Otter Tail Annual Report 2019

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FY2019 Annual Report · Otter Tail

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[
2019 A N N U A L R E P O R T

[

VISION

[

We will build a strong and focused diversified organization with an electric utility as our foundation.

GROW
OUR BUSINESSES

Otter Tail Power Company
Surveyor Jason Lee works on
transmission infrastructure
enhancements to improve
reliability and customer
satisfaction. In 2019 we
invested approximately
$36 million in transmission
system upgrades.

ACHIEVE OPERATIONAL
AND COMMERCIAL EXCELLENCE

BTD Shift Lead Matthew Chester maintains
operational excellence by ensuring customers
receive high-quality products with on-time
delivery. Through strategic execution, the
BTD Georgia facility was profitable in 2019
with both sales growth and significant
productivity improvements.

[

MISSION

VALUES

[

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.

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.

DEVELOP
OUR TALENT

Corporate Communications Director
Stephanie Hoff (left) and Otter Tail Power
Company Vice President of Energy Supply
Brad Tollerson engage employees in
Leading Others, a leadership development
program established to equip employees
across the enterprise with necessary tools,
resources, and opportunities to increase
knowledge, skills, and capabilities.

LETTER TO SHAREHOLDERS 2

ORGANIZATION CHART 4

FINANCIAL INFORMATION 5

10-K FINANCIAL REPORT 7

DIRECTORS AND LEADERSHIP 107

CONSOLIDATED OPERATIONS

($ in thousands, except share amounts)

2019

2018

PERCENT
CHANGE

$
$
$
$

919,503
86,847
2.17
1.40
11.6%

$
$
$
$

19.46
$
$
185,037
40,157,591
12,361
51.29

6.1%

$ 2,059,683
2,208

916,447
82,345
2.06
1.34
11.5%

0.3
5.5
5.3
4.5
0.9
5.9
29.0
1.2
(2.4)
3.3
14.7% (58.5)
4.6
(4.9)

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

$ 1,968,965
2,321

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

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

$
459,048
4,969,089
98,417
$
132,578
$ 2,390,468
$ 1,931,525
187,362
$
654

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

2.0
(0.2)
11.8
0.1
9.2
11.7
114.7
(2.2)

$
$
$
$

460,455
46,308
287,791
19,720
1,514

$
$
$
$

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

(1.2)
(9.5)
3.1
12.6
(6.3)

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

TO OUR
SHAREHOLDERS

CHARLES S. MACFARLANE
PRESIDENT AND CEO

[

A C H I E V E . A C C E L E R A T E .

[

Our 2019 financial results—which are driven by our strategic

initiatives to grow our businesses, achieve operational and

commercial excellence, and develop our talent—demonstrate

Otter Tail Corporation delivers value to shareholders as we

how our accomplishments continue to deliver value to

grow our electric and manufacturing platforms and develop

shareholders and position us to establish long-term success.

our systems, locations, and people. We will accomplish this

while achieving operational and commercial excellence.

Our electric platform continues to grow through capital

investments in generation and transmission. Our

[

U T I L I T Y A C H I E V E S M I L E S T O N E S

[

manufacturing platform remains focused on the growth

Otter Tail Power Company grew rate base by 6.1 percent

required to meet customer needs and operate efficient

in 2019, primarily through capital investment in generation

businesses. This year’s report highlights our 2019

and regional transmission projects.

achievements and our plans to accelerate toward reaching

The utility celebrated its 110th anniversary and marked

our strategic goals.

major milestones in the future of our generation resources

Through our combined efforts, we achieved consolidated

with two projects that began construction in 2019. The

net income and diluted earnings per share of $86.8 million

Merricourt Wind Energy Center is a 150-megawatt (MW)

and $2.17, respectively, compared with $82.3 million and

wind generation facility in southeast North Dakota. Astoria

$2.06 in 2018; earnings per share increased 5.3 percent year

Station is a 245-MW simple-cycle natural gas combustion

over year. Return on equity was 11.6 percent.
The dividend yield at year-end was 2.7 percent. Total

turbine in east central South Dakota. Both will prepare us

for our Hoot Lake coal-fired power plant’s 2021 retirement.

shareholder return has grown at a compounded annual

And both will provide immediate returns for amounts

rate of 14.4 percent over the past five years. We have paid

invested while under construction.

dividends on common stock for 81 years, or 325 consecutive

Merricourt Wind Energy Center construction began in

quarters. Our annual indicated dividend per share for 2020

August. The facility, which we expect to begin commercial

is $1.48, a 5.7 percent increase over our 2019 dividend rate.

operation in the fourth quarter of 2020, will generate

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

enough energy to power more than 65,000 homes. At an

15 years. Delaying our filing another year will allow us to

estimated cost of approximately $258 million, this is the

better incorporate outcomes of the Regional Haze Rule

largest capital project in company history.

into our modeling.

In May 2019 we began constructing Astoria Station. It will

Otter Tail Power Company’s new sustainability website

complement our wind generation by providing a reliable

went live. Transparency is important to our company and to

backstop when the wind is not blowing, and it will have

our industry. The new website aids in that transparency and

flexible operating options and low emissions. We expect to

highlights the responsible ways we meet diverse needs.

invest approximately $158 million in Astoria Station and for

We have established a ten-year plan for strategic upgrades

the facility to be on line in late 2020 or early 2021.

to technologies that support enhanced energy transmission

By 2022 we project more than 30 percent of our energy

and delivery and an improved customer experience.

will come from renewables, and carbon dioxide emissions

The utility achieved strong safety performance, reporting

from generation resources we own will be more than

its lowest OSHA recordable case rate on record. Thanks

30 percent lower than 2005 levels—all while keeping

to dedicated employees and leadership, Otter Tail Power

residential rates nearly 30 percent below the national

Company continues to reach important milestones while

average. Merricourt Wind Energy Center and Astoria Station

safely and effectively providing customers with an essential

are catalysts of these 30 percent trajectories.

service and maintaining affordable rates. Over the past

Otter Tail Power Company completed a few small-scale

decade, Otter Tail Power Company has grown by investing

solar projects in partnership with communities we serve.

in infrastructure while maintaining residential rates nearly

We continue to evaluate cost-effective solar additions that

30 percent below the national average, demonstrating our

will meet requirements in our three-state jurisdiction.

dedication to an intentional and responsible growth strategy.

We are enhancing transmission infrastructure by investing

approximately $39 million to improve reliability and provide

increased capacity for customers in the southern portion

of our service area. Phase one of this two-phase project is

complete, and we expect phase two to be in service in 2021.

[

M A N U F A C T U R I N G C O M P A N I E S

A C C E L E R A T E O P E R A T I O N A L E X C E L L E N C E

[

We are pursuing $897 million in capital investments at

Our manufacturing platform continues to provide growth

the utility between 2020 and 2024, driven by our coal-fired

through new products and services, market expansion, and

plant retirement, renewable resource additions, increased

increased efficiencies.

transmission capacity for renewable energy, and modernized

BTD, our contract metal fabricator and largest manufacturing

customer experience. These investments will allow us to

business, celebrated 40 years of innovation and growth.

deliver on our commitment to a cleaner energy future at

The company increased sales by 4 percent and net income

lower-than-average rates and produce a compounded

by 13.9 percent and substantially grew business with key

annual rate base growth of approximately 8 percent over

accounts in 2019. The Georgia facility, where we added

the 2019 to 2024 timeframe.

stamping capability to improve logistics and better serve

In May 2019 the South Dakota Public Utilities Commission

customers in the Southeast, significantly improved

approved a return on equity of 8.75 percent and a revenue

profitability as sales grew 19.7 percent in 2019. The company

increase of approximately $2.6 million, or 7.7 percent,

concluding our rate case filed in April 2018. In the ruling,

the commission approved a phase-in rider. In exchange, we

agreed not to file a general rate increase in South Dakota
until at least April 2022.

In December 2019 the Minnesota Public Utilities Commission

approved our request to extend the deadline to file our

next resource plan an additional year, until 2021. This plan

identifies the most cost-effective combinations of resources

for reliably meeting customers’ needs during the next

“WE REMAIN COMMITTED TO THE

PURPOSEFUL SELECTION, PLANNING, AND

EXECUTION OF THE RIGHT INITIATIVES AT

THE RIGHT TIMES TO FACILITATE MEASURED

GROWTH FOR EACH OF OUR PLATFORMS.”

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

accomplished this while delivering strong labor productivity

and continuing to improve on already-strong safety

performance, reporting its lowest OSHA recordable case

rate on record.

BTD successfully managed metal cost pass-through

despite great volatility in steel prices. The company balances

production output and inventory levels to ensure on-time

delivery remains strong. BTD continues to implement its

sales, inventory, and operations planning process to plan

for and respond to demand fluctuations in the oil and gas

fracking markets.

T.O. Plastics, our plastics thermoforming manufacturer, is

well positioned to meet demand in emerging horticulture

markets. The company has installed new equipment,

increasing production capacity to serve those markets.

Northern Pipe Products and Vinyltech, the PVC pipe

manufacturing companies that comprise our plastics

segment, performed well to overcome major weather issues

that impacted sales volume during the first three quarters

of 2019. Strong operational performance allowed the

plastics segment to maximize margins despite a 3 percent

drop in sales prices from 2018. We expect the beneficial

2019 housing market to continue in 2020. Both companies

continue to compete effectively by being flexible and

responsive and ensuring on-time deliveries.

Each manufacturing company had solid safety performance,

coming in under 2019 targets and contributing to Otter Tail

Corporation’s lowest OSHA recordable case rate on record.

Each company continues to provide great customer service

and prepare for opportunities in the markets it serves.

RECOGNIZE ACHIEVEMENT. ACCELERATE SUCCESS.

[

Otter Tail Corporation is focused on prudent capital investment,

continued operations improvement, 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 remain committed

to the purposeful selection, planning, and execution of the

right initiatives at the right times to facilitate measured

growth for each of our platforms.

We are energized by our 2019 achievements and look

forward to 2020, accelerating into a new decade of success.

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 CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

ELECTRIC

MANUFACTURING

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

BTD MANUFACTURING, INC.
Metal fabricator
Detroit Lakes, MN | 1995
Paul Gintner
1,145 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
Paul Meschke
201 employees
www.toplastics.com

NORTHERN PIPE
PRODUCTS, INC.
PVC pipe manufacturer
Fargo, ND | 1995
Terry Mitzel
94 employees
www.northernpipe.com

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

REVENUE BY PLATFORM (millions)

NET INCOME FROM CONTINUING
OPERATIONS BY PLATFORM (millions)

MARKET CAPITALIZATION
(millions)

6
1
9
$

0
2
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
$

4
1
5
$

$1,000

$750

$500

$250

$100

$75

$50

$25

9
5
$

9
4
$

0
1
$

2
6
$

0
5
$

2
1
$

2
8
$

4
5
$

8
2
$

7
8
$

9
5
$

8
2
$

2
7
$

9
4
$

3
2
$

0
6
0
2
$

9
6
9
,
1
$

8
5
7
,
1
$

5
0
6
,
1
$

$2,400

$1,800

$1,200

$600

2
5
1
,
1
$

8
0
0
,
1
$

12 13 14 15 16 17 18 19

14 15 16 17 18 19

Manufacturing

Electric

Total Continuing Operations
Electric
Manufacturing (including unallocated corporate costs)

GROWTH OF $1,000 INVESTMENT IN OTTER TAIL
COMMON STOCK MADE DECEMBER 31, 2009
(with dividends reinvested)

$4,000

$3,000

$2,000

$1,000

8
9
5
,
1
$

0
5
4
,
1
$

7
3
4
,
1
$

0
0
0
,
1
$

2
6
9
$

4
9
9
$

8
8
1
,
1
$

4
3
1
,
3
$

2
5
9
2
$

8
6
5
2
$

6
8
2
2
$

DIVIDEND PAYMENT HISTORY

DIVIDEND PAYOUT RATIO

$1.50

$1.20

$0.90

$0.60

$0.30

0
4
.
1
$

$2.40

$1.80

$1.20

$0.60

%
8
7

%
0
7

100%

%
5
6

75%

3
2
.
1
$

5
2
.
1
$

8
2
.
1
$

4
3
.
1
$

0
4
.
1
$

50%

25%

12 13 14 15 16 17 18 19

38 44 49 54 59 64 69 74 79 84 89 94 99 04 09 14 19

15 16 17

18 19

OPERATING INCOME BY PLATFORM (millions, pre-tax)

2
0
1
$

8
6
$

9
6
$

3
0
1
$

9
7
$

1
7
$

9
6
$

1
8
$

9
6
$

5
1
1
$

2
9
$

7
1
1
$

4
9
$

2
3
1
$

5
9
$

9
2
1
$

8
8
$

5
3
1
$

8
9
$

4
3
$

3
3
$

4
2
$

3
2
$

7
3
$

1
4
$

7
3
$

2
1
$

2
$

$150

$120

$90

$60

$30

3
5
1$
4
$

)
2
1
$
(

Consolidated

Electric

Manufacturing (including unallocated corporate costs)

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

SELECTED COMMON SHARE DATA

2019

2018

2017

2016

2015

2014

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

$
$

57.74
45.94

26.6
21.2
19.46

2019

4.1x
17
8.0
11.6
65

47.1
52.9
100.0

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

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

$
$

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

Notes: (1) Continuing Operations.

(2) Continuing Operations; see note 14 to consolidated financial statements in 2019 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

2019

2018

2017

2016

2015

2014

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 Kilowatt-hours Sold
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

$ 131,962
144,662
122,299
5,007
55,167
$ 459,097

1,303,317
1,625,373
1,972,629
67,770
4,969,089
198,569
5,167,658
(0.2)
7,240
392

10.13¢
8.90¢
6.20¢
8.12¢

103,328
27,291
48
1,911
132,578

$ 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

12,689
$ 1,289.40

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

$ 2,212,884
$ 731,110
33.0
2.81

$ 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

923,962

911,726

916,522

903,462

896,706

873,842

548,700
138,000
105,100
2,800
794,600

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

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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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, 2019

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

Trading Symbol(s)

Name of each exchange on which registered

Common Shares, par value $5.00 per share

OTTR

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 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 28, 2019
was $2,040,017,347.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date:
40,214,375 Common Shares ($5 par value) as of February 6, 2020.

Documents Incorporated by Reference: Proxy Statement for the 2020 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 9 A N N UA L R E P O R T

FORM 10-K

TABLE OF CONTENTS

DESCRIPTION

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

PART I

ITEM 1.

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

ITEM 1A.

Risk Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

ITEM 1B.

Unresolved Staff Comments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

ITEM 2.

ITEM 3.

Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

ITEM 3A.

Information About Our Executive Officers (as of February 20, 2020) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

ITEM 4.

Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

PART II

ITEM 5.

ITEM 6.

ITEM 7.

Market for Registrant’s Common Equity, Related Stockholder Matters And Issuer Purchases of Equity Securities . . . . . . . . 35

Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Consolidated Statements of Income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Consolidated Statements of Comprehensive Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Consolidated Statements of Common Shareholders’ Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Consolidated Statements of Capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Supplementary Financial Information—Quarterly Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95

ITEM 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

ITEM 9A.

Controls and Procedures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

ITEM 9B.

Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

PART III

ITEM 10.

Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

ITEM 11.

ITEM 12.

ITEM 13.

Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters . . . . . . . . . . . . . . . . . 97

Certain Relationships and Related Transactions, and Director Independence. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

ITEM 14.

Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

PART IV

ITEM 15.

Exhibits and Financial Statement Schedules. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

ITEM 16.

Form 10-K Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

Signatures

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

DEFINITIONS

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

2018 Notes

ACE
ADIT
ADP
AFUDC
ALJ
AQCS
ARO
ASC
ASC 326
ASC 606
ASC 718
ASC 820
ASC 840
ASC 842
ASC 980
ASM
ASU
ASU 2016-02
BTD
CAA
CCMC
CCR
CO2
CON
CPP
CSAPR
CWIP
D.C. Circuit

ECR
EDF
EDF-USD
EEI
EEP
EPA
ESSRP
Exchange Act
FASB
FERC
GAAP

GCR
GHG
IRP
kV
kW
kwh

February 2018 issuance of $100 million in
privately placed 4.07% Senior Unsecured Notes
due February 7, 2048
Affordable Clean Energy
Accumulated Deferred Income Taxes
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 326—Financial Instruments—Credit Losses
ASC Topic 606—Revenue from Contracts with Customers
ASC Topic 718—Compensation—Stock Compensation
ASC Topic 820—Fair Value Measurement
ASC Topic 840—Leases
ASC Topic 842—Leases
ASC Topic 980—Regulated Operations
Ancillary Services Market
Accounting Standards Update
ASU No. 2016-02, Leases (Topic 842)
BTD Manufacturing, Inc.
Clean Air Act
Coyote Creek Mining Company, L.L.C.
Coal Combustion Residuals
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
Environmental Cost Recovery
EDF Renewable Development, Inc.
EDF-RE US Development, LLC
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
Federal Energy Regulatory Commission
Generally Accepted Accounting Principles in the
United States
Generation Cost Recovery
Greenhouse Gas
Integrated Resource Plan
kiloVolt
kiloWatt
kilowatt-hour

LSA
MATS
Merricourt
MISO
MISO Tariff

Lignite Sales Agreement
Mercury and Air Toxics Standards
Merricourt Wind Energy Center
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 Department of Environmental Quality
North Dakota Public Service Commission
North Dakota Renewable Resource Adjustment
North American Electric Reliability Corporation
New England Transmission Owners
National Pollutant Discharge Elimination System
Notice of Inquiry

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

nitrogen oxide
Navajo Transitional Energy Co.
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
Regional Haze Rule
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
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
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 9 A N N UA L R E P O R T

PART I

[

I T E M 1 . B U S I N E S S

(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 report on Form 10-K.

Otter Tail Corporation and its subsidiaries conduct business primarily

in the United States. The Company had approximately 2,208 full-time
employees at December 31, 2019. 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.

The chart below indicates the operating companies included in each

of the Company’s reporting segments.

ELECTRIC

MANUFACTURING

PLASTICS

Otter Tail Power
Company

BTD
Manufacturing, Inc.

Northern Pipe
Products, Inc.

T.O. Plastics, Inc.

Vinyltech Corporation

(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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

(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 are
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 2019
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 2019 was 68% from the electric utility
and 32% from the manufacturing and plastic pipe businesses, including
unallocated corporate costs.

The Company maintains criteria in evaluating whether its operating

companies are a strategic fit. The operating company should:
(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

adapt to changing economic cycles.

(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 36 through 48 of this 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. See note 2 to our consolidated
financial statements included in this report on Form 10-K for additional
information about the Company’s segments and geographic areas.

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
50%, 49% and 51% of its consolidated operating revenues and 73%, 68%
and 72% of its consolidated operating income from its Electric segment
for the years ended December 31, 2019, 2018 and 2017, respectively.
The breakdown of retail electric revenues by state is as follows:

The above 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 2019, about 54% 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, 2019:

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

Ashtabula Wind III
Edgeley
Langdon

Total Purchased Wind

62,400 kW
21,000
19,500

102,900 kW

State

Minnesota
North Dakota
South Dakota

Total

2019

52.3%
37.7
10.0

2018

52.6%
38.6
8.8

100.0%

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

Great River Energy (through May 2021)

50,000 kW

OTP has a direct control load management system which provides

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

The territory served by OTP is predominantly agricultural. The

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

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, 2019, OTP served
132,578 customers. Although there are relatively few large customers,
sales to commercial and industrial customers are significant. One
customer accounted for 11.9% of 2019 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.

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 2019-2020 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 2020 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 2019 and 2018:

Customer Category

Commercial
Residential
Industrial
All Other Sources

Total

2019

35.4%
32.3
30.0
2.3

2018

37.0%
32.5
30.0
0.5

100.0%

Sources

2019

2018

Net kwhs % of Total
kwhs
(Thousands) Generated

Generated

Net kwhs % of Total
kwhs
Generated
(Thousands) Generated

CAPACITY AND DEMAND
As of December 31, 2019, OTP’s owned net-plant dependable kilowatt
(kW) capacity was:

Subbituminous Coal
Lignite Coal
Wind and Hydro
Natural Gas and Oil

Total

1,754,708
734,740
467,301
53,697

3,010,446

58.3% 1,891,394
1,080,639
24.4
494,394
15.5
70,015
1.8

53.5%
30.5
14.0
2.0

100.0% 3,536,442

100.0%

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

257,600 kW
149,500
141,600

548,700 kW

105,100 kW

2,800 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 9 A N N UA L R E P O R T

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 Peabody

COALSALES, LLC

Wyoming
subbituminous

December 31, 2020

Coyote Station

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

lignite

December 31, 2040

Hoot Lake Plant Navajo Transitional
Energy Co. (NTEC)

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.

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 share of unrecovered costs of
CCMC as of December 31, 2019 were $50.4 million. See note 1 to our
consolidated financial statements included in this report on Form 10-K
for additional information.

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. In October 2019, NTEC
purchased the assets of Cloud Peak Energy Resources LLC, including
its Spring Creek Mine in southeast Montana, through bankruptcy court.
For a two-day period in October, operations at the Spring Creek Mine
were suspended due to a disagreement between the Montana
Department of Environmental Quality and the NTEC. Subsequent
to the suspension of operations, the two parties agreed to allow the
mine to operate for an additional period while they work to resolve
differences regarding the NTEC’s waiver of sovereign immunity from
the state’s environmental laws.

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 2019,
2018, and 2017 was $2.129, $1.977 and $2.224, 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.

Rates

Regulation

2019

2018

% of
Electric
Revenues

% of
% of
Electric
kwh
Sales Revenues

% of
kwh
Sales

MN Retail Sales MN Public Utilities

47.0% 53.5%

46.2% 54.1%

Commission

ND Retail Sales ND Public Service

33.8

36.6

33.9

36.8

Commission

SD Retail Sales SD Public Utilities

9.0

9.9

7.7

9.1

Commission
Federal Energy
Regulatory Commission

Transmission
& Wholesale

Total

10.2

—

12.2

—

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 for 2019
were based on a two-month moving average in Minnesota and were
applied to the next billing period after becoming applicable. Adjustments
for fuel and purchased power costs are presently based on a three-month
moving average in South Dakota and a four-month moving average in
North Dakota and 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 took effect on January 1, 2020 (see discussion under
Minnesota—Fuel and Purchased Power Costs Recovery below).

2017 TAX CUTS AND JOBS ACT (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, OTP’s electric rates had been developed using a 35% tax
rate. The Minnesota Public Utilities Commission (MPUC), the North
Dakota Public Service Commission (NDPSC), the South Dakota Public
Utilities Commission (SDPUC) and the FERC 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 reduction into future electric rates, if warranted.

The MPUC required regulated utilities providing service in Minnesota

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ratepayers, in a one-time refund, the TCJA-related savings accrued
prior to the refund effective date. 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. New rates
reflecting the reduction in revenue requirements related to the TCJA
tax rate reduction went into effect June 1, 2019. A one-time refund to
Minnesota customers of $11.5 million in excess of amounts billed from
January 2018 through May 2019 occurred in August and September 2019.
OTP’s recent general rate cases in North Dakota and South Dakota
reflected the impact of the TCJA in interim rates. OTP accrued refund
liabilities for the time periods during which revenues were collected
under rates set to recover higher levels of federal income taxes than
OTP incurred under the lower federal tax rates in the TCJA.

ELECTRIC SEGMENT MAJOR CAPITAL EXPENDITURE PROJECTS
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 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 Wind Energy Center (Merricourt)—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 (collectively, EDF) to purchase and assume the
development assets and certain specified liabilities associated with
Merricourt, a 150-megawatt (MW) wind farm in southeastern North
Dakota, for a purchase price of approximately $34.7 million, subject
to adjustments for interconnection costs. Also on November 16, 2016,
OTP entered into a Turnkey Engineering, Procurement and Construction
Services Agreement (the TEPC Agreement) with EDF-RE US
Development, LLC (EDF-USD) pursuant to which EDF-USD 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. The agreements
contain customary representations, warranties, covenants and
indemnities for this type of transaction. On October 26, 2017 the MPUC
approved the facility under the Renewable Energy Standard making
Merricourt eligible for cost recovery under the Minnesota Renewable
Resource Recovery rider, subject to qualifications and reporting
obligations. The MPUC’s final written order was issued on January 10,
2018. A final order for an Advance Determination of Prudence (ADP)
for Merricourt, subject to qualifications and compliance obligations,
and a Certificate of Public Convenience and Necessity were issued by
the NDPSC on November 3, 2017. The phase-in rider approved by order
of the SDPUC on March 6, 2019 includes recovery of Merricourt costs.
The Merricourt generator interconnection agreement with MISO was
approved by the FERC in April 2019.

In connection with action by the FERC, OTP and EDF-USD agreed,

in the First Amendment to the Purchase Agreement and the TEPC
Agreement dated June 11, 2019, to change the purchase price to
$37.7 million and to make a related reallocation of responsibility for
interconnection costs and liabilities. On July 16, 2019, OTP closed on the
purchase of substantially all of the development assets and assumed
certain specified liabilities from EDF related to Merricourt pursuant to the
Purchase Agreement, as amended, for a purchase price of approximately
$37.7 million, subject to certain adjustments, and issued the notice to

EDF-USD to begin construction in August 2019. As of December 31, 2019,
OTP had capitalized approximately $81.7 million in project costs and
allowance for funds used during construction (AFUDC) associated with
Merricourt. OTP expects the project will be completed in October 2020
and cost approximately $258 million.

Astoria Station—OTP is constructing this 245 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. A final order granting
an ADP for Astoria Station was issued by the NDPSC on November 3,
2017, subject to certain qualifications and compliance obligations. On
August 3, 2018 the SDPUC issued an order granting a site permit for
Astoria Station. In a September 26, 2018 hearing the NDPSC established
a Generation Cost Recovery Rider for future recovery of costs incurred for
Astoria Station. On March 6, 2019 the SDPUC issued an order approving
a settlement that allows a phase-in rider which includes recovery of
Astoria Station costs. The interconnection agreement for Astoria Station
was executed by MISO in December 2018 and accepted by the FERC in
January 2019. Site preparation and excavation began in May 2019. As
of December 31, 2019, OTP had capitalized approximately $58.7 million
in project costs and AFUDC associated with Astoria Station. OTP expects
the project will be completed in late 2020 or early 2021 and cost
approximately $158 million.

Big Stone South–Ellendale Multi-Value Transmission Project (MVP)—
This 345-kiloVolt (kV) transmission line, energized on February 6, 2019,
extends 162 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
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
from the MVP. OTP capitalized costs of approximately $106 million on
this project, including assets that are 100% owned by OTP.

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.

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

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

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 key environmental regulations for which the impacts on OTP facilities
were not yet ascertainable: the federal Regional Haze Rule (RHR)
promulgated by the Environmental Protection Agency (EPA) in 1999
and the Affordable Clean Energy (ACE) Rule proposed by the EPA in
August 2018. On August 29, 2019 OTP filed a request to extend the
next resource plan filing date from June 1, 2020 to September 1, 2021.
The main reason for this request was to have more certainty on the
North Dakota Department of Environmental Quality (NDDEQ) decision on
the technology required to comply with the RHR. On December 5, 2019
the MPUC granted OTP’s request for an extension until September 1, 2021
to file its next resource plan. In connection with the extension, OTP is
required to file a document detailing its bidding process and timeline
for a solar project by April 15, 2020 and to make a compliance filing
with the MPUC detailing proposed next steps for contract negotiations
and filings by July 1, 2020. By December 31, 2020 OTP is required to
make a supplemental filing modeling scenarios showing differing levels
of RHR compliance costs, including a scenario where Coyote Station
closes as an alternative to adding environmental controls. OTP is also
required to provide a number of sensitivities for each scenario, including
Minnesota environmental externalities and carbon regulatory costs.

Fuel and Purchased Power Costs Recovery—The MPUC issued an order
authorizing the implementation of a new fuel clause adjustment
mechanism to be implemented January 1, 2020. OTP will submit
forecasted monthly fuel cost rates in advance for the upcoming
twelve-month period beginning January 1 of each year. 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.

This mechanism could result in reductions in Electric segment
operating income margins, increase variability in consolidated net
income in future periods if costs per kwh vary from forecasted costs
per kwh, and cause an increase in working capital and short-term
borrowings in the event recovery of all or a portion of excess costs is
delayed or 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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, but this range is currently under review by the MPUC. 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. OTP meets the current renewable sources
requirements with a combination of owned renewable generation and
purchases from renewable generation sources. Minnesota law also
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% 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 is evaluating potential options for maintaining
compliance and meeting the solar energy standard beyond 2021.
OTP’s compliance with the Minnesota renewable energy standard will
be measured through the Midwest Renewable Energy Tracking System.

Under the Next Generation Energy Act of 2007, an automatic
adjustment mechanism was established to allow Minnesota electric
utilities to recover investments and costs incurred to satisfy the
requirements of the renewable energy standard. The MPUC is authorized
to approve a rate schedule rider to enable utilities to recover the costs
of qualifying renewable energy projects that supply renewable energy
to Minnesota customers. Cost recovery for qualifying renewable energy
projects can be authorized outside of a rate case proceeding, provided
that such renewable projects have received previous MPUC approval.
Renewable resource costs eligible for recovery may include return on
investment, depreciation, operation and maintenance costs, taxes,
renewable energy delivery costs and other related expenses.

Minnesota Conservation Improvement Programs (MNCIP)—Under
Minnesota law, every regulated public utility that furnishes electric
service must make annual investments and expenditures in energy
conservation improvements or make a contribution to the state’s energy
and conservation account, in an amount equal to at least 1.5% of its
gross operating revenues from service provided in Minnesota.
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 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. The MNDOC issued a decision on May 20, 2019 to
extend all utilities 2017-2019 MNCIP plans one year, through 2020, with
an incentive based on 30% of spending and 10% of net benefits.

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 reserved for potential future refund.
No refund was required, and the $0.3 million reserve was reversed and
recorded as revenue in 2019.

Based on results from the 2018 MNCIP program year, OTP recognized
a financial incentive of $3.0 million in 2018. OTP requested approval for
recovery of its 2018 MNCIP program costs not included in base rates on
April 1, 2019. The request included a $3.0 million financial incentive and
an update to the MNCIP surcharge from the MNPUC. On October 24,
2019 the MPUC approved a $3.0 million financial incentive for 2018.

Based on results from the 2019 MNCIP program year, OTP recognized

a financial incentive of $2.7 million in 2019. By April 1, 2020 OTP will
request approval from the MPUC for recovery of the 2019 financial
incentive and its 2019 program costs not included in base rates.

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. 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 plans. On May 20, 2019 the MNDOC
issued a decision allowing OTP to use its 2017-2019 avoided costs for
the 2020 MNCIP year. The decision also approved the use of OTP’s
newly established avoided costs for the 2021-2023 MNCIP triennial plan
expected to be filed with the MNDOC on June 1, 2020.

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,

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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.

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 the second quarter of 2020.

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 addition,
on April 1, 2019, the MNDOC filed comments in OTP’s TCR rider docket,
opposing OTP’s proposal for TCR rider recovery of these costs. The
MPUC is not expected to act on the TCR rider until after the Minnesota
Supreme Court has acted and additional briefing has occurred in the
docket. The estimated amount credited to Minnesota customers under
the TCR rider through December 31, 2019 and subject to recovery if
the Minnesota Court of Appeals decision is upheld, is approximately
$2.6 million. If the Minnesota Court of Appeals decision is upheld,
there will be additional briefing in the pending TCR rider docket
regarding the recovery of these costs.

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. 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.

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 July 19, 2019, allowing for an
equity-to-total-capitalization ratio between 46.0% and 56.2%, with
total capitalization not to exceed $1,331,302,000 until the MPUC issues
a new capital structure order for 2020. OTP is required to file its 2020
capital structure petition no later than May 1, 2020.

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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

General Rates—On November 2, 2017 OTP filed a request with the
NDPSC for a rate review and an effective increase in annual revenues
from non-fuel base rates of $13.1 million or 8.72%. 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 ROE 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 ROE 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 (GCR) 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 were effective
February 1, 2019, with refunds of excess revenues collected under
interim rates applied to customers’ April 2019 bills, including $0.8 million
for amounts collected reflecting the higher tax rates 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. 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
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.

On May 1, 2019 the NDPSC approved OTP’s request for an annual
update to its NDRRA rider rate to -0.224% of base charges, based on an
annual refund requirement of $235,000, effective for bills rendered on
and after June 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
federal Production Tax Credits (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
NDRRA rider transitioned to recovery in base rates.

On December 31, 2019 OTP filed its annual update to the NDRRA
requesting approval for recovery of $3.8 million in renewable energy
costs from its North Dakota customers. The $3.8 million is net of a
credit of $0.5 million for amounts over-collected under the North
Dakota ECR that will be credited to North Dakota customers through
this RRA update.

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 continues to be updated annually for new or modified electric
transmission facilities and associated operating costs.

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
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.

OTP filed its annual update to the North Dakota TCR rider on

August 30, 2019 seeking recovery of approximately $5.7 million with a
proposed effective date of January 1, 2020. The filing included seven
new projects, updated costs associated with existing projects, details
about the pending MISO ROE complaint, and details about SPP-related
expenses. On December 18, 2019 the NDPSC approved the request.

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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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

On July 9, 2019 the SDPUC approved a stipulation agreement entered

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 ECR 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. On October 22, 2019
the NDPSC approved OTP’s request to decrease the ECR rate to zero
effective November 1, 2019 and to include the final tracker balance in
OTP’s December 31, 2019 annual update to its North Dakota RRA.

Generation Cost Recovery Rider—On May 15, 2019 the NDPSC approved
OTP’s request to establish an initial GCR rider rate for recovery of OTP’s
North Dakota jurisdictional share of the revenue requirements on its
investment in Astoria Station, effective on bills rendered after July 1, 2019.

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
were effective October 18, 2018. The second step in the request was an
additional 1.7% revenue increase to recover costs for Merricourt when
the wind generation facility goes into service.

The SDPUC approved a partial settlement on March 1, 2019 on all issues
of the rate case except ROE. The partial settlement included approval of
a phase-in plan to provide for a return on amounts invested in Astoria
Station and Merricourt, which addressed the second step of the request
for increased rates in South Dakota. The partial settlement also included
a moratorium on filing another general rate case in South Dakota until
the new generation projects have been in service for a year. The partial
settlement also allowed OTP to retain the impact of lower tax rates
related to the TCJA from January 1, 2018 through October 17, 2018
resulting in the reversal of an accrued refund liability and recognition of
$1.0 million in revenue in the first quarter of 2019. The SDPUC approved
the ROE portion of the rate case on May 14, 2019. Pursuant to the May 30,
2019 order, OTP’s allowed ROE was set at 8.75%, resulting in an annual
revenue increase of approximately $2.2 million prior to the approval of
a June 28, 2019 stipulation agreement discussed below. Final rates
went into effect August 1, 2019. An interim rate refund for the lower
ROE going back to October 18, 2018 was applied to South Dakota
customers’ October 2019 bills.

into by OTP with SDPUC staff for the purpose of correcting a mistake
in OTP’s rate base in its 2018 general rate case docket. The revenue
requirement stated in the SDPUC’s final order dated May 30, 2019
understated the correct amount of OTP’s South Dakota share of electric
transmission plant in service by approximately $4.1 million. For South
Dakota ratemaking purposes, the understatement resulted in an annual
revenue requirement shortfall of approximately $341,000. To address
the shortfall, the parties agreed that OTP would file an update to its
South Dakota TCR rider. OTP was authorized full recovery of the
transmission rate base correction reflected in the TCR rider tracker
beginning as of the first date of interim rates, October 18, 2018, with
the TCR rider rate update going into effect on October 1, 2019. The
stipulation agreement had the effect of increasing the non-fuel annual
revenue increase in the general rate case to approximately $2.6 million
or 7.7%, which is 69% of the adjusted requested annual revenue
increase of approximately $3.7 million or 11.1%.

To ensure rates are appropriately set under the stipulation, the parties

agreed to establish an earnings sharing mechanism to share with
customers any weather-normalized earnings above the authorized ROE
of 8.75%. OTP’s annual weather-normalized earnings are reported each
year by June 1 in its jurisdictional annual report, which will be used to
determine the earnings level for purposes of calculating any refund. The
earnings sharing mechanism requires that OTP will refund to customers
50% of any weather-normalized revenue that corresponds to the earnings
in excess of its authorized ROE, up to a maximum of 9.50% ROE for a
particular year. OTP will refund 100% of any earnings above 9.50% each
year. In the event a refund is due under this provision, OTP will notify
the SDPUC of the refund amount and plan for crediting customers
within 30 days of filing its South Dakota jurisdictional annual report.

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.

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 remained at $1.8 million
and was approved by the SDPUC on February 28, 2018 with an effective
date of March 1, 2018. 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 end of the 2018 general rate case.

OTP made a supplemental filing for the South Dakota TCR rider
on February 1, 2019. In an order dated February 20, 2019 the SDPUC
approved the supplemental filing and rates effective March 1, 2019.
Two new projects were approved for recovery under the rider: The Lake
Norden area transmission upgrade project with a recovery date effective
January 1, 2019 and the Big Stone South—Ellendale project with a
recovery date effective January 1, 2020.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

On September 17, 2019 the SDPUC approved OTP’s supplemental
TCR rider filing update request to address the transmission rate base
correction disclosed in the 2018 general rate case docket with updated
rates effective October 1, 2019.

OTP filed its annual update to the South Dakota TCR rider on
October 31, 2019 seeking recovery of $2.4 million with a proposed
effective date of March 1, 2020.

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, 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. The ending balance of the South Dakota ECR rider at the conclusion
of interim rates was refunded to South Dakota customers along with
their October 2019 interim rate refunds.

Phase-In Rate Plan Rider—On May 31, 2019 OTP petitioned the SDPUC
for approval of its initial rate for the Phase-In Rate Plan Rider as described
in OTP’s most recent South Dakota general rate case settlement
stipulation and approved by the SDPUC’s order in that rate case. The
petition is OTP’s initial filing for the rider to recover, in OTP’s South
Dakota jurisdiction, actual and forecasted costs for Astoria Station and
Merricourt, and forecasted net benefits associated with additional load
growth in the Lake Norden area.

On August 21, 2019 the SDPUC approved OTP’s supplemental filing for
its South Dakota Phase-In Rate Plan Rider effective September 1, 2019.

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 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.

On May 1, 2019 OTP filed its 2018 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 to $0.00164/kwh effective July 1, 2019. The SDPUC
approved the request on June 13, 2019. By May 1, 2020 OTP plans to
file its 2019 South Dakota EEP Status Report, financial incentive and
surcharge adjustment with the SDPUC. The filing will request approval
of an incentive of $209,700 and an update of the EEP surcharge with a
July 1, 2020 effective date.

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.

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.

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%.

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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

rider, 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
September 30, 2019.

On March 1, 2019 the FERC issued a Notice of Inquiry (NOI) seeking

comment on whether, and if so how, it should modify its policies
concerning the determination of the ROE used in designing jurisdictional
rates charged by public utilities. For years, the FERC has utilized a
particular two-step, analysis to establish ROEs for utilities and natural
gas interstate pipelines. The NOI sought comments on whether it should
develop ROEs using a different financial model. The NOI also sought
comments, among other things, on the continued use of RTO Adders.
On November 21, 2019 the FERC adopted a different two-step ROE

model and capital asset pricing model to determine whether a
jurisdictional public utility’s rate of ROE is just and reasonable under
section 206 of the Federal Power Act. Applying the new methodology in
complaints against the MISO transmission owners, the FERC determined
that the MISO transmission owners’ current base ROE should be 9.88%.
The FERC also stated it will use ranges of presumptively just and
reasonable ROEs in its analysis of whether existing ROEs have become
unjust and unreasonable. This order also implemented the FERC’s
revised methodology in the two complaints against the MISO
transmission owners’ base ROE. The order granted rehearing on the
first complaint, found the existing 12.38% ROE unjust and unreasonable,
and directed the MISO transmission owners to adopt a 9.88% ROE
effective September 28, 2016, and to provide refunds. The order also
dismissed the second complaint and found the record in that proceeding
did not support a finding that the 9.88% ROE established in the first
complaint proceeding had become unjust and unreasonable.

As a result of the FERC granting rehearing on the first complaint and
finding the existing 12.38% ROE unjust and unreasonable and directing
the MISO transmission owners to adopt a 9.88% ROE, OTP increased its
total refund provision related to the ROE complaints from $1.6 million
to $3.0 million as of December 31, 2019. The $3.0 million includes
provisions for:
(cid:1) an additional $0.2 million refund related to the first complaint as a
result of reducing the reasonable ROE from 10.32%, established in
the FERC’s September 28, 2016 refund order, to the newly
established 9.88% ROE,

(cid:1) a $1.3 million refund for the period from September 28, 2016 through
December 31, 2019 related to a reduction in the current ROE from
10.82% to 10.38% based on the newly established 9.88% reasonable
ROE for the first complaint period plus the 50-point RTO adder
granted by the FERC on January 5, 2015, and

(cid:1) a $1.5 million refund related to the second complaint period in

response to requests for rehearing on the FERC’s decision to dismiss
the second complaint based on a potential reduction in the
reasonable ROE for that period from 12.38% to 9.88% plus the
50-point RTO adder.

In response to the FERC’s November 21, 2019 order, the MISO

Transmission Owners (including OTP) and others filed requests seeking
rehearing of the FERC’s November 21, 2019 order, and a group of parties
filed with the U.S. Court of Appeals for the District of Columbia (D.C.
Circuit) a protective appeal.

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 2019 audit of OTP has concluded without any
material findings.

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
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.

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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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 option to initially fund the
construction of certain qualifying interconnection-related transmission
upgrades, sometimes referred to as the “self-fund option” or “self-fund.”
Thus, under the self-fund option, 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 over the period of the applicable service agreements.

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 (collectively,

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 has been briefed and
oral arguments heard, with a decision expected in early 2020.

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, 2019 OTP invested approximately $39.5 million in
environmental control facilities. The 2020 and 2021 construction budgets
include approximately $0.4 million and $1.2 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 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 2019.

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 2019 without acquiring
additional allowances.

On September 7, 2016 the EPA finalized a CSAPR update to address

interstate emission transport with respect to the more recent 2008
ozone NAAQS. The CSAPR update on interstate emission transport
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 the 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. On June 30, 2016, the EPA signed

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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. 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. On
December 28, 2018 the EPA issued a proposed rule that provides that it
is not “appropriate and necessary” to regulate hazardous air pollutants
from power plants; however, the EPA declined to propose rescission or
repeal of 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 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 (Round 1) and
focused on applying Best Available Retrofit Technology (BART) to
certain large stationary sources that were in existence on 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 (Round 2), with state implementation plans (SIPs) due to be
submitted to the EPA by July 31, 2021 and an anticipated compliance
date on or before December 31, 2028. For Round 2, states are required
to assess reasonable progress with the RHR and determine what
additional emission reductions are appropriate. As part of this
assessment, the NDDEQ requested that Coyote Station provide an
analysis of technically feasible SO2 and NOx emissions control options,
which OTP provided in January 2019.

On August 20, 2019 the EPA released a guidance document to assist
states with preparation of Round 2 SIPs. The guidance describes eight
steps for states to follow, including a step which involves decisions on
which emissions control measures are necessary to make reasonable
progress. The guidance stresses that a state should generally make
control decisions that are reasonably consistent among and across
sources within the state.

OTP understands the NDDEQ intends to require sources subject to
Round 2 reasonable progress determinations, including Coyote Station,
to undertake emissions control measures that are reasonably consistent
with those required of sources during Round 1. While this process is still
in the early stages, if the NDDEQ maintains its initial position, OTP
anticipates that significant emissions controls would be required at
Coyote Station by December 31, 2028 in order to maintain compliance
with the RHR. In light of the costs for such emissions control equipment,
there are scenarios where it may not be economically feasible to invest
in such equipment and an early retirement of the Coyote Station would
therefore be necessary. OTP and the other three co-owners of Coyote
Station have been evaluating, and will continue to evaluate, alternative
scenarios for the future of Coyote Station as the process with the NDDEQ
and other stakeholders evolves. This process could take several years
to finalize. The costs related to an early retirement of Coyote Station
would be material to OTP and the Company and would be subject to
state commission approval for recovery from customers. See note 1 to
our consolidated financial statements included in this report on Form
10-K for additional information on Coyote Station.

In order to meet the July 31, 2021 SIP submittal deadline, the NDDEQ

has indicated that it will begin drafting a SIP in mid-2020 and provide
preliminary control scenarios to the Western Regional Air Partnership
in the first quarter of 2020 (for purposes of regional visibility modeling).
The NDDEQ expects to provide a proposed SIP for public comment in
the first or second quarter of 2021.

As discussed above, OTP was required by the MPUC to model a

scenario in which Coyote Station is retired in 2028.

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 2019
these plants emitted approximately 3.0 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 the 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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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 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.
The final ACE Rule under CAA Section 111(d) went into effect on
September 6, 2019. The rule establishes guidelines for states to use in
developing plans to address GHG emissions from existing coal fired
power plants. Notably, the final rule establishes heat rate improvements
as the best system of emissions reductions for reducing carbon dioxide
emissions. Heat rate is a measure of the amount of energy required to
generate a unit of electricity. States will establish unit-specific standards
of performance that reflect the emission limitation achievable through
certain candidate heat-rate improvement technologies. Simultaneously
with the final ACE Rule, the EPA took action to repeal the Clean Power
Plan, and the EPA also finalized revisions to the timing and content
requirements of Section 111(d) state implementation plan submissions.
The final ACE Rule does not include any final action regarding New
Source Review. States now have until mid-2022 to submit a state
implementation plan. Several petitioners have filed challenges to the
rule in the D.C. Circuit. On November 22, 2019 the court denied the EPA’s
request for expedited review and petitioners’ requests to hold the case
in abeyance, pending administrative reconsideration of the ACE Rule.

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. Both the range of costs and the effective date are currently
under review by the MPUC. A decision is expected by March 31, 2020.
It is likely that both the range of costs and the effective date will
remain the same for 2020-2021.

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 61%, 78%
and 29%, respectively. OTP’s efforts to increase plant efficiency and
add renewable energy to its resource mix have reduced its CO2
intensity. Between 2005 and 2019 OTP decreased its overall system
average CO2 emissions intensity by approximately 24%. Further
reductions are expected with the planned addition of Merricourt and
replacement of Hoot Lake Plant generation with the Astoria Station
natural gas-fired generation plant.

(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.

(cid:1) 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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. Although the EPA is
currently reconsidering portions of the 2015 rule, 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 were followed by the
filing of the license application in November 2019. OTP expects the FERC
to issue an order on the license application in 2021. Total nameplate
rating (manufacturer’s expected output) of the five dams is 3,250 kW.

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

On December 19, 2014 the EPA announced a final rule regulating
coal combustion residuals (CCR) under the Resource Conservation and
Recovery Act regulating the disposal of coal ash generated from the

combustion of coal by electric utilities under Subtitle D’s nonhazardous
provisions. The 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 was 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 has begun a process to incorporate the CCR rule.
At the request of the Minnesota Pollution Control Agency (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
from 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 2019 approximately $187 million
in cash was invested for additions and replacements to its electric utility
properties. During the five years ended December 31, 2019 gross electric
property additions, including CWIP, were approximately $700 million
and gross retirements were approximately $93 million. OTP estimates
that during the five-year period 2020-2024 it will invest approximately
$897 million for electric construction, including:
(cid:1) $260 million for renewable wind and solar energy generation and

conservation, including Merricourt, scheduled for completion in 2020,
the exercise of a purchase option to transfer the Ashtabula III wind
farm to OTP in 2022, an investment in solar generation in 2023, and
routine wind-power replacement projects.

(cid:1) $169 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) $134 million for routine distribution plant replacement projects.
(cid:1) $117 million for transmission assets including new construction and

routine replacement projects.

(cid:1) $99 million for the Astoria Station natural gas-fired generation plant

to replace Hoot Lake Plant capacity.

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The remaining $118 million of the 2020-2024 anticipated capital
expenditures is for asset replacements, additions and improvements to
OTP’s other generation 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, 2019 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, 2019 OTP had 654 equivalent full-time employees.
A total of 384 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
and extruded raw material stock.

The Company derived 30%, 29% and 27% of its consolidated operating

revenues and 13%, 14% and 11% of its consolidated operating income
from the Manufacturing segment for the years ended December 31,
2019, 2018 and 2017, 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’s
Georgia facility offers a wide range of metal fabrication services ranging
from simple laser cutting services and high volume stamping to complex
weldments and assemblies for metal fabrication buyers and original
equipment manufacturers.

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

PRODUCT DISTRIBUTION
The principal method for distribution of the manufacturing companies’
products is by direct shipment to the customer by common carrier
ground transportation. No single customer or product of the Company’s
manufacturing companies accounted for 10% of the Company’s
consolidated revenue in 2019. However, the top two customers combined
accounted for 35% and the top five customers combined accounted for
over 54% of 2019 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 $179 million compared with $211 million one
year ago. Material price deflation is driving backlog down by $19 million
and the remaining $13 million decrease in backlog is volume driven.

CAPITAL EXPENDITURES
Capital expenditures in the Manufacturing segment typically include
additional investments in new manufacturing equipment or expenditures
to replace worn-out manufacturing equipment. Capital expenditures
may also be made for the purchase of land and buildings for plant
expansion and for investments in management information systems.
During 2019, cash expenditures for capital additions in the Manufacturing
segment were approximately $14 million. Total capital expenditures for
the Manufacturing segment during the five-year period 2020-2024 are
estimated to be approximately $67 million.

EMPLOYEES
At December 31, 2019 the Manufacturing segment had 1,346 full-time
employees. There were 1,145 full-time employees at BTD and 201 full-time
employees at T.O. Plastics as of December 31, 2019.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

PLASTICS

GENERAL
Plastics consists of businesses producing PVC pipe at plants in North
Dakota and Arizona. The Company derived 20%, 22% and 22% of its
consolidated operating revenues and 21%, 25% and 22% of its
consolidated operating income from the Plastics segment for the years
ended December 31, 2019, 2018 and 2017, 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 accounted for over 10% of the Company’s consolidated
revenue in 2019. However, two customers combined accounted for 46%
of 2019 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
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 Northern Pipe and Vinyltech can source
to supply their PVC resin requirements. Two vendors provided over 99%
of total resin purchases in 2019 and 2018. 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 2019, cash
expenditures for capital additions in the Plastics segment were
approximately $5 million. Total capital expenditures for the five-year
period 2020-2024 are estimated to be approximately $20 million to
replace existing equipment.

EMPLOYEES
At December 31, 2019 the Plastics segment had 168 full-time employees.
Northern Pipe had 94 full-time employees and Vinyltech had 74 full-time
employees as of December 31, 2019.

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[

I T E M 1 A . R I S K FA C T O R S

]

RISK FACTORS AND CAUTIONARY STATEMENTS
Our businesses are subject to various risks and uncertainties. Any of
the risks described below or elsewhere in this report on Form 10-K or in
our other SEC filings could materially adversely affect our business,
financial condition, results of operations and cash flows. Additional
risks and uncertainties we are not presently aware of or that we currently
consider immaterial may also affect our business, financial condition,
results operations and cash flows.

Oversight of Risk and Related Processes
A key accountability of the Board of Directors is the oversight of material
risk. Management and the Board of Directors have responsibility for
overseeing the identification and mitigation of top risks. Management
identifies and analyzes risks to determine the impact and other attributes
such as timing, likelihood and management control. Identification and
analysis occur formally through a top risk assessment conducted by
senior management, the financial disclosure process, and internal
auditing and compliance with financial and operational controls.
Management also identifies and analyzes risk through development of
goals and key performance indicators, which include risk identification
to determine barriers to implementing our strategy. We promote a
culture of compliance, including tone at the top. The process for risk
mitigation includes adherence to our code of conduct and compliance
policies, operation of formal risk management structures and overall
business management to mitigate the risks inherent in the implementation
of strategy. We manage and further mitigate risks through formal risk
management structures, including a management executive risk
committee and services such as internal audit/business risk management
and legal. Management communicates regularly with our Board of
Directors and key stakeholders regarding risk. Senior management
presents and communicates a periodic risk assessment to our Board of
Directors which provides information on the risks management believes
are material, including the earnings impact, timing, likelihood and
management control. The Board of Directors approaches oversight,
management and mitigation of risk as an integral and continuous part of
its governance of Otter Tail Corporation. The Board of Directors regularly
reviews management’s top risk assessment and analyzes areas of
existing and future risks and opportunities. Finally, the Board of
Directors conducts an annual strategy session where our future plans
and initiatives are reviewed.

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

Existing environmental laws or regulations may be revised, and new

laws or regulations may be adopted or become applicable to us.
Revised or additional regulations, which result in increased compliance

costs or additional operating restrictions, particularly if those costs are
not fully recoverable from customers, could have a material effect on
our results of operations.

Weather impacts, including normal seasonal fluctuation of weather,
as well as extreme weather events that could be associated with
climate change, could adversely affect our results of operations.
OTP’s business is seasonal and weather patterns can have a material
impact on its financial performance. Demand for electricity is normally
greater in the winter and summer months. Unusually mild summers
and winters could have an adverse effect on OTP’s financial condition
and results of operations. In addition, the companies in our Plastics
segments are affected by weather’s impact on contractors whose work
can be delayed and therefore reduce the need for PVC pipe during winter
weather and extreme wet conditions. Our businesses are located in areas
that could be subject to seasonal natural disasters such as severe snow
and ice storms, tornadoes, flooding and fires. These factors could result
in interruption of our business and damage to our facilities. An extreme
weather event within our utility service areas could directly affect our
capital assets, causing disruption in service to customers, due to
downed wires and poles or damage to other operating equipment.

In addition to variations in seasonal weather patterns, more widespread

climate change may also create physical and financial risks to the
Company. Physical risks of climate change, such as more frequent or
more extreme weather events, changes in temperature and precipitation
patterns, changes to ground and surface water availability, and other
related phenomena, could affect some or all of our operations. Severe
weather or other natural disasters related to climate change could be
destructive, which could result in increased costs and delayed capital
projects at OTP. Extreme weather conditions, such as uncommonly long
periods of high or low ambient temperature, in general require more
system backup, adding to costs, and can contribute to increased system
stress, including service interruptions. Such risks could have an adverse
effect on the Company’s financial condition, results of operations and
cash flows.

The Company may also be subject to litigation related to climate
change. Costs of such litigation could be significant, and an adverse
outcome could require substantial capital expenditures, changes in
operations and possible payment of penalties or damages which could
affect the Company’s results of operations and cash flows if the costs
are not recoverable in rates or covered by insurance.

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, on
acceptable terms and at reasonable costs, 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.
Market disruptions could include: a significant economic downturn,
volatility in commodity prices, turmoil in the financial services industry
and deterioration in capital market conditions. OTP is a party to
contracts that require the posting of collateral or settlement of
applicable contracts if credit ratings fall below certain levels.

Borrowings under our revolving credit agreements 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, 2024. There is
no assurance the replacement for LIBOR will be as favorable as LIBOR.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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.

To the extent financial markets view climate change and emissions
of GHGs as a financial risk, this could negatively affect the Company’s
stock price or the Company’s ability to access capital markets on
favorable terms and conditions.

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, 2019. 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 in our Manufacturing or Plastics segments 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 $170 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, 2019, 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 46.0% and 56.2% based on OTP’s 2019 capital structure
petition. OTP’s equity-to-total-capitalization ratio, including short-term
debt, was 51.2% as of December 31, 2019.

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. These laws are subject to change and expansion and may require
additional operational changes to comply.

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,

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

customers and regulators. In addition to property and casualty insurance
which may cover restoration of data, certain physical damage or
third-party injuries, we have cybersecurity insurance related to a breach
event. However, damage and claims arising from such incidents may
not be covered or may exceed the amount of any available insurance.
We have cybersecurity processes and controls designed to protect
and preserve the confidentiality, integrity and availability of data and
systems and we and each of our operating companies have adopted
disaster recovery plans. We have also adopted a number of security
measures, practices, awareness and training programs as well as system
processes to securely maintain confidential information. 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.

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
earnings growth targets, which 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.
We have a substantial capital investment program planned for the next
five years including investments in renewables, a natural gas-fired

plant, transmission assets and potential technology and infrastructure
projects. Our ability to successfully and timely complete capital additions
and improvements to existing facilities is contingent on many variables
including availability and timely delivery of materials and components,
which rely in part on a global markets, which markets could be subject
to political crises, public health crises or other catastrophic events that
are outside of our control. For example, in December 2019, a strain of
coronavirus was reported to have occurred in Wuhan, China, resulting
in certain manufacturing plants shuttering by government mandate. At
this point, the extent to which the coronavirus may impact our capital
projects is uncertain. There are also 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, unsuccessful implementation
or delay in implementing new technology, lack of markets for new
products, competition from producers of lower cost or alternative
products, product defects, loss of customers, severe weather events,
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 current and former manufacturing businesses 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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.
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 2019, one customer accounted for 12% of Electric
segment revenue, two customers accounted for a total of 35% of
Manufacturing segment revenue and two customers accounted for
46% 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.

The inability to attract and retain a qualified workforce including, but
not limited to, executive officers, key employees and employees with
specialized skills could have an adverse effect on our operations.
The success of our business heavily depends on the leadership of our
executive officers and key employees to implement our strategy. The
inability to attract and maintain a qualified workforce at all our operating
companies may negatively affect our ability to service our customers,
manufacture products, or successfully manage our business and
achieve our objectives. Competition for skilled workers is high and can
lead to increased labor expenses, decreased productivity and potentially
lost business opportunities. Our ability to maintain productivity,

relationships with customers, competitive costs, and quality services is
limited by the ability to employ the necessary skilled personnel and
could negatively affect our results of operations, financial position and
cash flows.

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,
generation curtailment, 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 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. Also,
there is no assurance the applicable regulatory authority will judge all
our costs to have been prudently incurred or that rates will produce full
recovery of such costs. In addition, there could be changes in the
regulatory environment that would impair the ability of OTP to recover
costs historically collected from their customers. 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 authorities
concerning the level or method of determining electric utility rates, the
authorized returns on equity, recoverability of fuel and purchase power
costs, approval of depreciation rates, 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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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 the FERC
and the 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 and disaster recovery plans 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. The 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, 2019, all 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.
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.

OTP’s electric generating facilities are subject to operational risks that
could result in early closure, 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. 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. There can be no assurance suppliers will fulfill
their obligations to provide coal. Certain of our former coal suppliers have
filed bankruptcy proceedings in the past which did not materially affect
our operations. Our current suppliers could experience financial issues,
operational problems or other circumstances, such as severe weather
or natural disaster that inhibit their ability to fulfill their obligations.
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 or extreme
weather conditions that could impact the rail lines between the coal
source mines and the plants. If OTP were unable to obtain its coal
requirements under existing coal supply and transportation contracts it
could be required to purchase coal at higher prices or forced to purchase
electricity from higher-cost generation resources in the MISO energy
market. 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. In addition, regulatory
authorities could disallow recovery of the increased fuel or purchase
power costs.

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, as well as risk of performance
below expected levels of output or efficiency affecting OTP’s electric
generating facilities. We could be subject to costs associated with any
unexpected failure to produce or deliver power, including failure caused
by a breakdown or forced outage, as well as repairing damage to facilities.
Early closure of a generating facility due to operational or economic

factors, environmental regulation or risks or litigation could have a
material adverse impact on our results of operations. We would be
obligated to pay for costs of closure of our share of generation facilities.
If recovery of our remaining investment in such facilities and the costs
associated with early closure, including decommissioning, remediation,
reclamation and restoration are not recovered from customers, it could
have a material impact on our results of operations.

The loss of a major generating facility would require OTP to identify
and receive approval for other sources of generation for its customers,
if available, and expose it to higher purchased power costs. In addition,
OTP may not be able to obtain timely regulatory approval for new
generation resources to replace closed facilities.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

Regulation of generating plant emissions 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.
In recent years, federal, state and local governments have taken steps to
reduce emissions of greenhouse gases, or GHGs. The EPA has finalized
a series of GHG monitoring, reporting and emissions control rules for
certain large sources of GHGs, and Congress has, from time to time,
considered adopting legislation to reduce GHG emissions. Numerous
states have already taken measures to reduce GHG emissions, primarily
through the development of GHG emission inventories and/or regional
GHG cap-and-trade programs. While the current administration has
announced that the United States will withdraw from international
commitments to reduce GHG emissions, many state and local officials
have announced their decisions to uphold such commitments.

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.

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 RHR. 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 closed facilities, in addition to obtaining
necessary regulatory permits and approvals.

The final version of the ACE Rule, which went into effect on

September 6, 2019, establishes guidelines for states to use in developing
plans to address GHG emissions from existing coal-fired power plants.
The ACE Rule established heat rate improvements as the best system
of emissions reduction for CO2 from existing coal-fired generation
units. States will establish unit-specific standards of performance that
reflect the emission limitation achievable through certain candidate
heat-rate improvement technologies. States have until mid-2022 to
submit a state implementation plan to the EPA for approval. We cannot
predict the impact of the ACE Rule on us until the state plans are
adopted and any judicial reviews are completed, but it could be
material to the Company.

State implementation of pollution control plans to improve visibility
and air quality at national parks under the EPA’s RHR could require us to
incur significant new costs, which could, dependent on determinations
by state regulatory commissions on approval to recover such costs
from customers, negatively impact our net income, financial position
and cash flows. OTP understands that the NDDEQ intends to require
sources subject to RHR Round 2 reasonable progress determinations,
including Coyote Station, to undertake emissions control measures that
are reasonably consistent with those required of sources during Round
1. While this process is still in the early stages, if the NDDEQ maintains
its initial position, OTP anticipates that significant emissions controls
would be required at Coyote Station by December 31, 2028 in order to
maintain compliance with the RHR. Plans are due to be submitted to
the EPA by July 2021. OTP expects the NDDEQ to begin drafting a state
implementation plan in mid-2020. In light of the costs for such emissions
control equipment, there are scenarios where it may not be economically
feasible to invest in such equipment and an early retirement of the

Coyote Station would therefore be necessary. The costs related to an
early retirement of Coyote Station would be material to OTP and the
Company and would be subject to state commission approval for
recovery from customers.

The long-range planning required for transmission and generation
projects creates risks of increased costs and lower returns on
investment when the project is finally completed.
Electric transmission and generation projects are planned years in
advance of when they are placed in service based on resource plans
using assumptions over the planning period. These assumptions include
sales growth, commodity prices, equipment and construction costs,
regulatory treatment, technology and public policy. Changes in critical
planning assumptions could result in excess generation, transmission
and distribution resources which increase cost per customer. These
changes could also result in stranded investments if the utility is not
able to fully recover the cost of the investment.

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. Federal trade policies,
including imposed and proposed tariffs could significantly increase the
prices and delivery of raw materials such as steel and aluminum that
are critical to the manufacturing businesses. 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.

Economic conditions in the industries in which our customers operate
can have an adverse impact on our results of operations and cash flows.
Our manufacturing businesses derive a large amount of their net
sales from customers in the following industry sectors: recreational
vehicle/powersports, lawn and garden, construction, agriculture, energy,
horticultural and life science. Factors affecting any of these industries
in general, or any of our customers in particular, could adversely affect
us because our net sales growth largely depends on the continued
growth of our customers’ businesses in their respective industries.
These factors include:
(cid:1) seasonality of demand for our customers’ products which may cause
our manufacturing capacity to be underutilized for periods of time;

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

remediating contaminated sites, if any, is difficult to accurately predict
and could exceed estimates. In addition, as environmental, health and
safety laws and regulations have tended to become stricter, we could
incur additional costs complying with requirements that are
promulgated in the future.

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 2019 and 2018. 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.

(cid:1) our customers’ failure to successfully market their products, to gain
or retain widespread commercial acceptance of their products or to
compete effectively in their industries;

(cid:1) loss of market share for our customers’ products, which may lead

our customers to reduce or discontinue purchasing our products and
components and to reduce prices, thereby exerting pricing pressure
on us;

(cid:1) economic conditions in the markets in which our customers operate,
in particular, the United States, including recessionary periods such
as a global economic downturn;

(cid:1) our customers’ decision to insource the production of components

that has traditionally been outsourced to us; and

(cid:1) product design changes or manufacturing process changes that may

reduce or eliminate demand for the components we supply.

We expect future sales will continue to depend on the success of our

customers. If economic conditions or demand for our customers’
products deteriorate, we may experience a material adverse effect on
our business, operating results and financial condition.

Our business and operating results may be adversely affected if we
are not able to maintain our manufacturing, engineering and
technological expertise.
The markets for our manufacturing businesses are characterized by
changing technology and evolving process development. The continued
success of our businesses will depend on our ability to:
(cid:1) hire, retain and expand our pool of qualified engineering and

trade-skilled personnel;

(cid:1) maintain technological leadership in our industry;
(cid:1) implement new and expand on current robotics, automation and

tooling technologies; and

(cid:1) anticipate or respond to changes in manufacturing processes in a

cost-effective and timely manner.

We may not be able to develop the capabilities required by our
customers in the future. The emergence of new technologies, industry
standards or customer requirements may render our equipment,
inventory or processes obsolete or uncompetitive. We may have to
acquire new technologies and equipment to remain competitive. The
acquisition and implementation of new technologies and equipment
may require us to incur significant expense and capital investment,
which could reduce our margins and affect our operating results. When
we establish or acquire new facilities, we may not be able to maintain
or develop our manufacturing, engineering and technological expertise
due to a lack of trained personnel, effective training of new staff or
technical difficulties with machinery. Failure to anticipate and adapt to
customers’ changing technological needs and requirements, to hire and
retain a sufficient number of engineers, and to maintain manufacturing,
engineering and technological expertise may have a material adverse
effect on our businesses and operating results.

Our manufacturing, painting and coating operations are subject to
environmental, health and safety laws and regulations that could
result in liabilities to us.
Our manufacturing, painting and coating operations are subject to
environmental, health and safety laws and regulations, including those
governing discharges to air and water, the management and disposal
of hazardous substances, the cleanup of contaminated sites and health
and safety matters. We could incur material costs, including cleanup
costs, civil and criminal fines, penalties and third-party claims for cost
recovery, property damage or personal injury as a result of violations
of or liabilities under such laws and regulations. The ultimate cost of

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

[

I T E M 3 . L E G A L P R O C E E D I N G S

]

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.

[

I T E M 1 B . U N R E S O LV E D S TA F F C O M M E N T S

None.

[

I T E M 2 . P R O P E R T I E S

]

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, 2019, OTP’s transmission facilities, which are
interconnected with lines of other public utilities, consisted of 780 miles
of jointly owned 345 kV lines; 494 miles of 230 kV lines, of which
70 miles are jointly owned; 918 miles of 115 kV lines; and 4,011 miles of
lower voltage lines, principally 41.6 kV. OTP owns the uprated portion
of 48 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 miles of energized line in
the Fargo–Monticello 345 kV project, approximately 4.8% of 255 miles
of energized line in the Brookings to Southeast Twin Cities 345 kV project,
50.0% of 72 miles of energized line in the Big Stone South–Brookings
345 kV project, and 50.0% of 162 miles of energized line in the Big Stone
South–Ellendale 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 business.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

[

I T E M 3 A .

I N F O R M AT I O N A B O U T O U R E X E C U T I V E O F F I C E R S ( A S O F F E B R U A R Y 2 0 , 2 0 2 0 )

]

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 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

Charles S. MacFarlane (55)
Kevin G. Moug (60)
Timothy J. Rogelstad (53)
John Abbott (61)
Jennifer O. Smestad (49)

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

President and Chief Executive Officer
Chief Financial Officer and Senior Vice President
Senior Vice President, Electric Platform
Senior Vice President, Manufacturing Platform
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 served as Chief Financial Officer and Senior Vice

President of the Company since April 9, 2001.

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.

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 under the headings “Selected Financial Data,”
“Retained Earnings and Dividend Restriction” and “Supplementary
Financial Information” in this report on Form 10-K. 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, 2019.

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, 2014, and
reinvestment of all dividends).

OTC

EEI

NASDAQ

$250

$200

$150

$100

$50

[

I T E M 4 . M I N E S A F E T Y D I S C L O S U R E S

Not Applicable.

]

2014

2015

2016

2017

2018

2019

OTC
EEI
Nasdaq

$ 100.00
$ 100.00
$ 100.00

$ 89.95
$ 96.10
$ 100.48

$ 143.08
$ 112.85
$ 113.55

$ 160.75
$ 126.07
$ 137.83

$ 184.77
$ 130.70
$ 130.33

$ 196.19
$ 164.41
$ 170.96

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

[

I T E M 6 . S E L E C T E D F I N A N C I A L D ATA

]

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

2019

2018

2017

2016

2015

Revenues
Electric

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

$ 458,065
1,032

$ 450,694
(439)

$ 436,508
(1,971)

$ 425,279
2,104

$ 410,109
(2,978)

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)

459,097
277,204
183,257
(55)

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)

$ 919,503
$ 918,471
86,847
$
—

$ 916,447
$ 916,886
82,345
$
—

$ 849,350
$ 851,321
72,439
$
—

$ 803,539
$ 801,435
62,321
$
—

$ 779,804
$ 782,782
58,589
$
756

86,847

82,345

72,439

62,321

59,345

$ 185,037
185,037
207,365
2,273,595
689,581
2.19
2.19
2.17
2.17
11.6%
1.40

65%

40,158
12,361

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

65%

39,665
12,661

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

70%

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

78%

37,857
14,062

(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 2019, 2018 and 2017 was 68%, 66% and
68%, respectively, from our electric utility business and 32%, 34% and
32%, 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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

Major growth strategies and initiatives in our future include:

The following table summarizes our consolidated results of operations

(cid:1) Planned capital budget expenditures of approximately $984 million
for the years 2020 through 2024, of which $897 million is for capital
projects at Otter Tail Power Company (OTP), including:

• $260 million for renewable wind and solar energy generation and

conservation, including the Merricourt Wind Energy Center
(Merricourt) scheduled for completion in 2020, the exercise of a
purchase option to transfer the Ashtabula III wind farm to OTP in
2022, an investment in solar generation in 2023 and routine
wind-power replacement projects.

• $169 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.

• $134 million for routine distribution plant replacement projects.
• $117 million for transmission assets including new construction and

routine replacement projects.

• $99 million for the Astoria Station natural gas-fired generation

plant to replace Hoot Lake Plant capacity.

(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 2019:
(cid:1) Our Electric segment net income increased 8.5% to $59.0 million

from $54.4 million in 2018.

(cid:1) Our Manufacturing segment net income increased 0.5% to

$12.9 million from $12.8 million in 2018.

(cid:1) Our Plastics segment net income decreased 13.6% to $20.6 million

from $23.8 million in 2018.

(cid:1) Our net cash from operations was $185.0 million compared with

$143.4 million in 2018.

(cid:1) Capital expenditures at OTP totaled $187.4 million as work was

completed on the Big Stone South–Ellendale Multi-Value Transmission
Project (MVP) and OTP started construction on both Merricourt and
Astoria Station.

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

unsecured notes in a private placement. OTP used a portion of the
$100 million proceeds from the issuance to repay $69.9 million of
existing indebtedness under the OTP Credit Agreement, primarily
incurred to fund OTP capital expenditures, and will use the remainder
of the proceeds to pay for additional capital expenditures and for
other general purposes.

(cid:1) We paid out $55.7 million in common dividends in 2019.

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

2019

2018

$ 459,048
277,204
183,251

$ 450,198
268,409
197,840

$ 919,503

$ 916,447

59,046
12,899
20,572
(5,670)

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

86,847

82,345

Electric segment revenues increased $8.8 million (2.0%) due to an

$18.2 million (4.7%) increase in retail sales revenue, resulting mainly
from higher rates and increased rider revenues, partially offset by
decreases in transmission services and wholesale sales revenue.
Manufacturing segment revenues increased $8.8 million (3.3%). Revenues
at BTD Manufacturing, Inc. (BTD) increased $9.5 million, with increased
parts sales to customers in all of BTD’s end-market manufacturers except
energy. Plastics segment revenues decreased $14.6 million (7.4%) due
to decreased sales volume and lower pipe prices.

The $4.5 million increase in net income in 2019 compared with 2018

reflects the following:
(cid:1) A $4.6 million increase in Electric segment net income from increased
retail revenue due to increases in transmission rider revenues, general
and interim rate increases in North Dakota and South Dakota and a
reduction in power plant maintenance expenses.

(cid:1) A $0.1 million increase in Manufacturing segment net income with

increased sales volumes and revenues at BTD being mostly offset by
lower sales and reduced margins at T.O. Plastics.

(cid:1) A $3.2 million decrease in Plastics segment net income resulted from

reduced sales and lower margins.

(cid:1) Corporate net losses decreased $3.1 million mainly as a result of

higher investment income, increased tax savings and a reduction in
contributions to our charitable foundation after our initial $2.0 million
funding in 2018.

Following is a more detailed analysis of our operating results by
business segment for the years ended December 31, 2019 and 2018,
followed by a discussion of our financial position at the end of 2019
and our outlook for 2020.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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 included in this report on Form 10-K
for additional information on our lines of business, locations of
operations and principal products and services. For a comparison of
fiscal year 2018 against fiscal year 2017, see Part II, Item 7 “Management’s
Discussion and Analysis of Financial Condition and Results of Operations”
in our report on Form 10-K for the fiscal year ended December 31, 2018,
filed with the SEC on February 22, 2019 and incorporated by reference
into this report on Form 10-K.

Intersegment Eliminations—Amounts presented in the following
segment tables for 2019 and 2018 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)

2019

2018

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

Retail Sales Revenues from
Contracts with Customers
Changes in Accrued Revenues

under Alternative
Revenue Programs

Total Retail Sales Revenue
Transmission Services 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

2019

% change

2018

405,446

388,690

1,032

406,478
40,542

5,007
7,070

459,097
59,256
72,066

153,529
60,044
15,785

335

5
(14)

(35)
(3)

2
(11)
5

(1)
7
1

(439)

388,251
46,947

7,735
7,322

450,255
66,815
68,355

155,534
55,935
15,585

88,031

Operating Revenues:

Electric
Product Sales

Cost of Products Sold
Other Nonelectric Expenses

Operating Income

98,417

49
6
34
21

57
—
21
36

Electric kilowatt-hour (kwh)

Sales (in thousands)
Retail kwh Sales
Wholesale kwh Sales—
Company Generation

Heating Degree Days
Cooling Degree Days

4,969,089

—

4,976,960

198,569
7,240
392

(27)
5
(31)

271,841
6,904
567

Results of operations for the Electric segment are impacted by

fluctuations in weather conditions and the resulting demand for
electricity for heating and cooling. The following table shows heating
and cooling degree days as a percent of normal.

Heating Degree Days
Cooling Degree Days

2019

115.6%
85.0%

2018

111.0%
123.5%

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 2019 and 2018, and between years.

Effect on Diluted Earnings Per Share

$ 0.078

$ 0.005

$ 0.073

2019 vs
Normal

2019 vs
2018

2018 vs
Normal

2019 Compared with 2018
The $18.2 million increase in retail revenue includes:
(cid:1) A $10.4 million increase in transmission cost recovery revenues due

to recent investments in transmission infrastructure and transmission
costs not currently recovered in base rates.

(cid:1) A $2.4 million increase in Minnesota Renewable Resource Adjustment
(RRA) rider revenues due to increased cost recovery requirements
resulting from the expiration of federal production tax credits (PTCs)
in November 2018 on a company-owned wind farm.

(cid:1) A $2.3 million increase in retail revenue related to the recovery of fuel

and purchased power costs incurred to serve retail customers.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

Electric operating and maintenance expenses decreased $2.0 million

due to:
(cid:1) A $3.3 million decrease in external service costs at Big Stone Plant

primarily related to its fall 2018 maintenance outage.

(cid:1) A $1.1 million decrease in expenses for vegetation and transmission

line maintenance.

(cid:1) A $0.8 million decrease in software support costs and regulatory

filing fees.

(cid:1) A $0.7 million reduction in employee benefits mainly related to

decreased health insurance costs.

(cid:1) A $0.5 million decrease in expense related to an increase in overhead

cost capitalization due to increased capital spending in 2019.

(cid:1) A $0.4 million decrease in pollution control expenses resulting from
decreases in generation at both Coyote Station and Hoot Lake Plant
during their 2019 maintenance outages.

These items were partially offset by:
(cid:1) A $2.4 million increase in costs related to Coyote Station’s 2019

extended maintenance outage.

(cid:1) A $1.4 million increase in MISO transmission services expenses due

to an increase in third-party MVPs in 2019.

(cid:1) A $0.7 million increase in costs at Hoot Lake Plant due to 2019

turbine repairs.

(cid:1) A $0.3 million increase in conservation program expenditures in 2019.

Depreciation expense increased $4.1 million due to capital additions

including the Big Stone South–Ellendale 345kV transmission line
energized in February 2019, the new customer information system put
in service in 2019 and other recent transmission plant upgrades.

Property tax expense increased $0.2 million due to capital additions,

mainly transmission assets, in South Dakota and Minnesota.

(cid:1) A $1.9 million increase in retail revenue in South Dakota due to the
reversal of a tax refund provision in connection with OTP’s 2018
South Dakota rate case settlement agreement.

(cid:1) A $1.4 million increase in average electric prices mainly related to

interim and final rate increases in South Dakota.

(cid:1) A $0.9 million increase in revenue related to the establishment of a

generation cost recovery rider in North Dakota in 2019 to provide for
a return on funds invested in Astoria Station during its construction
phase.

(cid:1) A $0.3 million increase in revenue related to the recovery of increased

conservation improvement program expenditures in 2019.

(cid:1) A $0.3 million increase in revenue mainly driven by a 4.9% increase
in heating degree days in 2019 partially offset by a 30.9% decrease
in cooling degree days between the years.

These items were partially offset by:
(cid:1) A $1.8 million decrease in retail revenue due to a decrease in kwh

sales to residential customers.

Transmission services revenues decreased $6.4 million mainly due to

a $5.0 million decrease associated with reductions in capital spending
and collections through the Midcontinent Independent System Operator,
Inc. (MISO) tariff. OTP also recorded an additional $1.4 million estimated
refund obligation due to a November 21, 2019 FERC ruling related to the
methodology used to determine the Return on Equity (ROE) component
of the transmission rate under the MISO tariff. This is mainly based on a
reduced ROE from 10.82% to 10.38% for the period from September 28,
2016 through December 31, 2019. The reduced ROE is based on a newly
established 9.88% ROE plus the 50-point Regional Transmission
Organization adder granted by the FERC on January 5, 2015. The FERC
ruling is subject to rehearing requests.

Wholesale electric revenues decreased $2.7 million resulting from a
27.0% decrease in wholesale kwh sales due to fewer opportunities for
wholesale sales as Coyote Station was offline during the second quarter
of 2019 due to an extended maintenance outage and Hoot Lake Plant
Unit 2 was offline for maintenance and repairs in June and July 2019.
The decrease in revenues also resulted from decreased regional market
demand in the third quarter of 2019 due to cooler summer weather,
which also drove down wholesale electricity prices.

Production fuel costs decreased $7.6 million mainly as a result of a
16.4% decrease in kwhs generated from our fuel-burning plants due to
the maintenance outage at Coyote Station and due to maintenance
and repairs at Hoot Lake Plant as noted above. The decrease in fuel
costs related to the decrease in generation was partially offset by a
6.1% increase in the cost of fuel per kwh generated at OTP’s fuel-burning
plants. The increased cost-per-kwh generated is mostly due to the
absorption of Coyote Creek Mining Company’s fixed coal mining costs
on less delivered fuel to Coyote Station during its planned spring 2019
maintenance outage.

The cost of purchased power to serve retail customers increased
$3.7 million due to a 23.1% increase in kwhs purchased as a result of
purchasing replacement power during the maintenance outages at
Coyote Station and Hoot Lake Plant. The increase in kwh purchases
was partially offset by a 5.1% decrease in kwh purchases in the fourth
quarter of 2019 related to Big Stone Plant’s availability during the
fourth quarter of 2019 compared to the same period last year when the
plant was down for scheduled maintenance. The increased costs due to
the increase in kwhs purchased were partially mitigated by a 14.4%
decrease in the cost per kwh purchased resulting from lower wholesale
energy prices in 2019.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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

The $0.5 million decrease in depreciation in our Manufacturing
segment includes a decrease of $0.4 million at BTD as a result of
certain assets reaching the ends of their depreciable lives.

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

(in thousands)

2019

% change

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

183,257
139,974
11,393
3,451

(7)
(6)
(8)
(7)

2018

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

Operating Income

28,439

(14)

32,917

2019 Compared with 2018
Plastics segment revenues decreased $14.6 million due to a 4.2%
decrease in pounds of polyvinyl chloride (PVC) pipe sold and a 3.3%
decrease in PVC pipe prices. Wet weather conditions across our sales
territory negatively impacted 2019 sales along with lower demand in
the Midwest and West Coast states. Cost of products sold decreased
$8.9 million due to the decrease in sales volume and a 1.9% decrease in
the cost per pound of pipe sold. The decrease in pipe prices net of the
decrease in costs resulted in a 7.7% decrease in gross margin per pound
of PVC pipe sold. Plastics segment operating expenses decreased
$0.9 million mainly due to a decrease in incentive compensation
related to decreased operating income.

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)

2019

% change

Other Operating Expenses
Depreciation and Amortization

9,515
330

(1)
51

2018

9,607
218

Corporate operating expenses decreased $0.1 million in 2019 as

compared to 2018 due to the following:
(cid:1) There was no contribution made in 2019 to the Otter Tail Corporation

Foundation as compared to a $2.0 million contribution in 2018.
(cid:1) The decrease in charitable contributions was mostly offset by

increases in stock incentive and health benefit costs not allocated to
the operating business segments.

(in thousands)

2019

% change

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

Operating Income

277,204
215,179
29,895
14,261

17,869

3
5
1
(4)

(2)

2018

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

18,266

2019 Compared with 2018
The $8.8 million increase in revenues in our Manufacturing segment
includes the following:
(cid:1) At BTD, revenues increased $9.5 million due to growth in parts
revenue of $12.3 million from increased sales to customers in
recreational vehicle, construction, industrial, agricultural, and lawn and
garden end markets, partially offset by reduced sales in energy end
markets. Included in the parts revenue increase is the pass through
of higher material costs of $0.7 million, with the remaining increase
due to $11.6 million in higher sales volume. The increase in parts
revenue was partially offset by a $2.8 million (31.9%) decrease in
revenue from scrap metal sales due to a 28.2% decrease in scrap
metal prices.

(cid:1) At T.O. Plastics, revenues decreased $0.7 million due to a $0.7 million

reduction in extrusion and other industrial sales, a $0.6 million
decrease in sales to a customer bringing more production in house
and a $0.2 million reduction in sales of horticultural containers,
partially offset by a $0.5 million increase in life science product sales
and a $0.3 million increase in sales of scrap material.

The $9.5 million increase in cost of products sold in our Manufacturing

segment includes the following:
(cid:1) Cost of products sold at BTD increased $8.4 million, including

$11.8 million in increased material costs with $11.1 million due to the
increased sales volume and $0.7 million passed through to customers.
The increase in material costs combined with a $0.7 million increase in
overhead costs was partially offset by a $4.1 million increase in
reimbursements of tooling costs from customers.

(cid:1) Cost of products sold at T.O. Plastics increased $1.1 million mainly due
to increased labor costs driven by increased production hours and by
wage increases. T.O. Plastics’ gross margin percentage decreased
from 2018 to 2019 as a result of a customer’s decision to bring more
production in house.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

CONSOLIDATED INTEREST CHARGES

(in thousands)

Interest Charges

2019

% change

2018

31,411

30,408

The $1.0 million increase in interest charges in 2019 compared with

2018 is due to:
(cid:1) A $0.8 million increase in interest expense related to interest expense
on the $100 million in notes issued by OTP on October 10, 2019.
(cid:1) A $0.5 million increase in interest on short-term borrowings between
the years resulting from a $9.1 million increase in average short-term
debt outstanding between the years and a 50 basis points increase
in the average interest rate paid on short-term debt between periods,
mainly as a result of an increase in Otter Tail Corporation’s average
short-term borrowings relative to a decrease in OTP’s average
short-term borrowings. Otter Tail Corporation’s short-term borrowing
rates are higher than OTP’s short-term borrowing rates.

(cid:1) A $0.3 million increase in interest expense due to a full year of interest
compared with 11 months of interest on the $100 million in notes
issued by OTP in February 2018.

These increases in interest expense were partially offset by a

$0.5 million increase in capitalized interest expense at OTP due to an
increase in capital expenditures at OTP subject to interest capitalization.

CONSOLIDATED NONSERVICE COST COMPONENTS OF
POSTRETIREMENT BENEFITS

(in thousands)

2019

% change

2018

Nonservice Cost Components
of Postretirement Benefits

4,293

(22)

5,509

The $1.2 million decrease in nonservice cost components of
postretirement benefits in 2019 compared with 2018 is mostly due
to a decrease in pension plan nonservice costs, mainly actuarial loss
amortization expenses, partially offset by interest cost increases on all
postretirement benefit plans at Otter Tail Corporation and OTP.

CONSOLIDATED OTHER INCOME

(in thousands)

Other Income

2019

% change

2018

5,112

3,461

The $1.7 million increase in other income in 2019 compared with 2018

includes:
(cid:1) A $1.1 million increase in cash values of corporate-owned life

insurance policies.

(cid:1) A $0.4 million increase in allowance for equity funds used during
construction (AFUDC) on OTP construction work in progress.

CONSOLIDATED INCOME TAXES
Income tax expense increased $2.8 million to $17.4 million in 2019 from
$14.6 million in 2018, mainly due to the expiration of federal PTCs on
OTP’s wind farms.

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)

Income Before Income Taxes

Tax Computed at the Company’s Federal
Statutory Rate (21% for 2019 and 2018)

Increases (Decreases) in Tax from:

State Income Taxes Net of Federal

Income Tax Expense

Differences Reversing in Excess of Federal Rates
Permanent Differences, R&D Tax Credits,

For the Year Ended December 31,

2019

$ 104,288

21,901

2018

96,933

20,356

3,561
(3,357)

5,210
(3,432)

Unitary Tax and Other Adjustments

(1,315)

(1,864)

North Dakota Wind Tax Credit Amortization—

Net of Federal Taxes

Corporate-owned Life Insurance
Excess Tax Deduction—Equity

Method Stock Awards

Allowance for Funds Used During

Construction—Equity

Employee Stock Ownership Plan

Dividend Deduction

Investment Tax Credit Amortization
Federal PTCs

Total Income Tax Expense

Effective Income Tax Rate

(1,033)
(749)

(1,033)
(3)

(744)

(501)

(281)
(41)
—

(708)

(431)

(298)
(98)
(3,111)

17,441

14,588

16.7%

15.0%

Federal PTCs are recognized as wind energy is generated based on a
per kwh rate prescribed in applicable federal statutes. In November 2018,
the eligibility period for OTP to earn federal PTCs on its currently
energized wind farms ended. 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.

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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

LIQUIDITY

The following table presents the status of our lines of credit as of December 31, 2019 and December 31, 2018:

(in thousands)

Otter Tail Corporation Credit Agreement
OTP Credit Agreement

Total

Line Limit

170,000
170,000

340,000

In Use on
December 31, 2019

6,000
—

6,000

Restricted due
to Outstanding
Letters of Credit

—
15,476

$ 15,476

Available on
December 31, 2019

Available on
December 31, 2018

164,000
154,524

318,524

$ 120,785
160,316

$ 281,101

We believe we have the necessary liquidity to effectively conduct

Equity and debt financing will be required in the period 2020

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 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 Company began issuing common shares in the fourth quarter of
2019 to meet the requirements of the Plan rather than purchasing shares
in the open market. On November 8, 2019, we entered into a Distribution
Agreement with KeyBanc Capital Markets Inc. (“KeyBanc”) under which
we may offer and sell our common shares from time to time through
KeyBanc, as our distribution agent, up to an aggregate sales price of
$75 million through an At-the-Market offering program. In the fourth
quarter of 2019, we received proceeds of $17,458,621 net of $220,995
paid to KeyBanc from the issuance of 347,000 shares under this program.

CASH REALIZATION
($ millions)

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

2.1x
5
8
1
$

1.7x
3
4
1
$

2
8
$

7
8
$

$200

$150

$100

$50

$1,500

$1,000

$500

%
6
4

%
7
4

Cash flows from operations
Net Income

Total capital
Interest-bearing debt (includes short-term debt)

through 2024 given the expansion plans related to our Electric segment
to fund construction of new rate base investments. Also, such financing
will be required should we decide to reduce borrowings under our lines
of credit or refund or retire early any of our presently outstanding
debt, to complete acquisitions or for other corporate purposes. Our
operating cash flows and access to capital markets can be impacted by
macroeconomic factors outside our control. In addition, our borrowing
costs can be impacted by changing interest rates on short-term and
long-term debt and ratings assigned to us by independent rating
agencies, which in part are based on certain credit measures such as
interest coverage and leverage ratios.

The determination of the amount of future cash dividends to be
declared and paid will depend on, among other things, our financial
condition, improvement in earnings per share, cash flows from
operations, the level of our capital expenditures and our future business
prospects. As a result of certain statutory limitations or regulatory or
financing agreements, restrictions could occur on the amount of
distributions allowed to be made by our subsidiaries. See note 7 to
consolidated financial statements included in this report on Form 10-K
for additional information. The decision to declare a dividend is
reviewed quarterly by the board of directors. On February 4, 2020 our
board of directors increased the quarterly dividend from $0.35 to $0.37
per common share.

2019 Cash Flows Compared with 2018 Cash Flows
Net cash provided by operating activities was $185.0 million in 2019
compared with $143.4 million in 2018. Primary reasons for the $41.6 million
increase in net cash provided by operations between the periods were:
(cid:1) A $23.1 million decrease in cash used for working capital items
mainly due to significant changes in inventories, accounts payable and
accounts receivable between the periods.

• Inventory balances decreased by $8.4 million during 2019 compared

to an increase of $18.2 million in 2018. This change is due to
decreases in raw material costs, primarily steel, from 2018 to 2019
and lower sales volumes in the Plastics segment during 2019
compared to 2018.

• The level of increases in accounts receivable declined by $6.7 million

from 2018 to 2019, primarily due to higher raw material costs
reflected in customer billings in 2018 when compared with 2019.
Our average collection period on a consolidated basis remained
steady at approximately 31 days.

• The reductions in cash used for inventories and accounts receivable
between the years were partially offset by a $15.2 million reduction
in cash from an increase in accounts payable and other current
liabilities in 2018 compared with essentially no change in these
items in 2019. The primary reason for the increase in accounts
payable and other current liabilities in 2018 was due to the recording
of refunds for the TCJA and interim rate refunds in North Dakota
and South Dakota.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

(cid:1) An $11.2 million increase from changes in regulatory asset and liability
balances related to fuel cost and Minnesota environmental cost
recovery riders included in changes in deferred debits and other
assets and changes in noncurrent liabilities and deferred credits.

(cid:1) A $4.5 million increase in net income.
(cid:1) A $3.4 million increase in depreciation and amortization expense.
(cid:1) A $1.5 million increase in non-cash stock-based compensation

expense in 2019.

These items were partially offset by:
(cid:1) A $2.5 million increase in discretionary contributions to the

corporation’s funded pension plan in 2019.

Net cash used in investing activities was $209.5 million in 2019

compared with $107.4 million in 2018. The $102.1 million increase in cash
used for investing activities includes a $101.9 million increase in capital
expenditures, mainly due to a $100.1 million increase in cash used for
capital expenditures at OTP related to construction of Merricourt and
Astoria Station projects and various transmission projects and upgrades.
Cash used for capital expenditures at T.O. Plastics increased $1.4 million
between periods mainly related to the replacement of a warehouse
roof that collapsed during a snowstorm in March 2019.

Net cash provided by financing activities was $44.8 million in 2019

compared with $51.4 million in cash used for financing activities in
2018. The $96.2 million increase in cash flows from financing activities
includes an $81.2 million reduction in repayments of short-term debt
and $20.3 million in proceeds from the issuance of stock in 2019 as we
began issuing new common shares under our At-the-Market offering
program launched in November 2019 and also began issuing new
common shares to fulfill the requirements of our Automatic Dividend
Reinvestment and Share Purchase Plan in the fourth quarter of 2019 to
raise capital to fund OTP’s major construction projects.

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 $207.4 million

in 2019, $105.4 million in 2018 and $132.9 million in 2017. Estimated
capital expenditures for 2020 are $385 million. Total capital expenditures
for the five-year period 2020 through 2024 are estimated to be
approximately $984 million, including:
(cid:1) $260 million for renewable wind and solar energy generation and

conservation, including Merricourt scheduled for completion in 2020,
the exercise of a purchase option to transfer Ashtabula III wind farm
to OTP in 2022, an investment in solar generation in 2023 and
routine wind-power replacement projects.

(cid:1) $169 million for numerous potential technology and infrastructure

(cid:1) $134 million for routine distribution plant replacement projects.
(cid:1) $117 million for transmission assets including new construction and

routine replacement projects.

(cid:1) $99 million for the Astoria Station natural gas-fired generation plant

to replace Hoot Lake Plant capacity.

(cid:1) $87 million in our Manufacturing and Plastics segments mainly for

replacement of existing equipment.

The breakdown of 2017, 2018 and 2019 actual cash used for capital
expenditures and 2020 through 2024 estimated capital expenditures
by segment is as follows:

(in millions)

2017

2018 2019 2020 2021 2022 2023 2024 2020-2024

Electric
Manufacturing
Plastics
Corporate

$ 119 $ 87 $ 187 $369 $124 $162 $140 $101
13
4
—

15
4
—

14
4
—

14
6
—

14
4
—

12
4
—

10
4
—

13
4
1

$ 897
67
20
—

Total

$ 133 $ 105 $ 207 $385 $142 $180 $159 $118

$ 984

CONTRACTUAL OBLIGATIONS
The following table summarizes our contractual obligations at
December 31, 2019 and the effect these obligations are expected to
have on our liquidity and cash flow in future periods.

(in millions)

Debt Obligations
Coal Contracts
Interest on Debt Obligations
Other Purchase Obligations
(including land easements)

Capacity and Energy Requirements
Postretirement Benefit Obligations
Right-of-Use Asset Operating

Lease Obligations

Less
than

1-3
1 Year Years

More
3-5 than 5
Years Years

Total

$ 698 $
596
468

6 $ 170
46
58

23
33

$ — $ 522
479
329

48
48

327
205
115

270
25
5

49
25
11

1
23
13

7
132
86

Total Contractual Cash Obligations $ 2,435 $ 367 $ 368

$ 140 $1,560

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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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 2020 through 2024 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 November 8,
2019 the Company entered into a Distribution Agreement with KeyBanc
under which we may offer and sell our common shares from time to
time through KeyBanc, as our distribution agent, up to an aggregate
sales price of $75 million through an At-the-Market offering program.

DEBT
Following are brief descriptions of the short-term and long-term credit
and debt agreements currently in place at Otter Tail Corporation and
OTP. See note 10 to our consolidated financial statements included in
this report on Form 10-K for additional information on the terms,
provisions, restrictions and covenants under these agreements.

SHORT-TERM DEBT
On October 29, 2012 we entered into a Third Amended and Restated
Credit Agreement (the OTC Credit Agreement), which provided for an
unsecured $130 million revolving credit facility that could be increased
subject to certain terms and conditions. On October 31, 2019 the OTC
Credit Agreement was amended to extend its expiration date by one
year from October 31, 2023 to October 31, 2024, and to increase the
amount of the revolving credit facility to $170 million. The amendment
also provides that this facility can be increased to $290 million subject
to certain terms and conditions. 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.

On October 29, 2012 OTP entered into a Second Amended and

LONG-TERM DEBT
On September 12, 2019,OTP entered into a Note Purchase Agreement
(the 2019 Note Purchase Agreement) with the purchasers named
therein, pursuant to which OTP agreed to issue to the purchasers, in a
private placement transaction, $175 million aggregate principal amount
of OTP’s senior unsecured notes consisting of (a) $10,000,000
aggregate principal amount of its 3.07% Series 2019A Senior Unsecured
Notes due October 10, 2029 (the Series 2019A Notes), (b) $26,000,000
aggregate principal amount of its 3.52% Series 2019B Senior Unsecured
Notes due October 10, 2039 (the Series 2019B Notes), (c) $64,000,000
aggregate principal amount of its 3.82% Series 2019C Senior Unsecured
Notes due October 10, 2049 (the Series 2019C Notes), (d) $10,000,000
aggregate principal amount of its 3.22% Series 2020A Senior Unsecured
Notes due February 25, 2030 (the Series 2020A Notes), (e) $40,000,000
aggregate principal amount of its 3.22% Series 2020B Senior Unsecured
Notes due August 20, 2030 (the Series 2020B Notes), (f) $10,000,000
aggregate principal amount of its 3.62% Series 2020C Senior Unsecured
Notes due February 25, 2040 (the Series 2020C Notes) and
(g) $15,000,000 aggregate principal amount of its 3.92% Series 2020D
Senior Unsecured Notes due February 25, 2050 (the Series 2020D Notes).
On October 10, 2019 OTP issued the Series 2019A Notes, Series 2019B

Notes and Series 2019C Notes (the 2019 Notes) pursuant to the 2019
Note Purchase Agreement. OTP used a portion of the $100 million
proceeds from the issuance to repay $69.9 million of existing
indebtedness under the OTP Credit Agreement, primarily incurred to
fund OTP capital expenditures, and intends to use the remainder of the
proceeds to pay for additional capital expenditures and for OTP general
corporate purposes. The Series 2020A Notes, the Series 2020C Notes
and the Series 2020D Notes are expected to be issued on February 25,
2020 and the Series 2020B Notes are expected to be issued on August 20,
2020, subject to the satisfaction of certain customary conditions to
closing.

On February 27, 2018 OTP issued $100 million aggregate principal

amount of its 4.07% Series 2018A Senior Unsecured Notes due
February 7, 2048 (the 2018 Notes) pursuant to a Note Purchase
Agreement dated as of November 14, 2017 (the 2018 Note Purchase
Agreement). Proceeds from the 2018 Notes were used to repay
outstanding borrowings under the OTP Credit Agreement.

On December 13, 2016 Otter Tail Corporation issued $80 million
aggregate principal amount of its 3.55% Guaranteed Senior Notes due
December 15, 2026 (the 2026 Notes) pursuant to a Note Purchase
Agreement dated as of September 23, 2016 (the 2016 Note Purchase
Agreement). 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).

On February 27, 2014 OTP issued $60 million aggregate principal
amount of its 4.68% Series A Senior Unsecured Notes due February 27,
2029 and $90 million aggregate principal amount of its 5.47% Series B
Senior Unsecured Notes due February 27, 2044 pursuant to a Note
Purchase Agreement dated as of August 14, 2013 (the 2013 Note
Purchase Agreement).

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).

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

FINANCIAL COVENANTS
We were in compliance with the financial covenants in our debt
agreements as of December 31, 2019.

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, 2019,
our Interest and Dividend Coverage Ratio calculated under the
requirements of the OTC Credit Agreement and the 2016 Note
Purchase Agreement was 4.51 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, 2019, OTP’s Interest and Dividend Coverage Ratio and
Interest Charges Coverage Ratio, calculated under the requirements
of the 2007 Note Purchase Agreement and 2011 Note Purchase
Agreement, was 3.71 to 1.00.

(cid:1) Under the 2013 Note Purchase Agreement, the 2018 Note Purchase
Agreement, and the 2019 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, 2019, our ratio of Interest-bearing Debt to Total
Capitalization was 0.47 to 1.00 on a consolidated basis and 0.49 to 1.00
for OTP. Neither Otter Tail Corporation nor OTP had any Priority
Indebtedness outstanding as of December 31, 2019.

OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit
totaling $18.2 million, but our line of credit borrowing limits are only
restricted by $15.5 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.

2020 BUSINESS OUTLOOK

We anticipate 2020 diluted earnings per share to be in the range of $2.22
to $2.37. The midpoint of the 2020 earnings per share guidance reflects
a 6% growth rate off 2019 diluted earnings per share. Our 2020 diluted
earnings per share guidance also includes $0.05 of dilution associated
with the planned issuance of common equity under our At-the-Market
Offering Program and Dividend Reinvestment and Employee Stock
Purchase Plans to help fund our construction projects at OTP.

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 2020 to be $385 million compared with actual
cash used for capital expenditures of $207 million in 2019. Our Electric
Segment accounts for 96% of our 2020 planned capital expenditures.
The increase in our planned expenditures is largely driven by the
Merricourt Wind Energy Center and Astoria Station natural gas-fired
electric plant rate base projects.

Segment components of our 2020 diluted earnings per share
guidance range compared with 2019 actual earnings are as follows.

Electric
Manufacturing
Plastics
Corporate

Total

Return on Equity

2019 EPS
by Segment

$
$
$
$

1.48
0.32
0.51
(0.14)

2.17

11.6%

2020 EPS Guidance
High
Low

1.67
$
0.31
$
$
0.43
$ (0.19)

2.22

1.70
$
0.35
$
$
0.47
$ (0.15)

2.37

11.0%

11.7%

The following items contribute to our earnings guidance for 2020.
(cid:1) We expect our Electric segment to provide approximately 75% of
our consolidated earnings in 2020 with an increase over 2019
segment net income based on:
• Capital spending on the Merricourt and Astoria Station rate base
projects of $178 million and $81 million, respectively, in 2020. The
Merricourt project has rider recovery mechanisms in place in
Minnesota and South Dakota and in process for approval in North
Dakota. The Astoria Station project has rider recovery mechanisms
in place in South Dakota and North Dakota. This project earns AFUDC
in Minnesota, is expected to be recovered through a rate case in
Minnesota and has already been approved in our integrated
resource plan.

• Increased revenues related to $22 million in anticipated capital
spending for self-fund generator interconnection agreements.

• No planned generation plant outages for 2020. Plant outage costs

totaled $3.1 million in 2019.

partially offset by:

• Normal weather in 2020. Weather favorably impacted 2019 earnings

by $0.08 per share compared to normal.

• Increased expenses caused in large part by a decrease in the

discount rate used for the pension plan and a lower rate used for
our long-term rate of return. The discount rate for 2020 is 3.47%
compared with 4.50% for 2019. For each 25-basis point decline in the
discount rate, pension expense increases approximately $1,041,000.
The assumed long-term rate of return for 2020 is 6.88% compared
with 7.25% in 2019. Each 25-basis point decline in this rate equates
to approximately $734,000 in increased pension expense.

• Higher depreciation and property tax expense due to large capital

projects being put into service.

• Increased interest costs associated with a full year’s interest expense
on the $100 million of senior unsecured notes that were issued in
October 2019 and interest on the $35 million and $40 million of
senior unsecured notes expected to be issued in February and
August of 2020, respectively.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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

compared with 2019 based on:
• Slightly lower earnings at BTD due to an expected decline in sales
driven mostly by lower sales volumes in the recreational vehicle
markets. Scrap revenues are expected to decline slightly as well
based on lower sales volumes 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 horticulture, life science and industrial markets.

• Backlog for the manufacturing companies of approximately

$179 million for 2020 compared with $211 million one year ago.

Raw material price deflation is driving backlog down by $19 million
and the remaining $13 million decrease in backlog is volume driven.

(cid:1) We expect 2020 net income from our Plastics segment to be lower
than 2019 based on lower expected operating margins in 2020. This
is due to an expected decline in sale prices of pipe and flat year-
over-year resin prices, partially offset by slightly higher sales volumes
in 2020 compared to 2019.

(cid:1) Corporate costs, net of tax, are expected to be higher in 2020

compared with 2019 primarily driven by higher short-term borrowing
costs at the corporate level and higher income tax expense, partially
offset by lower employee benefit and health care costs.

The following table shows our 2019 capital expenditures and 2020 through 2024 anticipated capital expenditures and electric utility average rate base.

(in millions)

Capital Expenditures:
Electric Segment:

Renewables and Natural Gas Generation
Technology and Infrastructure
Distribution Plant Replacements
Transmission (includes replacements)
Other

Total Electric Segment

Manufacturing and Plastics Segments

Total Capital Expenditures

2019

2020

2021

2022

2023

2024

Total

260
7
22
61
19

369

385

18
18
27
26
35

124

142

51
47
34
8
23

163

180

30
54
25
13
18

140

159

—
43
26
9
23

101

118

359
169
134
117
118

897

984

187

207

Total Electric Utility Average Rate Base

$ 1,170

$ 1,418

$ 1,573

$ 1,634

$ 1,690

$ 1,739

Rate Base Growth

21.2%

10.9%

3.9%

3.4%

2.9%

The capital expenditure plan for the 2020-2024 time period calls for Electric segment capital expenditures of $897 million based on the need for
additional wind and solar in rate base, capital spending for Astoria Station (part of our replacement solution for Hoot Lake Plant when it is retired in
2021), technology-related investments and distribution and transmission investments. Given this capital expenditure plan, our compounded annual
growth rate in rate base is projected to be 8.2% over the 2019 to 2024 timeframe.

Execution on the currently anticipated Electric segment capital expenditure plan is expected to grow rate base and be a key driver in increasing

utility earnings over the 2020 through 2024 timeframe.

Our outlook for 2020 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 report on Form 10-K.

CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES

Our significant accounting policies are described in note 1 to our
consolidated financial statements included in this report on Form 10-K.
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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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.
See note 11 to our consolidated financial statements included in this
report on Form 10-K for additional information on our pension and
postretirement benefit plans and related assumptions.

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 2020 for our noncontributory funded
pension plan is expected to be $6.8 million compared to $3.4 million
in 2019, reflecting a decrease in the estimated discount rate used to
determine annual benefit cost accruals from 4.5% in 2019 to 3.47% in
2020. The assumed rate of return on pension plan assets is 6.88% for
2020 compared with 7.25% for 2019. In selecting the discount rate, we
consider the yields of fixed income debt securities, which have ratings
of “Aa” published by recognized rating agencies, along with bond
matching models specific to our plan’s cash flows as a basis to
determine the rate.

Subsequent increases or decreases in actual rates of return on plan

assets over assumed rates or increases or decreases in the discount
rate or rate of increase in future compensation levels could significantly
change projected costs. For 2019, all other factors being held constant:
a 0.25 increase in the discount rate would have decreased our 2019
pension benefit cost by $842,000; a 0.25 decrease in the discount rate
would have increased our 2019 pension benefit cost by $1,041,000; a
0.25 increase in the assumed rate of increase in future compensation
levels would have increased our 2019 pension benefit cost by
$563,000; a 0.25 decrease in the assumed rate of increase in future
compensation levels would have decreased our 2019 pension benefit
cost by $545,000; and a 0.25 increase (or decrease) in the expected
long-term rate of return on plan assets would have decreased (or
increased) our 2019 pension benefit cost by $734,000.

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 2019 postretirement medical benefit costs by
$191,000. A 0.25 decrease in the discount rate would have increased
our 2019 postretirement medical benefit costs by $358,000.
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, 2019 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 Generally Accepted Accounting Principles in the United States,
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. See
note 2 to our consolidated financial statements included in this report
on Form 10-K for additional information on our operating segments.
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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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,
2019 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 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 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 report on
Form 10-K and in our other SEC filings.

I T E M 7 A . Q U A N T I TAT I V E A N D Q U A L I TAT I V E
D I S C L O S U R E S A B O U T M A R K E T R I S K

At December 31, 2019 we had exposure to market risk associated

with interest rates because we had $6.0 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, 2019 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 PVC pipe 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 9 A N N UA L R E P O R T

[

I T E M 8 . F I N A N C I A L S TAT E M E N T S A N D S U P P L E M E N TA R Y D ATA

]

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, 2019 and 2018, 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, 2019, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,
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, 2019, 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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated
or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements
and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way
our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate
opinions on the critical audit matters or on the accounts or disclosures to which they relate.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

Rate and Regulatory Matters—Impact of Rate Regulation on the Financial Statements—Refer to Notes 1, 3 and 4 to the financial statements.

Critical Audit Matter Description

The Company’s regulated Electric segment accounts for the financial effects of regulation in accordance with ASC 980, Regulated Operations. 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. This standard also 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 Company is subject to rate regulation by federal and state utility regulatory agencies (collectively, the “Commissions”), which have jurisdiction
with respect to the rates of electric distribution companies in Minnesota, North Dakota and South Dakota. The Company has stated that all regulatory
assets and regulatory liabilities are recoverable or refundable through the regulatory process.

Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and
equipment, regulatory assets and liabilities, operating revenues and expenses, depreciation expense, income taxes and multiple disclosures in the
notes to the financial statements. There is a risk that the Commissions will not approve full recovery of the costs of providing utility service or full
recovery of all amounts invested in the utility business and a reasonable return on that investment. As a result, we identified the impact of rate
regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account
balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements.
Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of capital expenditures
or operating costs that management believes were prudently incurred, and (3) a refund to customers. Given that management’s accounting
judgements are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized
knowledge of accounting for rate regulation and the rate setting process due its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

(cid:1) We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as
property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as
regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and
equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of
recovering costs in future rates or of a future reduction in rates.

(cid:1) We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
(cid:1) We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural memorandums,
filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in
rates based on precedence of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information
and compared to management’s recorded regulatory asset and liability balances for completeness.

(cid:1) We inquired of management about property, plant, and equipment that may be abandoned. We inspected the capital-projects budget and

construction-in-process listings and inquired of management to identify projects that are designed to replace assets that may be retired prior to
the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify
any evidence that may contradict management’s assertion regarding probability of an abandonment.

(cid:1) We compared actual spend for projects that have been capitalized to property, plant, and equipment to budget. We evaluated regulatory filings

for any evidence that intervenors are challenging full recovery of the cost of any capital projects.

(cid:1) We obtained an analysis from management and letters from internal and external legal counsel, as appropriate, regarding probability of recovery
for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s
assertion that amounts are probable of recovery or a future reduction in rates.

Goodwill—Manufacturing Reporting Unit—Refer to Note 1 to the financial statements

Critical Audit Matter Description

The Company’s evaluation of goodwill for impairment involves the comparison of the fair value of each reporting unit to its carrying value. The
Company performs qualitative and quantitative assessments of goodwill annually as of December 31 (the “measurement date”) and more often
when events indicate the assets may be impaired. The Company determines the fair value of its Manufacturing reporting unit by primarily using the
discounted cash flow model. The determination of the fair value using the discounted cash flow model requires management to make significant
estimates and assumptions related to forecasts of future revenues and profit margins. The Manufacturing reporting unit’s revenues and profit margins
are sensitive to changes in demand. The goodwill balance was $37.6 million as of December 31, 2019, of which $18.3 million was allocated to the
Manufacturing reporting unit. The fair value of the Manufacturing reporting unit exceeded its carrying value as of the measurement date and,
therefore, no impairment was recognized.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

We identified goodwill for the Manufacturing reporting unit as a critical audit matter because of the significant judgments made by management to
estimate its fair value and the difference between its fair value and carrying value and the sensitivity of the Manufacturing reporting unit’s operations
to changes in demand. This required a high degree of auditor judgment and an increased extent of effort when performing audit procedures to
evaluate the reasonableness of management’s estimates and assumptions related to forecasts of future revenue and profit margin.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to forecasts of future revenue and profit margin used by management to estimate the fair value of the Manufacturing
reporting unit included the following, among others:

(cid:1) We tested the effectiveness of controls over management’s goodwill impairment evaluation, including those over the determination of the fair

value of the Manufacturing reporting unit, such as controls related to forecasts of future revenue and profit margin.

(cid:1) We evaluated management’s ability to accurately forecast future revenues and profit margins by comparing actual results to management’s

historical forecasts.

(cid:1) We evaluated the reasonableness of management’s revenue and profit margin forecasts by comparing the forecasts to:

• Historical revenues and profit margins.
• Internal communications to management and the Board of Directors.
• Forecasted information included in Company press releases as well as in analyst and industry reports for the Company and certain of its

peer companies.

Minneapolis, Minnesota
February 20, 2020

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 9 A N N UA L R E P O R T

CONSOLIDATED BALANCE SHEETS, DECEMBER 31

(in thousands)

Assets

Current Assets

Cash and Cash Equivalents
Accounts Receivable:

Trade (less allowance for doubtful accounts of $1,339 for 2019 and $1,407 for 2018)
Other
Inventories
Unbilled Receivables
Income Taxes Receivable
Regulatory Assets
Other

Total Current Assets

Investments
Other Assets
Goodwill
Other Intangibles–Net
Regulatory Assets

Right of Use Asset—Operating Leases

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.

2019

2018

21,199

861

77,947
8,773
97,851
20,911
1,487
21,650
5,042

254,860

9,894
40,196
37,572
11,290
144,138

21,851

2,212,884
247,356
185,238

2,645,478
891,684

1,753,794

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

$ 2,273,595

$2,052,517

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

CONSOLIDATED BALANCE SHEETS, DECEMBER 31

(in thousands, except share data)

Liabilities and Equity

Current Liabilities
Short-Term Debt
Current Maturities of Long-Term Debt
Accounts Payable
Accrued Salaries and Wages
Accrued Taxes
Regulatory Liabilities
Current Operating Lease Liabilities
Other Accrued Liabilities

Total Current Liabilities

Pensions Benefit Liability
Other Postretirement Benefits Liability
Long-Term Operating Lease Liabilities
Other Noncurrent Liabilities

Commitments and Contingencies (note 9)

Deferred Credits

Deferred Income Taxes
Deferred Tax Credits
Regulatory Liabilities
Other

Total Deferred Credits

Capitalization (page 58)
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, 2019—40,157,591 Shares; 2018—39,664,884 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.

2019

2018

6,000
183
120,775
22,730
17,525
7,480
4,136
10,912

189,741

98,970
71,437
18,193
30,833

131,941
18,626
239,906
2,885

393,358

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

689,581

590,002

—

200,788
364,790
222,341
(6,437)

781,482

—

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

728,863

1,471,063

1,318,865

$ 2,273,595

$ 2,052,517

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

CONSOLIDATED STATEMENTS OF INCOME—FOR THE YEARS ENDED DECEMBER 31

(in thousands, except per-share amounts)

2019

2018

2017

Operating Revenues

Electric

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

458,016
1,032

459,048
460,455

919,503

59,256
72,066
153,529
355,119
50,782
78,086
15,785

784,623

134,880

31,411
4,293
5,112

104,288
17,441

86,847

39,721
39,954

2.19
2.17

$
$

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

129,389

132,287

30,408
5,509
3,461

96,933
14,588

82,345

39,600
39,892

2.08
2.06

29,604
5,620
2,632

99,695
27,256

72,439

39,457
39,748

1.84
1.82

$
$

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

Operating Income

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

See accompanying notes to consolidated financial statements.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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

(in thousands)

Net Income

2019

2018

2017

86,847

82,345

72,439

Other Comprehensive Income (Loss):

Unrealized Gain (Loss) on Available-for-Sale Securities:

Reversal of Previously Recognized Losses (Gains) Realized on

Sale of Investments and Included in Other Income During Period

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

Change in Unrealized Gain (Loss) on Available-for-Sale Securities—net-of-tax

Pension and Postretirement Benefit Plans:

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

Pension and Postretirement Benefit Plans—net-of-tax

Total Other Comprehensive (Loss) Income

Total Comprehensive Income

See accompanying notes to consolidated financial statements.

16
147
(34)

129

(2,779)
565
576
—

(1,638)

(1,509)

(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)

85,338

83,832

70,608

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY

(in thousands, except common shares outstanding)

Common
Shares
Outstanding

Par Value,
Common
Shares

Premium on
Common
Shares

Accumulated
0ther

Retained Comprehensive
Income/(Loss)
Earnings

Total
Common
Equity

Balance, December 31, 2016

39,348,136

$ 196,741

$337,684

$139,479

$ (3,800)(a) $670,104

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)

Balance, December 31, 2018

Common Stock Issuances, Net of Expenses
Common Stock Retirements and Forfeitures
Net Income
Other Comprehensive Income
ASU 2018-02 2017 TCJA Stranded Tax Transfer
Employee Stock Incentive Plan Expense
Common Dividends ($1.40 per share)

257,059
(47,704)

1,285
(239)

3,684
(1,560)

3,642

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

$ 197,787
893
(356)

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

4,441

39,664,884
547,931
(55,224)

$ 198,324
2,740
(276)

$344,250
17,036
(2,454)

5,958

(1,831)

4,969
(1,799)
72,439
(1,831)
3,642
(50,632)

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

1,487

$ (4,144)(a) $728,863
19,776
(2,730)
86,847
(1,509)
—
5,958
(55,723)

(1,509)
(784)

72,439

(50,632)

$161,286

82,345

(53,198)

$190,433

86,847

784

(55,723)

Balance, December 31, 2019

40,157,591

$ 200,788

$364,790

$222,341

$ (6,437)(a) $781,482

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

(in thousands)

Unrealized Gain (Loss) on Marketable Equity Securities:

Before Tax

Tax Effect
Stranded Tax Effect

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

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

Before Tax

Tax Effect
Stranded Tax Effect

2019

2018

2017

(14)
—

(95)

20
(10)

(85)

(15)
(10)

(8,772)

(6,558)

(9,462)

2,281
—

1,705
794

2,991
794

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

(6,491)

(4,059)

(5,677)

Accumulated Other Comprehensive Loss:

Before Tax

Tax Effect
Stranded Tax Effect

Net Accumulated Other Comprehensive Loss

See accompanying notes to consolidated financial statements.

(8,704)

(6,653)

(9,391)

2,267
—

1,725
784

2,976
784

(6,437)

(4,144)

(5,631)

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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

(in thousands)

2019

2018

2017

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

Net Cash Provided by Operating Activities

Cash Flows from Investing Activities

Capital Expenditures
Proceeds from Disposal of Noncurrent Assets
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

Net Cash Provided by (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.

86,847

82,345

72,439

78,086
(1,348)
11,507
(15,502)
(22,500)
33,534
(2,553)
5,958
76

(1,860)
8,419
2,919
(171)
1,625

185,037

(207,365)
8,519
(10,626)

(209,472)

(2,814)
(12,599)
20,338
(577)
(2,730)
100,000
(950)
(172)
(55,723)

44,773

20,338
861

21,199

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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

CONSOLIDATED STATEMENTS OF CAPITALIZATION, DECEMBER 31

(in thousands, except share data)

2019

2018

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
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%, Series 2011A, due December 1, 2021
Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022
Senior Unsecured Notes 6.37%, Series 2007C, due August 20, 2027
Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029
Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 2029 (1)
Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037
Senior Unsecured Notes 3.52%, Series 2019B, due October 10, 2039
Senior Unsecured Notes 5.47%, Series 2013B, due February 27, 2044
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048
Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049

Total—Otter Tail Power Company
Less: 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

6,000
—

6,000

80,000
351

80,351
183
356

79,812

140,000
30,000
42,000
60,000
10,000
50,000
26,000
90,000
100,000
64,000

612,000
2,231

609,769

692,351
183
2,587

689,581

—

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

—

Total Common Shareholders’ Equity

Total Capitalization

781,482

728,863

$ 1,471,063

$ 1,318,865

(1) Holder is COBANK, a cooperative lender. Interest payments are subject to cash credits which may result in a lower effective interest rate.

See accompanying notes to consolidated financial statements.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017

1. Summary of Significant Accounting Policies

Principles of Consolidation
The consolidated financial statements of Otter Tail Corporation and its
wholly owned subsidiaries (the Company) include the accounts of the
following segments: Electric, Manufacturing and Plastics. See note 2
to consolidated financial statements for further descriptions of the
Company’s business segments. All intercompany balances and
transactions have been eliminated in consolidation except profits on
sales to the regulated electric utility company from nonregulated
affiliates, which is in accordance with the requirements of Financial
Accounting Standards Board (FASB) Accounting Standards Codification
(ASC) Topic 980, Regulated Operations (ASC 980).

Regulation and ASC 980
The Company’s regulated electric utility company, Otter Tail Power
Company (OTP), accounts for the financial effects of regulation in
accordance with ASC 980. This standard allows for the recording of a
regulatory asset or liability for costs and revenues that will be collected
or refunded through the ratemaking process in the future. In accordance
with regulatory treatment, OTP defers utility debt redemption premiums
and amortizes such costs over the original life of the reacquired bonds.
See note 4 to consolidated financial statements for further discussion.
OTP is subject to various state and federal agency regulations. The
accounting policies followed by this business are subject to the Uniform
System of Accounts of the Federal Energy Regulatory Commission
(FERC). These accounting policies differ in some respects from those
used by the Company’s nonelectric businesses.

Plant, Retirements and Depreciation
Utility plant is stated at original cost. The cost of additions includes
contracted work, direct labor and materials, allocable overheads and
allowance for funds used during construction. The amount of interest
capitalized on electric utility plant was $1,728,000 in 2019, $1,206,000

in 2018 and $741,000 in 2017. 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 2.81% in 2019, 2.76% in 2018 and 2.74% in 2017. 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 2019, 2018 or 2017.
Maintenance and repairs are expensed as incurred. Gains or losses on
asset dispositions are included in the determination of operating income.

Recoverability of Long-Lived Assets
The Company reviews its long-lived assets whenever events or changes
in circumstances indicate the carrying amount of the assets may not be
recoverable. The Company determines potential impairment by comparing
the carrying amount of the assets with net cash flows expected to be
provided by operating activities of the business or related assets. If the
sum of the expected future net cash flows is less than the carrying amount
of the assets, the Company would recognize an impairment loss. Such an
impairment loss would be measured as the amount by which the carrying
amount exceeds the fair value of the asset, where fair value is based on
the discounted cash flows expected to be generated by the asset.

Jointly Owned Facilities
OTP is a joint owner in two coal-fired steam-powered electric generation plants: Big Stone Plant near Big Stone City, South Dakota and Coyote Station
near Beulah, North Dakota. OTP is also a joint owner, with other regional utilities, in five major transmission lines. The following table provides OTP’s
ownership percentages and amounts included in the Company’s December 31, 2019 and 2018 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, 2019

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

December 31, 2018

OTP
Ownership
Percentage

Electric Plant
in Service

Construction
Work in
Progress

Accumulated
Depreciation

Net Plant

53.9%
35.0%
50.0%
14.2%
50.0%
4.8%
14.8%

$ 337,197
184,493
106,343
78,184
53,036
26,286
16,331

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

384
83
—
—
—
—
—

361
2,588
106,490
—
(150)
—
—

$ (98,654)
(108,248)
(819)
(7,011)
(2,016)
(2,086)
(233)

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

$ 238,927
76,328
105,524
71,173
51,020
24,200
16,098

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

(1) Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO

Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff).

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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 required to buy certain assets of CCMC 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
because the Coyote Station owners are required to buy the membership
interests of CCMC 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, the owners will satisfy (or if permitted by CCMC’s applicable
lenders 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
prior to the end of the term due to certain events, OTP’s maximum
exposure to additional costs, as a result of its involvement with CCMC,
and potential impairment loss if recovery of those costs is denied by
regulatory authorities, could be as high as $50.4 million, OTP’s 35%
share of CCMC’s unrecovered costs as of December 31, 2019.

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.

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.

Revenue Recognition
In May 2014 the FASB issued a major update to the ASC, Accounting
Standards Update (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. 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

transmission service providers, under rate tariffs established by the
independent transmission system operator and approved by the FERC.
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), Energy
Intensive Trade Exposed and Conservation Improvement Program
riders.

(cid:1) In North Dakota: TCR, ECR, RRA and Generation Cost Recovery

(GCR) riders.

(cid:1) In South Dakota: TCR, ECR, Phase-in Rate Plan 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 changes in accrued
revenues under ARPs on a separate line in the revenue section of the
Company’s consolidated statement of income. See table in note 3 to
consolidated financial statements for total revenues billed and accrued
under ARP riders for the years ended December 31, 2019, 2018 and 2017.

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. 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. For revenue recognized on shipped products, there is
no further obligation to provide services related to such products. 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 to consolidated financial

statements for a disaggregation of the Company’s revenues by business
segment for the years ended December 31, 2019, 2018 and 2017.

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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

Investments
The following table provides a breakdown of the Company’s investments
at December 31:

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, 2019 and December 31, 2018:

2019

2018

December 31, 2019 (in thousands)

Level 1

Level 2

Level 3

(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

24
73
27

8,184

1,586

9,894

34
123
26

7,484

1,294

8,961

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, 2019. See further discussion below.

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

Assets:

Investments:

Equity Funds—Held by Captive

Insurance Company

Corporate Debt Securities—Held by

Captive Insurance Company

Government-Backed and
Government-Sponsored
Enterprises’ Debt Securities—Held by

Captive Insurance Company

Other Assets:

Money Market and Mutual Funds—

$ 1,586

$ 2,124

6,060

Retirement Plans

Total Assets

2,363

$ 3,949

$ 8,184

December 31, 2018 (in thousands)

Level 1

Level 2

Level 3

Assets:

Investments:

Equity Funds—Held by Captive

(in thousands)

Finished Goods
Work in Process
Raw Material, Fuel and Supplies

Total Inventories

December 31, December 31,

Insurance Company

$ 1,294

2019

31,863
16,508
49,480

2018

37,130
20,393
48,747

Corporate Debt Securities—Held by

Captive Insurance Company

Government-Backed and
Government-Sponsored
Enterprises’ Debt Securities—Held by

$ 5,898

97,851

$ 106,270

Captive Insurance Company

1,586

Other Assets:

Money Market and Mutual Funds—

Nonqualified Retirement Savings Plan

838

Total Assets

$ 2,132

$ 7,484

The level 2 fair values for Government-Backed and Government-
Sponsored Enterprises’ and Corporate Debt Securities Held by the
Company’s Captive Insurance Company 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.

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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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 2019 and 2018:

(in thousands)

Manufacturing
Plastics

Total

(in thousands)

Manufacturing
Plastics

Total

Gross Balance
December 31,
2018

18,270
19,302

37,572

Gross Balance
December 31,
2017

18,270
19,302

37,572

Balance
(net of impairments)
December 31,
2018

Accumulated
Impairments

Balance
Adjustments (net of impairments)
December 31,
2019

to Goodwill in
2019

—
—

—

18,270
19,302

37,572

—
—

—

18,270
19,302

37,572

Balance
(net of impairments)
December 31,
2017

Accumulated
Impairments

Balance
Adjustments (net of impairments)
December 31,
2018

to Goodwill in
2018

—
—

—

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, 2019 and December 31, 2018:

Gross Carrying
Amount

Accumulated
Amortization

Net Carrying
Amount

Remaining Amortization
Periods (months)

December 31, 2019 (in thousands)

Amortizable Intangible Assets:

Customer Relationships
Other

Total

December 31, 2018 (in thousands)

Amortizable Intangible Assets:

Customer Relationships
Other

Total

22,491
179

22,670

22,491
154

22,645

11,259
121

11,380

10,127
68

10,195

11,232
58

11,290

12,364
86

12,450

88-188
8-45

12-200
20

As of December 31,

2019

2018

The amortization expense for these intangible assets was:

Supplemental Disclosures of Cash Flow Information

(in thousands)

2019

2018

2017

(in thousands)

Amortization Expense—Intangible Assets

$ 1,186

$ 1,315

$ 1,347

Noncash Investing Activities:

The estimated annual amortization expense for these intangible

assets for the next five years is:

Transactions Related to Capital
Additions not Settled in Cash

37,429

13,757

(in thousands)

2020

2021

2022

2023

2024

Estimated Amortization Expense—

Intangible Assets

$ 1,140 $ 1,105 $ 1,105 $ 1,104 $ 1,099

Cash Paid During the Year for:

Interest (net of amount capitalized)
Income Taxes

$ 30,132
$ 4,797

$ 28,109
$ 6,109

$ 29,791
$ 5,064

(in thousands)

2019

2018

2017

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

New Accounting Standards Adopted
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 supersedes the
requirements under ASC Topic 840 on leases and requires the
recognition of lease assets and lease liabilities on the balance sheet
and the disclosure of key information about leasing arrangements. The
amendments in ASU 2016-02 are effective for fiscal years beginning
after December 15, 2018, including interim periods within those fiscal
years. 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. The Company
adopted the amendments in ASU 2016-02 to its consolidated financial
statements effective January 1, 2019. See note 8 to consolidated financial
statements for further information on leases and the Company’s
elections for applying the new standard.

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.

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 early adopted the
amendments in ASU 2017-04 in the first quarter of 2019. The Company
had no indication that any of its goodwill was impaired, and therefore,
the adoption of the updated standard had no impact on the Company’s
consolidated financial statements.

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/loss (AOCI/(L)) to retained earnings for stranded tax effects resulting from
the 2017 Tax Cuts and Jobs Act (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 adopted the updates in ASU 2018-02 effective January 1, 2019, applying them in the period of adoption and not retrospectively.
On adoption, the Company reclassified $784,000 of income tax effects of the TCJA on the gross deferred tax amounts reflected in AOCI/(L) at the
date of enactment of the TCJA and AOCI/(L) to retained earnings so the remaining gross deferred tax amounts related to items in AOCI/(L) will
reflect current effective tax rates.

Support for the determination of the stranded tax effects resulting from the enactment of the TCJA in AOCI/(L) is provided in the table below.

(in thousands)

Unrealized Gains on
Available-for-Sale
Securities

Unamortized Actuarial Losses and
Prior Service Costs on Pension
and Other Postretirement Benefits

Balance on December 22, 2017—Pre-tax
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts

$
$

71
10

$
$

(5,672)
(794)

AOCI/(L)

$ (5,601)
(784)
$

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

New Accounting Standards Pending Adoption
ASU 2016-13—In June 2016 the FASB issued ASU No. 2016-13, Financial
Instruments—Credit Losses (Topic 326) (ASC 326), which changes how
entities account for credit losses on receivables and certain other assets.
The guidance requires use of a current expected credit loss model, which
may result in earlier recognition of credit losses than under previous
accounting standards. ASC 326 is effective for interim and annual
periods beginning on or after December 15, 2019. The Company has
reviewed its outstanding investments and receivables that will be
subject to evaluation for credit losses under the new standard and
determined that application of the new expected loss model will not
have a material impact on its current calculation of credit losses and
allowance for doubtful accounts balance. The Company will apply
ASC 326 to its consolidated financial statements in the first quarter
of 2020. Adoption of the new standard will not have a material impact
on the Company’s consolidated financial statements and the Company
will not record a cumulative effect adjustment to retained earnings
on adoption.

ASU 2018-15—In August 2018 the FASB issued ASU No. 2018-15,
Intangibles—Goodwill and Other—Internal-Use Software
(Subtopic 350-40), which amends ASC 350-40, Internal-Use Software,
to address a customer’s accounting for implementation costs incurred
in a cloud computing arrangement that is a service contract. The
amendments in ASU 2018-15 align the requirements for capitalizing
implementation costs incurred in a hosting arrangement that is a
service contract with the requirements for capitalizing implementation
costs incurred to develop or obtain internal-use software (and hosting
arrangements that include an internal-use software license). Accordingly,
the amendments in ASU 2018-15 require an entity (customer) in a
hosting arrangement that is a service contract to follow the guidance in
ASC 350-40 to determine which implementation costs to capitalize as
an asset related to the service contract and which costs to expense.
The amendments in ASU 2018-15 also require the entity to present the
expense related to the capitalized implementation costs in the same
line item in the statement of income as the fees associated with the
hosting element (service) of the arrangement and classify payments
for capitalized implementation costs in the statement of cash flows in
the same manner as payments made for fees associated with the
hosting element. The entity is also required to present the capitalized
implementation costs in the statement of financial position in the same
line item that a prepayment for the fees of the associated hosting
arrangement would be presented. The amendments in ASU 2018-15
are effective for interim and annual periods beginning on or after
December 15, 2019 with early adoption permitted in any interim period.
The Company will adopt the amendments in ASU 2018-15 in the first
quarter of 2020 and expects there will be no impact to its consolidated
financial statements on adoption but does expect to begin capitalizing
implementation costs incurred in cloud computing arrangements
post-adoption.

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 operating 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 2019, 2018 and 2017. While no single customer
accounted for over 10% of consolidated revenue in 2019, certain
customers provided a significant portion of each business segment’s
2019 revenue. The Electric segment has one customer that provided
11.9% of 2019 segment revenues. The Manufacturing segment has
one customer that manufactures and sells recreational vehicles that
provided 23.8% of 2019 segment revenues and one customer that
manufactures and sells lawn and garden equipment that provided
11.1% of 2019 segment revenues. The Manufacturing segment’s top five
revenue-generating customers provided over 54% of 2019 segment
revenues. The Plastics segment has two customers that individually
provided 25.3% and 20.4% of 2019 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 98.8% of sales in 2019,
98.4% of sales in 2018 and 98.2% of sales in 2017.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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 2019, 2018 and 2017 is presented in the following table:

(in thousands)

Operating Revenue
Electric Segment:

Retail Sales Revenue from
Contracts with Customers

Changes in Accrued ARP Revenues

Total Retail Sales Revenue

Transmission Services Revenue
Wholesale Revenues—
Company Generation
Other Electric Revenues

Manufacturing Segment:
Metal Parts and Tooling
Plastic Products and Tooling
Other

Total Manufacturing Segment Revenues

Plastics Segment—Sale of

PVC Pipe Products

Intersegment Eliminations

2019

2018

2017

(in thousands)

2019

2018

2017

$ 405,446 $ 388,690 $ 376,902
(1,971)

(439)

1,032

Interest Charges

Electric
Manufacturing
Plastics
Corporate and Intersegment Eliminations

26,548 $
2,345
718
1,800

26,365 $
2,230
609
1,204

25,334
2,215
633
1,422

406,478
40,542

388,251
46,947

374,931
46,664

Total

Income Tax Expense (Benefit)

5,007
7,070

7,735
7,322

5,173
7,769

236,032
35,173
5,999

277,204

223,765
35,836
8,808

268,409

189,242
33,939
6,557

229,738

Electric
Manufacturing
Plastics
Corporate

Total

Net Income (Loss)

Electric
Manufacturing
Plastics
Corporate

31,411 $

30,408 $

29,604

12,867 $
2,784
7,309
(5,519)

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

17,013
989
7,448
1,806

17,441 $

14,588 $

27,256

59,046 $
12,899
20,572
(5,670)

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

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

183,257

197,840

185,132

Total

86,847 $

82,345 $

72,439

(55)

(57)

Capital Expenditures

Total Electric Segment Revenues

459,097

450,255

434,537

Total

$ 919,503 $ 916,447 $ 849,350

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

$ 215,179 $ 205,699 $ 176,473
140,107
(18)

139,974
(34)

148,881
(21)

Electric
Manufacturing
Plastics
Corporate

Total

$ 187,362 $
14,268
5,452
283

87,287 $ 118,444
9,916
13,316
4,432
4,199
121
623

$ 207,365 $ 105,425 $ 132,913

$1,931,525 $1,728,534 $1,690,224
167,023
87,230
59,801

187,556
91,630
44,797

195,742
92,049
54,279

$2,273,595 $2,052,517 $2,004,278

$ 355,119 $ 354,559 $ 316,562

Identifiable Assets

Electric
Manufacturing
Plastics
Corporate

Total

29,895 $
11,393
9,515
(21)

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

23,785
11,564
6,182
(39)

50,782 $

51,544 $

41,492

60,044 $
14,261
3,451
330

55,935 $
14,794
3,719
218

53,276
15,379
3,817
73

78,086 $

74,666 $

72,545

98,417 $
17,869
28,439
(9,845)

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

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

$ 134,880 $ 129,389 $ 132,287

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

3. Rate and Regulatory Matters

Below are descriptions of OTP’s major capital expenditure projects that
have had, or are expected to have, a significant impact on OTP’s revenue
requirements, rates and alternative revenue recovery mechanisms,
followed by summaries of specific general rate proceedings and
descriptions of rate riders and a summary of rate 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 2019, 2018 and 2017.

MAJOR CAPITAL EXPENDITURE PROJECTS
Merricourt Wind Energy Center (Merricourt)—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 (collectively, EDF) to purchase and assume the
development assets and certain specified liabilities associated with
Merricourt, a 150-megawatt (MW) wind farm in southeastern North
Dakota, for a purchase price of approximately $34.7 million, subject to
adjustments for interconnection costs. Also on November 16, 2016,
OTP entered into a Turnkey Engineering, Procurement and Construction
Services Agreement (the TEPC Agreement) with EDF-RE US
Development, LLC (EDF-USD) pursuant to which EDF-USD 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. The agreements
contain customary representations, warranties, covenants and
indemnities for this type of transaction. On October 26, 2017 the MPUC
approved the facility under the Renewable Energy Standard making
Merricourt eligible for cost recovery under the Minnesota Renewable
Resource Recovery rider, subject to qualifications and reporting
obligations. The MPUC’s final written order was issued on January 10,
2018. A final order for an Advance Determination of Prudence (ADP)
for Merricourt, subject to qualifications and compliance obligations,
and a Certificate of Public Convenience and Necessity were issued by
the NDPSC on November 3, 2017. The phase-in rider approved by order
of the SDPUC on March 6, 2019 includes recovery of Merricourt costs.
The Merricourt generator interconnection agreement with MISO was
approved by the FERC in April 2019.

In connection with action by the FERC, OTP and EDF-US agreed, in

the First Amendment to the Purchase Agreement and the TEPC
Agreement dated June 11, 2019, to change the purchase price to
$37.7 million and to make a related reallocation of responsibility for
interconnection costs and liabilities. On July 16, 2019 OTP closed on
the purchase of substantially all of the development assets and
assumed certain specified liabilities from EDF related to Merricourt
pursuant to the Purchase Agreement, as amended, for a purchase price
of approximately $37.7 million, subject to certain adjustments, and
issued the notice to EDF-USD to begin construction in August 2019. As
of December 31, 2019, OTP had capitalized approximately $81.7 million
in project costs and allowance for funds used during construction
(AFUDC) associated with Merricourt. OTP expects this project will be
completed in October of 2020.

Astoria Station—OTP is constructing this 245 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. A final order granting
an ADP for Astoria Station was issued by the NDPSC on November 3,
2017, subject to certain qualifications and compliance obligations. On
August 3, 2018 the SDPUC issued an order granting a site permit for
Astoria Station. In a September 26, 2018 hearing the NDPSC established
a GCR rider for future recovery of costs incurred for Astoria Station. On
March 6, 2019 the SDPUC issued an order approving a settlement that
allows a phase-in rider which includes recovery of Astoria Station costs.
The interconnection agreement for Astoria Station was executed by
MISO in December 2018 and accepted by the FERC in January 2019.
Site preparation and excavation began in May 2019. As of December 31,
2019, OTP had capitalized approximately $58.7 million in project costs
and AFUDC associated with Astoria Station. OTP expects this project
will be completed in late 2020 or early 2021.

Big Stone South–Ellendale Multi-Value Transmission Project (MVP)—
This 345-kiloVolt transmission line, energized on February 6, 2019,
extends 162 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
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 from the MVP. OTP capitalized costs of approximately
$106 million on this project, including assets that are 100% owned by OTP.

GENERAL RATES
Minnesota—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 is
7.5056% and its allowed rate of return on equity (ROE) is 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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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.

North Dakota—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
ROE 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 ROE 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.

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 did not require any rate
base adjustments from OTP’s original request and established a GCR
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 were effective February 1, 2019, with
refunds of excess revenues collected under interim rates applied to
customers’ April 2019 bills, including $0.8 million for amounts collected
reflecting the higher tax rates under interim rates in effect in January
and February 2018.

South Dakota—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
were effective October 18, 2018. The second step in the request was an
additional 1.7% revenue increase to recover costs for Merricourt when
the wind generation facility goes into service.

Pursuant to the May 30, 2019 order, OTP’s allowed ROE was set at
8.75%, resulting in an annual revenue increase of approximately
$2.2 million prior to the approval of a June 28, 2019 stipulation
agreement discussed below. Final rates went into effect August 1, 2019.
An interim rate refund for the lower ROE going back to October 18,
2018 was applied to South Dakota customers’ October 2019 bills.

On July 9, 2019 the SDPUC approved a stipulation agreement entered

To ensure rates are appropriately set under the stipulation, the parties

agreed to establish an earnings sharing mechanism to share with
customers any weather-normalized earnings above the authorized ROE
of 8.75%. OTP’s annual weather-normalized earnings are reported each
year by June 1 in its jurisdictional annual report, which will be used to
determine the earnings level for purposes of calculating any refund.
The earnings sharing mechanism requires that OTP will refund to
customers 50% of any weather-normalized revenue that corresponds
to the earnings in excess of its authorized ROE, up to a maximum of
9.50% ROE for a particular year. OTP will refund 100% of any earnings
above 9.50% each year. In the event a refund is due under this provision,
OTP will notify the SDPUC of the refund amount and plan for crediting
customers within 30 days of filing its South Dakota jurisdictional
annual report.

RATE RIDERS
OTP has several rate riders in place in each of its state jurisdictional
service areas. These rate riders are designed to recover expenses, costs
and returns on rate base investments not currently being recovered in
base, or general, rates. Following is a brief description and summary
of recent proceedings of riders in place in each state served by OTP
followed by tables showing revenues recorded under rate riders in
2019, 2018 and 2017 and a listing of rate rider updates impacting
revenues in 2019, 2018 and 2017.

MINNESOTA
Minnesota Conservation Improvement Programs (MNCIP)—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 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. The Minnesota

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

Department of Commerce (MNDOC) issued a decision on May 20, 2019
to extend all utilities’ 2017-2019 MNCIP plans one year, through 2020,
with an incentive based on 30% of spending and 10% of net benefits.
Based on results from MNCIP 2019, 2018 and 2017 program years,
OTP recognized financial incentives of $2.7 million for 2019, $3.0 million
for 2018 and $2.9 million for 2017, of which $2.6 million was recognized
in 2017 with $0.3 million that had been reserved for potential future
refund recognized in 2019.

Transmission Cost Recovery Rider—The Minnesota Public Utilities Act
provides a mechanism for automatic adjustment outside of a general
rate proceeding to recover the costs of new transmission facilities that
meet certain criteria, plus a return on investment at the level approved
in a utility’s last general rate case. Additionally, following approval of
the rate schedule, the MPUC may approve annual rate adjustments filed
pursuant to the rate schedule.

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 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 general rate case 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 the second quarter of 2020.
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 addition, on April 1, 2019, the MNDOC filed comments in OTP’s TCR
rider docket, opposing OTP’s proposal for TCR rider recovery of these
costs. The MPUC is not expected to act on the TCR rider until after
the Minnesota Supreme Court has acted and additional briefing has
occurred in the docket. The estimated amount credited to Minnesota
customers through the TCR rider through December 31, 2019, and
subject to recovery if the Minnesota Court of Appeals decision is
upheld is approximately $2.6 million. If the Minnesota Court of Appeals
decision is upheld, there will be additional briefing in the pending TCR
rider docket regarding the recovery of these costs.

Environmental Cost Recovery Rider—OTP had an ECR rider for recovery
of OTP’s Minnesota jurisdictional share of the revenue requirements of
its investment in the Big Stone Plant Air Quality Control System (AQCS).
The ECR rider provided for a return on the project’s construction work
in progress (CWIP) balance at the level approved in OTP’s 2010 general
rate case. In its 2016 general rate case order, the MPUC approved OTP’s
proposal to transition eligible rate base and expense recovery from the
ECR rider to base rate recovery effective with implementation of final
rates in November 2017. 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.

Renewable Resource Adjustment—Effective November 1, 2017, with the
implementation of final rates in Minnesota, new rates were put into effect
for the Minnesota RRA rider to address recovery of federal production
tax credits (PTCs) expiring on OTP’s wind farms in 2017 and 2018.
On June 21, 2019 OTP filed its annual update to the Minnesota RRA
requesting approval for recovery of the difference in PTCs in base rates
and the actual PTCs generated, as well as recovery of Merricourt.
On December 19, 2019 the MPUC approved a revised request which
included changes related to Merricourt capitalized costs.

Fuel and Purchased Power Costs Recovery—In a December 2017 order,
the MPUC adopted a program to implement certain procedural reforms
to Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel
and purchased power cost recovery. With this order, the method of
accounting for all Minnesota electric utilities changed to a monthly
budgeted, forward-looking FAC with annual prudence review and
true-up to actual allowed costs. On October 31, 2019 the MPUC
approved the forecasted monthly fuel cost rates submitted by OTP
for 2020 and the rates became effective on January 1, 2020. This
mechanism could result in reductions in Electric segment operating
income margins, increase variability in consolidated net income in
future periods if costs per kwh vary from forecasted costs per kwh and
cause an increase in working capital and short-term borrowings in the
event recovery of all or a portion of excess costs is delayed or denied
by the MPUC.

NORTH DAKOTA
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.

On December 31, 2019 OTP filed its annual update to the North

Dakota RRA requesting approval for recovery of the difference in PTCs
in base rates and the actual PTCs generated, as well as a return on
Merricourt costs incurred while under construction. This update also
included a credit for the remaining unrefunded credit balance in the
North Dakota ECR rider tracker on November 30, 2019.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

OTP made a supplemental filing for the South Dakota TCR rider
on February 1, 2019. On February 15, 2019 the SDPUC approved the
supplemental filing and rates effective March 1, 2019. Two new projects
were approved for recovery under the rider: The Lake Norden area
transmission upgrade project with a recovery date effective January 1,
2019 and the Big Stone South—Ellendale project with a recovery date
effective January 1, 2020.

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 were in effect. The ending balance of the South Dakota ECR rider
at the conclusion of interim rates was refunded to South Dakota
customers along with their October 2019 interim rate refunds.

Phase-In Rate Plan Rider—On May 31, 2019 OTP petitioned the SDPUC
for approval of its initial rate for the Phase-In Rate Plan Rider as
described in OTP’s most recent South Dakota general rate case
settlement stipulation and was approved by the SDPUC’s order in that
rate case. The petition is OTP’s initial filing for the rider to recover
OTP’s South Dakota share of actual and forecasted costs for Astoria
Station and Merricourt, and to refund forecasted net benefits associated
with additional load growth in the Lake Norden area.

On August 21, 2019 the SDPUC approved OTP’s supplemental filing
for its South Dakota Phase-In Rate Plan Rider effective September 1, 2019.

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 remained 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.

On December 18, 2019 the NDPSC approved OTP’s annual update
to its North Dakota TCR rider. The filing included seven new projects,
updated costs associated with existing projects, details about the
pending MISO ROE complaint, and details about SPP related expenses.

Environmental Cost Recovery Rider—OTP has an ECR rider in North
Dakota. The ECR rider provides for a return on investment at the level
approved in OTP’s preceding general rate case and 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 Mercury and Air Toxic Standards (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 North Dakota RRA annual update
filed on December 31, 2019.

Generation Cost Recovery Rider—On May 15, 2019 the NDPSC
approved OTP’s request to establish an initial GCR rider rate for recovery
of OTP’s North Dakota jurisdictional share of the revenue requirements
on its investment in Astoria Station, effective on bills rendered after
July 1, 2019.

SOUTH DAKOTA
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. A supplemental filing to update
the rider was made on January 29, 2018 to reflect updated costs and
collections and incorporate the impact of the reduction in the federal
corporate income tax rate under the TCJA. Effective October 18, 2018,
with the implementation of interim rates under South Dakota general
rate case proceedings, the TCR rate was decreased as a result of recovery
of certain costs being shifted to recovery in interim rates and included
for ongoing recoveries in final base rates at the end of the 2018 general
rate case.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

RATE RIDER UPDATES
The following table provides summary information on the status of updates since January 1, 2016 for the rate riders described above:

Rate Rider

Minnesota

Conservation Improvement Program
2018 Incentive and Cost Recovery
2017 Incentive and Cost Recovery
2016 Incentive and Cost Recovery
2015 Incentive and Cost Recovery

Transmission Cost Recovery

2018 Annual Update–Scenario A
–Scenario B

2017 Rate Reset
2016 Annual Update

Environmental Cost Recovery

2018 Annual Update
2017 Rate Reset
2016 Annual Update

Renewable Resource Adjustment
2019 Annual Update—Revised
2018 Annual Update
2017 Rate Reset

North Dakota

Renewable Resource Adjustment

2020 Annual Update
2019 Annual Update
2018 Rate Reset for effect of TCJA
2017 Rate Reset
2016 Annual Update
2015 Annual Update

Transmission Cost Recovery

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

Environmental Cost Recovery

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

Generation Cost Recovery

2019 Initial Request

South Dakota

Transmission Cost Recovery

2020 Annual Update
2019 Rate Reset
2019 Annual Update
2018 Interim Rate Reset
2017 Annual Update
2016 Annual Update
2015 Annual Update

Environmental Cost Recovery

2018 Interim Rate Reset
2017 Annual Update
2016 Annual Update

Phase-In Rate Plan Recovery

2019 Initial Request

R—Request Date
A—Approval Date

Effective Date
Requested or
Approved

Annual
Revenue
($000s)

11,926
10,283
9,868
8,590

6,475
2,708
(3,311)
4,736

—
(1,943)
11,884

12,506
5,886
1,279

3,828
(235)
9,650
9,989
9,156
9,262

5,739
4,801
7,469
7,959
6,916

—
(378)
7,718
8,537
9,917
10,359

A—December 27, 2019
A—October 4, 2018
A—September 15, 2017
A—July 19, 2016

January 1, 2020
November 1, 2018
October 1, 2017
October 1, 2016

R—November 30, 2018

June 1, 2019

A—October 30, 2017
A—July 5, 2016

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

A—December 19, 2019
A—August 29, 2018
A—October 30, 2017

R—December 31, 2019
A—May 1, 2019
A—February 27, 2018
A—December 20, 2017
A—March 15, 2017
A—June 22, 2016

A—December 18, 2019
A—December 6, 2018
A—February 27, 2018
A—November 29, 2017
A—December 14, 2016

A—October 22, 2019
A—December 19, 2018
A—February 27, 2018
A—December 20, 2017
A—July 12, 2017
A—June 22, 2016

November 1, 2017
September 1, 2016

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

January 1, 2020
November 1, 2018
November 1, 2017

April 1, 2020
June 1, 2019
March 1, 2018
January 1, 2018
April 1, 2017
July 1, 2016

January 1, 2020
February 1, 2019
March 1, 2018
January 1, 2018
January 1, 2017

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

A—May 15, 2019

July 1, 2019

R—October 31, 2019
A—September 17, 2019
A—February 20, 2019
A—October 18, 2018
A—February 28, 2018
A—February 17, 2017
A—February 12, 2016

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

March 1, 2020
October 1, 2019
March 1, 2019
October 18, 2018
March 1, 2018
March 1, 2017
March 1, 2016

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

A—August 21, 2019

September 1, 2019

$
$
$
$

$
$
$

$
$
$
$
$
$

$
$
$
$
$

$
$
$
$
$
$

$
$
$
$
$
$
$

$
$
$

Rate

$0.00710/kwh
$0.00600/kwh
$0.00536/kwh
$0.00275/kwh

Various
Various
Various
Various

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

$0.00467/kwh
$0.00219/kwh
$0.00049/kwh

3.744% of base
-0.224% of base
7.493% of base
7.756% of base
7.005% of base
7.573% of base

Various
Various
Various
Various
Various

0% of base
-0.310% of base
5.593% of base
6.629% of base
7.633% of base
7.904% of base

2,720

2.547% of base

2,407
2,046
1,638
1,171
1,779
2,053
1,895

(189)
2,082
2,238

Various
Various
Various
Various
Various
Various
Various

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

864

3.345% of base

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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:

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 from
the MVP.

2,165

1,664

1,843

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

Rate Rider (in thousands)

2019

2018

2017

Minnesota

Conservation Improvement Program

Costs and Incentives

Renewable Resource Adjustment
Transmission Cost Recovery
Environmental Cost Recovery

North Dakota

Transmission Cost Recovery
Generation Cost Recovery
Environmental Cost Recovery
Renewable Resource Adjustment

South Dakota

Transmission Cost Recovery
Conservation Improvement Program

Costs and Incentives

Environmental Cost Recovery
Phase-In Rate Plan

Total

$ 8,271
5,513
2,497
(1)

8,127 $
3,067
(2,039)
(24)

5,292
878
550
230

7,016
—
7,318
8,529

6,008
(196)
2,973
8,148

8,729
—
9,782
7,620

851
(29)
(125)

628
1,676
—

598
2,345
—

$ 26,092

$ 35,962 $ 47,850

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 directing OTP to return to ratepayers, in a one-time
refund, the TCJA-related savings accrued prior to the refund effective
date. 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. New rates reflecting the reduction
in revenue requirements related to the TCJA tax rate reduction went
into effect June 1, 2019. A one-time refund to Minnesota customers of
$11.5 million in excess of amounts billed from January 2018 through
May 2019 occurred in August and September 2019.

As described above, OTP’s recent general rate cases in North Dakota
and South Dakota reflected the impact of the TCJA in interim rates. OTP
accrued refund liabilities for the time periods during which revenues
were collected under rates set to recover higher levels of federal income
taxes than OTP incurred under the lower federal tax rates in the TCJA.

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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

ROE—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.

On March 1, 2019 the FERC issued a Notice of Inquiry (NOI) seeking

FERC’s revised methodology in the two complaints against the MISO
transmission owners’ base ROE. The order granted rehearing on the
first complaint, found the existing 12.38% ROE unjust and unreasonable,
and directed the MISO transmission owners to adopt a 9.88% ROE
effective September 28, 2016, and to provide refunds. The order also
dismissed the second complaint and found that the record in that
proceeding did not support a finding that the 9.88% ROE established
in the first complaint proceeding had become unjust and unreasonable.
As a result of the FERC granting rehearing on the first complaint and
finding the existing 12.38% ROE unjust and unreasonable and directing
the MISO transmission owners to adopt a 9.88% ROE, OTP increased its
refund provision related to the ROE complaints from $1.6 million to
$3.0 million as of December 31, 2019. The $3.0 million includes
provisions for:
(cid:1) an additional $0.2 million refund related to the first complaint as a
result of reducing the reasonable ROE from 10.32%, established in
the FERC’s September 28, 2016 refund order, to the newly
established 9.88% ROE,

4. Regulatory Assets and Liabilities

(cid:1) a $1.5 million refund related to the second complaint period in

In response to the FERC’s November 21, 2019 order, the MISO

Transmission Owners (including OTP) and others filed requests seeking
rehearing of the FERC’s November 21, 2019 order, and a group of parties
filed with the United States Court of Appeals for the District of Columbia
a protective appeal.

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, 2019

Current

Long-Term

Total

Remaining
Recovery/Refund
Period (months)

Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits (1)
Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment (1)
Conservation Improvement Program Costs and Incentives (2)
Minnesota Transmission Cost Recovery Rider Accrued Revenues (2)
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups (1)
Nonservice Costs Components of Postretirement Benefits Capitalized

9,090
—
4,024
4,208
2,033

$ 129,102
7,772
2,844
—
968

$ 138,192
7,772
6,868
4,208
3,001

for Ratemaking Purposes and Subject to Deferred Recovery (1)

Big Stone II Unrecovered Project Costs—Minnesota (1)
Debt Reacquisition Premiums (1)
Deferred Marked-to-Market Losses (1)
Big Stone II Unrecovered Project Costs—South Dakota (1)
South Dakota Deferred Rate Case Expenses Subject to Recovery (1)
North Dakota Deferred Rate Case Expenses Subject to Recovery (1)
Minnesota SPP Transmission Cost Recovery Tracker (1)
Minnesota Renewable Resource Rider Accrued Revenues (2)
South Dakota Transmission Cost Recovery Rider Accrued Revenues (2)
Deferred Lease Expenses (1)
Minnesota Environmental Cost Recovery Rider Accrued Revenues (2)

Total Regulatory Assets

Regulatory Liabilities:

Deferred Income Taxes
Accumulated Reserve for Estimated Removal Costs—Net of Salvage
Refundable Fuel Clause Adjustment Revenues
North Dakota Renewable Resource Recovery Rider Accrued Refund
North Dakota Transmission Cost Recovery Rider Accrued Refund
Prior Service Costs and Actuarial Gains on Postretirement Benefits
Revenue for Rate Case Expenses Subject to Refund—Minnesota
South Dakota Phase-In Rate Plan Rider Accrued Refund
North Dakota Generation Cost Recovery Rider Accrued Refund
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund
Other

Total Regulatory Liabilities

Net Regulatory Asset/(Liability) Position

—
715
201
743
144
138
122
—
131
97
—
4

1,681
225
548
—
253
245
244
202
—
—
54
—

1,681
940
749
743
397
383
366
202
131
97
54
4

$ 21,650

$ 144,138

$ 165,788

—
—
3,982
1,515
700
471
—
355
287
164
6

$ 141,707
97,726
—
—
—
—
401
—
—
—
72

$ 141,707
97,726
3,982
1,515
700
471
401
355
287
164
78

7,480

$ 14,170

$ 239,906

$ 247,386

$ (95,768)

$ (81,598)

see below
asset lives
21
12
24

asset lives
16
153
12
33
34
36
see below
12
2
39
12

asset lives
asset lives
12
12
12
12
see below
9
6
12
168

(1) Costs subject to recovery without a rate of return.
(2)Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

(in thousands)

Regulatory Assets:

Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits (1)
Accumulated ARO Accretion/Depreciation Adjustment (1)
Conservation Improvement Program Costs and Incentives (2)
Minnesota Transmission Cost Recovery Rider Accrued Revenues (2)
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up (1)
Nonservice Costs Components of Postretirement Benefits Capitalized

for Ratemaking Purposes and Subject to Deferred Recovery (1)

Big Stone II Unrecovered Project Costs—Minnesota (1)
Debt Reacquisition Premiums (1)
Deferred Marked-to-Market Losses (1)
Big Stone II Unrecovered Project Costs—South Dakota (1)
South Dakota Deferred Rate Case Expenses Subject to Recovery (1)
North Dakota Deferred Rate Case Expenses Subject to Recovery (1)
Minnesota SPP Transmission Cost Recovery Tracker (1)
Minnesota Renewable Resource Recovery Rider Accrued Revenues (2)
Minnesota Environmental Cost Recovery Rider Accrued Revenues (2)
Deferred Income Taxes (1)
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues (1)
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
Refundable Fuel Clause Adjustment Revenues
North Dakota Renewable Resource Recovery Rider Accrued Refund
North Dakota Transmission Cost Recovery Rider Accrued Refund
Revenue for Rate Case Expenses Subject to Refund—Minnesota
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
South Dakota Transmission Cost Recovery Rider Accrued Refund
South Dakota Environmental Cost Recovery Rider Accrued Refund
Other

Total Regulatory Liabilities

Net Regulatory Asset/(Liability) Position

December 31, 2018

Current

Long-Term

Total

Remaining
Recovery/Refund
Period (months)

6,346
—
5,995
444
240

—
681
207
1,661
100
178
455
—
452
121
—
328
17

$ 118,433
7,169
3,285
—
—

$ 124,779
7,169
9,280
444
240

986
947
753
743
342
—
—
176
—
—
2,423
—
—

986
1,628
960
2,404
442
178
455
176
452
121
2,423
328
17

$ 17,225

$ 135,257

$ 152,482

—
—
121
177
60
—
—
168
207
5

738

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

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

$ 226,469

$ 227,207

$ 16,487

$ (91,212)

$ (74,725)

see below
asset lives
21
12
12

asset lives
28
165
24
53
12
12
see below
12
12
asset lives
4
12

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

(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.

The regulatory asset and liability related to prior service costs and
actuarial losses on pensions and other postretirement benefits represents
benefit costs and actuarial losses and gains subject to recovery or refund
through rates as they are expensed. These unrecognized benefit costs
and actuarial losses and gains 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 or liabilities based on their
probable inclusion in future retail electric rates.

The Accumulated ARO Accretion/Depreciation Adjustment will

accrete and be amortized over the lives of property with asset
retirement obligations.

Conservation Improvement Program Costs and Incentives represent

mandated conservation expenditures and incentives recoverable
through retail electric rates.

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 were
recoverable from Minnesota customers as of the balance sheet date.

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.

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.

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.

Debt Reacquisition Premiums are being recovered from OTP
customers over the remaining original lives of the reacquired debt
issues, the longest of which is 153 months.

All Deferred Marked-to-Market Losses recorded as of the balance
sheet date relate to forward purchases of energy scheduled for delivery
through December 2020.

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.
South Dakota Deferred Rate Case Expenses Subject to Recovery relate

to costs incurred in conjunction with OTP’s most recent rate case in
South Dakota and are currently being recovered beginning with the
establishment of interim rates in October 2018.

North Dakota Deferred Rate Case Expenses Subject to Recovery
relate to costs incurred in conjunction with OTP’s most recent rate
case in North Dakota currently being recovered beginning with the
establishment of interim rates in January 2018.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

The Minnesota SPP Transmission Cost Recovery Tracker regulatory
asset relates to costs incurred to serve Minnesota customers that are
subject to recovery but that had not been billed to Minnesota customers
as of the balance sheet date.

Dakota. The balance represents amounts subject to refund to North
Dakota customers that had been billed to North Dakota customers as
of the balance sheet date.

The Minnesota Energy Intensive Trade Exposed Rider Accrued

Refund relates to over-collected amounts from Minnesota retail
customers for fuel and purchased power costs reductions provided to
customers in energy intensive trade exposed industries that were
subject to refund to Minnesota customers as of the balance sheet date.
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
were refundable to South Dakota customers as of the balance sheet date.

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 were refundable to South Dakota customers as of
the balance sheet date.

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.

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.
On November 8, 2019, the Company entered into a Distribution

Agreement with KeyBanc Capital Markets Inc. (KeyBanc Capital
Markets). Pursuant to the terms of the Distribution Agreement, the
Company may offer and sell its common shares from time to time
through KeyBanc, as the Company’s distribution agent for the offer
and sale of the shares, up to an aggregate sales price of $75,000,000.
Under the Distribution Agreement, the Company will designate the

minimum price and maximum number of common shares to be sold
through KeyBanc on any given trading day or over a specified period
of trading days, and KeyBanc will use commercially reasonable efforts
to sell such shares on such days, subject to certain conditions. Sales
of the shares, if any, will be made by means of ordinary brokers’
transactions on the Nasdaq Global Select Market at market prices or as
otherwise agreed with KeyBanc. The Company may also agree to sell
shares to KeyBanc, as principal for its own account, on terms agreed to
by the Company and KeyBanc in a separate agreement at the time of
sale. KeyBanc will receive from the Company a commission of up to
2% of the gross sales price per share for any shares sold through it as
the Company’s distribution agent under the Distribution Agreement.
The Company is not obligated to sell and KeyBanc is not obligated to
buy or sell any of the shares under the Distribution Agreement. The
shares, if issued, will be issued pursuant to the Company’s existing
shelf registration statement.

The Minnesota Renewable Resource Recovery Rider Accrued

Revenues relate to revenues earned on qualifying renewable resource
costs incurred to serve Minnesota customers that were recoverable
from Minnesota customers as of the balance sheet date.

The South Dakota Transmission Cost Recovery Rider Accrued

Revenues relate to revenues earned on qualifying transmission system
facilities and operating costs incurred to serve South Dakota customers
that were recoverable from South Dakota customers as of the balance
sheet date.

Deferred Lease Expenses: Under ASC 842 accounting rules, for

leases with scheduled escalating payments, rent expense is required to
be recognized on a straight-line basis over the life of the lease based
on the sum of those payments. Rate-regulated entities are generally
only allowed to recover the amount of actual cash payments on leases
and FERC accounting rules require that rent expense be recognized on
the basis of cash payments. The balance in the deferred lease expense
regulatory asset account represents operating lease right of use asset
cumulative amortization and interest costs in excess of cumulative
lease payments that are subject to recovery in future periods under
regulatory accounting treatment as cash payments are rendered.
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 were recoverable
from Minnesota customers as of the balance sheet date.

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.

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 were subject to recovery from other Minnesota
customers as of the balance sheet date.

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 were recoverable from
North Dakota customers as of the balance sheet date.

The Accumulated Reserve for Estimated Removal Costs—Net of
Salvage is reduced as actual removal costs, net of salvage revenues,
are incurred.

The North Dakota Renewable Resource Recovery Rider Accrued
Refund relates to amounts collected for qualifying renewable resource
costs incurred to serve North Dakota customers that were refundable
to North Dakota customers as of the balance sheet date.

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 were
refundable to North Dakota customers as of the balance sheet date.
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.

The South Dakota Phase-In Rate Plan Rider Accrued Refund relates
to amounts collected for actual and forecasted costs for Astoria Station,
Merricourt, and additional load growth that were refundable to South
Dakota customers as of the balance sheet date.

The North Dakota Generation Cost Recovery Rider Accrued Refund

relates to revenues collected under the rider in excess of returns
allowed on recoverable costs incurred for the North Dakota share of
OTP’s investment in Astoria Station, a natural gas-fired combustion
turbine generation facility under construction near Astoria, South

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

2019 Common Stock Activity
Following is a reconciliation of the Company’s common shares
outstanding from December 31, 2018 through December 31, 2019:

Common Shares Outstanding, December 31, 2018
Issuances:

At-the-Market Offering
Executive Stock Performance Awards (2016 awards earned)
Automatic Dividend Reinvestment and Share Purchase Plan:

Dividends Reinvested
Cash Invested

Vesting of Restricted Stock Units
Restricted Stock Issued to Directors
Directors Deferred Compensation

Retirements:

39,664,884

347,000
102,198

29,599
23,740
29,100
15,700
594

Shares Withheld for Individual Income Tax Requirements

Common Shares Outstanding, December 31, 2019

(55,224)

40,157,591

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 1,010,110 were available for issuance as of December 31, 2019.
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 through payroll
withholding at a discount of up to 15% off the market price at the end
of each six-month purchase period. For purchase periods between
January 1, 2017 and June 30, 2019, the purchase price was 100% of the
market price at the end of each six-month purchase period. For purchase

periods beginning after June 30, 2019, the purchase price is 85% of
the market price at the end of each six-month purchase period. Of the
1,400,000 common shares authorized to be issued under the Purchase
Plan, 349,763 were available for purchase as of December 31, 2019. 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,
13,432 common shares were issued in January 2020 for the purchase
period ended December 31, 2019, 3,672 common shares were purchased
in the open market in 2019, 7,757 common shares were purchased in
the open market in 2018, and 4,202 common shares were purchased
in the open market and 5,284 common shares were issued in 2017.

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 October 2019, the Company began issuing new shares to satisfy
the requirements of the Plan. In 2019, 53,339 common shares were issued,
and 109,807 shares were purchased in the open market to provide shares
for the Plan. 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 1,220,032 common shares
available for purchase or issuance under the Plan as of December 31,
2019. 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.

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 2019, 2018 and
2017. 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 reconciliations.

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 Employee Stock Purchase Plan
Shares Expected to be Issued Under the Deferred Compensation Program for Directors

Total Dilutive Shares

2019

2018

2017

39,720,847

39,599,944

39,457,261

147,001
65,421
15,377
3,228
1,952

232,979

212,043
59,980
17,751
—
2,478

292,252

210,784
56,952
20,380
—
2,970

291,086

Weighted Average Common Shares Outstanding—Diluted

39,953,826

39,892,196

39,748,347

The effect of dilutive shares on earnings per share for the years ended December 31, 2019, 2018 and 2017, 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 9 A N N UA L R E P O R T

6. Share-Based Payments

Purchase Plan
The Purchase Plan allows eligible employees to purchase the Company’s common shares through payroll withholding at a discount of up to 15%
off the market price at the end of each six-month purchase period. For purchase periods between January 1, 2017 and June 30, 2019, the purchase
price was 100% of the market price at the end of each six-month purchase period. For purchase periods beginning after June 30, 2019, the purchase
price is 85% of the market price at the end of each six-month purchase period. Under ASC Topic 718, Compensation—Stock Compensation (ASC 718),
the Company is required to record compensation expense related to the 15% discount. The 15% discount resulted in compensation expense of
$103,000 for the six-month period ended December 31, 2019.

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 8, 2019, 15,700 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 8, 2019 was $49.73 per share, the average of the high and low market price on the date of
grant. The restricted shares granted to directors in 2019 vest 33.3% per year on April 8 of each year in the period 2020 through 2022 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

43,225
15,700
18,320
—

40,605

2019

Weighted
Average
Grant-Date
Fair Value

37.53
49.73
36.02

42.93

$
$

776,000
660,000

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

Restricted Stock Granted to Employees
Under the 1999 Incentive Plan and 2014 Incentive Plan, restricted shares of the Company’s common stock were 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

—
—
—
—

—

2019

Weighted
Average
Grant-Date
Fair Value

$
$

—

—
—

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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

Restricted Stock Units Granted to Executive Officers and Key Employees
On February 13, 2019, 15,600 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 $49.6225 per share, the average of the high and low market price on the date of grant. On December 17,
2019, 600 restricted stock units under the 2014 Incentive Plan were granted to a key employee of the Company. The grant-date fair value of each
restricted stock unit was $52.165 per share, the average of the high and low market price on the date of grant. The restricted stock units granted in
2019 vest 25% per year on February 6 of each year in the period 2020 through 2023. The restricted stock units granted to executive officers and
key employees 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 dividend equivalent restricted stock unit awards granted to executive officers and key employees

for the years ended December 31:

Dividend Equivalent Restricted Stock Unit Awards

Nonvested, Beginning of Year
Granted
Vested
Forfeited

Nonvested, End of Year

Compensation Expense Recognized
Fair Value of Awards Vested

45,300
16,200
15,850
—

45,650

2019

Weighted
Average
Grant-Date
Fair Value

35.70
49.72
34.46

41.10

$ 1,055,000
546,000
$

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

Restricted Stock Units Granted to Employees
In 2019, 13,270 restricted stock unit awards under the 2014 Incentive Plan were granted to certain employees of the Company. The grant-date fair
value of each restricted stock unit was $44.45 per share 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. The restricted stock units granted in 2019
vest 100% on April 8, 2023. The restricted stock units granted to employees of the Company are not eligible to receive dividend equivalent payments
on unvested awards. 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

49,470
13,270
13,250
1,900

47,590

2019

Weighted
Average
Grant-Date
Fair Value

31.03
44.45
27.62
34.57

35.58

$
$

427,000
366,000

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

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 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 13, 2019 performance share awards were granted to the Company’s executive officers under the 2014 Incentive Plan for the 2019-2021
performance measurement period. Under the 2019 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 ROE. 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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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 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.

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

2019-2021
2018-2020
2017-2019
2016-2018
2015-2017

Total

83,400
81,000
89,250
122,250
126,450

Target
Shares

55,600
54,000
59,500
81,500
84,300

Expense Recognized in the
Year Ended December 31,

2019

2018

2017

$ 2,168,000
897,000
524,000
8,000
—

$ 3,597,000

$ 1,121,000
729,000
772,000
23,000

$ 2,645,000

854,000
580,000
573,000

$ 2,007,000

Earned
Shares

69,997
113,298
114,648

297,943

Stock-based payment expense recognized in 2019, 2018 and 2017 for the 2019-2021, 2018-2020 and 2017-2019 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 2017-2019 performance period also include shares received in 2020 by participants in the
plan based on the Company achieving a total shareholder return ranking of 19 out of 39 companies in the EEI Index and an average 3-year adjusted
ROE in excess of the targeted average 3-year adjusted ROE of 9.5% resulting in a payout at 120.19% of target.

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 ROE in
excess of the targeted average 3-year adjusted ROE 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 ROE
in excess of the targeted average 3-year adjusted ROE of 10.00% resulting in a payout at 136.00% of target.

As of December 31, 2019, 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 $3.5 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,
2019, 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 46.0% and 56.2% based on OTP’s 2019 capital structure petition
effective by order of the MPUC on July 19, 2019. As of December 31, 2019,
OTP’s equity-to-total-capitalization ratio including short-term debt was
51.2% and its net assets restricted from distribution totaled approximately
$519 million. Under the 2019 capital structure petition, total capitalization
for OTP cannot exceed $1,331,302,000.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

8. Leases

The Company adopted ASU 2016-02 and related updates (ASC 842),
which replaced previous lease accounting guidance, on January 1, 2019,
using the modified retrospective method of adoption. As a result, prior
periods have not been restated. ASC 842 requires lessees to record assets
and liabilities on the balance sheet for all leases with terms longer than
12 months. Adoption of the standard resulted in the recognition of net
lease assets and lease liabilities of $20 million on January 1, 2019. The
adoption of the new standard did not have a material effect on the
Company’s consolidated statements of income or cash flows. In addition,
the adoption did not have a material impact on the Company’s liquidity
or the Company’s covenant compliance under its current debt agreements.
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 lease classifications
determined under the requirements of ASC Topic 840. The Company
also elected the practical expedient related to land easements, allowing
for the continuation of historical accounting treatment for land easements
on existing agreements at OTP. In addition, the Company has elected
the hindsight practical expedient to determine the reasonably certain
lease term for leases in place at the time of adoption. The Company has
elected the practical expedient to not separate nonlease components
from lease components on real estate leases for the purpose of
determining the classification and the value of lease assets and lease
liabilities at the inception of a lease.

The Company enters into leases for coal rail cars, warehouse and
office space, land and certain office, manufacturing and material handling
equipment under varying terms and conditions. The lengths of the
leases vary from less than one year to approximately ten years. If a
lease contains an option to extend and there is reasonable certainty
the option will be exercised, the option is considered in the lease term
at inception. None of these leases met the criteria to be classified as
financing leases. Of the operating leases in place on January 1, 2019,
50 were capitalized as right-of-use assets and the remainder were
month-to-month leases with no long-term obligations.

The right-of-use asset operating leases in place at the time of adoption

were capitalized on the basis of their remaining payment obligation
balances, discounted to present value based on the Company’s
incremental borrowing rates (IBRs) appropriate to the leased asset and
lease terms. The remaining payments for operating lease right-of-use
assets are being charged to expense on a straight-line basis over the
life of the lease.

For the Company’s current lease obligations, no explicit interest
rates were stated in the lease agreements and no implicit rates could
be determined based on the terms of the agreements. Therefore, in all
cases, the Company has applied a formula-based IBR appropriate to
the individual company, type of lease and lease term.

The breakdown of right-of-use assets and lease liabilities as of

December 31, 2019 by business segment is provided in the following table.

(in thousands)

Electric Manufacturing Plastics Corporate

Total

Right of Use Assets—
Operating Leases:
Gross
Accumulated
Amortization

Net of Accumulated
Amortization

Obligations:

Current Operating
Lease Liabilities
Long-Term Operating
Lease Liabilities

$ 4,137

$ 20,347 $ 666

$ 769 $25,919

(1,166)

(2,375)

(395)

(132)

(4,068)

$ 2,971

$ 17,972 $ 271

$ 637 $ 21,851

$ 1,116

2,609 $ 256

$ 155 $ 4,136

2,176

15,470

532

18,193

Total Lease Liabilities $ 3,292

$ 18,079 $ 271

$ 687 $ 22,329

The amounts of the Company’s right-of-use operating lease

obligations as of December 31, 2019 for each of the five years in the
period 2020 through 2024 and in aggregate for the years beyond 2024
are presented in the following table.

(in thousands)

2020
2021
2022
2023
2024
Beyond 2024

Right-of-Use Operating Leases
Total
OTP Nonelectric

$ 1,243
1,228
326
268
217
283

3,969
3,717
3,588
3,303
2,870
5,304

$ 5,212
4,945
3,914
3,571
3,087
5,587

Total Minimum Obligations
Interest Component of Obligations

$ 3,565
(273)

$ 22,751
(3,714)

$ 26,316
(3,987)

Present Value of Minimum Obligations,

December 31, 2019

$ 3,292

$ 19,037

$ 22,329

The weighted-average remaining lease term for the Company’s
outstanding lease liabilities is 6.0 years and the weighted-average
discount rate is 5.3%.

A reconciliation of the Company’s operating lease obligations on
adoption of ASC Topic 842 on January 1, 2019 and its operating lease
obligations on December 31, 2019 is provided in the table below.

(in thousands)

OTP Nonelectric

Total

Operating Lease Obligations,

January 1, 2019

Non-cash Acquisition of
Right-of-Use Assets

Lease Modifications
Lease Obligation Payments
Interest Component of Lease

Obligation Payment

Operating Lease Obligations,

December 31, 2019

$ 3,609

$ 16,760

$ 20,369

758
71
(1,316)

5,560
(187)
(4,055)

6,318
(116)
(5,371)

170

959

1,129

$ 3,292

$ 19,037

$ 22,329

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

The lease modifications in the above table include adjustments in
future minimum lease obligations on several units of leased equipment
along with reductions for equipment leases terminated prior to the end
of the original lease term when the equipment being leased was
replaced with new equipment under a new lease.

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 CWIP or plant in service
after the project is completed and placed in service.

The Company’s nonelectric companies have obligations to make
future 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 products sold or other
nonelectric expenses, as appropriate, on the Company’s consolidated
statements of income.

The allocation of right-of-use asset and variable lease costs, including
non-cash costs related to straight-line amortization of escalating lease
payments, for 2019 is presented in the following table.

(in thousands)

Plant in Service or CWIP
Inventory
Cost of Products Sold
Electric Operation and

Maintenance Expenses

Other Nonelectric Expenses

Total

Operating
Lease Cost

Variable
Lease Cost

Total
Lease Cost

29
952
3,848

—
—
1,068

29
952
4,916

334
208

—
—

334
208

$ 5,371

1,068

$ 6,439

Prior to adopting ASU 842, the Company recorded operating lease
payments primarily related to leases of buildings and manufacturing
equipment according to the requirements of ASC 840—Leases (ASC 840).
Under ASC 840, these payments were charged to rent expense accounts
and reported in electric operations and maintenance, costs of products
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 and $6,237,000 in 2018
and 2017, respectively.

9. Commitments and Contingencies

Construction and Other Purchase Commitments
At December 31, 2019 OTP had commitments under contracts, including
its share of construction program and other commitments, extending
into 2021 of approximately $317 million. OTP’s other commitments
charged to rent expense totaled $283,000, $252,000 and $280,000 in
2019, 2018 and 2017, respectively.

On October 1, 2019 TOP entered into a new six-year resin supply
agreement that commenced on January 1, 2020. Under the new resin

supply agreement, there are no minimum purchase requirements, but
T.O. Plastics is required to purchase all of a specified class of regrind
resin delivered by the supplier at a set price per pound. Based on current
forecasted production levels, T.O. Plastics anticipates the quantity of
resin delivered under the supply agreement will not exceed its
requirements over the six-year term of the supply agreement or
exceed the market cost of alternative sources of the resin. T.O. Plastics
estimates it will pay the supplier approximately $1.9 million annually
under this agreement.

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 2043. 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 has an agreement with Peabody COALSALES, LLC 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. OTP has an all-requirements agreement with Navajo
Transitional Energy Co. (NTEC) for the purchase of subbituminous coal
for Hoot Lake Plant through December 31, 2023. There are no fixed
minimum purchase requirements under this agreement. In October
2019, NTEC purchased the assets of Cloud Peak Energy Resources LLC,
including its Spring Creek Mine in southeast Montana, through
bankruptcy court. For a two-day period in October, operations at the
Spring Creek Mine were suspended due to a disagreement between the
Montana Department of Environmental Quality and the NTEC.
Subsequent to the suspension of operations, the two parties have
agreed to allow the mine to operate for an additional period while they
work to resolve differences regarding the NTEC’s waiver of sovereign
immunity from the state’s environmental laws.

OTP Land Easements
OTP has commitments to make future payments for land easements not
classified as leases, extending into 2034 of approximately $10.2 million.
Land easement payments charged to rent expense totaled $617,000,
$605,000 and $593,000 in 2019, 2018 and 2017, respectively.

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, 2019, are as follows:

Construction
Program and Other

Coal
Capacity
Purchase
and Energy
Commitments Requirements Commitments

OTP Land
Easement
Payments

$ 269,774
47,230
22
11
6
—

24,844
12,988
11,827
11,827
11,801
131,913

22,644
22,935
22,793
23,955
24,369
479,123

630
642
655
668
682
6,931

$ 317,043

$ 205,200

$ 595,819

$ 10,208

(in thousands)

2020
2021
2022
2023
2024
Beyond 2024

Total

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

Contingencies
OTP had a $3.0 million refund liability on its balance sheet as of
December 31, 2019. This represents its best estimate of the refund
obligations that would arise net of amounts that would be subject to
recovery under state jurisdictional TCR riders. This is based on the
outcome of the appeals of the FERC ruling 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 results of the
appeal 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 that could impact
the Company’s consolidated financial statements are those related to
environmental remediation, risks associated with warranty claims
relating to divested businesses that could exceed established reserve
amounts, risks associated with adverse regulatory decisions that could
impact the recovery of fixed asset costs in future rates and litigation
matters.

On August 30, 2019 OTP submitted a depreciation technical update to
the MPUC for approval. MPUC approval of OTP’s depreciation technical
update is currently pending resolution of a disagreement with the
MNDOC over the remaining lives assigned to certain of OTP’s fixed
assets, including Hoot Lake Plant and seven hydroelectric plants.
Resolution of the disagreement could result in an increase in depreciation
expense without provision for recovery of a portion of the unrecovered
costs of those assets. OTP cannot determine at this time what portion,
if any, of the current unrecovered costs of these assets would be lost as
a result of resolving the disagreement over remaining lives, but estimates
that the remaining useful lives recommended by the MNDOC could
result in an asset impairment charge and after-tax reduction in net
income of up to $1.1 million.

State implementation of pollution control plans to improve visibility

and air quality at national parks under the EPA’s Regional Haze Rule
(RHR) could require OTP to incur significant new costs, which could,
dependent on determinations by state regulatory commissions on
approval to recover such costs from customers, negatively impact OTP’s
and the Company’s net income, financial position and cash flows. OTP
understands that the North Dakota Department of Environmental Quality
(NDDEQ) intends to require sources subject to RHR Round 2 reasonable
progress determinations, including Coyote Station, to undertake
emissions control measures that are reasonably consistent with those
required of sources during Round 1. While this process is still in the
early stages, if the NDDEQ maintains its initial position, OTP anticipates
that significant emissions controls would be required at Coyote Station
by December 31, 2028 in order to maintain compliance with the RHR.
Plans are due to be submitted to the EPA by July 2021. OTP expects
the NDDEQ to begin drafting preliminary control scenarios for regional
visibility modeling in the first quarter of 2020 and a state implementation
plan in mid-2020. In light of the costs for such emissions control
equipment, there are scenarios where it may not be economically
feasible to invest in such equipment and an early retirement of the
Coyote Station would therefore be necessary. The costs related to an
early retirement of Coyote Station would be material to OTP and the
Company and would be subject to state commission approval for
recovery from customers.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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, 2019, other than those relating
to the RHR, 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, 2019 and December 31, 2018:

Restricted
due to

Line December 31,
2019
Limit

In Use on Outstanding Available on Available on
Letters December 31, December 31,
2018
2019

of Credit

$ 170,000

6,000

— $ 164,000

$ 120,785

(in thousands)

Otter Tail

Corporation
Credit
Agreement

OTP Credit

Agreement

170,000

—

15,476

154,524

160,316

Total

$ 340,000

6,000

$ 15,476

$ 318,524

$ 281,101

Under the Otter Tail Corporation Credit Agreement (as defined below),
the maximum amount of debt outstanding in 2019 was $38.9 million on
July 17, 2019 and the average daily balance of debt outstanding during
2019 was $21.9 million. The weighted average interest rate paid on debt
outstanding under the OTC Credit Agreement was 3.8% in 2019 and
3.8% in 2018. Under the OTP Credit Agreement (as defined below), the
maximum amount of debt outstanding in 2019 was $73.2 million on
October 2, 2019 and the average daily balance of debt outstanding
during 2019 was $14.3 million. The weighted average interest rate paid
on debt outstanding under the OTP Credit Agreement during 2019 was
3.6% compared with 3.0% in 2018. The maximum amount of consolidated
short-term debt outstanding in 2019 was $109.2 million on October 1,
2019 and the average daily balance of consolidated short-term debt
outstanding during 2019 was $36.2 million. The weighted average
interest rate on consolidated short-term debt outstanding on
December 31, 2019 was 3.2%.

On October 29, 2012 the Company entered into a Third Amended and
Restated Credit Agreement (the OTC Credit Agreement), which provided
for an unsecured $130 million revolving credit facility that could be
increased subject to certain terms and conditions. On October 31, 2019
the OTC Credit Agreement was amended to extend its expiration date
by one year from October 31, 2023 to October 31, 2024, and to increase
the amount of the revolving credit facility to $170 million. The amendment
also provides this facility can be increased to $290 million subject to
certain terms and conditions. The Company can draw on this credit
facility to refinance certain indebtedness and support its operations
and the operations of certain 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 Corporation (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.

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, 2019 the OTP Credit
Agreement was amended to extend its expiration date by one year
from October 31, 2023 to October 31, 2024. 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, 2024. 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 agree-
ments 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
2019 Note Purchase Agreement
On September 12, 2019, OTP entered into a Note Purchase Agreement
with the purchasers named therein (the 2019 Note Purchase Agreement),
pursuant to which OTP agreed to issue to the purchasers, in a private
placement transaction, $175 million aggregate principal amount of
OTP’s senior unsecured notes consisting of (a) $10,000,000 aggregate
principal amount of its 3.07% Series 2019A Senior Unsecured Notes
due October 10, 2029 (the Series 2019A Notes), (b) $26,000,000
aggregate principal amount of its 3.52% Series 2019B Senior Unsecured
Notes due October 10, 2039 (the Series 2019B Notes), (c) $64,000,000
aggregate principal amount of its 3.82% Series 2019C Senior Unsecured
Notes due October 10, 2049 (the Series 2019C Notes), (d) $10,000,000
aggregate principal amount of its 3.22% Series 2020A Senior Unsecured
Notes due February 25, 2030 (the Series 2020A Notes), (e) $40,000,000
aggregate principal amount of its 3.22% Series 2020B Senior Unsecured
Notes due August 20, 2030 (the Series 2020B Notes), (f) $10,000,000
aggregate principal amount of its 3.62% Series 2020C Senior Unsecured
Notes due February 25, 2040 (the Series 2020C Notes) and
(g) $15,000,000 aggregate principal amount of its 3.92% Series 2020D
Senior Unsecured Notes due February 25, 2050 (the Series 2020D
Notes); and together with the Series 2019A Notes, the Series 2019B
Notes, the Series 2019C Notes, the Series 2020A Notes, the Series
2020B Notes and the Series 2020C Notes, (the Notes).

On October 10, 2019, OTP issued the Series 2019A Notes, Series 2019B

Notes and Series 2019C Notes (the 2019 Notes) pursuant to the 2019
Note Purchase Agreement. OTP used a portion of the $100 million
proceeds from the issuance to repay $69.9 million of existing indebtedness
under the OTP Credit Agreement, primarily incurred to fund OTP capital
expenditures, and intends to use the remainder of the proceeds to pay
for additional capital expenditures and for OTP’s general corporate
purposes. The Series 2020A Notes, the Series 2020C Notes and the
Series 2020D Notes are expected to be issued on February 25, 2020, and
the Series 2020B Notes are expected to be issued on August 20, 2020,
subject to the satisfaction of certain customary conditions to closing.

OTP may prepay all or any part of the 2019 Notes (in an amount not
less than 10% of the aggregate principal amount of the 2019 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 2019 Note Purchase Agreement, any prepayment made by
OTP of all of the (a) Series 2019A Notes then outstanding on or after
April 10, 2029, (b) Series 2019B Notes then outstanding on or after
April 10, 2039 or (c) Series 2019C Notes then outstanding on or after
April 10, 2049 will be made without any make-whole amount. The 2019
Note Purchase Agreement also requires OTP to offer to prepay all
outstanding Notes at 100% of the principal amount together with
unpaid accrued interest in the event of a Change of Control (as defined
in the 2019 Note Purchase Agreement) of OTP.

The 2019 Note Purchase Agreement contains a number of restrictions

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

interest expense and such a covenant is not contained in the 2019 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 2019 Note Purchase Agreement (an Additional
Covenant), then unless waived by the Required Holders (as defined in
the 2019 Note Purchase Agreement), the Additional Covenant will be
deemed to be incorporated into the 2019 Note Purchase Agreement.
The 2019 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 credit
agreement, provided that no default or event of default has occurred
and is continuing.

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.

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 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 2018 Note Purchase Agreement contains a number of restrictions

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.

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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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).

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.

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 2013
Notes). The 2013 Notes were issued on February 27, 2014.

The 2013 Note Purchase Agreement states that OTP may prepay all

or any part of the 2013 Notes (in an amount not less than 10% of the
aggregate principal amount of the 2013 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 2013 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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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, 2019 and December 31, 2018:

Otter Tail
Corporation

6,000

80,000

351

80,351
183
356

79,812

85,995

Otter Tail
Corporation
Consolidated

6,000

80,000
140,000
30,000
42,000
60,000
10,000
50,000
26,000
90,000
100,000
64,000
351

$ 692,351
183
2,587

$ 689,581

$ 695,764

Otter Tail
Corporation

Otter Tail
Corporation
Consolidated

9,215

80,000

523

80,523
172
407

79,944

89,331

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

December 31, 2019 (in thousands)

Short-Term Debt

Long-Term Debt:

3.55% Guaranteed Senior Notes, due December 15, 2026
Senior Unsecured Notes 4.63%, Series 2011A due December 1, 2021
Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022
Senior Unsecured Notes 6.37%, Series 2007C, due August 20, 2027
Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029
Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 2029 (1)
Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037
Senior Unsecured Notes 3.52%, Series 2019B, due October 10, 2039
Senior Unsecured Notes 5.47%, Series 2013B, due February 27, 2044
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048
Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049
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

—

$ 140,000
30,000
42,000
60,000
10,000
50,000
26,000
90,000
100,000
64,000

$ 612,000
—
2,231

$ 609,769

(1) Holder is COBANK, a cooperative lender. Interest payments are subject to cash credits which may result in a lower effective interest rate.

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%, Series 2011A due December 1, 2021
Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022
Senior Unsecured Notes 6.37%, Series 2007C, due August 20, 2027
Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029
Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037
Senior Unsecured Notes 5.47%, Series 2013B, 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)

The aggregate amounts of maturities on bonds outstanding and
other long-term obligations at December 31, 2019 for each of the next
five years are:

(in thousands)

2020

2021

2022

2023

2024

Aggregate Amounts of

Debt Maturities

183 $140,168

$30,000 $

— $

—

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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

Financial Covenants
The Company and OTP were in compliance with the financial covenants
in these debt agreements as of December 31, 2019.

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

The Company’s and OTP’s borrowing agreements are subject to

certain financial covenants. Specifically:
(cid:1) Under the OTC Credit Agreement and the 2016 Note Purchase

Agreement, the Company may not permit the ratio of its Interest-
bearing Debt to Total Capitalization to be greater than 0.60 to 1.00
or permit its Interest and Dividend Coverage Ratio to be less than
1.50 to 1.00 (each measured on a consolidated basis).

(cid:1) Under the 2016 Note Purchase Agreement, the Company may not

permit its 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 2013 Note Purchase Agreement, the 2018 Note Purchase
Agreement and the 2019 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.

11. Pension Plan and Other Postretirement Benefits

Pension Plan
The Company’s noncontributory funded pension plan covers substantially
all corporate employees and OTP nonunion employees hired prior to
September 1, 2006, and all union employees of OTP hired prior to
November 1, 2013, excluding Coyote Station employees. Coyote Station
employees hired before January 1, 2009 are covered under the plan.
The plan provides 100% vesting after five vesting years of service and
for retirement compensation at age 65, with reduced compensation in
cases of retirement prior to age 62. The Company reserves the right to
discontinue the plan, but no change or discontinuance may affect the
pensions theretofore vested.

The pension plan has a trustee who is responsible for pension payments

to retirees and a separate pension fund manager responsible for
managing the plan’s assets. An independent actuary assists the
Company in performing the necessary actuarial valuations for the plan.

The plan assets consist of common stock and bonds of public

companies, U.S. government securities, cash and cash equivalents and
alternative investments. None of the plan assets are invested in common
stock or debt securities of the Company.

The following table lists components of net periodic pension benefit

cost for the year ended December 31:

(in thousands)

Service Cost–

Benefit Earned During the Period

Interest Cost on Projected Benefit Obligation
Expected Return on Assets
Amortization of Prior Service Cost:

From Regulatory Asset
From Other Comprehensive Income (1)

Amortization of Net Actuarial Loss:

From Regulatory Asset
From Other Comprehensive Income (1)

2019

2018

2017

5,491
14,412
(21,297)

6,459 $

13,452
(21,199)

5,629
14,139
(19,229)

5
9

4,642
114

16
—

7,135
183

120
3

5,090
125

Net Periodic Pension Cost (2)

3,376

6,046 $

5,877

(1) Corporate cost included in nonservice cost components of postretirement benefits.
2017
(2) Allocation of costs:

2019

2018

Service costs included in OTP capital

expenditures

1,365

1,542 $

1,094

Service costs included in electric operation

and maintenance expenses

3,994

4,756

4,400

Service costs included in other nonelectric

expenses

Nonservice costs capitalized
Nonservice costs included in nonservice cost
components of postretirement benefits

132
(526)

161
(99)

(1,589)

(314)

135
48

200

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

2017

2019

4.50%
7.25%

3.90%
7.50%

4.60%
7.50%

3.00%

See below See below
4.50%
3.50%
2.75%

4.50%
3.50%
2.75%

The following table presents amounts recognized in the consolidated

balance sheets as of December 31:

(in thousands)

Regulatory Assets:

Unrecognized Prior Service Cost
Unrecognized Actuarial Loss

Total Regulatory Assets

Accumulated Other Comprehensive Loss:

Unrecognized Prior Service Cost
Unrecognized Actuarial (Gain) Loss

Total Accumulated Other Comprehensive Loss

Noncurrent Liability

Funded status as of December 31:

2019

2018

—
120,592

5
104,891

$ 120,592

$ 104,896

—
(82)

(82)

55,004

9
137

146

58,659

(in thousands)

Accumulated Benefit Obligation

Projected Benefit Obligation
Fair Value of Plan Assets

Funded Status

2019

2018

$ (346,723)

$ (297,972)

$ (384,785)
329,781

$ (328,442)
269,783

$ (55,004)

$ (58,659)

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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, 2019:

(in thousands)

2019

2018

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

$ 269,783
52,640
22,500
(15,142)

$ 285,319
(21,334)
20,000
(14,202)

Fair Value of Plan Assets at December 31

$ 329,781

$ 269,783

Measurement Dates:

2019

2018

Net Periodic Pension Cost
End of Year Benefit Obligations

Market Value of Assets

January 1, 2019
January 1, 2019
projected to
December 31, 2019
December 31, 2019

January 1, 2018
January 1, 2018
projected to
December 31, 2018
December 31, 2018

Cash flows—The Company had no minimum funding requirement as of
December 31, 2019 but made discretionary plan contributions of
$11.2 million in January 2020.

The following benefit payments, which reflect expected future service,

19.3%

(7.3%)

as appropriate, are expected to be paid out from plan assets:

(in thousands)

Years

2020

2021

2022

2023

2024

2025-2029

$15,908

$16,477

$17,116

$17,768

$18,374

$98,994

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 adhere

to must be present in the investment program.

• All transactions undertaken on behalf of the Plan must be in the

best interest of plan participants and their beneficiaries.

(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.

Estimated Asset Return
Reconciliation of Projected Benefit Obligation:

Projected Benefit Obligation at January 1
Service Cost
Interest Cost
Benefit Payments
Actuarial Loss (Gain)

$ 328,442
5,491
14,412
(15,142)
51,582

$ 352,718
6,459
13,452
(14,202)
(29,985)

Projected Benefit Obligation at December 31

$ 384,785

$ 328,442

Weighted average assumptions used to determine benefit obligations

at December 31:

Discount Rate
Rate of Increase in Future Compensation Level:

Participants to Age 39
Participants Age 40 to Age 49
Participants Age 50 and Older

2019

3.47%

4.50%
3.50%
2.75%

2018

4.50%

4.50%
3.50%
2.75%

The assumed rate of return on pension fund assets used for the

determination of 2020 net periodic pension cost is 6.88%. The assumed
long-term rate of return on plan assets is based primarily on asset
category studies using historical market return and volatility data with
forward looking estimates based on existing financial market conditions
and forecasts of capital markets. Modest excess return expectations
versus some market indices are incorporated into the return projections
based on the actively managed structure of the investment programs
and their records of achieving such returns historically. The Company
reviews its rate of return on plan asset assumptions annually. The
assumptions are largely based on the asset category rate-of-return
assumptions developed annually with the Company’s pension plan
investment advisors, as well as input from actuaries who work with the
pension plan and benchmarking to peer companies with similar asset
allocation strategies.

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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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 or the SEI Energy Debt Collective Fund.

The Company’s pension plan asset allocations at December 31, 2019

and 2018, by asset category are as follows:

Asset Allocation

Global MGD Volatility Fund (mixed equities fund)
Large Capitalization Equity Securities
International Equity Securities
Emerging Markets Equity Fund
Small and Mid-Capitalization Equity Securities
SEI Dynamic Asset Allocation Fund

Equity Securities

Fixed-Income Securities and Cash
Other—SEI Energy Debt Collective Fund

2019

20.4%
11.3%
9.3%
4.2%
4.1%
3.1%

52.4%
44.7%
2.9%

2018

—
17.5%
17.0%
3.4%
6.7%
4.0%

48.6%
47.1%
4.3%

100.0%

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:

The investments held by the SEI Energy Debt Collective Fund on
December 31, 2019 and 2018 consist mainly of below investment grade
high yielding bonds and loans of U.S. energy companies which trade at
a discount to fair value. Redemptions are allowed semi-annually with a
95-day notice period, subject to fund director consent and certain gate,
holdback and suspension restrictions. Subscriptions are allowed monthly
with a three-year lock up on subscriptions. The Company invested
$10.0 million in the SEI Energy Debt Fund in July 2015. The fund’s assets
are valued in accordance with valuations reported by the fund’s
sub-advisor or the fund’s underlying investments or other independent
third-party sources, although SEI in its discretion may use other valuation
methods, subject to compliance with ERISA (as applicable). The fund’s
assets are valued as of the close of business on the last business day
of each calendar month and are available 30 days after the end of a
calendar quarter. On an annual basis, as determined by the investment
manager in its sole discretion, an independent valuation agent is
retained to provide a valuation of the illiquid assets of the fund and of
any other asset of the fund, as determined by the investment manager in
its sole discretion. The Company reviews and verifies the reasonableness
of the year-end valuations.

Executive Survivor and Supplemental Retirement Plan (ESSRP)
The ESSRP is an unfunded nonqualified benefit plan for executive
officers and certain key management employees that provides for
defined benefit payments to these employees on their retirement for life
or to their beneficiaries on their death. In addition, the ESSRP provides
for survivor benefit payments to beneficiaries of executive officers. On
December 26, 2019, the Company’s Board of Directors amended and
restated the ESSRP to provide for (i) the freezing of participation in the
restoration retirement benefit component of the ESSRP and (ii) the
freezing of benefit accruals under the restoration retirement benefit
component of the ESSRP for all participants, except those designated
as a grandfathered participant, effective December 31, 2019.

In connection with amending and restating the ESSRP, the Board of
Directors also approved the making of special employer contributions to
named participants in the Otter Tail Corporation Executive Restoration
Plus Plan (the ERPP) who will be affected by the ESSRP freeze in order
to offset the impact of the freeze for those participants.

The following table lists components of net periodic pension benefit

(in thousands)

2019

2018

cost for the year ended December 31:

Assets in Level 1 of the Fair Value Hierarchy
SEI Energy Debt Collective Fund at NAV

Total Assets

$ 320,241
9,540

$ 258,307
11,476

$ 329,781

$ 269,783

(in thousands)

Service Cost–

2019

2018

2017

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

418

408

290

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)

1,735

1,589

1,686

5
17

124
348

20
34

206
722

16
38

285
440

(in thousands)

Global MGD Volatility Fund (mixed equities fund)
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

2019

67,184
37,357
30,653

13,447
10,168
13,792
147,639
1

2018

—
47,198
45,912

17,971
10,929
9,197
127,098
2

Total Assets

$ 320,241

$ 258,307

Net Periodic Pension Cost (2)

$ 2,647

$ 2,979

2,755

(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:

2019

2018

2017

Service costs included in electric

operation and maintenance expenses

104

Service costs included in other

nonelectric expenses

Nonservice costs included in nonservice cost
components of postretirement benefits

314

309

196

2,229

2,571

2,465

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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

2019

4.46%
3.40%

2018

2017

3.85%
2.92%

4.60%
3.00%

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

2019

2018

—
2,170

2,170

20
1,768

1,788

(43,966)

$ (39,699)

1
9,170

9,171

64
6,455

6,519

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, 2019 and a statement of
the funded status as of December 31 of both years:

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.

In 2019, the Company elected to obtain post-65 prescription drug
subsidies for its non-union plan participants from a provider under the
provider’s employer group waiver plan. As a result, the Company will
no longer apply for prescription drug subsidies for these participants.
Based on the provider’s projected costs, the post-65 starting claim cost
assumption for non-union retirees was lowered by 27% and the
Medicare Part D reimbursement assumption was eliminated for these
participants. A portion of the cost savings were shared with retirees
through lower 2020 premiums. The net effect of these plan amendments
reduced the Company’s projected benefit obligation for this plan by
$20.9 million in 2019. Beginning in 2020, the net savings from the
changes will be recognized as a reduction to expense over 4.3 years,
the expected remaining service period to retirement-age eligibility for
active participants.

The following table lists components of net periodic postretirement

benefit cost for the year ended December 31:

(in thousands)

2019

2018

(in thousands)

2019

2018

2017

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)

Net Periodic Postretirement

Benefit Cost (2)

$ 1,286
3,083

$ 1,526
2,583

$ 1,425
2,712

—
—

1,571
38

1,648
42

(4)
4

936
19

$ 5,978

$ 5,799

$ 5,092

Effect of Medicare Part D Subsidy

$ (179)

(470) $

(561)

(1) Corporate cost included in nonservice cost components of postretirement benefits.
2017
(2) Allocation of cost:

2019

2018

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

320

364

277

935
31
1,167

1,124
38
1,020

1,114
34
712

components of postretirement benefits

3,525

3,253

2,955

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
Curtailments
Actuarial Loss (Gain)

—
—
1,475
(1,475)

—

39,699
418
1,735
(1,475)
(1,671)
5,260

—
—
1,505
(1,505)

—

42,308
408
1,589
(1,505)
—
(3,101)

Projected Benefit Obligation at December 31

43,966

39,699

Weighted average assumptions used to determine benefit obligations

at December 31:

Discount Rate
Rate of Increase in Future Compensation Level:

2019

3.36%
3.50%

2018

4.46%
3.40%

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

2020

2021

2022

2023

2024

2025-2029

$1,571

$1,681

$2,279

$2,680

$2,627

$13,976

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

Weighted average assumptions used to determine net periodic

Weighted average assumptions used to determine benefit obligations

postretirement benefit cost for the year ended December 31:

at December 31:

Discount Rate

2019

4.44%

2018

2017

3.81%

4.46%

Discount Rate

2019

3.43%

2018

4.44%

The following table presents amounts recognized in the consolidated

Assumed healthcare cost-trend rates as of December 31:

balance sheets as of December 31:

(in thousands)

Regulatory Asset:

Unrecognized Prior Service Credit
Unrecognized Net Actuarial Loss (Gain)

Net Regulatory Asset

Projected Benefit Obligation Liability—

Net Amount Recognized

Accumulated Other Comprehensive (Income) Loss:

Unrecognized Prior Service Credit
Unrecognized Net Actuarial Loss (Gain)

Accumulated Other Comprehensive

(Income) Loss:

2019

2018

(20,363)
35,322

14,959

—
18,094

18,094

(71,437)

$ (71,561)

(501)
184

—
(107)

(317)

(107)

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, 2019:

(in thousands)

2019

2018

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
Plan Amendments
Actuarial Loss

—
—
2,757
(7,164)
4,407

—

71,561
1,286
3,083
(7,164)
4,407
(20,864)
19,128

—
—
3,183
(6,684)
3,501

—

69,774
1,526
2,583
(6,684)
3,501
—
861

Projected Benefit Obligation at December 31

71,437

71,561

Reconciliation of Accrued Postretirement Cost:

Accrued Postretirement Cost at January 1
Expense
Net Company Contribution

$ (53,574)
(5,978)
2,757

$ (50,958)
(5,799)
3,183

Accrued Postretirement Cost at December 31

$ (56,795)

$ (53,574)

Healthcare Cost-Trend Rate Assumed for Next Year
Rate to Which the Cost-Trend Rate is Assumed to Decline
Year the Rate Reaches the Ultimate Trend Rate

6.72%
4.50%
2038

7.00%
4.50%
2038

2019

2018

Measurement Dates:

2019

2018

Net Periodic Postretirement Benefit Cost January 1, 2019
January 1, 2019
End of Year Benefit Obligations
projected to
December 31, 2019

January 1, 2018
January 1, 2018
projected to
December 31, 2018

Cash flows—The Company expects to contribute $3.3 million net of
expected employee contributions for the payment of retiree medical
benefits and Medicare Part D subsidy receipts in 2020. The Company
expects to receive a Medicare Part D subsidy from the Federal government
of approximately $0.1 million in 2020. 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

2020

2021

2022

2023

2024

2025-2029

$3,323

$3,470

$3,653

$3,720

$3,778

$19,852

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 $5,265,000 for
2019, $4,532,000 for 2018 and $4,211,000 for 2017.

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
$374,000 for 2019, $398,000 for 2018 and $612,000 for 2017.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

12. Fair Value of Financial Instruments

13. Property, Plant and Equipment

December 31, 2019

December 31, 2018

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:

Cash Equivalents—The carrying amount approximates fair value
because of the short-term maturity of those instruments.

(in thousands)

Electric Plant in Service

Production
Transmission
Distribution
General

Short-Term Debt—The carrying amount approximates fair value because
the debt obligations are short-term and the balances outstanding as of
December 31, 2019 and December 31, 2018 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.

December 31, 2019

December 31, 2018

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

(in thousands)

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

Net Plant

915,996
647,474
526,146
123,268

2,212,884
177,584

2,390,468

731,110

1,659,358

187,904
53,412
6,040

247,356
7,654

255,010

160,574

94,436

1,753,794

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

Cash and Cash Equivalents $ 21,199
Short-Term Debt
(6,000)
Long-Term Debt including

$ 21,199
(6,000)

861
(18,599)

Current Maturities

(689,764)

(742,279)

(590,174)

(601,513)

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

Electric Fixed Assets:
Production Plant
Transmission Plant
Distribution Plant
General Plant

Nonelectric Fixed Assets:

Equipment
Buildings and Leasehold Improvements

9
51
15
5

2
5

82
75
70
57

12
40

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

The Company’s deferred tax assets and liabilities were composed of

the following on December 31:

(in thousands)

2019

2018

14. Income Taxes

The total income tax expense differs from the amount computed by
applying the federal income tax rate (21% in 2019 and 2018, and 35% in
2017) to net income before total income tax expense for the following
reasons:

(in thousands)

Tax Computed at Federal Statutory Rate
Increases (Decreases) in Tax from:

State Income Taxes Net of Federal Income

Tax Expense

Differences Reversing in Excess

of Federal Rates

Permanent Differences, R&D Tax Credits,

2019

2018

2017

$ 21,901

$ 20,356

$ 34,893

3,561

5,210

4,368

(3,357)

(3,432)

551

Unitary Tax and Other Adjustments

(1,315)

(1,864)

(1,873)

North Dakota Wind Tax Credit Amortization—

Net of Federal Taxes

Corporate-owned Life Insurance
Excess Tax deduction—Equity Method

Stock Awards

Allowance for Funds Used During

Construction—Equity

Employee Stock Ownership Plan

Dividend Deduction

Investment Tax Credit Amortization
Federal Production Tax Credits (PTCs)
Section 199 Domestic Production

Activities Deduction

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

(1,033)
(749)

(1,033)
(3)

(850)
(845)

(744)

(708)

(751)

(501)

(431)

(322)

(281)
(41)
—

(298)
(98)
(3,111)

(509)
(164)
(7,527)

Deferred Tax Assets
Benefit Liabilities
Retirement Benefits Liabilities
Regulatory Tax Liability
North Dakota Wind Tax Credits
Cost of Removal
Federal PTCs
Differences Related to Property
Lease Liability
Vacation Accrual
Net Operating Loss Carryforward
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
Right of Use Asset
North Dakota Wind Tax Credits
Impact of State Net Operating Losses

on Federal Taxes

Other

36,246
36,206
35,700
31,611
25,604
20,017
6,979
5,733
1,884
1,860
408
344
(800)

33,967
32,664
33,228
32,570
21,787
32,101
6,842
—
1,919
2,489
449
3,218
(600)

$ 201,792

$ 200,634

$ (268,495)
(36,206)
(17,556)
(5,705)
(3,126)

$ (261,396)
(32,664)
(15,145)
—
(4,386)

(385)
(2,260)

(523)
(7,496)

$ (333,733)

$ (321,610)

$ (131,941)

$ (120,976)

—

(1,471)

Total Deferred Tax Liabilities

1,756

Deferred Income Taxes

Income Tax Expense

$ 17,441

$ 14,588

$ 27,256

Overall Effective Federal and State

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—

16.7%

15.0%

27.3%

5,156
1,333
8,859
3,167
—

$ 4,960
1,395
8,065
4,410
(3,111)

$ 4,434
1,128
25,648
4,587
(7,527)

Net of Federal Taxes

Investment Tax Credit Amortization

(1,033)
(41)

(1,033)
(98)

(850)
(164)

In November of 2018, eligibility period for OTP to earn federal PTCs
on its most recently purchased wind turbines ended. Prior to the lapse,
OTP earned federal PTCs as wind energy was 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 in 2017 and ending for the last of its PTC-eligible
wind farms in 2018. 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

Total

$ 17,441

$ 14,588

$ 27,256

available as of December 31, 2019:

Total Income Before Income Taxes

$ 104,288

$ 96,933

$ 99,695

(in thousands)

United States

Amount

2022-2032 2033-2038 2039-2043

Federal Tax Credits
State Net Operating Losses
State Tax Credits

$ 23,002
1,860
32,177

—
1,833
—

$ 22,220
27
2,643

782
—
29,534

The following table summarizes the activity related to the Company’s

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

2019

2018

2017

$ 1,282

684

891

—

339
(170)

778
(186)

(172)

143
(206)

Balance on December 31

$ 1,488

$ 1,282

684

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

The balance of unrecognized tax benefits as of December 31, 2019
would reduce the Company’s effective tax rate if recognized. The total
amount of unrecognized tax benefits as of December 31, 2019 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, 2019.

The Company and its subsidiaries file a consolidated U.S. federal

income tax return and various state income tax returns. As of
December 31, 2019, with limited exceptions, the Company is no longer
subject to examinations by taxing authorities for tax years prior to
2016 for federal and North Dakota income taxes and prior to 2015 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. 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 Company recognized the income tax effects of the TCJA in its

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.

15. Asset Retirement Obligations (AROs)

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 2019.
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, 2019 and 2018 are presented in the following
table:

(in thousands)

Asset Retirement Obligations

2019

2018

Beginning Balance
New Obligations Recognized
Adjustments Due to Revisions in Cash Flow Estimates
Accrued Accretion
Settlements

9,117
—
3,099
440
—

Ending Balance

$ 12,656

Asset Retirement Costs Capitalized

Beginning Balance
New Obligations Recognized
Adjustments Due to Revisions in Cash Flow Estimates
Settlements

2,983
—
3,099
—

8,719
—
—
398
—

9,117

2,983
—
—
—

Ending Balance

6,082

2,983

Accumulated Depreciation—

Asset Retirement Costs Capitalized

Beginning Balance
New Obligations Recognized
Adjustments Due to Revisions in Cash Flow Estimates
Depreciation Expense
Settlements

Ending Balance

Settlements

Original Capitalized Asset Retirement Cost—Retired
Accumulated Depreciation
Asset Retirement Obligation
Settlement Cost

Gain on Settlement—

Deferred Under Regulatory Accounting

1,034
—
—
163
—

1,197

None
—
—
—
—

—

915
—
—
119
—

1,034

None
—
—
—
—

—

16. Subsequent Events

Stock Incentive Awards
On February 12, 2020 the following stock incentive awards were
granted to officers under the 2014 Incentive Plan with an estimated
grant-date fair value of $3.3 million.

Award

Shares/Units Granted

Vesting

Restricted Stock Units Granted

15,300

25% per year through
February 6, 2024

Stock Performance Awards Granted:

Under Executive Agreement
Under Legacy Agreement

47,600
7,400

December 31, 2022
December 31, 2022

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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. Restricted stock units granted to executive officers and
certain key employees 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 55,000 shares. For target performance the
participants would earn an aggregate of 27,500 common shares for
achieving the target set for the Company’s 3-year average adjusted
ROE. The participants would also earn an aggregate of 27,500 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, 2020 through
December 31, 2022, 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, 2020
and the average closing price for the 20 trading days immediately
preceding January 1, 2023. Actual payment may range from zero to

150% of the target amount, or up to 82,500 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 2020 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)

2019

2018

2019

2018

2019

2018

2019

2018

Operating Revenues:

Electric:

Revenues from Contracts with Customers
Changes in Accrued Revenues under Alternative

$ 129,144

$ 123,825

$ 101,861

$ 105,284

$ 115,285

$ 105,749

$ 111,726

$ 115,779

Revenue Programs

(1,049)

(875)

369

(1,565)

(921)

(317)

2,633

2,318

Total Electric Revenues
Product Sales under Contracts with Customers

Total Operating Revenues
Operating Income
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

$ 128,095
117,877

$ 245,972
$ 39,569
$ 26,324
.66
$
.66
$
.35
$
39,657
39,903

$ 122,950
118,316

$ 102,230
126,973

$ 103,719
122,629

$ 114,364
114,288

$ 105,432
122,230

$ 114,359
101,317

$ 118,097
103,074

$ 241,266
$ 229,203
$ 37,615
$ 26,819
$ 26,215
$ 15,426
.66
$
.39
$
.66
$
.39
$
.335 $
$
.35
39,712
39,918

39,551
39,864

$ 226,348
$ 228,652
$ 30,105
$ 37,255
$ 18,696
$ 24,745
.47
$
.62
$
.47
$
.62
$
.335 $
$
.35
39,715
39,947

39,606
39,879

$ 227,662
$ 215,676
$ 38,262
$ 31,237
$ 23,273
$ 20,352
.59
$
.51
$
.58
$
.51
$
.335 $
$
.35
39,799
40,048

39,622
39,904

$ 221,171
$ 23,407
$ 14,161
.36
$
.35
$
.335
$

39,622
39,922

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE

[

ITEM 9B. OTHER INFORMATION

None.

]

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 2020
Annual Meeting. The information regarding executive officers and
family relationships is set forth in Item 3A of this report on Form 10-K.
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 2020 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
2020 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 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 2020 Annual Meeting.

None.

[

ITEM 9A. CONTROLS AND PROCEDURES

]

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, 2019,
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, 2019.

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, 2019 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
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,
2019. 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, 2019, 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 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 9 A N N UA L R E P O R T

[

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

]

The information required by this Item regarding security ownership is incorporated by reference to the information under “Security Ownership of
Certain Beneficial Owners” in the Company’s definitive Proxy Statement for the 2020 Annual Meeting.

EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information as of December 31, 2019 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

320,807 (1)
1,153 (3)

—

321,960

$
$

0.00
0.00
N/A

—

0.00

1,010,110 (2)
— (4)
363,195 (5)

—

1,373,305

(1) Includes 83,400, 81,000 and 62,497 performance-based share awards granted in 2019, 2018 and 2017, respectively, 93,240 restricted stock units outstanding as of December 31,
2019, and 670 stock units as part of the director deferred compensation program and excludes 40,605 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) Includes 13,432 shares subject to purchase for the six-month purchase period ended December 31, 2019, with the remainder of the shares to be issued based on employee’s

election to participate in the plan.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS, AND DIRECTOR INDEPENDENCE

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

[

]

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 2020 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 2020
Annual Meeting.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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, 2019 and 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
Consolidated Statements of Income for the Three Years Ended December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
Consolidated Statements of Comprehensive Income for the Three Years Ended December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
Consolidated Statements of Common Shareholders’ Equity for the Three Years Ended December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
Consolidated Statements of Capitalization, December 31, 2019 and 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

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
Income Taxes Receivable
Other

Total Current Assets

Investments in Subsidiaries
Notes Receivable from Subsidiaries
Deferred Income Taxes
Right of Use Assets—Operating
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
Current Operating Lease Liabilities
Other

Total Current Liabilities

Long Term Operating Lease 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 9 A N N UA L R E P O R T

2019

2018

4,959

—

2,144
117
—
1,487
1,050

9,757

860,646
79,251
25,505
637
35,503

1,931
117
1,167
—
3,482

6,697

787,869
79,422
21,100
—
31,547

$ 1,011,299

$ 926,635

6,000
183
7
89,611
156
9,473

105,430

533
44,042

79,812
781,482

861,294

9,215
172
7
60,626
—
9,994

80,014

—
37,814

79,944
728,863

808,807

$ 1,011,299

$ 926,635

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

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)

Cash Flows from Operating Activities
Net Cash Provided by Operating Activities

Cash Flows from Investing Activities

Investment in Subsidiaries
Debt Repaid by Subsidiaries
Cash Used in 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 (Repayments) Borrowings
Borrowings from (Repayments to) Subsidiaries
Proceeds from Issuance of Common Stock
Common Stock Issuance Expenses
Payments for Retirement of Capital Stock
Short-Term and Long-Term Debt Issuance Expenses
Payments for Retirement of Long-Term Debt
Dividends Paid

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.

2019

—
10,529

(10,529)

93,731
(4,863)
(306)
3,063
(1,297)
1,566

91,894

81,365
(5,482)

86,847

2018

—
9,916

(9,916)

91,446
(4,043)
(387)
2,839
(1,422)
550

88,983

79,067
(3,278)

82,345

2017

—
7,138

(7,138)

82,715
(4,270)
(244)
2,848
(1,215)
1,054

80,888

73,750
1,311

72,439

2019

2018

2017

52,263

56,947

50,205

(34,990)
1,338
(257)

(33,909)

(31)
(3,215)
28,985
20,338
(577)
(2,730)
(270)
(172)
(55,723)

(13,395)

4,959
—

4,959

(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

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

OTTER TAIL CORPORATION (PARENT COMPANY)
Notes to Condensed Financial Statements
For the years ended December 31, 2019, 2018 and 2017

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 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, 2019:

(in thousands)

Otter Tail Power Company
Northern Pipe Products, Inc.
Vinyltech Corporation
BTD Manufacturing, Inc.
T.O. Plastics, Inc.
Varistar Corporation
Otter Tail Assurance Limited

As of December 31, 2018:

(in thousands)

Otter Tail Power Company
Northern Pipe Products, Inc.
Vinyltech Corporation
BTD Manufacturing, Inc.
T.O. Plastics, Inc.
Varistar Corporation
Otter Tail Assurance Limited

Accounts
Receivable

Interest
Receivable

Current
Notes
Receivable

Long-Term
Notes
Receivable

Accounts
Payable

$ 2,056
—
4
—
—
—
84

—
8
17
77
15
—
—

2,144

117

—
—
—
—
—
—
—

—

—
5,351
11,500
52,000
10,400
—
—

$ 79,251

7
—
—
—
—
—
—

Accounts
Receivable

Interest
Receivable

Current
Notes
Receivable

Long-Term
Notes
Receivable

Accounts
Payable

$ 1,877
—
4
—
—
—
50

—
8
17
77
15
—
—

—
—
—
415
—
752
—

—
5,522
11,500
52,000
10,400
—
—

1,931

117

1,167

$ 79,422

7
—
—
—
—
—
—

Current
Notes
Payable

—
3,056
15,099
18,474
3,099
49,883
—

$ 89,611

Current
Notes
Payable

—
5,623
15,305
—
14,308
25,390
—

$ 60,626

Dividends
Dividends paid to Otter Tail Corporation (the Parent) from its subsidiaries were as follows:

(in thousands)

2019

2018

2017

Cash Dividends Paid to Parent by Subsidiaries

55,660

53,134

50,571

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.

100

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

3. Exhibits

The following Exhibits are filed as part of, or incorporated by reference into, this report.

Previously Filed

File No.

As Exhibit No.

2-A

2-B

2-C

3-A

3-B

4-A

10-K/A for year
ended 12/31/16

10-Q for quarter
ended 6/30/19

2-B

2-C

2.1

8-K filed 7/1/09

8-K filed 8/23/07

3.1

3.2

4.1

4-A-1

8-K filed 12/20/07 4.3

4-A-2

8-K filed 9/15/08

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.**/***

First Amendment to Asset Purchase Agreement and Turnkey Engineering, Procurement and Construction
Services Agreement dated June 11, 2019, with EDF Renewables Development, Inc., f/k/a, EDF Renewable
Development, Inc., Power Partners Midwest, LLC, EDF-RE US Development, LLC and Merricourt Power
Partners, 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.

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.

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-B-7

8-K filed 11/5/19

4.1

4-C

8-K filed 11/2/12

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.

Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2019, 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 Wells Fargo Bank, National Association, 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.

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

101

Previously Filed

File No.

As Exhibit No.

4-C-1

8-K filed 11/1/13

4.2

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

4-C-7

8-K filed 11/5/19

4.2

4-D

8-K filed 8/3/11

4.1

4-E

4-F

8-K filed 8/16/13

4.1

8-K filed 9/27/16

4.1

4-G

8-K filed 11/16/17

4.1

4-H

8-K filed 9/16/19

4.1

4-I

10-A

10-A-1

10-A-2

10-A-3

10-A-4

10-A-5

10-A-6

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-F

10-F-1

10-F-2

10-F-3

10-F-4

10.1

First Amendment to Second Amended and Restated Credit Agreement, dated as of October 29, 2013, among
Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of
America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank
National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent
and as a Bank, and Wells Fargo Bank, National Association and Union Bank, N.A., as Banks.

Second Amendment to Second Amended and Restated Credit Agreement, dated as of November 3, 2014,
among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank,
Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank,
KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation
Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.

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.

Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2019,
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.

Note Purchase Agreement, dated as of July 29, 2011, between Otter Tail Power Company and the
Purchasers named therein.

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.

Note Purchase Agreement dated as of November 14, 2017 between Otter Tail Power Company and the
Purchasers named therein.

Note Purchase Agreement dated as of September 12, 2019 between Otter Tail Power Company and the
Purchasers named therein.

Description of Securities

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.

102

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

Previously Filed

File No.

As Exhibit No.

10-B

10-Q for quarter
ended 6/30/15

10-C

2-61043

10-C-1

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

10.3

5-H

10-H-1

10-H-2

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.**
Agreement for Sharing Ownership of Coyote Station Generating Unit No. 1 by and between the Company,
Minnkota Power Cooperative, Inc., Montana-Dakota Utilities Co., Northwestern Public Service Company and
Minnesota Power & Light Company (dated as of July 1, 1977).

Supplemental Agreement No. One, dated as of November 30, 1978, to Agreement for Sharing
Ownership of Coyote Generating Unit No. 1.

Supplemental Agreement No. Two, dated as of March 1, 1981, to Agreement for Sharing Ownership of Coyote
Generating Unit No. 1 and Amendment No. 2 dated March 1, 1981, to Coyote Plant Coal Agreement.

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-Q/A for quarter
ended 6/30/13

10.1

Wind Energy Purchase Agreement dated May 9, 2013 between Otter Tail Power Company and Ashtabula
Wind III, LLC.**

10-E

10-F-1

10-F-1a

10-K for year
ended 12/31/02

10-K for year
ended 12/31/10

10-F-1b

8-K filed 4/17/14

10-F-2

10-F-3

10-F-4

8-K filed 12/27/19

10-Q for quarter
ended 9/30/11

10-Q for quarter
ended 9/30/16

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.*

10.5

10.1

Second Amendment of Deferred Compensation Plan for Directors (2003 Restatement), as amended.*

Executive Survivor and Supplemental Retirement Plan (2020 Restatement).*

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-F-7

10-F-8

10-K for year
ended 12/31/13

10-O-12

2014 Executive Annual Incentive Plan.*

333-195337

4.1

Otter Tail Corporation 2014 Stock Incentive Plan.*

10-K for year
ended 12/31/16

10-J-14

Summary of Non-Employee Director Compensation (2016).*

10-F-9

8-K filed 2/11/15

10-F-10 8-K filed 2/11/15

10-F-11

8-K filed 4/15/15

10-F-12

8-K filed 2/11/15

10.3

10.4

10.2

10.5

Form of Restricted Stock Unit Award Agreement (Executives).*

Form of Restricted Stock Unit Award Agreement (Legacy).*

Form of Restricted Stock Award Agreement for Directors.*

Otter Tail Corporation Executive Restoration Plus Plan, as Amended and Restated.*

10-F-12a 10-K for year

10-F-18a First Amendment of Otter Tail Corporation Executive Restoration Plus Plan.*

10-F-13

ended 12/31/17

10-K for year
ended 12/31/17

10-F-14 10-Q for quarter
ended 03/31/18

10-F-15

10-Q for quarter
ended 03/31/18

10-F-19

Summary of Non-Employee Director Compensation (2018).*

10.1

Form of 2018 Performance Award Agreement (Executives).*

10.2

Form of 2018 Performance Award Agreement (Legacy).*

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

103

Previously Filed

File No.

As Exhibit No.

10-F-16

10-F-17

10-K for year
ended 12/31/18

10-F-18

Form of 2018 Restricted Stock Award Agreement for Directors.*

10-F-19

Summary of Non-Employee Director Compensation (2019).*

10-G

8-K filed 11/8/19

1.1

Distribution Agreement dated November 8, 2019, between Otter Tail Corporation and KeyBanc
Capital Markets Inc.

10-H

10-I-1

10-I-2

10-I-3

10-I-4

10-I-5

10-I-6

10-J

21-A

23-A

24-A

31.1

31.2

32.1

32.2

101.SCH

101.CAL

101.LAB

101.PRE

101.DEF

104

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-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.

Inline XBRL Taxonomy Extension Schema Document.

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

Inline XBRL Taxonomy Extension Label Linkbase Document.

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

Inline XBRL Taxonomy Extension Definition Linkbase Document.

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*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.

***Certain information has 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.

]

104

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.

[

OTTER TAIL CORPORATION

]

/s/ Kevin G. Moug

Kevin G. Moug
Chief Financial Officer and Senior Vice President
(authorized officer and principal financial officer)

Dated: February 20, 2020

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 20, 2020

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

105

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.

2020 Annual Meeting of Shareholders

Monday, April 20, 2020 • 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. 2019
dividends were $1.40 per share, and the year-end yield was
2.7 percent. Total shareholder return grew at a compounded
average annual rate of 12.1 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.

2020 Common Dividend Dates

EX-DIVIDEND
February 13
May 14
August 13
November 12

Key Statistics

RECORD
February 14
May 15
August 14
November 13

PAYMENT
March 10
June 10
September 10
December 10

Nasdaq . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . OTTR
Year-end stock price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $51.29
Year-end market-to-book ratio. . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6
Annual dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.7%
Shares outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40.2 million
Market capitalization (as of December 31, 2019). . . . . $2.06 billion
2019 average daily trading volume . . . . . . . . . . . . . . . . . . . . . 84,142
Institutional holdings

(shares as of December 31, 2019). . . . . . . . . . . . . . . . . 21.6 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
BBB+
Stable

BBB
N.A.
Stable

BBB+
BBB+
Stable

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

106

OT T E R TA I L CO R P O R AT I O N 2 0 1 9 A N N UA L R E P O R T

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

Back: Kevin Moug, Paul Knutson, Chuck MacFarlane, Tim Rogelstad, and Jennifer Smestad

Front: Stephanie Hoff and John Abbott

NATHAN PARTAIN

KAREN BOHN

JOHN ERICKSON

STEVEN FRITZE

KATHRYN JOHNSON

DIRECTORS

CHARLES MACFARLANE

TIMOTHY O’KEEFE

JAMES STAKE

THOMAS WEBB

NATHAN I. PARTAIN
Chairman of the Board
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
Chief Executive Officer and
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)

DR. KATHRYN O. JOHNSON
C/CG—Hill City, South Dakota
Owner and Principal, Johnson
Environmental Concepts
(geochemical consulting firm)

CHARLES S. MACFARLANE
Fergus Falls, Minnesota
President and Chief
Executive Officer,
Otter Tail Corporation

TIMOTHY J. O’KEEFE
C/CG—Grand Forks, North Dakota
Retired Executive Vice President,
University of North Dakota
Alumni Association;
Retired Chief Executive 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)

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

We continue to achieve high
customer service metrics at our
operating companies. Northern
Pipe Products Extrusion Associate
Mustapha Harb (right), together
with Maintenance Technician Chad
Warne and Certified Quality Specialist
Carlos Espinoza (cover), help provide
innovative solutions and consistent
product and service excellence.

Otter Tail Power Company Construction
Site Supervisor Keith Kelly (left) and
Project Engineer Jacob Robinson, along
with Business Specialist Carol Westergard
(cover), help oversee our Astoria Station
and Merricourt Wind Energy Center
generation projects, which are paving
the way for a cleaner energy future.

[

S H A R E H O L D E R S E R V I C E S

[

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