engage in transactions with related parties. The
2013 Note Purchase Agreement also contains affirmative covenants and
events of default, as well as certain financial covenants as described
below under the heading “Financial Covenants.” The 2013 Note Purchase
Agreement does not include provisions for the termination of the
agreement or the acceleration of repayment of amounts outstanding
due to changes in OTP’s credit ratings. The 2013 Note Purchase
Agreement includes a “most favored lender” provision generally
requiring that in the event the OTP Credit Agreement or any renewal,
extension or replacement thereof, at any time contains any financial
covenant or other provision providing for limitations on interest expense
and such a covenant is not contained in the 2013 Note Purchase
Agreement under substantially similar terms or would be more
beneficial to the holders of the Notes than any analogous provision
contained in the 2013 Note Purchase Agreement (an Additional
Covenant), then unless waived by the Required Holders (as defined in
the 2013 Note Purchase Agreement), the Additional Covenant will be
deemed to be incorporated into the 2013 Note Purchase Agreement.
The 2013 Note Purchase Agreement also provides for the amendment,
modification or deletion of an Additional Covenant if such Additional
Covenant is amended or modified under or deleted from the OTP
credit agreement, provided that no default or event of default has
occurred and is continuing.

2007 and 2011 Note Purchase Agreements
On December 1, 2011, OTP issued $140 million aggregate principal
amount of its 4.63% Senior Unsecured Notes due December 1, 2021
pursuant to a Note Purchase Agreement dated as of July 29, 2011
(the 2011 Note Purchase Agreement). OTP also has outstanding its
$122 million senior unsecured notes issued in three series consisting of
$30 million aggregate principal amount of 6.15% Senior Unsecured
Notes, Series B, due 2022; $42 million aggregate principal amount of
6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million
aggregate principal amount of 6.47% Senior Unsecured Notes, Series D,
due 2037 (collectively, the 2007 Notes). The 2007 Notes were issued
pursuant to a Note Purchase Agreement dated as of August 20, 2007
(the 2007 Note Purchase Agreement). On August 21, 2017 OTP used
borrowings under the OTP Credit Agreement to retire its $33 million
aggregate principal amount of 5.95% Senior Unsecured Notes, Series A,
which had been issued under the 2007 Note Purchase Agreement and
matured on August 20, 2017.

The 2011 Note Purchase Agreement and the 2007 Note Purchase
Agreement each states that OTP may prepay all or any part of the
notes issued thereunder (in an amount not less than 10% of the
aggregate principal amount of the notes then outstanding in the case
of a partial prepayment) at 100% of the principal amount prepaid,
together with accrued interest and a make-whole amount. The 2011
Note Purchase Agreement states in the event of a transfer of utility
assets put event, the noteholders thereunder have the right to require
OTP to repurchase the notes held by them in full, together with accrued

interest and a make-whole amount, on the terms and conditions
specified in the 2011 Note Purchase Agreement. The 2011 Note Purchase
Agreement and the 2007 Note Purchase Agreement each also states
that OTP must offer to prepay all of the outstanding notes issued
thereunder at 100% of the principal amount together with unpaid
accrued interest in the event of a change of control of OTP. The note
purchase agreements contain a number of restrictions on OTP, including
restrictions on OTP’s ability to merge, sell assets, create or incur liens
on assets, guarantee the obligations of any other party, and engage in
transactions with related parties. The note purchase agreements also
include affirmative covenants and events of default, and certain financial
covenants as described below under the heading “Financial Covenants.”

Financial Covenants
We were in compliance with the financial covenants in our debt
agreements as of December 31, 2017.

No Credit or Note Purchase Agreement contains any provisions
that would trigger an acceleration of the related debt as a result of
changes in the credit rating levels assigned to the related obligor
by rating agencies.

Our borrowing agreements are subject to certain financial

covenants. Specifically:
— Under the Otter Tail Corporation Credit Agreement and the 2016
Note Purchase Agreement, we may not permit the ratio of our
Interest-bearing Debt to Total Capitalization to be greater than
0.60 to 1.00 or permit our Interest and Dividend Coverage Ratio to
be less than 1.50 to 1.00 (each measured on a consolidated basis).
As of December 31, 2017 our Interest and Dividend Coverage Ratio
calculated under the requirements of the Otter Tail Corporation
Credit Agreement and the 2016 Note Purchase Agreement was
4.47 to 1.00.

— Under the 2016 Note Purchase Agreement, we may not permit our
Priority Indebtedness to exceed 10% of our Total Capitalization.
— Under the OTP Credit Agreement, OTP may not permit the ratio of
its Interest-bearing Debt to Total Capitalization to be greater than
0.60 to 1.00.

— Under the 2007 Note Purchase Agreement and 2011 Note Purchase
Agreement, OTP may not permit the ratio of its Consolidated Debt
to Total Capitalization to be greater than 0.60 to 1.00 or permit its
Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in
each case as provided in the related borrowing agreement, and OTP
may not permit its Priority Debt to exceed 20% of its Total
Capitalization, as provided in the related agreement. As of
December 31, 2017 OTP’s Interest and Dividend Coverage Ratio and
Interest Charges Coverage Ratio, calculated under the requirements
of the 2007 Note Purchase Agreement and 2011 Note Purchase
Agreement, was 3.62 to 1.00.

— Under the 2013 Note Purchase Agreement and the 2018 Note

Purchase Agreement, OTP may not permit its Interest-bearing Debt
to exceed 60% of Total Capitalization and may not permit its Priority
Indebtedness to exceed 20% of its Total Capitalization, in each case
as provided in the related agreement.

As of December 31, 2017 our ratio of Interest-bearing Debt to Total

Capitalization was 0.46 to 1.00 on a consolidated basis and 0.49 to
1.00 for OTP. Neither Otter Tail Corporation nor OTP had any Priority
Indebtedness outstanding as of December 31, 2017.

Our ratio of earnings to fixed charges from continuing operations

reported in Exhibit 12.1 to this Annual Report on Form 10-K, which
includes imputed finance costs on operating leases, was 4.1x for 2017
and 3.4x for 2016. During 2018, we expect this coverage ratio to
increase, assuming 2018 net income meets our expectations.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit
totaling $3.9 million, but our line of credit borrowing limits are only
restricted by $0.3 million in outstanding letters of credit. We do not
have any other off-balance-sheet arrangements or any relationships
with unconsolidated entities or financial partnerships. These entities
are often referred to as structured finance special purpose entities or
variable interest entities, which are established for the purpose of
facilitating off-balance-sheet arrangements or for other contractually
narrow or limited purposes. We are not exposed to any financing,
liquidity, market or credit risk that could arise if we had such relationships.

2018 BUSINESS OUTLOOK

We anticipate 2018 diluted earnings per share to be in the range of
$1.80 to $1.95. This guidance reflects the current mix of businesses we
own, strategies for improving future operating results, the cyclical
nature of some of our businesses, and current regulatory factors and
economic challenges facing our Electric, Manufacturing and Plastics
segments. Due to the tax rate reduction in the TCJA, we expect 2018
earnings for our Manufacturing and Plastics segments to be positively
impacted by $0.09 per share offset by $0.04 per share in our
corporate cost center. We expect capital expenditures for 2018 to be
$110 million compared with actual cash used for capital expenditures
of $133 million in 2017. Our planned expenditures for 2018 include
$33 million for the Big Stone South–Ellendale transmission line project,
which positively impacts earnings by providing an immediate return
on invested funds through rider recovery mechanisms.

Segment components of our 2018 earnings per share guidance

range compared with 2017 actual earnings are as follows:

2017 EPS by Segment

2018 EPS Guidance

GAAP-
Basis

1.24
$
0.28
$
$
0.54
$ (0.25)

Impact
of Tax
Reform

$
0.02
$ (0.07)
$ (0.08)
0.18
$

Before
Impact
of Tax
Reform(1)

Low

High

1.26
$
0.21
$
$
0.46
$ (0.07)

$ 1.37
$ 1.34
$ 0.30
$ 0.26
$ 0.36
$ 0.40
$ (0.16) $ (0.12)

Electric
Manufacturing
Plastics
Corporate

Total—Continuing

Operations

1.81

0.05

1.86

$ 1.80

$ 1.95

Return on Equity

10.6%

10.8%

10.1%

10.9%

(1) This table includes measures of financial performance and presentations of financial
information that are not defined by generally accepted accounting principles (GAAP).
Management believes that presenting diluted earnings per share from continuing
operations by segment and in total on a Non-GAAP basis by excluding the impact of the
TCJA tax rate reduction on deferred tax values will assist investors in making an
evaluation of our performance against expectations for 2018 on a comparable basis.
Management understands that there are material limitations on the use of non-GAAP
measures. Non-GAAP measures are not substitutes for GAAP measures for the purpose
of analyzing financial performance. These non-GAAP measures are not in accordance
with, or an alternative for, measures prepared in accordance with generally accepted
accounting principles and may be different from non-GAAP measures used by other
companies. In addition, these non-GAAP measures are not based on any comprehensive
set of accounting rules or principles. This information should not be construed as an
alternative to the reported results, which have been determined and provided in
accordance with GAAP.

Contributing to our earnings guidance for 2018 are the following
items:
— We expect 2018 Electric segment net income to be higher than

2017 segment net income based on:
• Normal weather for 2018. Milder than normal weather in 2017

negatively impacted diluted earnings per share by an estimated
$0.04 compared to normal.

• Constructive outcome of a rate case filed in North Dakota on
November 2, 2017 with a full year of increased interim rates in
2018. Our ability to obtain final rates similar to interim rates and
reasonable rates of return depends on regulatory action under
applicable statutes and regulations. We expect the effects of any
reduction in interim or final rates as a result of lower tax rates in
the TCJA to be offset by lower tax expenses. We cannot provide
assurance our interim rates will become final.

• Increase in transmission investments and other revenues.

offset by:

• Increased operating and maintenance expenses due to a planned
maintenance outage at our Big Stone Plant of $0.05 per share
and $0.09 for increasing costs of pension, medical, workers
compensation and retiree medical benefits. The increase in
pension costs is a result of a decrease in the discount rate from
4.60% to 3.90%.

• Higher depreciation and property tax expense due to large capital

projects being put into service.

• Increased interest expense related to replacing short-term debt at
an average annual rate of 2.4% with long-term debt at a rate of
4.07% along with an increase in combined short-term and
long-term borrowings to finance a portion of 2018 planned capital
expenditures.

— We expect 2018 net income from our Manufacturing segment to

increase over 2017 based on the following:
• Sales at BTD are expected to be flat year-over-year however,

earnings are expected to improve based on stronger year-over-year
operating margins achieved through cost reductions and
improved productivity.

• An increase in earnings from T.O. Plastics mainly driven by year-
over-year sales growth in horticulture, life science and industrial
markets.

• Lower income taxes of approximately $0.04 per share as a result
of the lower federal tax rates implemented as part of the TCJA.

• Backlog for the manufacturing companies of approximately

$166 million for 2018 compared with $118 million one year ago.
— We expect 2018 net income from the Plastics segment to be lower
than 2017, because 2017 results included sales driven by customer
reaction to the hurricanes that occurred in the Gulf of Mexico. This
had an estimated impact on earnings of $0.09 per diluted share in
2017. We also expect lower operating margins in 2018 due to a lower
expected sales prices and increasing resin prices on similar sales
volumes in 2018 compared to 2017 excluding the effect of the
hurricanes on 2017 sales. Plastics net income for 2018 will be
positively affected by lower effective tax rates in 2018 as a result of
the TCJA.

— Corporate costs, net of tax, are expected to be higher in 2018 than
in 2017 when excluding the effect of the TCJA on 2017 net losses in
the corporate cost center. The higher net-of-tax costs expected in
2018 are due, in part, to the lower tax rate that will be in effect in 2018.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

The impact of the TCJA on future results are based on reasonable estimates reflecting the anticipated impact of the TCJA, and are subject to
adjustment upon obtaining additional information or to reflect future changes resulting from future legislation, rules, regulations or interpretations
impacting the TCJA. The Company will continue to analyze the impact of the TCJA to assess the full effects on the Company’s future business and results.
The following table shows our 2017 capital expenditures and 2018 through 2022 anticipated capital expenditures and electric utility average

rate base:

(in millions)

Capital Expenditures:
Electric Segment:

Renewables and Natural Gas Generation
Transformative Technology and Infrastructure
Transmission
Other

Total Electric Segment
Manufacturing and Plastics Segments

Total Capital Expenditures

Total Electric Utility Average Rate Base

2017

2018

2019

2020

2021

2022

Total

1
—
45
49

95
15

110

308
22
12
40

382
14

396

102
32
9
42

185
15

200

50
43
7
45

145
14

159

1
39
7
47

94
14

108

462
136
80
223

901
72

973

119
14

133

$ 1,055

$ 1,091

$ 1,297

$ 1,480

$ 1,568

$ 1,625

The consolidated capital expenditure plan for the 2018-2022 time period calls for $973 million based on the need for additional wind and solar
in rate base and capital spending for Astoria Station, a natural gas-fired plant that is expected to replace Hoot Lake Plant when it is retired in 2021.
Given the increased capital expenditure plan, our compounded annual growth rate in rate base is projected to be 9.0% from 2017 through 2022.
Execution on the currently anticipated electric utility capital expenditure plan is expected to grow rate base and be a key driver in increasing

utility earnings over the 2018 through 2022 timeframe.

Our outlook for 2018 is dependent on a variety of factors and is subject to the risks and uncertainties discussed in Item 1A. Risk Factors, and

elsewhere in this Annual Report on Form 10-K.

CRITICAL ACCOUNTING POLICIES INVOLVING
SIGNIFICANT ESTIMATES

Our significant accounting policies are described in note 1 to our
consolidated financial statements. The discussion and analysis of
the financial statements and results of operations are based on our
consolidated financial statements, which have been prepared in
accordance with accounting principles generally accepted in the
United States of America. The preparation of these consolidated financial
statements requires management to make estimates and judgments
that affect the reported amounts of assets, liabilities, revenues and
expenses, and related disclosure of contingent assets and liabilities.
We use estimates based on the best information available in

recording transactions and balances resulting from business operations.
Estimates are used for such items as depreciable lives, asset impairment
evaluations, tax provisions, collectability of trade accounts receivable,
self-insurance programs, unbilled electric revenues, interim rate refunds,
warranty reserves and actuarially determined benefits costs and
liabilities. As better information becomes available or actual amounts
are known, estimates are revised. Operating results can be affected by
revised estimates. Actual results may differ from these estimates
under different assumptions or conditions. Management has discussed
the application of these critical accounting policies and the development
of these estimates with the Audit Committee of the board of directors.
The following critical accounting policies affect the more significant
judgments and estimates used in the preparation of our consolidated
financial statements.

PENSION AND OTHER POSTRETIREMENT BENEFITS OBLIGATIONS
AND COSTS
Pension and postretirement benefit liabilities and expenses for our
electric utility and corporate employees are determined by actuaries
using assumptions about the discount rate, expected return on plan
assets, rate of compensation increase and healthcare cost-trend rates.
Further discussion of our pension and postretirement benefit plans

and related assumptions is included in note 10 to our consolidated
financial statements.

These benefits, for any individual employee, can be earned and

related expenses can be recognized and a liability accrued over periods
of up to 35 or more years. These benefits can be paid out for up to
40 or more years after an employee retires. Estimates of liabilities
and expenses related to these benefits are among our most critical
accounting estimates. Although deferral and amortization of
fluctuations in actuarially determined benefit obligations and expenses
are provided for when actual results on a year-to-year basis deviate
from long-range assumptions, compensation increases and healthcare
cost increases or a reduction in the discount rate applied from one
year to the next can significantly increase our benefit expenses in the
year of the change. Also, a reduction in the expected rate of return on
pension plan assets in our funded pension plan or realized rates of
return on plan assets that are well below assumed rates of return or an
increase in the anticipated life expectancy of plan participants could
result in significant increases in recognized pension benefit expenses
in the year of the change or for many years thereafter because
actuarial losses can be amortized over the average remaining service
lives of active employees.

The pension benefit cost for 2018 for our noncontributory funded
pension plan is expected to be $6.6 million compared to $5.9 million
in 2017, reflecting a decrease in the estimated discount rate used to
determine annual benefit cost accruals from 4.60% in 2017 to 3.90% in
2018. The assumed rate of return on pension plan assets will remain at
7.50% in 2018. In selecting the discount rate, we consider the yields of
fixed income debt securities, which have ratings of “Aa” published by
recognized rating agencies, along with bond matching models specific
to our plan’s cash flows as a basis to determine the rate.

Subsequent increases or decreases in actual rates of return on plan

assets over assumed rates or increases or decreases in the discount
rate or rate of increase in future compensation levels could significantly
change projected costs. For 2017, all other factors being held constant:
a 0.25 increase in the discount rate would have decreased our 2017

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

pension benefit cost by $904,000; a 0.25 decrease in the discount
rate would have increased our 2017 pension benefit cost by $950,000;
a 0.25 increase in the assumed rate of increase in future compensation
levels would have increased our 2017 pension benefit cost by
$555,000; a 0.25 decrease in the assumed rate of increase in future
compensation levels would have decreased our 2017 pension benefit
cost by $543,000; and a 0.25 increase (or decrease) in the expected
long-term rate of return on plan assets would have decreased (or
increased) our 2017 pension benefit cost by $641,000.

Increases or decreases in the discount rate or in retiree healthcare

cost inflation rates could significantly change our projected
postretirement healthcare benefit costs. A 0.25 increase in the
discount rate would have decreased our 2017 postretirement medical
benefit costs by $217,000. A 0.25 decrease in the discount rate would
have increased our 2017 postretirement medical benefit costs by
$228,000. See note 10 to consolidated financial statements for the
cost impact of a change in medical cost inflation rates.

We believe the estimates made for our pension and other

postretirement benefits are reasonable based on the information that
is known at the point in time the estimates are made. These estimates
and assumptions are subject to a number of variables and are subject
to change.

TAXATION
We are required to make judgments regarding the potential tax effects
of various financial transactions and our ongoing operations to estimate
our obligations to taxing authorities. These tax obligations include
income, real estate and use taxes. These judgments could result in the
recognition of a liability for potential adverse outcomes regarding
uncertain tax positions that we have taken. While we believe our
liability for uncertain tax positions as of December 31, 2017 reflects
the most likely probable expected outcome of these tax matters in
accordance with the requirements of ASC Topic 740, Income Taxes,
the ultimate outcome of such matters could result in additional
adjustments to our consolidated financial statements. However, we
do not believe such adjustments would be material.

Deferred income taxes are provided for revenue and expenses which
are recognized in different periods for income tax and financial reporting
purposes. We assess our deferred tax assets for recoverability taking
into consideration our historical and anticipated earnings levels, the
reversal of other existing temporary differences, available net operating
loss carryforwards and available tax planning strategies that could be
implemented to realize the deferred tax assets. Based on this assessment,
management must evaluate the need for, and amount of, a valuation
allowance against our deferred tax assets. As facts and circumstances
change, adjustments to the valuation allowance may be required.

ASSET IMPAIRMENT
We are required to test for asset impairment relating to property and
equipment whenever events or changes in circumstances indicate that
the carrying amount of a long-lived asset may exceed its fair value
and not be recoverable. We apply the accounting guidance under
ASC 360-10-35, Property, Plant, and Equipment—Subsequent
Measurement, in order to determine whether or not an asset is
impaired. This standard requires an impairment analysis when
indicators of impairment are present. If such indicators are present,
the standard requires that if the sum of the future expected cash
flows from a company’s asset, undiscounted and without interest
charges, is less than the carrying amount, an asset impairment must
be recognized in the financial statements. The amount of the
impairment is the difference between the fair value of the asset and
the carrying amount of the asset.

We believe the accounting estimates related to an asset impairment

are critical because: (1) they are highly susceptible to change from

period to period, reflecting changing business cycles, (2) they require
management to make assumptions about future cash flows over
future years, and (3) the impact of recognizing an impairment could
have a significant effect on operations. Management’s assumptions
about future cash flows require significant judgment because actual
operating levels have fluctuated in the past and are expected to
continue to do so in the future.

As of December 31, 2017 an assessment of the carrying amounts of

our long-lived assets and other intangibles indicated these assets
were not impaired.

GOODWILL IMPAIRMENT
Goodwill is required to be evaluated annually for impairment, according
to ASC 350-20-35, Goodwill—Subsequent Measurement. We perform
qualitative assessments of goodwill impairment and quantitative
goodwill impairment testing annually in the fourth quarter. In addition,
the quantitative testing is performed on an interim basis whenever
events or circumstances indicate that the carrying amount of goodwill
may not be recoverable. Examples of such events or circumstances may
include a significant adverse change in business climate, weakness in
an industry in which our reporting units operate or recent significant
cash or operating losses with expectations that those losses will continue.
Under GAAP, we have the option of first performing a qualitative
assessment to test goodwill for impairment on a reporting unit basis.
If, after applying the qualitative assessment, we conclude that it is not
more likely than not that the fair value of the reporting unit is less than
its carrying value, the quantitative goodwill impairment test is not
required. If, after performing the qualitative assessment, we conclude
that it is more likely than not that the fair value of the reporting unit
is less than its carrying value, we would perform the quantitative
goodwill impairment test.

The quantitative goodwill impairment test is a two-step process
performed at the reporting unit level. We have determined the reporting
units for our goodwill impairment test are our operating segments, or
components of an operating segment, that constitute a business for
which discrete financial information is available and for which our
chief operating decision makers regularly review the operating results.
For more information on our operating segments, see note 2 to
consolidated financial statements. The first step of the quantitative
impairment test involves comparing the fair value of each reporting
unit to its carrying value. If the fair value of a reporting unit exceeds
its carrying value, the test is complete and no impairment is recorded.
If the fair value of a reporting unit is less than its carrying value, step
two of the test is performed to determine the amount of impairment
loss, if any. The impairment is computed by comparing the implied fair
value of the reporting unit’s goodwill to the carrying value of that
goodwill. If the carrying value is greater than the implied fair value,
an impairment loss must be recorded. At December 31, 2017, the fair
value substantially exceeded the carrying value at all our reporting
units reported under continuing operations.

Conducting a qualitative assessment to determine if the fair value of

a reporting unit is more likely than not in excess of its carrying value
and determining the fair value of a reporting unit under quantitative
testing requires judgment and the use of significant estimates which
include assumptions about the reporting unit’s future revenue,
profitability and cash flows, amount and timing of estimated capital
expenditures, inflation rates, weighted average cost of capital,
operational plans, and current and future economic conditions,
among others. The fair value of each reporting unit is determined
using a weighted combination of income and market approaches.
We use a discounted cash flow methodology for our income approach.
Under this approach, the discounted cash flow model determines fair
value based on the present value of projected cash flows over a
specified period and a residual value related to future cash flows

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

beyond the projection period. Both values are discounted using a rate
which reflects the best estimate of the weighted average cost of capital
at each reporting unit. Under the market approach, we estimate fair
value using multiples derived from comparable enterprise value
to EBITDA multiples, comparable price earnings ratios, comparable
enterprise value to sales multiples and if available, comparable sales
transactions for comparative peer companies for each respective
reporting unit. These multiples are applied to operating data for each
reporting unit to arrive at an indication of fair value. When performing
a qualitative assessment, we evaluate whether forecast scenarios used
in the most recent quantitative fair value calculation continue to be
reasonable considering industry events and the reporting unit’s
current circumstances. We believe the estimates and assumptions
used in our impairment assessments are reasonable and based on
available market information, but variations in any of the assumptions
could result in materially different calculations of fair value and
determinations of whether or not impairment is indicated.

FORWARD-LOOKING INFORMATION—SAFE
HARBOR STATEMENT UNDER THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995

This Annual Report on Form 10-K contains forward-looking statements
within the meaning of the Private Securities Litigation Reform Act of
1995 (the Act). When used in this Form 10-K and in future filings by
the Company with the SEC, in the Company’s press releases and in
oral statements, words such as “may,” “will,” “expect,” “anticipate,”
“continue,” “estimate,” “project,” “believes” or similar expressions are
intended to identify forward-looking statements within the meaning
of the Act. Such statements are based on current expectations and
assumptions, and entail various risks and uncertainties that could
cause actual results to differ materially from those expressed in such
forward-looking statements. Such risks and uncertainties include the
various factors set forth in Item 1A. Risk Factors of this Annual Report
on Form 10-K and in our other SEC filings.

ITEM 7A. Quantitative and Qualitative Disclosures

About Market Risk

At December 31, 2017 we had exposure to market risk associated with
interest rates because OTP had $112.4 million in short-term debt
outstanding subject to variable interest rates indexed to LIBOR plus
1.25% under the OTP Credit Agreement.

All of our remaining consolidated long-term debt outstanding on
December 31, 2017 has fixed interest rates. We manage our interest
rate risk through the issuance of fixed-rate debt with varying maturities,
through economic refunding of debt through optional refundings,
limiting the amount of variable interest rate debt, and the utilization of
short-term borrowings to allow flexibility in the timing and placement
of long-term debt.

We have not used interest rate swaps to manage net exposure
to interest rate changes related to our portfolio of borrowings. We
maintain a ratio of fixed-rate debt to total debt within a certain range.
It is our policy to enter into interest rate transactions and other financial
instruments only to the extent considered necessary to meet our
stated objectives. We do not enter into interest rate transactions for
speculative or trading purposes.

The companies in our Manufacturing segment are exposed to

market risk related to changes in commodity prices for steel, aluminum
and polystyrene and other plastics resins. The price and availability of
these raw materials could affect the revenues and earnings of our
Manufacturing segment.

The plastics companies are exposed to market risk related to

changes in commodity prices for PVC resins, the raw material used to
manufacture PVC pipe. The PVC pipe industry is highly sensitive to
commodity raw material pricing volatility. Historically, when resin
prices are rising or stable, sales volume has been higher and when
resin prices are falling, sales volume has been lower. Operating income
may decline when the supply of PVC pipe increases faster than demand.
Due to the commodity nature of PVC resin and the dynamic supply
and demand factors worldwide, it is very difficult to predict gross
margin percentages or to assume that historical trends will continue.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

ITEM 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of
Otter Tail Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets and statements of capitalization of Otter Tail Corporation and subsidiaries
(the “Company”) as of December 31, 2017 and 2016, and the related consolidated statements of income, comprehensive income, common
shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and the schedule
listed in the Index at Item 15 (collectively referred to as the “financial statements”). We also have audited the Company’s internal control over
financial reporting as of December 31, 2017, based on criteria established in Internal Control—Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Otter Tail Corporation and
subsidiaries as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period
ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the
Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the criteria
established in Internal Control—Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and
for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report Regarding
Internal Controls Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the
Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company
Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the
U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether
effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements,
whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used
and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also
included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable
basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that,
in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance
that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.

Minneapolis, Minnesota
February 20, 2018

We have served as the Company’s auditor since 1944.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

CONSOLIDATED BALANCE SHEETS, DECEMBER 31

(in thousands)

Assets

Current Assets

Cash and Cash Equivalents
Accounts Receivable:

Trade (less allowance for doubtful accounts of $1,094 for 2017 and $1,246 for 2016)
Other
Inventories
Unbilled Revenues
Income Taxes Receivable
Regulatory Assets
Other

Total Current Assets

Investments
Other Assets
Goodwill
Other Intangibles—Net
Regulatory Assets

Plant

Electric Plant in Service
Nonelectric Operations
Construction Work in Progress

Total Gross Plant

Less Accumulated Depreciation and Amortization

Net Plant

Total Assets

See accompanying notes to consolidated financial statements.

2017

2016

16,216

—

68,466
7,761
88,034
22,427
1,181
22,551
12,491

68,242
5,850
83,740
20,080
662
21,297
8,144

239,127

208,015

8,629
36,006
37,572
13,765
129,576

1,981,018
216,937
141,067

2,339,022
799,419

1,539,603

8,417
34,104
37,572
14,958
132,094

1,860,357
211,826
153,261

2,225,444
748,219

1,477,225

$ 2,004,278

$1,912,385

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

CONSOLIDATED BALANCE SHEETS, DECEMBER 31

(in thousands, except share data)

Liabilities and Equity

Current Liabilities
Short-Term Debt
Current Maturities of Long-Term Debt
Accounts Payable
Accrued Salaries and Wages
Accrued Taxes
Regulatory Liabilities
Other Accrued Liabilities
Liabilities of Discontinued Operations

Total Current Liabilities

Pensions Benefit Liability
Other Postretirement Benefits Liability
Other Noncurrent Liabilities

Commitments and Contingencies (note 8)

Deferred Credits

Deferred Income Taxes
Deferred Tax Credits
Regulatory Liabilities
Other

Total Deferred Credits

Capitalization (page 54)
Long-Term Debt—Net

Cumulative Preferred Shares—Authorized 1,500,000 Shares Without Par Value; Outstanding—None

Cumulative Preference Shares—Authorized 1,000,000 Shares Without Par Value; Outstanding—None

Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares;

Outstanding, 2017—39,557,491 Shares; 2016—39,348,136 Shares

Premium on Common Shares
Retained Earnings
Accumulated Other Comprehensive Loss

Total Common Equity

Total Capitalization

Total Liabilities and Equity

See accompanying notes to consolidated financial statements.

2017

2016

$ 112,371
186
84,185
21,534
16,808
9,688
11,389
492

256,653

109,708
69,774
22,769

100,501
21,379
232,893
3,329

358,102

42,883
33,201
89,350
17,497
16,000
3,294
12,083
1,363

215,671

97,627
62,571
21,706

226,591
22,849
82,433
7,492

339,365

490,380

505,341

—

197,787
343,450
161,286
(5,631)

696,892

—

196,741
337,684
139,479
(3,800)

670,104

1,187,272

1,175,445

$ 2,004,278

$ 1,912,385

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

CONSOLIDATED STATEMENTS OF INCOME—FOR THE YEARS ENDED DECEMBER 31

(in thousands, except per-share amounts)

2017

2016

2015

Operating Revenues

Electric
Product Sales

Total Operating Revenues

Operating Expenses

Production Fuel—Electric
Purchased Power—Electric System Use
Electric Operation and Maintenance Expenses
Cost of Products Sold (depreciation included below)
Other Nonelectric Expenses
Depreciation and Amortization
Property Taxes—Electric

Total Operating Expenses

Operating Income

Interest Charges
Other Income

Income Before Income Taxes—Continuing Operations
Income Tax Expense—Continuing Operations

Net Income from Continuing Operations

Discontinued Operations

Income (Loss)—net of Income Tax Expense (Benefit)
of $213 in 2017, $138 in 2016, and ($1,539) in 2015

Impairment Loss—net of Income Tax (Benefit) of $0 in 2015
Gain on Disposition—net of Income Tax Expense of $4,530 in 2015

Net Income from Discontinued Operations

Total Net Income

434,506
414,844

849,350

427,349
376,190

803,539

407,039
372,765

779,804

59,690
64,807
151,319
316,562
43,240
72,545
15,053

723,216

126,134

29,604
2,632

99,162
27,043

72,119

320
—
—

320

54,792
63,226
151,225
295,222
40,264
73,445
14,266

692,440

111,099

31,886
2,905

82,118
20,081

62,037

284
—
—

284

42,744
78,150
140,768
295,032
40,021
60,363
13,512

670,590

109,214

31,160
2,177

80,231
21,642

58,589

(5,404)
(1,000)
7,160

756

72,439

62,321

59,345

Average Number of Common Shares Outstanding—Basic
Average Number of Common Shares Outstanding—Diluted

39,457
39,748

38,546
38,731

37,495
37,668

Basic Earnings Per Common Share:

Continuing Operations
Discontinued Operations

Diluted Earnings Per Common Share:

Continuing Operations
Discontinued Operations

Dividends Declared Per Common Share

See accompanying notes to consolidated financial statements.

$
$

1.83
0.01

1.84

1.81
0.01

1.82
1.28

$
$

1.61
0.01

1.62

1.60
0.01

1.61
1.25

$
$

1.56
0.02

1.58

1.56
0.02

1.58
1.23

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME–FOR THE YEARS ENDED DECEMBER 31

(in thousands)

Net Income

2017

2016

2015

72,439

62,321

59,345

Other Comprehensive Income (Loss):

Unrealized Loss on Available-for-Sale Securities:

Reversal of Previously Recognized Gains Realized on Sale of Investments

and Included in Other Income During Period

Gains (Losses) Arising During Period
Income Tax (Expense) Benefit

Change in Unrealized Losses on Available-for-Sale Securities—net-of-tax

Pension and Postretirement Benefit Plans:

Actuarial (Losses) Gains Net of Regulatory Allocation Adjustment
Amortization of Unrecognized Postretirement Benefit Costs (note 10)
Income Tax Benefit (Expense)

Pension and Postretirement Benefit Plans—net-of-tax

Total Other Comprehensive Income (Loss)

Total Comprehensive Income

See accompanying notes to consolidated financial statements.

(15)
115
(35)

(3,791)
629
1,266

(1,896)

(1,831)

(3)
(14)
6

(11)

(445)
628
(74)

109

(3)
(49)
18

(34)

510
821
(532)

799

765

70,608

62,419

60,110

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY

(in thousands, except common shares outstanding)

Balance, December 31, 2014

Common Stock Issuances, Net of Expenses
Common Stock Retirements
Net Income
Other Comprehensive Income
Tax Benefit—Stock Compensation
Employee Stock Incentive Plan Expense
Common Dividends ($1.23 per share)

Balance, December 31, 2015

Common Stock Issuances, Net of Expenses
Common Stock Retirements
Net Income
Other Comprehensive Income
Employee Stock Incentive Plan Expense
ASU 2016-09 Adoption
Common Dividends ($1.25 per share)

Balance, December 31, 2016

Common Stock Issuances, Net of Expenses
Common Stock Retirements
Net Income
Other Comprehensive Income
Employee Stock Incentive Plan Expense
Common Dividends ($1.28 per share)

Common
Shares
Outstanding

Par Value,
Common
Shares

Premium on
Common
Shares

37,218,053
690,485
(51,352)

$ 186,090
3,453
(257)

$278,436
14,715
(1,339)

82
1,716

37,857,186
1,494,618
(3,668)

$ 189,286
7,473
(18)

$293,610
38,490
(86)

3,178
2,492

39,348,136
257,059
(47,704)

$ 196,741
1,285
(239)

$337,684
3,684
(1,560)

3,642

Accumulated
0ther

Retained Comprehensive
Income/(Loss)
Earnings

Total
Common
Equity

$112,903

59,345

(46,223)

$126,025

62,321

(623)
(48,244)

$139,479

72,439

(50,632)

$ (4,663)(a) $572,766
18,168
(1,596)
59,345
765
82
1,716
(46,223)

765

$ (3,898)(a) $605,023
45,963
(104)
62,321
98
3,178
1,869
(48,244)

$ (3,800)(a) $670,104
4,969
(1,799)
72,439
(1,831)
3,642
(50,632)

(1,831)

Balance, December 31, 2017

39,557,491

$ 197,787

$343,450

$161,286

$ (5,631)(a) $696,892

(a) Accumulated Other Comprehensive Loss on December 31 is comprised of the following:

(in thousands)

Unrealized Gain (Loss) on Marketable Equity Securities:

Before Tax

Tax Effect

Unrealized Gain (Loss) on Marketable Equity Securities—net-of-tax

Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits:

Before Tax
Tax Effect

Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits—net-of-tax

Accumulated Other Comprehensive Loss:

Before Tax

Tax Effect

Net Accumulated Other Comprehensive Loss

See accompanying notes to consolidated financial statements.

2017

2016

2015

(25)

(9,462)
3,785

(5,677)

(9,391)

3,760

(29)

(19)

(6,300)
2,519

(3,781)

(6,329)

2,529

(12)

(8)

(6,484)
2,594

(3,890)

(6,496)

2,598

(5,631)

(3,800)

(3,898)

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

CONSOLIDATED STATEMENTS OF CASH FLOWS—FOR THE YEARS ENDED DECEMBER 31

(in thousands)

2017

2016

2015

Cash Flows from Operating Activities

Net Income
Adjustments to Reconcile Net Income

to Net Cash Provided by Operating Activities:
Net Gain from Sale of Discontinued Operations
Net (Income) Loss from Discontinued Operations
Depreciation and Amortization
Deferred Tax Credits
Deferred Income Taxes
Change in Deferred Debits and Other Assets
Discretionary Contribution to Pension Fund
Change in Noncurrent Liabilities and Deferred Credits
Allowance for Equity/Other Funds Used During Construction
Change in Derivatives Net of Regulatory Deferral
Stock Compensation Expense—Equity Awards
Other—Net

Cash (Used for) Provided by Current Assets and Current Liabilities:

Change in Receivables
Change in Inventories
Change in Other Current Assets
Change in Payables and Other Current Liabilities
Change in Interest Payable and Income Taxes Receivable/Payable

Net Cash Provided by Continuing Operations
Net Cash Used in Discontinued Operations

Net Cash Provided by Operating Activities

Cash Flows from Investing Activities

Capital Expenditures
Proceeds from Disposal of Noncurrent Assets
Acquisition Purchase Price Cash Received (Paid)
Cash Used for Investments and Other Assets

Net Cash Used in Investing Activities—Continuing Operations
Net Proceeds from Sale of Discontinued Operations
Net Cash Used in Investing Activities—Discontinued Operations

Net Cash Used in Investing Activities

Cash Flows from Financing Activities

Change in Checks Written in Excess of Cash
Net Short-Term Borrowings (Repayments)
Proceeds from Issuance of Common Stock—net of Issuance Expenses
Payments for Retirement of Capital Stock
Proceeds from Issuance of Long-Term Debt
Short-Term and Long-Term Debt Issuance Expenses
Payments for Retirement of Long-Term Debt
Dividends Paid and Other Distributions

Net Cash (Used in) Provided by Financing Activities—Continuing Operations
Net Cash Provided by Financing Activities—Discontinued Operations

Net Cash (Used in) Provided by Financing Activities

Net Change in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period

Cash and Cash Equivalents at End of Period

See accompanying notes to consolidated financial statements.

72,439

62,321

59,345

—
(320)
72,545
(1,470)
24,001
(2,173)
—
19,257
(986)
—
3,642
10

(2,135)
(4,294)
(3,060)
(2,667)
(1,186)

173,603
(26)

173,577

(132,913)
4,491
—
(4,168)

(132,590)
—
—

(132,590)

2,434
69,488
4,349
(1,799)
—
(380)
(48,231)
(50,632)

(24,771)
—

(24,771)

16,216
—

16,216

—
(284)
73,445
(1,657)
19,124
(10,090)
(10,000)
14,685
(857)
—
3,178
7

(944)
1,874
(2,541)
11,941
3,339

163,541
(155)

163,386

(161,259)
4,837
1,500
(4,402)

(159,324)
—
—

(159,324)

(3,363)
(37,789)
43,873
(104)
130,000
(888)
(87,547)
(48,244)

(4,062)
—

(4,062)

—
—

—

(7,160)
6,404
60,363
(1,878)
26,027
11,407
(10,000)
20,524
(1,303)
(14,736)
1,716
(80)

(1,746)
1,960
(210)
(15,150)
(3,943)

131,540
(14,000)

117,540

(160,084)
3,590
(30,806)
(6,302)

(193,602)
39,401
(1,769)

(155,970)

2,857
69,818
13,782
(1,596)
—
(312)
(212)
(46,223)

38,114
316

38,430

—
—

—

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

—
42,883

42,883

15,000
80,000
106
836

95,942
231
539

95,172

33,000
140,000
30,000
42,000
60,000
50,000
90,000

445,000
32,970
1,861

410,169

540,942
33,201
2,400

505,341

—
80,000
27
684

80,711
186
461

80,064

—
140,000
30,000
42,000
60,000
50,000
90,000

412,000
—
1,684

410,316

492,711
186
2,145

490,380

696,892

670,104

$ 1,187,272

$1,175,445

CONSOLIDATED STATEMENTS OF CAPITALIZATION, DECEMBER 31

(in thousands, except share data)

2017

2016

Short-Term Debt

Otter Tail Corporation Credit Agreement
Otter Tail Power Company Credit Agreement

Total Short-Term Debt

Long-Term Debt

Obligations of Otter Tail Corporation

—
112,371

$ 112,371

Term Loan, LIBOR plus 0.90%, due February 5, 2018
3.55% Guaranteed Senior Notes, due December 15, 2026
North Dakota Development Note, 3.95%, due April 1, 2018
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021

Total—Otter Tail Corporation
Less: Current Maturities—net of Unamortized Debt Issuance Costs

Unamortized Long-Term Debt Issuance Costs

Total Otter Tail Corporation Long-Term Debt net of Unamortized Debt Issuance Costs

Obligations of Otter Tail Power Company

Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Senior Unsecured Notes 4.63%, due December 1, 2021
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044

Total—Otter Tail Power Company
Less: Current Maturities—net of Unamortized Debt Issuance Costs

Unamortized Long-Term Debt Issuance Costs

Total Otter Tail Power Company Long-Term Debt net of Unamortized Debt Issuance Costs

Total Consolidated Long-Term Debt
Less: Current Maturities—net of Unamortized Debt Issuance Costs

Unamortized Long-Term Debt Issuance Costs

Total Consolidated Long-Term Debt net of Unamortized Debt Issuance Costs

Cumulative Preferred Shares—Without Par Value, Authorized 1,500,000 Shares; Outstanding: None

Cumulative Preference Shares—Without Par Value, Authorized 1,000,000 Shares; Outstanding: None

Total Common Shareholders’ Equity

Total Capitalization

See accompanying notes to consolidated financial statements.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2017, 2016 AND 2015

1. Summary of Significant Accounting Policies

Principles of Consolidation
The consolidated financial statements of Otter Tail Corporation and its
wholly owned subsidiaries (the Company) include the accounts of the
following segments: Electric, Manufacturing and Plastics. See note 2
to consolidated financial statements for further descriptions of the
Company’s business segments. All intercompany balances and
transactions have been eliminated in consolidation except profits on
sales to the regulated electric utility company from nonregulated
affiliates, which is in accordance with the requirements of Financial
Accounting Standards Board (FASB) Accounting Standards
Codification (ASC) Topic 980, Regulated Operations (ASC 980).

Regulation and ASC 980
The Company’s regulated electric utility company, Otter Tail Power
Company (OTP), accounts for the financial effects of regulation in
accordance with ASC 980. This standard allows for the recording of a
regulatory asset or liability for costs and revenues that will be collected
or refunded through the ratemaking process in the future. In accordance
with regulatory treatment, OTP defers utility debt redemption premiums
and amortizes such costs over the original life of the reacquired bonds.
See note 4 to consolidated financial statements for further discussion.
OTP is subject to various state and federal agency regulations. The
accounting policies followed by this business are subject to the Uniform
System of Accounts of the Federal Energy Regulatory Commission
(FERC). These accounting policies differ in some respects from those
used by the Company’s nonelectric businesses.

Plant, Retirements and Depreciation
Utility plant is stated at original cost. The cost of additions includes
contracted work, direct labor and materials, allocable overheads and
allowance for funds used during construction. The amount of interest
capitalized on electric utility plant was $741,000 in 2017, $495,000 in
2016 and $723,000 in 2015. The cost of depreciable units of property
retired less salvage is charged to accumulated depreciation. Removal
costs, when incurred, are charged against the accumulated reserve for
estimated removal costs, a regulatory liability. Maintenance, repairs
and replacement of minor items of property are charged to operating
expenses. The provisions for utility depreciation for financial reporting

Jointly Owned Facilities (dollars in thousands)

December 31, 2017

Big Stone Plant
Coyote Station
Fargo—Monticello 345 kV line
Brookings—Southeast Twin Cities 345 kV line (1)
Bemidji—Grand Rapids 230 kV line
Big Stone South—Brookings 345kV line (1)
Big Stone South—Ellendale 345 kV line (1)

December 31, 2016

Big Stone Plant
Coyote Station
Fargo-Monticello 345 kV line
Brookings—Southeast Twin Cities 345 kV line (1)
Bemidji—Grand Rapids 230 kV line
Big Stone South—Brookings 345kV line (1)
Big Stone South—Ellendale 345 kV line (1)

purposes are made on the straight-line method based on the
estimated remaining service lives of the properties (5 to 82 years).
Such provisions as a percent of the average balance of depreciable
electric utility property were 2.74% in 2017, 2.88% in 2016 and 2.61%
in 2015. Gains or losses on group asset dispositions are taken to the
accumulated provision for depreciation reserve and impact current
and future depreciation rates.

Property and equipment of nonelectric operations are carried at
historical cost or at fair value if acquired in a business combination,
and are depreciated on a straight-line basis over the assets’ estimated
useful lives (3 to 40 years). The cost of additions includes contracted
work, direct labor and materials, allocable overheads and capitalized
interest. No interest was capitalized on nonelectric plant in 2017, 2016
or 2015. Maintenance and repairs are expensed as incurred. Gains or
losses on asset dispositions are included in the determination of
operating income.

Recoverability of Long-Lived Assets
The Company reviews its long-lived assets whenever events or changes
in circumstances indicate the carrying amount of the assets may not
be recoverable. The Company determines potential impairment by
comparing the carrying amount of the assets with net cash flows
expected to be provided by operating activities of the business or
related assets. If the sum of the expected future net cash flows is less
than the carrying amount of the assets, the Company would recognize
an impairment loss. Such an impairment loss would be measured as
the amount by which the carrying amount exceeds the fair value of
the asset, where fair value is based on the discounted cash flows
expected to be generated by the asset.

Jointly Owned Facilities
OTP is a joint owner in two coal-fired steam-powered electric
generation plants: Big Stone Plant near Big Stone City, South Dakota
and Coyote Station near Beulah, North Dakota. OTP is also a joint
owner, with other regional utilities, in four major in-service transmission
lines and one additional major transmission line under construction.
The following table provides OTP’s ownership percentages and
amounts included in the Company’s December 31, 2017 and 2016
consolidated balance sheets for OTP’s share of jointly owned assets
in each of these jointly owned facilities:

OTP
Ownership
Percentage

Electric Plant
in Service

Construction
Work in
Progress

Accumulated
Depreciation

Net Plant

53.9%
35.0%
14.2%
4.8%
14.8%
50.0%
50.0%

$ 329,942
177,721
78,192
26,269
16,331
53,225
—

$ 328,809
176,315
78,298
26,406
16,331
—
—

1,074
158
—
—
—
—
89,980

23
113
—
—
—
45,050
49,160

$ (74,165)
(103,944)
(4,667)
(1,293)
(1,753)
434
—

$ (65,665)
(101,499)
(3,511)
(924)
(1,573)
—
—

$ 256,851
73,935
73,525
24,976
14,578
52,791
89,980

$ 263,167
74,929
74,787
25,482
14,758
45,050
49,160

(1) Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO

Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff).

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

The Company’s share of direct revenue and expenses of the jointly
owned facilities is included in operating revenue and expenses in the
consolidated statements of income.

Coyote Station Lignite Supply Agreement—Variable Interest Entity—
In October 2012 the Coyote Station owners, including OTP, entered into
a lignite sales agreement (LSA) with Coyote Creek Mining Company,
L.L.C. (CCMC), a subsidiary of The North American Coal Corporation,
for the purchase of lignite coal to meet the coal supply requirements
of Coyote Station for the period beginning in May 2016 and ending in
December 2040. The price per ton paid by the Coyote Station owners
under the LSA reflects the cost of production, along with an agreed
profit and capital charge. CCMC was formed for the purpose of mining
coal to meet the coal fuel supply requirements of Coyote Station from
May 2016 through December 2040 and, based on the terms of the
LSA, is considered a variable interest entity (VIE) due to the transfer
of all operating and economic risk to the Coyote Station owners, as
the agreement is structured so that the price of the coal would cover
all costs of operations as well as future reclamation costs. The Coyote
Station owners are also providing a guarantee of the value of the assets
of CCMC as they would be required to buy certain assets at book value
should they terminate the contract prior to the end of the contract
term and are providing a guarantee of the value of the equity of CCMC
in that they are required to buy the entity at the end of the contract
term at equity value. Under current accounting standards, the primary
beneficiary of a VIE is required to include the assets, liabilities, results
of operations and cash flows of the VIE in its consolidated financial
statements. No single owner of Coyote Station owns a majority interest
in Coyote Station and none, individually, has the power to direct the
activities that most significantly impact CCMC. Therefore, none of the
owners individually, including OTP, is considered a primary beneficiary
of the VIE and the Company is not required to include CCMC in its
consolidated financial statements.

If the LSA terminates prior to the expiration of its term or the
production period terminates prior to December 31, 2040 and the
Coyote Station owners purchase all of the outstanding membership
interests of CCMC as required by the LSA, the owners will satisfy, or
(if permitted by CCMC’s applicable lender) assume, all of CCMC’s
obligations owed to CCMC’s lenders under its loans and leases. The
Coyote Station owners have limited rights to assign their rights and
obligations under the LSA without the consent of CCMC’s lenders
during any period in which CCMC’s obligations to its lenders remain
outstanding. In the event the contract is terminated because regulations
or legislation render the burning of coal cost prohibitive and the
assets worthless, OTP’s maximum exposure to loss as a result of its
involvement with CCMC as of December 31, 2017 could be as high as
$57.1 million, OTP’s 35% share of unrecovered costs.

Income Taxes
Comprehensive interperiod income tax allocation is used for
substantially all book and tax temporary differences. Deferred income
taxes arise for all temporary differences between the book and tax
basis of assets and liabilities. Deferred taxes are recorded using the
tax rates scheduled by tax law to be in effect in the periods when the
temporary differences reverse. The Company amortizes investment
tax credits over the estimated lives of related property. The Company
records income taxes in accordance with ASC Topic 740, Income Taxes,
and has recognized in its consolidated financial statements the tax
effects of all tax positions that are “more-likely-than-not” to be
sustained on audit based solely on the technical merits of those
positions as of the balance sheet date. The term “more-likely-than-not”
means a likelihood of more than 50%. The Company classifies interest
and penalties on tax uncertainties as components of the provision
for income taxes. See note 13 to consolidated financial statements
regarding the Company’s accounting for uncertain tax positions.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

The Company also is required to assess the realizability of its deferred
tax assets, taking into consideration the Company’s forecast of future
taxable income, the reversal of other existing temporary differences,
available net operating loss carryforwards and available tax planning
strategies that could be implemented to realize the deferred tax assets.
Based on this assessment, management must evaluate the need for,
and amount of, valuation allowances against the Company’s deferred
tax assets. To the extent facts and circumstances change in the future,
adjustments to the valuation allowance may be required.

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (TCJA)
was signed into law. The major impacts of the changes included in the
TCJA are discussed in note 13 to consolidated financial statements.

Revenue Recognition
Due to the diverse business operations of the Company, revenue
recognition depends on the product produced and sold or service
performed. The Company recognizes revenue when the earnings
process is complete, evidenced by an agreement with the customer,
there has been delivery and acceptance, the price is fixed or
determinable and collectability is reasonably assured. In cases where
significant obligations remain after delivery, revenue recognition is
deferred until such obligations are fulfilled. Provisions for sales returns
are recorded at the time of the sale based on historical information
and current trends.

For the Company’s operating companies recognizing revenue on
certain products when shipped, those operating companies have no
further obligation to provide services related to such product. The
shipping terms used in these instances are FOB shipping point.
The majority of the revenues recorded by the companies in the
Manufacturing and Plastics segments are recorded when products
are shipped.

Customer electricity use is metered and bills are rendered monthly.

Revenue is accrued for electricity consumed but not yet billed. Rate
schedules applicable to substantially all customers include a fuel
clause adjustment, under which the rates are adjusted to reflect
changes in average cost of fuels and purchased power, and a
surcharge for recovery of conservation-related expenses. Revenue is
recognized for fuel and purchased power costs incurred in excess of
amounts recovered in base rates but not yet billed through the fuel
clause adjustment, for conservation program incentives and bonuses
earned but not yet billed and for renewable resource, transmission-
related and environmental incurred costs and investment returns
approved for recovery through riders.

Revenues on wholesale electricity sales from Company-owned
generating units are recognized when energy is delivered. For shared
use of transmission facilities with certain regional transmission
cooperatives, revenues are estimated. Bills are rendered based on
anticipated usage and settlements are made later based on actual
usage. Estimated revenues may be adjusted prior to settlement, or
at the time of settlement, to reflect actual usage.

Under ASC Topic 815, Derivatives and Hedging, OTP accounts for
forward energy contracts as derivatives subject to mark-to-market
accounting unless those contracts meet the definition of a capacity
contract or are not subject to unplanned netting, then OTP accounts
for the contracts under the normal purchases and sales exception to
mark-to-market accounting.

Warranty Reserves
Certain products sold by the Company’s manufacturing and plastics
companies carry product warranties for one year after the shipment
date. These companies’ standard product warranty terms generally
include post-sales support and repairs or replacement of a product
at no additional charge for a specified period of time. While these
companies engage in extensive product quality programs and
processes, including actively monitoring and evaluating the quality

of their component suppliers, they base their estimated warranty
obligations on warranty terms, ongoing product failure rates, repair
costs, product call rates, average cost per call, and current period
product shipments. The Company’s manufacturing and plastics
companies have not incurred any significant warranty costs over
the last three fiscal years.

Shipping and Handling Costs
The Company includes revenues received for shipping and handling
in operating revenues. Expenses paid for shipping and handling are
recorded as part of cost of goods sold.

Use of Estimates
The Company uses estimates based on the best information available in
recording transactions and balances resulting from business operations.
As better information becomes available (or actual amounts are known),
the recorded estimates are revised. Consequently, operating results
can be affected by revisions to prior accounting estimates.

Cash Equivalents
The Company considers all highly liquid debt instruments purchased
with maturity of 90 days or less to be cash equivalents.

Investments
The following table provides a breakdown of the Company’s investments
at December 31:

(in thousands)

Cost Method:

Economic Development Loan Pools
Other

Equity Method Partnerships
Marketable Debt Securities Classified as

Available-for-Sale

Marketable Equity Securities Classified as

Available-for-Sale

Total Investments

2017

2016

54
115
23

45
115
24

7,160

1,285

8,629

Level 2—Pricing inputs are other than quoted prices in active markets,
but are either directly or indirectly observable as of the reported date.
The types of assets and liabilities included in Level 2 are typically
either comparable to actively traded securities or contracts, such as
treasury securities with pricing interpolated from recent trades of
similar securities, or priced with models using highly observable
inputs, such as commodity options priced using observable forward
prices and volatilities.

Level 3—Significant inputs to pricing have little or no observability
as of the reporting date. The types of assets and liabilities included
in Level 3 are those with inputs requiring significant management
judgment or estimation and may include complex and subjective
models and forecasts.

The following tables present, for each of the hierarchy levels, the
Company’s assets and liabilities that are measured at fair value on
a recurring basis as of December 31, 2017 and December 31, 2016:

December 31, 2017 (in thousands)

Level 1

Level 2

Level 3

Assets:

Investments:

Equity Funds—Held by Captive

Insurance Company

Corporate Debt Securities—Held by

Captive Insurance Company

Government-Backed and
Government-Sponsored
Enterprises’ Debt Securities—Held by
Captive Insurance Company

Other Assets:

Money Market and Mutual Funds—
Nonqualified Retirement Savings Plan

Total Assets

$ 1,285

$ 5,373

1,787

823

$ 2,108

$ 7,160

8,225

December 31, 2016 (in thousands)

Level 1

Level 2

Level 3

—

Assets:

Investments:

8,417

Corporate Debt Securities—Held by

Captive Insurance Company

Government-Backed and
Government-Sponsored
Enterprises’ Debt Securities—Held by
Captive Insurance Company

Other Assets:

Money Market and Mutual Funds—
Nonqualified Retirement Savings Plan

Total Assets

$ 5,280

2,945

849

$ 8,225

The Company’s marketable securities classified as available-for-sale

are held for insurance purposes and are reflected at their fair values
on December 31, 2017. See further discussion below.

Agreements Subject to Legally Enforceable Netting Arrangements
OTP has certain derivative contracts that are designated as normal
purchases and carried at historical cost in the accompanying balance
sheet. Individual counterparty exposures for these contracts can be
offset according to legally enforceable netting arrangements. The
Company does not offset assets and liabilities under legally enforceable
netting arrangements on the face of its consolidated balance sheet.

Fair Value Measurements
The Company follows ASC Topic 820, Fair Value Measurements and
Disclosures (ASC 820), for recurring fair value measurements. ASC 820
provides a single definition of fair value, requires enhanced disclosures
about assets and liabilities measured at fair value and establishes a
hierarchal framework for disclosing the observability of the inputs
utilized in measuring assets and liabilities at fair value. The three levels
defined by the hierarchy and examples of each level are as follows:

Level 1—Quoted prices are available in active markets for identical
assets or liabilities as of the reported date. The types of assets and
liabilities included in Level 1 are highly liquid and actively traded
instruments with quoted prices, such as equities listed by the
New York Stock Exchange and commodity derivative contracts listed
on the New York Mercantile Exchange .

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

The valuation techniques and inputs used for the Level 2 fair value

measurements in the table above are as follows:

Government-Backed and Government-Sponsored Enterprises’ and
Corporate Debt Securities Held by the Company’s Captive Insurance
Company—Fair values are determined on the basis of valuations
provided by a third-party pricing service which utilizes industry
accepted valuation models and observable market inputs to
determine valuation. Some valuations or model inputs used by the
pricing service may be based on broker quotes.

Inventories
Electric segment inventories are reported at average cost. The
Manufacturing and Plastics segments’ inventories are stated at the
lower of average cost or market. Inventories consist of the following
at December 31:

(in thousands)

Finished Goods
Work in Process
Raw Material, Fuel and Supplies

Total Inventories

2017

26,605
14,222
47,207

2016

27,755
11,754
44,231

88,034

83,740

Goodwill and Other Intangible Assets
The Company accounts for goodwill and other intangible assets in
accordance with the requirements of ASC Topic 350, Intangibles—
Goodwill and Other, measuring its goodwill for impairment annually
in the fourth quarter, and more often when events indicate the assets
may be impaired. The Company does qualitative assessments of its
reporting units with recorded goodwill to determine if it is more likely
than not that the fair value of the reporting unit exceeds its book
value. The Company also does quantitative assessments of its
reporting units with recorded goodwill to determine the fair value
of the reporting unit.

In the first quarter of 2015, Foley recorded a $1.0 million goodwill

impairment charge based on adjustments to the carrying value of
Foley. The first quarter 2015 goodwill impairment loss is reflected in
the results of discontinued operations. See note 15 to consolidated
financial statements.

On September 1, 2015 BTD Manufacturing, Inc. (BTD), acquired the
assets of Impulse Manufacturing, Inc. (Impulse) of Dawsonville, Georgia.
The acquired business operates under the name BTD-Georgia. Based
on the preliminary purchase price allocation, the difference in the fair
value of assets acquired and the price paid for Impulse resulted in an
initial estimate of acquired goodwill of $8.2 million. A final determination
of the purchase price was agreed to in June 2016 resulting in a
$2.2 million reduction in acquired goodwill in June 2016.

The following tables summarize changes to goodwill by business segment during 2017 and 2016:

(in thousands)

Manufacturing
Plastics

Total

(in thousands)

Manufacturing
Plastics

Total

Gross Balance
December 31,
2016

18,270
19,302

37,572

Gross Balance
December 31,
2015

20,430
19,302

39,732

Accumulated
Impairments

Balance
(net of impairments)
December 31,
2016

Balance
Adjustments (net of impairments)
December 31,
2017

to Goodwill in
2017

—
—

—

18,270
19,302

37,572

—
—

—

18,270
19,302

37,572

Accumulated
Impairments

Balance
(net of impairments)
December 31,
2015

—
—

—

20,430
19,302

39,732

Balance
Adjustments (net of impairments)
December 31,
2016

to Goodwill in
2016

(2,160)
—

(2,160)

18,270
19,302

37,572

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

Intangible assets with finite lives are amortized over their estimated

useful lives and reviewed for impairment in accordance with
requirements under ASC Topic 360-10-35, Property, Plant, and
Equipment—Overall—Subsequent Measurement. In 2017 the Company
capitalized $154,000 in implementation costs for new financial
reporting consolidation software included in other amortizable
intangible assets. In September 2017 the Company initiated use of
the software and began amortizing the implementation costs.

The following table summarizes the components of the Company’s

intangible assets at December 31, 2017 and December 31, 2016:

December 31, 2017
(in thousands)

Carrying Accumulated Carrying
Amount Amortization Amount

Gross

Remaining
Net Amortization
Periods
(months)

Amortizable Intangible Assets:

Customer Relationships
Covenant not to Compete
Other

Total

$22,491
590
154

$23,235

$ 8,994
459
17

$13,497
131
137

$ 9,470

$13,765

December 31, 2016 (in thousands)

Amortizable Intangible Assets:

Customer Relationships
Covenant not to Compete

Total

$22,491
590

$23,081

$ 7,861
262

$14,630
328

$ 8,123

$14,958

24-212
8
32

36-224
20

The amortization expense for these intangible assets was:

(in thousands)

2017

2016

2015

Amortization Expense—Intangible Assets

$1,347

$1,436

$1,127

The estimated annual amortization expense for these intangible

assets for the next five years is:

(in thousands)

2018

2019

2020

2021

2022

Estimated Amortization Expense—

Intangible Assets

$ 1,315 $ 1,184 $ 1,133 $ 1,099 $ 1,099

Supplemental Disclosures of Cash Flow Information

(in thousands)

Noncash Investing Activities:

Transactions Related to Capital
Additions not Settled in Cash

As of December 31,

2017

2016

13,887

13,533

(in thousands)

2017

2016

2015

Cash Paid (Received) During the Year for:

Interest (net of amount capitalized)
Income Taxes

$ 29,791
$ 5,064

$ 30,512
$ 31,269
$ (1,291) $ 7,322

New Accounting Standards Adopted
Accounting Standards Update (ASU) 2015-11—In July 2015 the Financial
Accounting Standards Board (FASB) issued ASU No. 2015-11, Inventory
(Topic 330): Simplifying the Measurement of Inventory, which requires
that inventories be measured at the lower of cost or net realizable value
instead of the lower of cost or market value. Net realizable value is
defined as the estimated selling price in the ordinary course of business,
less reasonably predictable costs of completion, disposal, and
transportation. The standards update was effective prospectively for
fiscal years and interim periods beginning after December 15, 2016.
The Company adopted the updates in ASU 2015-11 in the first quarter
of 2017. The adoption of the updated standard did not have a material
impact on the Company’s consolidated financial statements as market
and net realizable value were substantially the same for the inventories
of its manufacturing companies.

New Accounting Standards Pending Adoption
ASU 2014-09—In May 2014 the FASB issued ASU No. 2014-09, Revenue
from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a
comprehensive, principles-based accounting standard which amends
current revenue recognition guidance with the objective of improving
revenue recognition requirements by providing a single comprehensive
model to determine the measurement of revenue and the timing of
revenue recognition. ASC 606 also requires expanded disclosures to
enable users of financial statements to understand the nature,
amount, timing and uncertainty of revenue and cash flows arising
from contracts with customers.

Amendments to the ASC in ASU 2014-09, as amended, are effective
for fiscal years beginning after December 15, 2017. Application methods
permitted are: (1) full retrospective, (2) retrospective using one or more
practical expedients and (3) retrospective with the cumulative effect
of initial application recognized at the date of initial application. As
of December 31, 2017 the Company had reviewed its revenue streams
and contracts and determined areas where the amendments in
ASU 2014-09 are applicable and has developed controls for new
processes that will be required to track and report revenues where the
timing of revenue recognition may change under ASU 2014-09. Based
on review of the Company’s revenue streams, the Company has not
identified any contracts where the timing of revenue recognition will
change as a result of the adoption of the updates in ASU 2016-09.
The Company will adopt the updates in ASU 2014-09 on a modified
retrospective basis on January 1, 2018, the date of initial application,
but will not be recording a cumulative effect adjustment to retained
earnings on application of the updates because the adoption of the
updates in ASU 606 have no material impact on the timing of
revenue recognition for the Company or its subsidiaries. Adoption
of ASU 2014-09 will result in additional disclosures related to the
nature, timing and certainty of revenues and any contract assets or
liabilities that may be required to be reported under the updated
standard.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

The Company will report adjustments to Alternative Revenue

Program (ARP) revenues at OTP as a separate line item within revenue
on the face of the Company’s consolidated statements of income.
The ARP revenue adjustments are recorded on the basis of recoverable
costs incurred and returns earned under rate riders and are not
considered revenue from contracts with customers.

ASU 2016-02—In February 2016 the FASB issued ASU No. 2016-02,
Leases (Topic 842) (ASU 2016-02). ASU 2016-02 is a comprehensive
amendment of the ASC, creating Topic 842, which will supersede the
current requirements under ASC Topic 840 on leases and require the
recognition of lease assets and lease liabilities on the balance sheet
and the disclosure of key information about leasing arrangements.
Topic 842 affects any entity that enters into a lease, with some specified
scope exemptions. The main difference between previous Generally
Accepted Accounting Principles in the United States (GAAP) and
Topic 842 is the recognition of lease assets and lease liabilities by
lessees for those leases classified as operating leases under previous
GAAP. Topic 842 retains a distinction between finance leases and
operating leases. The classification criteria for distinguishing between
finance leases and operating leases are substantially similar to the
classification criteria for distinguishing between capital leases and
operating leases in the previous guidance. Topic 842 also requires
qualitative and specific quantitative disclosures by lessees and lessors
to meet the objective of enabling users of financial statements to
assess the amount, timing, and uncertainty of cash flows arising from
leases. The amendments in ASU 2016-02 are effective for fiscal years
beginning after December 15, 2018, including interim periods within
those fiscal years. Early application of the amendments in ASU 2016-02
is permitted. The Company has developed a list of all current leases
outstanding and continues to review ASU 2016-02, identifying key im-
pacts to its businesses to determine areas where the amendments in
ASU 2016-02 will be applicable and is evaluating transition options.
The Company does not currently plan to apply the amendments in
ASU 2016-02 to its consolidated financial statements prior to 2019.

ASU 2017-04—In January 2017 the FASB issued ASU No. 2017-04,
Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for
Goodwill Impairment (ASU 2017-04), which simplifies how an entity is
required to test goodwill for impairment by eliminating Step 2 from
the goodwill impairment test. Step 2 measures a goodwill impairment
loss by comparing the implied fair value of a reporting unit’s goodwill
with the carrying amount of that goodwill. In computing the implied
fair value of goodwill under Step 2, an entity has to perform procedures
to determine the fair value at the impairment testing date of its assets
and liabilities (including unrecognized assets and liabilities) following
the procedure that would be required in determining the fair value of
assets acquired and liabilities assumed in a business combination.
Under the amendments in ASU 2017-04, an entity will perform its annual,
or interim, goodwill impairment test by comparing the fair value of a
reporting unit with its carrying amount. An entity will recognize an
impairment charge for the amount by which the carrying amount
exceeds the reporting unit’s fair value; however, the loss recognized
will not exceed the total amount of goodwill allocated to that reporting
unit. Additionally, an entity will consider income tax effects from any
tax deductible goodwill on the carrying amount of the reporting unit
when measuring the goodwill impairment loss, if applicable.

The amendments in ASU 2017-04 modify the concept of impairment

from the condition that exists when the carrying amount of goodwill
exceeds its implied fair value to the condition that exists when the
carrying amount of a reporting unit exceeds its fair value. An entity no
longer will determine goodwill impairment by calculating the implied
fair value of goodwill by assigning the fair value of a reporting unit to all

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

of its assets and liabilities as if that reporting unit had been acquired
in a business combination. Because these amendments eliminate Step 2
from the goodwill impairment test, they should reduce the cost and
complexity of evaluating goodwill for impairment. The amendments in
ASU 2017-04 are effective for annual or any interim goodwill impairment
tests in fiscal years beginning after December 15, 2019. Early adoption
is permitted for interim or annual goodwill impairment tests performed
on testing dates after January 1, 2017.

ASU 2017-07—In March 2017 the FASB issued ASU No. 2017-07,
Compensation—Retirement Benefits (Topic 715): Improving the
Presentation of Net Periodic Pension Cost and Net Periodic Postretirement
Benefit Cost (ASU 2017-07), which is intended to improve the
presentation of net periodic pension cost and net periodic
postretirement benefit cost. ASC Topic 715, Compensation—Retirement
Benefits (ASC 715), does not prescribe where the amount of net benefit
cost should be presented in an employer’s income statement and does
not require entities to disclose by line item the amount of net benefit
cost that is included in the income statement or capitalized in assets.
The amendments in ASU 2017-07 require that an employer report the
service cost component of periodic benefit costs in the same line item
or items as other compensation costs arising from services rendered
by the pertinent employees during the period. The other components
of net benefit cost as defined in ASC 715 are required to be presented
in the income statement separately from the service cost component
and outside a subtotal of income from operations. The amendments in
ASU 2017-07 also allow only the service cost component to be eligible
for capitalization when applicable (for example, as a cost of internally
manufactured inventory or a self-constructed asset). The amendments
in ASU 2017-07 are effective for annual periods beginning after
December 15, 2017, including interim periods within those annual periods.
The amendments will be applied retrospectively for the presentation of
the service cost component and the other components of net periodic
pension cost and net periodic postretirement benefit cost in the income
statement and prospectively, on and after the effective date, for the
capitalization of the service cost component of net periodic pension
cost and net periodic postretirement benefit cost in assets.

The majority of the Company’s benefit costs to which the amendments

in ASU 2017-07 apply are related to benefit plans in place at OTP, the
Company’s regulated provider of electric utility services. The amendments
in ASU 2017-07 deviate significantly from current prescribed ratemaking
and regulatory accounting treatment of postretirement benefit costs,
which require the capitalization of a portion of all the components of
net periodic benefit costs be included in rate base additions and
provide for rate recovery of the non-capitalized portion of all of the
components of net periodic pension costs as recoverable operating
expenses. The Company has assessed the impact adoption of the
amendments in ASU 2017-07 will have on its consolidated financial
statements, financial position and results of operations and OTP has
determined the regulatory assets to be established in order to reflect the
effect of the required regulatory accounting treatment of the non-service
cost components that cannot be capitalized to plant in service under
the ASU 2017-07 amendments to GAAP. The non-service cost
components of the affected net periodic benefit costs will be reported
below the operating income line on the Company’s consolidated
income statements upon adoption of the amendments in ASU 2017-07.
The Company does not plan to adopt the updates in ASU 2017-07

prior to the first quarter of 2018, the required effective period for
application of the updates by the Company. The Company’s non-service
cost components of net periodic post-retirement benefit costs that
were capitalized to plant in service in 2017 that would have been
recorded as regulatory assets if the amendments in ASU 2017-07 were
applicable in 2017 were $0.8 million. The Company’s non-service costs

components of net periodic post-retirement benefit costs included in
operating expense that will be included in other income and deductions
on adoption of ASU 2017-07 were $5.6 million in 2017 and $5.1 million
in 2016.

2. Business Combinations, Dispositions and Segment

Information

Business Combinations
The Company acquired no new businesses in 2017 or 2016.

On September 1, 2015 BTD acquired the assets of Impulse of

Dawsonville, Georgia for $30.8 million in cash. A post-closing reduction
in the purchase price of $1.5 million was agreed to in June 2016 resulting
in an adjusted purchase price of $29.3 million. The acquired business,
operating under the name BTD-Georgia, is a full-service metal fabricator
located 30 miles north of Atlanta, Georgia, which offers a wide range
of metal fabrication services ranging from simple laser cutting services
and high volume stamping to complex weldments and assemblies for
metal fabrication buyers and original equipment manufacturers. In
addition to serving some of BTD’s existing customers from a location
closer to the customers’ manufacturing facilities, this acquisition
provides opportunities for growth in new and existing markets for BTD
with complementing production capabilities that expand the capacity
of services offered by BTD. Pro forma results of operations have not
been presented for this acquisition because the effect of the acquisition
was not material to the Company.

Below is condensed balance sheet information disclosing the final

allocation of the purchase price assigned to each major asset and
liability category of BTD-Georgia:

(in thousands)

Assets:
Current Assets
Goodwill
Other Intangible Assets
Other Amortizable Assets
Fixed Assets

Total Assets

Liabilities:
Current Liabilities
Lease Obligation

Total Liabilities

Cash Paid

4,906
6,083
6,270
1,380
13,649

$ 32,288

2,971
11

2,982

$ 29,306

In execution of the Company’s announced strategy of realigning its

business portfolio to reduce its risk profile and dedicate a greater
portion of its resources toward electric utility operations, the Company
sold several of its holdings in recent years. On December 31, 2014 the
Company was in the process of negotiating the sales of Foley, its
mechanical and prime contractor on industrial projects, and AEV, Inc.,
its electrical design and construction services company, which resulted
in the removal of its Construction segment from continuing operations.
The sale of Foley closed on April 30, 2015 and the sale of the assets of
AEV, Inc. closed on February 28, 2015.

The results of operations of the Company’s recently disposed

businesses are reported as discontinued operations in the Company’s
consolidated financial statements as of and for the years ended
December 31, 2017, 2016 and 2015, and are summarized in note 15 to
consolidated financial statements.

Segment Information
The accounting policies of the segments are described under note 1—
Summary of Significant Accounting Policies. The Company’s businesses
have been classified into three segments to be consistent with its
business strategy and the reporting and review process used by the
Company’s chief operating decision makers. These businesses sell
products and provide services to customers primarily in the United
States. The Company’s business structure currently includes the
following three segments: Electric, Manufacturing and Plastics.
The chart below indicates the companies included in each segment.

ELECTRIC

MANUFACTURING

PLASTICS

Otter Tail Power
Company

BTD
Manufacturing, Inc.

Northern Pipe
Products, Inc.

T.O. Plastics, Inc.

Vinyltech Corporation

Electric includes the production, transmission, distribution and sale of
electric energy in Minnesota, North Dakota and South Dakota by OTP.
In addition, OTP is a participant in the MISO markets. OTP’s operations
have been the Company’s primary business since 1907.

Manufacturing consists of businesses in the following manufacturing

activities: contract machining, metal parts stamping, fabrication and
painting, and production of plastic thermoformed horticultural containers,
life science and industrial packaging, and material handling components.
These businesses have manufacturing facilities in Georgia, Illinois and
Minnesota and sell products primarily in the United States.

Plastics consists of businesses producing polyvinyl chloride (PVC) pipe
at plants in North Dakota and Arizona. The PVC pipe is sold primarily
in the upper Midwest and Southwest regions of the United States.
OTP is a wholly owned subsidiary of the Company. All of the

Company’s other businesses are owned by its wholly owned subsidiary,
Varistar Corporation (Varistar). The Company’s Corporate operating
costs include items such as corporate staff and overhead costs, the
results of the Company’s captive insurance company and other items
excluded from the measurement of operating segment performance.
Corporate assets consist primarily of cash, prepaid expenses,
investments and fixed assets. Corporate is not an operating segment.
Rather, it is added to operating segment totals to reconcile to totals
on the Company’s consolidated financial statements.

No single customer accounted for over 10% of the Company’s

consolidated revenues in 2017, 2016 and 2015. While no single customer
accounted for over 10% of consolidated revenue in 2017, certain
customers provided a significant portion of each business segment’s
2017 revenue. The Electric segment has one customer that provided
11.7% of 2017 Electric segment revenues. The Manufacturing segment
has one customer that manufactures and sells recreational vehicles
that provided 24.3% of 2017 Manufacturing segment revenues and one
customer that manufactures and sells lawn and garden equipment
that provided 12.0% of 2017 Manufacturing segment revenues. The
Plastics segment has two customers that individually provided 20.6%
and 17.8% of 2017 Plastics segment revenues. The loss of any one of
these customers would have a significant negative impact on the
financial position and results of operations of the respective business
segment and the Company.

All of the Company’s long-lived assets are within the United States

and sales within the United States accounted for 98.2% of sales in
2017, 98.6% of sales in 2016 and 97.1% of sales in 2015.

The Company evaluates the performance of its business segments
and allocates resources to them based on earnings contribution and

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

return on total invested capital. Information on continuing operations
for the business segments for 2017, 2016 and 2015 is presented in the
following table:

(in thousands)

Operating Revenue

Electric
Manufacturing
Plastics
Intersegment Eliminations

2017

2016

2015

$ 434,537 $ 427,383 $ 407,131
215,011
157,758
(96)

221,289
154,901
(34)

229,738
185,132
(57)

Total

$ 849,350 $ 803,539 $ 779,804

Cost of Products Sold

Manufacturing
Plastics
Intersegment Eliminations

$ 176,473 $ 171,732 $ 171,956
123,085
(9)

123,496
(6)

140,107
(18)

Total

$ 316,562 $ 295,222 $ 295,032

Other Nonelectric Expenses

Manufacturing
Plastics
Corporate
Intersegment Eliminations

Total

Depreciation and Amortization

Electric
Manufacturing
Plastics
Corporate

Total

Operating Income (Loss)

Electric
Manufacturing
Plastics
Corporate

Total

Interest Charges

23,785 $
11,564
7,930
(39)

21,994 $

9,402
8,896
(28)

21,116
9,849
9,143
(87)

43,240 $

40,264 $

40,021

53,276 $
15,379
3,817
73

53,743 $
15,794
3,861
47

44,786
11,853
3,552
172

72,545 $

73,445 $

60,363

90,392 $
14,101
29,644
(8,003)

90,131 $
11,769
18,142
(8,943)

87,171
10,086
21,272
(9,315)

$ 126,134 $ 111,099 $ 109,214

Electric
Manufacturing
Plastics
Corporate and Intersegment Eliminations

25,334 $

25,069 $

2,215
633
1,422

3,859
1,034
1,924

24,371
3,560
1,026
2,203

Total

29,604 $

31,886 $

31,160

Income Tax Expense (Benefit)—

Continuing Operations

Electric
Manufacturing
Plastics
Corporate

Total

Net Income (Loss)

Electric
Manufacturing
Plastics
Corporate
Discontinued Operations

Total

Capital Expenditures

Electric
Manufacturing
Plastics
Corporate

Total

Identifiable Assets

Electric
Manufacturing
Plastics
Corporate

Total

17,013 $
989
7,448
1,593

16,366 $

2,276
6,538
(5,099)

16,067
2,299
8,187
(4,911)

27,043 $

20,081 $

21,642

49,446 $
11,050
21,696
(10,073)
320

49,829 $

5,694
10,628
(4,114)
284

48,370
4,247
12,108
(6,136)
756

72,439 $

62,321 $

59,345

$ 118,444 $ 149,648 $ 135,572
20,295
4,206
11

8,429
3,085
97

9,916
4,432
121

$ 132,913 $ 161,259 $ 160,084

$1,690,224 $1,622,231 $1,520,887
173,860
81,624
42,312

166,525
84,592
39,037

167,023
87,230
59,801

$2,004,278 $1,912,385 $1,818,683

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

3. Rate and Regulatory Matters

Below are descriptions of OTP’s major capital expenditure projects
that have had, or will have, a significant impact on OTP’s revenue
requirements, rates and alternative revenue recovery mechanisms,
followed by summaries of specific electric rate or rider proceedings
with the Minnesota Public Utilities Commission (MPUC), the North
Dakota Public Service Commission (NDPSC), the South Dakota Public
Utilities Commission (SDPUC) and the FERC, impacting OTP’s
revenues in 2017, 2016 and 2015.

MAJOR CAPITAL EXPENDITURE PROJECTS
Big Stone South–Ellendale Multi-Value Transmission Project (MVP)—
This is a 345-kiloVolt (kV) transmission line that will extend 163 miles
between a substation near Big Stone City, South Dakota and a
substation near Ellendale, North Dakota. OTP jointly developed this
project with Montana-Dakota Utilities Co., a division of MDU Resources
Group, Inc., and the parties will have equal ownership interest in the
transmission line portion of the project. MISO approved this project as
an MVP under the MISO Open Access Transmission, Energy and
Operating Reserve Markets Tariff (MISO Tariff) in December 2011.
MVPs are designed to enable the region to comply with energy policy
mandates and to address reliability and economic issues affecting
multiple areas within the MISO region. The cost allocation is designed
to ensure the costs of transmission projects with regional benefits are
properly assigned to those who benefit. Construction began on this
line in the second quarter of 2016 and is expected to be completed
in 2019. OTP’s capitalized costs on this project as of December 31, 2017
were approximately $90.0 million, which includes assets that are
100% owned by OTP.

Big Stone South–Brookings MVP—This 345-kV transmission line extends
approximately 70 miles between a substation near Big Stone City,
South Dakota and the Brookings County Substation near Brookings,
South Dakota. OTP and Northern States Power–Minnesota, a subsidiary
of Xcel Energy Inc., jointly developed this project and the parties have
equal ownership interest in the transmission line portion of the project.
MISO approved this project as an MVP under the MISO Tariff in
December 2011. Construction began on this line in the third quarter of
2015 and the line was energized on September 8, 2017. OTP’s capitalized
costs on this project as of December 31, 2017 were approximately
$72.7 million, which includes assets that are 100% owned by OTP.

Recovery of OTP’s major transmission investments is through the
MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota
and South Dakota Transmission Cost Recovery (TCR) Riders.

REAGENT COSTS
OTP’s systemwide costs for reagents are expected to increase to
approximately $2.2 million annually through May 2021 when Hoot
Lake Plant is expected to be retired. The Minnesota, North Dakota
and South Dakota share of costs are approximately 50%, 40% and
10%, respectively. Reagent costs for the Big Stone Plant AQCS and
Coyote Station and Hoot Lake Plant Mercury and Air Toxics Standards
(MATS) were initially incurred in 2015 when projects went into service.

MINNESOTA
2016 General Rate Case—The MPUC rendered its final decision in OTP’s
2016 general rate case in March 2017 and issued its written order on
May 1, 2017. Pursuant to the order, OTP’s allowed rate of return on rate
base decreased from 8.61% to 7.5056% and its allowed rate of return
on equity decreased from 10.74% to 9.41%. On July 6, 2017 the MPUC
denied OTP’s request for reconsideration of certain of the MPUC’s
rulings in the rate case and confirmed its May 1, 2017 order.

The MPUC’s order also included: (1) the determination that all costs

(including FERC allocated costs and revenues) of the Big Stone
South–Brookings and Big Stone South–Ellendale MVP projects will be
included in the Minnesota TCR rider and jurisdictionally allocated to
OTP’s Minnesota customers, and (2) approval of OTP’s proposal to
transition rate base, expenses and revenues from Environmental Cost
Recovery (ECR) and TCR riders to base rate recovery, with the transition
occurring when final rates are implemented. The rate base balances,
expense levels and revenue levels existing in the riders at the time of
implementation of final rates will be used to establish the amounts
transitioned to base rates. Certain MISO expenses and revenues will
remain in the TCR rider to allow for the ongoing refund or recovery
of these variable revenues and costs.

Information on interim and final rate increases and interim revenue

refunds accrued is detailed in the tables below:

($ in thousands)

Interim Rates Authorized
April 14, 2016

Final Rates

Revenue Increase—Annualized based

on Test Year Data

Revenue Percent Increase
Return on Rate Base
Jurisdictional Rate Base based on Test Year Data
Return on Equity

Based on Equity to Total Capital of

Debt to Total Capital

16,816

10,471

9.56%
8.07%

5.34%
7.5056%

$ 483,000

$ 471,000

10.40%
52.50%
47.50%

9.41%
52.50%
47.50%

Interim Revenue (in thousands)

April 16, 2016 through October 31, 2017

Billed
Accrued Refund
Net Interim Revenue
Interest on Refundable Amount
Final Refund

$ 23,289
$
8,779
$ 14,510
265
$
9,044
$

In addition to the interim rate refund, OTP will be required to refund
the difference between (1) amounts collected under its Minnesota ECR
and TCR riders based on the return on equity (ROE) approved in its most
recent rider update and (2) amounts that would have been collected
based on the lower 9.41% ROE approved in its 2016 general rate case
going back to April 16, 2016, the date interim rates were implemented.
As of October 31, 2017 the revenues collected under the Minnesota
ECR and TCR riders subject to refund due to the lower ROE rate and
other adjustments were $0.9 million and $1.4 million, respectively. These
amounts will be refunded to Minnesota customers over a 12-month
period through reductions in the Minnesota ECR and TCR rider rates
in effect November 1, 2017, as approved by the MPUC. The TCR rate is
provisional and subject to revision under a separate docket.

OTP accrued interim and rider rate refunds until final rates became

effective, for bills rendered on and after November 1, 2017. The final
interim rate refund, including interest, of $9.0 million was applied as a
credit to Minnesota customers’ electric bills beginning November 17, 2017.

The Minnesota Department of Commerce (MNDOC) may require a
utility to make investments and expenditures in energy conservation
improvements whenever it finds that the improvement will result in
energy savings at a total cost to the utility less than the cost to the
utility to produce or purchase an equivalent amount of a new supply of
energy. Such MNDOC orders can be appealed to the MPUC. Investments
made pursuant to such orders generally are recoverable costs in rate

cases, even though ownership of the improvement may belong to
the property owner rather than the utility. OTP recovers conservation
related costs not included in base rates under the MNCIP through the
use of an annual recovery mechanism approved by the MPUC.

On May 25, 2016 the MPUC adopted the MNDOC’s proposed changes

to the MNCIP financial incentive. The new model provides utilities an
incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and
10% of 2019 net benefits, assuming the utility achieves 1.7% savings
compared to retail sales. OTP estimates the impact of the new model
will reduce the MNCIP financial incentive by approximately 50%
compared to the previous incentive mechanism. MNCIP incentives
included $5.0 million approved for 2016 and $4.3 million approved
for 2015.

Transmission Cost Recovery Rider—The Minnesota Public Utilities Act
(the MPU Act) provides a mechanism for automatic adjustment outside
of a general rate proceeding to recover the costs of new transmission
facilities that have been previously approved by the MPUC in a
Certificate of Need (CON) proceeding, certified by the MPUC as a
Minnesota priority transmission project, made to transmit the electricity
generated from renewable generation sources ultimately used to
provide service to the utility’s retail customers, or exempt from the
requirement to obtain a Minnesota CON. The MPUC may also authorize
cost recovery via such TCR riders for charges incurred by a utility under
a federally approved tariff that accrue from other transmission owners’
regionally planned transmission projects that have been determined
by the MISO to benefit the utility or integrated transmission system.
The MPU Act also authorizes TCR riders to recover the costs of new
transmission facilities approved by the regulatory commission of the
state in which the new transmission facilities are to be constructed, to
the extent approval is required by the laws of that state, and determined
by the MISO to benefit the utility or integrated transmission system.
Finally, under certain circumstances, the MPU Act also authorizes TCR
riders to recover the costs associated with distribution planning and
investments in distribution facilities to modernize the utility grid. Such
TCR riders allow a return on investment at the level approved in a
utility’s last general rate case. Additionally, following approval of the
rate schedule, the MPUC may approve annual rate adjustments filed
pursuant to the rate schedule. MISO regional cost allocation allows
OTP to recover some of the costs of its transmission investment from
other MISO customers.

In OTP’s 2016 general rate case order issued on May 1, 2017, the

MPUC ordered OTP to include, in the TCR rider retail rate base,
Minnesota’s jurisdictional share of OTP’s investment in the Big Stone
South–Brookings and Big Stone South–Ellendale MVP Projects and all
revenues received from other utilities under MISO’s tariffed rates as a
credit in its TCR revenue requirement calculations. In doing so, the
MPUC’s order diverts interstate wholesale revenues that have been
approved by the FERC to offset FERC-approved expenses, effectively
reducing OTP’s recovery of those FERC-approved expense levels. The
MPUC-ordered treatment will result in the projects being treated as
retail investments for Minnesota retail ratemaking purposes. Because
the FERC’s revenue requirements and authorized returns will vary
from the MPUC revenue requirements and authorized returns for the
project investments over the lives of the projects, the impact of this
decision will vary over time and be dependent on the differences
between the revenue requirements and returns in the two jurisdictions

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

at any given time. On August 18, 2017 OTP filed an appeal of the
MPUC order with the Minnesota Court of Appeals to contest the portion
of the order requiring OTP to allocate costs between jurisdictions of
the FERC MVP transmission projects in the TCR rider. OTP believes the
MPUC-ordered treatment conflicts with federal authority over
transmission of electricity in interstate commerce and rates for the
transmission of electricity subject to the jurisdiction of the FERC as set
forth in the Federal Power Act of 1935, as amended (Federal Power Act).
A decision is expected in late 2018.

Environmental Cost Recovery Rider—OTP had an ECR rider for
recovery of OTP’s Minnesota jurisdictional share of the revenue
requirements of its investment in the Big Stone Plant Air Quality
Control System (AQCS). The ECR rider provided for a return on the
project’s construction work in progress (CWIP) balance at the level
approved in OTP’s 2010 general rate case. In its 2016 general rate case
order, the MPUC approved OTP’s proposal to transition eligible rate
base and expense recovery from the ECR rider to base rate recovery,
effective with implementation of final rates in November 2017.

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed
a request with the MPUC to revise its Fuel Clause Adjustment (FCA)
rider in Minnesota to include recovery of reagent and emission
allowance costs. On March 12, 2015 the MPUC denied OTP’s request
to revise its FCA rider to include recovery of these costs. These costs
were included in OTP’s 2016 general rate case in Minnesota and were
considered for recovery either through the FCA rider or general rates.
In its 2016 general rate case order issued May 1, 2017 the MPUC again
denied OTP’s request for recovery of test-year reagent costs and
emission allowances in base fuel costs or through the FCA rider.
Instead, the test-year costs will be recovered in general rates and
variability of those costs in excess of amounts included in general
rates will only be recovered to the extent actual kilowatt-hour (kwh)
sales exceed forecasted kwh sales used to establish general rates.

NORTH DAKOTA
General Rates—On November 2, 2017 OTP filed a request with the
NDPSC for a rate review and an effective increase in annual revenues
from non-fuel base rates of $13.1 million or 8.72%. In the request, OTP
proposed an allowed return on rate base of 7.97% and an allowed rate
of return on equity of 10.30%. On December 20, 2017 the NDPSC
approved OTP’s request for interim rates to increase annual revenue
collections by $12.8 million, effective January 1, 2018. OTP used a lower
rate of return on equity in the calculation of interim rates based on the
rate of return on equity used in its 2018 test-year rate request.

OTP’s most recent general rate increase in North Dakota of $3.6 million,

Renewable Resource Adjustment—OTP has a North Dakota Renewable
Resource Adjustment which enables OTP to recover its North Dakota
jurisdictional share of investments in renewable energy facilities. This
rider allows OTP to recover costs associated with new renewable energy
projects as they are completed, along with a return on investment.

Transmission Cost Recovery Rider—North Dakota law provides a
mechanism for automatic adjustment outside of a general rate
proceeding to recover jurisdictional capital and operating costs
incurred by a public utility for new or modified electric transmission
facilities. For qualifying projects, the law authorizes a current return on
CWIP and a return on investment at the level approved in the utility’s
most recent general rate case.

Environmental Cost Recovery Rider—OTP has an ECR rider in North
Dakota to recover its North Dakota jurisdictional share of the revenue
requirements associated with its investment in the Big Stone Plant
AQCS and Hoot Lake Plant MATS projects. The ECR rider provides for
a return on investment at the level approved in OTP’s most recent
general rate case and for recovery of OTP’s North Dakota share of
reagent and emission allowance costs.

SOUTH DAKOTA
2010 General Rate Case—OTP’s most recent general rate increase in
South Dakota of approximately $643,000 or approximately 2.32% was
granted by the SDPUC in an order issued on April 21, 2011 and effective
with bills rendered on and after June 1, 2011. Pursuant to the order,
OTP’s allowed rate of return on rate base was set at 8.50%.

Environmental Cost Recovery Rider—OTP has an ECR rider in South
Dakota to recover its South Dakota jurisdictional share of revenue
requirements associated with its investment in the Big Stone Plant
AQCS and Hoot Lake Plant MATS projects.

Reagent Costs and Emission Allowances—On August 1, 2014 OTP
filed a request with the SDPUC to revise its FCA rider in South Dakota
to include recovery of reagent and emission allowance costs. On
September 16, 2014 the SDPUC approved OTP’s request to include
recovery of these costs in its South Dakota FCA rider.

TCJA
The TCJA reduced the federal corporate income tax rate from 35% to 21%.
Currently, all OTP rates have been developed using a 35% tax rate. The
MPUC, the NDPSC, the SDPUC and the FERC have all initiated dockets
or proceedings to begin working with utilities to assess the impact of
the lower income tax rates under the TCJA on electric rates, and
develop regulatory strategies to incorporate the tax change into future
rates, if warranted. The MPUC required its regulated utilities to make
filings by January 30, 2018 and February 15, 2018, but has not made a
determination on rate treatment. OTP currently has an active rate case
in North Dakota and anticipates incorporating the impact of the tax
changes to North Dakota rates within that proceeding. The SDPUC
required initial comments by February 1, 2018 and indicated that
revenues collected subsequent to December 31, 2017 would be subject
to refund, pending determination of the impacts of the TCJA. OTP is
still assessing these impacts and will continue to work with the
respective commissions to determine if any rate adjustments are
necessary, and if so, to determine the appropriate timing and
approach for making those adjustments.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

RATE RIDER UPDATES
The following table provides summary information on the status of updates since January 1, 2014 for the rate riders described above:

Rate Rider

Minnesota

Conservation Improvement Program
2016 Incentive and Cost Recovery
2015 Incentive and Cost Recovery
2014 Incentive and Cost Recovery
2013 Incentive and Cost Recovery

Transmission Cost Recovery

2017 Rate Reset (1)
2016 Annual Update
2015 Annual Update
2014 Annual Update
2013 Annual Update

Environmental Cost Recovery

2017 Rate Reset
2016 Annual Update
2015 Annual Update
2014 Annual Update

North Dakota

Renewable Resource Adjustment

2017 Rate Reset
2016 Annual Update
2015 Annual Update
2014 Annual Update
2013 Annual Update

Transmission Cost Recovery

2017 Annual Update
2016 Annual Update
2015 Annual Update
2014 Annual Update

Environmental Cost Recovery

2017 Rate Reset
2017 Annual Update
2016 Annual Update
2015 Annual Update
2014 Annual Update

South Dakota

Transmission Cost Recovery

2017 Annual Update
2016 Annual Update
2015 Annual Update
2014 Annual Update
2013 Annual Update

Environmental Cost Recovery

2017 Annual Update
2016 Annual Update
2015 Annual Update
2014 Initial Request

R—Request Date
A—Approval Date

A—September 15, 2017
A—July 19, 2016
A—July 10, 2015
A—September 26, 2014

A—October 30, 2017
A—July 5, 2016
A—March 9, 2016
A—February 18, 2015
A—June 24, 2014

A—October 30, 2017
A—July 5, 2016
A—March 9, 2016
A—November 26, 2014

A—December 20, 2017
A—March 15, 2017
A—June 22, 2016
A—March 25, 2015
A—March 12, 2014

A—November 29, 2017
A—December 14, 2016
A—December 16, 2015
A—December 17, 2014

A – December 20, 2017
A—July 12, 2017
A—June 22, 2016
A—June 17, 2015
A—July 10, 2014

R—November 1, 2017
A—February 17, 2017
A—February 12, 2016
A—February 13, 2015
A—February 18, 2014

A—October 13, 2017
A—October 26, 2016
A—October 15, 2015
A—November 25, 2014

Effective Date
Requested or
Approved

Annual
Revenue
($000s)

October 1, 2017
October 1, 2016
October 1, 2015
October 1, 2014

November 1, 2017
September 1, 2016
April 1, 2016
March 1, 2015
March 1, 2014

November 1, 2017
September 1, 2016
October 1, 2015
December 1, 2014

January 1, 2018
April 1, 2017
July 1, 2016
April 1, 2015
April 1, 2014

January 1, 2018
January 1, 2017
January 1, 2016
January 1, 2015

January 1, 2018
August 1, 2017
July 1, 2016
July 1, 2015
August 1, 2014

March 1, 2018
March 1, 2017
March 1, 2016
March 1, 2015
March 1, 2014

November 1, 2017
November 1, 2016
November 1, 2015
December 1, 2014

$
$
$
$

$
$
$
$
$

$
$
$
$

$
$
$
$
$

$
$
$
$

$
$
$
$
$

$
$
$
$

Rate

$0.00536/kwh
$0.00275/kwh
$0.00287/kwh
$0.00263/kwh

Various
Various
Various
Various
Various

9,868
8,590
8,689
8,862

(3,311)
4,736
7,203
8,388
2,066

(1,943)
11,884
12,104

9,229 (2)

-0.935% of base
6.927% of base
7.006% of base
7.006% of base

9,989
9,156
9,262
5,441
8,068

7,959
6,916
9,985
8,463

8,537
9,917
10,359
12,249
9,880

1,779
2,053
1,895
1,538
1,349

2,082
2,238
2,728
1,995

7.756% of base
7.005% of base
7.573% of base
4.069% of base
$0.00437/kwh

Various
Various
Various
Various

6.629% of base
7.633% of base
7.904% of base
9.193% of base
7.531% of base

Various
Various
Various
Various
Various

$0.00483/kwh
$0.00536/kwh
$0.00643/kwh
$0.00487/kwh

(1) Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket.
(2) Amount approved for recovery over ten months through September 30, 2015. Initial 2014 annual update requirement was $10.2 million to be effective October 1, 2014.

Due to delayed approval, the amount was reduced for revenues billed under the rider rate in effect from October 1, 2014 through November 30, 2014.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

On February 12, 2015 another group of stakeholders filed a complaint

with the FERC seeking to reduce the ROE component of the
transmission rates that MISO transmission owners, including OTP,
may collect under the MISO Tariff from 12.38% to a proposed 8.67%.
This second complaint established a second 15-month refund period
from February 12, 2015 to May 11, 2016. The FERC issued an order on
June 18, 2015 setting the complaint for hearings before an ALJ, which
were held the week of February 16, 2016. A non-binding decision by
the presiding ALJ was issued on June 30, 2016 finding that the MISO
transmission owners’ ROE should be 9.7%. OTP is currently waiting for
the issuance of a FERC order on the second complaint.

Based on the probable reduction by the FERC in the ROE component
of the MISO Tariff, OTP had a $2.7 million liability on its balance sheet
as of December 31, 2016, representing OTP’s best estimate of the
refund obligations that would arise, net of amounts that would be
subject to recovery under state jurisdictional TCR riders, based on a
reduced ROE. MISO processed the refund for the FERC-ordered
reduction in the MISO Tariff allowed ROE for the first 15-month refund
period in its February and June 2017 billings. The refund, in combination
with a decision in the 2016 Minnesota general rate case that affected
the Minnesota TCR rider, has resulted in a reduction in OTP’s accrued
MISO Tariff ROE refund liability from $2.7 million on December 31, 2016
to $1.6 million as of December 31, 2017.

In June 2014, the FERC adopted a two-step ROE methodology for
electric utilities in an order issued in a complaint proceeding involving
New England Transmission Owners (NETOs). The issue of how to apply
the FERC ROE methodology has been contested in various complaint
proceedings, including the two ROE complaints involving MISO
transmission owners discussed above. In April 2017 the Court of
Appeals for the District of Columbia (D.C. Circuit) vacated and
remanded the FERC’s June 2014 ROE order in the NETOs’ complaint.
The D.C. Circuit found that the FERC had not properly determined that
the ROE authorized for NETOs prior to June 2014 was unjust and
unreasonable. The D.C. Circuit also found that the FERC failed to justify
the new ROE methodology. OTP will await the FERC response to the
April 2017 action of the D.C. Circuit before determining if an adjustment
to its accrued refund liability is required. On September 29, 2017 the
MISO transmission owners filed a motion to dismiss the second
complaint based on the D.C. Circuit decision in the NETO complaint. If
FERC were to act on a motion to dismiss, it would eliminate the refund
obligation from the second complaint and the ROE from the first
complaint would remain in effect.

4. Regulatory Assets and Liabilities

As a regulated entity, OTP accounts for the financial effects of regulation
in accordance with ASC 980. This accounting standard allows for the
recording of a regulatory asset or liability for costs that will be collected
or refunded in the future as required under regulation. Additionally,
ASC 980-605-25 provides for the recognition of revenues authorized
for recovery outside of a general rate case under alternative revenue
programs which provide for recovery of costs and incentives or returns
on investment in such items as transmission infrastructure, renewable
energy resources or conservation initiatives.

REVENUES RECORDED UNDER RATE RIDERS
The following table presents revenue recorded by OTP under rate
riders in place in Minnesota, North Dakota and South Dakota for the
years ended December 31:

Rate Rider (in thousands)

2017

2016

2015

Minnesota

Conservation Improvement Program

Costs and Incentives (1)
Transmission Cost Recovery
Environmental Cost Recovery

North Dakota

Renewable Resource Adjustment
Transmission Cost Recovery
Environmental Cost Recovery

South Dakota

Transmission Cost Recovery
Environmental Cost Recovery
Conservation Improvement Program

9,225 $
2,973
8,148

7,620
8,729
9,782

1,843
2,345

12,920 $

5,795
12,443

7,800
7,694
11,089

1,820
2,538

10,724
5,202
10,238

8,409
6,609
9,502

1,290
1,967

Costs and Incentives

598

468

583

(1) Includes MNCIP costs recovered in base rates.

On November 12, 2013 a group of industrial customers and other
stakeholders filed a complaint with the FERC seeking to reduce the
ROE component of the transmission rates that MISO transmission
owners, including OTP, may collect under the MISO Tariff. The
complainants sought to reduce the 12.38% ROE used in MISO’s
transmission rates to a proposed 9.15%. The complaint established a
15-month refund period from November 12, 2013 to February 11, 2015.
A non-binding decision by the presiding Administrative Law Judge
(ALJ) was issued on December 22, 2015 finding that the MISO
transmission owners’ ROE should be 10.32%, and the FERC issued
an order on September 28, 2016 setting the base ROE at 10.32%.
A number of parties requested rehearing of the September 2016 order
and the requests are pending FERC action.

On November 6, 2014 a group of MISO transmission owners, including

OTP, filed for a FERC incentive of an additional 50-basis points for
Regional Transmission Organization participation (RTO Adder). On
January 5, 2015 the FERC granted the request, deferring collection of
the RTO Adder until the FERC issued its order in the ROE complaint
proceeding. Based on the FERC adjustment to the MISO Tariff ROE
resulting from the November 12, 2013 complaint and OTP’s incentive
rate filing, OTP’s ROE will be 10.82% (a 10.32% base ROE plus the
0.5% RTO Adder) effective September 28, 2016.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

(in thousands)

Regulatory Assets:

December 31, 2017

Current

Long-Term

Total

Remaining
Recovery/Refund
Period (months)

Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits (1)
Conservation Improvement Program Costs and Incentives (2)
Accumulated ARO Accretion/Depreciation Adjustment (1)
Deferred Marked-to-Market Losses (1)
Big Stone II Unrecovered Project Costs—Minnesota (1)
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up (2)
Debt Reacquisition Premiums (1)
Big Stone II Unrecovered Project Costs—South Dakota (2)
North Dakota Renewable Resource Rider Accrued Revenues (2)
North Dakota Deferred Rate Case Expenses Subject to Recovery (1)
Minnesota Deferred Rate Case Expenses Subject to Recovery (1)
North Dakota Environmental Cost Recovery Rider Accrued Revenues (2)
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues (2)

9,090
7,385
—
4,063
650
—
254
100
206
309
267
152
75

$ 112,487
2,774
6,651
2,405
1,636
1,985
960
442
236
—
—
—
—

$ 121,577
10,159
6,651
6,468
2,286
1,985
1,214
542
442
309
267
152
75

Total Regulatory Assets

Regulatory Liabilities:

Deferred Income Taxes
Accumulated Reserve for Estimated Removal Costs—Net of Salvage
Refundable Fuel Clause Adjustment Revenues
Minnesota Environmental Cost Recovery Rider Accrued Refund
Minnesota Transmission Cost Recovery Rider Accrued Refund
Minnesota Renewable Resource Recovery Rider Accrued Refund
North Dakota Transmission Cost Recovery Rider Accrued Refund
Revenue for Rate Case Expenses Subject to Refund—Minnesota
South Dakota Environmental Cost Recovery Rider Accrued Refund
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
South Dakota Transmission Cost Recovery Rider Accrued Refund
Other

Total Regulatory Liabilities

Net Regulatory Asset/(Liability) Position

$ 22,551

$ 129,576

$ 152,127

—
—
5,778
1,667
802
409
349
208
187
132
151
5

$ 149,052
83,100
—
—
609
—
—
—
—
48
—
84

$ 149,052
83,100
5,778
1,667
1,411
409
349
208
187
180
151
89

9,688

$ 12,863

$ 232,893

$ 242,581

$(103,317)

$ (90,454)

see below
21
asset lives
36
40
24
177
65
15
12
4
12
12

asset lives
asset lives
12
11
22
12
12
4
12
24
12
192

(1) Costs subject to recovery without a rate of return.
(2) Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

(in thousands)

Regulatory Assets:

December 31, 2016

Current

Long-Term

Total

Remaining
Recovery/Refund
Period (months)

Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits (1)
Conservation Improvement Program Costs and Incentives (2)
Accumulated ARO Accretion/Depreciation Adjustment (1)
Deferred Marked-to-Market Losses (1)
Big Stone II Unrecovered Project Costs—Minnesota (1)
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up (2)
Debt Reacquisition Premiums (1)
Big Stone II Unrecovered Project Costs—South Dakota (2)
North Dakota Renewable Resource Rider Accrued Revenues (2)
Minnesota Deferred Rate Case Expenses Subject to Recovery (1)
North Dakota Environmental Cost Recovery Rider Accrued Revenues (2)
Deferred Income Taxes (1)
Recoverable Fuel and Purchased Power Costs (1)
Minnesota Renewable Resource Rider Accrued Revenues (2)
North Dakota Transmission Cost Recovery Rider Accrued Revenues (2)
South Dakota Transmission Cost Recovery Rider Accrued Revenues (2)

6,443
4,836
—
4,063
778
333
325
100
1,319
1,082
113
—
1,798
34
—
73

$ 108,267
5,158
6,153
6,467
2,087
—
1,214
543
482
—
—
1,014
—
—
568
141

$ 114,710
9,994
6,153
10,530
2,865
333
1,539
643
1,801
1,082
113
1,014
1,798
34
568
214

Total Regulatory Assets

Regulatory Liabilities:

Deferred Income Taxes
Accumulated Reserve for Estimated Removal Costs—Net of Salvage
Minnesota Environmental Cost Recovery Rider Accrued Refund
Minnesota Transmission Cost Recovery Rider Accrued Refund
North Dakota Transmission Cost Recovery Rider Accrued Refund
Revenue for Rate Case Expenses Subject to Refund—Minnesota
South Dakota Environmental Cost Recovery Rider Accrued Refund
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
Other

Total Regulatory Liabilities

Net Regulatory Asset Position

$ 21,297

$ 132,094

$ 153,391

—
—
139
757
1,381
711
285
—
21

818
80,404
—
—
782
208
—
132
89

818
80,404
139
757
2,163
919
285
132
110

3,294

$ 18,003

$ 82,433

$ 85,727

$ 49,661

$ 67,664

see below
21
asset lives
48
52
12
189
77
15
12
12
asset lives
12
9
24
14

asset lives
asset lives
12
12
24
16
12
24
204

(1) Costs subject to recovery without a rate of return.
(2) Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

The Accumulated Reserve for Estimated Removal Costs—Net of
Salvage is reduced as actual removal costs, net of salvage revenues,
are incurred.

The Minnesota Environmental Cost Recovery Rider Accrued Refund
relates to amounts collected on the Minnesota share of OTP’s investment
in the Big Stone Plant AQCS project that are refundable to Minnesota
customers as of December 31, 2017.

The Minnesota Transmission Cost Recovery Rider Accrued Refund
relates to amounts collected for qualifying transmission system facilities
and operating costs incurred to serve Minnesota customers that are
refundable to Minnesota customers as of December 31, 2017.

The Minnesota Renewable Resource Rider Accrued Refund relates
to amounts collected for qualifying renewable resource costs incurred
to serve Minnesota customers that are refundable to Minnesota
customers as of December 31, 2017.

The North Dakota Transmission Cost Recovery Rider Accrued Refund
relates to amounts collected for qualifying transmission system facilities
and operating costs incurred to serve North Dakota customers that
are refundable to North Dakota customers as of December 31, 2017.
Revenue for Rate Case Expenses Subject to Refund—Minnesota
relates to revenues collected under general rates to recover costs
related to prior rate case proceedings in excess of the actual costs
incurred, which are subject to refund over a 24-month period
beginning with the establishment of interim rates in April 2016.

The South Dakota Environmental Cost Recovery Rider Accrued
Refund relates to amounts collected on the South Dakota share of
OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant
MATS projects that are refundable to South Dakota customers as of
December 31, 2017.

The South Dakota Transmission Cost Recovery Rider Accrued

Revenues relate to revenues earned on qualifying transmission system
facilities that had not been billed to South Dakota customers as of
December 31, 2016.

The South Dakota Transmission Cost Recovery Rider Accrued
Refund relates to amounts collected for qualifying transmission
system facilities and operating costs incurred to serve South Dakota
customers that are refundable to South Dakota customers as of
December 31, 2017.

If for any reason OTP ceases to meet the criteria for application of
guidance under ASC 980 for all or part of its operations, the regulatory
assets and liabilities that no longer meet such criteria would be removed
from the consolidated balance sheet and included in the consolidated
statement of income as an expense or income item in the period in
which the application of guidance under ASC 980 ceases.

The regulatory liability and asset related to Deferred Income Taxes
results from changes in statutory tax rates accounted for in accordance
with ASC Topic 740, Income Taxes.

The regulatory asset related to prior service costs and actuarial losses
on pensions and other postretirement benefits represents benefit costs
and actuarial losses subject to recovery through rates as they are
expensed over the remaining service lives of active employees included
in the plans. These unrecognized benefit costs and actuarial losses are
required to be recognized as components of Accumulated Other
Comprehensive Income in equity under ASC Topic 715, Compensation—
Retirement Benefits, but are eligible for treatment as regulatory assets
based on their probable recovery in future retail electric rates.

Conservation Improvement Program Costs and Incentives represent

mandated conservation expenditures and incentives recoverable
through retail electric rates.

The Accumulated Asset Retirement Obligation (ARO)

Accretion/Depreciation Adjustment will accrete and be amortized
over the lives of property with asset retirement obligations.

All Deferred Marked-to-Market Losses recorded as of December 31,

2017 relate to forward purchases of energy scheduled for delivery
through December 2020.

Big Stone II Unrecovered Project Costs—Minnesota are the Minnesota

share of generation and transmission plant-related costs incurred by
OTP related to its participation in the abandoned Big Stone II project.
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups
relate to the over/under collection of revenue based on comparison of
the expected versus actual construction on eligible projects in the
period. The true-ups also include the state jurisdictional portion of
MISO Schedule 26/26A for regional transmission cost recovery that
was included in the calculation of the state transmission riders and
subsequently adjusted to reflect actual billing amounts in the schedule.

Debt Reacquisition Premiums are being recovered from OTP
customers over the remaining original lives of the reacquired debt
issues, the longest of which is 177 months.

Big Stone II Unrecovered Project Costs—South Dakota are the
South Dakota share of generation and transmission plant-related
costs incurred by OTP related to its participation in the abandoned
Big Stone II project.

North Dakota Renewable Resource Rider Accrued Revenues relate
to qualifying renewable resource costs incurred to serve North Dakota
customers that have not been billed to North Dakota customers as of
December 31, 2017.

North Dakota Deferred Rate Case Expenses Subject to Recovery
relate to costs incurred in conjunction with OTP’s current rate case
in North Dakota currently being recovered over a 12-month period
beginning with the establishment of interim rates in January 2018.
Minnesota Deferred Rate Case Expenses Subject to Recovery
relate to costs incurred in conjunction with OTP’s 2016 rate case
in Minnesota currently being recovered over a 24-month period
beginning with the establishment of interim rates in April 2016.

North Dakota Environmental Cost Recovery Rider Accrued Revenues

relate to revenues earned on the North Dakota share of OTP’s
investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS
projects and for reagent and emission allowances costs that are
recoverable from North Dakota customers as of December 31, 2017.

Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues

relate to revenues recorded for fuel and purchased power costs
reductions provided to customers in energy intensive trade exposed
industries that are subject to recovery from other Minnesota customers.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

5. Common Shares and Earnings per Share

Shelf Registration
The Company’s shelf registration statement filed with the Securities and
Exchange Commission (SEC) on May 11, 2015, under which the Company
may offer for sale, from time to time, either separately or together in
any combination, equity, debt or other securities described in the shelf
registration statement, including common shares of the Company,
expires on May 11, 2018.

2014 Stock Incentive Plan
The 2014 Stock Incentive Plan (2014 Incentive Plan), which was
approved by the Company’s shareholders in April 2014, provides for
the grant of stock options, stock appreciation rights, restricted stock,
restricted stock units, performance awards, and other stock and
stock-based awards. A total of 1,900,000 common shares were
authorized for granting stock awards under the 2014 Incentive Plan,
of which 1,244,353 were available for issuance as of December 31, 2017.
The 2014 Incentive Plan terminates on December 13, 2023.

Common Share Distribution Agreement
On May 11, 2015, the Company entered into a Distribution Agreement
with J.P. Morgan Securities (JPMS) under which it may offer and sell
its common shares from time to time in an At-the-Market offering
program through JPMS, as its distribution agent, up to an aggregate
sales price of $75 million.

Under the Distribution Agreement, the Company will designate the

minimum price and maximum number of shares to be sold through
JPMS on any given trading day or over a specified period of trading
days, and JPMS will use commercially reasonable efforts to sell such
shares on such days, subject to certain conditions. Sales of the shares,
if any, will be made by means of ordinary brokers’ transactions on the
NASDAQ Global Select Market at market prices or as otherwise agreed
with JPMS. The Company may also agree to sell shares to JPMS, as
principal for its own account, on terms agreed by the Company and
JPMS in a separate agreement at the time of sale. The Company is not
obligated to sell and JPMS is not obligated to buy or sell any of the
shares under the Distribution Agreement. The shares, if issued, will be
issued pursuant to the Company’s existing shelf registration statement.

2017 Common Stock Activity
Following is a reconciliation of the Company’s common shares
outstanding from December 31, 2016 through December 31, 2017:

Common Shares Outstanding December 31, 2016
Issuances:
Executive Stock Performance Awards (2014 shares earned)
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested
Cash Invested
Vesting of Restricted Stock Units
Restricted Stock Issued to Directors
Employee Stock Ownership Plan
Employee Stock Purchase Plan:
Dividends Reinvested
Cash Invested
Directors Deferred Compensation
Retirements:
Shares Withheld for Individual Income Tax Requirements

Common Shares Outstanding December 31, 2017

39,348,136

89,291

68,235
29,463
22,225
17,600
14,835

9,566
5,284
560

(47,704)

39,557,491

Employee Stock Purchase Plan
The 1999 Employee Stock Purchase Plan (Purchase Plan) allowed
eligible employees to purchase the Company’s common shares at
85% of the market price at the end of each six-month purchase period
through December 31, 2016. For purchase periods beginning after
January 1, 2017, the purchase price is 100% of the market price at
the end of each six-month purchase period. On April 16, 2012, the
Company’s shareholders approved an amendment to the Purchase
Plan, increasing the number of shares available under the Purchase
Plan from 900,000 common shares to 1,400,000 common shares
and making certain other changes to the terms of the Purchase Plan.
Of the 1,400,000 common shares authorized to be issued under the
Purchase Plan, 374,624 were available for purchase as of December 31,
2017. At the discretion of the Company, shares purchased under the
Purchase Plan can be either new issue shares or shares purchased in
the open market. To provide shares for purchases for the Purchase
Plan, 9,486 common shares were issued in 2017, 53,875 common
shares were issued in 2016 and 42,253 common shares were issued in
2015. Shares available for purchase were also reduced by 49 shares in
2017 to reserve for fractional shares.

Dividend Reinvestment and Share Purchase Plan
The Company’s shelf registration statement filed with the SEC on
May 11, 2015, as amended on October 13, 2015, provides for the issuance
of up to 1,500,000 common shares under the Company’s Automatic
Dividend Reinvestment and Share Purchase Plan (the Plan), which
permits shares purchased by participants in the Plan to be either new
issue common shares or common shares purchased in the open market.
New common shares issued under the Plan totaled 97,698 in 2017,
278,811 in 2016 and 302,519 in 2015, leaving 820,972 common shares
available for issuance under the Plan as of December 31, 2017.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

Earnings Per Share
The numerator used in the calculation of both basic and diluted earnings per common share is net income with no adjustments in 2017, 2016 and 2015.
The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding
during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently
returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings
per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation:

Weighted Average Common Shares Outstanding—Basic

Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based

Compensation Expense and Excess Tax Benefits:

Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers

based on Measurement Period-to-Date Performance

Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees
Nonvested Restricted Shares
Shares Expected to be Issued Under the Deferred Compensation Program for Directors
Potentially Dilutive Stock Options

Total Dilutive Shares

2017

2016

2015

39,457,261

38,546,459

37,494,986

210,784
56,952
20,380
2,970
—

291,086

118,644
45,712
16,778
3,417
—

184,551

100,194
36,180
22,848
13,488
330

173,040

Weighted Average Common Shares Outstanding—Diluted

39,748,347

38,731,010

37,668,026

The effect of dilutive shares on earnings per share for the years ended December 31, 2017, 2016 and 2015, resulted in no differences greater than

$0.014 between basic and diluted earnings per share in total or from continuing or discontinued operations in any period.

6. Share-Based Payments

Purchase Plan
Through December 31, 2016, the Purchase Plan allowed employees through payroll withholding to purchase shares of the Company’s common
stock at a 15% discount from the average market price on the last day of a six-month investment period. Under ASC Topic 718, Compensation—
Stock Compensation (ASC 718), the Company was required to record compensation expense related to the 15% discount. The 15% discount resulted
in compensation expense of $173,000 in 2016 and $184,000 in 2015. For purchase periods beginning after January 1, 2017, the purchase price is
100% of the market price at the end of each six-month purchase period.

Stock Options Granted Under the 1999 Incentive Plan
The Company granted 2,041,500 options for the purchase of the Company’s common stock under the 1999 Stock Incentive Plan (1999 Incentive Plan).
The exercise price of the options granted was the average market price of the Company’s common stock on the grant date. Under ASC 718
accounting requirements, compensation expense is recorded based on the estimated fair value of the options on their grant date using a fair-value
option pricing model. Under ASC 718 accounting requirements, the fair value of the options granted has been recorded as compensation expense
over the requisite service period (the vesting period of the options). The estimated fair value of all options granted under the 1999 Incentive Plan
was based on the Black-Scholes option pricing model. There were no options outstanding as of December 31 of each of the years, 2017, 2016 or 2015.

Presented below is a summary of the stock options activity:

Stock Options Activity

Outstanding, Beginning of Year
Exercised
Forfeited or Expired

Outstanding, End of Year

Exercisable, End of Year
Cash Received for Options Exercised
Intrinsic Value of Options Exercised

Options

—
—
—

—

2017

Average
Exercise
Price

2016

Average
Exercise
Price

Options

—
—
—

—

Options

12,750
10,250
2,500

—

2015

Average
Exercise
Price

24.93
24.93
24.93

$
$

256,000
75,000

Restricted Stock Granted to Directors
Under the 1999 Incentive Plan and the 2014 Incentive Plan, restricted shares of the Company’s common stock were granted to members of the
Company’s board of directors as a form of compensation. All remaining restricted shares issued under the 1999 Incentive Plan vested on April 8, 2017.
Under ASC 718 accounting requirements, compensation expense related to restricted shares is based on the fair value of the restricted shares on
their grant dates. On April 10, 2017, 17,600 shares of restricted stock were granted to the Company’s nonemployee directors. The grant-date fair
value of each share of restricted stock granted on April 10, 2017 was $37.75 per share, the average of the high and low market price on the date
of grant. The restricted shares granted in 2017 vest 25% per year on April 8 of each year in the period 2018 through 2021 and are eligible for full
dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of
the restricted stock award agreement.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

Presented below is a summary of the status of directors’ restricted stock awards for the years ended December 31:

Directors’ Restricted Stock Awards

Nonvested, Beginning of Year
Granted
Vested
Forfeited

Nonvested, End of Year

Compensation Expense Recognized
Fair Value of Shares Vested in Year

46,334
17,600
17,134
—

46,800

2017

Weighted
Average
Grant-Date
Fair Value

29.71
37.75
29.93

32.65

$
$

658,000
513,000

38,217
23,200
15,083
—

46,334

2016

Weighted
Average
Grant-Date
Fair Value

29.78
28.66
28.28

29.71

$ 491,000
$ 427,000

38,050
15,200
15,033
—

38,217

2015

Weighted
Average
Grant-Date
Fair Value

27.47
31.775
25.96

29.78

$ 417,000
$ 390,000

Restricted Stock Granted to Employees
Under the 1999 Incentive Plan and 2014 Incentive Plan, restricted shares of the Company’s common stock have been granted to employees as a
form of compensation. All remaining restricted shares issued under the 1999 Incentive Plan vested on April 8, 2017. Under ASC 718 accounting
requirements, compensation expense related to restricted shares is based on the fair value of the restricted shares on their grant dates. No shares
of restricted stock have been granted to employees since 2014.

Presented below is a summary of the status of employees’ restricted stock awards for the years ended December 31:

Employees’ Restricted Stock Awards

Nonvested, Beginning of Year
Granted
Vested
Forfeited

Nonvested, End of Year

Compensation Expense Recognized
Fair Value of Awards Vested

7,180
—
4,285
—

2,895

2017

Weighted
Average
Grant-Date
Fair Value

29.72

29.94

29.41

$
$

70,000
128,000

13,581
—
6,401
—

7,180

2016

Weighted
Average
Grant-Date
Fair Value

28.56

27.25

29.72

96,000
$
$ 174,000

45,280
—
31,699
—

13,581

2015

Weighted
Average
Grant-Date
Fair Value

27.46

27.09

28.56

$ 359,000
$ 859,000

Restricted Stock Units Granted to Executive Officers
On February 2, 2017, 15,900 restricted stock units under the 2014 Incentive Plan were granted to the Company’s executive officers. The grant-date
fair value of each restricted stock unit was $37.65 per share, the average of the high and low market price on the date of grant. The restricted
stock units granted to executive officers in 2017 vest 25% per year on February 6 of each year in the period 2018 through 2021 and are eligible to
receive dividend equivalent payments on all unvested awards over the awards’ respective vesting periods, subject to forfeiture under the terms of
the restricted stock unit award agreements. The vesting of restricted stock units is accelerated in the event of a change in control, disability, death
or retirement, subject to proration on retirement in certain cases.

Presented below is a summary of the status of restricted stock unit awards granted to executive officers for the years ended December 31:

Executives’ Restricted Stock Unit Awards

Nonvested, Beginning of Year
Granted
Vested
Forfeited

Nonvested, End of Year

Compensation Expense Recognized
Fair Value of Awards Vested

41,825
15,900
9,975
—

47,750

2017

Weighted
Average
Grant-Date
Fair Value

30.23
37.65
30.16

32.71

$
$

576,000
301,000

24,300
22,000
4,475
—

41,825

2016

Weighted
Average
Grant-Date
Fair Value

31.682
28.915
31.69

30.23

$ 446,000
$ 142,000

—
29,100
4,800
—

24,300

2015

Weighted
Average
Grant-Date
Fair Value

31.681
31.675

31.682

$ 452,000
$ 152,000

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

Restricted Stock Units Granted to Employees
In 2017 the following restricted stock unit awards under the 2014 Incentive Plan were granted to key employees of the Company who are not
executive officers:

Restricted Stock Units Vesting 100% on April 8, 2021
Restricted Stock Units Vesting 100% on April 8, 2021

Grant Date

Units Granted

Grant-Date Fair Value per Award

April 10, 2017
September 25, 2017

9,995
1,000

$32.78
$38.29

The grant-date fair value of each restricted stock unit was based on the average of the high and low market price of the Company’s common
stock on the date of grant, discounted for the value of the dividend exclusion over the four-year vesting period. Under the terms of the restricted
stock unit award agreements, all outstanding (unvested) restricted stock units held by a retiring grantee vest immediately on normal retirement.

Presented below is a summary of the status of employees’ restricted stock unit awards for the years ended December 31:

Employees’ Restricted Stock Unit Awards

Nonvested, Beginning of Year
Granted
Vested
Forfeited

Nonvested, End of Year

Compensation Expense Recognized
Fair Value of Awards Vested

Restricted
Stock
Units

47,370
10,995
11,550
375

46,440

2017

Weighted
Average
Grant-Date
Fair Value

25.19
33.28
25.30
26.92

27.07

$
$

331,000
292,000

Restricted
Stock
Units

46,600
17,220
12,250
4,200

47,370

2016

Weighted
Average
Grant-Date
Fair Value

23.75
24.54
19.03
24.51

25.19

$ 307,000
$ 233,000

Restricted
Stock
Units

45,900
15,650
12,250
2,700

46,600

2015

Weighted
Average
Grant-Date
Fair Value

21.82
25.89
19.46
22.84

23.75

$ 304,000
$ 238,000

Stock Performance Awards granted to Executive Officers
Agreements for stock performance awards have been granted under the 2014 Incentive Plan for the Company’s executive officers. Under these
agreements, the officers could be awarded shares of the Company’s common stock based on the Company’s total shareholder return relative to
that of its peer group of companies in the Edison Electric Institute (EEI) Index over a three-year period beginning on January 1 of the year the
awards are granted. The awards also include a performance incentive based on the Company’s average 3-year adjusted return on equity (ROE)
relative to a targeted average 3-year adjusted ROE. The number of shares earned, if any, will be awarded and issued at the end of each three-year
performance measurement period. The participants have no voting or dividend rights under these award agreements until common shares, if any,
are issued at the end of the performance measurement period.

On February 2, 2017 performance share awards were granted to the Company’s executive officers under the 2014 Incentive Plan for the
2017-2019 performance measurement period. Under the 2017 performance share award agreements the aggregate award for performance at
target is 59,500 shares. For target performance the participants would earn an aggregate of 39,667 common shares based on the Company’s
total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance measurement
period of January 1, 2017 through December 31, 2019, with the beginning and ending share values based on the average closing price of a share of
the Company’s common stock for the 20 trading days immediately following January 1, 2017 and the average closing price for the 20 trading days
immediately preceding January 1, 2020. The participants would also earn an aggregate of 19,833 common shares for achieving the target set for
the Company’s 3-year average adjusted ROE. Actual payment may range from zero to 150% of the target amount, or up to 89,250 common shares.
The grant-date fair value of each performance share award was determined using a Monte Carlo fair valuation simulation model resulting in a
weighted average fair value of $30.25 per share, except for one grantee whose performance shares were fair valued at $36.27 per share due to
retirement provisions in his award agreement.

Under the 2017 performance award agreements payment in the event of retirement, resignation for good reason or involuntary termination
without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that
the payment of performance awards granted to certain officers who are parties to executive employment agreements with the Company is to be
made at target at the date of any such event. The vesting of these performance awards is accelerated and paid at target in the event of a change
in control, disability or death and on retirement at or after age 62 for certain officers who are parties to executive employment agreements with
the Company. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC 718,
and recognized over the grantee’s requisite service period based on the grant-date fair value of the award.

The table below provides a summary of stock performance awards granted and amounts expensed related to the stock performance awards:

Performance
Period

Maximum Shares
Subject To Award

2017-2019
2016-2018
2015-2017
2014-2016
2013-2015

Total

89,250
122,250
126,450
159,450
90,600

Target
Shares

59,500
81,500
84,300
106,300
45,300

2017

854,000
580,000
573,000
—
—

Expense Recognized in the
Year Ended December 31,

2016

2015

798,000
535,000
332,000
—

943,000
(64,000)
(445,000)

$ 2,007,000

$ 1,665,000

434,000

Earned
Shares

7,500
11,100
114,648
121,491
22,500

277,239

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

Stock-based payment expense recognized in 2017, 2016 and 2015 for
the 2017-2019, 2016-2018 and 2015-2017 performance awards reflects
the accelerated recognition of expense for outstanding and unvested
awards of executives who are eligible for retirement and whose
awards vest on normal retirement, as defined in the performance
award agreements, prior to the vesting dates of the awards.

The earned shares shown in the table above for the 2016-2018 and
2017-2019 performance periods include vested shares to be issued in
2018 to a participant who retired on December 31, 2017 and had
reached age 62 prior to retirement.

The earned shares shown in the table above for the 2015-2017

performance period include shares received in 2018 by participants in
the plan based on the Company achieving a total shareholder return
ranking of 2 out of 42 companies in the EEI Index and an average
3-year adjusted return on equity of 10.16% relative to a targeted
average 3-year adjusted return on equity of 10.00% resulting payout
at 136.00% of target.

The earned shares shown in the table above for the 2014-2016
performance period include shares received in 2017 by participants in
the plan based on the Company achieving a total shareholder return
ranking of 19 out of 43 companies in the EEI Index and a resulting
payout at 114.29% of target. The earned shares also include shares
for a portion of the award that vested on normal retirement of the
Company’s former CEO on July 1, 2015 that were issued in 2016
following the 180 day deferral period required under the Internal
Revenue Code at a value of $26.35 per share or $848,000.

The earned shares shown in the table above for the 2013-2015
performance period reflect shares that vested on normal retirement
of the Company’s former CEO on July 1, 2015 that were issued in 2016
following the 180 day deferral period required under the Internal
Revenue Code at a value of $26.35 per share or $593,000.

In connection with the resignation of an executive officer in May 2014,

the following unvested stock performance awards were forfeited:
8,900 granted in 2014 and 4,900 granted in 2013.

As of December 31, 2017 the total remaining unrecognized amount
of compensation expense related to stock-based compensation for all
of the Company’s stock-based payment programs was approximately
$4.0 million (before income taxes), which will be amortized over a
weighted average period of 2.0 years.

7. Retained Earnings and Dividend Restriction

The Company is a holding company with no significant operations of
its own. The primary source of funds for payments of dividends to the
Company’s shareholders is from dividends paid or distributions made by
the Company’s subsidiaries. As a result of certain statutory limitations
or regulatory or financing agreements, restrictions could occur on the
amount of distributions allowed to be made by the Company’s
subsidiaries.

Both the Company and OTP credit agreements contain restrictions
on the payment of cash dividends upon a default or event of default.
An event of default would be considered to have occurred if the
Company did not meet certain financial covenants. As of December 31,
2017 the Company was in compliance with these financial covenants.
See note 9 to consolidated financial statements for further information
on the covenants.

The MPUC indirectly limits the amount of dividends OTP can pay
to the Company by requiring an equity-to-total-capitalization ratio
between 47.4% and 58.0% based on OTP’s 2017 capital structure
petition approved by order of the MPUC on September 1, 2017. As of
December 31, 2017 OTP’s equity-to-total-capitalization ratio including
short-term debt was 51.4% and its net assets restricted from distribution
totaled approximately $471,000,000. Total capitalization for OTP
cannot currently exceed $1,178,024,000.

8. Commitments and Contingencies of Continuing

Operations

Construction and Other Purchase Commitments
At December 31, 2017 OTP had commitments under contracts, including
its share of construction program commitments, extending into 2019,
of approximately $41.0 million. At December 31, 2017 T.O. Plastics had
commitments for the purchase of resin through December 31, 2021 of
approximately $6.7 million.

Electric Utility Capacity and Energy Requirements and Coal
Purchase and Delivery Contracts
OTP has commitments for the purchase of capacity and energy
requirements under agreements extending into 2041. OTP has
contracts providing for the purchase and delivery of a significant
portion of its current coal requirements. OTP’s current coal purchase
agreements for Big Stone Plant and Coyote Station expire at the end
of 2019 and 2040, respectively. OTP has an agreement with Cloud
Peak Energy Resources LLC for the purchase of subbituminous coal
for Hoot Lake Plant through December 31, 2023. OTP has no fixed
minimum purchase requirements under the agreement, but all of
Hoot Lake Plant’s coal requirements for the period covered must be
purchased under this agreement. The dollar amounts of OTP’s
estimated purchase requirements under this agreement are excluded
from the table below because OTP has not committed to any minimum
level of purchases under the agreement. Fuel clause adjustment
mechanisms lessen the risk of loss from market price changes because
they currently provide for recovery of most fuel costs. See table below
for schedule of commitments.

Operating Leases
OTP has obligations to make future operating lease payments primarily
related to land leases and coal rail-car leases. The Company’s nonelectric
companies have obligations to make future operating lease payments
primarily related to leases of buildings and manufacturing equipment.
Rent expense from continuing operations was $7,110,000, $7,565,000
and $6,447,000 for 2017, 2016 and 2015, respectively.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

The amounts of the Company’s construction program and other commitments and commitments under capacity and energy agreements, coal and

coal delivery contracts and operating leases for continuing operations as of December 31, 2017, are as follows:

(in thousands)

2018
2019
2020
2021
2022
Beyond 2022

Total

Construction
Program and Other
Commitments

Capacity
and Energy
Requirements

Coal
Purchase
Commitments

29,218
15,159
1,680
1,680
—
—

24,424
24,925
24,844
12,988
11,827
154,310

26,021
23,016
22,102
22,537
22,300
527,520

OTP

1,838
1,435
1,436
1,241
761
8,644

Operating Leases
Nonelectric

4,175
4,183
3,362
1,434
1,439
4,326

Total

6,013
5,618
4,798
2,675
2,200
12,970

47,737

$ 253,318

$ 643,496

15,355

18,919

34,274

Contingencies
OTP had a $2.7 million refund liability on its balance sheet as of
December 31, 2016 representing its best estimate of the refund
obligations that would arise, net of amounts that would be subject to
recovery under state jurisdictional TCR riders, based on the likelihood
of the FERC reducing the ROE component of the MISO Tariff and
ordering MISO to refund amounts charged in excess of the lower rate.
In the February and June 2017 MISO billings, MISO processed the
refund of the FERC-ordered reduction in the MISO Tariff allowed ROE
for the first 15-month refund period. The refund, in combination with
a decision in the 2016 Minnesota general rate case that affected the
Minnesota TCR rider, resulted in a reduction in OTP’s accrued MISO
Tariff ROE refund liability from $2.7 million as of December 31, 2016
to $1.6 million as of December 31, 2017.

Together with as many as 200 utilities, generators and power

marketers, OTP participated in proceedings before the FERC regarding
the calculation, assessment and implementation of MISO Revenue
Sufficiency Guarantee (RSG) charges for entities participating in the
MISO wholesale energy market since that market’s start on April 1,
2005 until the conclusion of the proceedings on May 2, 2015. The
proceedings fundamentally concerned MISO’s application of its MISO
RSG rate on file with the FERC to market participants, revisions to the
RSG rate based on several FERC orders, and the FERC’s decision to
not resettle the markets based on MISO application of the RSG rate to
market participants. Several of the FERC’s orders are on review in a
set of consolidated cases before the D.C. Circuit. The consolidated
petitions at the D.C. Circuit involve multiple petitioners and intervenors.
OTP is an intervenor in these cases. Final briefs were filed on January 26,
2018. Oral arguments will occur in the spring of 2018. A final decision
is not expected until late in 2018. MISO has not made available past
billing or resettlement data necessary for determining amounts that
might be payable if the FERC’s decisions are reversed. Therefore, the
Company cannot estimate OTP’s exposure at this time from a final
order reversing the relevant FERC orders, which could have an adverse
effect on the Company’s results of operations.

Contingencies, by their nature, relate to uncertainties that require
the Company’s management to exercise judgment both in assessing
the likelihood a liability has been incurred as well as in estimating the
amount of potential loss. The most significant contingencies impacting
the Company’s consolidated financial statements are those related to
environmental remediation, risks associated with indemnification
obligations under divestitures of discontinued operations and litigation
matters. Should all of these known items result in liabilities being
incurred, the loss could be as high as $1.0 million, excluding any liability
for RSG charges for which an estimate cannot be made at this time.

In 2014 the Environmental Protection Agency (EPA) published both
proposed standards of performance for carbon dioxide (CO2) emissions
from new, reconstructed and modified fossil fuel-fired power plants

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

(New Source Performance Standards), and proposed CO2 emission
guidelines for existing fossil fuel-fired power plants (the Clean Power
Plan) under section 111 of the Clean Air Act. The EPA published final
rules for each of these proposals on October 23, 2015. Both rules were
challenged on legal grounds. On February 9, 2016 the U.S. Supreme
Court granted a stay of the Clean Power Plan, pending disposition of
petitions for review in the D.C. Circuit. The D.C. Circuit heard oral
argument on challenges to the Clean Power Plan on September 27,
2016 before the full court, and a decision was expected in the first half
of 2017. However, pursuant to Executive Order 13783, Promoting Energy
Independence and Economic Growth, the EPA was directed to consider
suspending, revising or rescinding the CO2 rules discussed above.
Thereafter, the EPA issued notices in the Federal Register of its intent
to review these rules pursuant to the Executive Order, and it filed
motions to stay the pending litigation. The D.C. Circuit subsequently
issued orders holding in abeyance the appeals of both the New Source
Performance Standards and the Clean Power Plan, pending EPA
review. On October 16, 2017 the EPA published a proposed rule to
rescind the Clean Power Plan. Therefore, there is uncertainty regarding
the future of both rules.

Other
The Company is a party to litigation and regulatory enforcement matters
arising in the normal course of business. The Company regularly
analyzes current information and, as necessary, provides accruals for
liabilities that are probable of occurring and that can be reasonably
estimated. The Company believes the effect on its consolidated results
of operations, financial position and cash flows, if any, for the disposition
of all matters pending as of December 31, 2017 will not be material.

9. Short-Term and Long-Term Borrowings

SHORT-TERM DEBT
The following table presents the status of the Company’s lines of
credit as of December 31, 2017 and December 31, 2016:

Restricted
due to

Line December 31,
Limit
2017

In Use on Outstanding Available on Available on
Letters December 31, December 31,
2016
2017

of Credit

$ 130,000

— $

— $ 130,000

$ 130,000

(in thousands)

Otter Tail

Corporation
Credit
Agreement

OTP Credit

Agreement

170,000

112,371

Total

$ 300,000

$ 112,371

300

57,329

127,067

$ 187,329

$ 257,067

Under the Otter Tail Corporation Credit Agreement (as defined below),
the maximum amount of debt outstanding in 2017 was $15,169,000 on
April 3, 2017 and the average daily balance of debt outstanding during
2017 was $2,305,000. The weighted average interest rate paid on debt
outstanding under the Otter Tail Corporation Credit Agreement during
2017 was 2.8% compared with 2.3% in 2016. Under the OTP Credit
Agreement (as defined below), the maximum amount of debt
outstanding in 2017 was $112,371,000 on December 29, 2017 and
the average daily balance of debt outstanding during 2017 was
$69,391,000. The weighted average interest rate paid on debt
outstanding under the OTP Credit Agreement during 2017 was 2.4%
compared with 1.8% in 2016. The maximum amount of consolidated
short-term debt outstanding in 2017 was $112,371,000 on December 29,
2017 and the average daily balance of consolidated short-term debt
outstanding during 2017 was $71,696,000. The weighted average
interest rate on consolidated short-term debt outstanding on
December 31, 2017 was 2.7%.

On October 29, 2012 the Company entered into a Third Amended

and Restated Credit Agreement (the Otter Tail Corporation Credit
Agreement), which is an unsecured $130 million revolving credit facility
that may be increased to $250 million on the terms and subject to the
conditions described in the Otter Tail Corporation Credit Agreement.
On October 31, 2017 the Otter Tail Corporation Credit Agreement was
amended to extend its expiration date by one year from October 29,
2021 to October 31, 2022. The Company can draw on this credit facility
to refinance certain indebtedness and support its operations and the
operations of its subsidiaries. Borrowings under the Otter Tail
Corporation Credit Agreement bear interest at LIBOR plus 1.50%,
subject to adjustment based on the Company’s senior unsecured
credit ratings or the issuer rating if a rating is not provided for the
senior unsecured credit. The Company is required to pay commitment
fees based on the average daily unused amount available to be drawn
under the revolving credit facility. The Otter Tail Corporation Credit
Agreement contains a number of restrictions on the Company and the
businesses of its wholly owned subsidiary, Varistar and its subsidiaries,
including restrictions on the Company’s and Varistar’s ability to merge,
sell assets, make investments, create or incur liens on assets, guarantee
the obligations of certain other parties and engage in transactions
with related parties. The Otter Tail Corporation Credit Agreement also
contains affirmative covenants and events of default, and financial
covenants as described below under the heading “Financial Covenants.”
The Otter Tail Corporation Credit Agreement does not include provisions
for the termination of the agreement or the acceleration of repayment
of amounts outstanding due to changes in the Company’s credit ratings.
The Company’s obligations under the Otter Tail Corporation Credit
Agreement are guaranteed by certain of the Company’s subsidiaries.
Outstanding letters of credit issued by the Company under the Otter
Tail Corporation Credit Agreement can reduce the amount available
for borrowing under the line by up to $40 million.

On October 29, 2012 OTP entered into a Second Amended and

Restated Credit Agreement (the OTP Credit Agreement), providing for
an unsecured $170 million revolving credit facility that may be increased
to $250 million on the terms and subject to the conditions described
in the OTP Credit Agreement. On October 31, 2017 the OTP Credit
Agreement was amended to extend its expiration date by one year
from October 29, 2021 to October 31, 2022. OTP can draw on this credit
facility to support the working capital needs and other capital
requirements of its operations, including letters of credit in an aggregate
amount not to exceed $50 million outstanding at any time. Borrowings
under this line of credit bear interest at LIBOR plus 1.25%, subject to
adjustment based on the ratings of OTP’s senior unsecured debt or
the issuer rating if a rating is not provided for the senior unsecured

debt. OTP is required to pay commitment fees based on the average
daily unused amount available to be drawn under the revolving credit
facility. The OTP Credit Agreement contains a number of restrictions on
the business of OTP, including restrictions on its ability to merge, sell
assets, make investments, create or incur liens on assets, guarantee
the obligations of any other party, and engage in transactions with
related parties. The OTP Credit Agreement also contains affirmative
covenants and events of default, and financial covenants as described
below under the heading “Financial Covenants.” The OTP Credit
Agreement does not include provisions for the termination of the
agreement or the acceleration of repayment of amounts outstanding
due to changes in OTP’s credit ratings. OTP’s obligations under the OTP
Credit Agreement are not guaranteed by any other party.

LONG-TERM DEBT ISSUANCES AND RETIREMENTS
2018 Note Purchase Agreement
On November 14, 2017, OTP entered into a Note Purchase Agreement
(the 2018 Note Purchase Agreement) with the purchasers named
therein, pursuant to which OTP agreed to issue to the purchasers, in a
private placement transaction, $100 million aggregate principal amount
of OTP’s 4.07% Series 2018A Senior Unsecured Notes due February 7,
2048 (the 2018 Notes). The 2018 Notes were issued on February 7,
2018. Proceeds from the 2018 Notes were used to repay $100 million
in outstanding borrowings under the OTP Credit Agreement.

OTP may prepay all or any part of the Notes (in an amount not
less than 10% of the aggregate principal amount of the Notes then
outstanding in the case of a partial prepayment) at 100% of the principal
amount so prepaid, together with unpaid accrued interest and a
make-whole amount; provided that if no default or event of default
exists under the Note Purchase Agreement, any prepayment made by
OTP of all of the Notes then outstanding on or after August 7, 2047
will be made without any make-whole amount. The 2018 Note Purchase
Agreement also requires OTP to offer to prepay all outstanding Notes
at 100% of the principal amount together with unpaid accrued interest
in the event of a Change of Control (as defined in the 2018 Note
Purchase Agreement) of OTP.

The 2018 Note Purchase Agreement contains a number of restrictions
on the business of OTP. These include restrictions on OTP’s abilities to
merge, sell assets, create or incur liens on assets, guarantee the
obligations of any other party, and engage in transactions with related
parties. The 2018 Note Purchase Agreement also contains other
negative covenants and events of default, as well as certain financial
covenants as described below under the heading “Financial Covenants.”
The 2018 Note Purchase Agreement does not include provisions for
the termination of the agreement or the acceleration of repayment of
amounts outstanding due to changes in OTP’s credit ratings. The 2018
Note Purchase Agreement includes a “most favored lender” provision
generally requiring that in the event the OTP Credit Agreement or any
renewal, extension or replacement thereof, at any time contains any
financial covenant or other provision providing for limitations on
interest expense and such a covenant is not contained in the 2018 Note
Purchase Agreement under substantially similar terms or would be
more beneficial to the holders of the 2018 Notes than any analogous
provision contained in the 2018 Note Purchase Agreement (Additional
Covenant), then unless waived by the Required Holders (as defined in
the 2018 Note Purchase Agreement), the Additional Covenant will be
deemed to be incorporated into the 2018 Note Purchase Agreement.
The 2018 Note Purchase Agreement also provides for the amendment,
modification or deletion of an Additional Covenant if such Additional
Covenant is amended or modified under or deleted from the OTP
Credit Agreement, provided that no default or event of default has
occurred and is continuing.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

2016 Note Purchase Agreement
On September 23, 2016 the Company entered into a Note Purchase
Agreement (the 2016 Note Purchase Agreement) with the purchasers
named therein, pursuant to which the Company agreed to issue to the
purchasers, in a private placement transaction, $80 million aggregate
principal amount of its 3.55% Guaranteed Senior Notes due December 15,
2026 (the 2026 Notes). The 2026 Notes were issued on December 13,
2016. The Company’s obligations under the 2016 Note Purchase
Agreement and the 2026 Notes are guaranteed by its Material
Subsidiaries (as defined in the 2016 Note Purchase Agreement, but
specifically excluding OTP). The proceeds from the issuance of the
2026 Notes were used to repay the remaining $52,330,000 of the
Company’s 9.000% Senior Notes due December 15, 2016, and to pay
down a portion of the $50 million in funds borrowed in February 2016
under the Company’s term loan agreement.

The Company may prepay all or any part of the 2026 Notes (in an

amount not less than 10% of the aggregate principal amount of the
2026 Notes then outstanding in the case of a partial prepayment) at
100% of the principal amount prepaid, together with unpaid accrued
interest and a make-whole amount; provided that if no default or
event of default exists under the 2016 Note Purchase Agreement, any
optional prepayment made by the Company of all of the 2026 Notes
on or after September 15, 2026 will be made without any make-whole
amount. The Company is required to offer to prepay all of the
outstanding 2026 Notes at 100% of the principal amount together
with unpaid accrued interest in the event of a Change of Control (as
defined in the 2016 Note Purchase Agreement) of the Company. In
addition, if the Company and its Material Subsidiaries sell a “substantial
part” of its or their assets and use the proceeds to prepay or retire
senior Interest-bearing Debt (as defined in the 2016 Note Purchase
Agreement) of the Company and/or a Material Subsidiary in accordance
with the terms of the 2016 Note Purchase Agreement, the Company is
required to offer to prepay a Ratable Portion (as defined in the 2016
Note Purchase Agreement) of the 2026 Notes held by each holder of
the 2026 Notes.

The 2016 Note Purchase Agreement contains a number of restrictions

on the business of the Company and the Material Subsidiaries that
became effective on execution of the 2016 Note Purchase Agreement.
These include restrictions on the Company’s and the Material
Subsidiaries’ abilities to merge, sell assets, create or incur liens on
assets, guarantee the obligations of any other party, engage in
transactions with related parties, redeem or pay dividends on the
Company’s and the Material Subsidiaries’ shares of capital stock, and
make investments. The 2016 Note Purchase Agreement also contains
other negative covenants and events of default, as well as certain
financial covenants as described below under the heading “Financial
Covenants.” The 2016 Note Purchase Agreement does not include
provisions for the termination of the agreement or the acceleration of
repayment of amounts outstanding due to changes in the Company’s
or the Material Subsidiaries’ credit ratings.

2013 Note Purchase Agreement
On August 14, 2013 OTP entered into a Note Purchase Agreement (the
2013 Note Purchase Agreement) with the purchasers named therein
pursuant to which OTP agreed to issue to the purchasers, in a private
placement transaction, $60 million aggregate principal amount of
OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029
(the Series A Notes) and $90 million aggregate principal amount of
OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044
(the Series B Notes and, together with the Series A Notes, the Notes).
The Notes were issued on February 27, 2014.

The 2013 Note Purchase Agreement states that OTP may prepay all or
any part of the Notes (in an amount not less than 10% of the aggregate
principal amount of the Notes then outstanding in the case of a partial
prepayment) at 100% of the principal amount prepaid, together with
accrued interest and a make-whole amount, provided that if no default
or event of default under the 2013 Note Purchase Agreement exists,
any optional prepayment made by OTP of (i) all of the Series A Notes
then outstanding on or after November 27, 2028 or (ii) all of the Series B
Notes then outstanding on or after November 27, 2043, will be made
at 100% of the principal prepaid but without any make-whole amount.
In addition, the 2013 Note Purchase Agreement states OTP must offer
to prepay all of the outstanding Notes at 100% of the principal amount
together with unpaid accrued interest in the event of a Change of
Control (as defined in the 2013 Note Purchase Agreement) of OTP.

The 2013 Note Purchase Agreement contains a number of restrictions
on the business of OTP, including restrictions on OTP’s ability to merge,
sell assets, create or incur liens on assets, guarantee the obligations of
any other party, and engage in transactions with related parties. The
2013 Note Purchase Agreement also contains affirmative covenants
and events of default, as well as certain financial covenants as described
below under the heading “Financial Covenants.” The 2013 Note Purchase
Agreement does not include provisions for the termination of the
agreement or the acceleration of repayment of amounts outstanding
due to changes in OTP’s credit ratings. The 2013 Note Purchase
Agreement includes a “most favored lender” provision generally
requiring that in the event the OTP Credit Agreement or any renewal,
extension or replacement thereof, at any time contains any financial
covenant or other provision providing for limitations on interest
expense and such a covenant is not contained in the 2013 Note
Purchase Agreement under substantially similar terms or would be
more beneficial to the holders of the Notes than any analogous
provision contained in the 2013 Note Purchase Agreement (Additional
Covenant), then unless waived by the Required Holders (as defined in
the 2013 Note Purchase Agreement), the Additional Covenant will be
deemed to be incorporated into the 2013 Note Purchase Agreement.
The 2013 Note Purchase Agreement also provides for the amendment,
modification or deletion of an Additional Covenant if such Additional
Covenant is amended or modified under or deleted from the OTP
Credit Agreement, provided that no default or event of default has
occurred and is continuing.

Term Loan Agreement
On February 5, 2016 the Company borrowed $50 million under an
unsecured Term Loan Agreement (the Term Loan Agreement) at an
interest rate based on the 30 day LIBOR plus 90 basis points. The
proceeds from the Term Loan Agreement were used to pay down
borrowings under the Otter Tail Corporation Credit Agreement that
were used to fund the expansion of BTD’s Minnesota facilities in 2015
and to fund the September 1, 2015 acquisition of BTD-Georgia. The
Company repaid $35 million of the $50 million in the fourth quarter of
2016 and repaid the remaining $15 million during 2017. The Term Loan
Agreement terminated on February 5, 2018.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

pursuant to a Note Purchase Agreement dated as of August 20, 2007
(the 2007 Note Purchase Agreement). On August 21, 2017 OTP used
borrowings under the OTP Credit Agreement to retire the $33 million
5.95%, Series A Senior Unsecured Notes, which had been issued under
the 2007 Note Purchase Agreement and matured on August 20, 2017.
The 2011 Note Purchase Agreement and the 2007 Note Purchase
Agreement each states that OTP may prepay all or any part of the notes
issued thereunder (in an amount not less than 10% of the aggregate
principal amount of the notes then outstanding in the case of a partial
prepayment) at 100% of the principal amount prepaid, together with
accrued interest and a make-whole amount. The 2011 Note Purchase
Agreement states in the event of a transfer of utility assets put event,
the noteholders thereunder have the right to require OTP to repurchase
the notes held by them in full, together with accrued interest and a
make-whole amount, on the terms and conditions specified in the 2011
Note Purchase Agreement. The 2011 Note Purchase Agreement and
the 2007 Note Purchase Agreement each also states that OTP must
offer to prepay all of the outstanding notes issued thereunder at 100%

of the principal amount together with unpaid accrued interest in the
event of a change of control of OTP. The note purchase agreements
contain a number of restrictions on OTP, including restrictions on OTP’s
ability to merge, sell assets, create or incur liens on assets, guarantee
the obligations of any other party, and engage in transactions with
related parties. The note purchase agreements also include affirmative
covenants and events of default, and certain financial covenants as
described below under the heading “Financial Covenants.”

Shelf Registration
On May 11, 2015 the Company filed a shelf registration statement with
the SEC under which the Company may offer for sale, from time to
time, either separately or together in any combination, equity, debt or
other securities described in the shelf registration statement, which
expires on May 11, 2018.

The following tables provide a breakdown of the assignment of the
Company’s consolidated short-term and long-term debt outstanding
as of December 31, 2017 and December 31, 2016:

December 31, 2017 (in thousands)

Short-Term Debt

Long-Term Debt:

Term Loan, LIBOR plus 0.90%, due February 5, 2018
3.55% Guaranteed Senior Notes, due December 15, 2026
Senior Unsecured Notes 4.63%, due December 1, 2021
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
North Dakota Development Note, 3.95%, due April 1, 2018
PACE Note, 2.54%, due March 18, 2021

Total

Less: Current Maturities net of Unamortized Debt Issuance Costs

Unamortized Long-Term Debt Issuance Costs

Total Long-Term Debt net of Unamortized Debt Issuance Costs

Total Short-Term and Long-Term Debt (with current maturities)

December 31, 2016 (in thousands)

Short-Term Debt

Long-Term Debt:

Term Loan, LIBOR plus 0.90%, due February 5, 2018
3.55% Guaranteed Senior Notes, due December 15, 2026
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Senior Unsecured Notes 4.63%, due December 1, 2021
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
North Dakota Development Note, 3.95%, due April 1, 2018
PACE Note, 2.54%, due March 18, 2021

Total

Less: Current Maturities net of Unamortized Debt Issuance Costs

Unamortized Long-Term Debt Issuance Costs

Total Long-Term Debt net of Unamortized Debt Issuance Costs

Total Short-Term and Long-Term Debt (with current maturities)

OTP

$ 112,371

$ 140,000
30,000
42,000
60,000
50,000
90,000

$ 412,000
—
1,684

$ 410,316

$ 522,687

OTP

42,883

33,000
140,000
30,000
42,000
60,000
50,000
90,000

$ 445,000
32,970
1,861

$ 410,169

$ 486,022

Otter Tail
Corporation

Otter Tail
Corporation
Consolidated

—

$ 112,371

—
80,000

27
684

80,711
186
461

80,064

80,250

—
80,000
140,000
30,000
42,000
60,000
50,000
90,000
27
684

$ 492,711
186
2,145

$ 490,380

$ 602,937

Otter Tail
Corporation

Otter Tail
Corporation
Consolidated

—

15,000
80,000

106
836

95,942
231
539

95,172

95,403

42,883

15,000
80,000
33,000
140,000
30,000
42,000
60,000
50,000
90,000
106
836

$ 540,942
33,201
2,400

$ 505,341

$ 581,425

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

The aggregate amounts of maturities on bonds outstanding and
other long-term obligations at December 31, 2017 for each of the next
five years are:

(in thousands)

2018

2019

2020

2021

2022

Aggregate Amounts of

Debt Maturities

186 $

172 $

185 $140,167 $ 30,000

Financial Covenants
The Company and OTP were in compliance with the financial
covenants in these debt agreements as of December 31, 2017.

No Credit or Note Purchase Agreement contains any provisions that

would trigger an acceleration of the related debt as a result of
changes in the credit rating levels assigned to the related obligor by
rating agencies.

The Company’s and OTP’s borrowing agreements are subject to

certain financial covenants. Specifically:
— Under the Otter Tail Corporation Credit Agreement and the 2016

Note Purchase Agreement, the Company may not permit the ratio
of its Interest-bearing Debt to Total Capitalization to be greater
than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio
to be less than 1.50 to 1.00 (each measured on a consolidated basis)
as provided in the agreements.

— Under the 2016 Note Purchase Agreement, the Company may not

permit its Priority Indebtedness to exceed 10% of its Total
Capitalization. The Company had no Priority Indebtedness
outstanding as of December 31, 2017.

— Under the OTP Credit Agreement, OTP may not permit the ratio of
its Interest-bearing Debt to Total Capitalization to be greater than
0.60 to 1.00.

— Under the 2007 Note Purchase Agreement and the 2011 Note
Purchase Agreement, OTP may not permit the ratio of its
Consolidated Debt to Total Capitalization to be greater than 0.60 to
1.00 or permit its Interest and Dividend Coverage Ratio to be less
than 1.50 to 1.00, in each case as provided in the related borrowing
agreement, and OTP may not permit its Priority Debt to exceed
20% of its Total Capitalization, as provided in the related agreement.

— Under the 2013 Note Purchase Agreement and the 2018 Note

10. Pension Plan and Other Postretirement Benefits

Pension Plan
The Company’s noncontributory funded pension plan covers
substantially all corporate employees and OTP nonunion employees
hired prior to September 1, 2006, and all union employees of OTP
hired prior to November 1, 2013, excluding Coyote Station employees.
Coyote Station employees hired before January 1, 2009 are covered
under the plan. The plan provides 100% vesting after five vesting years
of service and for retirement compensation at age 65, with reduced
compensation in cases of retirement prior to age 62. The Company
reserves the right to discontinue the plan but no change or
discontinuance may affect the pensions theretofore vested.

The pension plan has a trustee who is responsible for pension

payments to retirees and a separate pension fund manager responsible
for managing the plan’s assets. An independent actuary assists the
Company in performing the necessary actuarial valuations for the plan.

The plan assets consist of common stock and bonds of public

companies, U.S. government securities, cash and cash equivalents and
alternative investments. None of the plan assets are invested in
common stock or debt securities of the Company.

The following table lists components of net periodic pension benefit

cost for the year ended December 31:

(in thousands)

Service Cost–

Benefit Earned During the Period
Interest Cost on Projected Benefit

Obligation

Expected Return on Assets
Amortization of Prior Service Cost:

From Regulatory Asset
From Other Comprehensive Income (1)

Amortization of Net Actuarial Loss:

From Regulatory Asset
From Other Comprehensive Income (1)

2017

2016

2015

5,629

5,518

6,059

14,139
(19,229)

14,195
(19,454)

13,344
(18,383)

120
3

5,090
125

189
5

5,153
127

188
5

6,676
171

Net Periodic Pension Cost (2)

5,877

5,733

8,060

(1) Corporate cost included in Other Nonelectric Expenses.
(2)Allocation of Costs:

2017

2016

2015

Costs included in OTP Capital Expenditures $
Costs included in Electric Operation and

1,142

1,048

1,453

Maintenance Expenses

Costs included in Other Nonelectric Expenses

4,594
141

4,547
138

6,406
201

Weighted average assumptions used to determine net periodic

pension cost for the year ended December 31:

Discount Rate
4.60%
Long-Term Rate of Return on Plan Assets
7.50%
Rate of Increase in Future Compensation Level 3.00%

2017

2016

4.76%
7.75%
3.13%

2015

4.35%
7.75%
3.13%

The following table presents amounts recognized in the consolidated

balance sheets as of December 31:

(in thousands)

Regulatory Assets:

Unrecognized Prior Service Cost
Unrecognized Actuarial Loss

Total Regulatory Assets

Accumulated Other Comprehensive Loss:

Unrecognized Prior Service Cost
Unrecognized Actuarial Loss

Total Accumulated Other Comprehensive Loss

Noncurrent Liability

2017

2016

21
99,360

99,381

9
439

448

67,399

141
98,039

98,180

12
406

418

60,292

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

Funded status as of December 31:

(in thousands)

Accumulated Benefit Obligation

Projected Benefit Obligation
Fair Value of Plan Assets

Funded Status

2017

2016

$ (316,095)

$ (281,414)

$ (352,718)
285,319

$ (314,637)
254,345

(67,399)

$ (60,292)

The following tables provide a reconciliation of the changes in the

fair value of plan assets and the plan’s benefit obligations over the
two-year period ended December 31, 2017:

(in thousands)

2017

2016

Reconciliation of Fair Value of Plan Assets:

Fair Value of Plan Assets at January 1
Actual Return on Plan Assets
Discretionary Company Contributions
Benefit Payments

$ 254,346
44,181
—
(13,208)

$ 233,639
23,794
10,000
(13,088)

Fair Value of Plan Assets at December 31

$ 285,319

$ 254,345

Market-related value of plan assets—The Company’s expected return
on plan assets is determined based on the expected long-term rate of
return on plan assets and the market-related value of plan assets.

The Company bases actuarial determination of pension plan expense

or income on a market-related valuation of assets, which reduces
year-to-year volatility. This market-related valuation calculation
recognizes investment gains or losses over a five-year period from the
year in which they occur. Investment gains or losses for this purpose
are the difference between the expected return calculated using the
market-related value of assets and the actual return based on the
fair value of assets. Since the market-related valuation calculation
recognizes gains or losses over a five-year period, the future value
of the market-related assets will be impacted as previously deferred
gains or losses are recognized.

Measurement Dates:

2017

2016

Estimated Asset Return
Reconciliation of Projected Benefit Obligation:

Projected Benefit Obligation at January 1
Service Cost
Interest Cost
Benefit Payments
Actuarial Loss

Net Periodic Pension Cost
End of Year Benefit Obligations

January 1, 2017
January 1, 2017
projected to
December 31, 2017
December 31, 2017

January 1, 2016
January 1, 2016
projected to
December 31, 2016
December 31, 2016

17.8%

10.1%

Market Value of Assets

$ 314,637
5,629
14,139
(13,208)
31,521

$ 302,740
5,518
14,195
(13,088)
5,272

The estimated amounts of unrecognized net actuarial losses and

prior service costs to be amortized from regulatory assets and
accumulated other comprehensive loss into the net periodic pension
cost in 2018 are:

Projected Benefit Obligation at December 31

$ 352,718

$ 314,637

(in thousands)

Weighted average assumptions used to determine benefit obligations

at December 31:

Discount Rate
Rate of Increase in Future Compensation Level:

All participants—prior to 2017
Participants to Age 39
Participants Age 40 to Age 49
Participants Age 50 and Older

2016

4.60%

3.00%

2017

3.90%

4.50%
3.50%
2.75%

The assumed rate of return on pension fund assets used for the
determination of 2018 net periodic pension cost is 7.50%. The assumed
long-term rate of return on plan assets is based primarily on asset
category studies using historical market return and volatility data with
forward looking estimates based on existing financial market conditions
and forecasts of capital markets. Modest excess return expectations
versus some market indices are incorporated into the return projections
based on the actively managed structure of the investment programs
and their records of achieving such returns historically. The Company
reviews its rate of return on plan asset assumptions annually. The
assumptions are largely based on the asset category rate-of-return
assumptions developed annually with the Company’s pension plan
investment advisors, as well as input from actuaries who work with
the pension plan and benchmarking to peer companies with similar
asset allocation strategies.

Decrease in Regulatory Assets:

Amortization of Unrecognized Prior Service Cost
Amortization of Unrecognized Actuarial Loss

Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost
Amortization of Unrecognized Actuarial Loss

Total Estimated Amortization

2018

16
7,142

—
176

$ 7,334

Cash flows—The Company had no minimum funding requirement as
of December 31, 2017 but made discretionary plan contributions of
$20 million as of February 2018.

The following benefit payments, which reflect expected future
service, as appropriate, are expected to be paid out from plan assets:

(in thousands)

Years

2018

2019

2020

2021

2022

2023-2027

$14,384

$15,022

$15,666

$16,336

$17,041

$93,882

The following objectives guide the investment strategy of the

Company’s pension plan (the Plan):
— The assets of the Plan will be invested in accordance with all

applicable laws in a manner consistent with fiduciary standards
including Employee Retirement Income Security Act standards
(if applicable). Specifically:
• The safeguards and diversity that a prudent investor would adhere

to must be present in the investment program.

• All transactions undertaken on behalf of the Plan must be in the

best interest of plan participants and their beneficiaries.
— The primary objective of the Plan is to provide a source of
retirement income for its participants and beneficiaries.

— The near-term primary financial objective of the Plan is to improve

the funded status of the Plan.

— A secondary financial objective is to minimize pension funding and

expense volatility where possible.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

Permitted Range

Mutual Fund

< 85% PBO >=85% PBO >=90% PBO >=95% PBO >=100% PBO

39%–59% 34%–54%

24%–44%

14%–34%

0%–20%

Emerging Markets Equity Fund
SEI Dynamic Asset Allocation Mutual Fund
Fixed Income Securities Mutual Funds
Cash Management—Money Market Fund

22%–42% 30%–50% 40%–60%

53%–73%

70%–100%

Total Assets

$ 273,999

$ 234,303

The asset allocation strategy developed by the Company’s Retirement

Plans Administration Committee (the Committee) is based on the
current needs of the Plan and the objectives listed above. An asset/
liability review is conducted annually or as often as necessary to assess
the impact of various asset allocations on funded status and other
financial variables. The current needs of the Plan, the overall investment
objectives above, the investment preferences and risk tolerance of the
Committee and the desired degree of diversification suggest the need
for an investment allocation including multiple asset classes.

The asset allocation in the table below contains guideline percentages,
at market value, of the total Plan invested in various asset classes. The
Permitted Range is a guide and will at times not reflect the actual asset
allocation as this will be dictated by market conditions, the independent
actions of the Committee and/or Investment Managers and required
cash flows to and from the Plan. The Permitted Range anticipates this
fluctuation and provides flexibility for the Investment Managers’
portfolios to vary around the target without the need for immediate
rebalancing. The Investment Manager will proactively monitor the
asset allocation and will direct the purchases and sales to remain
within the stated ranges.

The policy of the Plan is to invest assets in accordance with the

allocations shown below:

Asset Class /
PBO Funded
Status

Equity
Investment
Grade Fixed
Income
Below
Investment
Grade Fixed
Income*
Other**

0%–15%
5%–20%

0%–10%
0%–15%

* Includes (but not limited to) High Yield Bond Fund and Emerging Markets Debt funds.
** Other category may include cash, alternatives, and/or other investment strategies
that may be classified other than equity or fixed income, such as the Dynamic Asset
Allocation fund.

The Company’s pension plan asset allocations at December 31, 2017

and 2016, by asset category are as follows:

Asset Allocation

Large Capitalization Equity Securities
International Equity Securities
Small and Mid-Capitalization Equity Securities
Emerging Markets Equity Fund
SEI Dynamic Asset Allocation Fund

Equity Securities

Fixed-Income Securities and Cash
Other—SEI Energy Debt Collective Fund
Other—SEI Special Situation Collective Investment Trust

2017

23.5%
18.1%
8.7%
5.5%
5.0%

60.8%
35.2%
4.0%
0.0%

2016

21.4%
22.0%
9.0%
0.0%
5.4%

57.8%
34.3%
4.1%
3.8%

100.0%

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

The following table presents the Company’s pension fund assets
measured at fair value and included in Level 1 of the fair value hierarchy
and assets measured using the NAV practical expedient to fair valuation
as of December 31:

(in thousands)

Assets in Level 1 of the Fair Value Hierarchy
SEI Energy Debt Collective Fund at NAV
SEI Special Situation Collective Investment

Trust Fund at NAV

Total Assets

2017

2016

$ 273,999
11,320

$ 234,303
10,441

—

9,601

$ 285,319

$ 254,345

Fair Value Measurements of Pension Fund Assets
ASC 715, Compensation—Retirement Benefits, requires disclosures
about pension plan assets identified by the three levels of the fair
value hierarchy established by ASC 820-10-35.

The following table presents, the Company’s pension fund assets
measured at fair value and included in Level 1 of the fair value hierarchy
as of December 31:

(in thousands)

Large Capitalization Equity Securities Mutual Fund
International Equity Securities Mutual Funds
Small and Mid-Capitalization Equity Securities

2017

66,946
51,636

24,848
15,824
14,371
100,373
1

2016

54,483
55,916

23,011
—
13,622
87,268
3

The investments held by the SEI Energy Debt Collective Fund on
December 31, 2017 and 2016 consist mainly of below investment grade
high yielding bonds and loans of U.S. energy companies which trade
at a discount to fair value. Redemptions are allowed semi-annually
with a 95-day notice period, subject to fund director consent and
certain gate, holdback and suspension restrictions. Subscriptions are
allowed monthly with a three-year lock up on subscriptions. The
Company invested $10.0 million in the SEI Energy Debt Fund in July 2015.
The fund’s assets are valued in accordance with valuations reported by
the fund’s sub-advisor or the fund’s underlying investments or other
independent third party sources, although SEI in its discretion may
use other valuation methods, subject to compliance with ERISA
(as applicable). The fund’s assets are valued as of the close of business
on the last business day of each calendar month and are available
30 days after the end of a calendar quarter. On an annual basis, as
determined by the investment manager in its sole discretion, an
independent valuation agent is retained to provide a valuation of
the illiquid assets of the fund and of any other asset of the fund,
as determined by the investment manager in its sole discretion. The
Company reviews and verifies the reasonableness of the year-end
valuations.

Executive Survivor and Supplemental Retirement Plan (ESSRP)
The ESSRP is an unfunded, nonqualified benefit plan for executive
officers and certain key management employees. The ESSRP provides
defined benefit payments to these employees on their retirements for
life or to their beneficiaries on their deaths for a 15-year postretirement
period. Life insurance carried on certain plan participants is payable to
the Company on the employee’s death. There are no plan assets in this
nonqualified benefit plan due to the nature of the plan.

The following table lists components of net periodic pension benefit

Weighted average assumptions used to determine benefit obligations

cost for the year ended December 31:

at December 31:

(in thousands)

2017

2016

2015

Service Cost–Benefit Earned

During the Period

Interest Cost on Projected

Benefit Obligation

Amortization of Prior Service Cost:

From Regulatory Asset
From Other Comprehensive Income (1)

Amortization of Net Actuarial Loss:

From Regulatory Asset
From Other Comprehensive Income (2)

290

252

189

1,686

1,667

1,523

16
38

285
440

16
38

293
446

16
38

334
602

Net Periodic Pension Cost (3)

$ 2,755

$ 2,712

$ 2,702

(1) Amortization of Prior Service Costs from
Other Comprehensive Income Charged to:

Electric Operation and Maintenance Expenses
Other Nonelectric Expenses

(2)Amortization of Net Actuarial Loss from
Other Comprehensive Income Charged to:

Electric Operation and Maintenance Expenses
Other Nonelectric Expenses

(3)ESSRP costs are not capitalized.

15
23

265
175

15
23

272
174

15
23

310
292

Weighted average assumptions used to determine net periodic

pension cost for the year ended December 31:

Discount Rate
4.60%
Rate of Increase in Future Compensation Level 3.00%

2017

2016

4.76%
3.13%

2015

4.35%
3.15%

The following table presents amounts recognized in the consolidated

balance sheets as of December 31:

(in thousands)

Regulatory Assets:

Unrecognized Prior Service Cost
Unrecognized Actuarial Loss

Total Regulatory Assets

Projected Benefit Obligation Liability—

Net Amount Recognized

Accumulated Other Comprehensive Loss:

Unrecognized Prior Service Cost
Unrecognized Actuarial Loss

Total Accumulated Other Comprehensive Loss

2017

2016

40
3,229

3,269

58
2,890

2,948

(42,308)

$ (37,335)

98
9,024

9,122

134
5,915

6,049

The following tables provide a reconciliation of the changes in the
fair value of plan assets and the plan’s projected benefit obligations
over the two-year period ended December 31, 2017 and a statement of
the funded status as of December 31 of both years:

(in thousands)

2017

2016

Reconciliation of Fair Value of Plan Assets:

Fair Value of Plan Assets at January 1
Actual Return on Plan Assets
Employer Contributions
Benefit Payments

Fair Value of Plan Assets at December 31

Reconciliation of Projected Benefit Obligation:

Projected Benefit Obligation at January 1
Service Cost
Interest Cost
Benefit Payments
Plan Amendments
Actuarial Loss

—
—
1,175
(1,175)

—

37,335
290
1,686
(1,175)
—
4,172

—
—
1,188
(1,188)

—

35,811
252
1,667
(1,188)
—
793

Projected Benefit Obligation at December 31

42,308

37,335

Discount Rate
Rate of Increase in Future Compensation Level:

2017

3.85%
2.92%

2016

4.60%
3.00%

The estimated amounts of unrecognized net actuarial losses and

prior service costs to be amortized from regulatory assets and
accumulated other comprehensive loss into the net periodic pension
cost for the ESSRP in 2018 are:

(in thousands)

Decrease in Regulatory Assets:

Amortization of Unrecognized Prior Service Cost
Amortization of Unrecognized Actuarial Loss

Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost
Amortization of Unrecognized Actuarial Loss

Total Estimated Amortization

2018

16
267

38
661

982

Cash flows—The ESSRP is unfunded and has no assets; contributions
are equal to the benefits paid to plan participants. The following
benefit payments, which reflect future service, as appropriate, are
expected to be paid:

(in thousands)

Years

2018

2019

2020

2021

2022

2023-2027

$1,568

$1,612

$1,576

$1,670

$2,255

$13,775

Other Postretirement Benefits
The Company provides a portion of health insurance and life insurance
benefits for retired OTP and corporate employees. Substantially all of
the Company’s electric utility and corporate employees may become
eligible for health insurance benefits if they reach age 55 and have 10
years of service. There are no plan assets. The following table lists
components of net periodic postretirement benefit cost for the year
ended December 31:

(in thousands)

2017

2016

2015

Service Cost–Benefit Earned

During the Period

Interest Cost on Projected Benefit Obligation
Amortization of Prior Service Cost

From Regulatory Asset
From Other Comprehensive Income (1)

Amortization of Net Actuarial Loss

From Regulatory Asset
From Other Comprehensive Income (1)

$ 1,425
2,712

$ 1,301
2,503

$ 1,297
2,097

(4)
4

936
19

134
3

379
9

205
5

—
—

Net Periodic Postretirement Benefit Cost (2) $ 5,092

$ 4,329

$ 3,604

Effect of Medicare Part D Subsidy

$ (561)

$ (923) $ (1,487)

(1) Corporate cost included in Other Nonelectric Expenses
(2)Allocation of Costs:

2017

2016

2015

Costs included in OTP Capital Expenditures
Costs included in Electric Operation and

Maintenance Expenses

Costs included in Other Nonelectric Expenses

989

792

650

3,981
122

3,433
104

2,864
90

Weighted average assumptions used to determine net periodic

postretirement benefit cost for the year ended December 31:

Discount Rate

2017

4.46%

2016

4.57%

2015

4.20%

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

The following table presents amounts recognized in the consolidated

balance sheets as of December 31:

(in thousands)

Regulatory Asset:

Unrecognized Prior Service Cost
Unrecognized Net Actuarial Loss

Net Regulatory Asset

Projected Benefit Obligation Liability—

Net Amount Recognized

Accumulated Other Comprehensive (Income) Loss:

Unrecognized Prior Service Cost
Unrecognized Net Actuarial Gain

Accumulated Other Comprehensive Income

2017

2016

—
18,927

18,927

(4)
13,586

13,582

(69,774)

$ (62,571)

—
(111)

(111)

4
(171)

(167)

The following tables provide a reconciliation of the changes in the
fair value of plan assets and the plan’s projected benefit obligations
and accrued postretirement benefit cost over the two-year period
ended December 31, 2017:

(in thousands)

2017

2016

Reconciliation of Fair Value of Plan Assets:

Fair Value of Plan Assets at January 1
Actual Return on Plan Assets
Company Contributions
Benefit Payments (Net of Medicare Part D Subsidy)
Participant Premium Payments

Fair Value of Plan Assets at December 31

Reconciliation of Projected Benefit Obligation:

Projected Benefit Obligation at January 1
Service Cost (Net of Medicare Part D Subsidy)
Interest Cost (Net of Medicare Part D Subsidy)
Benefit Payments (Net of Medicare Part D Subsidy)
Participant Premium Payments
Actuarial Loss

Projected Benefit Obligation at December 31

Reconciliation of Accrued Postretirement Cost:

Accrued Postretirement Cost at January 1
Expense
Net Company Contribution

—
—
3,290
(6,534)
3,244

—

62,571
1,425
2,712
(6,534)
3,244
6,356

—
—
2,825
(5,908)
3,083

—

48,730
1,301
2,503
(5,908)
3,083
12,862

69,774

62,571

(49,156)
(5,092)
3,290

$ (47,652)
(4,329)
2,825

Accrued Postretirement Cost at December 31

(50,958)

$ (49,156)

Weighted average assumptions used to determine benefit obligations

at December 31:

Discount Rate

2017

3.81%

2016

4.46%

Assumed healthcare cost-trend rates as of December 31:

Healthcare Cost-Trend Rate Assumed for Next Year Pre-65
Healthcare Cost-Trend Rate Assumed for Next Year Post-65
Rate to Which the Cost-Trend Rate is Assumed to Decline
Year the Rate Reaches the Ultimate Trend Rate

2017

2016

5.85% 6.01%
6.03% 6.23%
4.50% 4.50%
2038

2038

Assumed healthcare cost-trend rates have a significant effect on
the amounts reported for healthcare plans. A one-percentage-point
change in assumed healthcare cost-trend rates for 2017 would have
the following effects:

(in thousands)

Effect on the Postretirement Benefit Obligation
Effect on Total of Service and Interest Cost
Effect on Expense

1 Point
Increase

$
$
$

9,301
731
1,589

1 Point
Decrease

$ (7,692)
(601)
$
$ (1,500)

Measurement Dates:

2017

2016

Net Periodic Postretirement Benefit Cost January 1, 2017
End of Year Benefit Obligations
January 1, 2017
projected to

January 1, 2016
January 1, 2016
projected to

December 31, 2017 December 31, 2016

The estimated net amounts of unrecognized prior service cost to be
amortized from regulatory assets and accumulated other comprehensive
loss into the net periodic postretirement benefit cost in 2018 are:

(in thousands)

Decrease in Regulatory Assets:

Amortization of Unrecognized Actuarial Loss

Decrease in Accumulated Other Comprehensive Loss:

Amortization of Unrecognized Actuarial Loss

Total Estimated Amortization

2018

$ 1,649

$ 1,690

Cash flows—The Company expects to contribute $4.0 million net of
expected employee contributions for the payment of retiree medical
benefits and Medicare Part D subsidy receipts in 2018. The Company
expects to receive a Medicare Part D subsidy from the Federal
government of approximately $0.4 million in 2018. The following
benefit payments, which reflect expected future service, as appropriate,
net of expected Medicare Part D subsidy receipts and participant
premium payments, are expected to be paid:

(in thousands)

Years

2018

2019

2020

2021

2022

2023-2027

$3,986

$4,107

$4,133

$4,218

$4,327

$21,089

401K Plan
The Company sponsors a 401K plan for the benefit of all corporate
and subsidiary company employees. Contributions made to these
plans by the Company and its subsidiary companies included in
continuing operations totaled $4,211,000 for 2017, $3,877,000 for 2016
and $3,602,000 for 2015.

Employee Stock Ownership Plan
The Company has a stock ownership plan for the benefit of all its
electric utility employees. Contributions made by the Company were
$612,000 for 2017, $647,000 for 2016 and $674,000 for 2015.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

11. Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair
value of each class of financial instruments for which it is practicable
to estimate that value:

The estimated service lives for rate-regulated properties is 5 to 82
years. For nonelectric property the estimated useful lives are from 3 to
40 years.

Service Life Range (years)

Low

High

Cash Equivalents—The carrying amount approximates fair value
because of the short-term maturity of those instruments.

Short-Term Debt—The carrying amount approximates fair value
because the debt obligations are short-term and the balances
outstanding as of December 31, 2017 and December 31, 2016 related
to the OTP Credit Agreement were subject to a variable interest rate
of LIBOR plus 1.25%, which approximates market rates.

Electric Fixed Assets:
Production Plant
Transmission Plant
Distribution Plant
General Plant

Nonelectric Fixed Assets:

Equipment
Buildings and Leasehold Improvements

13. Income Taxes

9
42
5
5

3
7

82
70
68
50

12
40

Long-Term Debt including Current Maturities—The fair value of the
Company’s and OTP’s long-term debt is estimated based on the
current market indications of rates available to the Company for the
issuance of debt. The Company’s long-term debt subject to variable
interest rates on December 31, 2016 approximated fair value. The fair
value measurements of the Company’s long-term debt issues fall into
level 2 of the fair value hierarchy set forth in ASC 820.

The total income tax expense differs from the amount computed by

applying the federal income tax rate (35% in 2017, 2016 and 2015) to
net income before total income tax expense for the following reasons:

(in thousands)

2017

2016

2015

Tax Computed at Federal Statutory Rate—

Continuing Operations

$ 34,707

$ 28,741

$ 28,081

(in thousands)

December 31, 2017

December 31, 2016

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

Cash and Cash Equivalents $ 16,216
Short-Term Debt
(112,371)
Long-Term Debt including

$ 16,216
(112,371)

— $

(42,883)

—
(42,883)

Current Maturities

(490,566)

(543,691)

(538,542)

(583,835)

12. Property, Plant and Equipment

(in thousands)

December 31, 2017

December 31, 2016

Electric Plant in Service

Production
Transmission
Distribution
General

Electric Plant in Service
Construction Work in Progress

Total Gross Electric Plant
Less Accumulated Depreciation

and Amortization

Net Electric Plant

Nonelectric Operations Plant

Equipment
Buildings and Leasehold Improvements
Land

Nonelectric Operations Plant
Construction Work in Progress

Total Gross Nonelectric Plant
Less Accumulated Depreciation

and Amortization

Net Nonelectric Operations Plant

Net Plant

897,732
500,352
482,867
100,067

1,981,018
132,556

2,113,574

662,431

1,451,143

160,263
52,280
4,394

216,937
8,511

225,448

136,988

88,460

1,539,603

891,330
410,679
466,285
92,063

1,860,357
149,997

2,010,354

622,657

$ 1,387,697

155,809
51,323
4,694

211,826
3,264

215,090

125,562

89,528

$ 1,477,225

Increases (Decreases) in Tax from:

Federal Production Tax Credits (PTCs)
State Income Taxes Net of Federal

Income Tax Expense

Section 199 Domestic Production

Activities Deduction

North Dakota Wind Tax Credit

Amortization—Net of Federal Taxes

Corporate-owned Life Insurance
Excess Tax deduction—Equity Method

Stock Awards

Employee Stock Ownership Plan

Dividend Deduction

Allowance for Funds Used During

Construction—Equity

Investment Tax Credit Amortization
Differences Reversing in Excess of Federal Rates
Permanent and Other Differences
Effect of TCJA Tax Rate Reduction on
Value of Net Deferred Tax Assets

Total Income Tax Expense—

Continuing Operations

Income Tax Expense—

(7,527)

(7,175)

(6,962)

4,341

2,848

4,945

(1,471)

(482)

—

(850)
(845)

(751)

(850)
(680)

(850)
(167)

—

(509)

(537)

(560)

(322)
(164)
551
(1,873)

(280)
(350)
77
(1,231)

(426)
(571)
(1,143)
(705)

1,756

—

$ 27,043

$ 20,081

$ 21,642

Discontinued Operations—U.S.

213

138

2,991

Income Tax Expense—Continuing and

Discontinued Operations

$ 27,256

$ 20,219

$ 24,633

Overall Effective Federal, State and

Foreign Income Tax Rate

Income Tax Expense From Continuing
Operations Includes the Following:

Current Federal Income Taxes
Current State Income Taxes
Deferred Federal Income Taxes
Deferred State Income Taxes
Federal PTCs
North Dakota Wind Tax Credit

27.3%

24.5%

29.3%

4,581
1,154
25,320
4,529
(7,527)

1,070
1,211
23,586
2,589
(7,175)

211
1
23,050
6,763
(6,962)

Amortization—Net of Federal Taxes

Investment Tax Credit Amortization

(850)
(164)

(850)
(350)

(850)
(571)

Total

$ 27,043

$ 20,081

$ 21,642

Total Income Before Income Taxes—

Continuing and Discontinued Operations

$ 99,695

$ 82,540

$ 83,978

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

The Company’s deferred tax assets and liabilities were composed of

the following on December 31:

(in thousands)

Deferred Tax Assets

Federal PTCs
Regulatory Tax Liability
North Dakota Wind Tax Credits
Benefit Liabilities
Retirement Benefits Liabilities
Cost of Removal
Differences Related to Property
Net Operating Loss Carryforward
Vacation Accrual
Investment Tax Credits
Other

Total Deferred Tax Assets

Deferred Tax Liabilities

Differences Related to Property
Retirement Benefits Regulatory Asset
Excess Tax over Book Pension
North Dakota Wind Tax Credits
Impact of State Net Operating Losses

on Federal Taxes

Other

Total Deferred Tax Liabilities

Deferred Income Taxes

2017

2016

40,614
39,465
32,962
32,328
31,894
21,800
6,499
3,203
1,844
515
668

43,433
2,422
32,962
44,381
38,390
31,636
9,876
3,865
2,725
818
5,371

$ 211,792

$ 215,879

$ (257,906)
(31,894)
(14,077)
(4,112)

$ (371,761)
(38,390)
(15,509)
(3,654)

(673)
(3,631)

(1,352)
(11,804)

$ (312,293)

$ (442,470)

$ (100,501)

$ (226,591)

Federal PTCs are earned as wind energy is generated based on a

per kwh rate prescribed in applicable federal statutes. OTP’s kwh
generation from its wind turbines eligible for PTCs increased 4.4% in
2017 compared with 2016. North Dakota wind energy credits are based
on dollars invested in qualifying facilities and are being recognized on
a straight-line basis over 25 years.

Schedule of expiration of tax credits and tax net operating losses

available as of December 31, 2017:

(in thousands)

United States

Amount 2022-2031

2032-37 2038-2043

Federal Tax Credits
State Net Operating Losses
State Tax Credits

$ 43,238
3,203
33,568

— $ 43,238
864
231

2,339
376

—
—
32,961

The following table summarizes the activity related to the Company’s

unrecognized tax benefits:

The balance of unrecognized tax benefits as of December 31, 2017
would reduce the Company’s effective tax rate if recognized. The total
amount of unrecognized tax benefits as of December 31, 2017 is not
expected to change significantly within the next 12 months. The
Company classifies interest and penalties on tax uncertainties as
components of the provision for income taxes in the Company’s
consolidated statement of income. There was no amount accrued for
interest on tax uncertainties as of December 31, 2017.

The Company and its subsidiaries file a consolidated U.S. federal

income tax return and various state income tax returns. As of
December 31, 2017, with limited exceptions, the Company is no longer
subject to examinations by taxing authorities for tax years prior to
2014 for federal and North Dakota state income taxes and for years
prior to 2013 for Minnesota state income taxes.

TCJA
In December 2017 the TCJA was enacted. The TCJA includes a number
of changes to existing U.S. tax laws that impact the Company, most
notably a reduction of the federal corporate income tax rate from
35% to 21% for tax years beginning after December 31, 2017.

The Company measures deferred tax assets and liabilities using
enacted tax rates that will apply in the years in which the temporary
differences are expected to be recovered or paid. Accordingly, the
Company’s deferred tax assets and liabilities were remeasured to
reflect the reduction in the U.S. corporate income tax rate from
35% to 21%. The revaluation for OTP required the creation of a
regulatory liability and an offsetting reduction in deferred tax liability.
This regulatory liability will generally be amortized over the remaining
life of the related assets. On a consolidated financial statement basis,
the revaluation resulted in a one-time, non-cash, income tax expense
of approximately $1.8 million in 2017. The impacts of the TCJA
adjustments to deferred taxes and regulatory liabilities are provided
in the reconciliation below:

(in thousands)

Deferred Tax
Liability

Deferred Tax
Regulatory Liability

Balance on January 1, 2017

$ 226,591

818

Change due to 2017 Accruals
and Amortizations
TCJA Deferred Tax Valuation Adjustment
Tax Effect on TCJA Deferred Tax
Valuation Adjustment
TCJA Adjustment to Income Tax Expense

20,012
(109,072)

(38,786)
1,756

376
109,072

38,786
—

Balance on December 31, 2017

$ 100,501

$ 149,052

(in thousands)

2017

2016

2015

The Company recognized the income tax effects of the TCJA in its

Balance on January 1
Increases Related to Tax Positions

for Prior Years

Decreases Related to Tax Positions

for Prior Years

Increases Related to Tax Positions

for Current Year

Uncertain Positions Resolved During Year

Balance on December 31

891

468

222

(378)

143
—

684

406

—

114
(97)

236

—

10
—

891

468

2017 consolidated financial statements in accordance with Staff
Accounting Bulletin No. 118, which provides SEC staff guidance for the
application of ASC Topic 740, Income Taxes, in the reporting period in
which the TCJA was signed into law. Current estimates may be revised
and are subject to change due, in part, to complexities and uncertainties
associated with the TCJA. While the Company is able to make
reasonable estimates of the impact of the TCJA for the reduction in
the federal corporate tax rate, changes to bonus depreciation and
consequences on the Company’s regulatory liabilities, the final impact
of the TCJA may differ from these estimates due to, among other
things, changes in the Company’s interpretations and assumptions
and additional guidance that may be issued by the U.S. Internal
Revenue Service, rate regulators or the FASB.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

14. Asset Retirement Obligations (AROs)

15. Discontinued Operations

On April 30, 2015 the Company sold Foley for $12.0 million in cash,
plus $6.3 million in adjustments for working capital and other related
items received in October 2015, less $1.0 million in selling expenses.
On February 28, 2015 the Company sold the assets of AEV, Inc. for
$22.3 million in cash, plus $0.6 million in adjustments for working
capital and fixed assets received in October 2015, less $0.8 million in
selling expenses. Foley and AEV, Inc. were formerly included in the
Company’s Construction segment.

On February 8, 2013 the Company completed the sale of

substantially all the assets of its dock and boatlift company, formerly
included in the Company’s Manufacturing segment. On November 30,
2012 the Company completed the sale of the assets of the Company’s
wind tower manufacturing business. This business was the only
remaining entity in the Company’s former Wind Energy segment.
The Company’s Wind Energy and Construction segments were
eliminated as a result of the sales of its wind tower manufacturing
business, Foley and AEV, Inc. The financial position, results of operations
and cash flows of Foley, AEV, Inc., the Company’s wind tower
manufacturing business and its dock and boatlift company are
reported as discontinued operations in the Company’s consolidated
financial statements.

The Company’s AROs are related to OTP’s coal-fired generation plants
and its 92 wind turbines located in North Dakota. The AROs include
items such as site restoration, closure of ash pits, and removal of certain
structures, generators, asbestos and storage tanks. The Company has
legal obligations associated with the retirement of a variety of other
long-lived tangible assets used in electric operations where the
estimated settlement costs are individually and collectively immaterial.
The Company has no assets legally restricted for the settlement of any
of its AROs.

OTP recorded no new AROs in 2017.
Reconciliations of carrying amounts of the present value of the
Company’s legal AROs, capitalized asset retirement costs and related
accumulated depreciation and a summary of settlement activity for
the years ended December 31, 2017 and 2016 are presented in the
following table:

(in thousands)

Asset Retirement Obligations

Beginning Balance
New Obligations Recognized
Adjustments Due to Revisions in Cash Flow Estimates
Accrued Accretion
Settlements

Ending Balance

Asset Retirement Costs Capitalized

Beginning Balance
New Obligations Recognized
Adjustments Due to Revisions in Cash Flow Estimates
Settlements

Ending Balance

Accumulated Depreciation—

Asset Retirement Costs Capitalized

Beginning Balance
New Obligations Recognized
Adjustments Due to Revisions in Cash Flow Estimates
Depreciation Expense
Settlements

Ending Balance

Settlements

Original Capitalized Asset Retirement Cost—Retired
Accumulated Depreciation
Asset Retirement Obligation
Settlement Cost

Gain on Settlement—

Deferred Under Regulatory Accounting

2017

2016

$ 8,341
—
—
378
—

$ 8,719

$ 2,983
—
—
—

$ 2,983

795
—
—
120
—

915

None
—
—
—
—

—

$ 8,084
—
(103)
360
—

$ 8,341

$ 3,086
—
(103)
—

$ 2,983

673
—
—
122
—

795

None
—
—
—
—

—

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

Following are summary presentations of the results of discontinued operations for the years ended December 31, 2017, 2016 and 2015:

For the Year Ended December 31, 2017

(in thousands)

Operating Expenses
Income Tax (Benefit) Expense

Net (Loss) Income

For the Year Ended December 31, 2016

(in thousands)

Operating Expenses
Income Tax (Benefit) Expense

Net (Loss) Income

For the Year Ended December 31, 2015

(in thousands)

Operating Revenues
Operating Expenses
Asset Impairment Charge
Interest Expense
Other Income (Deductions)
Income Tax (Benefit) Expense

Net (Loss) Income from Operations

(Loss) Gain on Disposition Before Taxes
Income Tax (Benefit) Expense on Disposition

Net Gain on Disposition

Net (Loss) Income

Foley

AEV, Inc.

233
(93)

(140)

—
—

—

Foley

AEV, Inc.

250
(136)

(114)

—
5

(5)

Wind
Tower
Business

(460)
184

276

Wind
Tower
Business

(757)
303

454

Dock and Intercompany
Boatlift Transactions
Adjustment

Business

(306)
122

184

—
—

—

Dock and Intercompany
Boatlift Transactions
Adjustment

Business

85
(34)

(51)

—
—

—

Foley

AEV, Inc.

$ 21,625
26,839
1,000
177
(42)
(921)

(5,512)

(204)
(227)

2,998
4,532
—
27
2
(638)

(921)

11,894
4,757

7,137

Wind
Tower
Business

Dock and Intercompany
Boatlift Transactions
Adjustment

Business

—
(462)
—
—
111
229

344

—
—

—

—
966
—
—
—
(386)

(580)

—
—

—

—
(240)
—
(204)
(2)
177

265

—
—

—

Total

(533)
213

320

Total

(422)
138

284

Total

$ 24,623
31,635
1,000
—
69
(1,539)

(6,404)

11,690
4,530

7,160

$ (5,489)

6,216

344

(580)

265

756

Foley and AEV, Inc. entered into fixed-price construction contracts.
Revenues under these contracts were recognized on a percentage-of-
completion basis. The method used to determine the progress of
completion was based on the ratio of costs incurred to total estimated
costs on construction projects. An increase in estimated costs on one
large job in progress at Foley in excess of previous period cost estimates
resulted in pretax charges of $4.4 million in 2015. In the first quarter of
2015, Foley recorded a $1.0 million goodwill impairment charge based
on adjustments to the carrying value of Foley.

Following are summary presentations of the major components of
assets and liabilities of discontinued operations as of December 31, 2017
and December 31, 2016:

December 31, 2017

(in thousands)

Current Liabilities

Liabilities of Discontinued

Operations

December 31, 2016

(in thousands)

Current Liabilities

Liabilities of Discontinued

Operations

Wind
Tower
Business

130

Wind
Tower
Business

589

Dock and
Boatlift
Business

362

Dock and
Boatlift
Business

774

Total

492

Total

$ 1,363

Included in current liabilities of discontinued operations are warranty

reserves. Details regarding the warranty reserves follow:

(in thousands)

Warranty Reserve Balance, January 1
Additional Provision for Warranties

Made During the Year

Settlements Made During the Year
Decrease in Warranty Estimates for Prior Years

2017

2016

1,369

2,103

—
(112)
(760)

—
(24)
(710)

Warranty Reserve Balance, December 31

497

1,369

The warranty reserve balances as of December 31, 2017 relate
entirely to products produced by the Company’s former wind tower
and dock and boatlift manufacturing companies. Certain products
sold by the companies carried one to fifteen year warranties. Although
the assets of these companies have been sold and their operating
results are reported under discontinued operations in the Company’s
consolidated statements of income, the Company retains responsibility
for warranty claims related to the products they produced prior to the
sales of these companies.

Expenses associated with remediation activities of these companies
could be substantial. For wind towers, the potential exists for multiple
claims based on one defect repeated throughout the production
process or for claims where the cost to repair or replace the defective
part is highly disproportionate to the original cost of the part. For
example, if the Company is required to cover remediation expenses in
addition to regular warranty coverage, the Company could be required
to accrue additional expenses and experience additional unplanned
cash expenditures which could adversely affect the Company’s
consolidated net income and financial condition.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

16. Subsequent Events

Stock Incentive Awards
On February 5, 2018 the following stock incentive awards were
granted to officers under the 2014 Incentive Plan:

Award

Restricted Stock
Units Granted

Stock Performance
Awards Granted

Weighted Average
Grant-Date
Fair Value
per Award

Shares/Units
Granted

Vesting

15,200

54,000

41.325 25% per year through
February 6, 2022

35.73

December 31, 2020

The vesting of restricted stock units is accelerated in the event of a
change in control, disability, death or retirement, subject to proration
in certain cases. All restricted stock units granted to executive officers
are eligible to receive dividend equivalent payments on all unvested
awards over the awards respective vesting periods, subject to forfeiture
under the terms of the restricted stock unit award agreements. The
grant-date fair value of each restricted stock unit was the average of
the high and low market price per share on the date of grant.

Under the performance share awards the aggregate award for
performance at target is 54,000 shares. For target performance the
participants would earn an aggregate of 27,000 common shares for
achieving the target set for the Company’s 3-year average adjusted
return on equity. The participants would also earn an aggregate of
27,000 common shares based on the Company’s total shareholder

return relative to the total shareholder return of the companies that
comprise the EEI Index over the performance measurement period of
January 1, 2018 through December 31, 2020, with the beginning and
ending share values based on the average closing price of a share of
the Company’s common stock for the 20 trading days immediately
following January 1, 2018 and the average closing price for the
20 trading days immediately preceding January 1, 2021. Actual
payment may range from zero to 150% of the target amount, or up to
81,000 common shares. There are no voting or dividend rights related
to these shares until the shares, if any, are issued at the end of the
performance measurement period. The terms of these awards are
such that the entire award will be classified and accounted for as
equity, as required under ASC 718, and will be measured over the
performance period based on the grant-date fair value of the award.
The grant-date fair value of each performance share award was
determined using a Monte Carlo fair valuation simulation model.

Under the 2018 Performance Award Agreements, payment and the

amount of payment in the event of retirement, resignation for good
reason or involuntary termination without cause is to be made at the
end of the performance period based on actual performance, subject
to proration in certain cases, except that the payment of performance
awards granted to an officer who is a party to an Executive
Employment Agreement with the Company is to be made at
target at the date of any such event.

The end of the period over which compensation expense is
recognized for the above share-based awards for the individual
grantees is the shorter of the indicated vesting period for the
respective awards or the date the grantee becomes eligible for
retirement as defined in their award agreement.

SUPPLEMENTARY FINANCIAL INFORMATION

QUARTERLY INFORMATION (NOT AUDITED)
Because of changes in the number of common shares outstanding and the impact of diluted shares, the sum of the quarterly earnings per
common share may not equal total earnings per common share.

Three Months Ended

(in thousands, except per share data)

Operating Revenues—Continuing Operations
Operating Income—Continuing Operations
Net Income (Loss):

Continuing Operations
Discontinued Operations

Total Net Income

Basic Earnings Per Share:
Continuing Operations
Discontinued Operations

Total Basic Earnings Per Share

Diluted Earnings Per Share:
Continuing Operations
Discontinued Operations

Total Diluted Earnings Per Share
Dividends Declared Per Common Share
Price Range:

High
Low

Average Number of Common Shares Outstanding—Basic
Average Number of Common Shares Outstanding—Diluted

March 31

June 30

September 30

December 31

2017

2016

2017

2016

2017

2016

2017

2016

$ 214,117
$ 32,801

$ 206,242
$ 27,576

$ 212,086
$ 29,589

$ 203,482
$ 27,083

$ 216,457
$ 31,609

$ 197,175
$ 27,284

$ 206,690
$ 32,135

$ 196,640
$ 29,156

$ 19,529
56
$

$ 14,490
30
$

$ 16,717
61
$

$ 15,556
119
$

$ 17,773
$

(39) $

$ 14,594
22

$ 18,100
242
$

$ 17,397
113
$

$ 19,585

$ 14,520

$ 16,778

$ 15,675

$ 17,734

$ 14,616

$ 18,342

$ 17,510

$
$

.50

$
— $

.50

.49

$
— $

$
.49
.3200 $

.38

$
— $

.38

$
— $

.38
$
.3125 $

.43

$
— $

.43

.42

$
— $

$
.42
.3200 $

.41

$
— $

.41

$
— $

.41
$
.3125 $

.45

$
— $

.45

$
— $

$
.45
.3200 $

.38

$
— $

.38

.37

$
— $

.37
$
.3125 $

.45
.01

.46

.45
.01

$
$

.45
—

.45

.44
—

$
.46
.3200 $

.44
.3125

40.80
35.65
39,351
39,641

29.73
25.80
37,937
38,045

41.95
36.45
39,463
39,702

33.50
27.77
38,179
38,321

44.50
38.75
39,508
39,795

36.42
32.89
38,833
39,006

48.65
43.30
39,508
39,855

42.55
33.08
39,236
39,552

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

ITEM 9. Changes in and Disagreements With

ITEM 9B. Other Information

Accountants on Accounting and
Financial Disclosure

None.

ITEM 9A. Controls and Procedures

PART III

ITEM 10. Directors, Executive Officers and Corporate

Governance

The information required by this Item regarding Directors is
incorporated by reference to the information under “Election of
Directors” in the Company’s definitive Proxy Statement for the 2018
Annual Meeting. The information regarding executive officers and
family relationships is set forth in Item 3A hereto. The information
regarding Section 16 reporting is incorporated by reference to the
information under “Security Ownership of Directors and Officers—
Section 16(a) Beneficial Ownership Reporting Compliance” in the
Company’s definitive Proxy Statement for the 2018 Annual Meeting.
The information required by this Item regarding the Company’s
procedures for recommending nominees to the board of directors is
incorporated by reference to the information under “Meetings and
Committees of the Board of Directors—Corporate Governance
Committee” in the Company’s definitive Proxy Statement for the
2018 Annual Meeting. The information required by this Item in regard
to the Audit Committee and the Company’s Audit Committee financial
experts is incorporated by reference to the information under “Meetings
and Committees of the Board of Directors—Audit Committee” in the
Company’s definitive Proxy Statement for the 2018 Annual Meeting.
The Company has adopted a code of conduct that applies to all of
its directors, officers (including its principal executive officer, principal
financial officer, and its principal accounting officer or controller or
person performing similar functions) and employees. The Company’s
code of conduct is available on its website at www.ottertail.com. The
Company intends to satisfy the disclosure requirements under Item 5.05
of Form 8-K regarding an amendment to, or waiver from, a provision
of its code of conduct by posting such information on its website at
the address specified above. Information on the Company’s website is
not deemed to be incorporated by reference into this Annual Report
on Form 10-K.

ITEM 11. Executive Compensation

The information required by this Item is incorporated by reference
to the information under “Compensation Discussion and Analysis,”
“Report of Compensation Committee,” “Executive Compensation”
and “Director Compensation” in the Company’s definitive Proxy
Statement for the 2018 Annual Meeting.

Evaluation of Disclosures Controls and Procedures. Under the
supervision and with the participation of the Company’s management,
including the Chief Executive Officer and the Chief Financial Officer,
the Company evaluated the effectiveness of the design and operation
of its disclosure controls and procedures (as defined in Rule 13a-15(e)
under the Securities Exchange Act of 1934 (the Exchange Act)) as of
December 31, 2017, the end of the period covered by this report.
Based on that evaluation, the Chief Executive Officer and Chief Financial
Officer concluded that the Company’s disclosure controls and
procedures were effective as of December 31, 2017.

Changes in Internal Control over Financial Reporting. There were no
changes in the Company’s internal control over financial reporting
(as defined in Rules 13a-15(f) under the Exchange Act) during the
fourth quarter ended December 31, 2017 that have materially affected,
or are reasonably likely to materially affect, the Company’s internal
control over financial reporting.

Management’s Report Regarding Internal Control Over Financial
Reporting. Management is responsible for the preparation and integrity
of the consolidated financial statements and representations in this
Annual Report on Form 10-K. The consolidated financial statements of
the Company have been prepared in conformity with generally accepted
accounting principles applied on a consistent basis and include some
amounts that are based on informed judgments and best estimates
and assumptions of management.

In order to assure the consolidated financial statements are prepared

in conformance with generally accepted accounting principles,
management is responsible for establishing and maintaining adequate
internal control over financial reporting, as such term is defined in
Exchange Act Rule 13a-15(f). These internal controls are designed
only to provide reasonable assurance, on a cost-effective basis, that
transactions are carried out in accordance with management’s
authorizations and assets are safeguarded against loss from
unauthorized use or disposition.

Management has completed its assessment of the effectiveness

of the Company’s internal control over financial reporting as of
December 31, 2017. In making this assessment, management used the
criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission in Internal Control—Integrated Framework
(2013) to conduct the required assessment of the effectiveness of the
Company’s internal control over financial reporting. Based on this
assessment, management concluded that, as of December 31, 2017,
the Company’s internal control over financial reporting was effective
based on those criteria. The Company’s independent registered public
accounting firm, Deloitte & Touche LLP, has audited the Company’s
consolidated financial statements included in this Annual Report on
Form 10-K and issued an attestation report on the Company’s internal
control over financial reporting.

Attestation Report of Independent Registered Public Accounting
Firm. The attestation report of Deloitte & Touche LLP, the Company’s
independent registered public accounting firm, regarding the Company’s
internal control over financial reporting is provided on page 47.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this Item regarding security ownership is incorporated by reference to the information under “Security Ownership of Certain
Beneficial Owners” and “Security Ownership of Directors and Officers” in the Company’s definitive Proxy Statement for the 2018 Annual Meeting.

EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information as of December 31, 2017 about the Company’s common stock that may be issued under all of its equity
compensation plans:

Plan Category

Number of securities to be issued
upon exercise of outstanding
options, warrants and rights
(a)

Weighted average exercise
price of outstanding options,
warrants and rights
(b)

Number of securities remaining available for
future issuance under equity compensation plans
(excluding securities reflected in column (a))
(c)

Equity compensation plans approved by security holders:

2014 Stock Incentive Plan
1999 Stock Incentive Plan
1999 Employee Stock Purchase Plan

Equity compensation plans not approved by security holders

Total

411,585 (1)
2,325(3)
—

—

413,910

$
$

0.00
0.00
N/A

—

0.00

1,244,353 (2)
— (4)
374,624 (5)

—

1,618,977

(1) Includes 85,500, 116,700 and 114,648 performance based share awards granted in 2017, 2016 and 2015, respectively, 94,190 restricted stock units outstanding as of December 31,
2017, and 547 stock units as part of the director deferred compensation program, and excludes 49,695 shares of restricted stock issued under the 2014 Stock Incentive Plan.

(2)The 2014 Stock Incentive Plan provides for the issuance of any shares available under the plan in the form of restricted stock, restricted stock units, performance awards and

other types of stock-based awards, in addition to the granting of options, warrants or stock appreciation rights.

(3)Director deferred compensation program stock units under the 1999 Stock Incentive Plan.

(4)The 1999 Stock Incentive Plan provided for the issuance of any shares available under the plan in the form of restricted stock, restricted stock units, performance awards and

other types of stock-based awards, in addition to the granting of options, warrants or stock appreciation rights. The 1999 Stock Incentive Plan expired by its terms on
December 13, 2013 and no more awards may be granted thereunder.

(5)Shares are issued based on employee’s election to participate in the plan.

ITEM 13. Certain Relationships and Related

ITEM 14. Principal Accountant Fees and Services

Transactions, and Director Independence

The information required by this Item is incorporated by reference to
the information under “Policy and Procedures Regarding Transactions
with Related Persons,” “Election of Directors” and “Meetings and
Committees of the Board of Directors” in the Company’s definitive
Proxy Statement for the 2018 Annual Meeting.

The information required by this Item is incorporated by reference to
the information under “Ratification of Independent Registered Public
Accounting Firm—Fees” and “Ratification of Independent Registered
Public Accounting Firm—Pre-Approval of Audit/Non-Audit Services
Policy” in the Company’s definitive Proxy Statement for the 2018
Annual Meeting.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

PART IV

ITEM 15. Exhibits and Financial Statement Schedules

(a) List of documents filed as part of this report:

1. Financial Statements

Page

Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
Consolidated Balance Sheets, December 31, 2017 and 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Consolidated Statements of Income for the Three Years Ended December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
Consolidated Statements of Comprehensive Income for the Three Years Ended December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51
Consolidated Statements of Common Shareholders’ Equity for the Three Years Ended December 31, 2017. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
Consolidated Statements of Capitalization, December 31, 2017 and 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

2. Financial Statement Schedules

SCHEDULE 1—CONDENSED FINANCIAL INFORMATION OF REGISTRANT
OTTER TAIL CORPORATION (PARENT COMPANY)
Condensed Balance Sheets, December 31

(in thousands)

ASSETS

Current Assets

Cash and Cash Equivalents
Accounts Receivable
Accounts Receivable from Subsidiaries
Interest Receivable from Subsidiaries
Income Taxes Receivable
Notes Receivable from Subsidiaries
Other

Total Current Assets

Investments in Subsidiaries
Notes Receivable from Subsidiaries
Deferred Income Taxes
Other Assets

Total Assets

LIABILITIES AND EQUITY

Current Liabilities
Short-Term Debt
Current Maturities of Long-Term Debt
Accounts Payable to Subsidiaries
Notes Payable to Subsidiaries
Other

Total Current Liabilities

Other Noncurrent Liabilities
Commitments and Contingencies
Capitalization

Long-Term Debt, Net of Current Maturities
Common Shareholder Equity

Total Capitalization

Total Liabilities and Equity

See accompanying notes to condensed financial statements.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

2017

2016

16,371
—
2,098
117
—
1,752
1,130

21,468

724,613
79,611
27,923
31,559

6,218
12
1,706
141
662
1,671
936

11,346

692,723
79,843
35,387
29,079

$ 885,174

$ 848,378

—
186
6
61,908
7,799

69,899

38,319

80,064
696,892

776,956

—
231
5,958
38,519
5,838

50,546

32,556

95,172
670,104

765,276

$ 885,174

$ 848,378

OTTER TAIL CORPORATION (PARENT COMPANY)
Condensed Statements of Income—For the Years Ended December 31

(in thousands)

Operating Loss

Revenue
Operating Expenses

Operating Loss

Other Income (Expense)

Equity Income in Earnings of Subsidiaries
Interest Charges
Interest Charges to Subsidiaries
Interest Income from Subsidiaries
Other Income

Total Other Income

Income Before Income Taxes
Income Tax Expense (Benefit)

Net Income

See accompanying notes to condensed financial statements.

2017

2016

2015

—
8,353

(8,353)

82,715
(4,270)
(244)
2,848
1,054

82,103

73,750
1,311

72,439

—
9,689

(9,689)

67,047
(6,817)
(173)
4,897
1,621

66,575

56,886
(5,435)

62,321

—
10,188

(10,188)

66,067
(6,786)
(193)
4,786
421

64,295

54,107
(5,238)

59,345

OTTER TAIL CORPORATION (PARENT COMPANY)
Condensed Statements of Cash Flows—For the Years Ended December 31

(in thousands)

2017

2016

2015

Cash Flows from Operating Activities
Net Cash Provided by Operating Activities

Cash Flows from Investing Activities

Return of Capital (Investment in Subsidiaries)
Debt Repaid by (Issued to) Subsidiaries
Cash (Used in) Provided by Investing Activities

Net Cash Provided by (Used in) Investing Activities

Cash Flows from Financing Activities

Change in Checks Written in Excess of Cash
Net Short-Term (Repayments) Borrowings
Borrowings from (Repayments to) Subsidiaries
Proceeds from Issuance of Common Stock
Common Stock Issuance Expenses
Payments for Retirement of Capital Stock
Proceeds from the Issuance of Long-Term Debt
Short-Term and Long-Term Debt Issuance Expenses
Payments for Retirement of Long-Term Debt
Dividends Paid and Other Distributions

Net Cash (Used in) Provided by Financing Activities

Net Change in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period

Cash and Cash Equivalents at End of Period

See accompanying notes to condensed financial statements.

50,205

83,296

53,958

—
151
(121)

—
—
23,389
4,349
—
(1,799)
—
(158)
(15,231)
(50,632)

(40,082)

10,153
6,218

16,371

9,912
(3,309)
106

6,709

(428)
(59,666)
(60,948)
44,435
(562)
(104)
130,000
(723)
(87,547)
(48,244)

(83,787)

6,218
—

6,218

(88,079)
(12,592)
(11)

(100,682)

213
48,812
32,249
14,233
(451)
(1,596)
—
(312)
(201)
(46,223)

46,724

—
—

—

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

OTTER TAIL CORPORATION (PARENT COMPANY)
Notes to Condensed Financial Statements For the years ended December 31, 2017, 2016 and 2015

Incorporated by reference are Otter Tail Corporation’s consolidated statements of comprehensive income and common shareholders’ equity in
Part II, Item 8.

Basis of Presentation
The condensed financial information of Otter Tail Corporation is presented to comply with Rule 12-04 of Regulation S-X. The unconsolidated
condensed financial statements do not reflect all of the information and notes normally included with financial statements prepared in accordance
with GAAP. Therefore, these condensed financial statements should be read with the consolidated financial statements and related notes included
in this Annual Report on Form 10-K.

Otter Tail Corporation’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and
liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income
from operations of the subsidiaries is reported on a net basis as equity income in earnings of subsidiaries.

Related Party Transactions

AS OF DECEMBER 31, 2017:

(in thousands)

Otter Tail Power Company
Vinyltech Corporation
Northern Pipe Products, Inc.
BTD Manufacturing, Inc.
Wind Tower Business
Dock and Boatlift Business
T.O. Plastics, Inc.
Varistar Corporation
Otter Tail Assurance Limited

AS OF DECEMBER 31, 2016:

(in thousands)

Accounts
Receivable

Interest
Receivable

Current
Notes
Receivable

Long-Term
Notes
Receivable

Accounts
Payable

2,067
2
4
—
—
—
—
—
25

—
17
8
77
—
—
15
—
—

—
—
—
—
1,461
291
—
—
—

—
11,500
5,711
52,000
—
—
10,400
—
—

2,098

117

1,752

$ 79,611

6
—
—
—
—
—
—
—
—

Accounts
Receivable

Interest
Receivable

Current
Notes
Receivable

Long-Term
Notes
Receivable

Accounts
Payable

$ 1,572
3
—
—
—
—
—
60
71

—
20
10
92
—
—
19
—
—

—
—
—
—
1,441
230
—
—
—

—
11,500
5,943
52,000
—
—
10,400
—
—

10
—
—
—
—
—
—
5,948
—

Current
Notes
Payable

—
20,603
8,186
7,260
—
—
13,446
12,413
—

$ 61,908

Current
Notes
Payable

—
15,951
6,560
2,342
—
—
12,378
1,288
—

1,706

141

1,671

$ 79,843

5,958

$ 38,519

Dividends
Dividends paid to Otter Tail Corporation (the Parent) from its subsidiaries were as follows:

(in thousands)

2017

2016

2015

Cash Dividends Paid to Parent by Subsidiaries

50,571

77,779

46,188

See Otter Tail Corporation’s notes to consolidated financial statements in Part II, Item 8 for other disclosures.

Other schedules are omitted because of the absence of the conditions under which they are required, because the amounts are insignificant or

because the information required is included in the financial statements or the notes thereto.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

3. Exhibits

The following Exhibits are filed as part of, or incorporated by reference into, this report.

8-K filed 12/20/07 4.3

First Amendment, dated as of December 14, 2007, to Note Purchase Agreement, dated as of August 20, 2007.

Previously Filed

File No.

As Exhibit No.

2-A

8-K filed 7/1/09

2.1

2-B

2-C

3-A

3-B

4-A

4-A-1

4-A-2

4-A-3

4-B

10-K/A for year
ended 12/31/16

8-K filed 7/1/09

8-K filed 8/23/07

2-B

2-C

3.1

3.2

4.1

8-K filed 9/15/08

8-K filed 7/1/09

8-K filed 11/2/12

4.1

4.2

4.1

4-B-1

8-K filed 11/1/13

4.1

4-B-2

8-K filed 11/4/14

4.1

4-B-3

8-K filed 11/3/15

4.1

4-B-4

8-K filed 11/3/16

4.1

4-B-5

8-K filed 11/2/17

4.1

4-C

8-K filed 11/2/12

4.2

4-C-1

8-K filed 11/1/13

4.2

4-C-2

8-K filed 11/4/14

4.2

Plan of Merger, dated as of June 30, 2009, by and among Otter Tail Corporation (now known as Otter Tail Power
Company), Otter Tail Holding Company (now known as Otter Tail Corporation) and Otter Tail Merger Sub Inc.

Asset Purchase Agreement, dated as of November 16, 2016, among Otter Tail Power Company, EDF
Renewable Development, Inc., Power Partners Midwest, LLC, EDF-RE US Development, LLC and Merricourt
Power Partners, LLC.**/***

Turnkey Engineering, Procurement and Construction Services Agreement, dated as of November 16, 2016,
between Otter Tail Power Company and EDF-RE US Development, LLC.**/***

Restated Articles of Incorporation.

Restated Bylaws.

Note Purchase Agreement, dated as of August 20, 2007.

Second Amendment, dated as of September 11, 2008, to Note Purchase Agreement, dated as of August 20, 2007.

Third Amendment, dated as of June 26, 2009, to Note Purchase Agreement dated as of August 20, 2007.

Third Amended and Restated Credit Agreement dated as of October 29, 2012 among Otter Tail Corporation,
the Banks named therein, Bank of America, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication
Agents, KeyBank National Association, as Documentation Agent, U.S. Bank National Association, as
administration agent for the Banks and U.S. Bank National Association, Merrill Lynch, Pierce, Fenner &
Smith Incorporated and J.P. Morgan Securities LLC, as Joint Lead Arrangers and Joint Book Runners.

First Amendment to Third Amended and Restated Credit Agreement, dated as of October 29, 2013,
among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank,
Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank,
KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West and Union
Bank, N.A., as Banks.

Second Amendment to Third Amended and Restated Credit Agreement, dated as of November 3, 2014,
among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank,
Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank,
KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank.

Third Amendment to Third Amended and Restated Credit Agreement, dated as of October 29, 2015,
among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank,
Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank,
KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank.

Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016,
among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank,
Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank,
KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank.

Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2017, among
Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of
America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank
National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank.

Second Amended and Restated Credit Agreement dated as of October 29, 2012 among Otter Tail Power
Company, the Banks named therein, JPMorgan Chase Bank, N.A. and Bank of America, N.A., as Co-
Syndication Agents, KeyBank National Association and CoBank, ACB, as Co-Documentation Agents,
U.S. Bank National Association, as administrative agent for the Banks, and U.S. Bank National Association,
Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as Joint Lead Arrangers
and Joint Book Runners.

First Amendment to Second Amended and Restated Credit Agreement, dated as of October 29, 2013,
among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank,
Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank,
KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation
Agent and as a Bank, and Wells Fargo Bank, National Association and Union Bank, N.A., as Banks.

Second Amendment to Second Amended and Restated Credit Agreement, dated as of November 3, 2014,
among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank,
Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank,
KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation
Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

Previously Filed

File No.

As Exhibit No.

4-C-3

8-K filed 11/3/15

4.2

4-C-4

8-K filed 11/3/16

4.2

4-C-5

8-K filed 11/2/17

4.2

Third Amendment to Second Amended and Restated Credit Agreement, dated as of October 29, 2015,
among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank,
Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank,
KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation
Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.

Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2016,
among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank,
Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank,
KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation
Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.

Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2017,
among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank,
Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank,
KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation
Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.

4-D

8-K filed 8/3/11

4.1

Note Purchase Agreement, dated as of July 29, 2011, between Otter Tail Power Company and the
Purchasers named therein.

4-E

8-K filed 8/16/13

4.1

Note Purchase Agreement dated as of August 14, 2013 between Otter Tail Power Company and the
Purchasers named therein.

4-F

8-K filed 2/9/16

4.1

Term Loan Agreement dated as of February 5, 2016 among Otter Tail Corporation, the Banks named
therein and JPMorgan Chase Bank, N.A., as administrative agent for the Banks, and J.P. Morgan Securities
LLC, as Lead Arranger and Book Runner.

4-G

8-K filed 9/27/16

4.1

Note Purchase Agreement dated as of September 23, 2016 between Otter Tail Corporation and the
Purchasers named therein.

4-H

8-K filed 11/16/17

4.1

Note Purchase Agreement dated as of November 14, 2017 between Otter Tail Power Company and the
Purchasers named therein.

10-A

10-A-1

10-A-2

10-A-3

10-A-4

10-A-5

10-A-6

10-B

10-K for year
ended 12/31/89

10-K for year
ended 12/31/91

10-Q for quarter
ended 9/30/03

10-K for year
ended 12/31/92

10-Q for quarter
ended 6/30/15

10-F

10-F-1

10-F-2

10-F-3

10-F-4

10.1

Agreement for Sharing Ownership of Generating Plant by and between the Company, Montana-Dakota
Utilities Co., and Northwestern Public Service Company (dated as of January 7, 1970).

Letter of Intent for purchase of share of Big Stone Plant from Northwestern Public Service Company
(dated as of May 8, 1984).

Supplemental Agreement No. 1 to Agreement for Sharing Ownership of Big Stone Plant
(dated as of July 1, 1983).

Supplemental Agreement No. 2 to Agreement for Sharing Ownership of Big Stone Plant
(dated as of March 1, 1985).

Supplemental Agreement No. 3 to Agreement for Sharing Ownership of Big Stone Plant
(dated as of March 31, 1986).

Supplemental Agreement No. 4 to Agreement for Sharing Ownership of Big Stone Plant
(dated as of April 24, 2003).

10-F-5

Amendment I to Letter of Intent dated May 8, 1984, for purchase of share of Big Stone Plant.

10.3

Big Stone South–Ellendale Project Ownership Agreement dated as of June 12, 2015 between Otter Tail
Power Company, a wholly owned subsidiary of Otter Tail Corporation, and Montana-Dakota Utilities Co.,
a division of MDU Resources Group, Inc.**

10-C

2-61043

5-H

10-C-1

10-C-2

10-C-3

10-C-4

10-K for year
ended 12/31/89

10-K for year
ended 12/31/92

Agreement for Sharing Ownership of Coyote Station Generating Unit No. 1 by and between the Company,
Minnkota Power Cooperative, Inc., Montana-Dakota Utilities Co., Northwestern Public Service Company
and Minnesota Power & Light Company (dated as of July 1, 1977).

Supplemental Agreement No. One, dated as of November 30, 1978, to Agreement for Sharing Ownership
of Coyote Generating Unit No. 1.

Supplemental Agreement No. Two, dated as of March 1, 1981, to Agreement for Sharing Ownership of
Coyote Generating Unit No. 1 and Amendment No. 2 dated March 1, 1981, to Coyote Plant Coal Agreement.

Amendment, dated as of July 29, 1983, to Agreement for Sharing Ownership of Coyote Generating
Unit No. 1.

10-H-1

10-H-2

10-H-3

10-H-4 Agreement, dated as of September 5, 1985, containing Amendment No. 3 to Agreement for Sharing
Ownership of Coyote Generating Unit No. 1, dated as of July 1, 1977, and Amendment No. 5 to Coyote
Plant Coal Agreement, dated as of January 1, 1978.

10-C-5

10-Q for quarter
ended 9/30/01

10-A

Amendment, dated as of June 14, 2001, to Agreement for Sharing Ownership of Coyote Generating
Unit No. 1.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

Previously Filed

File No.

As Exhibit No.

10-C-6

10-D

10-Q for quarter
ended 9/30/03

10-K for year
ended 12/31/12

10.2

10-J

10-D-1

8-K filed 1/31/14

10.1

10-D-2

8-K filed 3/18/15

10.1

Amendment, dated as of April 24, 2003, to Agreement for Sharing Ownership of Coyote Generating
Unit No. 1.

Lignite Sales Agreement between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company,
Northern Municipal Power Agency, Montana-Dakota Utilities Co., Northwestern Corporation, dated as of
October 10, 2012.**

First Amendment to Lignite Sales Agreement dated as of January 30, 2014 among Otter Tail Power
Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources
Group, Inc., NorthWestern Corporation and Coyote Creek Mining Company, L.L.C.

Second Amendment to Lignite Sales Agreement dated as of March 16, 2015 among Otter Tail Power
Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources
Group, Inc., NorthWestern Corporation and Coyote Creek Mining Company, L.L.C.

10-E

10-F-1

10-F-1a

10-Q/A for quarter
ended 6/30/13

10.1

Wind Energy Purchase Agreement dated May 9, 2013 between Otter Tail Power Company and Ashtabula
Wind III, LLC.**

10-K for year
ended 12/31/02

10-K for year
ended 12/31/10

10-N-1

Deferred Compensation Plan for Directors, as amended.*

10-N-1A First Amendment of Deferred Compensation Plan for Directors (2003 Restatement), as amended.*

10-F-1b 8-K filed 4/17/14

10.5

Second Amendment of Deferred Compensation Plan for Directors (2003 Restatement), as amended.*

10-F-2

8-K filed 2/04/05

10.1

Executive Survivor and Supplemental Retirement Plan (2005 Restatement).*

10-F-2a 10-K for year

10-N-2a First Amendment of Executive Survivor and Supplemental Retirement Plan (2005 Restatement).*

ended 12/31/06

10-F-2b 10-K for year

10-N-2B Second Amendment of Executive Survivor and Supplemental Retirement Plan (2005 Restatement).*

10.1

10.4

10.1

Nonqualified Retirement Plan (2011 Restatement).*

1999 Employee Stock Purchase Plan, As Amended (2016).

1999 Stock Incentive Plan, As Amended (2006).*

Form of Restricted Stock Award Agreement for Directors.*

10-O-12 2014 Executive Annual Incentive Plan.*

4.1

10.1

10.2

10.3

Otter Tail Corporation 2014 Stock Incentive Plan.*

Form of 2014 Performance Award Agreement.*

Form of 2014 Restricted Stock Award Agreement for Executive Officers.*

Form of 2014 Restricted Stock Award Agreement for Directors.*

10-J-14

Summary of Non-Employee Director Compensation (2016).*

10.1

10.2

10.3

10.4

10.2

10.5

Form of 2015 Performance Award Agreement (Executives).*

Form of 2015 Performance Award Agreement (Legacy).*

Form of 2015 Restricted Stock Unit Award Agreement (Executives).*

Form of 2015 Restricted Stock Unit Award Agreement (Legacy).*

Form of 2015 Restricted Stock Award Agreement for Directors.*

Otter Tail Corporation Executive Restoration Plus Plan, as Amended and Restated.*

First Amendment of Otter Tail Corporation Executive Restoration Plus Plan*

Summary of Non-Employee Director Compensation (2018).*

10-F-3

10-F-4

ended 12/31/10

10-Q for quarter
ended 9/30/11

10-Q for quarter
ended 9/30/16

10-F-5

8-K filed 4/13/06

10-F-6

8-K filed 4/13/06

10-F-7

10-K for year
ended 12/31/13

10-F-8

333-195337

10-F-9

8-K filed 4/17/14

10-F-10 8-K filed 4/17/14

10-F-11

8-K filed 4/17/14

10-F-12

10-K for year
ended 12/31/16

10-F-13

8-K filed 2/11/15

10-F-14 8-K filed 2/11/15

10-F-15

8-K filed 2/11/15

10-F-16 8-K filed 2/11/15

10-F-17

8-K filed 4/15/15

10-F-18

8-K filed 2/11/15

10-F-18a

10-F-19

10-G

10-H-1

10-H-2

10-I-1

10-I-2

8-K filed 5/11/15

1.1

Distribution Agreement dated May 11, 2015, between Otter Tail Corporation and J.P. Morgan Securities LLC.

10-K for year
ended 12/31/12

10-K for year
ended 12/31/10

10-O-1

Executive Employment Agreement, Kevin Moug.*

10-O-2

Executive Employment Agreement, George Koeck.*

10-Q-3

Change in Control Severance Agreement, Kevin G. Moug.*

10-Q-4

Change in Control Severance Agreement, George Koeck.*

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

10-I-3

10-I-4

10-I-5

10-I-6

10-I-7

10-J

12.1

21-A

23-A

24-A

31.1

31.2

32.1

32.2

101

Previously Filed

File No.

As Exhibit No.

10-K for year
ended 12/31/11

10-Q for quarter
ended 9/30/14

10-K for year
ended 12/31/15

10-Q-5

Change in Control Severance Agreement, Chuck MacFarlane.*

10.3

Change in Control Severance Agreement, Timothy Rogelstad.*

10.6

Change in Control Severance Agreement, Paul Knutson.*

10-R-6

Change in Control Severance Agreement, John Abbott.*

Change in Control Severance Agreement, Jennifer Smestad.*

Otter Tail Corporation Executive Severance Plan.*

Calculation of Ratios of Earnings to Fixed Charges and Preferred Dividends.

Subsidiaries of Registrant.

Consent of Deloitte & Touche LLP.

Power of Attorney.

Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Financial statements from the Annual Report on Form 10-K of Otter Tail Corporation for the year ended
December 31, 2017, formatted in Extensible Business Reporting Language: (i) the Consolidated Balance
Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Comprehensive
Income, (iv) the Consolidated Statements of Common Shareholders’ Equity, (v) the Consolidated
Statements of Cash Flows, (vi) the Consolidated Statements of Capitalization, (vii) the Notes to
Consolidated Financial Statements and (viii) Schedule I.

*Management contract, compensatory plan or arrangement required to be filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K.

**Confidential information has been omitted from this Exhibit and filed separately with the Securities and Exchange Commission pursuant to a confidential
treatment request under Rule 24b-2.

***Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company hereby undertakes to furnish copies of any of the
omitted schedules and exhibits to the Securities and Exchange Commission upon request.
Pursuant to Item 601(b)(4)(iii) of Regulation S-K, copies of certain instruments defining the rights of holders of certain long-term debt of the Company are
not filed, and in lieu thereof, the Company agrees to furnish copies thereof to the Securities and Exchange Commission upon request.

ITEM 16. Form 10-K Summary

None.

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.

OTTER TAIL CORPORATION

/s/ Kevin G. Moug
Kevin G. Moug
Chief Financial Officer and Senior Vice President
(authorized officer and principal financial officer)

Dated: February 20, 2018

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:

SIGNATURE AND TITLE

Charles S. MacFarlane

President and Chief Executive Officer
(principal executive officer) and Director

Kevin G. Moug

Chief Financial Officer and Senior Vice President
(principal financial and accounting officer)

Nathan I. Partain

Chairman of the Board and Director

Karen M. Bohn, Director

John D. Erickson, Director

Steven L. Fritze, Director

Kathryn O. Johnson, Director

Timothy J. O’Keefe, Director

Joyce Nelson Schuette, Director

James B. Stake, Director

/s/ Charles S. MacFarlane
Charles S. MacFarlane
Pro Se and Attorney-in-Fact

Dated February 20, 2018

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O RT

SHAREHOLDER SERVICES

Otter Tail Corporation Stock Listing
Otter Tail Corporation common stock trades on the Nasdaq
Global Select Market. Our ticker symbol is OTTR. You can find our
daily stock price on our website, www.ottertail.com. Shareholders
who sign up for Internet account access can view their account
information online.

2018 Annual Meeting of Shareholders

Monday, April 9, 2018 • 10:00 a.m., Central Daylight Time
Bigwood Event Center
Country Inn & Suites
925 Western Avenue
Fergus Falls, Minnesota

Dividends
Otter Tail Corporation has paid dividends on our common shares
each quarter since 1938 without interruption or reduction. 2017
dividends were $1.28 per share, and the year-end yield was
2.9 percent. Total shareholder return grew at a compounded
average annual rate of 7.3 percent for the past ten years.

Dividend Reinvestment and Share Purchase Plan
Our Dividend Reinvestment and Share Purchase Plan provides
shareholders of record with a convenient method for purchasing
shares of Otter Tail Corporation common stock. Approximately
80 percent of eligible shareowners holding approximately
11 percent of our common shares are enrolled. Through this plan,
participants may have their dividends automatically reinvested in
additional shares without paying any brokerage fees or service
charges. Shareholders also may contribute a minimum of $10
and a maximum of $120,000 annually. Automatic withdrawal
from a checking or savings account is available for this service.
Shareholders also may sell shares through the plan. Existing
Otter Tail shareholders and new investors can enroll online
through Shareowneronline.com. For the first purchase, the
minimum investment is $250. For more information, contact
Shareholder Services.

Electronic Dividend Deposit
You can arrange for electronic deposit of your dividends directly
to your checking or savings accounts. For authorization materials,
contact Shareholder Services.

Stock Certificates and DRS
Replacing missing certificates is a costly and time-consuming
process so you should keep a separate record of the certificate
number, purchase date, date of issue, price paid, and exact
registration name. If you are enrolled in the Dividend Reinvestment
and Share Purchase Plan, you have the option of depositing your
common certificates into your plan account. We also offer direct
registration system (DRS) as a method of holding your shares in
book-entry form, which eliminates the need to hold stock
certificates.

2018 Common Dividend Dates

EX-DIVIDEND
February 14
May 14
August 14
November 14

Key Statistics

RECORD
February 15
May 15
August 15
November 15

PAYMENT
March 10
June 9
September 10
December 10

NASDAQ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . OTTR
Year-end stock price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $44.45
Year-end market-to-book ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5
Annual dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.9%
Shares outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39.6 million
Market capitalization (as of December 31, 2017) . . . . . $1.76 billion
2017 average daily trading volume . . . . . . . . . . . . . . . . . . . . . . 93,411
Institutional holdings

(shares as of December 31, 2017) . . . . . . . . . . . . . . . . 20.2 million

Current Credit Ratings

Moody’s

Fitch

S&P

Otter Tail Corporation:

Issuer Default Rating
Senior Unsecured Debt
Outlook

Otter Tail Power Company:

Issuer Default Rating
Senior Unsecured Debt
Outlook

Transfer Agent

Baa2
N.A.
Stable

A3
N.A.
Stable

BBB-
BBB-
Stable

BBB
N.A.
Positive

BBB
BBB+
Stable

BBB
BBB
Positive

Equiniti Shareowner Services
P.O. Box 64856
St. Paul, MN 55164-0856
Phone: 800-468-9716 or 651-450-4064

Shareholder Services

Otter Tail Corporation
215 South Cascade Street
P.O. Box 496
Fergus Falls, MN 56538-0496

Phone: 800-664-1259
or 218-739-8479
Email: sharesvc@ottertail.com
Fax: 218-998-3165

OT T E R TA I L CO R P O R AT I O N 2 0 1 7 A N N UA L R E P O R T

Our manufacturing

companies supply

valued products to

customers in various

markets. In 2017

custom metal

fabricator BTD

continued to deliver

key customer

orders, including

ﬁ xtures used for

transporting wind

turbine blades.

Otter Tail Power

Company’s mix of

energy resources

allows for some of

the lowest rates in the

nation. Renewable

Energy Construction

and Operations

Manager Harvey

McMahon (left) and

Wind Farm Supervisor

Craig Burchill oversee

our wind power

resources—a least-

cost option for our

customers—which

produce some of the

highest capacity

factors in the region.

DIR CTORS
DIR CTORS
DIR CTORS
DIR CTORS
DIR CTORS
DIR CTORS
DIR CTORS

CHARLES S. MACFARLANE
President and
Chief Executive Ofﬁ cer

KEVIN G. MOUG
Chief Financial Ofﬁ cer and
Senior Vice President

GEORGE A. KOECK
Senior Vice President,
General Counsel,
and Corporate Secretary

NATHAN I. PARTAIN
Chairman of the Board
of Directors
Chicago, Illinois
President and
Chief Investment Ofﬁ cer,
Duff & Phelps Investment
Management Co.; President,
Chief Executive Ofﬁ cer and
Chief Investment Ofﬁ cer,
DNP Select Income Fund, Inc.
(closed-end utility fund)

JENNIFER SMESTAD
Succeeding George Koeck
as Vice President, General Counsel,
and Corporate Secretary

KAREN M. BOHN
A/CG–Edina, Minnesota
President, Galeo Group, LLC
(management consulting ﬁ rm)

JOHN D. ERICKSON
Fergus Falls, Minnesota
Former President and
Chief Executive Ofﬁ cer,
Otter Tail Corporation (utility
and diversiﬁ ed businesses)

STEVEN L. FRITZE
A/CG—Eagan, Minnesota
Retired Chief Financial Ofﬁ cer,
Ecolab Inc. (diversiﬁ ed
manufacturing)

TIMOTHY J. ROGELSTAD
Senior Vice President,
Electric Platform;
President, Otter Tail
Power Company

JOHN S. ABBOTT
Senior Vice President,
Manufacturing Platform;
President, Varistar

CRIS M. OEHLER
Vice President,
Corporate Communication

PAUL L. KNUTSON
Vice President,
Human Resources

KATHRYN O. JOHNSON
C/CG—Hill City, South Dakota
Owner/Principal, Johnson Environmental
Concepts (geochemical consulting ﬁ rm)

CHARLES S. MACFARLANE
Fergus Falls, Minnesota
President and Chief Executive Ofﬁ cer,
Otter Tail Corporation

TIMOTHY J. O’KEEFE
C/CG—Grand Forks, North Dakota
Retired Executive Vice President,
University of North Dakota
Alumni Association;
Retired Chief Executive Ofﬁ cer,
University of North Dakota
Foundation (nonproﬁ t)

JOYCE NELSON SCHUETTE
A/C—Walker, Minnesota
Retired Managing Director and
Investment Banker, Piper Jaffray & Co.
(ﬁ nancial services)

JAMES B. STAKE
A/C—Edina, Minnesota
Retired Executive Vice President,
Enterprise Services, 3M Company
(diversiﬁ ed manufacturing)

Committees: A—Audit C—Compensation CG—Corporate Governance

NATHAN PARTAIN

KAREN BOHN

JOHN ERICKSON

STEVEN FRITZE

KATHRYN JOHNSON

Otter Tail Corporation delivers value by building strong electric utility and manufacturing platforms.

For our shareholders we deliver above-average returns through operational excellence and

growing our businesses.

For our customers we commit to quality and value in everything we do.

For our employees we provide an environment of opportunity with accountability where

people are valued and empowered to do their best work.

MISSION

INTEGRITY: We conduct business responsibly and honestly.

SAFETY: We provide safe workplaces and require safe work practices.

PEOPLE: We build respectful relationships and create an environment where people thrive.

PERFORMANCE: We strive for excellence, act on opportunity, and deliver on commitments.

COMMUNITY: We improve the communities where we work and live.

VALUES

VISION

WE WILL BUILD A STRONG AND FOCUSED

DIVERSIFIED ORGANIZATION WITH AN

ELECTRIC UTILITY AS OUR FOUNDATION.

EX CUTIVE
EX CUTIVE LEADERSHIP
EX CUTIVE
EX CUTIVE
EX CUTIVE
EX CUTIVE
EX CUTIVE

CHARLES MACFARLANE

TIMOTHY O’KEEFE

JOYCE SCHUETTE

Left to right: George Koeck, Cris Oehler, John Abbott, Paul Knutson,
Tim Rogelstad, Chuck MacFarlane, Kevin Moug, and Jennifer Smestad

JAMES STAKE

Otter Tail Corporation
Internal Audit Manager
Janelle Johnson evaluates
and improves effectiveness
of critical company processes.
She completed an internal audit

at BTD’s Lakeville facility in 2017.

Northern Pipe Products Yard Lift
Operator Jesus Guajardo (cover) and
Customer Service Representative Andrew

Stockinger provide customers with high

quality service and PVC pipe. Together
with Vinyltech, Northern Pipe successfully

managed accelerated production and
shipping surrounding the 2017 hurricanes.

ABOUT THE

COV R

Otter Tail Power Company Energy

Management Representative Roger Garton
(cover with our electric vehicle and left)

helps customers with rebates and programs.

Our Commercial Design Assistance program

determined energy savings opportunities for

Leech Lake Band of Ojibwe’s new Tribal Justice Center.

GROW

OUR BUSINE SSES

ACHIEVE

O PERATI ONAL AND COMM ERCI AL EXCE LLE NCE

DEVELOP OUR TAL ENT

SHAREHOLDER SERVICES
215 S. Cascade St., P.O. Box 496
Fergus Falls, MN 56538-0496
Phone: 800-664-1259
or 218-739-8479
Email: sharesvc@ottertail.com
www.ottertail.com
NASDAQ: OTTR

DRIVEN TO

2 0 1 7 A N N U A L R E P O R T

EXCELLENCE