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4-Traders Homepage  >  Equities  >  Nasdaq  >  Otter Tail Corporation    OTTR

Delayed Quote. Delayed  - 03/01 06:31:31 pm
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02/13 OTTER TAIL CORP : ex-dividend day
02/07 OTTER TAIL CORP : OTTR) Files An 8-K Results of Operations and Finan..
02/07 OTTER TAIL : posts 4Q profit
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OTTER TAIL : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-K)

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02/22/2017 | 06:03pm CET

Overview




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



Our strategy is to continue to grow our largest business, the regulated electric
utility, which will lower our overall risk, create a more predictable earnings
stream, improve our credit quality and preserve our ability to fund the
dividend. Over time, we expect the electric utility business will provide
approximately 75% to 85% of our overall earnings. We expect our manufacturing
and plastic pipe businesses will provide 15% to 25% of our earnings, and will
continue to be a fundamental part of our strategy. The actual mix of earnings
from continuing operations in 2016, 2015 and 2014 was 80%, 83% and 77%,
respectively, from our electric utility business and 20%, 17% and 23%,
respectively, from our manufacturing and plastic pipe businesses, including
unallocated corporate costs.



Reliable utility performance along with rate base investment opportunities over
the next five years will provide us with a strong base of revenues, earnings and
cash flows. We also look to our manufacturing and plastic pipe companies to
provide organic growth as well. Organic, internal growth comes from new products
and services, market expansion and increased efficiencies. We expect much of our
growth in these businesses in the next few years will come from utilizing
expanded plant capacity from capital investments made in previous years. We will
also evaluate opportunities to allocate capital to potential acquisitions in our
Manufacturing and Plastics segments. We are a committed long-term owner and
therefore we do not acquire companies in pursuit of short-term gains. However,
we will divest operating companies that no longer fit into our



36






strategy and risk profile over the long term. In the period 2011 through 2015 we
sold several businesses in execution of our announced strategy to realign our
portfolio of businesses and refocus our capital investment in the electric
utility.



On September 1, 2015 Miller Welding & Iron Works, Inc., a wholly owned
subsidiary of BTD Manufacturing, Inc. (BTD), acquired the assets of Impulse
Manufacturing, Inc. of Dawsonville, Georgia for $30.8 million in cash. A
post-closing reduction in the purchase price of $1.5 million was agreed to in
June 2016 resulting in an adjusted purchase price of $29.3 million. The acquired
business, now operating under the name BTD-Georgia, is a full-service, high-tech
metal fabricator located 30 miles north of Atlanta, Georgia. BTD-Georgia offers
a wide range of metal fabrication services ranging from simple laser cutting
services and high volume stamping to complex weldments and assemblies for metal
fabrication buyers and original equipment manufacturers.



Major growth strategies and initiatives in our future include:

· Planned capital budget expenditures of up to $936 million for the years 2017

through 2021, of which $862 million are for capital projects at Otter Tail

Power Company (OTP), including $315 million for renewable wind and solar

energy generation projects, $147 million for natural gas-fired generation to

replace Hoot Lake Plant capacity and $116 million for transmission projects

designated by the Midcontinent Independent System Operator, Inc. (MISO) as

Multi-Value Projects (MVPs). The remainder of OTP's 2017-2021 anticipated

capital expenditures is for asset replacements, additions and improvements

across OTP's generation, transmission, distribution and general plant. See

"Capital Requirements" section for further discussion.

· The $315 million planned investment for renewable wind and solar energy

generation projects includes the Merricourt Wind Project. In November 2016 OTP

signed agreements to purchase this 150-megawatt (MW) wind farm in southeastern

North Dakota that EDF Renewable Energy will design and build in 2019.

· 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 2016:



· Our Electric segment net income increased 3.0% to $49.8 million from $48.4

million in 2015.

· Our Manufacturing segment net income increased 34.1% to $5.7 million from $4.2

million in 2015.

· Our Plastics segment net income decreased 12.2% to $10.6 million from $12.1

    million in 2015.

  · Our net cash from continuing operations was $163.5 million.

· Capital Expenditures at OTP totaled $149.6 million as work continued on two

major MISO-designated MVPs.

· We raised net proceeds of $43.9 million from the sale of 1,014,115 shares of

common stock through our At-the-Market offering program and the issuance of

356,339 shares of common stock through our stock plans.

· We issued $130.0 million of long-term debt, paid $87.5 million to retire and

redeem long-term debt, including the retirement of $52.3 million of our 9.000%

notes due in December 2016, and reduced our short-term borrowings by $37.8

    million.




The following table summarizes our consolidated results of operations for the
years ended December 31:



(in thousands)                                    2016          2015
Operating Revenues:
Electric                                        $ 427,349     $ 407,039
Manufacturing                                     221,289       215,011
Plastics                                          154,901       157,754
Total Operating Revenues                        $ 803,539     $ 779,804
Net Income (Loss) From Continuing Operations:
Electric                                        $  49,829     $  48,370
Manufacturing                                       5,694         4,247
Plastics                                           10,628        12,108
Corporate                                          (4,114 )      (6,136 )

Total Net Income From Continuing Operations: $ 62,037 $ 58,589




37






Revenues in our Electric and Manufacturing business segments increased in 2016
compared with 2015. Major factors contributing to a $20.3 million (5.0%)
increase in Electric segment revenues between the years were increased
kilowatt-hour (kwh) sales to pipeline customers, increased revenue billed under
an interim rate increase in Minnesota net of an estimated potential refund, an
increase in transmission tariff revenues and a net increase in rider revenues
related to increased rider rates, offset by a decrease in revenues from the
recovery of fuel and purchased power costs due to a net reduction in those costs
in 2016. Manufacturing segment revenues increased $6.3 million (2.9%). Revenues
at BTD showed a net increase of $9.8 million, with revenues from BTD-Georgia,
acquired in September 2015, increasing by $15.4 million. Revenues from BTD's
other locations decreased $5.6 million, despite a $9.6 million increase in
revenue from sales of wind tower components from BTD's Illinois plant, due to
reduced sales to manufacturers of recreational, agricultural and industrial
equipment as demand for these products remained soft in 2016. Revenues at T.O.
Plastics, Inc. (T.O. Plastics) decreased $3.5 million, mainly due to the loss of
product sales to a major customer who began producing the product in-house in
2015. Plastics segment revenues were down $2.9 million (1.8%), despite a 10.5%
increase in pounds of polyvinyl chloride (PVC) pipe sold, mainly due to lower
PVC sales prices driven by lower raw material costs.



The $3.4 million increase in net income from continuing operations in 2016 compared with 2015 reflects the following:

· A $1.5 million increase in Electric segment net income due to increased net

interim rates in Minnesota and increased retail rider revenues which were

almost entirely offset by increased operating and income tax expenses.

· A $1.4 million increase in Manufacturing segment net income is mainly due to

sales of wind tower components from BTD's Illinois plant and improved

productivity and profits at BTD's Minnesota facilities.

· A $2.0 million net-of-tax decrease in Corporate net losses as a result of

receiving nontaxable benefit proceeds from corporate-owned life insurance and

    lower operating expenses due to lower benefit and insurance costs.




offset by:



· A $1.5 million decrease in Plastics segment net income mainly due to reduced

margins on pipe sales resulting from sales prices that declined more than the

   decline in raw material costs.



Following is a more detailed analysis of our operating results by business segment for the years ended December 31, 2016, 2015 and 2014, followed by a discussion of our financial position at the end of 2016 and our outlook for 2017.




Results of Operations



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



Intersegment Eliminations-Amounts presented in the following segment tables for
2016, 2015 and 2014 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)    2016      2015      2014
           Operating Revenues:
           Electric                                   $  34     $  92     $ 114
           Product Sales                                  -         4         -
           Cost of Products Sold                          6         9        45
           Other Nonelectric Expenses                    28        87        69




38






                                    Electric


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



                                                   %                               %
(in thousands)                   2016           change           2015           change           2014
Retail Sales Revenues         $   376,610               3     $   364,614               1     $   361,100
Wholesale Revenues -
Company Generation                  4,584              83           2,499             (78 )        11,160
Net Revenue - Energy
Trading Activity                        -            (100 )           186             (82 )         1,031
Other Revenues                     46,189              16          39,832              16          34,452
Total Operating Revenues      $   427,383               5     $   407,131               -     $   407,743
Production Fuel                    54,792              28          42,744             (36 )        67,216
Purchased Power - System
Use                                63,226             (19 )        78,150              19          65,848
Other Operation and
Maintenance Expenses              151,225               7         140,768              (1 )       141,936
Depreciation and
Amortization                       53,743              20          44,786               2          44,076
Property Taxes                     14,266               6          13,512               7          12,607
Operating Income              $    90,131               3     $    87,171              15     $    76,060
Electric kilowatt-hour
(kwh) Sales (in thousands)
Retail kwh Sales                4,750,421               3       4,593,604              (2 )     4,695,062
Wholesale kwh Sales -
Company Generation                190,288              77         107,510             (61 )       273,454
Wholesale kwh Sales -
Purchased Power Resold                  -            (100 )         5,547  
          (68 )        17,303
Heating Degree Days                 5,314              (6 )         5,633             (22 )         7,205
Cooling Degree Days                   451              (7 )           483              32             367




2016 Compared with 2015

The following table shows heating and cooling degree days as a percent of
normal:



                       2016       2015
Heating Degree Days     84.1 %      88.2 %
Cooling Degree Days     97.4 %     103.4 %



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



                                       2016 vs Normal      2015 vs Normal  

2016 vs 2015 Effect on Diluted Earnings Per Share $ (0.067 ) $ (0.044 ) $ (0.023 )

The $12.0 million increase in retail revenue includes:

· An $11.0 million increase in retail revenue related to a 9.56% interim rate

increase implemented in April 2016 in conjunction with OTP's 2016 general rate

    increase request in Minnesota.


· A $4.4 million increase in Environmental Cost Recovery (ECR) rider revenue due

to the recovery of additional investment and costs related to the operation of

the air quality control system (AQCS) at Big Stone Plant that was placed in

    service in December 2015.


· A $4.3 million increase in revenue related to an increase in retail kwh sales,

    mainly to pipeline customers.


· A $2.2 million increase in Transmission Cost Recovery (TCR) rider revenues

related to increased investment in transmission plant.

· A $1.7 million increase in Conservation Improvement Program (CIP) cost recovery

   revenues directly related to additional CIP activities.




offset by:



· A $5.7 million decrease in fuel and purchased power cost recovery revenues

mainly due to an 11.4% decrease in kwhs purchased partially offset by a 19.7%

    kwh increase in generation.


· A $3.6 million reduction in interim rate revenues recorded to provide for an

estimated refund related to a modification in OTP's original request and other

    expected outcomes in the pending Minnesota general rate case.


· A $1.6 million decrease in revenues related to decreased consumption due to

milder weather in 2016, evidenced by a 5.7% reduction in heating-degree days

and 6.6% reduction in cooling-degree days between the years.

· A $0.6 million decrease in Renewable Resource Adjustment (RRA) rider revenues

in North Dakota, which were down as a result of earning more federal Production

Tax Credits (PTCs) to pass back to customers due to a 3.6% increase in kwhs

   generated from wind turbines eligible for PTCs.




39






A $2.1 million increase in revenue from wholesale electric sales from company-owned generation was partially offset by a $1.5 million increase in fuel costs for wholesale generation, resulting in a $0.6 million increase in wholesale revenue net of fuel costs as increased plant availability in 2016 provided greater opportunity for OTP to respond to market demand.

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

· A $4.8 million increase in MISO transmission tariff revenues, mainly driven by

increased investment in regional transmission lines and related returns on and

recovery of Capacity Expansion 2020 (CapX2020) and MISO-designated MVP

investment costs and operating expenses.

· A $3.0 million increase in MISO network integration transmission service

revenues due to a regional transmission cooperative terminating its integrated

transmission agreement with OTP and joining the Southwest Power Pool (SPP) in

    2016.




offset by:



· A $1.3 million decrease in revenue related to a reduction in integrated

   transmission agreement revenues from two regional transmission providers
   related to the curtailment of services under one agreement and the
   discontinuance of another agreement.




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



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



Electric operating and maintenance expenses increased $10.5 million as a result of:

· $3.7 million in transmission expenses from the SPP as a result of a regional

transmission cooperative terminating its integrated transmission agreement

with OTP and joining the SPP in 2016.

· A $1.9 million increase in pollution control reagent costs at Big Stone Plant

and Coyote Station related to compliance with the Environmental Protection

Agency (EPA) power plant emission regulations.

· A $1.7 million increase in CIP program expenditures related to additional CIP

activities.

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

transmission investment by other MISO members.

· A $1.1 million increase in storm repair expenses associated with excessive

storm damage in OTP's Minnesota service area in July 2016 and in its North

    Dakota and South Dakota service areas in December 2016.

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



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



The $0.8 million increase in property tax expense is related to property additions in Minnesota and North Dakota in 2015.

2015 Compared with 2014

Retail sales revenue increased $3.5 million mainly as a result of:

· An $8.7 million increase in ECR rider revenues related to earning a return in

North Dakota and Minnesota on increasing amounts invested in the AQCS at Big

Stone Plant, earning a return on the Hoot Lake Plant Mercury and Air Toxics

Standards (MATS) project in North Dakota beginning in 2015, and the initiation

of an ECR rider in South Dakota in December 2014 to recover costs and earn a

return on amounts invested in the Big Stone Plant AQCS and Hoot Lake Plant

MATS projects.

· A $3.1 million increase in revenues recoverable under CIP riders related to an

    increase in CIP incentives awarded for 2014 program results as well as
    increases in CIP accruals for 2015 program incentives and recoverable
    expenditures.

· A $3.1 million increase in revenue from higher sales to pipeline customers.




40





· A $0.9 million increase in North Dakota RRA rider revenues.




offset by:


· A $4.8 million decrease in revenues related to a 2.2% decrease in retail kwh

sales mainly resulting from milder weather in 2015, evidenced by

heating-degree days that were 21.8% lower than in 2014 and 88.2% of normal.

Weather impacted diluted earnings per share negatively by approximately $0.08

per share in 2015 compared with 2014 and approximately $0.05 per share

compared with weather normalized sales for 2015.

· A $4.0 million decrease in revenues from the recovery of fuel and purchased

power costs due to the 2.2% decrease in retail kwh sales and a 3.0% decrease

    in the combined cost of fuel and purchased power per kwh purchased and
    generated.

  · A $3.0 million decrease in revenues due to lower sales to residential
    customers in North Dakota and Minnesota and lower sales to commercial
    customers in North Dakota.

· A $0.4 million reduction in Big Stone II cost recovery rider revenues in North

Dakota as the North Dakota share of costs were fully recovered by March 31,

    2014.




Wholesale electric revenues from company-owned generation decreased $8.7 million
as a result of a 60.7% reduction in wholesale kwh sales combined with a 43.0%
decrease in revenue per wholesale kwh sold. The decreases in wholesale kwh sales
and prices were driven by decreased wholesale market demand resulting from
milder weather in 2015. Also, OTP had fewer resources available for selling into
the wholesale market. Big Stone Plant was off line from March through July 2015
for an extended maintenance outage. Coyote Station operated at reduced load in
2015 due to ongoing repairs related to a December 2014 boiler feed pump failure
and fire. Hoot Lake Plant was curtailed in 2015 due to low market prices for
electricity, which was a factor contributing to a strategic decision to shut
down Hoot Lake Plant's Unit 3 for preventative maintenance in September 2015.
Generation from company-owned wind turbines was down 6.0% from 2014, primarily
due to lower average wind speeds in the first half of 2015. The decrease in
wholesale prices for electricity was due, in part, to lower prices for natural
gas used in the generation of electricity in 2015 compared with 2014.



Net revenue from energy trading activities decreased $0.8 million as a result of
OTP discontinuing its trading activities not directly associated with serving
retail customers in December 2014 due to a lack of market activity and
profitable trading opportunities.



Other electric revenues increased $5.4 million, primarily as a result of an
increase in MISO transmission tariff revenues related to increased investment in
regional transmission projects including returns on and recovery of CapX2020 and
MISO-designated MVP investment costs and operating expenses.



Production fuel costs decreased $24.5 million as a result of a 39.3% decrease in
kwhs generated from OTP's steam-powered and combustion turbine generators
primarily due to the factors discussed above. The cost of purchased power to
serve retail customers increased $12.3 million due to a 55.7% increase in kwhs
purchased, partially offset by a 23.8% decrease in the cost per kwh purchased.
The increase in power purchases for retail sales was necessitated by the reduced
availability of company-owned generating capacity discussed above. The decreased
cost per kwh purchased was driven by lower market demand due to milder weather
in 2015 in combination with lower prices for natural gas used in the generation
of electricity.


Electric operating and maintenance expenses decreased $1.2 million reflecting:

· A $3.0 million net reduction in generation plant operating and maintenance

costs between the years as costs incurred in 2014 at Hoot Lake Plant and

Coyote Station were more than the maintenance costs incurred at Big Stone

Plant in 2015. Although kwh generation decreased for all three plants in 2015,

work done on the plants in 2014 was more operating and maintenance in nature

while more capitalized projects were completed in 2015. Also, with the plants

generating fewer kwhs in 2015, operating costs were lower in 2015.

· A $1.4 million reduction in travel related expenses as a result of increased

vehicle usage on capital projects and lower fuel prices.

· A $0.7 million increase in capitalized administrative and general expenses due

to more time being spent on capital projects.

· A $0.4 million reduction in the North Dakota share of Big Stone II costs being

amortized as the North Dakota share of costs were fully recovered by March 31,

2014.

· An expense of $0.3 million recorded in June 2014 related to OTP not earning a

    return on the deferred recovery of the Minnesota share of Big Stone II
    abandoned transmission plant costs.




offset by:



41






  · A $3.8 million increase in MISO transmission tariff charges related to

increasing investments by other transmission owners in regional CapX2020 and

    MISO-designated MVP transmission projects.

  · A $0.9 million increase in Minnesota CIP expenditures and new program
    implementation costs.




Depreciation expense increased $0.7 million as a result of increased investment
in transmission, distribution and general plant placed in service in 2014 and
2015.


The $0.9 million increase in property tax expense primarily is due to increased property valuations and transmission plant additions in Minnesota.



                                 Manufacturing


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




                                                   %                         %
  (in thousands)                    2016        change        2015         change        2014
  Operating Revenues              $ 221,289           3     $ 215,011           (2 )   $ 219,583
  Cost of Products Sold             171,732           -       171,956            2       169,033
  Lease Exit Costs                        -           -             -            -         2,843
  Other Operating Expenses           21,994           4        21,116            3        20,497
  Depreciation and Amortization      15,794          33        11,853           13        10,518
  Operating Income                $  11,769          17     $  10,086          (40 )   $  16,692




2016 Compared with 2015

The increase in revenues in our Manufacturing segment in 2016 compared with 2015 relates to the following:

· Revenues at BTD increased $9.8 million, including:

o A $15.4 million increase in revenues at BTD-Georgia as a result of BTD owning

and operating this plant for the entire year of 2016 compared to four months in

   2015.




o A $9.6 million increase in revenues mainly related to the production of wind

   tower components.




offset by:



o A $15.2 million decrease in revenues related to lower sales to manufacturers of

recreational and agricultural equipment due to softness in end markets served

   by those manufacturers.



· Revenues at T.O. Plastics decreased $3.5 million, including:

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

customer insourcing product into its own manufacturing facilities.

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

execution challenges, including lower sales to a major distributor.




offset by:


o A net $0.1 million increase in sales of other products in the industrial and

   life sciences markets.



The decrease in cost of products sold in our Manufacturing segment includes the following:

· Cost of products sold at BTD increased $1.7 million. This includes a $15.5

million increase in cost of products sold at BTD-Georgia, offset by a $13.8

million net decrease in cost of products sold at BTD's other facilities. The

$13.8 million decrease is related to the decrease in sales, partially offset by

an increase in costs of products sold at BTD's Illinois plant as a result of

   the increase in the production of wind tower components.



· Cost of products sold at T.O. Plastics decreased $1.9 million related to the

   decrease in sales.



Gross margins at BTD were positively impacted in 2016 by changes in customer product mix between periods.

The $0.9 million increase in operating expenses in our Manufacturing segment includes the following:

· Operating expenses at BTD increased $1.4 million, of which $1.2 million was due

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



· Operating expenses at T.O. Plastics decreased $0.4 million, primarily as a

   result of a $0.5 million decrease in selling expenses.




42
The $3.9 million increase in depreciation and amortization expenses in our
Manufacturing segment includes a $2.3 million increase at BTD-Georgia and a $1.8
million increase at BTD's other plants mainly as a result of placing new assets
in service in Minnesota in 2015 and 2016. Depreciation expense at T.O. Plastics
decreased $0.2 million between the years.



2015 Compared with 2014

The decrease in revenues in our Manufacturing segment in 2015 compared with 2014 relates to the following:

· Revenues at BTD decreased $6.6 million (3.5%) due to the following:

o An $8.6 million decrease in sales, mainly to manufacturers of oil and gas

exploration and extraction equipment as a result of a reduction in drilling

    activity related to low oil prices.


o A $3.2 million decrease in sales of scrap metal due to a reduction in scrap

metal prices and a reduction in scrap volume related to lower production and

    sales volumes between years.


o A $2.1 million decrease in sales to manufacturers of agricultural equipment

related to continued softness in the agricultural industry.

o A $1.5 million reduction in tooling revenues.

o Offset by $8.8 million in sales at BTD-Georgia, acquired on September 1, 2015.

  · Revenues at T.O. Plastics increased $2.0 million (6.1%) reflecting:

o A $1.4 million increase in sales of horticultural containers.

o A $0.5 million increase in sales of custom products.

o A $0.1 million increase in sales of various other products to industrial

   customers.



The increase in cost of products sold in our Manufacturing segment relates to the following:

· Cost of products sold at BTD decreased $0.4 million, reflecting an $8.7

million decrease in costs related to decreased sales, offset by $8.3 million

in costs incurred at BTD-Georgia from September through December 2015.

· Cost of products sold at T.O. Plastics increased $3.3 million due to increases

in material, labor and freight costs related to the increase in sales at T.O.

   Plastics.




The $2.8 million reduction in Manufacturing segment operating expenses related
to the lease exit costs incurred in 2014, was partially offset by $0.6 million
in operating expenses incurred at BTD-Georgia from September through December
2015. Labor and benefit expense increases of $1.0 million at BTD were mostly
offset by a $0.9 million reduction in labor and benefit expenses at T.O.
Plastics between the years.



Depreciation and amortization expense at BTD-Georgia from September through December 2015 was approximately $1.0 million. A $0.6 million increase in depreciation expense at BTD related to recent asset additions under its Minnesota facilities expansion plan was partially offset by a $0.3 million decrease in depreciation expense at T.O. Plastics as a result of certain assets reaching the end 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)                    2016         change        2015         change        2014
Operating Revenues              $ 154,901           (2 )   $ 157,758           (8 )   $ 172,050
Cost of Products Sold             123,496            -       123,085          (12 )     139,081
Other Operating Expenses            9,402           (5 )       9,849            6         9,292
Depreciation and Amortization       3,861            9         3,552            6         3,364
Operating Income                $  18,142          (15 )   $  21,272            5     $  20,313




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



43





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.



2015 Compared with 2014

The $14.3 million decrease in Plastics segment revenues is the result of a 7.0%
decrease in the price per pound of pipe sold in combination with a 1.4% decrease
in pounds of PVC pipe sold. The decrease in sales are due in part to delayed
purchases related to falling resin prices and in part to reduced demand in the
region of the United States between the Mississippi River and the Rocky Mountain
states, especially in Texas where soft markets were exacerbated by severe spring
flooding. The $16.0 million decrease in costs of products sold is mainly due to
a 10.2% decrease in the cost per pound of pipe sold as a result of lower resin
prices. The $0.6 million increase in operating expenses was mainly related to
increased wage and benefit costs.



                                   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)                        2016        change       2015        change        2014
Airplane Rent and Lease Exit Costs   $     -            -     $     -      
     -     $  3,012
Other Operating Expenses               8,896           (3 )     9,143          (12 )     10,406
Depreciation and Amortization             47          (73 )       172           48          116



Corporate operating expenses decreased $0.2 million in 2016 as compared to 2015
as a result of decreased expenditures for contracted services and a decrease in
claims at our captive insurance company, partially offset by a decrease in
expenses allocated to OTP.



Corporate operating expenses decreased $4.3 million in 2015 compared with 2014 primarily due to:

· A $3.0 million reduction in airplane operating lease expense related to the

early termination of an airplane lease in the second quarter of 2014, as

divestitures had reduced the need for the airplane. The cost to terminate the

lease early was approximately $2.5 million or a net-of-tax impact on diluted

    earnings per share of ($0.04).


· A $0.8 million reduction in insurance costs at our captive insurance company

related to lower claims activity in 2015.




 · A $0.5 million decrease in labor expense due to a reduction in employees in
   2015.




                         CONSOLIDATED INTEREST CHARGES



                                   %                        %
(in thousands)       2016       change        2015       change        2014
Interest Charges   $ 31,886           2     $ 31,160           5     $ 29,648



The $0.7 million increase in interest charges in 2016 compared with 2015 is due
to an increase in interest expense on short-term debt at OTP as a result of a
$24.7 million increase in OTP's daily average balance of short-term debt
outstanding between the years and a $0.2 million decrease in capitalized
interest expense. The increase in OTP's use of short-term borrowing is related
to its increasing investment in two major MVP transmission line projects under
construction.


The $1.5 million increase in interest charges in 2015 compared with 2014 is mainly due to:

· A $1.3 million increase in interest expense incurred in January and February

of 2015 at OTP related to the February 27, 2014 issuance of $60 million

aggregate principal amount of OTP's 4.68% Series A Senior Unsecured Notes due

February 27, 2029 and $90 million aggregate principal amount of OTP's 5.47%

Series B Senior Unsecured Notes due February 27, 2044.

· A $19.6 million increase in the daily average balance of short-term debt

   outstanding in 2015 compared with 2014.




44






                           Consolidated OTHER INCOME



                                            %                       %
            (in thousands)    2016       change       2015        change       2014
            Other Income     $ 2,905          33     $ 2,177          (39 )   $ 3,557



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

The $1.4 million decrease in other income in 2015 compared with 2014, includes:

· A $0.8 million gain on the sale of an investment in tax-credit-qualified low

   income housing rental property in 2014 that was not duplicated in 2015.



· A $0.3 million reduction in other income at OTP related to reductions in

allowance for equity funds used in construction (AFUDC) and carrying charges

earned on funds invested in Minnesota CIP prior to recovery, in alignment with

   a decrease in short-term borrowing rates.




 · A $0.2 million reduction in corporate-owned life insurance cash surrender value
   increases.




                           Consolidated Income Taxes



Income tax expense - continuing operations was $20.1 million in 2016 compared
with $21.6 million in 2015 and $16.6 million in 2014. The following table
provides a reconciliation of income tax expense - continuing operations
calculated at the federal statutory rate on income from continuing operations
before income taxes reported on our consolidated statements of income:



                                                        For the Year Ended December 31,
(in thousands)                                       2016              2015            2014
Tax Computed at Federal Statutory Rate -          $    28,741       $    28,081     $   25,704
Continuing Operations
Increases (Decreases) in Tax from:
Federal PTCs                                           (7,175 )          (6,962 )       (7,517 )
State Income Taxes Net of Federal Income Tax            2,848             4,945          1,993
Expense
North Dakota Wind Tax Credit Amortization - Net          (850 )            (850 )         (849 )
of Federal Taxes
Corporate-owned Life Insurance                           (680 )            (167 )         (354 )
Dividend Received/Paid Deduction                         (537 )            (560 )         (622 )
Section 199 Domestic Production Activities               (482 )               -         (1,026 )
Deduction
Investment Tax Credit Amortization                       (350 )            (571 )         (597 )
AFUDC - Equity                                           (280 )            (426 )         (505 )
Differences Reversing in Excess of Federal                 77            (1,143 )         (106 )
Rates
Permanent and Other Differences                        (1,231 )            (705 )          436
Total Income Tax Expense - Continuing             $    20,081       $    21,642     $   16,557
Operations
Effective Income Tax Rate - Continuing                   24.5 %           
27.0 %         22.5 %
Operations



Federal PTCs are recognized as wind energy is generated based on a per kwh rate
prescribed in applicable federal statutes. OTP's kwh generation from its wind
turbines eligible for PTCs increased 3.6% in 2016 compared with 2015. OTP's kwh
generation from its wind turbines eligible for PTCs decreased 7.4% in 2015
primarily due to lower average wind speed in 2015 compared with 2014. North
Dakota wind energy credits are based on dollars invested in qualifying
facilities and are being recognized on a straight-line basis over 25 years.


                            DISCONTINUED OPERATIONS


On April 30, 2015 we sold Foley Company (Foley) for $12.0 million in cash, plus
$6.3 million in adjustments for working capital and other related items received
in October 2015, less $1.0 million in selling expenses. On February 28, 2015 we
sold the assets of AEV, Inc. for $22.3 million in cash, plus $0.6 million in
adjustments for working capital and fixed assets received in October 2015, less
$0.8 million in selling expenses. Foley and AEV, Inc were formerly included
in
our Construction segment.



45






On February 8, 2013 we completed the sale of substantially all the assets of our
dock and boatlift company, formerly included in our Manufacturing segment. On
November 30, 2012 we completed the sale of the assets of our wind tower
manufacturing business. This business was the only remaining entity in our
former Wind Energy segment.



Our Wind Energy and Construction segments were eliminated as a result of the
sales of our wind tower manufacturing business, Foley and AEV, Inc. The
financial position, results of operations and cash flows of Foley, AEV, Inc.,
our wind tower manufacturing business and our dock and boatlift company are
reported as discontinued operations in our consolidated financial statements.
Following are the results of discontinued operations by entity for the years
ended December 31, 2016, 2015 and 2014:



                                                             Wind         Dock and      Intercompany
                                                             Tower        Boatlift      Transactions
(in thousands)                 Foley        AEV, Inc.      Business       Business       Adjustment         Total
2016 Net (Loss) Income        $   (114 )   $        (5 )   $     454     $      (51 )   $           -     $     284
2015 Net (Loss) Income        $ (5,489 )   $     6,216     $     344     $     (580 )   $         265     $     756
2014 Net (Loss) Income        $ (3,034 )   $     2,621     $     (11 )   $ 
    274     $         990     $     840




Foley and AEV, Inc. entered into fixed-price construction contracts. Revenues
under these contracts were recognized on a percentage-of-completion basis. The
method used to determine the progress of completion was based on the ratio of
costs incurred to total estimated costs on construction projects. An increase in
estimated costs on one large job in progress at Foley in excess of previous
period cost estimates resulted in pretax charges of $4.4 million in 2015.



Impact of Inflation



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



Our Manufacturing and Plastics segments consist entirely of businesses whose
revenues are not subject to regulation by ratemaking authorities. Increased
operating costs are reflected in product or services pricing with any
limitations on price increases determined by the marketplace. Raw material
costs, labor costs, fuel and energy costs and interest rates are important
components of costs for companies in these segments. Any or all of these
components could be impacted by inflation or other pricing pressures, with a
possible adverse effect on our profitability, especially where increases in
these costs exceed price increases on finished products. In recent years, our
operating companies have faced strong inflationary and other pricing pressures
with respect to steel, fuel, resin, and health care costs, which have been
partially mitigated by pricing adjustments.



Liquidity


The following table presents the status of our lines of credit as of December 31, 2016 and December 31, 2015:



                                                      In Use on         Restricted due to       Available on       Available on
                                                     December 31,          Outstanding          December 31,       December 31,
(in thousands)                      Line Limit           2016           Letters of Credit           2016               2015
Otter Tail Corporation Credit
Agreement                          $    130,000     $            -     $                 -     $      130,000     $       90,334
OTP Credit Agreement                    170,000             42,883                      50            127,067            148,694
Total                              $    300,000     $       42,883     $                50     $      257,067     $      239,028



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



We believe our financial condition is strong and our cash, other liquid assets,
operating cash flows, existing lines of credit, access to capital markets and
borrowing ability because of investment-grade credit ratings, when taken
together, provide adequate resources to fund ongoing operating requirements and
future capital expenditures related to expansion of existing businesses and
development of new projects. On May 11, 2015 we filed a shelf registration
statement with the Securities and Exchange Commission (SEC) under which we may
offer for sale, from time to time, either separately or together in any
combination, equity, debt or other securities described in the shelf
registration statement, which expires on May 11, 2018. On



46






May 11, 2015, we entered into a Distribution Agreement with J.P. Morgan
Securities LLC (JPMS) under which we may offer and sell our common shares from
time to time through JPMS, as our distribution agent, up to an aggregate sales
price of $75 million through an At-the-Market offering program. We sold 36,403
shares at the end of the third quarter of 2016 under this program that were
settled in October 2016 and received proceeds of $1,256,000 net of $16,000
in
commissions paid to JPMS.



Equity or debt financing will be required in the period 2017 through 2021 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 8
to consolidated financial statements for more information. The decision to
declare a dividend is reviewed quarterly by the board of directors. On February
2, 2017 our board of directors increased the quarterly dividend from $0.3125 to
$0.32 per common share.


2016 Cash Flows Compared with 2015 Cash Flows


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



· An $18.2 million decrease in cash used for accounts payable and other current

liabilities at OTP, reflecting higher levels of payables in December 2016 for

coal deliveries and transmission services related to the colder temperatures in

December 2016 and the payment, in January 2015, of large billings for coal

   transportation, coal and power purchased in December 2014.



· A $10.7 million decrease in cash used for accounts payable and other current

liabilities at the plastic pipe companies related to an increase in year-end

   resin purchases in 2016 compared to 2015.



· A $7.3 million decrease in cash used for interest payable and income taxes

receivable between the years, mainly related to having made a $4.0 million

estimated tax payment in December 2015 that was refunded in the first quarter

of 2016, as a five-year extension of bonus depreciation for income taxes,

approved on December 18, 2015, resulted in a lower federal income tax liability

   for the Company in 2015.




offset by:



· A $2.3 million increase in unbilled revenues at OTP between the years resulting

from the 2016 increase in interim rates in Minnesota and increased kwh sales

   due to colder weather in December 2016 compared with December 2015.



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



Net cash used in financing activities of continuing operations was $4.1 million
in 2016 compared with net cash provided by financing activities of $38.1 million
in 2015. Financing activities in 2016 included:



· $80.0 million in proceeds from the issuance of our 3.55% Guaranteed Senior

   Notes due December 15, 2026 in December 2016.



 · $50.0 million borrowed under our term loan agreement in February 2016.

· $32.8 million in net proceeds from the issuance of 1,014,115 shares of common

   stock under the Company's At-the-Market offering program.



· $11.1 million in net proceeds from the issuance of 356,399 shares of common

stock under the Company's automatic dividend reinvestment and share purchase

   plans.




offset by:



· The repayment of the $52.3 million balance of our 9.000% notes due in December

   2016.



· A $41.2 million reduction of short-term borrowings and checks written in excess

   of cash.




47






· The repayment of $35.0 million of funds borrowed in February 2016 under our

   term loan agreement.



· $48.2 million in common stock dividend payments.





The outstanding short-term borrowings that were paid down were, in part, used to
fund the expansion of BTD's Minnesota facilities in 2015 and the September 1,
2015 acquisition of BTD-Georgia. See note 6 to the Company's consolidated
financial statements for further information on stock issuances and retirements
in 2016.


2015 Cash Flows Compared with 2014 Cash Flows

Cash provided by operating activities from continuing operations was $131.5
million in 2015 compared with $125.8 million in 2014. Contributing to the $5.7
million increase in cash provided by continuing operations between the periods
were:


· A $10.0 million decrease in discretionary contributions to the Company's

   pension plan.



· A $2.3 million increase in depreciation expense.

· A $1.6 million increase in net income from continuing operations.




offset by:


· $7.2 million in cash used to decrease accounts payable at OTP in 2015 partly

related to power purchases and repair services incurred in connection with the

   boiler pump failure and fire at Coyote Station in December 2014.



In continuing operations, net cash used in investing activities was $193.6
million in 2015 compared with $163.9 million in 2014. The purchase of the assets
of BTD-Georgia for $30.8 million on September 1, 2015 was the main factor
contributing to the $29.7 million increase in cash used in investing activities
of continuing operations between the periods. A $3.4 million decrease in cash
used for capital expenditures includes a $13.1 million reduction in capital
expenditures at OTP as several major projects were completed and placed in
service in 2015, including two CapX2020 transmission line projects and the new
AQCS at Big Stone Plant, partially offset by a $9.0 million increase in cash
used for capital expenditures in our Manufacturing segment, mainly at BTD as it
moved forward with its project to expand and realign its Minnesota production
and warehouse facilities.



Investing activities of discontinued operations in 2015 includes cash proceeds,
net of selling expenses, of $22.1 million from the sale of AEV, Inc. and $17.3
million from the sale of Foley, partially offset by $1.8 million in cash used in
investing activities of discontinued operations, mainly related to the purchase
by AEV, Inc. of assets being leased under operating leases prior to the assets
being sold.



Net cash provided by financing activities of continuing operations was $38.1
million in 2015 compared with $49.7 million in 2014. Net cash provided by
financing activities in 2015 includes $69.8 million in short-term borrowings
used to fund a portion of our capital expenditures and the acquisition of
BTD-Georgia. Net cash proceeds of $13.8 million from the issuance of common
stock under our At-the-Market offering program and various stock purchase and
dividend reinvestment plans were also used to fund a portion of our capital
expenditures. See note 6 to the Company's consolidated financial statements for
further information on stock issuances and retirements in 2015. Cash used for
common stock dividend payments totaled $46.2 million in 2015.



[[Image Removed]] [[Image Removed]]




48






Capital Requirements



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 $161.3 million in 2016, $160
million in 2015 and $164 million in 2014. Estimated capital expenditures for
2017 are $149 million. Total capital expenditures for the five-year period 2017
through 2021 are estimated to be approximately $936 million, which includes $315
million for renewable wind and solar energy generation projects, $147 million
for natural gas-fired generation to replace Hoot Lake Plant capacity and $116
million for OTP transmission projects designated by the MISO as MVPs.



The breakdown of 2014, 2015 and 2016 actual cash used for capital expenditures and 2017 through 2021 estimated capital expenditures by segment is as follows:



   (in millions)   2014      2015      2016      2017      2018      2019      2020      2021       2017-2021
   Electric        $ 149     $ 136     $ 150     $ 135     $ 173     $ 346     $ 130     $  78     $       862
   Manufacturing      11        20         8        10        13        11        10        10              54
   Plastics            4         4         3         4         4         4         4         4              20
   Total           $ 164     $ 160     $ 161     $ 149     $ 190     $ 361     $ 144     $  92     $       936



The following table summarizes our contractual obligations at December 31, 2016
and the effect these obligations are expected to have on our liquidity and cash
flow in future periods.



                                                      Less than           1-3           3-5       More than
(in millions)                             Total          1 Year         Years         Years         5 Years
Coal Contracts (required minimums)     $    671     $        31     $      44     $      45     $       551
Debt Obligations                            584              76            15           141             352
Interest on Debt Obligations                337              27            50            50             210
Capacity and Energy Requirements            277              24            49            38             166
Postretirement Benefit Obligations          100               5           
11            11              73
Other Purchase Obligations                   85              74            11             -               -
Operating Lease Obligations                  40               7             9             7              17

Total Contractual Cash Obligations $ 2,094 $ 244 $ 189

           292     $     1,369




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



CAPITAL 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 2017 through 2021 given the expansion plans
related to our Electric segment to fund construction of new rate base and
transmission investments, in the event we decide to reduce borrowings under our
lines of credit, to refund or retire early any of our presently outstanding
debt, to complete acquisitions or for other corporate purposes. There can be no
assurance that any additional required financing will be available through bank
borrowings, debt or equity financing or otherwise, or that if such financing is
available, it will be available on terms acceptable to us. If adequate funds are
not available on acceptable terms, our businesses, results of operations and
financial condition could be adversely affected.



Under our shelf registration statement filed with the SEC we may offer for sale,
from time to time, either separately or together in any combination, equity,
debt or other securities described in the shelf registration statement, until
May 11, 2018.


Under our At-the-Market offering program, we may offer and sell our common shares from time to time through JPMS, as our distribution agent, up to an aggregate sales price of $75 million, of which $39.2 million remained available at December 31, 2016. Under the Distribution Agreement with JPMS, we will designate the minimum price and maximum



49





number of shares to be sold through JPMS on any given trading day or over a
specified period of trading days, and JPMS will use commercially reasonable
efforts to sell such shares on such days, subject to certain conditions. We are
not obligated to sell and JPMS is not obligated to buy or sell any of the shares
under the Agreement.



Short-Term Debt


The following table presents the status of our lines of credit as of December 31, 2016 and December 31, 2015:



                                                      In Use on         Restricted due to       Available on       Available on
                                                     December 31,          Outstanding          December 31,       December 31,
(in thousands)                      Line Limit           2016           Letters of Credit           2016               2015
Otter Tail Corporation Credit
Agreement                          $    130,000     $            -     $                 -     $      130,000     $       90,334
OTP Credit Agreement                    170,000             42,883                      50            127,067            148,694
Total                              $    300,000     $       42,883     $                50     $      257,067     $      239,028




Under the Otter Tail Corporation Credit Agreement (as defined below), the
maximum amount of debt outstanding in 2016 was $63,757,000 on January 4, 2016
and the average daily balance of debt outstanding during 2016 was $16,200,000.
The weighted average interest rate paid on debt outstanding under the Otter Tail
Corporation Credit Agreement during 2016 was 2.3% compared with 2.0% in 2015.
Under the OTP Credit Agreement (as defined below), the maximum amount of debt
outstanding in 2016 was $51,885,000 on December 16, 2016 and the average daily
balance of debt outstanding during 2016 was $32,576,000. The weighted average
interest rate paid on debt outstanding under the OTP Credit Agreement during
2016 was 1.8% compared with 1.5% in 2015. The maximum amount of consolidated
short-term debt outstanding in 2016 was $87,211,000 on January 25, 2016 and the
average daily balance of consolidated short-term debt outstanding during 2016
was $48,776,000. The weighted average interest rate on consolidated short-term
debt outstanding on December 31, 2016 was 1.9%.



On October 29, 2012 we entered into a Third Amended and Restated Credit
Agreement (the Otter Tail Corporation Credit Agreement), which is an unsecured
$130 million revolving credit facility that may be increased to $250 million on
the terms and subject to the conditions described in the Otter Tail Corporation
Credit Agreement. On October 31, 2016 the Otter Tail Corporation Credit
Agreement was amended to extend its expiration date by one year from October 29,
2020 to October 29, 2021 and the unsecured revolving credit facility was reduced
from $150 million to $130 million. We can draw on this credit facility to
refinance certain indebtedness and support our operations and the operations of
certain of our subsidiaries. Borrowings under the Otter Tail Corporation Credit
Agreement bear interest at LIBOR plus 1.75%, subject to adjustment based on our
senior unsecured credit ratings. We are required to pay commitment fees based on
the average daily unused amount available to be drawn under the revolving credit
facility. The Otter Tail Corporation Credit Agreement contains a number of
restrictions on us and the businesses of our wholly owned subsidiary, Varistar
Corporation (Varistar) and its subsidiaries, including restrictions on our and
their ability to merge, sell assets, make investments, create or incur liens on
assets, guarantee the obligations of certain other parties and engage in
transactions with related parties. The Otter Tail Corporation Credit Agreement
also contains affirmative covenants and events of default, and financial
covenants as described below under the heading "Financial Covenants." The Otter
Tail Corporation Credit Agreement does not include provisions for the
termination of the agreement or the acceleration of repayment of amounts
outstanding due to changes in our credit ratings. Our obligations under the
Otter Tail Corporation Credit Agreement are guaranteed by certain of our
subsidiaries. Outstanding letters of credit issued by us under the Otter Tail
Corporation Credit Agreement can reduce the amount available for borrowing under
the line by up to $40 million.



On October 29, 2012 OTP entered into a Second Amended and Restated Credit
Agreement (the OTP Credit Agreement), providing for an unsecured $170 million
revolving credit facility that may be increased to $250 million on the terms and
subject to the conditions described in the OTP Credit Agreement. On October 31,
2016 the OTP Credit Agreement was amended to extend its expiration date by one
year from October 29, 2020 to October 29, 2021. 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. 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.



50






Long-Term Debt



2016 Note Purchase Agreement

On September 23, 2016 we entered into a Note Purchase Agreement (the 2016 Note
Purchase Agreement) with the purchasers named therein, pursuant to which we
agreed to issue to the purchasers, in a private placement transaction, $80
million aggregate principal amount of our 3.55% Guaranteed Senior Notes due
December 15, 2026 (the 2026 Notes). The 2026 Notes were issued on December 13,
2016. Our obligations under the 2016 Note Purchase Agreement and the 2026 Notes
are guaranteed by our Material Subsidiaries (as defined in the 2016 Note
Purchase Agreement, but specifically excluding OTP). The proceeds from the
issuance of the 2026 Notes were used to repay the remaining $52,330,000 of our
9.000% Senior Notes due December 15, 2016, and to pay down a portion of the
$50 million in funds borrowed in February 2016 under our term loan agreement.



We may prepay all or any part of the 2026 Notes (in an amount not less than 10%
of the aggregate principal amount of the 2026 Notes then outstanding in the case
of a partial prepayment) at 100% of the principal amount prepaid, together with
unpaid accrued interest and a make-whole amount; provided that if no default or
event of default exists under the 2016 Note Purchase Agreement, any optional
prepayment made by us of all of the 2026 Notes on or after September 15, 2026
will be made without any make-whole amount. We are required to offer to prepay
all of the outstanding 2026 Notes at 100% of the principal amount together with
unpaid accrued interest in the event of a Change of Control (as defined in the
2016 Note Purchase Agreement) of the Company. In addition, if we and our
Material Subsidiaries sell a "substantial part" of our or their assets and use
the proceeds to prepay or retire senior Interest-bearing Debt (as defined in the
2016 Note Purchase Agreement) of the Company and/or a Material Subsidiary in
accordance with the terms of the 2016 Note Purchase Agreement, we are required
to offer to prepay a Ratable Portion (as defined in the 2016 Note Purchase
Agreement) of the 2026 Notes held by each holder of the 2026 Notes.



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



Term Loan Agreement


On February 5, 2016 we entered into a Term Loan Agreement (the Term Loan
Agreement) with the Banks named therein, JPMorgan Chase Bank, N.A. (JPMorgan),
as administrative agent, and JPMS, as Lead Arranger and Book Runner. The Term
Loan Agreement provides for an unsecured term loan with an aggregate commitment
of $50 million that we may use for purposes of funding working capital, capital
expenditures and other corporate purposes of the Company and certain of our
subsidiaries. Under the Term Loan Agreement, we may, on up to two occasions,
enter into additional tranches of term loans in minimum increments of $10
million, subject to the consent of the lenders and so long as the aggregate
amount of outstanding term loans does not exceed $100 million at any time.
Borrowings under the Term Loan Agreement will bear interest at either (1) LIBOR
plus 0.90% or (2) the greater of (a) the Prime Rate, (b) the Federal Reserve
Bank of New York Rate plus 0.50% and (c) LIBOR multiplied by the Statutory
Reserve Rate plus 1%. The applicable interest rate will depend on our election
of whether to make the advance a LIBOR advance. The Term Loan Agreement
terminates on February 5, 2018.



On February 5, 2016 we borrowed $50 million under the Term Loan Agreement at an
interest rate based on the 30 day LIBOR plus 90 basis points and used the
proceeds to pay down borrowings under the Otter Tail Corporation Credit
Agreement that were used to fund the expansion of BTD's Minnesota facilities in
2015 and to fund the September 1, 2015 acquisition of BTD-Georgia. We repaid
$35.0 million under the Term Loan Agreement in the fourth quarter of 2016.



The Term Loan Agreement contains a number of restrictions on us, Varistar and
certain subsidiaries of Varistar, including restrictions on our and their
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 Term Loan Agreement also contains affirmative
covenants and events of default, as well as certain financial covenants as
described below under the heading "Financial Covenants." The Term Loan Agreement
does not include provisions for the termination of the agreement or the
acceleration of repayment of amounts outstanding due to changes in our credit
ratings. Our obligations under the Term Loan Agreement are guaranteed by
Varistar and certain of its subsidiaries.



51






2013 Note Purchase Agreement

On August 14, 2013 OTP entered into a Note Purchase Agreement (the 2013 Note
Purchase Agreement) with the Purchasers named therein, pursuant to which OTP
agreed to issue to the Purchasers, in a private placement transaction, $60
million aggregate principal amount of OTP's 4.68% Series A Senior Unsecured
Notes due February 27, 2029 (the Series A Notes) and $90 million aggregate
principal amount of OTP's 5.47% Series B Senior Unsecured Notes due February 27,
2044 (the Series B Notes and, together with the Series A Notes, the Notes). On
February 27, 2014 OTP issued all $150 million aggregate principal amount of
the
Notes.


The 2013 Note Purchase Agreement states that OTP may prepay all or any part of
the Notes (in an amount not less than 10% of the aggregate principal amount of
the Notes then outstanding in the case of a partial prepayment) at 100% of the
principal amount prepaid, together with accrued interest and a make-whole
amount, provided that if no default or event of default under the 2013 Note
Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the
Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the
Series B Notes then outstanding on or after November 27, 2043, will be made at
100% of the principal prepaid but without any make-whole amount. In addition,
the 2013 Note Purchase Agreement states OTP must offer to prepay all of the
outstanding Notes at 100% of the principal amount together with unpaid accrued
interest in the event of a change of control 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 OTP's existing credit agreement or any renewal, extension or
replacement thereof, at any time contains any financial covenant or other
provision providing for limitations on interest expense and such a covenant is
not contained in the 2013 Note Purchase Agreement under substantially similar
terms or would be more beneficial to the holders of the Notes than any analogous
provision contained in the 2013 Note Purchase Agreement (an "Additional
Covenant"), then unless waived by the Required Holders (as defined in the 2013
Note Purchase Agreement), the Additional Covenant will be deemed to be
incorporated into the 2013 Note Purchase Agreement. The 2013 Note Purchase
Agreement also provides for the amendment, modification or deletion of an
Additional Covenant if such Additional Covenant is amended or modified under or
deleted from the OTP credit agreement, provided that no default or event of
default has occurred and is continuing.



2007 and 2011 Note Purchase Agreements

On December 1, 2011, OTP issued $140 million aggregate principal amount of its
4.63% Senior Unsecured Notes due December 1, 2021 pursuant to a Note Purchase
Agreement dated as of July 29, 2011 (2011 Note Purchase Agreement). OTP also has
outstanding its $155 million senior unsecured notes issued in four series
consisting of $33 million aggregate principal amount of 5.95% Senior Unsecured
Notes, Series A, due 2017; $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 of the outstanding notes
issued thereunder at 100% of the principal amount together with unpaid accrued
interest in the event of a change of control of OTP. The note purchase
agreements contain a number of restrictions on OTP, including restrictions on
OTP's ability to merge, sell assets, create or incur liens on assets, guarantee
the obligations of any other party, and engage in transactions with related
parties. The note purchase agreements also include affirmative covenants and
events of default, and certain financial covenants as described below under the
heading "Financial Covenants."



52






Financial Covenants

We were in compliance with the financial covenants in our debt agreements as of December 31, 2016.




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



Our borrowing agreements are subject to certain financial covenants. Specifically:

· Under the Otter Tail Corporation Credit Agreement, the Term Loan 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, 2016 our Interest

and Dividend Coverage Ratio calculated under the requirements of the Otter Tail

   Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note
   Purchase Agreement was 3.68 to 1.00.



· Under the 2016 Note Purchase Agreement, we may not permit our Priority

   Indebtedness to exceed 10% of our Total Capitalization.



· Under the OTP Credit Agreement, OTP may not permit the ratio of its

Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00.

· Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP

may not permit the ratio of its Consolidated Debt to Total Capitalization to be

greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to

be less than 1.50 to 1.00, in each case as provided in the related borrowing

agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total

Capitalization, as provided in the related agreement. As of December 31, 2016

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 3.64 to 1.00.



· Under the 2013 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, each as provided in the

   2013 Note Purchase Agreement.



As of December 31, 2016 our ratio of Interest-bearing Debt to Total Capitalization was 0.46 to 1.00 on a consolidated basis and 0.47 to 1.00 for OTP. Neither Otter Tail Corporation or OTP had any Priority Indebtedness outstanding as of December 31, 2016.

Our ratio of earnings to fixed charges from continuing operations reported in
Exhibit 12.1 to this Annual Report on Form 10-K, which includes imputed finance
costs on operating leases, was 3.4x for 2016 and 2015. During 2017, we expect
this coverage ratio to increase, assuming 2017 net income meets our
expectations.




OFf-Balance-Sheet Arrangements

We and our subsidiary companies have outstanding letters of credit totaling $4.6
million, but our line of credit borrowing limits are only restricted by $50,000
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.



53








2017 BUSINESS OUTLOOK



We anticipate 2017 diluted earnings per share to be in the range of $1.60 to
$1.75. This guidance reflects the current mix of businesses we own, considers
the cyclical nature of some of our businesses, and reflects current regulatory
factors and economic challenges facing our Electric, Manufacturing and Plastics
segments and strategies for improving future operating results. We expect
capital expenditures for 2017 to be $149 million compared with actual cash used
for capital expenditures of $161 million in 2016. Major projects in our planned
expenditures for 2017 include investments in two large transmission line
projects for the Electric segment, which positively impact earnings by providing
an immediate return on invested funds through rider recovery mechanisms.



Segment components of our 2017 earnings per share guidance range compared with 2016 actual earnings are as follows:



                                          2016 EPS         2017 EPS Guidance
                                         by Segment         Low          High
         Electric                        $      1.29     $     1.31     $  1.34
         Manufacturing                   $      0.15     $     0.17     $  0.21
         Plastics                        $      0.27     $     0.26     $  0.30
         Corporate                       $     (0.11 )   $    (0.14 )   $ (0.10 )

Total - Continuing Operations $ 1.60 $ 1.60 $ 1.75

Contributing to our earnings guidance for 2017 are the following items:

· We expect 2017 Electric segment net income to be higher than 2016 segment net

   income based on:




o Normal weather for 2017. Milder than normal weather in 2016 negatively impacted

diluted earnings per share by $0.07 compared to normal.

o Constructive outcome of a rate case filed in Minnesota on February 16, 2016

with a full year of increased rates compared with 8.5 months in 2016. The

Minnesota Public Utilities Commission determines our rates. Our ability to

obtain final rates similar to interim rates and reasonable rates of return

depends on regulatory action under applicable statutes and regulations. We

cannot provide assurance our interim rates will become final and that our

modifications to our original request will ultimately be approved.

o Rider recovery increases, including transmission riders related to the Electric

segment's continuing investments in its share of the MVPs in South Dakota.

o Expected increases in sales to pipeline and commercial customers.




offset by:


o Increased operating and maintenance expenses of $0.06 per share due to

inflationary increases and increasing costs of medical, workers compensation

and retiree medical. Included is an increase in pension costs as a result of a

decrease in the discount rate from 4.76% to 4.60% and a decrease in the assumed

long-term rate of return on plan assets from 7.75% to 7.50%.

o Higher depreciation and property tax expense due to large capital projects

   being put into service.




o Lower CIP incentives of $0.04 per share in Minnesota as a result of program

changes made by the state. OTP estimates the implementation of the new CIP

financial incentive model will reduce these incentives by approximately 50%

compared to the previous incentive mechanism.

o Increased costs related to contractual price increases in certain capacity

   agreements.



· We expect 2017 net income from our Manufacturing segment to increase over 2016

   due to:




o Increased sales of 4.5% coming primarily from the lawn and garden end markets.

We continue to see soft end markets in agriculture, oil and gas.

o Improved margins on parts and tooling sales given improved productivity across

all of BTD's locations and lower interest costs as a result of the refinancing

of long-term debt completed in the fourth quarter of 2016.

o An increase in earnings from T.O. Plastics mainly driven by year over year

sales growth in our horticulture and custom markets and lower interest costs as

a result of the refinancing of long-term debt completed in the fourth quarter

   of 2016.




o Backlog for the manufacturing companies of approximately $118 million for 2017

compared with $134 million one year ago.


54





· We expect 2017 net income from the Plastics segment to be similar to 2016.

Sales volumes in 2017 are expected to be down compared with 2016 due to lower

sales in the Southern California and Texas markets offset by strengthening

sales prices resulting in improved operating margins year over year. The

Plastics segment also benefits from lower interest costs as a result of the

   refinancing of long term debt completed in the fourth quarter of 2016.



· Corporate costs in 2017 are expected to be in line with 2016 costs.

The following table shows our 2016 capital expenditures and 2017 through 2021 anticipated capital expenditures and electric utility average rate base:




(in millions)              2015      2016        2017        2018        2019        2020        2021        Total
Capital Expenditures:
Electric Segment:
Renewables and Natural
Gas Generation                                  $     3     $    80     $   288     $    71     $    20     $   462
Transmission                                         88          49          11          11           7         166
Other                                                44          44          47          48          51         234
Total Electric Segment              $   150     $   135     $   173     $   346     $   130     $    78     $   862
Manufacturing and
Plastics Segments                        11          14          17          15          14          14          74
Total Capital
Expenditures                        $   161     $   149     $   190     $   361     $   144     $    92     $   936
Total Electric Utility
Average Rate Base        $  919     $ 1,001 *   $ 1,063     $ 1,118     $ 1,267     $ 1,396     $ 1,419


*Estimated



The consolidated capital expenditure plan for the 2017-2021 time period calls
for $936 million based on the need for additional wind and solar in rate base
and capital spending for a natural gas-fired plant that is expected to replace
Hoot Lake Plant when it is retired in 2021. Taking into account the increased
capital expenditure plan, our compounded annual growth rate in rate base is
projected to be 7.5% over the 2015 to 2021 timeframe.



Execution on the currently anticipated electric utility capital expenditure plan
is expected to grow rate base and be a key driver in increasing utility earnings
over the 2017 through 2021 timeframe.



Our outlook for 2017 is dependent on a variety of factors and is subject to the
risks and uncertainties discussed in Item 1A. Risk Factors, and elsewhere in
this Annual Report on Form 10-K.



Critical Accounting Policies Involving Significant Estimates




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



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



55





Pension and Other Postretirement Benefits Obligations and Costs


Pension and postretirement benefit liabilities and expenses for our electric
utility and corporate employees are determined by actuaries using assumptions
about the discount rate, expected return on plan assets, rate of compensation
increase and healthcare cost-trend rates. Further discussion of our pension and
postretirement benefit plans and related assumptions is included in note 11 to
our consolidated financial statements.



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



The pension benefit cost for 2017 for our noncontributory funded pension plan is
expected to be $5.9 million compared to $5.7 million in 2016, reflecting a
decrease in the assumed rate of return on pension plan assets from 7.75% in 2016
to 7.50% in 2017, and a decrease in the estimated discount rate used to
determine annual benefit cost accruals from 4.76% in 2016 to 4.60% in 2017. 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
2016, all other factors being held constant: a 0.25 increase in the discount
rate would have decreased our 2016 pension benefit cost by $892,000; a 0.25
decrease in the discount rate would have increased our 2016 pension benefit cost
by $937,000; a 0.25 increase in the assumed rate of increase in future
compensation levels would have increased our 2016 pension benefit cost by
$521,000; a 0.25 decrease in the assumed rate of increase in future compensation
levels would have decreased our 2016 pension benefit cost by $509,000; and a
0.25 increase (or decrease) in the expected long-term rate of return on plan
assets would have decreased (or increased) our 2016 pension benefit cost by
$628,000.



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 2016 postretirement medical benefit costs by $197,000. A 0.25 decrease in the discount rate would have increased our 2016 postretirement medical benefit costs by $206,000. See note 11 to consolidated financial statements for the cost impact of a change in medical cost inflation rates.




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



Taxation


We are required to make judgments regarding the potential tax effects of various
financial transactions and our ongoing operations to estimate our obligations to
taxing authorities. These tax obligations include income, real estate and use
taxes. These judgments could result in the recognition of a liability for
potential adverse outcomes regarding uncertain tax positions that we have taken.
While we believe our liability for uncertain tax positions as of December 31,
2016 reflects the most likely probable expected outcome of these tax matters in
accordance with the requirements of ASC Topic 740, Income Taxes, the ultimate
outcome of such matters could result in additional adjustments to our
consolidated financial statements. However, we do not believe such adjustments
would be material.



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



56






Asset Impairment

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



We believe the accounting estimates related to an asset impairment are critical
because: (1) they are highly susceptible to change from period to period,
reflecting changing business cycles, (2) they require management to make
assumptions about future cash flows over future years, and (3) the impact of
recognizing an impairment could have a significant effect on operations.
Management's assumptions about future cash flows require significant judgment
because actual operating levels have fluctuated in the past and are expected to
continue to do so in the future.



As of December 31, 2016 an assessment of the carrying amounts of our long-lived assets and other intangibles indicated these assets were not impaired.

Goodwill Impairment

Goodwill is required to be evaluated annually for impairment, according to ASC
350-20-35, Goodwill - Subsequent Measurement. We perform quantitative goodwill
impairment testing annually in the fourth quarter. In addition, the test 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.



The quantitative goodwill impairment test is a two-step process performed at the
reporting unit level. We have determined the reporting units for our goodwill
impairment test are our operating segments, or components of an operating
segment, that constitute a business for which discrete financial information is
available and for which our chief operating decision makers regularly review the
operating results. For more information on our operating segments, see note 2 to
consolidated financial statements. The first step of the quantitative impairment
test involves comparing the fair value of each reporting unit to its carrying
value. If the fair value of a reporting unit exceeds its carrying value, the
test is complete and no impairment is recorded. If the fair value of a reporting
unit is less than its carrying value, step two of the test is performed to
determine the amount of impairment loss, if any. The impairment is computed by
comparing the implied fair value of the reporting unit's goodwill to the
carrying value of that goodwill. If the carrying value is greater than the
implied fair value, an impairment loss must be recorded. At December 31, 2016,
the fair value substantially exceeded the carrying value at all our reporting
units reported under continuing operations.



Determining the fair value of a reporting unit requires judgment and the use of
significant estimates which include assumptions about the reporting unit's
future revenue, profitability and cash flows, amount and timing of estimated
capital expenditures, inflation rates, weighted average cost of capital,
operational plans, and current and future economic conditions, among others. The
fair value of each reporting unit is determined using a weighted combination of
income and market approaches. We use a discounted cash flow methodology for our
income approach. Under this approach, the discounted cash flow model determines
fair value based on the present value of projected cash flows over a specified
period and a residual value related to future cash flows 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. 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.



acquisition METHOD OF accounting


We account for acquisitions under the requirements of ASC Topic 805, Business
Combinations. Under ASC 805 the term "purchase method of accounting" is replaced
with "acquisition method of accounting" and requires an acquirer to recognize
the assets acquired, the liabilities assumed and any noncontrolling interest in
the acquiree at the acquisition date, measured at their fair values as of that
date, with limited exceptions.



57






Acquired assets and liabilities assumed that are subject to critical estimates
include property, plant and equipment, intangible assets and inventory. The fair
value of property, plant and equipment is based on valuations performed by
qualified internal personnel and/or with the assistance of outside appraisers.
Fair values assigned to plant and equipment are based on several factors
including the age and condition of the equipment, maintenance records of the
equipment and auction values for equipment with similar characteristics at the
time of purchase. Intangible assets are identified and valued using the
guidelines of ASC 805. The fair value of intangible assets is based on estimates
including royalty rates, customer attrition rates and estimated cash flows.



While the allocation of purchase price is subject to a high degree of judgment
and uncertainty, we do not expect the estimates to vary significantly once an
acquisition is complete. We believe our estimates have been reasonable in the
past as there have been no significant valuation adjustments to the allocation
of purchase price.


Forward-Looking Information - Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995

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

© Edgar Online, source Glimpses

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Managers
NameTitle
Charles S. MacFarlane President, CEO, Chief Operating Officer & Director
Nathan Ivey Partain Chairman
Kevin G. Moug Chief Financial Officer & Senior Vice President
Karen M. Bohn Independent Director
John D. Erickson Director
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Sector and Competitors
1st jan.Capitalization (M$)
OTTER TAIL CORPORATION-6.25%1 507
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IBERDROLA SA0.64%42 923
EXELON CORPORATION3.04%33 764
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