Otter Tail Annual Report 2018

FY2018 Annual Report · Otter Tail

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intentional

PLANNING FOR SHAREHOLDERS,

CUSTOMERS, AND EMPLOYEES

2 0 1 8 A N N U A L R E P O R T

Otter Tail Power Company Trainer
and Quality Assurance Analyst
Michelle Gunderson oversees training
efforts for the utility’s new Customer
Information System. Live in early 2019,
this multi-year project marks a significant
first step for technology investments that
will allow us to better meet customers’
changing service expectations.

Northern Pipe Products Quality
Assurance Coordinator Charlie Shorma
maintains operational excellence by
paying close attention to detail regarding
product standards and quality.
High-quality product combined with
strong customer service allows for
continued company growth.

T.O. Plastics
Vice President
of Human Resources
and Talent Development

Julia Nguyen (left) and
Quality Assurance Inspector
Abdi Mohamed demonstrate how
employees’ everyday work aligns with
company values, goals, and initiatives, including

safely delivering quality products on time.

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VISION

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

MISSION

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.

SUMMARY OF THE YEAR

CONSOLIDATED OPERATIONS

($ in thousands, except share amounts)

2018

2017

PERCENT
CHANGE

Operating Revenues
Net Income
Diluted Earnings per Share
Dividends per Common Share
Return on Average Common Equity
Book Value per Common Share
Cash Flow from Operating Activities
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

$
$
$
$

916,447
82,345
2.06
1.34
11.5%

$
$
$
$

849,350
72,439
1.82
1.28
10.6%

18.38
$
$
143,448
39,664,884
12,661
49.64

17.62
$
$
173,577
39,557,491
13,053
44.45

14.7%

12.1%

$ 1,968,965
2,321

$ 1,758,330
2,097

ELECTRIC PLATFORM ($ in thousands)

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

MANUFACTURING PLATFORM ($ in thousands)

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

450,198
4,976,960
88,031
132,448
$ 2,189,811
$ 1,728,534
87,287
$
669

434,506
4,814,984
94,797
132,146
$ 2,113,574
$ 1,690,224
118,444
$
668

$
$
$
$

466,249
51,183
279,186
17,515
1,615

$
$
$
$

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

12.4
17.0
9.8
22.1
16.2

7.9
13.7
13.2
4.7
8.5
4.3
(17.4)
0.3
(3.0)
11.7
21.5
12.0
10.7

3.6
3.4
(7.1)
0.2
3.6
2.3
(26.3)
0.1

VALUES

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.

LETTER TO SHAREHOLDERS

ORGANIZATION CHART

FINANCIAL INFORMATION

10-K FINANCIAL REPORT

DIRECTORS AND LEADERSHIP

103

OT T E R TA I L C O R P O R AT I O N 2 0 1 8 A N N U A L R E P O RT

T
O

O
U
R

shareholders

OTTER TAIL CORPORATION’S INTENTIONAL GROWTH

INTENTIONAL GROWTH

DELIVERS SHAREHOLDER VALUE

Otter Tail Corporation targets growth while

maintaining operational and commercial excellence through

our two focused platforms: electric and manufacturing. We

deliver long-term value to shareholders as we organically

grow our electric rate base and manufacturing platform

and develop our systems, locations, and people.

Our electric platform continues to grow through capital

investments in transmission and generation projects. Our

manufacturing platform remains focused on the growth

required to meet customer needs and operate efficient
businesses. This year’s report theme, Intentional, refers to
purposeful selection, planning, and execution of the right

initiatives at the right time to facilitate measured growth

for each of our platforms.

Through our combined efforts, we achieved consolidated

net income and diluted earnings per share of $82.3 million

and $2.06, respectively, compared with $72.4 million and

$1.82 in 2017. Return on equity was 11.5 percent.

Our stock performed well. For the three years ended in

2018, Otter Tail Corporation provided the top total shareholder

return in the Edison Electric Institute Index of investor-owned

electric utilities. The dividend yield at year-end was 2.7 percent.

Total shareholder return has grown at a compounded annual

rate of 15.3 percent over the past five years. We have paid

dividends on common stock for 80 years, or 321 consecutive

quarters. Our annual indicated dividend per share for 2019

is $1.40, a 4.5 percent increase over our 2018 dividend rate.

Excellent 2018 financial results demonstrate our actions,

driven by our strategic initiatives to grow our business,

achieve operational and commercial excellence, and develop

our talent, continue to deliver shareholder value and

position us for long-term success.

UTILITY PROVIDES GROWTH AND STABILITY

Otter Tail Power Company grew rate base by 4.5 percent

in 2018, primarily with capital investment in regional

transmission projects.

Our utility is a 50 percent owner in a recently energized

163-mile 345-kv line that runs northwest from the Big Stone

Substation near Big Stone City, South Dakota, to the Ellendale

Substation near Ellendale, North Dakota. This is a

Midcontinent Independent System Operator (MISO)-

designated multi-value project, allowing cost recovery from

C H A R L E S S . M A C F A R L A N E
PRESIDENT AND CEO

OT T E R TA I L C O R P O R AT I O N 2 0 1 8 A N N U A L R E P O RT

STRATEGY FOCUSES ON CAPITAL INVESTMENT, CONTINUED IMPROVEMENT IN OPERATIONS, AND TALENT DEVELOPMENT.

all customers in MISO’s upper-Midwest footprint. Our investment is approximately $115 million. The line improves regional

transmission reliability and allows for the interconnection of significant renewable and other generation resources.

In preparation for our Hoot Lake coal-fired power plant’s 2021 retirement, we will construct wind and natural gas generation

resources. By 2022 we anticipate approximately 30 percent of our energy will come from renewables. And carbon dioxide emissions

from generation resources we own will be approximately 33 percent lower than 2005 levels, even as we forecast generating

23 percent more megawatt-hours annually.

Our agreement to purchase the proposed 150-megawatt Merricourt wind project to be built in southeastern North Dakota is

progressing. We expect the wind farm to be online in 2020. At an estimated cost of approximately $270 million, this will be the

largest capital project in company history.

In July the South Dakota Public Utilities Commission approved our site permit for Astoria Station, a 250-megawatt simple-cycle

natural gas-fired plant near Astoria, South Dakota. We have executed the generator interconnection agreement and combustion

turbine generator purchase agreement. Our utility will construct, own, and operate the facility. We expect the project to cost
approximately $165 million and to be in service in 2021 with three to five full-time employees. Astoria Station pre-construction

activity will begin this summer. Full construction will begin in 2020.

Otter Tail Power Company continues to evaluate cost-effective solar additions that will meet requirements in all three states we serve.

In November 2018 the Minnesota Public Utilities Commission unanimously voted to approve our request to extend the deadline

from 2019 to 2020 for our next resource plan. This plan identifies the most cost-effective combinations of resources for reliably meeting

customers’ needs during the next 15 years. Delaying our filing one year will allow us to consider the outcomes of two key environmental

regulations that may impact our modeling, the Regional Haze Rule and the proposed Affordable Clean Energy Rule.

We are pursuing $973 million in capital investments at the utility between 2019 and 2023, producing a compounded annual rate

base growth of approximately 8 percent between 2018 and 2023.

The North Dakota Public Service Commission granted Otter Tail Power Company a revenue increase of 3.1 percent based on

an authorized 9.77 percent return on equity. This increase, effective February 2019, concludes the rate case we filed in 2017.

In January 2018 we implemented an interim rate increase while the commission considered our request.

We filed a rate case with the South Dakota Public Utilities Commission in April 2018, requesting to increase non-fuel rates by

10.1 percent or $3.3 million annually, as the first step in a two-step request. The second step in the request is an additional 1.7 percent

increase in 2020 to recover costs for the Merricourt wind project. Interim rates went into effect in October 2018.

We continue to invest in systems that help us meet our customers’ expectations. In February 2019 our new Customer Information

System, which is our biggest system upgrade in a generation, went live. This new system is the foundation for evolving tools that help

our employees more effectively perform their jobs and communicate with our customers.

The utility, along with other investor-owned electric utilities, published reports highlighting our shared commitments to

sustainability. The Edison Electric Institute, which represents all United States investor-owned electric companies, launched the

first industry-focused environmental, social, governance, and sustainability reporting framework. Every day we work to ensure

we can continue to supply our customers with reliable, affordable, and increasingly clean energy. It is important that our customers,

communities, and investors understand all that goes into that—from our day-to-day business decisions to our planning process for

generation resources. Transparency is important to our company and to our industry.

The utility continued to earn high customer satisfaction scores and achieved strong safety performance in 2018. Thanks to

dedicated employees and leadership, Otter Tail Power Company continues to deliver shareholder value while safely and effectively

providing customers with an essential service and maintaining rates 25 percent lower than the national average.

MANUFACTURING COMPANIES’ CUSTOMER FOCUS CREATES OPPORTUNITY
BTD, our contract metal fabricator and largest manufacturing business, increased sales by 19 percent and earnings by 13 percent

in 2018. The Georgia location, which has been focused on operational improvements, was profitable in the last half of 2018.

The company achieved this while reporting its lowest OSHA rate and highest on-time delivery in its history.

OT T E R TA I L C O R P O R AT I O N 2 0 1 8 A N N U A L R E P O RT

ELECTRIC

MANUFACTURING

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

BTD MANUFACTURING, INC.
Metal fabricator
Detroit Lakes, MN | 1995
Paul Gintner
1,273 employees
www.btdmfg.com

LEGEND

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

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

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

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

Our investment in BTD’s Minnesota

facilities has provided additional capabilities

and capacity to meet customer needs,

demonstrated through record-level paint hours in the

Lakeville plant. BTD’s expansion to the Southeast also has

created new opportunities, and the company has begun

work to improve efficiency by updating the Georgia

production plant layout. BTD gained share in the power

sport and utility vehicle markets and benefited from a

strong energy market in 2018. We continue to monitor

the impact on domestic markets from 2018 tariffs.

Northern Pipe Products and Vinyltech, the PVC pipe

manufacturing companies that comprise our plastics

segment, had an exceptional year of strong operational

performance and positively contributed to earnings while

remaining highly competitive. Both companies improved

financial performance with favorable market conditions

supporting strong sales prices. And both continue to

improve in the markets they serve by providing excellent

customer service, demonstrating flexibility and

responsiveness to customer requests. We’re targeting

more organic volume growth through new markets and

continued operational excellence.

T.O. Plastics, our plastics thermoforming manufacturer,

celebrated its 70th anniversary in 2018 and achieved

6 percent overall sales growth and a 29 percent increase

in earnings compared with 2017. The company’s

horticulture segment continues to grow through key

account relationships and new product launches.

T.O. Plastics installed new equipment and enhanced

cleanroom capabilities and capacity to serve its life

science business segment.

OUR INTENT IS CONTINUED SUCCESS

Otter Tail Corporation’s intentional growth strategy

focuses on capital investment, continued improvement in

operations, and talent development. We know our success

depends on our understanding of the environments in

which we operate, how we define our role within them,

and how we deliver value.

We are pleased with our 2018 achievements and intend

to continue delivering excellent results. Thank you to our

customers for choosing to work with us, our employees for

accomplishing so much, and you, our shareholders,

for investing in our success.

Charles S. MacFarlane

President and Chief Executive Officer

OT T E R TA I L C O R P O R AT I O N 2 0 1 8 A N N U A L R E P O RT

REVENUE BY PLATFORM (millions)

NET INCOME FROM CONTINUING
OPERATIONS BY PLATFORM (millions)

MARKET CAPITALIZATION
(millions)

6
1
9
9 $
4
8
$

9
9
7
$

0
8
7
$

4
0
8
$

3
4
7
$

0
1
7
$

6
5
6
4 $
8
5
$

3
1
6
$

4
1
5
$

$1,000

$750

$500

$250

$80

$60

$40

$20

7
5
$

4
4
$

3
1
$

9
5
$

9
4
$

2
6
$

0
5
$

0
1
$

2
1
$

2
8
$

4
5
$

8
2
$

2
7
$

9
4
$

3
2
$

9
6
9
,
1
8 $
5
7
,
1
$

5
0
6
,
1
$

$2,000

$1,500

$1,000

$500

2
5
1
,
1
$

2
6
0
,
1
$

8
0
0
,
1
$

08 09 10 11 12 13 14 15 16 17 18

13 14 15 16 17 18

Electric

Manufacturing

Total Continuing Operations
Electric
Manufacturing (including unallocated corporate costs)

GROWTH OF $1,000 INVESTMENT IN OTTER TAIL
COMMON STOCK MADE DECEMBER 31, 2008
(with dividends reinvested)

8
1
3
3
$

6
8
8
2
$

9
6
5
2
$

$4,000

$3,000

$2,000

$1,000

6
9
7
,
1
$

0
3
6
,
1
$

5
1
6
,
1
$

5
3
3
,
1
$

0
0
0
,
1
$

4
2
1
,
1
$

1
8
0
,
1
$

7
1
1
,
1
$

DIVIDEND PAYMENT HISTORY

DIVIDEND PAYOUT RATIO

4
3
.
1
$

$1.25

$1.00

$0.75

$0.50

$0.25

$2.40

$1.80

%
7
7

%
8
7

100%

%
0
7

%
5
6

75%

$1.20

1
2
.
1
$

3
2
.
1
$

5
2
.
1
$

8
2
.
1
$

4
3
.
1
$

50%

$0.60

25%

08 09 10 11 12 13 14 15 16 17 18

38 43 48 53 58 63 68 73 78 83 88 93 98 03 08 13 18

14 15 16 17 18

Dividend

Payout Ratio

OPERATING INCOME BY PLATFORM (millions, pre-tax)

$150

$120

$90

$60

$30

($30)

2
0
1
$

1
8
$

9
6
$

1
7
$

9
6
$

8
6
$

9
6
$

5
1
1
$

2
9
$

3
0
1
$

9
7
$

2
3
1
$

9
2
1
$

7
1
1
$

4
9
$

5
9
$

8
8
$

4
3
$

3
3
$

4
2
$

3
2
$

7
3
$

1
4
$

0
6
$

7
5
$

3
5
$

1
4
$

3
$

2
$

2
1
$

)
2
1
$
(

Consolidated

Electric

Manufacturing (including unallocated corporate costs)

OT T E R TA I L C O R P O R AT I O N 2 0 1 8 A N N U A 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)
Dividends Payout Ratio (percent)
Capital Ratio (percent):
Short-term and Long-term Debt
Common Equity

$
$

2018

51.88
39.00

25.2
18.9
18.38

2018

4.0x
15
8.4
11.5
65

45.5
54.5
100.0

2017

48.65
35.65

26.7
19.6
17.62

2017

4.3x
27
7.9
10.6
70

46.4
53.6
100.0

2016

2015

2014

$
$

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

2013

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

Notes: (1) Continuing Operations.

(2) Continuing Operations; see note 14 to consolidated financial statements in 2018 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

2018

2017

2016

2015

2014

2013

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

$ 127,539
145,237
118,080
7,735
51,664
$ 450,255

1,321,132
1,611,770
1,978,881
65,177
4,976,960
271,840
5,248,800
3.4
6,904
567

9.65¢
9.01¢
5.97¢
7.74¢

104,242
27,158
55
993
132,448

$ 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

12,740
$ 1,226.02

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

$ 2,019,721
$ 699,642
34.6
2.76

$ 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

911,726

916,522

903,462

896,706

873,842

863,561

548,500
138,000
106,200
2,900
795,600

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

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 C O R P O R AT I O N 2 0 1 8 A N N U A 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, 2018

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

Commission File Number 0-53713

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

(State or other jurisdiction of incorporation or organization)

MINNESOTA

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 every Interactive Data File required to be submitted 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 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 company.
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

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 29, 2018 was
$1,810,041,170.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 39,729,708
Common Shares ($5 par value) as of February 15, 2019.

Documents Incorporated by Reference: Proxy Statement for the 2019 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 8 A N N UA L R E P O RT

FORM 10-K

TABLE OF CONTENTS

DESCRIPTION

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

PART I

ITEM 1.

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

ITEM 1A.

Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

ITEM 1B.

Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

ITEM 2.

ITEM 3.

Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

ITEM 3A.

Executive Officers of the Registrant (as of February 22, 2019) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

ITEM 4.

Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

PART II

ITEM 5.

ITEM 6.

ITEM 7.

Market for Registrant’s Common Equity, Related Stockholder Matters And Issuer Purchases of Equity Securities . . . . . . . 32

Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

ITEM 7A.

Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

ITEM 8.

Financial Statements and Supplementary Data:

Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Consolidated Balance Sheets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Consolidated Statements of Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Consolidated Statements of Comprehensive Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

Consolidated Statements of Common Shareholders’ Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Consolidated Statements of Cash Flows. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Consolidated Statements of Capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

Notes to Consolidated Financial Statements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Supplementary Financial Information—Quarterly Information. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

ITEM 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

ITEM 9A.

Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

ITEM 9B.

Other Information. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

PART III

ITEM 10.

Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

ITEM 11.

ITEM 12.

ITEM 13.

Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters . . . . . . . . . . . . . . . . . 93

Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

ITEM 14.

Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

PART IV

ITEM 15.

Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

ITEM 16.

Form 10-K Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

Signatures

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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.

2018 Notes

ACE
ADP
AFUDC
ALJ
AQCS
ARO
ASC
ASC 606
ASC 715
ASC 718
ASC 820
ASC 980
ASM
ASU
BTD
CAA
CCMC
CCR
CIP
CO2
CON
CPP
CSAPR
CWIP
D.C. Circuit

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

GHG
Impulse
IRP
JPMS
kV
kW

February 2018 issuance of $100 million in
privately placed 4.07% Senior Unsecured Notes
due February 7, 2048
Affordable Clean Energy
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 715—Compensation—Retirement Benefits
ASC Topic 718—Compensation—Stock Compensation
ASC Topic 820—Fair Value Measurement
ASC Topic 980—Regulated Operations
Ancillary Services Market
Accounting Standards Update
BTD Manufacturing, Inc.
Clean Air Act
Coyote Creek Mining Company, L.L.C.
Coal Combustion Residuals
Conservation Improvement Program
carbon dioxide
Certificate of Need
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
Generally Accepted Accounting Principles in the
United States
Greenhouse Gas
Impulse Manufacturing, Inc.
Integrated Resource Plan
J.P. Morgan Securities LLC
kiloVolt
kiloWatt

kwh
LSA
MATS
MISO
MISO Tariff

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
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

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

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
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
Solar renewable energy credits
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

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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 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 4150 19th Avenue
South, Suite 101, 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). These reports are also
available on the SEC’s website (www.sec.gov). Information on the
Company’s and the SEC’s websites 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 2,321 full-time
employees at December 31, 2018. 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.

(cid:1) 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 maintains a moderate risk profile by investing in rate
base growth opportunities in its Electric segment and organic growth
opportunities in its manufacturing platform, which includes its
Manufacturing and Plastics segments. This strategy and risk profile is
designed to provide a more predictable earnings stream, maintain the
Company’s credit quality and preserve its ability to fund the dividend.
The Company’s goal is to deliver annual growth in earnings per share
between five to seven percent over the next several years, using 2018
diluted earnings per share 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. 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 continue to be a fundamental part of its
strategy. The actual mix of earnings in 2018 was 66% from the electric
utility and 34% from the manufacturing and plastic pipe businesses,
including unallocated corporate costs.

The chart below indicates the companies included in each of the

The Company maintains criteria in evaluating whether its operating

Company’s reporting segments.

ELECTRIC

MANUFACTURING

PLASTICS

Otter Tail Power
Company

BTD
Manufacturing, Inc.

Northern Pipe
Products, Inc.

companies are a strategic fit. The operating company should:
(cid:1) Maintain a threshold level of net earnings and a return on invested
capital in excess of the Company’s weighted average cost of capital.
(cid:1) Have a strategic differentiation from competitors and a sustainable

cost advantage.

(cid:1) Operate within a stable and growing industry and be able to quickly

T.O. Plastics, Inc.

Vinyltech Corporation

adapt to changing economic cycles.

(cid:1) 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.

(cid:1) 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.

(cid:1) Have a strong management team committed to operational and

commercial 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 33 through 48 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 64 through 65
of this Annual Report on Form 10-K.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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
49%, 51% and 53% of its consolidated operating revenues and 68%, 72%
and 81% of its consolidated operating income from its Electric segment
for the years ended December 31, 2018, 2017 and 2016, respectively.
The breakdown of retail electric revenues by state is as follows:

State

Minnesota
North Dakota
South Dakota

Total

2018

52.6%
38.6
8.8

2017

52.8%
38.5
8.7

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 2018,
about 63% 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 December 31, 2018:

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)

62,400 kW
21,000
19,500

102,900 kW

80,000 kW

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

100.0%

OTP has a direct control load management system which provides

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, 2018,
OTP served 132,448 customers. Although there are relatively few large
customers, sales to commercial and industrial customers are significant.
One customer accounted for 11% of 2018 Electric segment revenue.
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.

Customer Category

Commercial
Residential
Industrial
All Other Sources

Total

2018

37.0%
32.5
30.0
0.5

2017

35.2%
31.1
31.8
1.9

100.0%

CAPACITY AND DEMAND
As of December 31, 2018, OTP’s owned net-plant dependable kilowatt
(kW) capacity was:

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 2018-2019 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 2019 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 transported by rail.

The following table shows the sources of energy used to generate

OTP’s net output of electricity for 2018 and 2017:

2018

Net kwhs
Generated

% of Total
kwhs
(Thousands) Generated

2017
Net kwhs % of Total
kwhs
Generated
(Thousands) Generated

1,891,394
1,080,639
494,394
70,015

3,536,442

53.5% 1,440,017
920,451
30.5
534,474
14.0
36,703
2.0

49.1%
31.4
18.2
1.3

100.0% 2,931,645

100.0%

Sources

Subbituminous Coal
Lignite Coal
Wind and Hydro
Natural Gas and Oil

Total

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

256,400 kW
151,100
141,000

548,500 kW

106,200 kW

2,900 kW

49,500 kW
48,000
40,500

138,000 kW

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

OTP has the following primary coal supply agreements:

A breakdown of electric rate regulation by each jurisdiction follows:

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, 2020

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

OTP and its Big Stone Plant co-owners entered into the current coal

purchase agreement with Peabody COALSALES, LLC in May 2018 for
the purchase of subbituminous coal for Big Stone Plant’s coal
requirements through December 31, 2020. There is no fixed minimum
purchase requirement under this agreement but all of Big Stone
Plant’s coal requirements for the period covered must be purchased
under this agreement, except for the portion to be purchased in 2019
under the agreement with Contura Coal Sales, LLC.

In October 2012 OTP and its Coyote Station co-owners 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 Coyote Station’s coal requirements for the period
May 2016 through 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. There are no fixed minimum
purchase requirements under this agreement.

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 for the years 2018,
2017, and 2016 was $1.977, $2.224 and $2.146, respectively.

TRANSMISSION REVENUES
OTP earns significant revenues from the transmission of electricity
for others over the transmission assets it separately owns, or jointly
owns with other transmission service providers, under rate tariffs
established by MISO and approved by the Federal Energy Regulatory
Commission (FERC).

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.

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Rates

Regulation

2018

2017

% of
Electric
Revenues

% of
% of
Electric
kwh
Sales Revenues

% of
kwh
Sales

MN Retail Sales MN Public Utilities

46.2% 54.1%

46.4% 54.0%

Commission

ND Retail Sales ND Public Service

33.9

36.8

33.9

37.1

Commission

SD Retail Sales SD Public Utilities

7.7

9.1

7.7

8.9

Commission
Federal Energy
Regulatory Commission

Transmission
& Wholesale

Total

12.2

—

12.0

—

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 electric bill.
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 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. Minnesota has made changes to
its fuel and purchased power cost recovery mechanism that will take
effect January 1, 2020 (see discussion under Fuel and Purchased
Power Costs Recovery below).

2017 TAX CUTS AND JOBS ACT (TCJA)
The TCJA, passed in December 2017, reduced the federal income tax
rate from 35% to 21% effective January 1, 2018 for the Company. At the
time of passage, all OTP rates had been developed using a 35% tax rate.
In 2018, the Minnesota Public Utilities Commission (MPUC), the North
Dakota Public Service Commission (NDPSC), the South Dakota Public
Utilities Commission (SDPUC) and the FERC each initiated dockets or
proceedings to begin working with utilities to assess the impact of the
lower income tax rate on electric rates, and to develop regulatory
strategies to incorporate the tax change into future rates, if warranted.
The MPUC required regulated utilities providing service in Minnesota

to make filings by February 15, 2018. On December 5, 2018 the MPUC
issued its final order related to the TCJA docket, which directed OTP to
return to ratepayers, in a one-time refund, the TCJA-related savings
accrued prior to the refund effective date. The order also directed OTP
to use these savings to reduce customers’ base rates prospectively—
allocating the savings to customers in proportion to the size of each
customer’s bill, or to each customer class in proportion to the class’s

size. OTP expects the rate change and refund to occur in the second
quarter of 2019, pending MPUC approval of OTP’s January 3, 2019
compliance filing. As described below, OTP’s current general rate cases
in North Dakota and South Dakota reflect the impact of the TCJA.

OTP has accrued refund liabilities for the time period when revenues
were collected under rates set to recover higher levels of federal income
taxes than OTP incurs under the lower federal tax rates in the TCJA. As
of December 31, 2018, accrued refund liabilities related to the tax rate
reduction were $8.4 million in Minnesota, $0.8 million in North Dakota
for amounts collected reflecting the higher tax rate under interim rates
in effect in January and February 2018, $1.0 million in South Dakota billed
prior to October 18, 2018, and $0.2 million for FERC jurisdictional rates.
On March 15, 2018, the FERC granted the request for waiver from a
group of MISO transmission operators (including OTP) to revise inputs
to their projected net revenue requirements for the 2018 rate year to
reflect TCJA impacts.

ELECTRIC SEGMENT 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.

Merricourt Project—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 and certain specified
liabilities associated with a 150-megawatt (MW) wind farm in south-
eastern North Dakota (the Merricourt Project) for a purchase price of
approximately $34.7 million, subject to adjustments for interconnection
costs. The Purchase Agreement will close on satisfaction of various
closing conditions (including regulatory approvals). Also on November 16,
2016, OTP entered into a Turnkey Engineering, Procurement and
Construction Services Agreement with EDF pursuant to which EDF will
develop, design, procure, construct, interconnect, test and commission
the wind farm with a targeted completion date in 2020 for consideration
of approximately $200.5 million, subject to certain adjustments, payable
following the closing of the Purchase Agreement in installments in
connection with certain project construction milestones. Depending
on the timing of MISO interconnection approval, construction of the
Merricourt Project is currently anticipated to begin in mid-2019. The
agreements contain customary representations, warranties, covenants
and indemnities for this type of transaction. As of December 31, 2018,
OTP had capitalized approximately $4.9 million in development costs
associated with the Merricourt Project. A final order for an Advance
Determination of Prudence (ADP), subject to qualifications and
compliance obligations, and a Certificate of Public Convenience and
Necessity were issued by the NDPSC on November 3, 2017. On
October 26, 2017 the MPUC approved the facility under the Renewable
Energy Standard making the Merricourt Project eligible for cost
recovery under the Minnesota Renewable Resource Recovery rider,
subject to qualifications and reporting obligations.

capitalized approximately $8.3 million in development costs associated
with Astoria Station. On August 3, 2018 the SDPUC issued an order
granting a site permit for Astoria Station. A final order granting ADP
for Astoria Station was issued by the NDPSC on November 3, 2017,
subject to certain qualifications and compliance obligations. The
interconnection agreement for Astoria Station was executed by MISO
in December 2018 and accepted by the FERC in January 2019. In a
September 26, 2018 hearing the NDPSC approved an overall annual
revenue increase for OTP and established a Generation Cost Recovery
rider for future recovery of costs incurred for Astoria Station.

Big Stone South–Ellendale Multi-Value Transmission Project (MVP)—
This is a 345 kiloVolt (kV) transmission line that extends 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., and the parties will have equal ownership
interest in the transmission line portion of the project. The 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 MISO 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 the
line was energized on February 6, 2019. OTP’s capitalized costs on this
project as of December 31, 2018 were approximately $106 million,
which includes assets that are 100% owned by OTP.

Big Stone South–Brookings 345-kV MVP—OTP invested approximately
$73 million (including assets that are 100% owned by OTP) and has a
50.0% ownership interest in the jointly-owned assets of this 70-mile
transmission line energized in 2017.

Recovery of OTP’s major transmission investments is through the
MISO Tariff and, currently, Minnesota, North Dakota and South Dakota
base rates and 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

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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.

General Rates—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 (ROE) decreased from 10.74% to 9.41%. The MPUC denied
OTP’s request for reconsideration of certain of the MPUC’s rulings
in the rate case.

OTP accrued interim and rider rate refunds until final rates became
effective. The final interim rate refund, including interest, of $9.0 million
was applied as a credit to Minnesota customers’ electric bills beginning
in November 2017. In addition to the interim rate refund, OTP refunded
the difference between (1) amounts collected under its Minnesota ECR
and TCR riders based on the 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. 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 were refunded to Minnesota
customers over a 12-month period beginning in November 2017 through
reductions in the Minnesota ECR and TCR rider rates. The TCR rider
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
Certificate of Need (CON) hearings, rate reviews and other proceedings.
Typically, resource plans 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:
(cid:1) The addition of 200 MW of wind resources in the 2018 to 2020

timeframe.

(cid:1) The addition of 30 MW of solar resources by 2020 to comply with

Minnesota’s Solar Energy Standard.

(cid:1) The addition of up to 250 MW of peaking capacity in 2021.
(cid:1) Average annual energy savings of 46.8 gigawatt-hours

(1.6% of retail sales).

(cid:1) Modification of OTP’s IRP to include an additional 100 MW to 200

MW of wind in the 2022 to 2023 timeframe.

On November 29, 2018 the MPUC extended the deadline for OTP’s next
IRP filing from June 3, 2019 to June 1, 2020. The MPUC order cited two

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

key environmental regulations for which the impacts on OTP facilities
are not yet ascertainable: the federal Regional Haze Rule promulgated by
the Environmental Protection Agency (EPA) in 1999 and the Affordable
Clean Energy (ACE) Rule proposed by the EPA in August 2018.

Fuel and Purchased Power Costs Recovery—The MPUC has issued an
order authorizing the implementation of a new fuel clause adjustment
mechanism to be implemented January 1, 2020. Prior to implementation,
OTP will be required to submit forecasted monthly fuel cost rates for
the twelve-month period beginning January 1, 2020. On approval by
the MPUC, those rates will be published in advance of each year to give
customers notice of the next year’s 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,
be required to show prudence of costs incurred over forecast before
being authorized recovery. The refund of any over-collection or recovery
of any under-collection would be handled through a true-up mechanism.
OTP is working with other Minnesota utilities, the MNDOC and other
stakeholders to address questions and further develop the mechanism
prior to implementation.

On MPUC finalization of an order implementing the mechanism,
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 most recent
rate case or annual fuel cost adjustment filing preceding the annual
period of recovery. OTP will continue to accrue revenue and a regulatory
asset for fuel and purchased power costs incurred in excess of amounts
recovered under the adjustment mechanism unless and until recovery
of those excess amounts are deemed not prudent and recovery is not
granted through the true-up mechanism in a subsequent order by the
MPUC. This mechanism could result in reductions in Electric segment
operating income margins and could increase variability in consolidated
net income in future periods if costs per kwh vary from forecasted
costs per kwh and recovery of all or a portion of excess costs is denied
by the MPUC.

Renewable Energy Standards, Conservation, Renewable Resource
Riders—Minnesota law favors energy conservation and load-management
measures over the addition of new generation 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. Minnesota 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 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 $5.00 to $25.00 per ton of CO2 commencing
in 2025. The MPUC is required to annually update these estimates.

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
sufficient solar renewable energy credits (SRECs) to meet 100 percent
of its 2020 obligation and approximately 70% of its 2021 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 enough renewable resources to comply
with current requirements under 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 2022. 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.

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 included as 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. The financial incentive is also limited to 40%
of 2017 MNCIP spending, 35% of 2018 spending and 30% of 2019
spending. The new model reduces the MNCIP financial incentive by
approximately 50% compared to the previous incentive mechanism.
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 a decrease in energy savings compared to 2016 program results of
approximately 10%. OTP requested approval for recovery of its 2017
MNCIP program costs not included in base rates on March 30, 2018.
The request included a $2.6 million financial incentive and an update
to the MNCIP surcharge from the MPUC. On June 13, 2018, in reply
comments to a MNDOC recommendation for approval filed on May 30,
2018, OTP increased its request for a financial incentive to $2.9 million.
On October 4, 2018, the MPUC issued an order approving OTP’s
request of $2.9 million with an effective date of November 1, 2018,
subject to further review by the MPUC to ensure no previous decisions
conflict with the decision, with $0.3 million subject to possible refund.
Based on results from the 2018 MNCIP program year, OTP recognized
$3.0 million out of a potential $3.15 million in financial incentives earned
in 2018. OTP will request approval for recovery of its 2018 program
costs not included in base rates, a $3.15 million financial incentive and
an update to its MNCIP surcharge from the MPUC by April 1, 2019.

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
required 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, the 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 authorizes the MPUC
to approve 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 that are 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 most recently completed general rate case or such other rate

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of return the MPUC determines is in the public interest. Additionally,
following approval of a 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.

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 MVPs 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 diverted
interstate wholesale revenues approved by the FERC to offset
FERC-approved expenses, effectively reducing OTP’s recovery of those
FERC-approved expense levels. The MPUC-ordered treatment resulted
in the projects being treated as retail investments for Minnesota retail
ratemaking purposes. Because the FERC’s revenue requirements and
authorized returns vary from the MPUC revenue requirements and
authorized returns for the project investments over the lives of the
projects, the impact of this decision can 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 jurisdictionally
allocate costs of the FERC MVP transmission projects in the TCR rider.

On June 11, 2018 the Minnesota Court of Appeals reversed the
MPUC’s order related to the inclusion of Minnesota’s jurisdictional
share of OTP’s investment in the Big Stone South–Brookings and Big
Stone South–Ellendale MVPs and all revenues received from other
utilities under MISO’s tariffed rates as a credit in OTP Minnesota TCR
revenue requirement calculations. On July 11, 2018 the MPUC filed a
petition for review of the MVP decision to the Minnesota Supreme
Court, which has granted review of the Minnesota Court of Appeals
decision. A decision by the Minnesota Supreme Court is expected in
either second or third quarter 2019.

On November 30, 2018 OTP filed its annual update and supplemental

filing to the Minnesota TCR rider. In this filing two scenarios were
submitted based on whether the Minnesota Supreme Court affirms
the original decision by the Minnesota Court of Appeals to exclude the
MVP projects from the TCR rider or overturns the Minnesota Court of
Appeals decision and includes the two MVP projects in the TCR rider. In
both situations the rates are proposed to be effective June 1, 2019 if a
decision is made in late first quarter or early second quarter 2019. If
the decision is made later than second quarter of 2019, it is likely the
MPUC will delay its decision on the TCR rider update. The amount

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credited to Minnesota customers under the TCR through December 31,
2018 and subject to recovery if the Minnesota Court of Appeals
decision is upheld, is approximately $2.3 million.

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 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. 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 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. Accordingly, in its 2018
annual update filing OTP requested, and the MPUC approved, setting
the Minnesota ECR rider rate to zero effective December 1, 2018.

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

Capital Structure Petition—Minnesota law requires an annual filing
of a capital structure petition with the MPUC. In this filing the MPUC
reviews 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 October 18, 2018, allowing for
an equity-to-total-capitalization ratio between 47.9% and 58.5%, with
total capitalization not to exceed $1,204,416,000 until the MPUC issues
a new capital structure order for 2019. OTP is required to file its 2019
capital structure petition no later than May 1, 2019.

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 and routes in
North Dakota for large electric generating facilities and high voltage
transmission lines, respectively. 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 also
required to submit a ten-year facility 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.

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%. The requested
$13.1 million increase was net of reductions in North Dakota Renewable
Resource Adjustment (NDRRA), TCR and ECR rider revenues that would
have resulted from a lower allowed rate of return on equity and changes
in allocation factors in the general rate case. 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. In response to
the reduction in the federal corporate tax rate under the TCJA, the
NDPSC issued an order on February 27, 2018 reducing OTP’s annual
revenue requirement for interim rates by $4.5 million to $8.3 million,
effective March 1, 2018.

On March 23, 2018 OTP made a supplemental filing to its initial
request for a rate review, reducing its request for an annual revenue
increase from $13.1 million to $7.1 million, a 4.8% annual increase. The
$6.0 million decrease included $4.8 million related to tax reform and
$1.2 million related to other updates.

In a September 26, 2018 hearing the NDPSC approved an overall
annual revenue increase of $4.6 million (3.1%) and a ROE of 9.77% on a
52.5% equity capital structure. This compares with OTP’s March 2018
adjusted annual revenue increase request of $7.1 million (4.8%) and a
requested ROE of 10.3%. The NDPSC’s approval does not require any
rate base adjustments from OTP’s original request and establishes a
Generation Cost Recovery rider for future recovery of costs incurred
for Astoria Station. The net revenue increase reflects a reduction in
income tax recovery requirements related to the TCJA and decreases
in rider revenue recovery requirements. Final rates will be effective
February 1, 2019, with refunds of excess revenues collected under
interim rates applied to customers’ April 2019 bills. OTP has accrued
an interim rate refund of $3.0 million as of December 31, 2018, which
includes the $0.8 million in excess revenue collected for income taxes
under interim rates in effect in January and February 2018.

Renewable Resource Adjustment—OTP has a NDRRA rider 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. 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 (PTCs) used. The NDPSC approved the NDRRA 2015
annual update on June 22, 2016 with an effective date of July 1, 2016.
The updated NDRRA reflected a reduction in the ROE component of
the rate from 10.75%, approved in OTP’s 2008 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 and the NDRRA
rate increased from 7.005% to 7.756% with an effective date of
January 1, 2018. A reset of the NDRRA rate to reflect the effect of the
federal corporate tax rate reduction under the TCJA was approved on
February 27, 2018, reducing the NDRRA rate to 7.493%, effective
March 1, 2018.

In a filing to the NDPSC on December 31, 2018 OTP requested approval
for an annual update to its NDRRA rider rate to -0.224% of base charges,
based on an annual refund requirement of $236,000, to be effective
for bills rendered on and after April 1, 2019. The refund requirement
results from recovery of the Ashtabula, Langdon, and Luverne wind
projects being moved into base rates as of December 31, 2018 as well as
a reduction in revenue requirements related to the difference between
the deferred tax asset for PTCs included in base rates and actual
amounts associated with the Ashtabula and Langdon wind projects.

Effective in February 2019 with the implementation of general rates

based on the results of OTP’s 2017 general rate case, recovery of
renewable resource costs previously being recovered through the
North Dakota RRA rider transitioned to recovery in base rates.

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. Based on the order in the general rate case,
only certain costs will remain subject to refund or recovery through
this rider: Southwest Power Pool (SPP) costs and MISO Schedule 26
and 26A revenues and expenses and costs related to rider projects still
under construction in the test year used in the 2017 general rate case.
This rider will continue to be updated annually for new or modified
electric transmission facilities and associated operating costs.

On September 1, 2016 OTP filed its annual update to the TCR rider
requesting a revenue requirement of $5.7 million, including a reduction
of $2.6 million for a projected over-collection for 2016. Primary drivers
of a 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 two
succeeding years to reduce the volatility 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 made a
supplemental filing on November 2, 2017, reducing its request by
$0.6 million to $8.0 million to reflect the rate of return and allocation
factors used in its general rate case filed the same day. The NDPSC
approved the update for recovery of the $8.0 million revenue
requirement on November 29, 2017 and the new rates went into effect
on January 1, 2018. A reset of the TCR rate to reflect the effect of the
federal corporate tax rate reduction under the TCJA was approved on
February 27, 2018, reducing annual revenue recovery under the TCR
rate by $0.5 million effective March 1, 2018.

On August 31, 2018 OTP filed its annual update to the TCR rider. The

filing included three new projects along with updates to collections,
actual costs and forecasted amounts for rider-eligible projects. The
filing also reflected projects moving to base rates proposed to become
effective in October 2018, in the above-described general rate case.
On November 7, 2018 OTP filed a supplement to the TCR rider update
indicating two of the three new projects had been postponed and the

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

roll-in of rider costs to base rates was calculated based on a change to
January 1, 2019. The update request was approved by the NDPSC on
December 6, 2018 and the updated rates went into effect with bills
rendered on or after February 1, 2019 to coincide with the launch of
OTP’s new customer information and billing system.

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 Toxic Standards (MATS)
projects. The ECR rider has provided for a return on investment at the
level approved in OTP’s preceding general rate case and for recovery
of OTP’s North Dakota share of reagent and emission allowance 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 August 1, 2017. 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 and 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. A reset of the ECR rate to reflect the effect of the federal corporate
tax rate reduction under the TCJA was approved on February 27, 2018,
reducing the ECR rate to 5.593%, effective March 1, 2018.

Based on the order in the 2017 general rate case, project costs

previously being recovered under the rider will be recovered in base rates
and reagent and emission allowance costs will be recovered through the
energy adjustment rider. The rider was zeroed out at the implementation
of final rates on February 1, 2019, except for an overcollection balance
that will be refunded to ratepayers through the rider.

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.

General Rates—On April 20, 2018 OTP filed a request with the SDPUC
to increase non-fuel rates in South Dakota by approximately $3.3 million
annually, or 10.1%, as the first step in a two-step request. Interim rates
went into effect October 18, 2018. On February 5, 2019 SDPUC staff
and OTP requested that the SDPUC issue a procedural schedule setting
evidentiary hearings for March 26-28, 2019. The full effects of the TCJA
on South Dakota revenue requirements will be addressed in the rate
case and incorporated into final rates at the conclusion of that case.
The second step in the request is an additional 1.7% increase to recover
costs for the proposed Merricourt wind generation facility when the
facility goes into service. On February 15, 2019 the Company reached a
partial settlement with SDPUC staff which requires SDPUC approval.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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. 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 federal corporate income tax rate
under the TCJA. The updated annual revenue requirement request was
$1.8 million. Effective October 18, 2018, with the implementation of
interim rates under South Dakota general rate case proceedings, the
TCR rate was decreased to reflect an annual revenue requirement of
$1.2 million as a result of certain costs being transitioned to recovery
through interim rates and proposed for ongoing recovery in final base
rates at the conclusion of the pending general rate case.

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, 2016 OTP filed its
2016 update to the ECR rider, requesting recovery of approximately
$2.2 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.
Effective October 18, 2018, with the implementation of interim rates
under South Dakota general rate case proceedings, the ECR rate was
decreased to -$0.00075/kwh to refund $0.2 million previously collected
under the rider, and the ECR-eligible costs are proposed for ongoing
recovery in final base rates at the end of the 2018 general rate case
described above.

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

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.

On May 1, 2018, OTP filed its 2017 South Dakota EEP Status Report,
financial incentive, and surcharge adjustment with the SDPUC. The filing
requested approval of an incentive of $134,700 and an increase in the
EEP surcharge from $0.00138/kwh to $0.00155/kwh effective
July 1, 2018. The SDPUC approved the request on June 26, 2018. On
September 21, 2018 OTP filed a modification to its 2016-2019 EEP Plan.
This modification requested an additional $250,000 annually for three
years starting in 2019. The increased budget was requested to pay
additional rebates for a large customer that is planning to make
significant energy efficiency investments in its expanding facilities.
On December 11, 2018, the SDPUC approved the request.

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 suspension period, subject to ultimate
approval by the FERC.

MVPs—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.

Transmission Tariff ROE Complaints—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%. Several parties
requested rehearing of the September 2016 order and the requests are
pending FERC action.

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 was 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, 2018.

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 U.S. Court of
Appeals for the District of Columbia Circuit (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 NETOs complaint.
The motion is currently pending before the FERC.

On October 16, 2018 the FERC issued an order proposing a

methodology for addressing the issues that were remanded to the
FERC by the D.C. Circuit in April 2017. The FERC order established a
paper hearing on how the methodology should apply to the proceedings
pending before the FERC involving NETOs’ ROE. In the order, the FERC
selected a preliminary just and reasonable ROE for NETOs of 10.41%,
exclusive of incentives, with a proposed cap on any pre-existing
incentive-based total ROE at 13.08% and directed participants to
submit supplemental briefs and additional written evidence regarding
the proposed approaches to the Federal Power Act Section 206 inquiry
and how to apply them to the NETO ROE complaints. On November 15,
2018 the FERC issued an order establishing a paper hearing on whether
and how a two-step ROE methodology developed for NETOs should
apply to the ROE for the MISO transmission owners. Initial briefs were
due February 13, 2019 and reply briefs are due April 10, 2019.

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

OTP believes its estimated accrued MISO Tariff ROE refund liability

OTP, filed for a FERC incentive of an additional 50 basis points for
Regional Transmission Organization participation (RTO Adder). On

of $1.6 million as of December 30, 2018 related to the second MISO
tariff ROE complaint is appropriate.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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 has regulatory authority spanning the United States, Canada and
the northern portion of Baja California, Mexico, and is subject to
oversight by the FERC and governmental authorities in Canada. NERC’s
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. MRO’s current audit of OTP began with notification in
October 2018. The final report is not expected for several months.

MISO
OTP is a member of the MISO. The MISO operates the transmission
facilities owned by others and administers energy and generation
capacity markets. As the transmission provider and security
coordinator for the region, the MISO seeks to optimize the efficiency
of the interconnected system, provide 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 including 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 day-ahead and real-time 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. The 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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 currently participating in a Distributed Generation (DG)

Workgroup in Minnesota in a docket established by the MPUC.
Distributed energy resources are utility- or customer-owned resources
on the distribution grid that can include combined heat and power, solar
photovoltaic, wind, battery storage, thermal storage, and demand-
response technologies. DG is the generation of electricity on-site or
close to where it is needed in small facilities designed to meet local
needs. Advances in technology and economics are contributing to
increasing interest in DG in Minnesota and consumer requests for DG
will likely grow. OTP is working to accurately identify and quantify the
impacts (including costs and values) of DG; this can be difficult because
the impacts of DG vary geographically and over time.

In 2011 the FERC required some electric transmission providers,
including the MISO, to remove from their tariffs a federal right of first
refusal to construct transmission facilities selected in a regional
transmission plan for purposes of cost allocation. However, state
laws allowing rights of first refusal to construct electric transmission
infrastructure still exist in Minnesota, North Dakota and South Dakota.
OTP and other Minnesota electric transmission owners (Amici Utilities)

are involved in a federal lawsuit and subsequent 8th Circuit appeal
filed by LSP Transmission Holdings, LLC (LSP) challenging a Minnesota
statute granting incumbent electric transmission owners a right of first
refusal to construct new transmission facilities connected to existing
facilities. LSP has argued that the Minnesota law violates the dormant
Commerce Clause of the U.S. Constitution. A federal district court
rejected that argument, and LSP appealed. The Amici Utilities support
the Minnesota right of first refusal law as a reasoned policy judgment
by the State of Minnesota and thus not subject to challenge under the
dormant Commerce Clause. The appeal is currently being briefed, and
it is unknown at this time when a decision will be issued.

OTP has been involved in a MISO process re-establishing the right of
transmission owners to elect the initial funding of electric transmission
projects required to support the interconnection of the generator’s

project to the MISO transmission system. In 2018 the D.C. Circuit
vacated earlier FERC orders limiting transmission owners’ initial funding
of transmission upgrade projects required by generator interconnections.
As a result, the MISO Tariff and related agreements establish once again
that MISO transmission owners have the discretion to initially fund the
construction of certain qualifying interconnection-related transmission
upgrades. Thus, the Company, as a MISO transmission owner, can invest
the initial capital for such qualifying upgrades and earn a return on
and of the capital investment from interconnection customers.

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, 2018 OTP invested approximately
$120.4 million in environmental control facilities. The 2019 and 2020
construction budgets include approximately $4.2 million and $0.3 million,
respectively, for environmental equipment for existing facilities.
Additional expenditures may be required depending on the outcome
of various environmental regulations currently under consideration
for implementation, and such expenditures could be material.

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
sources. All of OTP’s generating facilities met the NOx standards
during 2018.

The Cross-State Air Pollution Rule (CSAPR) requires SO2 and NOx

emission reductions in primarily eastern states in order to allow
downwind 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. Hoot Lake met the CSAPR requirements in 2018 without acquiring
additional allowances.

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.
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
proceeded under several different pathways. For certain large sources,
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 is located.

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 December 28, 2018 EPA issued
a proposed rule that provides that it is not “appropriate and necessary”
to regulate hazardous air pollutants from power plants; however, EPA
concludes that this new finding would not cause it to rescind MATS.
The proposed rule also addresses the CAA requirement to conduct a
risk and technology review for power plants, which concludes no
revisions to MATS are warranted.

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 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 CAA establishes a national
visibility goal to prevent any future, and remedy any existing,
anthropogenic visibility impairment in Class I air quality areas. The
EPA’s Regional Haze Rule (RHR), as adopted in 1999 and revised most
recently on January 10, 2017, implements the CAA’s visibility protection
provisions. The RHR requires states to determine the consistent rate of
progress over time necessary to attain natural visibility conditions on
the twenty percent most anthropogenically impaired days by the
year 2064. The first RHR implementation period covered the years
2008-2018 and focused on applying Best Available Retrofit Technology
(BART) to certain large stationary sources that were in existence on

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August 7, 1977 but were not in operation before August 7, 1962.
Big Stone Plant was determined to be subject to BART, and therefore
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. Coyote Station is not
a BART-eligible source but was ultimately required to install separated
over-fire air to reduce NOx emissions as a reasonable progress source.
The second RHR implementation period will cover the years 2018-
2028, with state implementation plans (SIPs) due to be submitted to
EPA by July 31, 2021. For this second period, states are required to
assess reasonable progress with the RHR and determine whether
additional emission reductions are needed. As part of this assessment,
the North Dakota Department of Health requested that Coyote Station
provide an analysis of technically feasible SO2 and NOx emissions
control options, which OTP provided in January 2019. EPA is continuing
to develop other implementation tools that will be needed by states
for the second period, including producing 2028 visibility modeling
results, estimating international source contributions, and developing
updated guidance on SIP development. Therefore, additional control
measures and related costs required at Coyote Station for the second
RHR implementation period remain uncertain but could be material.

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 2018
these plants emitted approximately 3.7 million (short) 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.
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 NSPS under section 111(b)
of the CAA that require 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

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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 cleaner
fuels such as natural gas. On December 20, 2018 the EPA proposed
revisions to the 2015 NSPS; however, the revisions would only impact
the standards for new, reconstructed, and modified coal or coal-refuse
steam generating units. No changes are being proposed to the NSPS
for natural gas combustion turbines.

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” that limits the emission of air pollutants using what
the EPA determines to be the best system of emission.

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 Section 111(d) emission
guidelines for existing fossil fuel-fired power plants, termed the Clean
Power Plan (CPP). The CPP 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 August 21, 2018 the EPA proposed a
replacement for the CPP—the ACE Rule. Among other things, the
ACE Rule determines that the best system of emission reduction for
greenhouse gas emissions from coal-fired power plants are heat rate
improvement measures, identifies a list of “candidate technologies” for
improving a plant’s heat rate, and proposes changes to the New
Source Review program. OTP submitted comments on the ACE Rule
and it is anticipated that a final rule will be issued in 2019.

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 2018
and 2019 the range is $5 to $25 per ton, and the applicable effective
date to begin using CO2 costs in resource planning decisions is 2025.

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. The costs are updated periodically. The most
recent 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.

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:
(cid:1) Supply efficiency and reliability: Since 2005, SO2, NOx and mercury
emitted from OTP’s fossil fuel-fired plants have decreased 42%, 69%
and 80%, respectively. OTP’s efforts to increase plant efficiency and
add renewable energy to its resource mix have reduced its CO2
intensity. Between 2005 and 2018 OTP decreased its overall system
average CO2 emissions intensity by approximately 21%. Further
reductions are expected with the planned addition of the Merricourt
Wind Project and replacement of Hoot Lake Plant generation with
the Astoria Station natural gas-fired generation plant in the 2021
timeframe.

(cid:1) Conservation: Since 1992 OTP has helped its customers conserve more
than 4.7 million cumulative megawatt-hours of electricity, which is
roughly equivalent to the amount of electricity that 398,500 average
homes would use in a year and represents approximately 389% of
the annual energy sales of OTP’s entire residential customer base.
(cid:1) 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. Minnesota’s legislative mandate requires
investor-owned utilities to serve 1.5% of their Minnesota retail electric
sales with solar power by 2020. OTP has purchased sufficient SRECs
to meet 100% of its 2020 obligation and approximately 70% of its
2021 obligation. OTP is exploring options for constructing a solar
project to meet its continuing obligation after 2021.

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 or other emissions is unknown at this
time, any capital and operating costs incurred for additional pollution
control equipment or 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, now known as the Clean Water Act, 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,
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’s
NPDES permit was renewed in 2018 with minimal impact 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 a 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.

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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 rule has required OTP to complete certain actions, such
as installing additional groundwater monitoring wells and investigating
whether existing surface impoundments should be retired or retrofitted
with liners. The Big Stone Plant surface impoundment was closed by
removing all CCR material and replaced with new ash handling
technology in 2018. A similar project is expected to be completed at
Coyote Station in 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
In order to meet customer needs, OTP is continually expanding,
replacing and improving its electric facilities. During 2018 approximately
$87 million in cash was invested for additions and replacements to its
electric utility properties. During the five years ended December 31, 2018
gross electric property additions, including CWIP, were approximately
$635 million and gross retirements were approximately $90 million.
OTP estimates that during the five-year period 2019-2023 it will invest
approximately $973 million for electric construction, including:
(cid:1) $348 million for renewable wind and solar energy generation and
conservation, including the Merricourt Wind Project scheduled for
completion in 2020, the exercise of a purchase option on the
Ashtabula III wind farm in 2022, a major investment in solar
generation in 2022 and routine wind-power replacement projects.

(cid:1) $150 million for the Astoria natural gas-fired generation plant to

replace Hoot Lake Plant capacity.

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(cid:1) $145 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.

(cid:1) $122 million for transmission assets including new construction and
routine replacement projects. New construction includes $7.8 million
for the completion of the Big Stone South–Ellendale line in 2019.

The remaining $208 million of the 2019-2023 anticipated capital
expenditures is for asset replacements, additions and improvements
to OTP’s other generation, 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, 2018 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, 2018 OTP had 669 equivalent full-time employees.
A total of 394 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 29%, 27% and 28% of its consolidated operating

revenues and 14%, 11% and 11% of its consolidated operating income
from the Manufacturing segment for the years ended December 31,
2018, 2017 and 2016, 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.

During 2018, cash expenditures for capital additions in the Manufacturing
segment were approximately $13 million. Total capital expenditures for
the Manufacturing segment during the five-year period 2019-2023 are
estimated to be approximately $77 million.

EMPLOYEES
At December 31, 2018 the Manufacturing segment had 1,445 full-time
employees. There were 1,273 full-time employees at BTD and 172
full-time employees at T.O. Plastics as of December 31, 2018.

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, the top two customers
combined accounted for 33% and the top five customers combined
accounted for over 52% of 2018 Manufacturing segment revenue.

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 based on 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
Manufacturing segment. Additionally, a certain amount of residual
material (scrap) is a by-product 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 2019
revenues of approximately $211 million compared with $166 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.

PLASTICS

GENERAL
Plastics consists of businesses producing PVC pipe at plants in North
Dakota and Arizona. The Company derived 22%, 22% and 19% of its
consolidated operating revenues and 25%, 22% and 16% of its
consolidated operating income from the Plastics segment for the years
ended December 31, 2018, 2017 and 2016, 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, northwest
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 39% of
2018 Plastics segment revenue.

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 based
on 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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 three vendors that Northern Pipe and Vinyltech can
source to supply their PVC resin requirements. Two vendors provided
over 99% of total resin purchases in 2018 and 100% in 2017. The supply
of PVC resin may also be limited primarily due to manufacturing
capacity and the limited availability of raw material components. Most
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. In 2017, Hurricane Harvey caused major resin
suppliers in the Gulf Coast region to shut down production facilities
impacting raw material availability. 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 2018,
cash expenditures for capital additions in the Plastics segment were
approximately $4 million. Total capital expenditures for the five-year
period 2019-2023 are estimated to be approximately $20 million to
replace existing equipment.

EMPLOYEES
At December 31, 2018 the Plastics segment had 170 full-time
employees. Northern Pipe had 100 full-time employees and Vinyltech
had 70 full-time employees as of December 31, 2018.

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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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.

Borrowings under our $130 million revolving credit agreement and
OTP’s $170 million revolving credit agreement currently use LIBOR as
the base to determine the applicable interest rate to charge. LIBOR is
currently expected to be eliminated by January 1, 2022. The credit
agreements contain provisions to determine how interest rates will be
established in the event a replacement for LIBOR has not been identified
before the agreements expire on October 31, 2023. There is no assurance
that the replacement for LIBOR will be as favorable as LIBOR.

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, 2018. 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, 2018, 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 Otter Tail Corporation by requiring an equity-to-total-capitalization
ratio between 47.9% and 58.5% based on OTP’s 2018 capital structure
petition. OTP’s equity-to-total-capitalization ratio, including short-term
debt, was 53.2% as of December 31, 2018.

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, our business could be harmed.
The operation of our business is dependent on the secure function of
our computer hardware and software systems. Furthermore, all 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. Information
systems, both ours and those of third parties, are vulnerable to security
breach by computer hackers and cyber terrorists, and the negligent or
intentional breach of established controls and procedures or
mismanagement of confidential information by employees. We may
also be impacted by attacks and data security breaches of financial
institutions, merchants or third-party processors. While we regularly
conduct cybersecurity assessments, we cannot be certain our
information security systems and protocols and those of our vendors
and other third parties are sufficient to withstand a cyber-attack or
other security breach.

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. For example, we may
be subject to liability under various federal, state and international
data protections laws.

The misappropriation, corruption or loss of personally identifiable

information and other confidential data could lead to significant
monetary damages, regulatory enforcement actions and breach
notification and mitigation expenses such as credit monitoring and
result in reputational damage affecting relations with shareholders,
customers and regulators. 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 and we have adopted a disaster
recovery plan. Additionally, we’ve taken steps to increase cybersecurity
awareness among our employees through mandatory education and
training programs and through informational communications on
potential security threats and techniques used by hackers and cyber
criminals. However, all these measures and technology may not
adequately prevent security breaches or cyber-attacks or enable us to
recover effectively from such an attack. 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.

Like many other companies, we have been the target of malicious
cyber-attack attempts in the normal course of business. Although these
prior cyber-attacks have been limited in scope, have not interrupted
our business operations and have not had a material impact on our
financial results, this may not continue to be the case in the future.
Cybersecurity incidents involving businesses and other institutions are
on the rise, we believe these incidents are likely to continue and we are
unable to predict the direct or indirect impact of future attacks or
breaches to our business.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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.

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 our businesses through capital projects, including
infrastructure and new technology additions, or to grow or realign our
businesses through acquisitions or 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 the Company, 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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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 2018 one customer accounted for 11% of Electric
segment revenue, two customers accounted for a total of 33% of
Manufacturing segment revenue and two customers accounted for
39% 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.
Several 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.
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 utility business, 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. 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. 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.

In addition, energy policy initiatives at the state or federal level could

increase incentives for distributed generation or authorize municipal
utility formation or acquisition of service territory, or local initiatives
could introduce generation or distribution requirements that could
change the current integrated utility model.

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 and regulatory requirements; 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

and a disaster recovery plan 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. FERC has approved Version
5 of the Critical Infrastructure Protection Cybersecurity Standards. The
standards require us to categorize our cyber assets as high, medium
and low impact. As of December 31, 2018, all of these cyber assets
were in compliance with the standard. However, all these measures
and technology may not adequately prevent security breaches or
cyber-attacks or enable us to recover effectively from such a breach or
attack. 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
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 electricity for its customers, if available, and expose it to
higher purchased power costs.

Changes to regulation of generating plant emissions, including but not
limited to CO2 emissions and regional haze regulation under state
implementation plans, could affect our operating costs and the costs
of supplying electricity to our customers and the economic viability of
continued operation of certain of OTP’s steam-powered electric plants.
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 current administration on the direction and scope of U.S. and

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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. 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 CPP rule is not currently in effect as a result of a
stay by the U.S. Supreme Court granted in 2016. On August 21, 2018
the EPA proposed a replacement for the CPP—the ACE Rule. Among
other things, the ACE Rule determines the best system of emission
reduction for greenhouse gas emissions from coal-fired power plants is
to improve a plant’s heat rate, identifies a list of “candidate technologies”
for improving a plant’s heat rate and proposes changes to the New
Source Review program. The fate of the former administration’s GHG
rules is uncertain, as is the outcome of EPA’s potential GHG regulatory
actions under the current administration. The final outcome of this
rulemaking process could have a material adverse impact on our
business and financial results.

State implementation of pollution control plans to improve visibility

and air quality at national parks under the EPA’s Regional Haze Rule
could require us to incur significant new costs, which could negatively
impact our net income, financial position and operating cash flows. The
EPA is involved in ongoing litigation with states and regulated industries
regarding the adequacy of state implementation plans. However, in
September 2018, the EPA’s Regional Haze Reform Roadmap prioritized
giving more power to states to determine emissions controls and relying
on other Clean Air Act programs to improve visibility.

In certain circumstances, it may not be economically viable to install
and operate pollution control equipment at older generation facilities
in order to bring them into compliance with environmental laws and
regulations, including state implementation plans for the Regional Haze
Rule. In those circumstances, it may be necessary to pursue replacement
electric generation facilities as an alternative, which may require
incurring significant investment in new facilities and recording
significant asset impairment charges relating to replaced facilities,
in addition to obtaining necessary regulatory permits and approvals.

MANUFACTURING
Competition from foreign and domestic manufacturers, the price and
availability of raw materials, trade policy and tariffs affecting prices
and markets for raw material and manufactured products, 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 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 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 provided over 99% of our total
purchases of PVC resin in 2018 and 2017. In addition, the supply of
PVC resin may be limited primarily due to manufacturing capacity and
the limited availability of raw material components. Most 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 many 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 Griggs and Steele Counties, North
Dakota with a nameplate rating of 49,500 kW.

As of December 31, 2018, OTP’s transmission facilities, which are

interconnected with lines of other public utilities, consisted of 618
pole-miles of jointly owned 345 kV lines; 470 pole-miles of 230 kV lines,
of which 70 miles are jointly owned; 873 pole-miles of 115 kV lines; and
3,989 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 8 A N N UA L R E P O RT

ITEM 3A. Executive Officers of the Registrant (As of February 22, 2019)

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 (54)
Kevin G. Moug (59)
Timothy J. Rogelstad (52)
John Abbott (60)
Jennifer O. Smestad (48)

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

Mr. MacFarlane was elected as the Company’s President and Chief
Executive Officer and as member of the Company’s board of directors
on April 13, 2015. Prior to that, he served as President and Chief
Operating Officer of the Company, since April 14, 2014. Mr. MacFarlane
joined OTP in 2001, served as its President from 2003 to 2014 and has
served as its Chief Executive Officer from 2007 to the present. He
served as Senior Vice President, Electric Platform of the Company
from 2012 to 2014.

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

more than five years.

Timothy J. Rogelstad was appointed to succeed Mr. MacFarlane as

President of OTP and Senior Vice President, Electric Platform of the
Company on April 14, 2014. 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.

John Abbott was selected to serve as Senior Vice President,

Manufacturing Platform, and President of Varistar on February 5, 2015.
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.

Jennifer O. Smestad was appointed to the position of Vice President,

General Counsel and Corporate Secretary of the Company, effective
January 1, 2018. 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.

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 33 of this Annual Report on Form 10-K
under the heading “Selected Financial Data,” on Page 77 under the
heading “Retained Earnings and Dividend Restriction” and on Page 91
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, 2018.

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, 2013, and
reinvestment of all dividends).

OTC

EEI

NASDAQ

$250

$200

$150

$100

$50

2013

2014

2015

2016

2017

2018

OTC
EEI
Nasdaq

$ 100.00
$ 100.00
$ 100.00

$ 110.19
$ 128.91
$ 112.46

$ 99.12
$ 123.88
$ 113.00

$ 157.67
$ 145.48
$ 127.70

$ 177.14
$ 162.52
$ 155.01

$ 203.60
$ 168.49
$ 146.57

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

ITEM 6. Selected Financial Data

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

2018

2017

2016

2015

2014

Revenues
Electric

Revenues from Contracts with Customers
Changes in Accrued Revenues under Alternative Revenue Programs

$ 450,694
(439)

$ 436,508
(1,971)

$ 425,279
2,104

$ 410,109
(2,978)

$ 406,242
1,501

Total Electric Revenues
Manufacturing Revenues from Contracts with Customers
Plastics Revenues from Contracts with Customers
Intersegment Eliminations—Contracts with Customers

Total Operating Revenues

Revenues from Contracts with Customers
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 Per Common Share
Dividend Payout Ratio
Common Shares Outstanding—Year End
Number of Common Shareholders (3)

450,255
268,409
197,840
(57)

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)

$ 916,447

$ 849,350

$ 803,539

$ 779,804

$ 799,262

$ 916,886
82,345
$
—

$ 851,321
72,439
$
—

$ 801,435
62,321
$
—

$ 782,782
58,589
$
756

$ 797,761
56,883
$
840

82,345

72,439

62,321

59,345

57,723

$ 143,448
143,448
105,425
2,052,517
590,002
2.08
2.08
2.06
2.06
11.5%
1.34

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

65%

70%

39,665
12,661

39,557
13,053

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

9.8%

1.25

78%

39,348
13,805

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

$ 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

(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 in 2018, 2017 and 2016 was 66%, 68% and
80%, respectively, from our electric utility business and 34%, 32% and
20%, respectively, from our manufacturing and plastic pipe businesses,
including unallocated corporate costs.

We expect that 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.

Major growth strategies and initiatives in our future include:

(cid:1) Planned capital budget expenditures of approximately $1.1 billion for
the years 2019 through 2023, of which $973 million are for capital
projects at Otter Tail Power Company (OTP), including:

• $348 million for renewable wind and solar energy generation and

conservation, including the Merricourt Wind Project scheduled for
completion in 2020, the exercise of a purchase option on the
Ashtabula III wind farm in 2022, a major investment in solar
generation in 2022 and routine wind-power replacement projects.

• $150 million for the Astoria natural gas-fired generation plant to
• $145 million for numerous potential technology and infrastructure

replace Hoot Lake Plant capacity.

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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

• $122 million for transmission assets including new construction

and routine replacement projects. New construction includes
$7.8 million for the completion of the Big Stone South–Ellendale
line in 2019.

(cid:1) Continued investigation and evaluation of organic growth

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

In 2018:
(cid:1) Our Electric segment net income increased 10.1% to $54.4 million

from $49.4 million in 2017.

(cid:1) Our Manufacturing segment net income increased 16.2% to

$12.8 million from $11.1 million in 2017.

(cid:1) Our Plastics segment net income increased 9.8% to $23.8 million

from $21.7 million in 2017.

(cid:1) Our net cash from continuing operations was $143.4 million.
(cid:1) Capital expenditures at OTP totaled $87.3 million as work continued
toward completion on the Big Stone South–Ellendale Multi-Value
Transmission Project (MVP).

(cid:1) OTP issued $100 million aggregate principal amount of its 4.07%

Series 2018A Senior Unsecured Notes due February 7, 2048, using
the proceeds to repay outstanding borrowings under the OTP
Credit Agreement.

(cid:1) We decreased short-term borrowing by $93.8 million.
(cid:1) We paid out $53.2 million in common dividends in 2018.

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

Net Income (Loss):

Electric
Manufacturing
Plastics
Corporate

Total Net Income

2018

2017

$ 450,198
268,409
197,840

$ 434,506
229,712
185,132

$ 916,447

$ 849,350

54,431
12,839
23,819
(8,744)

49,446
11,050
21,696
(9,753)

82,345

72,439

Revenues in each of our business segments increased in 2018

compared with 2017, driven by higher sales volume for the Electric and
Manufacturing segments and higher margins for the Plastics segment.
Manufacturing segment revenues increased $38.7 million (16.8%).
Revenues at BTD Manufacturing, Inc. (BTD) increased $36.8 million,
with revenue increases at all of BTD’s locations as a result of increased
product sales across all end market categories. Included in the product
sales are increased steel costs which are passed through to customers.
Revenues at T.O. Plastics, Inc. (T.O. Plastics) increased $1.9 million due
to increased sales of horticultural products. Electric segment revenues
increased $15.7 million (3.6%) mainly due to a $13.3 million (3.6%)
increase in retail sales revenue resulting from a 3.4% increase in retail
kilowatt-hour (kwh) sales. The increase in electric revenue also
included a $2.6 million (49.5%) increase in wholesale energy sales from
OTP’s generating units. Plastics segment revenues increased $12.7 million
(6.9%), mainly due to a 9.4% increase in polyvinyl chloride (PVC) pipe
prices, partially offset by a 2.3% decrease in pounds of pipe sold.
Higher sales volume in 2017 was mainly due to buying spurred by
concerns of product shortages and production delays related to 2017
hurricanes in the Gulf of Mexico.

A $12.7 million decrease in income tax expense in 2018 is mainly due
to the decrease in the United States federal corporate income tax rate
from 35% in 2017 to 21% in 2018 under the 2017 Tax Cuts and Jobs
Act (TCJA).

The $9.9 million increase in net income in 2018 compared with 2017

reflects the following:
(cid:1) A $5.0 million increase in Electric segment net income from

increased consumption due to favorable weather in 2018, and
increases in interim rates, net of estimated refunds, in our North
and South Dakota rate cases, partially offset by higher operating and
maintenance expenses.

(cid:1) A $1.8 million increase in Manufacturing segment net income, mainly

due to increased sales across almost all customer groups.
Manufacturing segment net income was also impacted by the effect
of the change in tax law under the TCJA.

(cid:1) A $2.1 million increase in Plastics segment net income was mainly

due to higher pipe PVC prices and increased margins on pipe sales in
2018. Plastics segment net income was also impacted favorably by
the effect of the change in tax law under the TCJA.

(cid:1) Corporate after-tax cost decreased $1.0 million in 2018. Corporate
costs in 2017 included $7.2 million in additional tax expense due to
the effect of the change in tax law under the TCJA. This was partially
offset in 2018 primarily by increased charitable contributions and
employee benefit costs.

As a result of the tax rate reduction included in the TCJA, deferred
tax assets and liabilities were reduced in value in 2017. The impact by
segment on 2017 income tax expense is summarized below:

(in thousands)

Electric
Manufacturing
Plastics
Corporate

Total

Decrease/(Increase)

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

(1,756)

Following is a more detailed analysis of our operating results by
business segment for the years ended December 31, 2018, 2017 and
2016, followed by a discussion of our financial position at the end of
2018 and our outlook for 2019.

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 2018, 2017 and 2016 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)

2018

2017

2016

Operating Revenues:

Electric
Product Sales

Cost of Products Sold
Other Nonelectric Expenses

57
—
21
36

31
26
18
39

34
—
6
28

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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

(in thousands)

2018 change

2017 change

2016

Retail Sales Revenues from

Contracts with Customers $ 388,690

3 $ 376,902

1 $ 374,506

Changes in Accrued

Revenues under Alternative
Revenue Programs

Total Retail Sales Revenue
Wholesale Revenues—
Company Generation

Other Revenues

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

Maintenance Expenses

Depreciation and Amortization
Property Taxes

(439)

(1,971) (194)

2,104

$ 388,251

4 $ 374,931

— $ 376,610

7,735
54,269

50
—

5,173
54,433

13
18

4,584
46,189

$ 450,255
66,815
68,355

4 $ 434,537
59,690
64,807

12
5

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

155,534
55,935
15,585

6
5
4

146,914
53,276
15,053

—
(1)
6

147,274
53,743
14,266

Operating Income

88,031

(7) $

94,797

1 $ 94,082

Electric kilowatt-hour (kwh)

Sales (in thousands)

Retail kwh Sales
Wholesale kwh Sales—
Company Generation

Heating Degree Days
Cooling Degree Days

4,976,960

4,814,984

1 4,750,421

271,841
6,904
567

34
16
49

203,397
5,931
380

7
12
(16)

190,288
5,314
451

The following table shows heating and cooling degree days as a

percent of normal.

Heating Degree Days
Cooling Degree Days

2018

111.0%
123.5%

2017

93.9%
82.1%

2016

84.1%
97.4%

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 2018, 2017 and 2016, and between years.

2018 vs
Normal

2018 vs
2017

2017 vs
Normal

2017 vs
2016

2016 vs
Normal

Effect on Diluted
Earnings Per Share

$0.07

$0.11

$(0.04)

$0.03

$(0.07)

2018 Compared with 2017
The $13.3 million increase in retail revenue includes:
(cid:1) A $7.6 million increase in revenue related to the recovery of increased
fuel and purchased power costs. The increase in fuel and purchase
power costs was driven by a 3.4% increase in kwhs sold, combined
with an increase in higher-cost purchased power in the fourth quarter
of 2018 to provide replacement power during a nine-week scheduled
fall maintenance outage at Big Stone Plant. The revenue increase
was also driven by a $1.9 million reduction in estimated unbilled fuel
revenues recorded in the fourth quarter of 2017.

(cid:1) A $6.3 million increase related to increased consumption due to

colder and warmer weather in 2018 compared with 2017, evidenced
by a 16.4% increase in heating-degree days and 49.2% increase in
cooling degree days between the years.

(cid:1) A $5.7 million increase, net of an estimated refund, related to an

interim rate increase implemented in January 2018 in conjunction
with OTP’s 2017 general rate increase request in North Dakota.
(cid:1) A $4.2 million increase in North Dakota and Minnesota Renewable

Resource Adjustment (RRA) rider revenues related to the expiration
of federal production tax credit (PTC) eligibility on one of OTP’s
wind farms.

(cid:1) A $2.8 million increase in Minnesota Conservation Improvement

Program (MNCIP) cost recovery revenues and incentives.
(cid:1) A $0.7 million increase related to an interim rate increase

implemented in October 2018 in conjunction with OTP’s 2018
general rate increase request in South Dakota.

partially offset by:
(cid:1) A $9.6 million reduction in revenues for the provision of refunds
related to the recovery of federal income taxes in current retail
electric rates in our state jurisdictions and under Federal Energy
Regulatory Commission approved transmission tariffs that are in
excess of lower federal income taxes under the TCJA.

(cid:1) A $2.5 million decrease in North Dakota Environmental Cost

Recovery (ECR) rider revenues due to a reduction in the return on
equity component of the North Dakota rider from 10.75% in 2017 to
9.77% in 2018, lower federal taxes being recovered through the
riders and a lower investment balance for environmental upgrades
due to depreciation.

(cid:1) A $1.9 million reduction in North Dakota and South Dakota

Transmission Cost Recovery (TCR) rider revenues related to a
reduction in transmission costs, including lower federal income
taxes under the TCJA.

Wholesale electric revenues increased $2.6 million due to a 33.7%
increase in wholesale kwh sales and an 11.9% increase in wholesale
electric prices. Increased demand and higher wholesale prices provided
greater opportunity for wholesale energy sales and economic dispatch
of OTP’s generating units in 2018 compared with 2017.

Production fuel costs increased $7.1 million, due to a 26.9% increase
in kwhs generated from OTP’s fuel-burning plants to provide electricity
for the increases in retail and wholesale demand driven by colder
weather in the first four months and the last three months of 2018 and
warmer weather from May through September 2018 compared with
the same periods in 2017.

The cost of purchased power to serve retail customers increased
$3.5 million. The cost per kwhs purchased increased by 16.1% while
kwhs purchased decreased 9.2%. Increased system demand lead to
the increase in cost per kwh purchased. Increased generation from
company-owned generating units driven by higher market prices for
electricity contributed to the decrease in kwhs purchased between
the years.

Electric operating and maintenance expenses increased $8.6 million

due to:
(cid:1) A $2.9 million increase in Big Stone Plant contracted maintenance
expenses related to its 2018 nine-week scheduled fall maintenance
outage.

(cid:1) A $2.4 million increase in conservation program spending.
(cid:1) A $1.9 million increase in benefit and other labor-related costs.
(cid:1) A $1.0 million increase in donations due to increased community

giving in 2018 and to an irrevocable commitment of $0.5 million to
fund OTP’s charitable foundation established in 2018.

(cid:1) A $0.4 million increase in other operating and maintenance expense.

Depreciation expense increased $2.7 million mainly due to the Big

Stone South-Brookings transmission line being placed in service in
September 2017 and to increased investments in other transmission
assets.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

Property tax expense increased $0.5 million in 2018 related to

increased investments in our electric plant in service.

2017 Compared with 2016
The $1.7 million decrease in retail electric revenue includes:
(cid:1) 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.

(cid:1) 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.

(cid:1) 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.

(cid:1) A $1.0 million increase in North Dakota TCR rider revenues as a

result of increased investment in transmission assets qualifying for
revenue recovery through the TCR rider.

more than offset by:
(cid:1) A $7.1 million reduction in Minnesota 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 Midcontinent Independent System
Operator, Inc. (MISO) transmission tariff related to complaints
currently under judicial review resulted in lower TCR revenues in
Minnesota.

(cid:1) A $3.7 million decrease in 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.

(cid:1) A $1.9 million decrease in revenue due to a change in estimate that

reduced unbilled revenues.

(cid:1) 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:

(cid:1) 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.

(cid:1) 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 decreased $0.4 million

due to:
(cid:1) A $1.2 million decrease in transmission expenditures to independent

system operators in 2017.

(cid:1) A $1.2 million decrease in MNCIP expenditures due to a delay in

regulatory approval of an LED streetlight project planned for 2017.

(cid:1) A $0.7 million net reduction in other operating expenses.

mostly offset by:
(cid:1) A $2.7 million increase in labor and benefit costs due to increased

wages and higher medical benefit payments.

Depreciation and amortization expense decreased $0.5 million due

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.

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

(in thousands)

2018 change

2017 change

2016

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

Operating Income

$ 268,409
205,699
29,650
14,794

$ 18,266

17
17
25
(4)

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

4 $ 221,289
171,732
3
21,994
8
15,794
(3)

$ 14,101

20 $ 11,769

2018 Compared with 2017
The $38.7 million increase in revenues in our Manufacturing segment
includes the following:
(cid:1) Revenues at BTD increased $36.8 million, including increases of

$33.8 million in parts revenue, including increased sales of $9.4 million
to manufacturers of agricultural equipment, $7.8 million to
manufacturers of recreational vehicles, $7.5 million to manufacturers
of construction equipment, $4.6 million to manufacturers of industrial
equipment, and $3.1 million to manufacturers of lawn and garden
equipment. Included in the parts revenue increases is the pass
through of higher material costs of $12.7 million, with the remaining
increase due to higher sales volume and a $1.5 million increase in
pricing unrelated to material cost increases. Revenues from scrap
metal sales increased $2.3 million due to higher scrap volume from
increased production and an 11% increase in scrap metal pricing.
(cid:1) Revenues at T.O. Plastics increased $1.9 million due to a $3.1 million
increase in sales of horticultural containers, partially offset by
decreases in sales of industrial and life sciences products totaling
$1.2 million.

The $29.2 million increase in cost of products sold in our

Manufacturing segment includes the following:
(cid:1) Cost of products sold at BTD increased $27.8 million due to increased

sales volume and the $12.7 million in higher material costs.

(cid:1) Cost of products sold at T.O. Plastics increased $1.4 million related to
the increase in product sales and higher labor and freight costs.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

The $5.9 million increase in operating expenses in our Manufacturing

segment includes the following:
(cid:1) Operating expenses at BTD increased $5.3 million because of the

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

following:

• A $2.2 million increase in short-term incentives.
• A $2.0 million increase in labor, benefit and recruiting expenses
• A $1.1 million increase in other administrative and general

due to hiring more employees.

expenses.

(cid:1) Operating expenses at T.O. Plastics increased $0.6 million, mainly
due to increases in labor and benefit expenses due to hiring more
employees.

The $0.6 million decrease in depreciation in our Manufacturing

segment includes decreases of $0.4 million at BTD related to reductions
in stored tooling amortization and $0.2 million at T.O. Plastics due to
certain manufacturing equipment being fully depreciated in 2018.

2017 Compared with 2016
The $8.4 million increase in revenues in our Manufacturing segment in
2017 compared with 2016 relates to the following:
(cid:1) 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, partially 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.
(cid:1) Revenues at 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.

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

segment includes the following:
(cid:1) Cost of products sold at BTD increased $2.3 million because of the

increase in product sales.

(cid:1) Costs of products sold at T.O. Plastics increased $2.4 million due to

the increase in sales.

The $1.8 million increase in Manufacturing segment operating

expenses includes the following:
(cid:1) Operating expenses at BTD increased $1.9 million because of the

following:

• A $0.7 million increase in labor and benefit costs because of an
• A $0.4 million increase in contracted service expenditures for

increase in employees in a growing business.

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.

(cid:1) 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 due to
certain assets reaching the ends of their depreciable lives in 2017.
Depreciation expense at BTD decreased $0.1 million year over year.

(in thousands)

2018 change

2017 change

2016

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

$ 197,840
148,881
12,323
3,719

7
6
7
(3)

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

20 $ 154,901
123,496
13
9,402
23
3,861
(1)

Operating Income

$ 32,917

$ 29,644

63 $ 18,142

2018 Compared with 2017
Plastics segment revenues increased $12.7 million due to a 9.4%
increase in PVC pipe prices on a 2.3% decrease in pounds of pipe sold.
Cost of products sold increased $8.8 million, despite the 2.3% decrease
in sales volume, due to an 8.8% increase in the cost per pound of
pipe sold. The increase in pipe prices in excess of the increase in cost
per pound of pipe sold resulted in an 11.3% increase in gross margin
per pound of PVC pipe sold. Plastics segment operating expenses
increased by $0.8 million mainly due to an increase in property
maintenance costs, sales commissions and other selling and
administrative costs.

Hurricane Harvey had a significant impact on market conditions
from September through December 2017. Pounds of PVC pipe sold was
lower in the last four months of 2018 compared with the same period
in 2017. This was due to increased sales and pricing resulting from 2017
hurricanes in the Gulf Coast region of the United States where the
majority of U.S. resin production plants are located. Major resin suppliers
shut down production facilities which impacted raw material availability.
This created pipe-availability concerns among distributors and
contractors, accelerating pipe demand and favorably impacting our
diluted earnings by an estimated $0.09 per share in 2017.

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. 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.

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 8 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)

2018 change

2017 change

Other Operating Expenses
Depreciation and Amortization

9,607

55
218 199

6,182
73

(15) $
55

2016

7,315
47

Corporate operating expenses increased $3.4 million in 2018 as

compared to 2017 due to the following:
(cid:1) A $1.7 million increase in charitable contributions due to an

irrevocable commitment to fund Otter Tail Corporation’s charitable
foundation established in 2018.

(cid:1) A $1.7 million increase in employee benefit costs.

Corporate operating expenses decreased $1.1 million in 2017 as
compared to 2016 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.

Other income increased $0.8 million in 2018 compared with 2017
mainly because of a $1.2 million increase in OTP’s allowance for equity
funds used during construction (AFUDC) partially offset by a $0.5 million
decrease in cash surrender values from corporate-owned life insurance.
Other income decreased $0.3 million in 2017 compared with 2016,
mainly because of the receipt of $0.7 million in nontaxable corporate-
owned life insurance proceeds in 2016 while no similar proceeds were
received in 2017, partially 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.

CONSOLIDATED INCOME TAXES
Income tax expense was $14.6 million in 2018 compared with
$27.3 million in 2017 and $20.2 million in 2016. Income tax expense
decreased $12.7 million in 2018 compared with 2017, mainly due to the
decrease in the federal corporate income tax rate from 35% in 2017 to
21% in 2018 under the TCJA. Income tax expense increased $7.0 million
in 2017 compared with 2016 mainly because of a $17.2 million increase
in income before income taxes.

The following table provides a reconciliation of income tax expense
calculated at the federal statutory rate on income before income taxes
reported on our consolidated statements of income:

(in thousands)

For the Year Ended December 31,

2018

2017

2016

CONSOLIDATED INTEREST CHARGES

Income Before Income Taxes

$ 96,933

$ 99,695

$ 82,540

(in thousands)

Interest Charges

2018 change

2017 change

2016

$ 30,408

$ 29,604

(7) $ 31,886

The $0.8 million increase in interest charges in 2018 compared with

2017 is related to OTP’s February 2018 issuance of $100 million in
privately placed 4.07% Senior Unsecured Notes due February 7, 2048
(2018 Notes). Interest expense of $3.6 million in 2018 on the 2018
Notes was mostly offset by:
(cid:1) A $1.4 million reduction in long-term debt interest expense related
to the retirement of OTP’s $33.0 million outstanding 5.95%, Series A
Senior Unsecured Notes at maturity on August 20, 2017 and the
August 2017 early retirement of the remaining $15 million balance
on our $50 million term loan term due February 5, 2018.

(cid:1) A $0.9 million reduction in short-term debt interest mainly related

to the paydown of OTP’s short-term debt outstanding on February 7,
2018 with proceeds from the 2018 Notes.

(cid:1) A $0.5 million increase in capitalized interest in 2018.

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.

CONSOLIDATED OTHER INCOME

(in thousands)

Other Income

2018 change

2017 change

2016

3,461

2,632

(9) $

2,905

Tax Computed at Company’s Net Composite

Federal and State Statutory Rate
(21% for 2018, 35% for 2017 and 2016)

Increases (Decreases) in Tax from:

State Income Taxes Net of Federal

Income Tax Expense

Differences Reversing in Excess of

Federal Rates

Federal PTCs
Permanent Differences, R&D Tax Credits,

$ 20,356

$ 34,893

$ 28,889

5,210

4,368

2,869

(3,432)
(3,111)

551
(7,527)

77
(7,175)

Unitary Tax and Other Adjustments

(1,864)

(1,873)

(1,262)

North Dakota Wind Tax Credit Amortization—

Net of Federal Taxes

Excess Tax Deduction—Stock

Compensation Awards

AFUDC—Equity
Employee Stock Ownership Plan

Dividend Deduction

Investment Tax Credit Amortization
Corporate-owned Life Insurance
Section 199 Domestic Production

Activities Deduction

Effect of TCJA Tax Rate Reduction on
Value of Net Deferred Tax Assets

(1,033)

(850)

(708)
(431)

(298)
(98)
(3)

—

(751)
(322)

(509)
(164)
(845)

—
(280)

(537)
(350)
(680)

(1,471)

(482)

1,756

—

Total Income Tax Expense

Effective Income Tax Rate

$ 14,588

$ 27,256

$ 20,219

15.0%

27.3%

24.5%

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 decreased 53.0% in
2018 compared with 2017 due to the PTC eligibility period ending for
one of OTP’s wind farms. 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. 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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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, 2018 and December 31, 2017:

(in thousands)

Otter Tail Corporation Credit Agreement
OTP Credit Agreement

Total

Line Limit

130,000
170,000

300,000

In Use on
December 31, 2018

9,215
9,384

$ 18,599

Restricted due
to Outstanding
Letters of Credit

—
300

300

Available on
December 31, 2018

Available on
December 31, 2017

120,785
160,316

281,101

$ 130,000
57,329

$ 187,329

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 3, 2018 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 3, 2021. On May 3, 2018,
we also filed a shelf registration statement with the SEC for the
issuance of up to 1,500,000 common shares until May 3, 2021, under
our 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. On May 1, 2018 our Distribution Agreement with
J.P. Morgan Securities, LLC (JPMS) for our At-the-Market Offering
Program ended as required under the agreement. No shares were
issued under this program in 2018.

Equity or debt financing will be required in the period 2019 through
2023 given plans to fund construction of new rate base investments to
expand our Electric segment. 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, 2019 our board of directors increased the
quarterly dividend from $0.335 to $0.35 per common share.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

2017 Cash Flows Compared with 2016 Cash Flows
The $10.2 million increase in cash provided by operating activities
between the years includes a $10.1 million increase in net income and
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 $26.9 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 partially 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, partially offset by $1.8 million in stock
repurchases related to tax withholding requirements for stock incentive
awards. See note 5 to the 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.

2018 Cash Flows Compared with 2017 Cash Flows
Net cash provided by operating activities was $143.4 million in 2018
compared with net cash provided by operating activities of $173.6 million
in 2017. Primary reasons for the $30.2 million decrease in net cash
provided by operations between the periods were:
(cid:1) A $9.9 million increase in net income.
(cid:1) A $2.1 million increase in depreciation and amortization expense.
(cid:1) A $1.5 million decrease in cash used for working capital items.

more than offset by:
(cid:1) A $20.0 million increase in discretionary contributions to the

corporation’s funded pension plan.

(cid:1) A $2.4 million decrease in noncurrent liabilities and deferred credits
in 2018 compared with a $19.3 million increase in 2017. The change
was primarily driven by an increase in the discount rates used to
value pension and other postretirement benefit liabilities.

(cid:1) A $4.8 million reduction in the level of increases in deferred tax

liabilities related to the lower federal income tax rate under the TCJA.

Net cash used in investing activities was $107.4 million in 2018
compared with $132.6 million in 2017. The $25.2 million decrease in
cash used for investing activities includes a $27.5 million decrease in
capital expenditures, mainly due to a $31.2 million reduction in cash
used for capital expenditures at OTP as the Big Stone South–Brookings
345 kiloVolt (kV) transmission line project, placed in service September
2017, was under construction during the first nine months of 2017. OTP
capital work on the Big Stone South–Ellendale 345-kV transmission
line project and on a major project to replace its customer information
system was winding down toward the end of 2018. OTP implemented
its new customer information system in February 2019. Cash used for
capital expenditures at BTD increased $3.4 million between periods
mainly due to the addition of manufacturing equipment to add
capabilities and expand capacity at all of BTD’s manufacturing plants.
Corporate capital expenditures increased $0.5 million between periods
for leasehold improvements and office equipment purchased in 2018
in connection with an April 2018 office move. The decrease in cash
used for capital expenditures was partially offset by a $2.1 million
decrease in proceeds from the disposal of noncurrent assets reflecting
$1.5 million in proceeds in 2017 from the sale of property by OTP with
no similar transaction in 2018 and a $0.6 million reduction in proceeds
from the sale of investments by our captive insurance company, Otter
Tail Assurance Limited.

Net cash used in financing activities was $51.4 million in 2018
compared with $24.8 million in 2017. Financing activities in 2018
included proceeds from the issuance of $100 million of 2018 Notes,
which were used to pay down a portion of borrowings then outstanding
under the OTP Credit Agreement. Financing activities in 2018 also
included the distribution of $53.2 million in common dividend payments.
(See discussion below on cash used for financing activities in 2017.)

CASH REALIZATION (millions)

2.6x

3
6
1
$

2.4x

4
7
1
$

1.7x

3
4
1
$

2
7
$

2
8
$

2
6
$

$200

$150

$100

$50

Cash flows from operations

Net income

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

$1,500

$1,000

$500

%
6
4

Total capital

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 8 A N N UA L R E P O RT

CONTRACTUAL OBLIGATIONS
The following table summarizes our contractual obligations at
December 31, 2018 and the effect these obligations are expected to
have on our liquidity and cash flow in future periods.

(in millions)

Coal Contracts
Debt Obligations
Interest on Debt Obligations
Capacity and Energy Requirements
Postretirement Benefit Obligations
Other Purchase Obligations
(including land easements)
Operating Lease Obligations

Less
than

1-3
1 Year Years

Total

$ 619 $
592
398
230
111

23 $ 46
140
—
58
28
38
25
12
6

More
3-5 than 5
Years Years

$ 47 $ 503
422
270
143
79

30
42
24
14

80
31

44
6

27
11

1
7

8
7

Total Contractual Cash Obligations $ 2,061 $ 132 $ 332

$ 165 $1,432

Coal contract obligations are based on estimated coal consumption
and costs for the delivery of coal to Coyote Station from Coyote Creek
Mining Company under the lignite sales agreement that ends in 2040,
except for $1.0 million in purchase obligations in 2019 at Big Stone
Plant. 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.

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 $105.4 million

in 2018, $132.9 million in 2017 and $161.3 million in 2016. Estimated
capital expenditures for 2019 are $203 million. Total capital
expenditures for the five-year period 2019 through 2023 are estimated
to be approximately $1.1 billion, including:
(cid:1) $348 million for renewable wind and solar energy generation and
conservation, including the Merricourt Wind Project scheduled for
completion in 2020, the exercise of a purchase option on the
Ashtabula III wind farm in 2022, a major investment in solar
generation in 2022 and routine wind-power replacement projects.

(cid:1) $150 million for the Astoria natural gas-fired generation plant to

replace Hoot Lake Plant capacity.

(cid:1) $145 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.

The breakdown of 2016, 2017 and 2018 actual cash used for capital
expenditures and 2019 through 2023 estimated capital expenditures
by segment is as follows:

(in millions)

2016 2017 2018 2019 2020 2021 2022 2023 2019-2023

Electric
Manufacturing
Plastics
Corporate

$ 150 $ 119 $ 87 $183 $393 $120 $177 $100
15
19
4
4
— —

14
3
—

14
4
—

10
4
—

15
5
—

13
4
1

8
3
—

$ 973
77
20
—

Total

$ 161 $ 133 $ 105 $203 $411 $137 $200 $119

$1,070

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 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 2019 through 2023 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.

On May 3, 2018 we filed a shelf registration statement with the 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 3, 2021. On May 3,
2018 we also filed a shelf registration statement with the SEC for the issuance of up to 1,500,000 common shares under our 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. The shelf registration for the Plan expires on May 3, 2021. On May 1, 2018 our Distribution
Agreement with JPMS for our At-the-Market Offering Program ended.

Short-Term Debt
The following table presents the status of our lines of credit as of December 31, 2018 and December 31, 2017:

(in thousands)

Otter Tail Corporation Credit Agreement
OTP Credit Agreement

Total

Line Limit

130,000
170,000

300,000

In Use on
December 31, 2018

9,215
9,384

$ 18,599

Restricted due
to Outstanding
Letters of Credit

—
300

300

Available on
December 31, 2018

Available on
December 31, 2017

120,785
160,316

281,101

$ 130,000
57,329

$ 187,329

Under the Otter Tail Corporation Credit Agreement (OTC Credit

Agreement) (as defined below), the maximum amount of debt
outstanding in 2018 was $17.7 million on September 17, 2018 and the
average daily balance of debt outstanding during 2018 was $5.5 million.
The weighted average interest rate paid on debt outstanding under
the OTC Credit Agreement during 2018 was 3.8% compared with
2.8% in 2017. Under the OTP Credit Agreement (as defined below), the
maximum amount of debt outstanding in 2018 was $122.0 million on
January 16, 2018 and the average daily balance of debt outstanding
during 2018 was $21.6 million. The weighted average interest rate paid
on debt outstanding under the OTP Credit Agreement during 2018 was
3.0% compared with 2.4% in 2017. The maximum amount of consolidated
short-term debt outstanding in 2018 was $122.0 million on January 16,
2018 and the average daily balance of consolidated short-term debt
outstanding during 2018 was $27.1 million. The weighted average
interest rate on consolidated short-term debt outstanding on
December 31, 2018 was 3.9%.

On October 29, 2012 we entered into a Third Amended and Restated

Credit Agreement (the OTC 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 OTC Credit
Agreement. On October 31, 2018 the OTC Credit Agreement was
amended to extend its expiration date by one year from October 31, 2022
to October 31, 2023. 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 OTC 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 OTC Credit
Agreement contains a number of restrictions on us and the businesses of
our wholly owned subsidiary, Varistar Corporation 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 OTC Credit Agreement also contains affirmative
covenants and events of default, and financial covenants as described
below under the heading “Financial Covenants.” The OTC 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 OTC
Credit Agreement are guaranteed by certain of our subsidiaries.
Outstanding letters of credit issued by us under the OTC 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, 2018 the OTP Credit
Agreement was amended to extend its expiration date by one year
from October 31, 2022 to October 31, 2023. 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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.

Both the OTC Credit Agreement and the OTP Credit Agreement

currently expire on October 31, 2023. Borrowings under these
agreements currently use LIBOR as the base to determine the
applicable interest rate. LIBOR is currently expected to be eliminated
by January 1, 2022. Both agreements contain a provision to determine
how interest rates will be established in the event a replacement for
LIBOR has not been identified before the agreement expires. The
process calls for the parties to jointly agree on an alternate rate of
interest to LIBOR, such as the Secured Overnight Financing Rate, that
gives due consideration to prevailing market convention for determining
a rate of interest for syndicated loans in the United States at such
time. The parties will enter into amendments to these agreements to
reflect any alternate rate of interest and other related changes to the
agreements as may be applicable. If for any reason an agreement
cannot be reached on an alternate rate of interest, then any borrowings
under the agreements will be determined using the Prime Rate plus a
margin based on the Company’s and OTP’s Long-Term Debt Ratings at
the time of the borrowings. If the alternate rate of interest agreed to
by the parties is less than zero, such rate shall be deemed to be zero
for the purposes of the credit agreement.

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 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

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 a Term Loan Agreement.

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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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 (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.

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, 2018.

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:
(cid:1) Under the OTC 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, 2018,
our Interest and Dividend Coverage Ratio calculated under the
requirements of the OTC Credit Agreement and the 2016 Note
Purchase Agreement was 4.35 to 1.00.

(cid:1) Under the 2016 Note Purchase Agreement, we may not permit our
Priority Indebtedness to exceed 10% of our Total Capitalization.
(cid:1) 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.

(cid:1) 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, 2018, OTP’s Interest and Dividend Coverage Ratio

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

and Interest Charges Coverage Ratio, calculated under the
requirements of the 2007 Note Purchase Agreement and 2011
Note Purchase Agreement, was 3.28 to 1.00.

(cid:1) 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, 2018, our ratio of Interest-bearing Debt to Total

Capitalization was 0.46 to 1.00 on a consolidated basis and 0.47 to
1.00 for OTP. Neither Otter Tail Corporation nor OTP had any Priority
Indebtedness outstanding as of December 31, 2018.

OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit
totaling $3.2 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.

2019 BUSINESS OUTLOOK

We anticipate 2019 diluted earnings per share to be in the range of
$2.10 to $2.25. We have taken into consideration strategies for
improving future operating results, the cyclical nature of some of our
businesses, and current regulatory factors facing our Electric segment.
We expect capital expenditures for 2019 to be $203 million compared
with actual cash used for capital expenditures of $105 million in 2018.
Our planned expenditures for 2019 include $61 million for the Merricourt
Wind Project and $40 million for the planned natural gas-fired electric
plant near Astoria, South Dakota.

Segment components of our 2019 earnings per share guidance

range compared with 2018 actual earnings are as follows:

Electric
Manufacturing
Plastics
Corporate

Total

Return on Equity

2018 EPS
by Segment

$
$
$
$

1.36
0.32
0.60
(0.22)

2.06

11.5%

2019 EPS Guidance
High
Low

1.46
$
0.37
$
$
0.44
$ (0.17)

2.10

1.49
$
0.41
$
$
0.48
$ (0.13)

2.25

11.5%

12.3%

The following items contribute to our earnings guidance for 2019.
(cid:1) We expect 2019 Electric segment net income to be higher than 2018

segment net income based on:

• Constructive outcome of a rate case filed in South Dakota in 2018.

Interim rates went into effect on October 18, 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.

• Increases in allowance for funds used during construction (AFUDC)

for planned capital projects, including the Merricourt Wind Project,
and increases in AFUDC and North Dakota Generation Cost
Recovery Rider revenue relating to Astoria Station which is
expected to begin construction in 2019.

• Increased revenues from completion of the Big Stone South—

Ellendale project and additional transmission investments related
to our South Dakota Transmission Reliability project.

• Decreased operating and maintenance expenses due to decreasing

costs of pension, medical, workers compensation and retiree
medical benefits and continued efforts to manage spending. The
decrease in pension costs is a result of an increase in the discount
rate from 3.90% to 4.50%.

partially offset by:

• Normal weather for 2019. Weather favorably impacted 2018
• Higher depreciation and property tax expense due to large capital

earnings per share by $.07 compared to normal.

projects being put into service.

(cid:1) We expect 2019 net income from our Manufacturing segment to

increase over 2018 based on:

• Increased sales at BTD driven by growth in the recreational vehicle,

lawn and garden and agricultural end markets. Most of this growth
is organic with BTD’s existing customer base. Scrap revenues are
expected to increase as well based on increased volume with
scrap prices staying flat between the years.

• An increase in earnings from T.O. Plastics mainly driven by year-

over-year sales growth in our horticulture, life science and
industrial markets.

• Backlog for the manufacturing companies of approximately

$211 million for 2019 compared with $166 million one year ago.

(cid:1) We expect 2019 net income from the Plastics segment to be lower
than 2018 based on lower expected operating margins in 2019.
This is due to expected increasing resin prices on slightly higher
sales volumes in 2019 compared to 2018.

(cid:1) Corporate costs, net of tax, are expected to be lower in 2019 than

in 2018.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

The following table shows our 2018 capital expenditures and 2019 through 2023 anticipated capital expenditures and electric utility ending rate

base:

(in millions)

Capital Expenditures:
Electric Segment:

Renewables and Natural Gas Generation
Transformative Technology and Infrastructure
Transmission (includes replacements)
Other

Total Electric Segment
Manufacturing and Plastics Segments

Total Capital Expenditures

Total Electric Utility Ending Rate Base

2018

2019

2020

2021

2022

2023

Total

103
3
37
40

183
20

203

292
25
38
38

393
18

411

18
39
13
50

120
17

137

83
46
11
37

177
23

200

2
32
23
43

100
19

119

498
145
122
208

973
97

$ 1,070

87
18

105

$ 1,112

$ 1,210

$ 1,510

$ 1,539

$ 1,614

$ 1,631

The consolidated capital expenditure plan for the 2019-2023 time period calls for $1.1 billion based on the need for additional wind and solar in

rate base, capital spending for the Astoria Station natural gas-fired plant that is part of our replacement solution for Hoot Lake Plant when it is
retired in 2021, technology-related investments and transmission investments, including Self-Funded upgrades. Given the increased capital
expenditure plan, our compounded annual growth rate in rate base is projected to be 7.9% over the 2018 to 2023 timeframe.

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 2019 through 2023 timeframe.

Our outlook for 2019 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 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 11 to 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 30 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 2019 for our noncontributory funded
pension plan is expected to be $3.4 million compared to $6.0 million in
2018, reflecting an increase in the estimated discount rate used to
determine annual benefit cost accruals from 3.90% in 2018 to 4.50% in
2019. The assumed rate of return on pension plan assets will remain at
7.25% in 2019. In selecting the discount rate, we consider the yields of

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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 2018, all other factors being held constant:
a 0.25 increase in the discount rate would have decreased our 2018
pension benefit cost by $1,063,000; a 0.25 decrease in the discount rate
would have increased our 2018 pension benefit cost by $1,120,000; a
0.25 increase in the assumed rate of increase in future compensation
levels would have increased our 2018 pension benefit cost by $591,000;
a 0.25 decrease in the assumed rate of increase in future compensation
levels would have decreased our 2018 pension benefit cost by $576,000;
and a 0.25 increase (or decrease) in the expected long-term rate of
return on plan assets would have decreased (or increased) our 2018
pension benefit cost by $707,000.

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 2018 postretirement medical benefit costs by
$244,000. A 0.25 decrease in the discount rate would have increased
our 2018 postretirement medical benefit costs by $256,000. See note
11 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, 2018 reflects
the most likely probable expected outcome of these tax matters in
accordance with the requirements of Accounting Standards
Codification (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.

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, 2018, the fair value substantially
exceeded the carrying value at all our reporting units.

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
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 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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, 2018 we had exposure to market risk associated
with interest rates because OTP had $9.4 million in short-term debt
outstanding subject to variable interest rates indexed to LIBOR plus
1.25% under the OTP Credit Agreement and we had $9.2 million in
short-term debt outstanding subject to variable interest rates indexed
to LIBOR plus 1.50% under the Otter Tail Corporation Credit Agreement.
All of our remaining consolidated long-term debt outstanding on
December 31, 2018 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 8 A N N UA L R E P O RT

Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the 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, 2018 and 2017, 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, 2018, 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, 2018, 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 the Company as of
December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,
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, 2018, 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 22, 2019

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 8 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 $1,407 for 2018 and $1,094 for 2017)
Other
Inventories
Unbilled Receivables
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.

2018

2017

861

16,216

75,144
9,741
106,270
23,626
2,439
17,225
6,114

241,420

8,961
35,759
37,572
12,450
135,257

2,019,721
228,120
181,626

2,429,467
848,369

1,581,098

68,466
7,761
88,034
22,427
1,181
22,551
12,491

239,127

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

$ 2,052,517

$2,004,278

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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

Total Current Liabilities

Pensions Benefit Liability
Other Postretirement Benefits Liability
Other Noncurrent Liabilities

Commitments and Contingencies (note 9)

Deferred Credits

Deferred Income Taxes
Deferred Tax Credits
Regulatory Liabilities
Other

Total Deferred Credits

Capitalization (page 56)
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, 2018—39,664,884 Shares; 2017—39,557,491 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.

2018

2017

18,599
172
96,291
24,857
17,287
738
12,149

170,093

98,358
71,561
24,326

120,976
19,974
226,469
1,895

369,314

$ 112,371
186
84,677
21,534
16,808
9,688
11,389

256,653

109,708
69,774
22,769

100,501
21,379
232,893
3,329

358,102

590,002

490,380

—

198,324
344,250
190,433
(4,144)

728,863

—

197,787
343,450
161,286
(5,631)

696,892

1,318,865

1,187,272

$ 2,052,517

$ 2,004,278

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 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)

2018

2017

2016

Operating Revenues

Electric

Revenues from Contracts with Customers
Changes in Accrued Revenues under Alternative Revenue Programs

Total Electric
Product Sales from Contracts with Customers

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

450,637
(439)

450,198
466,249

916,447

66,815
68,355
155,534
354,559
51,544
74,666
15,585

787,058

436,477
(1,971)

434,506
414,844

849,350

59,690
64,807
146,914
316,562
41,492
72,545
15,053

717,063

425,245
2,104

427,349
376,190

803,539

54,792
63,226
147,274
295,222
38,683
73,445
14,266

686,908

Operating Income

129,389

132,287

116,631

Interest Charges
Nonservice Cost Components of Postretirement Benefits
Other Income

Income Before Income Taxes
Income Tax Expense

Net Income

Average Number of Common Shares Outstanding–Basic
Average Number of Common Shares Outstanding–Diluted

Basic Earnings Per Common Share
Diluted Earnings Per Common Share

Dividends Declared Per Common Share

See accompanying notes to consolidated financial statements.

30,408
5,509
3,461

96,933
14,588

82,345

39,600
39,892

2.08
2.06

1.34

$
$

29,604
5,620
2,632

99,695
27,256

72,439

39,457
39,748

1.84
1.82

1.28

$
$

31,886
5,110
2,905

82,540
20,219

62,321

38,546
38,731

1.62
1.61

1.25

$
$

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME–FOR THE YEARS ENDED DECEMBER 31

(in thousands)

Net Income

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

(Losses) Gains Arising During Period
Income Tax Benefit (Expense)

Change in Unrealized Losses on Available-for-Sale Securities—net-of-tax

Pension and Postretirement Benefit Plans:

Actuarial Gains (Losses) net of Regulatory Allocation Adjustment
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)
Income Tax (Expense) Benefit
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act

Pension and Postretirement Benefit Plans—net-of-tax

Total Other Comprehensive Income (Loss)

Total Comprehensive Income

See accompanying notes to consolidated financial statements.

2018

2017

2016

82,345

72,439

62,321

(105)
(61)
35

(131)

1,919
985
(755)
(531)

1,618

1,487

(15)
115
(35)

(3,791)
629
1,266
—

(1,896)

(1,831)

(3)
(14)
6

(11)

(445)
628
(74)
—

109

83,832

70,608

62,419

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 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, 2015

Common Stock Issuances, Net of Expenses
Common Stock Retirements and Forfeitures
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 and Forfeitures
Net Income
Other Comprehensive Income
Employee Stock Incentive Plan Expense
Common Dividends ($1.28 per share)

Balance, December 31, 2017

Common Stock Issuances, Net of Expenses
Common Stock Retirements and Forfeitures
Net Income
Other Comprehensive Income
Employee Stock Incentive Plan Expense
Common Dividends ($1.34 per share)

Common
Shares
Outstanding

Par Value,
Common
Shares

Premium on
Common
Shares

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

39,557,491
178,601
(71,208)

$ 197,787
893
(356)

$343,450
(986)
(2,655)

4,441

Accumulated
0ther
Comprehensive
Income/(Loss)

Total
Common
Equity

$ (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)

$ (5,631)(a) $696,892
(93)
(3,011)
82,345
1,487
4,441
(53,198)

1,487

Retained
Earnings

$126,025

62,321

(623)
(48,244)

$139,479

72,439

(50,632)

$161,286

82,345

(53,198)

Balance, December 31, 2018

39,664,884

$ 198,324

$344,250

$190,433

$ (4,144)(a) $728,863

(a) Accumulated Other Comprehensive Loss on December 31 is comprised of the following:

(in thousands)

Unrealized (Loss) Gain on Marketable Equity Securities:

Before Tax

Tax Effect

Stranded Tax Effect

Unrealized (Loss) Gain on Marketable Equity Securities—net-of-tax

Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits:

Before Tax

Tax Effect
Stranded Tax Effect

2018

2017

2016

(95)

(10)

(85)

(15)

(10)

(6,558)

(9,462)

1,705
794

2,991
794

(29)

—

(19)

(6,300)

2,519

—

Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits—net-of-tax

(4,059)

(5,677)

(3,781)

Accumulated Other Comprehensive Loss:

Before Tax

Tax Effect

Stranded Tax Effect

Net Accumulated Other Comprehensive Loss

See accompanying notes to consolidated financial statements.

(6,653)

(9,391)

1,725

784

2,976

784

(6,329)

2,529

—

(4,144)

(5,631)

(3,800)

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

CONSOLIDATED STATEMENTS OF CASH FLOWS—FOR THE YEARS ENDED DECEMBER 31

(in thousands)

2018

2017

2016

Cash Flows from Operating Activities

Net Income
Adjustments to Reconcile Net Income

to Net Cash Provided by Operating Activities:

Depreciation and Amortization
Deferred Tax Credits
Deferred Income Taxes
Change in Deferred Debits and Other Assets
Discretionary Contribution to Pension Plan
Change in Noncurrent Liabilities and Deferred Credits
Allowance for Equity/Other Funds Used During Construction
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 Operating Activities

Cash Flows from Investing Activities

Capital Expenditures
Proceeds from Disposal of Noncurrent Assets
Acquisition Purchase Price Cash Received
Cash Used for Investments and Other Assets

Net Cash Used in Investing Activities

Cash Flows from Financing Activities

Change in Checks Written in Excess of Cash
Net Short-Term (Repayments) Borrowings
Proceeds from Issuance of Common Stock
Common Stock 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 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.

82,345

72,439

62,321

74,666
(1,405)
19,224
941
(20,000)
(2,414)
(2,194)
4,441
—

(8,559)
(18,236)
(754)
14,997
396

143,448

(105,425)
2,378
—
(4,372)

(107,419)

(345)
(93,772)
—
(108)
(3,011)
100,000
(761)
(189)
(53,198)

(51,384)

(15,355)
16,216

861

72,545
(1,470)
24,001
(2,173)
—
19,257
(986)
3,642
10

(2,135)
(4,294)
(3,060)
(3,013)
(1,186)

173,577

(132,913)
4,491
—
(4,168)

(132,590)

2,434
69,488
4,349
—
(1,799)
—
(380)
(48,231)
(50,632)

(24,771)

16,216
—

16,216

73,445
(1,657)
19,124
(10,090)
(10,000)
14,685
(857)
3,178
7

(944)
1,874
(2,541)
11,502
3,339

163,386

(161,259)
4,837
1,500
(4,402)

(159,324)

(3,363)
(37,789)
44,435
(562)
(104)
130,000
(888)
(87,547)
(48,244)

(4,062)

—
—

—

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

CONSOLIDATED STATEMENTS OF CAPITALIZATION, DECEMBER 31

(in thousands)

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

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 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
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048

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.

2018

2017

9,215
9,384

18,599

80,000
—
523

80,523
172
407

79,944

140,000
30,000
42,000
60,000
50,000
90,000
100,000

512,000
—
1,942

510,058

592,523
172
2,349

590,002

—
112,371

$ 112,371

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

728,863

696,892

$ 1,318,865

$ 1,187,272

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2018, 2017 AND 2016

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).

Prior Period Reclassifications
In 2018, the Company adopted Accounting Standards Update (ASU)
2014-09, Revenues from Contracts with Customers (Topic 606)
(ASU 2014-09), and ASU 2017-07, Compensation—Retirement Benefits
(Topic 715): Improving the Presentation of Net Periodic Pension Cost and
Net Periodic Postretirement Benefit Cost (ASU 2017-07). See additional
information under Revenue Recognition and New Accounting Standards
Adopted below. The adoption of the updated standards required the
reclassifications of prior period revenues, expenses, operating income
and other income and deductions to conform to presentation and
classification requirements under the updated standards.

The updates in ASU 2014-09, which require the separate presentation

of revenues from contracts with customers from other revenues on
the face of the income statement, resulted in the separate presentation
of adjustments to retail electric sales revenue under regulatory
Alternative Revenue Programs (ARP’s) from revenues from contracts
with customers, but did not affect total operating or total electric
operating revenues reported in prior years.

The updates in ASU 2017-07 require the reporting of the nonservice
cost components of pension and other postretirement benefits outside
of operating expense and operating income. The reclassification of
these nonservice costs components has resulted in reductions in
electric operation and maintenance expenses of $4,405,000 in 2017
and $3,951,000 in 2016, reductions in other nonelectric expenses of
$1,215,000 in 2017 and $1,159,000 in 2016 and increases to operating
income and the separate disclosure of nonservice cost components of
postretirement benefits below the operating income line of $5,620,000
in 2017 and $5,110,000 in 2016.

Additionally, in 2018 the Company decided to no longer separate the
residual effects of discontinued operations from the results of continuing
operations due to the immaterial impact of discontinued operations
relative to the results of continuing operations. The effects of
discontinued operations are now included in other nonelectric
expenses and income tax expense, with the liabilities of discontinued
operations included in accounts payable and the cash flows from
discontinued operations included in changes in accounts payable and
other current liabilities in the Company’s consolidated financial
statements for the years ended December 31, 2018, 2017 and 2016.

The above reclassifications resulted in no changes to the Company’s

net income or retained earnings for the years ended December 31,
2017 and 2016.

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 $1,206,000 in 2018, $741,000 in
2017 and $495,000 in 2016. 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
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 2.76% in 2018, 2.74% in 2017 and 2.88% in 2016. 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 (2 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 2018, 2017
or 2016. 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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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, 2018 and 2017 consolidated balance sheets for OTP’s share of jointly owned assets in each of these jointly owned facilities:

Jointly Owned Facilities (dollars in thousands)

December 31, 2018

Big Stone Plant
Coyote Station
Fargo–Monticello 345 kV line
Brookings–Southeast Twin Cities 345 kV line
Bemidji–Grand Rapids 230 kV line
Big Stone South–Brookings 345kV line
Big Stone South–Ellendale 345 kV line (1)

December 31, 2017

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%

$ 336,051
177,713
78,184
26,281
16,331
53,235
—

$ 329,942
177,721
78,192
26,269
16,331
53,225
—

361
2,588
—
—
—
(150)
106,490

1,074
158
—
—
—
—
89,980

$ (92,007)
(100,997)
(5,891)
(1,713)
(2,091)
(1,264)
—

$ (74,165)
(103,944)
(4,667)
(1,293)
(1,753)
(434)
—

$ 244,405
79,304
72,293
24,568
14,240
51,821
106,490

$ 256,851
73,935
73,525
24,976
14,578
52,791
89,980

(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).

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, 2018 could be as high as $53.9 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 14 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 8 A N N UA L R E P O RT

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 14 to consolidated financial statements.

Revenue Recognition
In May 2014 the Financial Accounting Standards Board (FASB) issued a
major update to the ASC, ASU 2014-09, Revenue from Contracts with
Customers (Topic 606) (ASC 606). The Company adopted the updates
in ASC 606 effective January 1, 2018 on a modified retrospective basis
but did not record a cumulative effect adjustment to retained earnings
on application of the updates because the adoption of the updates in
ASC 606 had no material impact on the timing of revenue recognition
for the Company or its subsidiaries. ASC 606 is a comprehensive,
principles-based accounting standard which amended previous 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 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.

Due to the diverse business operations of the Company, recognition

of revenue from contracts with customers depends on the product
produced and sold or service performed. The Company recognizes
revenue from contracts with customers, at prices that are fixed or
determinable as evidenced by an agreement with the customer, when
the Company has met its performance obligation under the contract
and it is probable that the Company will collect the amount to which
it is entitled in exchange for the goods or services transferred or to be
transferred to the customer. Depending on the product produced and
sold or service performed and the terms of the agreement with the
customer, the Company recognizes revenue either over time, in the
case of delivery or transmission of electricity or related services or the
production and storage of certain custom-made products, or at a point
in time for the delivery of standardized products and other products
made to the customers specifications where the terms of the contract
require transfer of the completed product. 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 ASC 606. Provisions for sales
returns, early payment terms discounts, volume-based variable pricing
incentives and warranty costs are recorded as reductions to revenue at
the time revenue is recognized based on customer history, historical
information and current trends.

In addition to recognizing revenue from contracts with customers
under ASC 606, the Company also records adjustments to Electric segment
revenues for amounts subject to future collection under alternative
revenue programs (ARPs) as defined in ASC 980. The ARP revenue
adjustments are recorded on the basis of recoverable costs incurred
and returns earned under rate riders on a separate line on the face of
the Company’s consolidated statements of income as they do not meet
the criteria to be classified as revenue from contracts with customers.

Electric Segment Revenues—In the Electric segment, the Company
recognizes revenue in two categories: (1) revenues from contracts with
customers and (2) adjustments to revenues for amounts collectible
under ARPs.

Most Electric segment revenues are earned from the generation,
transmission and sale of electricity to retail customers at rates approved
by regulatory commissions in the states where OTP provides service.
OTP also earns revenue from the transmission of electricity for others
over the transmission assets it owns separately, or jointly with other
transmission service providers, under rate tariffs established by the
independent transmission system operator and approved by the FERC.
These revenues account for over 80% of other electric revenues
reported in the table of disaggregated revenues in note 2. A third
source of revenue for OTP comes from the generation and sale of
electricity to wholesale customers at contract or market rates. Revenues
from all these sources meet the criteria to be classified as revenue
from contracts with customers and are recognized over time as energy
is delivered or transmitted. Revenue is recognized based on the metered
quantity of electricity delivered or transmitted at the applicable rates.
For electricity delivered and consumed after a meter is read but prior
to the end of the reporting period, OTP records revenue and an unbilled
receivable based on estimates of the kilowatt-hours (kwh) of energy
delivered to the customer.

ARPs provide for adjustments to rates outside of a general rate case

proceeding, usually as a surcharge applied to future billings typically
through the use of rate riders subject to periodic adjustments, to
encourage or incentivize investments in certain areas such as
conservation, renewable energy, pollution reduction or control,
improved infrastructure of the transmission grid or other programs
that provide benefits to the general public under public policy, laws or
regulations. ARP riders generally provide for the recovery of specified
costs and investments and include an incentive component to provide
the regulated utility with a return on amounts invested. OTP has
recovered costs and earned incentives or returns on investments
subject to recovery under several ARP rate riders, including:
(cid:1) In Minnesota: Transmission Cost Recovery (TCR), Environmental

Cost Recovery (ECR), Renewable Resource Adjustment (RRA) and
Conservation Improvement Program riders.

(cid:1) In North Dakota: TCR, ECR and RRA riders
(cid:1) In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation)

riders.

OTP accrues ARP revenue on the basis of costs incurred, investments

made and returns on those investments that qualify for recovery
through established riders. Amounts billed under riders in effect at the
time of the billing are included in revenues from contracts with customers
net of amounts billed that are subject to refund through future rider
adjustments. Amounts accrued and subject to recovery through future
rider rate updates and adjustments are reported as ARP revenue
adjustments on a separate line in the revenue section of the Company’s
consolidated statement of income. See table in note 3 for total revenues
billed and accrued under ARP riders for the years ended December 31,
2018, 2017 and 2016.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

Manufacturing Segment Revenues—Companies in the Manufacturing
segment, BTD Manufacturing, Inc. (BTD) and T.O. Plastics, Inc. (T.O.
Plastics), earn revenue predominantly from the production and delivery
of custom-made or standardized parts to customers across several
industries. BTD also earns revenue from the production and sale of
tools and dies to other manufacturers. For the production and delivery
of standardized products and other products made to customer
specifications where the terms of the contract require transfer of the
completed product, the operating company has met its performance
obligation and recognizes revenue at the point in time when the product
is shipped and adjusts the revenue for volume rebate variable pricing
considerations the company expects the customer will earn and for
applicable early payment discounts the company expects the customer
will take. For revenue recognized on products when shipped, the
operating companies have no further obligation to provide services
related to such products. The shipping terms used in these instances
are FOB shipping point.

Plastics Segment Revenues—Companies in our Plastics segment earn
revenue predominantly from the sale and delivery of standardized
polyvinyl chloride (PVC) pipe products produced at their manufacturing
facilities. Revenue from the sale of these products is recognized at the
point in time when the product is shipped based on prices agreed to in
a purchase order. Billed amounts of revenue recognized are adjusted for
volume rebate variable pricing considerations the operating company
expects the customer will earn and applicable early payment discounts
the company expects the customer will take. For revenue recognized
on shipped products, there is no further obligation to provide services
related to such product. The shipping terms used in these instances are
FOB shipping point. The Plastics segment has one customer for which
it produces and stores a product made to the customer’s specifications
and design under a build and hold agreement. For sales to this customer,
the operating company recognizes revenue as the custom-made
product is produced, adjusting the amount of revenue for volume rebate
variable pricing considerations the operating company expects the
customer will earn and applicable early payment discounts the company
expects the customer will take. Ownership of the pipe transfers to the
customer prior to delivery and the operating company is paid a
negotiated fee for storage of the pipe. Revenue for storage of the
pipe is also recognized over time as the pipe is stored.

See operating revenue table in note 2 for a disaggregation of the

Company’s revenues by business segment for the years ended
December 31, 2018, 2017 and 2016.

Agreements Subject to Legally Enforceable Netting Arrangements
OTP has certain derivative contracts that are designated as normal
purchases. 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.

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

2018

2017

34
123
26

7,484

1,294

8,961

45
115
24

7,160

1,285

8,629

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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, 2018. See further discussion below.

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, 2018 and December 31, 2017:

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.

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.

December 31, 2018 (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:

$ 1,294

$ 5,898

1,586

Money Market and Mutual Funds—

Nonqualified Retirement Savings Plan

838

Total Assets

$ 2,132

$ 7,484

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:

$ 1,285

$ 5,373

1,787

Money Market and Mutual Funds—

Nonqualified Retirement Savings Plan

823

Total Assets

$ 2,108

$ 7,160

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
Inventories, valued at the lower of cost or net realizable value, consist
of the following:

(in thousands)

Finished Goods
Work in Process
Raw Material, Fuel and Supplies

Total Inventories

December 31, December 31,

2018

37,130
20,393
48,747

2017

26,605
14,222
47,207

$ 106,270

88,034

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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.

The following tables summarize changes to goodwill by business segment during 2018 and 2017:

(in thousands)

Manufacturing
Plastics

Total

(in thousands)

Manufacturing
Plastics

Total

Gross Balance
December 31,
2017

18,270
19,302

37,572

Gross Balance
December 31,
2016

18,270
19,302

37,572

Accumulated
Impairments

Balance
(net of impairments)
December 31,
2017

Balance
Adjustments (net of impairments)
December 31,
to Goodwill in
2018
2018

—
—

—

18,270
19,302

37,572

—
—

—

18,270
19,302

37,572

Accumulated
Impairments

Balance
(net of impairments)
December 31,
2016

Balance
Adjustments (net of impairments)
December 31,
to Goodwill in
2017
2017

—
—

—

18,270
19,302

37,572

—
—

—

18,270
19,302

37,572

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.

The following table summarizes the components of the Company’s

intangible assets at December 31, 2018 and December 31, 2017:

Supplemental Disclosures of Cash Flow Information

(in thousands)

Noncash Investing Activities:

Transactions Related to Capital
Additions not Settled in Cash

As of December 31,

2018

2017

13,757

13,887

December 31, 2018
(in thousands)

Carrying Accumulated Carrying
Amount Amortization Amount

Gross

Remaining
Net Amortization
Periods
(months)

Amortizable Intangible Assets:

Customer Relationships
Other

Total

$22,491
154

$22,645

$ 10,127
68

$12,364
86

$ 10,195

$12,450

December 31, 2017 (in thousands)

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

12-200
20

24-212
8
32

The amortization expense for these intangible assets was:

(in thousands)

Amortization Expense—Intangible Assets

2018

$1,315

2017

2016

$1,347

$1,436

The estimated annual amortization expense for these intangible

assets for the next five years is:

(in thousands)

2019

2020

2021

2022

2023

Estimated Amortization Expense—

Intangible Assets

$ 1,184 $ 1,133 $ 1,099 $ 1,099 $ 1,099

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

(in thousands)

2018

2017

2016

Cash Paid (Received) During the Year for:

Interest (net of amount capitalized)
Income Taxes

$ 28,109
$ 6,109

$ 29,791
$ 5,064

$ 31,269
$ (1,291)

New Accounting Standards Adopted
ASU 2014-09—In May 2014 the FASB issued ASU 2014-09, Revenue
from Contracts with Customers (Topic 606). The Company adopted the
updates in ASC 606 effective January 1, 2018 on a modified retrospective
basis. See disclosures above under Revenue Recognition.

ASU 2016-01—In January 2016 the FASB issued ASU No. 2016-01,
Financial Instruments—Overall (Subtopic 825-10) (ASU 2016-01). The
amendments in ASU 2016-01 address certain aspects of recognition,
measurement, presentation, and disclosure of financial instruments
and require equity investments (except those accounted for under the
equity method of accounting or those that result in consolidation of
the investee) to be measured at fair value with changes in fair value
recognized in net income. For the Company, the amendments in ASU
2016-01 are effective for fiscal years beginning after December 15, 2017,
including interim periods within those fiscal years. The Company
adopted the updates in ASU 2016-01 in the first quarter of 2018,
which results in changes in the fair value of equity instruments held
as investments by the Company’s captive insurance company being
classified in net income.

ASU 2017-07—In March 2017 the FASB issued ASU 2017-07 with the
intent of improving 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, which
the Company has provided in the electric operation and maintenance
and other nonelectric expense lines on its income statement. 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
Company has provided the amount of the nonservice cost components
of net periodic postretirement benefit costs in a separate line below
interest expense on the face of its consolidated income statement. 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 Company adopted the amendments on January 1, 2018.
The amendments have been 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
Company’s consolidated income statements 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 applicable to OTP, 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 the components of net periodic
pension costs as recoverable operating expenses. OTP has established
regulatory assets to reflect the effect of the required regulatory
accounting treatment of the nonservice cost components that cannot
be capitalized to plant in service under ASU 2017-07.

The Company’s nonservice cost components of net periodic

postretirement 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 nonservice costs components of net periodic
postretirement benefit costs included in operating expense in 2017
and 2016 are now reported on a separate line outside of operating
income and above other income in the Company’s consolidated
statements of income. Additional information on the allocation of
postretirement benefit costs for the years ended December 31, 2018,
2017 and 2016 is provided in note 11 for the Company’s major benefit
programs presented.

New Accounting Standards Pending Adoption
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. The Company
has developed a list of all current leases outstanding. The Company
has determined areas where the amendments in ASU 2016-02 are
applicable to its businesses, evaluated transition options and determined
the practical expedients it will elect on implementation. The Company
will apply the amendments in ASU 2016-02 to its consolidated financial
statements in the first quarter of 2019. Other than first-time recognition
of these types of operating leases on the Company’s consolidated
balance sheet, the implementation is not expected to have a significant
impact on the Company’s consolidated financial statements. See note
8 for further information on leases and the Company’s elections for
applying the new standard and the expected impacts on adoption.

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 must 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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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 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. The Company will early adopt the
amendments in ASU 2017-04 in 2019. In 2018, there was no indication
that the carrying amount of any of the Company’s reporting units
exceeded the reporting unit’s fair value. Therefore, there was no
requirement to apply step 2 for impairment testing at December 31, 2018.

ASU 2018-02—In February 2018 the FASB issued ASU No. 2018-02,
Income Statement—Reporting Comprehensive Income (Topic 220):
Reclassification of Certain Tax Effects from Accumulated Other
Comprehensive Income (ASU 2018-02). The amendments in ASU 2018-02,
which are narrow in scope, allow a reclassification from accumulated
other comprehensive income to retained earnings for stranded tax
effects resulting from the TCJA. Consequently, the amendments
eliminate the stranded tax effects resulting from the TCJA and will
improve the usefulness of information reported to financial statement
users. The amendments in ASU 2018-02 also require certain disclosures
about stranded tax effects and are effective for fiscal years beginning
after December 15, 2018, and interim periods within those fiscal years.
The amendments in ASU 2018-02 can be applied either in the period of
adoption or retrospectively to each period (or periods) in which the
effect of the change in the U.S. federal corporate income tax rate in the
TCJA is recognized. The Company will adopt the amendments in ASU
2018-02 in the first quarter of 2019 and apply them in the period of
adoption and not retrospectively. On adoption, the Company will
reclassify $784,000 of income tax effects of the TCJA on the gross
deferred tax amounts at the date of enactment of the TCJA from
other comprehensive loss to retained earnings so the remaining gross
deferred tax amounts related to items in other comprehensive loss
will reflect current effective tax rates.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

2. Business 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 maker. 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 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 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. 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 2018, 2017 and 2016. While no single customer
accounted for over 10% of consolidated revenue in 2018, certain
customers provided a significant portion of each business segment’s
2018 revenue. The Electric segment has one customer that provided
11.2% of 2018 segment revenues. The Manufacturing segment has
one customer that manufactures and sells recreational vehicles that
provided 22.2% of 2018 segment revenues and one customer that
manufactures and sells lawn and garden equipment that provided
11.2% of 2018 segment revenues. The Manufacturing segment’s top
five revenue-generating customers provided over 52% of 2018 segment
revenues. The Plastics segment has two customers that individually
provided 22.1% and 17.0% of 2018 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 the Company’s long-lived assets are within the United States and

sales within the United States accounted for 98.4% of sales in 2018,
98.2% of sales in 2017 and 98.6% of sales in 2016.

The Company evaluates the performance of its business segments
and allocates resources to them based on earnings contribution and
return on total invested capital. Information for the business segments
for 2018, 2017 and 2016 is presented in the following table:

2018

2017

2016

3. Rate and Regulatory Matters

(in thousands)

Operating Revenue
Electric Segment:

Retail Sales Revenue from Contracts

with Customers

Changes in Accrued ARP Revenues

Total Retail Sales Revenue

Wholesale Revenues—Company Generation
Other Electric Revenues

$ 388,690 $ 376,902 $ 374,506
2,104
376,610
4,584
46,189
427,383

(439)
388,251
7,735
54,269
450,255

(1,971)
374,931
5,173
54,433
434,537

Total Electric Segment Revenues
Manufacturing Segment:
Metal Parts and Tooling
Plastic Products and Tooling
Other

223,765
35,836
8,808
268,409
Total Manufacturing Segment Revenues
Plastics Segment—Sale of PVC Pipe Products 197,840
(57)
Intersegment Eliminations

185,868
31,431
3,990
221,289
154,901
(34)
$ 916,447 $ 849,350 $ 803,539

189,242
33,939
6,557
229,738
185,132
(57)

Total

Cost of Products Sold

Manufacturing
Plastics
Intersegment Eliminations

Total

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

Electric
Manufacturing
Plastics
Corporate and Intersegment Eliminations

Total

Income Tax Expense (Benefit)

Electric
Manufacturing
Plastics
Corporate

Total

Net Income (Loss)

Electric
Manufacturing
Plastics
Corporate

Total

Capital Expenditures

Electric
Manufacturing
Plastics
Corporate

Total

Identifiable Assets

Electric
Manufacturing
Plastics
Corporate

Total

$ 205,699 $ 176,473 $ 171,732
123,496
(6)
$ 354,559 $ 316,562 $ 295,222

148,881
(21)

140,107
(18)

29,650 $
12,323
9,607
(36)
51,544 $

55,935 $
14,794
3,719
218
74,666 $

23,785 $
11,564
6,182
(39)
41,492 $

53,276 $
15,379
3,817
73
72,545 $

21,994
9,402
7,315
(28)
38,683

53,743
15,794
3,861
47
73,445

88,031 $
18,266
32,917
(9,825)

94,082
11,769
18,142
(7,362)
$ 129,389 $ 132,287 $ 116,631

94,797 $
14,101
29,644
(6,255)

26,365 $
2,230
609
1,204
30,408 $

5,685 $
3,393
8,728
(3,218)
14,588 $

54,431 $
12,839
23,819
(8,744)
82,345 $

25,334 $
2,215
633
1,422
29,604 $

17,013 $
989
7,448
1,806
27,256 $

49,446 $
11,050
21,696
(9,753)
72,439 $

25,069
3,859
1,034
1,924
31,886

16,366
2,276
6,538
(4,961)
20,219

49,829
5,694
10,628
(3,830)
62,321

87,287 $ 118,444 $ 149,648
8,429
9,916
13,316
3,085
4,432
4,199
97
121
623
$ 105,425 $ 132,913 $ 161,259

$1,728,534 $1,690,224 $ 1,622,231
166,525
84,592
39,037
$2,052,517 $2,004,278 $ 1,912,385

187,556
91,630
44,797

167,023
87,230
59,801

Below are descriptions of OTP’s major capital expenditure projects that
have had, or are expected to 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 2018, 2017 and 2016.

MAJOR CAPITAL EXPENDITURE PROJECTS
Merricourt Project—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 and certain specified
liabilities associated with a 150-megawatt (MW) wind farm in
southeastern North Dakota (the Merricourt Project) for a purchase price
of approximately $34.7 million, subject to adjustments for interconnection
costs. The Purchase Agreement will close on satisfaction of various
closing conditions (including regulatory approvals). Also on November 16,
2016, OTP entered into a Turnkey Engineering, Procurement and
Construction Services Agreement with EDF pursuant to which EDF will
develop, design, procure, construct, interconnect, test and commission
the wind farm with a targeted completion date in 2020 for consideration
of approximately $200.5 million, subject to certain adjustments, payable
following the closing of the Purchase Agreement in installments in
connection with certain project construction milestones. Depending on
the timing of MISO interconnection approval, construction of the
Merricourt Project is currently anticipated to begin in mid-2019. The
agreements contain customary representations, warranties, covenants
and indemnities for this type of transaction. As of December 31, 2018,
OTP had capitalized approximately $4.9 million in development costs
associated with the Merricourt Project. A final order for an Advance
Determination of Prudence (ADP), subject to qualifications and
compliance obligations, and a Certificate of Public Convenience and
Necessity were issued by the NDPSC on November 3, 2017. On
October 26, 2017 the MPUC approved the facility under the Renewable
Energy Standard making the Merricourt Project eligible for cost
recovery under the Minnesota Renewable Resource Recovery rider,
subject to qualifications and reporting obligations.

Astoria Station—OTP is moving forward with plans for the development,
construction and ownership of this 250-MW simple-cycle natural
gas-fired combustion turbine generation facility near Astoria, South
Dakota 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. As of December 31,
2018, OTP had capitalized approximately $8.3 million in development
and other costs associated with Astoria Station. On August 3, 2018 the
SDPUC issued an order granting a site permit for Astoria Station. A final
order granting ADP for Astoria Station was issued by the NDPSC on
November 3, 2017, subject to certain qualifications and compliance
obligations. The interconnection agreement for Astoria Station was
executed by MISO in December 2018 and accepted by the FERC in
January 2019. In a September 26, 2018 hearing the NDPSC approved an
overall annual revenue increase for OTP and established a Generation
Cost Recovery rider for future recovery of costs incurred for Astoria
Station.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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., and the parties will have equal ownership
interest in the transmission line portion of the project. The 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 MISO 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 the
line was energized on February 6, 2019. OTP’s capitalized costs on this
project as of December 31, 2018 were approximately $106 million,
which includes assets that are 100% owned by OTP.

Big Stone South–Brookings 345-kV MVP—OTP invested approximately
$73 million, which includes assets that are 100% owned by OTP, and
has a 50.0% ownership interest in the jointly-owned assets of this
70-mile transmission line energized in 2017.

Recovery of OTP’s major transmission investments is through the MISO

Tariff (several as MVPs) and, currently, Minnesota, North Dakota and
South Dakota base rates and 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 Air Quality
Control System (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
General Rates—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 (ROE) decreased from 10.74% to 9.41%.

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 MVPs will be included in the
Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota
customers (see discussion under Minnesota Transmission Cost Recovery
Rider below), and (2) approval of OTP’s proposal to transition rate base,
expenses and revenues from ECR and TCR riders to base rate recovery,
which occurred when final rates were implemented on November 1, 2017.
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.
OTP accrued interim and rider rate refunds until final rates became
effective. 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. In addition to the interim rate refund, OTP refunded
the difference between (1) amounts collected under its Minnesota ECR
and TCR riders based on the 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. 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 were refunded to Minnesota
customers over a 12-month period beginning in November 2017
through reductions in the Minnesota ECR and TCR rider rates. The TCR
rider rate is provisional and subject to revision under a separate docket.

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.

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 included as 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 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 financial incentive is also limited to 40%
of 2017 MNCIP spending, 35% of 2018 spending and 30% of 2019
spending. The new model reduces the MNCIP financial incentive by
approximately 50% compared to the previous incentive mechanism.

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 a decrease in energy savings compared to 2016 program results of
approximately 10%. OTP requested approval for recovery of its 2017
MNCIP program costs not included in base rates on March 30, 2018.
The request included a $2.6 million financial incentive and an update to
the MNCIP surcharge from the MPUC. On June 13, 2018 OTP increased
its request for a financial incentive to $2.9 million. On October 4, 2018,
the MPUC issued an order approving OTP’s request of $2.9 million
subject to further review by the MPUC to ensure no previous decisions
conflict with the decision, with $0.3 million subject to a possible
subsequent refund.

Based on results from the 2018 MNCIP program year, OTP recognized
$3.0 million out of a potential $3.15 million in financial incentives earned
in 2018. OTP will request approval for recovery of its 2018 program
costs not included in base rates, a $3.15 million financial incentive and
an update to its MNCIP surcharge from the MPUC by April 1, 2019.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

Transmission Cost Recovery Rider—The Minnesota Public Utilities Act
(the MPU Act) authorizes the MPUC to approve 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 that are 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 most recently completed general
rate case or such other rate of return the MPUC determines is in the
public interest. Additionally, following approval of a 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 MVPs 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 diverted
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
resulted in the projects being treated as retail investments for Minnesota
retail ratemaking purposes. Because the FERC’s revenue requirements
and authorized returns vary from the MPUC revenue requirements and
authorized returns for the project investments over the lives of the
projects, the impact of this decision would 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
jurisdictionally allocate costs of the FERC MVP transmission projects
in the TCR rider.

On June 11, 2018 the Minnesota Court of Appeals reversed the MPUC’s
order related to the inclusion of Minnesota’s jurisdictional share of OTP’s
investment in the Big Stone South–Brookings and Big Stone South–
Ellendale MVPs and all revenues received from other utilities under
MISO’s tariffed rates as a credit in OTP Minnesota TCR revenue
requirement calculations. On July 11, 2018 the MPUC filed a petition for
review of the MVP decision to the Minnesota Supreme Court, which
granted review of the Minnesota Court of Appeals decision. A decision
by the Minnesota Supreme Court is expected in either second or third
quarter 2019.

On November 30, 2018 OTP filed its annual update and supplemental

filing to the Minnesota TCR rider. In this filing two scenarios were
submitted based on whether the Minnesota Supreme Court affirms

the original decision by the Minnesota Court of Appeals to exclude the
MVP projects from the TCR rider or overturns the Minnesota Court of
Appeals decision and includes the two MVP projects in the TCR rider. In
both situations the rates are proposed to be effective June 1, 2019 if a
decision is made in late first quarter or early second quarter 2019. If
the decision is made later than second quarter of 2019, it is likely the
MPUC will delay its decision on the TCR rider update. The amount
credited to Minnesota customers through the TCR through December 31,
2018 and subject to recovery if the Minnesota Court of Appeals
decision is upheld, is approximately $2.3 million.

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 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.
Accordingly, in its 2018 annual update filing OTP requested, and the
MPUC approved, setting the Minnesota ECR rider rate to zero effective
December 1, 2018.

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%. The requested $13.1 million
increase was net of reductions in North Dakota RRA, TCR and ECR rider
revenues that would have resulted from a lower allowed rate of return
on equity and changes in allocation factors in the general rate case. In
the request, OTP proposed an allowed return on rate base of 7.97%
and an allowed rate of return on equity of 10.3%. 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. In
response to the reduction in the federal corporate tax rate under the
TCJA, the NDPSC issued an order on February 27, 2018 reducing OTP’s
annual revenue requirement for interim rates by $4.5 million to
$8.3 million, effective March 1, 2018.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

for Astoria Station. The net revenue increase reflects a reduction in
income tax recovery requirements related to the TCJA and decreases
in rider revenue recovery requirements. Final rates were effective
February 1, 2019, with refunds of excess revenues collected under
interim rates applied to customers’ April 2019 bills. OTP has accrued
an interim rate refund of $3.0 million as of December 31, 2018, which
includes $0.8 million in excess revenue collected for income taxes
under interim rates in effect in January and February 2018.

OTP’s previously approved general rate increase in North Dakota of

$3.6 million, or approximately 3.0%, was granted by the NDPSC in an
order issued in November 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 RRA
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.

Effective in February 2019 with the implementation of general rates

based on the results of OTP’s 2017 general rate case, recovery of
renewable resource costs previously being recovered through the
North Dakota RRA rider transitioned to recovery in base rates.

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. Based on the order in the 2017 general
rate case, only certain costs will remain subject to refund or recovery
through this rider: Southwest Power Pool (SPP) costs and MISO
Schedule 26 and 26A revenues and expenses and costs related to
rider projects still under construction in the test year used in the 2017
general rate case. This rider will continue to be updated annually for
new or modified electric transmission facilities and associated
operating costs.

Environmental Cost Recovery Rider—OTP has an ECR rider in North
Dakota. The ECR rider has provided for a return on investment at the
level approved in OTP’s preceding general rate case and for recovery
of OTP’s North Dakota share of environmental investments and costs
approved for recovery under the rider. Prior to its 2017 general rate
case reaching a final settlement and final rates going into effect on
February 1, 2019, OTP’s North Dakota jurisdictional share of the revenue
requirements associated with its investment in the Big Stone Plant
AQCS and Hoot Lake Plant MATS projects were being recovered
through the ECR rider. Effective February 1, 2019 these rate base
investments are being recovered under general rates and the rider
was zeroed out except for an overcollection balance that will be
refunded to ratepayers through the rider.

SOUTH DAKOTA
General Rates—On April 20, 2018 OTP filed a request with the SDPUC
to increase non-fuel rates in South Dakota by approximately $3.3 million
annually, or 10.1%, as the first step in a two-step request. Interim rates
went into effect October 18, 2018. On February 5, 2019 SDPUC staff
and OTP requested that the SDPUC issue a procedural schedule setting
evidentiary hearings for March 26-28, 2019. The full effects of the TCJA
on South Dakota revenue requirements will be addressed in the rate
case and incorporated into final rates at the conclusion of that case.
The second step in the request is an additional 1.7% increase to recover
costs for the proposed Merricourt wind generation facility when the
facility goes into service. On February 15, 2019 OTP reached a partial
settlement with SDPUC staff which requires SDPUC approval.

OTP’s previously approved general rate increase in South Dakota of
approximately $643,000 or approximately 2.32% was granted by the
SDPUC in an order issued in April 2011 and effective in June 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. 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 South Dakota share of environmental investments and costs
approved for recovery under the rider. Prior to interim rates going into
effect on October 18, 2018 pending a final decision on OTP’s South
Dakota general rate increase request, OTP’s South Dakota jurisdictional
share of the revenue requirements associated with its investment in
the Big Stone Plant AQCS and Hoot Lake Plant MATS projects were
being recovered through the ECR rider. With the initiation of interim
rates, recovery of the costs previously being recovered under the ECR
rider was transitioned to recovery under interim rates and the South
Dakota ECR rider rate was reset to provide a refund to customers
while interim rates are in effect.

Reagent Costs and Emission Allowances—The SDPUC has approved
the recovery of reagent and emission allowance costs in OTP’s South
Dakota FCA rider.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

RATE RIDER UPDATES
The following table provides summary information on the status of updates since January 1, 2015 for the rate riders described above:

Rate Rider

Minnesota

Conservation Improvement Program
2017 Incentive and Cost Recovery
2016 Incentive and Cost Recovery
2015 Incentive and Cost Recovery
2014 Incentive and Cost Recovery

Transmission Cost Recovery

2018 Annual Update –Scenario A
–Scenario B

2017 Rate Reset
2016 Annual Update
2015 Annual Update
2014 Annual Update

Environmental Cost Recovery

2018 Annual Update
2017 Rate Reset
2016 Annual Update
2015 Annual Update

Renewable Resource Adjustment

2018 Annual Update
2017 Rate Reset

North Dakota

Renewable Resource Adjustment

2019 Annual Update
2018 Rate Reset for effect of TCJA
2017 Rate Reset
2016 Annual Update
2015 Annual Update
2014 Annual Update

Transmission Cost Recovery
2018 Supplemental Update
2018 Rate Reset for effect of TCJA
2017 Annual Update
2016 Annual Update
2015 Annual Update

Environmental Cost Recovery

2018 Update
2018 Rate Reset for effect of TCJA
2017 Rate Reset
2017 Annual Update
2016 Annual Update
2015 Annual Update

South Dakota

Transmission Cost Recovery
2018 Interim Rate Reset
2017 Annual Update
2016 Annual Update
2015 Annual Update
2014 Annual Update

Environmental Cost Recovery

2018 Interim Rate Reset
2017 Annual Update
2016 Annual Update
2015 Annual Update

R—Request Date
A—Approval Date

Effective Date
Requested or
Approved

Annual
Revenue
($000s)

A—October 4, 2018
A—September 15, 2017
A—July 19, 2016
A—July 10, 2015

November 1, 2018
October 1, 2017
October 1, 2016
October 1, 2015

R—November 30, 2018

June 1, 2019

A—October 30, 2017
A—July 5, 2016
A—March 9, 2016
A—February 18, 2015

A—November 29, 2018
A—October 30, 2017
A—July 5, 2016
A—March 9, 2016

A—August 29, 2018
A—October 30, 2017

R—December 31, 2018
A—February 27, 2018
A—December 20, 2017
A—March 15, 2017
A—June 22, 2016
A—March 25, 2015

A—December 6, 2018
A—February 27, 2018
A—November 29, 2017
A—December 14, 2016
A—December 16, 2015

A—December 19, 2018
A—February 27, 2018
A—December 20, 2017
A—July 12, 2017
A—June 22, 2016
A—June 17, 2015

A—October 18, 2018
A—February 28, 2018
A—February 17, 2017
A—February 12, 2016
A—February 13, 2015

A—October 18, 2018
A—October 13, 2017
A—October 26, 2016
A—October 15, 2015

November 1, 2017
September 1, 2016
April 1, 2016
March 1, 2015

December 1, 2018
November 1, 2017
September 1, 2016
October 1, 2015

November 1, 2018
November 1, 2017

April 1, 2019
March 1, 2018
January 1, 2018
April 1, 2017
July 1, 2016
April 1, 2015

February 1, 2019
March 1, 2018
January 1, 2018
January 1, 2017
January 1, 2016

February 1, 2019
March 1, 2018
January 1, 2018
August 1, 2017
July 1, 2016
July 1, 2015

October 18, 2018
March 1, 2018
March 1, 2017
March 1, 2016
March 1, 2015

October 18, 2018
November 1, 2017
November 1, 2016
November 1, 2015

$
$
$
$

$
$
$
$
$
$

$
$
$
$

$
$

$
$
$
$
$
$

$
$
$
$
$

$
$
$
$
$
$

$
$
$
$
$

$
$
$
$

10,283
9,868
8,590
8,689

6,475
2,708
(3,311)
4,736
7,203
8,388

—
(1,943)
11,884
12,104

5,886
1,279

(236)
9,650
9,989
9,156
9,262
5,441

4,801
7,469
7,959
6,916
9,985

(378)
7,718
8,537
9,917
10,359
12,249

1,171
1,779
2,053
1,895
1,538

(189)
2,082
2,238
2,728

Rate

$0.00600/kwh
$0.00536/kwh
$0.00275/kwh
$0.00287/kwh

Various
Various
Various
Various
Various
Various

0% of base
-0.935% of base
6.927% of base
7.006% of base

$.00244/kwh
$.00049/kwh

-0.224% of base
7.493% of base
7.756% of base
7.005% of base
7.573% of base
4.069% of base

Various
Various
Various
Various
Various

-0.310% of base
5.593% of base
6.629% of base
7.633% of base
7.904% of base
9.193% of base

Various
Various
Various
Various
Various

-$0.00075/kwh
$0.00483/kwh
$0.00536/kwh
$0.00643/kwh

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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)

2018

2017

2016

Minnesota

Conservation Improvement Program
Costs and Incentives (1)
Renewable Resource Adjustment
Environmental Cost Recovery
Transmission Cost Recovery

North Dakota

Renewable Resource Adjustment
Environmental Cost Recovery
Transmission Cost Recovery

South Dakota

Environmental Cost Recovery
Transmission Cost Recovery
Conservation Improvement Program
Costs and Incentives

$12,028
3,067
(24)
(2,039)

$ 9,225
(196)
8,148
2,973

$ 12,920
—
12,443
5,795

8,529
7,318
7,016

1,676
1,664

7,620
9,782
8,729

2,345
1,843

7,800
11,089
7,694

2,538
1,820

628

598

468

(1) Includes MNCIP costs recovered in base rates.

TCJA
The TCJA, passed in December 2017, reduced the federal corporate
income tax rate from 35% to 21%, effective January 1, 2018. At the time
of passage, all OTP’s rates had been developed using a 35% tax rate.
The MPUC, the NDPSC, the SDPUC and the FERC each initiated dockets
or proceedings to begin working with utilities to assess the impact of
the lower rates on electric rates, and to develop regulatory strategies
to incorporate the tax change into future rates, if warranted.

The MPUC required regulated utilities providing service in Minnesota

to make filings by February 15, 2018. On August 9, 2018 the MPUC
determined the impacts of the TCJA as calculated, including amortization
of excess accumulated deferred income taxes, should be refunded and
rates should be adjusted going forward to account for the impacts of the
TCJA. On December 5, 2018 the MPUC released its final order related
to the TCJA docket which directs OTP to return to ratepayers, in a
one-time refund, the TCJA-related savings accrued prior to the refund
effective date. OTP must amortize its protected excess accumulated
deferred income taxes (ADIT) as early as U.S. Internal Revenue Service
provisions allow and amortize its unprotected excess ADIT over ten
years. OTP was instructed to use its 2017 year-end ADIT balance to
calculate its excess ADIT balance. The order also directs OTP to use
these savings to reduce customers’ base rates prospectively—allocating
the savings to customers in proportion to the size of each customer’s
bill, or to each customer class in proportion to the class’s size. OTP
expects the rate change and refund to occur in the second quarter of
2019, pending MPUC approval of OTP’s January 3, 2019 compliance filing.
As described above, OTP’s current general rate cases in North Dakota
and South Dakota reflect the ongoing impact of the TCJA in interim rates.
OTP has accrued refund liabilities for the time periods when revenues
were collected under rates set to recover higher levels of federal income
taxes than OTP incurs under the lower federal tax rates in the TCJA.
As of December 31, 2018, accrued refund liabilities related to the tax
rate reduction were $8.4 million in Minnesota, $0.8 million in North
Dakota for amounts collected reflecting the higher tax rates under
interim rates in effect in January and February 2018, $1.0 million in
South Dakota billed prior to October 18, 2018, and $0.2 million for
FERC jurisdictional rates.

As of March 15, 2018, the FERC granted the request for waiver from
a group of MISO transmission operators (including OTP) to revise inputs
to their projected net revenue requirements for the 2018 rate year to
reflect recent tax law changes.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

FERC
Wholesale power sales and transmission rates are subject to the
jurisdiction of the FERC under the Federal Power Act of 1935 (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
suspension period, subject to ultimate approval by the FERC.

MVPs—MVPs are designed to enable the MISO 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 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%. Several 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 went to 10.82% (a 10.32% base ROE plus the
0.5% RTO Adder) effective September 28, 2016.

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, 2018.

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 U.S. 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 NETOs complaint.
The motion is currently pending before the FERC.

FERC by the D.C. Circuit in April 2017. The FERC order established a
paper hearing on how the methodology should apply to the proceedings
pending before the FERC involving NETOs’ ROE. In the order, the FERC
selected a preliminary just and reasonable ROE for NETOs of 10.41%,
exclusive of incentives, with a proposed cap on any pre-existing
incentive-based total ROE at 13.08% and directed participants to
submit supplemental briefs and additional written evidence regarding
the proposed approaches to the Federal Power Act Section 206 inquiry
and how to apply them to the NETO ROE complaints. On November 15,
2018, FERC issued an order establishing a paper hearing on whether
and how a two-step ROE methodology developed for NETOs should
apply to the ROE for MISO transmission owners. Initial briefs were due
February 13, 2019 and reply briefs are due April 10, 2019.

OTP believes its estimated accrued MISO Tariff ROE refund liability

On October 16, 2018 the FERC issued an order proposing a

methodology for addressing the issues that were remanded to the

of $1.6 million as of December 31, 2018 related to the second MISO
tariff ROE complaint is appropriate.

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. 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, 2018

Current

Long-Term

Total

Remaining
Recovery/Refund
Period (months)

6,346
5,995
—
—
1,661
681

$ 118,433
3,285
7,169
2,423
743
947

$ 124,779
9,280
7,169
2,423
2,404
1,628

for Ratemaking Purposes and Subject to Deferred Recovery (1)

Debt Reacquisition Premiums (1)
North Dakota Deferred Rate Case Expenses Subject to Recovery (1)
Minnesota Renewable Resource Recovery Rider Accrued Revenues (2)
Minnesota Transmission Cost Recovery Rider Accrued Revenues (2)
Big Stone II Unrecovered Project Costs—South Dakota (1)
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues (1)
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up (1)
South Dakota Deferred Rate Case Expenses Subject to Recovery (1)
Minnesota SPP Transmission Cost Recovery Tracker (1)
Minnesota Environmental Cost Recovery Rider Accrued Revenues (2)
North Dakota Environmental Cost Recovery Rider Accrued Revenues (2)

Total Regulatory Assets

Regulatory Liabilities:

Deferred Income Taxes
Accumulated Reserve for Estimated Removal Costs—Net of Salvage
South Dakota Environmental Cost Recovery Rider Accrued Refund
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
North Dakota Renewable Resource Recovery Rider Accrued Refund
South Dakota Transmission Cost Recovery Rider Accrued Refund
Revenue for Rate Case Expenses Subject to Refund—Minnesota
Refundable Fuel Clause Adjustment Revenues
North Dakota Transmission Cost Recovery Rider Accrued Refund
Other

Total Regulatory Liabilities

Net Regulatory Asset/(Liability) Position

—
207
455
452
444
100
328
240
178
—
121
17

986
753
—
—
—
342
—
—
—
176
—
—

986
960
455
452
444
442
328
240
178
176
121
17

$ 17,225

$ 135,257

$ 152,482

—
—
207
—
177
168
—
121
60
5

738

$ 142,779
83,229
—
187
—
—
166
—
—
108

$ 142,779
83,229
207
187
177
168
166
121
60
113

$ 226,469

$ 227,207

$ 16,487

$ (91,212)

$ (74,725)

(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.

see below
21
asset lives
asset lives
24
28

asset lives
165
12
12
12
53
4
12
12
see below
12
12

asset lives
asset lives
12
24
12
12
see below
12
12
180

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

(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)
Debt Reacquisition Premiums (1)
North Dakota Deferred Rate Case Expenses Subject to Recovery (1)
Big Stone II Unrecovered Project Costs—South Dakota (1)
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues (1)
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up (1)
North Dakota Environmental Cost Recovery Rider Accrued Revenues (2)
Minnesota Deferred Rate Case Expenses Subject to Recovery (1)
North Dakota Renewable Resource Recovery Rider Accrued Revenues (2)

9,090
7,385
—
4,063
650
254
309
100
75
—
152
267
206

$ 112,487
2,774
6,651
2,405
1,636
960
—
442
—
1,985
—
—
236

$ 121,577
10,159
6,651
6,468
2,286
1,214
309
542
75
1,985
152
267
442

Total Regulatory Assets

Regulatory Liabilities:

Deferred Income Taxes
Accumulated Reserve for Estimated Removal Costs—Net of Salvage
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
Revenue for Rate Case Expenses Subject to Refund—Minnesota
Refundable Fuel Clause Adjustment Revenues
North Dakota Transmission Cost Recovery Rider Accrued Refund
Minnesota Environmental Cost Recovery Rider Accrued Refund
Minnesota Transmission Cost Recovery Rider Accrued Refund
Minnesota Renewable Resource Recovery Rider Accrued Refund
Other

Total Regulatory Liabilities

Net Regulatory Asset/(Liability) Position

$ 22,551

$ 129,576

$ 152,127

—
—
187
132
151
208
5,778
349
1,667
802
409
5

$ 149,052
83,100
—
48
—
—
—
—
—
609
—
84

$ 149,052
83,100
187
180
151
208
5,778
349
1,667
1,411
409
89

9,688

$ 12,863

$ 232,893

$ 242,581

$(103,317)

$ (90,454)

(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.

see below
21
asset lives
36
40
177
12
65
12
24
12
4
15

asset lives
asset lives
12
24
12
4
12
12
11
22
12
192

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.

The regulatory asset and liability related to Deferred Income Taxes
results from changes in statutory tax rates accounted for in accordance
with ASC Topic 740, Income Taxes.

All Deferred Marked-to-Market Losses recorded as of December 31,

2018 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.
The Nonservice Costs Components of Postretirement Benefits

Capitalized for Ratemaking Purposes and Subject to Deferred Recovery
are employee benefit-related costs that are required to be capitalized
for ratemaking purposes and are recovered over the depreciable lives
of the assets to which the related labor costs were applied.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 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 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, 2018.

North Dakota Renewable Resource Recovery Rider Accrued Refund

relates to amounts collected for qualifying renewable resource costs
incurred to serve North Dakota customers that are refundable to
North Dakota customers as of December 31, 2018.

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, 2018.

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 were subject to refund over a 24-month period
beginning with the establishment of interim rates in April 2016.

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, 2018.
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 were 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 were
refundable to Minnesota customers as of December 31, 2017.

The Minnesota Renewable Resource Recovery Rider Accrued Refund

relates to amounts collected for qualifying renewable resource costs
incurred to serve Minnesota customers that were refundable to
Minnesota 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.

Debt Reacquisition Premiums are being recovered from OTP
customers over the remaining original lives of the reacquired debt
issues, the longest of which is 165 months.

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 beginning with the
establishment of interim rates in January 2018.

Minnesota Renewable Resource Recovery Rider Accrued Revenues
relate to an increase in renewable revenue requirements resulting from
the expiration of tax credits for certain wind turbines. The balance
represents amounts subject to recovery from Minnesota customers that
have not been billed to Minnesota customers as of December 31, 2018.
The Minnesota Transmission Cost Recovery Rider Accrued Revenues
relate to revenues earned on qualifying transmission system facilities
and operating costs incurred to serve Minnesota customers that are
recoverable from Minnesota customers as of December 31, 2018.

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.
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.
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.
South Dakota Deferred Rate Case Expenses Subject to Recovery
relate to costs incurred in conjunction with OTP’s current rate case in
South Dakota and are currently being recovered beginning with the
establishment of interim rates in October 2018.

The Minnesota SPP Transmission Cost Recovery Tracker regulatory

asset relates to costs incurred to serve Minnesota customers that
are subject to recovery but that have not been billed to Minnesota
customers as of December 31, 2018.

The Minnesota Environmental Cost Recovery Rider Accrued Revenues
relate to revenues earned on the Minnesota share of OTP’s investment
in the Big Stone Plant AQCS project that are recoverable from Minnesota
customers as of December 31, 2018.

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, 2018.

Minnesota Deferred Rate Case Expenses Subject to Recovery relate
to costs incurred in conjunction with OTP’s 2016 rate case in Minnesota
which were being recovered over a 24-month period beginning with
the establishment of interim rates in April 2016.

North Dakota Renewable Resource Recovery Rider Accrued Revenues

relate to qualifying renewable resource costs incurred to serve North
Dakota customers that had not been billed to North Dakota customers
as of December 31, 2017.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

5. Common Shares and Earnings per Share

Shelf Registration and Common Share Distribution Agreement
On May 3, 2018 the Company filed a shelf registration statement with the
Securities and Exchange Commission (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 3, 2021. The shelf
registration statement replaced the Company’s prior shelf registration
statement. On May 1, 2018 the Company’s Distribution Agreement with
J.P. Morgan Securities, LLC (JPMS) for the Company’s At-the-Market
Offering Program ended as required under the agreement.

2018 Common Stock Activity
Following is a reconciliation of the Company’s common shares
outstanding from December 31, 2017 through December 31, 2018:

Common Shares Outstanding, December 31, 2017
Issuances:
Executive Stock Performance Awards (2015 awards)
Executive Stock Performance Awards (2016 and 2017 awards)
Vesting of Restricted Stock Units
Restricted Stock Issued to Directors
Directors Deferred Compensation
Retirements:
Shares Withheld for Individual Income Tax Requirements

Common Shares Outstanding, December 31, 2018

39,557,491

114,648
18,600
26,575
18,200
578

(71,208)

39,664,884

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
1,121,330 were available for issuance as of December 31, 2018. The
2014 Incentive Plan terminates on December 13, 2023.

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, 366,867 were available
for purchase as of December 31, 2018. 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, 7,757 common shares were purchased
in the open market in 2018, 4,202 common shares were purchased in
the open market and 5,284 common shares were issued in 2017 and
53,875 common shares were issued in 2016.

Dividend Reinvestment and Share Purchase Plan
On May 3, 2018, the Company filed a shelf registration statement with
the SEC 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. The shelf registration for the Plan expires
on May 3, 2021. In 2018, 116,822 common shares were purchased in
the open market to provide shares for the Plan. Although shares are
purchased on the open market, they must be sold under the registration
statement due to the features of the plan, leaving 1,383,178 common
shares available for purchase or issuance under the Plan as of
December 31, 2018. The shelf registration statement replaced the
Company’s prior shelf registration statement, which provided for the
issuance of up to 1,500,000 common shares under the Plan. Common
shares purchased in the open market under the Plan pursuant to the
Company’s prior shelf registration statement totaled 53,853 in 2018
and 87,634 in 2017. New common shares issued under the Plan
pursuant to the Company’s prior shelf registration statement totaled
97,698 in 2017 and 278,811 in 2016.

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 2018, 2017 and
2016. 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

Total Dilutive Shares

Weighted Average Common Shares Outstanding—Diluted

2018

2017

2016

39,599,944

39,457,261

38,546,459

212,043
59,980
17,751
2,478

292,252

210,784
56,952
20,380
2,970

291,086

118,644
45,712
16,778
3,417

184,551

39,892,196

39,748,347

38,731,010

The effect of dilutive shares on earnings per share for the years ended December 31, 2018, 2017 and 2016, resulted in no differences greater than

$0.016 between basic and diluted earnings per share in any period.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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. 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.

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 9, 2018, 18,200 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 9, 2018 was $43.40 per share, the average of the high and low market price on the date of
grant. The restricted shares granted in 2018 vest 33.3% per year on April 8 of each year in the period 2019 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.

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

46,800
18,200
21,775
—

43,225

2018

Weighted
Average
Grant-Date
Fair Value

32.65
43.40
31.94

37.53

$
$

661,000
696,000

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

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

2,895
—
2,895
—

—

2018

Weighted
Average
Grant-Date
Fair Value

29.41

—

$
$

16,000
85,000

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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

Restricted Stock Units Granted to Executive Officers
On February 5, 2018, 15,200 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 $41.325 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 2018 vest 25% per year on February 6 of each year in the period 2019 through 2022 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

47,750
15,200
17,650
—

45,300

2018

Weighted
Average
Grant-Date
Fair Value

32.71
41.325
32.462

35.70

$
$

769,000
573,000

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

Restricted Stock Units Granted to Employees
In 2018 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, 2022
Restricted Stock Units Vesting 100% on April 8, 2022
Restricted Stock Units Vesting 100% on April 8, 2022

Grant Date

Units Granted

Grant-Date Fair Value per Award

April 9, 2018
June 20, 2018
September 25, 2018

12,945
1,000
835

$38.45
$42.46
$43.25

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

46,440
14,780
8,925
2,825

49,470

2018

Weighted
Average
Grant-Date
Fair Value

27.07
38.99
25.23
25.86

31.03

$
$

351,000
225,000

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

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 5, 2018 performance share awards were granted to the Company’s executive officers under the 2014 Incentive Plan for the 2018-2020

performance measurement period. Under the 2018 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 ROE. 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 Edison Electric Institute 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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 awards until the shares, if any, are issued at the end of the performance measurement period. 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 party to an Executive Employment Agreement with the Company is to be made at target at the date of any such event.
The vesting of these awards is accelerated and paid at target on the event of a change in control. The terms of these awards are such that the entire
award will be classified and accounted for as equity, as required under ASC Topic 718, Compensation—Stock Compensation, 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.

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

2018-2020
2017-2019
2016-2018
2015-2017
2014-2016

Total

81,000
89,250
122,250
126,450
159,450

Target
Shares

54,000
59,500
81,500
84,300
106,300

2018

$ 1,121,000
729,000
772,000
23,000
—

$ 2,645,000

Expense Recognized in the
Year Ended December 31,

2017

2016

854,000
580,000
573,000
—

798,000
535,000
332,000

$ 2,007,000

$ 1,665,000

Earned
Shares

7,500
113,298
114,648
121,491

356,937

Stock-based payment expense recognized in 2018, 2017 and 2016 for the 2018-2020, 2017-2019 and 2016-2018 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 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 2016-2018 performance period also include shares received in 2019 by participants in the
plan based on the Company achieving a total shareholder return ranking of 1 out of 41 companies in the EEI Index and an average 3-year adjusted
return on equity in excess of the targeted average 3-year adjusted return on equity of 10.00% resulting in a payout at 145.17% of target.

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 in excess of the targeted average 3-year adjusted return on equity of 10.00% resulting in a 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.
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.

As of December 31, 2018, 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 $4.3 million (before income taxes), which will be amortized over a weighted average
period of 1.9 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, 2018, the
Company was in compliance with these financial 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
the Company by requiring an equity-to-total-capitalization ratio between
47.9% and 58.5% based on OTP’s 2018 capital structure petition effective
by order of the MPUC on October 18, 2018. As of December 31, 2018,
OTP’s equity-to-total-capitalization ratio including short-term debt
was 53.2% and its net assets restricted from distribution totaled
approximately $477 million. Total capitalization for OTP cannot
currently exceed $1.2 billion.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

8. Leases

The Company leases rail cars for transporting coal, warehouse and office
space, land and certain office, manufacturing and material handling
equipment, and currently has no assets held under capital leases.

OTP has obligations to make future operating lease payments primarily
related to coal rail-car leases. OTP’s rail car lease payments are charged
to fuel inventory and then expensed to production fuel—electric as a
component of fuel cost when fuel is burned. OTP also leases office and
operating equipment with lease payments charged to rent expense
and reported in electric operation and maintenance expenses on the
Company’s consolidated statements of income. From time to time,
OTP will lease construction equipment or land for lay-down yards for
materials used on capital projects. These leases are generally short
term in nature with the lease payments being charged to the related
construction project and included in construction work in progress or
plant in service after the project is completed and placed in service.

other leases with immaterial obligations in the aggregate relative to
the obligations associated with capitalized right-of-use operating assets
will also not be capitalized but will continue to be charged directly to
rent expense on a straight-line basis.

Leases in place at the time of adoption will be capitalized on the
basis of their remaining payment obligation balances, discounted to
present value based on an explicit or implicit borrowing rate or on the
Company’s incremental borrowing rate appropriate to the leased asset
and lease terms. The remaining payments for operating lease right-of
use assets will be charged to expense on a straight-line basis over the
life of the lease beginning in January 2019.

The Company estimates adoption of the standard will result in
recognition of net lease assets and lease liabilities of approximately
$20 million on January 1, 2019. The Company believes adoption of
the new standard will not have a material effect on its liquidity and
the standard is not expected to have an impact on the Company’s
debt-covenant compliance under its current debt agreements.

The Company’s nonelectric companies have obligations to make future

Because the leases to be capitalized as right of use assets under ASC

operating lease payments primarily related to leases of buildings and
manufacturing equipment. These payments are charged to rent expense
accounts and reported in costs of goods sold or other nonelectric
expenses, as appropriate, on the Company’s consolidated statements
of income. Lease payment expenses including payments for rail car
leases totaled $6,273,000, $6,237,000 and $6,711,000 in 2018, 2017
and 2016, respectively.

The amounts of the Company’s future operating leases obligations

of December 31, 2018 are as follows:

(in thousands)

2019
2020
2021
2022
2023
Beyond 2023

Total

OTP

1,099
1,077
1,047
214
196
448

4,081

Operating Leases
Nonelectric

5,086
4,800
3,971
3,740
3,385
6,295

Total

6,185
5,877
5,018
3,954
3,581
6,743

27,277

31,358

In February 2016, the FASB issued ASU No. 2016-02. The new standard
requires lessees to record assets and liabilities on the balance sheet for
all leases with terms longer than 12 months. Leases will be classified as
either finance or operating, with classification affecting the pattern of
expense recognition in the income statement.

The Company adopted the new standard on January 1, 2019 as
required under GAAP. The Company elected the package of practical
expedients permitted under the transition guidance within the new
standard, which among other things, allows for the carry forward of
historical lease classifications determined under the requirements of
ASC Topic 840. The Company has also elected the practical expedient
related to land easements, allowing for the continuation of historical
current accounting treatment for land easements on existing agreements.
In addition, the Company has elected the hindsight practical expedient
to determine the reasonably certain lease term for existing leases.
On implementation of the new lease accounting standard, ASC
Topic 842, Leases in January 2019, the majority of the Company’s
leased assets will be capitalized as right-of-use operating assets.
Certain leases that are short-term in nature—less than one year—will
not be capitalized, as a policy election, and the associated rent payments
will continue to be charged directly to rent expense. Payment for certain

Topic 842 are operating leases and were operating leases under ASC
Topic 840, the adoption of the new standard will have no material impact
on the Company’s consolidated statements of income or cash flows.

9. Commitments and Contingencies

Construction and Other Purchase Commitments
At December 31, 2018 OTP had commitments under contracts, including
its share of construction program commitments and other nonlease
commitments, extending into 2021 of approximately $64.5 million.
OTP’s other nonlease commitments charged to rent expense totaled
$252,000, $280,000 and $272,000 in 2018, 2017 and 2016, respectively.
At December 31, 2018 T.O. Plastics had commitments for the purchase
of resin through December 31, 2021 of approximately $5.0 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 also has
contracts providing for the purchase and delivery of a significant
portion of its current coal requirements. OTP’s current coal purchase
agreements for Coyote Station expire at the end of 2040. OTP’s current
coal purchase agreements for Big Stone Plant expire at the end of 2020.
OTP entered into a coal purchase agreement with Peabody COALSALES,
LLC effective May 14, 2018 for the purchase of subbituminous coal for
Big Stone Plant’s coal requirements through December 31, 2020. There
is no fixed minimum purchase requirement under this agreement but
all of Big Stone Plant’s coal requirements for the period covered must
be purchased under this agreement, except for the portion contracted
to be purchased in 2019 under an existing agreement with Contura
Coal Sales, LLC. OTP has an all-requirements agreement with Cloud
Peak Energy Resources LLC for the purchase of subbituminous coal for
Hoot Lake Plant through December 31, 2023. There are no fixed
minimum purchase requirements under this agreement.

OTP Land Easements
OTP has commitments to make future payments for land easements
not classified as leases. Land easement payments charged to rent
expense totaled $605,000, $593,000 and $582,000 in 2018, 2017
and 2016, respectively.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 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 purchase and coal delivery contracts and land easements as of
December 31, 2018, are as follows:

Construction
Program and Other

Coal
Capacity
Purchase
and Energy
Commitments Requirements Commitments

OTP Land
Easement
Payments

43,887
23,939
1,681
—
—
—

24,925
24,844
12,988
11,827
11,827
143,099

23,397
22,645
22,935
22,793
23,955
503,492

617
630
642
655
668
7,612

69,507

$ 229,510

$ 619,217

$ 10,824

(in thousands)

2019
2020
2021
2022
2023
Beyond 2023

Total

Contingencies
OTP had a $1.6 million refund liability on its balance sheet as of
December 31, 2018 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. As
discussed in Note 3 in greater detail, OTP believes its estimated accrued
refund liability is appropriate based on the current facts and
circumstances and is awaiting further action by the FERC before
determining if a change in this estimate will be needed.

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. In addition to the potential ROE refund
described above, the most significant contingencies impacting the
Company’s consolidated financial statements are those related to
environmental remediation, risks associated with warranty claims
relating to divested businesses that could exceed the established
reserve amounts and litigation matters. Should all of these known
items, excluding the ROE refund liability already recognized, result in
liabilities being incurred, the loss could be as high as $1.0 million.

In 2015 the Environmental Protection Agency (EPA), acting under
Section 111(d) of the Clean Air Act, issued the Clean Power Plan which
required states to submit plans to limit carbon dioxide emissions from
certain fossil fuel-fired power plants. The rule is not currently in effect
as a result of a stay by the Supreme Court in 2016. In 2017, the EPA
issued a Notice of Proposed Rulemaking to repeal the Clean Power
Plan; comments were due in April 2018.

On August 21, 2018 the EPA proposed a replacement for the Clean

Power Plan—the Affordable Clean Energy (ACE) Rule. Among other
things, the ACE Rule determines that the best system of emission
reduction for greenhouse gas emissions from coal-fired power plants
is to improve the plants’ heat rates, identifies a list of “candidate
technologies” for improving a plant’s heat rate and proposes that
physical or operational changes to a power plant would not be a
“major modification” triggering extensive New Source Review, if the
change does increase hourly emissions. If the ACE Rule goes into
effect, states will have three years after the final rule to submit a state
implementation plan.

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, 2018 will not be material.

10. 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, 2018 and December 31, 2017:

Restricted
due to

Line December 31,
2018
Limit

In Use on Outstanding Available on Available on
Letters December 31, December 31,
2017

of Credit

2018

$ 130,000

9,215

— $ 120,785

$ 130,000

(in thousands)

Otter Tail

Corporation
Credit
Agreement

OTP Credit

Agreement

170,000

9,384

Total

$ 300,000

$ 18,599

300

160,316

57,329

$ 281,101

$ 187,329

Under the Otter Tail Corporation Credit Agreement (as defined below),
the maximum amount of debt outstanding in 2018 was $17.7 million on
September 17, 2018 and the average daily balance of debt outstanding
during 2018 was $5.5 million. The weighted average interest rate paid
on debt outstanding under the OTC Credit Agreement during 2018 was
3.8% compared with 2.8% in 2017. Under the OTP Credit Agreement
(as defined below), the maximum amount of debt outstanding in 2018
was $122.0 million on January 16, 2018 and the average daily balance
of debt outstanding during 2018 was $21.6 million. The weighted average
interest rate paid on debt outstanding under the OTP Credit Agreement
during 2018 was 3.0% compared with 2.4% in 2017. The maximum
amount of consolidated short-term debt outstanding in 2018 was
$122.0 million on January 16, 2018 and the average daily balance of
consolidated short-term debt outstanding during 2018 was $27.1 million.
The weighted average interest rate on consolidated short-term debt
outstanding on December 31, 2018 was 3.9%.

On October 29, 2012 the Company entered into a Third Amended
and Restated Credit Agreement (the OTC 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 OTC Credit Agreement. On October 31, 2018 the OTC Credit Agreement
was amended to extend its expiration date by one year from October 31,
2022 to October 31, 2023. 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 OTC 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 OTC 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 OTC Credit Agreement also contains affirmative
covenants and events of default, and financial covenants as described
below under the heading “Financial Covenants.” The OTC 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
OTC Credit Agreement are guaranteed by certain of the Company’s
subsidiaries. Outstanding letters of credit issued by the Company
under the OTC Credit Agreement can reduce the amount available for
borrowing under the line by up to $40 million.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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, 2018 the OTP Credit Agreement
was amended to extend its expiration date by one year from October 31,
2022 to October 31, 2023. 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.

Both the Otter Tail Corporation Credit Agreement and the OTP Credit

Agreement currently expire on October 31, 2023. Borrowings under
these agreements currently use LIBOR as the base to determine the
applicable interest rate. LIBOR is currently expected to be eliminated
by January 1, 2022. Both credit agreements contain a provision to
determine how interest rates will be established in the event a
replacement for LIBOR has not been identified before the agreement
expires. The process calls for the parties to jointly agree on an alternate
rate of interest to LIBOR, such as the Secured Overnight Financing Rate,
that gives due consideration to prevailing market convention for
determining a rate of interest for syndicated loans in the United States
at such time. The parties will enter into amendments to these
agreements to reflect any alternate rate of interest and other related
changes to the agreements as may be applicable. If for any reason an
agreement cannot be reached on an alternate rate of interest, then
any borrowings under the agreements will be determined using the
Prime Rate plus a margin based on the Company’s and OTP’s Long-
Term Debt Ratings at the time of the borrowings. If the alternate rate
of interest agreed to by the parties is less than zero, such rate shall be
deemed to be zero for the purposes of the credit agreement.

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
outstanding borrowings under the OTP Credit Agreement.

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

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 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 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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 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.

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 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 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 3, 2018 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 3, 2021.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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, 2018.

December 31, 2018 (in thousands)

Short-Term Debt

Long-Term Debt:

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
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048
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, 2017 (in thousands)

Short-Term Debt

Long-Term Debt:

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)

OTP

9,384

$ 140,000
30,000
42,000
60,000
50,000
90,000
100,000

$ 512,000
—
1,942

$ 510,058

$ 519,442

OTP

$ 112,371

$ 140,000
30,000
42,000
60,000
50,000
90,000

$ 412,000
—
1,684

$ 410,316

$ 522,687

Otter Tail
Corporation

Otter Tail
Corporation
Consolidated

9,215

80,000

523

80,523
172
407

79,944

89,331

27
684

80,711
186
461

80,064

80,250

18,599

80,000
140,000
30,000
42,000
60,000
50,000
90,000
100,000
523

$ 592,523
172
2,349

$ 590,002

$ 608,773

Otter Tail
Corporation
Consolidated

$ 112,371

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

—

80,000

The aggregate amounts of maturities on bonds outstanding and
other long-term obligations at December 31, 2018 for each of the next
five years are:

(in thousands)

2019

2020

2021

2022

2023

Aggregate Amounts of

Debt Maturities

172 $

185 $140,166 $ 30,000 $

—

Financial Covenants
The Company and OTP were in compliance with the financial covenants
in these debt agreements as of December 31, 2018.

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.

(cid:1) Under the 2016 Note Purchase Agreement, the Company may not

permit our Priority Indebtedness to exceed 10% of its Total
Capitalization.

(cid:1) 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.

(cid:1) 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.

The Company’s and OTP’s borrowing agreements are subject to

(cid:1) Under the 2013 Note Purchase Agreement and the 2018 Note

certain financial covenants. Specifically:
(cid:1) 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

11. Pension Plan and Other Postretirement Benefits

The following table presents amounts recognized in the consolidated

balance sheets as of December 31:

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)

2018

2017

2016

$ 6,459
13,452
(21,199)

$ 5,629
14,139
(19,229)

$ 5,518
14,195
(19,454)

16
—

7,135
183

120
3

5,090
125

189
5

5,153
127

Net Periodic Pension Cost (2)

$ 6,046

$ 5,877

$ 5,733

(1) Corporate cost included in nonservice cost components of postretirement benefits.
2016
(2)Allocation of Costs:

2018

2017

1,542

$ 1,094

1,009

Service Costs included in OTP Capital

Expenditures

Service costs included in electric operation

and maintenance expenses
Service costs included in other

nonelectric expenses

Nonservice costs capitalized
Nonservice costs included in nonservice cost

components of postretirement benefits

(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

Funded status as of December 31:

2018

2017

5
104,891

$ 104,896

9
137

146

58,659

21
99,360

99,381

9
439

448

67,399

(in thousands)

Accumulated Benefit Obligation

Projected Benefit Obligation
Fair Value of Plan Assets

Funded Status

2018

2017

$ (297,972)

$ (316,095)

$ (328,442)
269,783

$ (352,718)
285,319

(58,659)

$ (67,399)

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, 2018:

(in thousands)

2018

2017

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

$ 285,319
(21,334)
20,000
(14,202)

$ 254,346
44,181
—
(13,208)

Fair Value of Plan Assets at December 31

$ 269,783

$ 285,319

Estimated Asset Return
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1
Service Cost
Interest Cost
Benefit Payments
Actuarial (Gain) Loss

(7.3%)

17.8%

$ 352,718
6,459
13,452
(14,202)
(29,985)

$ 314,637
5,629
14,139
(13,208)
31,521

4,756

4,400

4,377

Projected Benefit Obligation at December 31

$ 328,442

$ 352,718

161
(99)

(314)

135
48

200

132
39

176

Weighted average assumptions used to determine benefit obligations

at December 31:

Weighted average assumptions used to determine net periodic

pension cost for the year ended December 31:

Discount Rate
Long-Term Rate of Return on Plan Assets
Rate of Increase in Future
Compensation Level
Participants to Age 39
Participants Age 40 to Age 49
Participants Age 50 and Older

2018

3.90%
7.50%

2017

4.60%
7.50%

2016

4.76%
7.75%

3.00%

3.13%

See below
4.50%
3.50%
2.75%

Discount Rate
Rate of Increase in Future Compensation Level:

Participants to Age 39
Participants Age 40 to Age 49
Participants Age 50 and Older

2018

4.50%

4.50%
3.50%
2.75%

2017

3.90%

4.50%
3.50%
2.75%

The assumed rate of return on pension fund assets used for the
determination of 2019 net periodic pension cost is 7.25%. 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

The following objectives guide the investment strategy of the

Company’s pension plan (the Plan):
(cid:1) 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
• All transactions undertaken on behalf of the Plan must be in the

adhere to must be present in the investment program.

best interest of plan participants and their beneficiaries.
(cid:1) The primary objective of the Plan is to provide a source of
retirement income for its participants and beneficiaries.

(cid:1) The near-term primary financial objective of the Plan is to improve

the funded status of the Plan.

(cid:1) A secondary financial objective is to minimize pension funding and

expense volatility where possible.

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**

Permitted Range

< 85% PBO >=85% PBO >=90% PBO >=95% PBO >=100% PBO

39%-59% 34%-54% 24%-44% 14%-34%

0%-20%

22%-42% 30%-50% 40%-60% 53%-73% 70%-100%

0%-15% 0%-15%
5%-20% 5%-20%

0%-15% 0%-10%
5%-20% 0%-15%

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.

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.

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:

2018

2017

Net Periodic Pension Cost
End of Year Benefit Obligations

Market Value of Assets

January 1, 2018
January 1, 2018
projected to
December 31, 2018
December 31, 2018

January 1, 2017
January 1, 2017
projected to
December 31, 2017
December 31, 2017

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 2019 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

2019

5
4,642

9
114

4,770

Cash flows—The Company had no minimum funding requirement as
of December 31, 2018 but made discretionary plan contributions of
$10 million as of February 2019.

The following benefit payments, which reflect expected future
service, as appropriate, are expected to be paid out from plan assets:

(in thousands)

Years

2019

2020

2021

2022

2023

2024-2028

$15,086

$15,689

$16,356

$17,017

$17,709

$96,186

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

The Company’s pension plan asset allocations at December 31, 2018

and 2017, by asset category are as follows:

Asset Allocation

Large Capitalization Equity Securities
International Equity Securities
Small and Mid-Capitalization Equity Securities
SEI Dynamic Asset Allocation Fund
Emerging Markets Equity Fund

Equity Securities

Fixed-Income Securities and Cash
Other—SEI Energy Debt Collective Fund

2018

17.5%
17.0%
6.7%
4.0%
3.4%

48.6%
47.1%
4.3%

2017

23.5%
18.1%
8.7%
5.0%
5.5%

60.8%
35.2%
4.0%

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

cost for the year ended December 31:

100.0%

(in thousands)

Service Cost–

2018

2017

2016

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

Total Assets

2018

2017

$ 258,307
11,476

$ 273,999
11,320

$ 269,783

$ 285,319

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:

Benefit Earned During the Period

408

290

252

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)

1,589

1,686

1,667

20
34

206
722

16
38

285
440

16
38

293
446

Net Periodic Pension Cost (2)

$ 2,979

$ 2,755

$ 2,712

(1) Amortization of prior service costs and net actuarial losses from other

comprehensive income are included in nonservice cost components of postretirement
benefits on the face of the Company’s consolidated statements of income.

(2)Allocation of Costs:

2018

2017

2016

Service costs included in electric operation

and maintenance expenses
Service costs included in other

nonelectric expenses

Nonservice costs included in nonservice cost
components of postretirement benefits

309

196

165

2,571

2,465

2,460

(in thousands)

Large Capitalization Equity Securities Mutual Fund $
International Equity Securities Mutual Funds
Small and Mid-Capitalization Equity Securities

Mutual Fund

SEI Dynamic Asset Allocation Mutual Fund
Emerging Markets Equity Fund
Fixed Income Securities Mutual Funds
Cash Management—Money Market Fund

2018

47,198
45,912

2017

66,946
51,636

17,971
10,929
9,197
127,098
2

24,848
14,371
15,824
100,373
1

Total Assets

$ 258,307

$ 273,999

Weighted average assumptions used to determine net periodic

pension cost for the year ended December 31:

Discount Rate
Rate of Increase in Future
Compensation Level

2018

3.85%

2017

4.60%

2016

4.76%

2.92%

3.00%

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

Projected Benefit Obligation Liability—

Net Amount Recognized

Accumulated Other Comprehensive Loss:

Unrecognized Prior Service Cost
Unrecognized Actuarial Loss

Total Accumulated Other Comprehensive Loss

2018

2017

20
1,768

1,788

40
3,229

3,269

(39,699)

$ (42,308)

64
6,455

6,519

98
9,024

9,122

The investments held by the SEI Energy Debt Collective Fund on
December 31, 2018 and 2017 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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

Other Postretirement Benefits
The Company provides a portion of health insurance benefits for retired
OTP and corporate employees. The retiree health insurance benefits
will be available for all corporate employees and OTP nonunion
employees hired prior to September 1, 2006, and all union employees
of OTP hired prior to November 1, 2010, excluding Coyote Station
employees. Coyote Station employees hired before January 1, 2009
are covered under the plan. To be eligible for retiree health insurance
benefits the employee must be 55 years of age with a minimum of
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)

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)

2018

2017

2016

$ 1,526
2,583

$ 1,425
2,712

$ 1,301
2,503

—
—

1,648
42

(4)
4

936
19

134
3

379
9

Net Periodic Postretirement Benefit Cost (2) $ 5,799

$ 5,092

$ 4,329

Effect of Medicare Part D Subsidy

$ (470)

(561) $

(923)

(1) Corporate cost included in nonservice cost components of postretirement benefits.
2016
(2)Allocation of Cost:

2018

2017

Service Costs included in OTP capital expenditures $
Service costs included in electric operation

364

277

238

and maintenance expenses

1,124

1,114

1,032

Service costs included in other nonelectric

expenses

Nonservice costs capitalized
Nonservice costs included in nonservice cost
components of postretirement benefits

38
1,020

34
712

31
554

3,253

2,955

2,474

Weighted average assumptions used to determine net periodic

postretirement benefit cost for the year ended December 31:

Discount Rate

2018

3.81%

2017

4.46%

2016

4.57%

The following table presents amounts recognized in the consolidated

balance sheets as of December 31:

(in thousands)

2018

2017

Projected Benefit Obligation Liability—

Net Amount Recognized

Unrecognized Net Actuarial Loss (Gain):

Regulatory Asset
Accumulated Other Comprehensive Income:

Unrecognized Net Actuarial Loss

(71,561)

$ (69,774)

18,094
(107)

17,987

18,927
(111)

18,816

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, 2018 and a statement
of the funded status as of December 31 of both years:

(in thousands)

2018

2017

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 (Gain) Loss

—
—
1,505
(1,505)

—

42,308
408
1,589
(1,505)
—
(3,101)

—
—
1,175
(1,175)

—

37,335
290
1,686
(1,175)
—
4,172

Projected Benefit Obligation at December 31

39,699

42,308

Weighted average assumptions used to determine benefit obligations

at December 31:

Discount Rate
Rate of Increase in Future Compensation Level:

2018

4.46%
3.40%

2017

3.85%
2.92%

(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

2019

5
124

17
348

494

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

2019

$1,468

2020

$1,527

2021

$1,618

2022

$2,214

2023

2024-2028

$2,635

$14,215

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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, 2018:

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 2019 are:

2018

2017

Decrease in Regulatory Assets:

(in thousands)

Amortization of Unrecognized Actuarial Loss

Decrease in Accumulated Other Comprehensive Loss:

Amortization of Unrecognized Actuarial Loss

Total Estimated Amortization

2019

1,570

1,609

(in thousands)

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

—
—
3,183
(6,684)
3,501

—

69,774
1,526
2,583
(6,684)
3,501
861

—
—
3,290
(6,534)
3,244

—

62,571
1,425
2,712
(6,534)
3,244
6,356

71,561

69,774

(50,958)
(5,799)
3,183

$ (49,156)
(5,092)
3,290

Accrued Postretirement Cost at December 31

(53,574)

$ (50,958)

Weighted average assumptions used to determine benefit obligations

at December 31:

Discount Rate

2018

4.44%

2017

3.81%

Assumed healthcare cost-trend rates as of December 31:

(in thousands)

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

2018

2017

7.00% 5.85%
7.00% 6.03%
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 2018 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

$
$
$

9,095
758
1,953

1 Point
Decrease

$ (7,586)
$
(600)
$ (1,589)

Measurement Dates:

2018

2017

Net Periodic Postretirement Benefit Cost January 1, 2018
January 1, 2018
End of Year Benefit Obligations
projected to

January 1, 2017
January 1, 2017
projected to

December 31, 2018 December 31, 2017

Cash flows—The Company expects to contribute $4.2 million net of
expected employee contributions for the payment of retiree medical
benefits and Medicare Part D subsidy receipts in 2019. The Company
expects to receive a Medicare Part D subsidy from the Federal
government of approximately $0.4 million in 2019. 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

2019
$4,247

2020
$4,322

2021
$4,483

2022
$4,698

2023
$4,781

2024-2028
$24,183

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 totaled $4,532,000 for
2018, $4,211,000 for 2017 and $3,877,000 for 2016.

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
$398,000 for 2018, $612,000 for 2017 and $647,000 for 2016.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

12. 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 2 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, 2018 and December 31, 2017 related to
the Otter Tail Corporation Credit Agreement and the OTP Credit
Agreement were subject to variable interest rates of LIBOR plus 1.50%
and LIBOR plus 1.25%, respectively, which approximate market rates.

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 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.

Electric Fixed Assets:
Production Plant
Transmission Plant
Distribution Plant
General Plant

Nonelectric Fixed Assets:

Equipment
Buildings and Leasehold Improvements

14. Income Taxes

9
42
5
5

2
5

82
70
68
50

12
40

The total income tax expense differs from the amount computed by
applying the federal income tax rate (21% in 2018, and 35% in 2017 and
2016) to net income before total income tax expense for the following
reasons:

(in thousands)

December 31, 2018

December 31, 2017

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

Tax Computed at Federal Statutory Rate
Increases (Decreases) in Tax from:

State Income Taxes Net of Federal Income

(in thousands)

2018

2017

2016

$ 20,356

$ 34,893

$ 28,889

Cash and Cash Equivalents $
Short-Term Debt
Long-Term Debt including

861
(18,599)

$ 16,216
(112,371)

Current Maturities

(590,174)

(601,513)

(490,566)

(543,691)

13. Property, Plant and Equipment

Tax Expense

Differences Reversing in Excess of Federal Rates
Federal Production Tax Credits (PTCs)
Permanent Differences, R&D Tax Credits,

5,210
(3,432)
(3,111)

4,368
551
(7,527)

2,869
77
(7,175)

Unitary Tax and Other Adjustments

(1,864)

(1,873)

(1,262)

North Dakota Wind Tax Credit Amortization—

Net of Federal Taxes

Excess Tax deduction—Equity Method

(1,033)

(850)

Stock Awards

(708)

(751)

—

December 31, 2018 December 31, 2017

Allowance for Funds Used During

(in thousands)

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

905,224
512,832
502,261
99,404

2,019,721
170,090

2,189,811

699,642

1,490,169

170,634
53,011
4,475

228,120
11,536

239,656

148,727

90,929

1,581,098

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

Construction—Equity

Employee Stock Ownership Plan

Dividend Deduction

Investment Tax Credit Amortization
Corporate-owned Life Insurance
Section 199 Domestic Production

Activities Deduction

Effect of TCJA Tax Rate Reduction on
Value of Net Deferred Tax Assets

(431)

(322)

(280)

(298)
(98)
(3)

(509)
(164)
(845)

(537)
(350)
(680)

—

(1,471)

(482)

1,756

—

Income Tax Expense

$ 14,588

$ 27,256

$ 20,219

Overall Effective Federal, State and

Foreign Income Tax Rate

Income Tax Expense 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 Amortization—

Net of Federal Taxes

15.0%

27.3%

24.5%

$ 4,960
1,395
8,065
4,410
(3,111)

$ 4,434
1,128
25,648
4,587
(7,527)

989
1,208
23,774
2,623
(7,175)

(1,033)
(98)

(850)
(164)

(850)
(350)

$ 14,588

$ 27,256

$ 20,219

136,988

Investment Tax Credit Amortization

88,460

$ 1,539,603

Total

Total Income Before Income Taxes

$ 96,933

$ 99,695

$ 82,540

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 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
Benefit Liabilities
Regulatory Tax Liability
Retirement Benefits Liabilities
North Dakota Wind Tax Credits
Federal PTCs
Cost of Removal
Differences Related to Property
Net Operating Loss Carryforward
Vacation Accrual
Investment Tax Credits
Other
Valuation Allowance

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

2018

2017

33,967
33,228
32,664
32,570
32,101
21,787
6,842
2,489
1,919
449
3,218
(600)

32,328
39,465
31,894
32,962
40,614
21,800
6,499
3,203
1,844
515
668
—

$ 200,634

$ 211,792

$ (261,396)
(32,664)
(15,145)
(4,386)

$ (257,906)
(31,894)
(14,077)
(4,112)

(523)
(7,496)

(673)
(3,631)

$ (321,610)

$ (312,293)

$ (120,976)

$ (100,501)

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 decreased 53.0% in
2018 compared with 2017 due to the PTC eligibility period ending for
one of OTP’s wind farms. 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, 2018:

(in thousands)

United States

Amount

2022-2032 2033-2038 2039-2043

Federal Tax Credits
State Net Operating Losses
State Tax Credits

$ 34,586
2,489
33,106

—
2,396
273

$ 34,586
93
3,326

—
—
29,507

The balance of unrecognized tax benefits as of December 31, 2018
would reduce the Company’s effective tax rate if recognized. The total
amount of unrecognized tax benefits as of December 31, 2018 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, 2018.

The Company and its subsidiaries file a consolidated U.S. federal

income tax return and various state income tax returns. As of
December 31, 2018, with limited exceptions, the Company is no longer
subject to examinations by taxing authorities for tax years prior to
2015 for federal and North Dakota income taxes and prior to 2014 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% in 2017. 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

The following table summarizes the activity related to the Company’s

The Company recognized the income tax effects of the TCJA in its

unrecognized tax benefits:

(in thousands)

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

2018

2017

2016

$ 684

891

468

—

778
(186)

406

(172)

143
(206)

—

114
(97)

Balance on December 31

$ 1,282

684

891

2017 consolidated financial statements in accordance with Staff
Accounting Bulletin No. 118, which provided SEC staff guidance for the
application of ASC Topic 740, Income Taxes, and allowed up to one
year to complete the required analyses and accounting for the TCJA.
At December 31, 2017 the Company was 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 accounting for the income
tax effects of the enactment of the TCJA was complete as of
September 30, 2018. The Company did not make any material
adjustments in 2018 to the amounts recorded at December 31, 2017.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

15. Asset Retirement Obligations (AROs)

16. Subsequent Events

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 2018.
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, 2018 and 2017 are presented in the
following table:

2018

2017

$ 8,341
—
—
378
—

$ 8,719

$ 2,983
—
—
—

$ 2,983

795
—
—
120
—

915

None
—
—
—
—

—

(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

$ 8,719
—
—
398
—

$ 9,117

$ 2,983
—
—
—

$ 2,983

Beginning Balance
New Obligations Recognized
Adjustments Due to Revisions in Cash Flow Estimates
Depreciation Expense
Settlements

915
—
—
119
—

Ending Balance

Settlements

Original Capitalized Asset Retirement Cost—Retired
Accumulated Depreciation
Asset Retirement Obligation
Settlement Cost

Gain on Settlement—

Deferred Under Regulatory Accounting

$ 1,034

None
—
—
—
—

—

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

Stock Incentive Awards
On February 13, 2019 the following stock incentive awards were
granted to officers under the 2014 Incentive Plan:

Weighted Average
Grant-Date
Fair Value
per Award

Shares/Units
Granted

Vesting

15,600

$ 49.6225 25% per year through
February 6, 2023

Award

Restricted Stock
Units Granted

Stock Performance
Awards Granted:

Under Executive Agreement 47,800
7,800
Under Legacy Agreement

$
$

42.875
45.885

December 31, 2021
December 31, 2021

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 55,600 shares. For target performance the
participants would earn an aggregate of 27,800 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
27,800 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, 2019 through December 31, 2021, 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, 2019 and the average closing price for the 20
trading days immediately preceding January 1, 2022. Actual payment
may range from zero to 150% of the target amount, or up to 83,400
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 2019 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 party to an Executive Employment
Agreement with the Company is to be made at target at the date of
any such event. The vesting of these awards is accelerated and paid at
target in the event of a change in control.

The end of the period over which compensation expense is recognized

for the above share-based awards for the individual grantees is the
earlier 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

March 31

June 30

September 30

December 31

(in thousands, except per share data)

2018

2017

2018

2017

2018

2017

2018

2017

Operating Revenues:

Electric:

Revenues from contracts with Customers
Changes in Accrued Revenues under Alternative

Revenue Programs

$ 123,825

$ 119,782

$ 105,284

$ 102,655

$ 105,749

$ 102,923

$ 115,779

$ 111,117

(875)

(1,239)

(1,565)

(424)

(317)

471

2,318

(779)

Total Electric Revenues
Product Sales under Contracts with Customers

$ 122,950
118,316

$ 118,543
95,574

$ 103,719
122,629

$ 102,231
109,855

$ 105,432
122,230

$ 103,394
113,063

$ 118,097
103,074

$ 110,338
96,352

Total Operating Revenues
Operating Income (1)
Net Income
Basic Earnings Per Share
Diluted Earnings Per Share
Dividends Declared Per Common Share
Average Number of Common Shares Outstanding—Basic
Average Number of Common Shares Outstanding—Diluted

$ 206,690
$ 216,457
$ 212,086
$ 214,117
$ 221,171
$ 227,662
$ 226,348
$ 241,266
$ 33,942
$ 32,948
$ 31,097
$ 34,300
$ 23,407
$ 38,262
$ 30,105
$ 37,615
$ 18,342
$ 17,734
$ 16,778
$ 19,585
$ 14,161
$ 23,273
$ 18,696
$ 26,215
.46
$
.45
$
.43
$
.50
$
.36
$
.59
$
.47
$
.66
$
.46
.45
.42
.49
$
$
$
$
.35
.58
.47
.66
$
$
$
$
.320
.335 $
.320 $
.335 $
.320 $
.335 $
.320 $
.335 $
$

39,551
39,864

39,351
39,641

39,606
39,879

39,463
39,702

39,622
39,904

39,508
39,795

39,622
39,922

39,508
39,855

(1) With the adoption, in 2018, of accounting standard updates included in ASU 2017-07, the Company began charging nonservice cost components of postretirement benefits
previously charged to operating expense to a separate expense line outside of and below operating income, resulting in decreased operating expenses and increased
operating income. Accordingly, operating income for the 2017 quarters have been restated to reflect the reclassification of the nonservice cost components of postretirement
benefits for those periods.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 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 2019
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 Certain Beneficial Owners—
Section 16(a) Beneficial Ownership Reporting Compliance” in the
Company’s definitive Proxy Statement for the 2019 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 “Corporate
Governance—Director Nomination Process” in the Company’s definitive
Proxy Statement for the 2019 Annual Meeting. The information
required by this Item regarding the Audit Committee and the Company’s
Audit Committee financial experts is incorporated by reference to
the information under “Committees of the Board of Directors—Audit
Committee” in the Company’s definitive Proxy Statement for the
2019 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,”
“Pay Ratio Disclosure” and “Director Compensation” in the Company’s
definitive Proxy Statement for the 2019 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, 2018, 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, 2018.

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, 2018 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, 2018. 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, 2018,
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 49.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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” in the Company’s definitive Proxy Statement for the 2019 Annual Meeting.

EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information as of December 31, 2018 about the Company’s common stock that may be issued under all 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

356,585 (1)
1,747 (3)
—

—

358,332

$
$

0.00
0.00
N/A

—

0.00

1,121,330 (2)
— (4)
366,867 (5)

—

1,488,197

(1) Includes 81,000, 78,000 and 102,198 performance-based share awards granted in 2018, 2017 and 2016, respectively, 94,770 restricted stock units outstanding as of

December 31, 2018, and 617 stock units as part of the director deferred compensation program and excludes 43,225 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 “Committees of the
Board of Directors” in the Company’s definitive Proxy Statement for
the 2019 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 2019
Annual Meeting.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
Consolidated Balance Sheets, December 31, 2018 and 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
Consolidated Statements of Income for the Three Years Ended December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
Consolidated Statements of Comprehensive Income for the Three Years Ended December 31, 2018. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
Consolidated Statements of Common Shareholders’ Equity for the Three Years Ended December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
Consolidated Statements of Capitalization, December 31, 2018 and 2017. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
Notes to Consolidated Financial Statements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

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
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 8 A N N UA L R E P O RT

2018

2017

—
—
1,931
117
1,167
3,482

6,697

787,869
79,422
21,100
31,547

16,371
—
2,098
117
1,752
1,130

21,468

724,613
79,611
27,923
31,559

$ 926,635

$ 885,174

9,215
172
7
60,626
9,994

80,014

37,814

79,944
728,863

808,807

—
186
6
61,908
7,799

69,899

38,319

80,064
696,892

776,956

$ 926,635

$ 885,174

OTTER TAIL CORPORATION (PARENT COMPANY)
Condensed Statements of Income—For the Years Ended December 31

(in thousands)

Operating Loss

Revenue from Contracts with Customers
Operating Expenses

Operating Loss

Other Income (Expense)

Equity Income in Earnings of Subsidiaries
Interest Charges
Interest Charges to Subsidiaries
Interest Income from Subsidiaries
Nonservice Cost Components of Postretirement Benefits
Other Income

Total Other Income

Income Before Income Taxes
Income Tax (Benefit) Expense

Net Income

2018

2017

2016

—
9,916

(9,916)

91,446
(4,043)
(387)
2,839
(1,422)
550

88,983

79,067
(3,278)

82,345

—
7,138

(7,138)

82,715
(4,270)
(244)
2,848
(1,215)
1,054

80,888

73,750
1,311

72,439

—
8,530

(8,530)

67,047
(6,817)
(173)
4,897
(1,159)
1,621

65,416

56,886
(5,435)

62,321

See accompanying notes to condensed financial statements.

OTTER TAIL CORPORATION (PARENT COMPANY)
Condensed Statements of Cash Flows—For the Years Ended December 31

(in thousands)

2018

2017

2016

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 (Used in) Provided by Investing Activities

Cash Flows from Financing Activities

Change in Checks Written in Excess of Cash
Net Short-Term Borrowings (Repayments)
(Repayments to) Borrowings from 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 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.

56,947

50,205

83,296

(24,764)
774
(623)

(24,613)

31
9,215
(1,281)
—
(108)
(3,011)
—
(164)
(189)
(53,198)

(48,705)

(16,371)
16,371

—

—
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

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 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, 2018, 2017 and 2016

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, 2018:

(in thousands)

Otter Tail Power Company
Vinyltech Corporation
Northern Pipe Products, Inc.
BTD Manufacturing, Inc.
T.O. Plastics, Inc.
Varistar Corporation
Otter Tail Assurance Limited

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

Accounts
Receivable

Interest
Receivable

Current
Notes
Receivable

Long-Term
Notes
Receivable

Accounts
Payable

1,877
4
—
—
—
—
50

—
17
8
77
15
—
—

—
—
—
415
—
752
—

—
11,500
5,522
52,000
10,400
—
—

1,931

117

1,167

$ 79,422

7
—
—
—
—
—
—

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
—
—
—
—
—
—
—
—

Current
Notes
Payable

—
15,305
5,623
—
14,308
25,390
—

$ 60,626

Current
Notes
Payable

—
20,603
8,186
7,260
—
—
13,446
12,413
—

$ 61,908

Dividends
Dividends paid to Otter Tail Corporation (the Parent) from its subsidiaries were as follows:

(in thousands)

Cash Dividends Paid to Parent by Subsidiaries

2018

2017

2016

53,134

50,571

77,779

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 8 A N N UA L R E P O RT

3. Exhibits

The following Exhibits are filed as part of, or incorporated by reference into, this report.

Previously Filed

File No.

As Exhibit No.

2-A

8-K filed 7/1/09

2.1

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.

2-B

2-C

3-A

3-B

4-A

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

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, between Otter Tail Power Company and the
Purchasers named therein.

4-A-1

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,
between Otter Tail Power Company and the Purchasers named therein.

4-A-2

8-K filed 9/15/08

4.1

Second Amendment, dated as of September 11, 2008, to Note Purchase Agreement, dated as of August 20, 2007,
between Otter Tail Power Company and the Purchasers named therein.

4-A-3

8-K filed 7/1/09

4.2

Third Amendment, dated as of June 26, 2009, to Note Purchase Agreement dated as of August 20, 2007,
between Otter Tail Power Company and the Purchasers named therein.

4-B

8-K filed 11/2/12

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-B-6

8-K filed 11/6/18

4.1

4-C

8-K filed 11/2/12

4.2

4-C-1

8-K filed 11/1/13

4.2

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.

Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2018, 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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

Previously Filed

File No.

As Exhibit No.

4-C-2

8-K filed 11/4/14

4.2

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

4-C-6

8-K filed 11/6/18

4.2

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.

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.

Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2018, 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

4-F

8-K filed 9/27/16

4.1

Note Purchase Agreement dated as of August 14, 2013 between Otter Tail Power Company and the
Purchasers named therein.

Note Purchase Agreement dated as of September 23, 2016 between Otter Tail Corporation and the
Purchasers named therein.

4-G

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

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).

10-C-1

10-K for year
ended 12/31/89

10-H-1

Supplemental Agreement No. One, dated as of November 30, 1978, 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 8 A N N UA L R E P O RT

Previously Filed

File No.

As Exhibit No.

10-C-2

10-C-3

10-C-4

10-C-5

10-C-6

10-D

10-K for year
ended 12/31/89

10-K for year
ended 12/31/92

10-Q for quarter
ended 9/30/01

10-Q for quarter
ended 9/30/03

10-K for year
ended 12/31/12

10-H-2

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.

10-H-3

Amendment, dated as of July 29, 1983, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.

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-A

Amendment, dated as of June 14, 2001, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.

10.2

Amendment, dated as of April 24, 2003, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.

10-J

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.**

10-D-1

8-K filed 1/31/14

10.1

10-D-2

8-K filed 3/18/15

10.1

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 10.1
ended 6/30/13

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-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

10.1

Nonqualified Retirement Plan (2011 Restatement).*

10.1

1999 Employee Stock Purchase Plan, As Amended (2016).

10-F-5

8-K filed 4/13/06

10.4

1999 Stock Incentive Plan, As Amended (2006).*

10-F-6

10-K for year
ended 12/31/13

10-O-12 2014 Executive Annual Incentive Plan.*

10-F-7

333-195337

4.1

Otter Tail Corporation 2014 Stock Incentive Plan.*

10-F-8

10-K for year
ended 12/31/16

10-F-9

8-K filed 2/11/15

10-F-10 8-K filed 2/11/15

10-F-11

8-K filed 2/11/15

10-F-12 8-K filed 2/11/15

10-F-13 8-K filed 4/15/15

10-F-14 8-K filed 2/11/15

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.*

10-F-14a 10-K for year

10-F-18a First Amendment of Otter Tail Corporation Executive Restoration Plus Plan.*

10-F-15

ended 12/31/17

10-K for year
ended 12/31/17

10-F-19 Summary of Non-Employee Director Compensation (2018).*

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

10-F-16

10-F-17

10-F-18

10-F-19

10-G

10-H-1

10-H-2

10-H-3

10-H-4

10-H-5

10-H-6

10-I

21-A

23-A

24-A

31.1

31.2

32.1

32.2

101

Previously Filed

File No.

As Exhibit No.

10-Q for quarter
ended 03/31/18

10-K for year
ended 12/31/12

10-K for year
ended 12/31/10

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-K for year
ended 12/31/17

10.1

Form of 2018 Performance Award Agreement (Executives).*

10.2

Form of 2018 Performance Award Agreement (Legacy).*

Form of 2018 Restricted Stock Award Agreement for Directors.*

Summary of Non-Employee Director Compensation (2019).*

10-O-1

Executive Employment Agreement, Kevin Moug.*

10-Q-3

Change in Control Severance Agreement, Kevin G. Moug.*

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.*

10-I-7

Change in Control Severance Agreement, Jennifer Smestad.*

10-J

Otter Tail Corporation Executive Severance Plan.*

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, 2018, 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 1.

*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.

100

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

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 22, 2019

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

James B. Stake, Director

Thomas J. Webb, Director

/s/ Charles S. MacFarlane
Charles S. MacFarlane
Pro Se and Attorney-in-Fact

Dated February 22, 2019

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

101

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.

2019 Annual Meeting of Shareholders

Monday, April 8, 2019 • 10:30 a.m., Central Daylight Time
Bigwood Event Center
Country Inn & Suites, by Radisson
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. 2018
dividends were $1.34 per share, and the year-end yield was
2.7 percent. Total shareholder return grew at a compounded
average annual rate of 12.7 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
82 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.

102

OT T E R TA I L CO R P O R AT I O N 2 0 1 8 A N N UA L R E P O RT

2019 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 9
June 10
September 10
December 10

Nasdaq . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . OTTR
Year-end stock price. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $49.64
Year-end market-to-book ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.7
Annual dividend yield. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.7%
Shares outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39.7 million
Market capitalization (as of December 31, 2018) . . . . . $1.97 billion
2018 average daily trading volume . . . . . . . . . . . . . . . . . . . . . 82,544
Institutional holdings

(shares as of December 31, 2018). . . . . . . . . . . . . . . . . 20.8 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

Baa2
N.A.
Stable

A3
N.A.
Stable

BBB-
BBB-
Stable

BBB
N.A.
Positive

BBB
BBB+
Stable

BBB
BBB
Positive

Transfer Agent

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

Back: Chuck MacFarlane, John Abbott, Tim Rogelstad, Paul Knutson, and Stephanie Hoff | Front: Jennifer Smestad and Kevin Moug

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

NATHAN I. PARTAIN
Chairman of the Board
of Directors
Chicago, Illinois
President and
Chief Investment Officer,
Duff & Phelps Investment
Management Co.; President
and Chief Executive Officer,
DNP Select Income Fund, Inc.
(closed-end utility fund)

KAREN M. BOHN
A/CG—Edina, Minnesota
President, Galeo Group, LLC
(management consulting firm)

JOHN D. ERICKSON
Fergus Falls, Minnesota
Former President and
Chief Executive Officer,
Otter Tail Corporation (utility
and diversified businesses)

STEVEN L. FRITZE
A/CG—Eagan, Minnesota
Retired Chief Financial
Officer, Ecolab Inc.
(diversified manufacturing)

KATHRYN O. JOHNSON
C/CG—Hill City, South Dakota
Owner/Principal, Johnson
Environmental Concepts
(geochemical consulting firm)

CHARLES S. MACFARLANE
Fergus Falls, Minnesota
President and Chief
Executive Officer,
Otter Tail Corporation

EXECUTIVE
LEADERSHIP

TIMOTHY J. O’KEEFE
C/CG—Grand Forks, North Dakota
Retired Executive Vice President,
University of North Dakota
Alumni Association;
Retired Chief Executive Officer,
University of North Dakota
Foundation (nonprofit)

JAMES B. STAKE
A/C—Edina, Minnesota
Retired Executive Vice President,
Enterprise Services, 3M Company
(diversified manufacturing)

THOMAS J. WEBB
A/C—Richland, Michigan
Retired Executive Vice President,
Chief Financial Officer, and
Vice Chairman, CMS Energy
Corporation (gas and
electric utility)

DIRECTORS

NATHAN PARTAIN

KAREN BOHN

CHARLES S. MACFARLANE
President and
Chief Executive Officer

KEVIN G. MOUG
Chief Financial Officer and
Senior Vice President

TIMOTHY J. ROGELSTAD
Senior Vice President,
Electric Platform;
President, Otter Tail
Power Company

JOHN S. ABBOTT
Senior Vice President,
Manufacturing Platform;
President, Varistar

PAUL L. KNUTSON
Vice President,
Human Resources

JENNIFER O. SMESTAD
Vice President,
General Counsel,
and Corporate Secretary

STEPHANIE A. HOFF
Director,
Corporate Communications

JOHN ERICKSON

STEVEN FRITZE

KATHRYN JOHNSON

CHARLES MACFARLANE

TIMOTHY O’KEEFE

JAMES STAKE

THOMAS WEBB

ABOUT THE COVER

Otter Tail Corporation Risk
Manager Pat Murray (left)
and BTD Safety Coordinator
Nicholas Umland, along with
BTD Manufacturing Engineer
Cassidy Meerman (cover),
help create an environment for
growth and success. In 2018 BTD

experienced a record year in sales.

plan

build

Otter Tail Power Company Supply
Engineering Manager Kirk Phinney
(left) and Supply Engineering/
Operations Manager William
Swanson, together with Wind Farm
Supervisor Craig Burchill (cover),
help implement the utility’s
resource plan, which calls for
capital investments in the Astoria
Station natural gas-fired plant in
South Dakota and the Merricourt
wind farm in North Dakota.

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