ELECTRIC

~~We may experience fluctuations~~General

Electric includes OTP and, through December 31, 2012, the operations of OTESCO, which were not materially significant in 2012 and 2011. OTP, headquartered in Fergus Falls, Minnesota, provides electricity to more than 130,000 customers in a service area with outer boundaries that encompass a total expanse of 70,000 square miles of western Minnesota, eastern North Dakota, and northeastern South Dakota. OTESCO, headquartered in Fergus Falls, Minnesota, provided technical and engineering services primarily in North Dakota and Minnesota. The Company derived 42%, 41% and 41% of its consolidated operating revenues and ~~expenses related~~64%, 74% and 88% of its consolidated operating income from the Electric segment for the years ended December 31, 2013, 2012 and 2011, respectively.

The breakdown of retail electric revenues by state is as follows:

State	2013			2012
Minnesota		48.2	%		48.9	%
North Dakota		42.8			42.0
South Dakota		9.0			9.1
Total		100.0	%		100.0	%

The territory served by OTP is predominantly agricultural. The aggregate population of OTP’s retail electric service area is approximately 230,000. In this service area of 422 communities and adjacent rural areas and farms, approximately 125,646 people live in communities having a population of more than 1,000, according to ~~our~~the 2010 census. The only communities served which have a population in excess of 10,000 are Jamestown, North Dakota (15,427); Bemidji, Minnesota (13,431); and Fergus Falls, Minnesota (13,138). As of December 31, 2013, OTP served 130,188 customers. Although there are relatively few large customers, sales to commercial and industrial customers are significant.

The following table provides a breakdown of electric ~~operations,~~revenues by customer category. All other sources include gross wholesale sales from utility generation, net revenue from energy trading activity and sales to municipalities.

Customer Category	2013			2012
Commercial		36.9	%		36.0	%
Residential		33.3			32.6
Industrial		23.2			25.0
All Other Sources		6.6			6.4
Total		100.0	%		100.0	%

Wholesale electric energy kilowatt-hour (kwh) sales were 12.5% of total kwh sales for 2013 and 11.8% for 2012. Wholesale electric energy kwh sales increased by 13.9% between the years while revenue per kwh sold increased by 18.8%. Activity in the short-term energy market is subject to change based on a number of factors and it is difficult to predict the quantity of wholesale power sales or prices for wholesale power in the future.

Capacity and Demand

As of December 31, 2013 OTP’s owned net-plant dependable kilowatt (kW) capacity was:


Baseload Plants
Big Stone Plant	256,700		kW
Coyote Station		149,000
Hoot Lake Plant		148,900
Total Baseload Net Plant	554,600		kW
Combustion Turbine and Small Diesel Units	104,900		kW
Hydroelectric Facilities	2,600		kW
Owned Wind Facilities (rated at nameplate)
Luverne Wind Farm (33 turbines)	49,500		kW
Ashtabula Wind Center (32 turbines)		48,000
Langdon Wind Center (27 turbines)		40,500
Total Owned Wind Facilities	138,000		kW

The baseload net plant capacity for Big Stone Plant and Coyote Station constitutes OTP’s ownership percentages of 53.9% and 35%, respectively. OTP owns 100% of the Hoot Lake Plant. During 2013, OTP generated about 70.8% of its retail kwh sales and purchased the balance.

In addition to the owned facilities described above OTP had the following purchased power agreements in place on December 31, 2013:


Purchased Wind Power Agreements (rated at nameplate and greater than 2,000 kW)
Ashtabula Wind III	62,400		kW
Edgeley		21,000
Langdon		19,500
Total Purchased Wind	102,900		kW

Other Purchased Power Agreements (in excess of 1 year and 500 kW)
Great River Energy1	100,000		kW
1 Through May 2021.

OTP has a direct control load management system which ~~may cause our financial results~~provides some flexibility to ~~fluctuate and could impair our ability~~OTP to ~~make distributions~~effect reductions of peak load. OTP also offers rates to ~~shareholders or scheduled payments~~customers which encourage off-peak usage.

OTP’s capacity requirement is based on ~~our debt obligations, or~~MISO Module E requirements. OTP is required to have sufficient Zonal Resource Credits to meet ~~covenants~~its monthly weather normalized forecast demand, plus a reserve obligation. The MISO Resource Adequacy Construct changed significantly for the 2013/2014 MISO Planning Year effective June 1, 2013. OTP met its MISO obligation for 2013. OTP generating capacity combined with additional capacity under ~~our borrowing agreements.~~purchased power agreements (as described above) and load management control capabilities is expected to meet 2014 system demand and MISO reserve requirements.

Fuel Supply

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

The following table shows the sources of energy used to generate OTP’s net output of electricity for 2013 and 2012:


	2013					2012
Sources	Net Kilowatt Hours Generated (Thousands)		% of Total Kilowatt Hours Generated			Net Kilowatt Hours Generated (Thousands)		% of Total Kilowatt Hours Generated
Subbituminous Coal		2,322,608		62.4	%		2,094,293	61.2	%
Lignite Coal		881,973		23.7			782,358	22.9
Wind and Hydro		471,176		12.7			490,387	14.3
Natural Gas and Oil		43,165		1.2			55,637	1.6
Total		3,718,922		100.0	%		3,422,675	100.0	%

OTP has the following primary coal supply agreements:


Plant	Coal Supplier	Type of Coal	Expiration Date
Big Stone Plant	Peabody COALSALES, LLC	Wyoming subbituminous	December 31, 2016
Big Stone Plant	Westmoreland Resources, Inc.	Montana subbituminous	December 31, 2014
Coyote Station	Dakota Westmoreland Corporation	North Dakota lignite	May 4, 2016
Coyote Station	Coyote Creek Mining Company, L.L.C.	North Dakota lignite	December 31, 2040
Hoot Lake Plant	Cloud Peak Energy Resources LLC	Montana subbituminous	December 31, 2015

OTP has about 58% of its coal needs for Big Stone under contract through December 2016.

The contract with Dakota Westmoreland Corporation expires on May 4, 2016. In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton to be paid by the Coyote Station owners under the LSA will reflect the cost of production, along with an agreed profit and capital charge. The LSA provides for the Coyote Station owners to purchase the membership interests in CCMC in the event of certain early termination events and also at the end of the term of the LSA.

OTP has about 84% of its anticipated coal needs for Hoot Lake Plant secured under contract through December 2015.

It is OTP’s practice to maintain a minimum 30-day inventory (at full output) of coal at the Big Stone Plant and a 20-day inventory at Coyote Station and Hoot Lake Plant.

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

The average cost of fuel consumed (including handling charges to the plant sites) per million British Thermal Units for the years 2013, 2012, and 2011 was $2.055, $2.108, and $1.922, respectively.

General Regulation

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

A ~~number~~breakdown of ~~factors, many~~electric rate regulation by each jurisdiction is as follows:

		2013						2012
Rates	Regulation	% of Electric Revenues			% of kwh Sales			% of Electric Revenues			% of kwh Sales
MN Retail Sales	MN Public Utilities Commission		43.8	%		42.5	%		45.2	%		43.4	%
ND Retail Sales	ND Public Service Commission		39.0			36.8			38.8			36.4
SD Retail Sales	SD Public Utilities Commission		8.2			8.2			8.4			8.5
Transmission & Wholesale	Federal Energy Regulatory Commission		9.0			12.5			7.6			11.7
Total			100.0	%		100.0	%		100.0	%		100.0	%

OTP operates under approved retail electric tariffs in all three states it serves. OTP has an obligation to serve any customer requesting service within its assigned service territory. The pattern of electric usage can vary dramatically during a 24-hour period and from season to season. OTP’s tariffs are designed to recover the costs of providing electric service. To the extent that peak usage can be reduced or shifted to periods of lower usage, the cost to serve all customers is reduced. In order to shift usage from peak times, OTP has approved tariffs in all three states for residential demand control, general service time of use and time of day, real-time pricing, and controlled and interruptible service. Each of these specialized rates is designed to improve efficient use of OTP resources, while giving customers more control over their electric bill. OTP also has approved tariffs in its three service territories which ~~are beyond our control, may contribute~~allow qualifying customers to ~~fluctuations~~release and sell energy back to OTP when wholesale energy prices make such transactions desirable.

With a few minor exceptions, OTP’s electric retail rate schedules provide for adjustments in ~~our revenues and expenses from electric operations, causing our net income~~rates based on the cost of fuel delivered to fluctuate from period to period. These risks include fluctuations in the volume and price of sales of electricity to customers or other utilities, which may be affected by factors such as mergers and acquisitions of other utilities, geographic location of other utilities, transmission costs (including increased costs related to operations of regional transmission organizations), changes in the manner in which wholesale power is sold and purchased, unplanned interruptions at OTP’s generating plants, as well as for adjustments based on the ~~effects~~cost of ~~regulation~~electric energy purchased by OTP. OTP also credits certain margins from wholesale sales to the fuel and legislation, demographic changes in OTP’s customer base and changes in OTP’s customer demand or load growth. Electric wholesale margins have been significantly and adversely affected by increased efficiencies in the MISO market. Electric wholesale trading margins could also be adversely affected by losses due to trading activities. Other risks include weather conditions or changes in weather patterns (including severe weather that could result in damage to OTP’s assets),purchased power adjustment. The adjustments for fuel and purchased power costs are presently based on a two month moving average in Minnesota and by the Federal Energy Regulatory Commission (FERC), a three month moving average in South Dakota and a four month moving average in North Dakota. These adjustments are applied to the next billing period after becoming applicable. These adjustments also include an over or under recovery mechanism, which is calculated on an annual basis in Minnesota and on a monthly basis in North Dakota and South Dakota.

The following summarizes the material regulations of each jurisdiction applicable to OTP’s electric operations, as well as any specific electric rate proceedings during the last three years with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC. The Company’s manufacturing and infrastructure businesses are not subject to direct regulation by any of these agencies.

Minnesota

Under the Minnesota Public Utilities Act, OTP is subject to the jurisdiction of the MPUC with respect to rates, issuance of securities, depreciation rates, public utility services, construction of major utility facilities, establishment of exclusive assigned service areas, contracts and arrangements with subsidiaries and other affiliated interests, and other matters. The MPUC has the authority to assess the need for large energy facilities and to issue or deny certificates of need, after public hearings, within one year of an application to construct such a facility.

Pursuant to the Minnesota Power Plant Siting Act, the MPUC has authority to select or designate sites in Minnesota for new electric power generating plants (50,000 kW or more) and routes for transmission lines (100 kilovolt (kV) or more) in an orderly manner compatible with environmental preservation and the efficient use of resources, and to certify such sites and routes as to environmental compatibility after an environmental impact study has been conducted by the Minnesota Department of Commerce (MNDOC) and the Office of Administrative Hearings has conducted contested case hearings.

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

2010 General Rate Case—OTP filed a general rate case on April 2, 2010 requesting an 8.01% base rate increase as well as a 3.8% interim rate increase. On May 27, 2010, the MPUC issued an order accepting the filing, suspending rates, and approving the interim rate increase, as requested, to be effective with customer usage on and after June 1, 2010. The MPUC held a hearing to decide on the issues in the rate case on March 25, 2011 and issued a written order on April 25, 2011. The MPUC authorized a revenue increase of approximately $5.0 million, or 3.76% in base rate revenues, excluding the effect of moving recovery of wind investments to base rates. The MPUC’s written order included: (1) recovery of Big Stone II costs over five years, (2) moving recovery of wind farm assets from rider recovery to base rate recovery, (3) transfer of a portion of Minnesota Conservation Improvement Program (MNCIP) costs from rider recovery to base rate recovery, (4) transfer of the investment in two transmission lines from rider recovery to base rate recovery, and (5) changing the mechanism for providing customers with a credit for margins earned on asset-based wholesale sales of electricity from a credit to base rates to a credit to the Minnesota Fuel Clause Adjustment. Final rates went into effect October 1, 2011. The overall increase to customers was approximately 1.6% compared to the authorized interim rate increase of 3.8%, which resulted in an interim rate refund to Minnesota retail electric customers of approximately $3.9 million in the fourth quarter of 2011. Pursuant to the order, OTP’s allowed rate of ~~economic growth~~return on rate base increased from 8.33% to 8.61% and its allowed rate of return on equity increased from 10.43% to 10.74%. OTP’s authorized rates of return are based on a capital structure of 48.28% long term debt and 51.72% common equity.

Conservation Improvement Programs—Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or ~~decline~~make a contribution to the state’s energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota. The Next Generation Energy Act of 2007, passed by the Minnesota legislature in May 2007, transitions from a conservation spending goal to a conservation energy savings goal.

The MNDOC may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC.

On January 11, 2012 the MPUC approved the recovery of $3.5 million for 2010 MNCIP financial incentives. Beginning in January 2012, OTP’s MNCIP Conservation Cost Recovery Adjustment increased from 3.0% to 3.8% for all Minnesota retail electric customers. On March 30, 2012 OTP recognized an additional $0.4 million of incentive related to 2011 and submitted its annual 2011 financial incentive filing request for $2.6 million. In December 2012, the MPUC approved the recovery of $2.6 million in financial incentives for 2011 and also ordered a change in the MNCIP cost recovery methodology used by OTP from a percentage of a customer’s bill to an amount per kwh consumed. On January 1, 2013 OTP’s MNCIP surcharge decreased from 3.8% of the customer’s bill to $0.00142 per kwh, which equates to approximately 1.9% of a customer’s bill. OTP recognized $2.6 million of MNCIP financial incentives in 2012 and an additional $0.1 million in 2013 relating to 2012 program results. On October 10, 2013 the MPUC approved OTP’s 2012 financial incentive request for $2.7 million as well as its request for an updated surcharge rate to be implemented on November 1, 2013.

Integrated Resource Plan (IRP)—Minnesota law requires utilities to submit to the MPUC for approval a 15-year advance IRP. A resource plan is a set of resource options a utility could use to meet the service needs of its customers over a forecast period, including an explanation of the utility’s supply and demand circumstances, and the extent to which each resource option would be used to meet those service needs. The MPUC’s findings of fact and conclusions regarding resource plans shall be considered prima facie evidence, subject to rebuttal, in Certificate of Need (CON) hearings, rate reviews and other proceedings. Typically, the filings are submitted every two years.

In the MPUC order approving the 2011-2025 IRP in February 2012, OTP was required to submit a base-load diversification study specifically focused on evaluating retirement and repower options for the Hoot Lake Plant. In an order dated March 25, 2013 the MPUC approved OTP’s recommendations that Hoot Lake Plant add pollution-control equipment at a cost of approximately $10.0 million to comply with U.S. Environmental Protection Agency’s (EPA) mercury and air toxics standards by 2015 and discontinue burning coal in 2020.

On December 2, 2013 OTP filed its 2014-2028 IRP with the MPUC. Copies of the 2014-2028 IRP were provided to both the NDPSC and SDPUC. Approximately 65% of the resource options called for by the 2014-2028 IRP are comprised of existing resources and wholesale energy purchases similar to existing levels. The remaining 35% is comprised of the following components: 65% natural gas simple cycle combustion turbines and 35% conservation and demand response. Capacity additions proposed in the 2014-2028 IRP are as follows:


Resource	Proposed Megawatts
Natural gas	194
Demand Response/Conservation	106

OTP expects a MPUC order on its 2014-2028 IRP filing during the second quarter of 2014.

Renewable Energy Standards, Conservation, Renewable Resource Riders—Minnesota law favors conservation over the addition of new resources. In addition, Minnesota law requires the use of renewable resources where new supplies are needed, unless the utility proves that a renewable energy facility is not in the public interest. An existing environmental externality law requires the MPUC, to the extent practicable, to quantify the environmental costs associated with each method of electricity generation, and to use such monetized values in evaluating generation resources. The MPUC must disallow any nonrenewable rate base additions (whether within or outside of the state) or any related rate recovery, and may not approve any nonrenewable energy facility in an integrated resource plan, unless the utility proves that a renewable energy facility is not in the public interest. The state has prioritized the acceptability of new generation with wind and solar ranked first and coal and nuclear ranked fifth, the lowest ranking. The MPUC’s current estimate of the range of costs of future CO2 regulation to be used in modeling analyses for resource plans is $9 to $34/ton of CO2 commencing in 2017. The MPUC is required to annually update these estimates.

Minnesota has a renewable energy standard which requires OTP to generate or procure sufficient renewable generation such that the following percentages of total retail electric sales to Minnesota customers come from qualifying renewable sources: 17% by 2016; 20% by 2020 and 25% by 2025. In addition, a new standard established by the 2013 legislature requires 1.5% of total electric sales to be supplied by solar energy by the year 2020. OTP is currently evaluating the new legislation and potential options for meeting that standard. Under certain circumstances and after consideration of costs and reliability issues, the MPUC may modify or delay implementation of the standards. OTP has acquired renewable resources and expects to acquire additional renewable resources in order to maintain compliance with the Minnesota renewable energy standard. OTP’s compliance with the Minnesota renewable energy standard will be measured through the Midwest Renewable Energy Tracking System.

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

The costs for three major wind farms previously approved by the MPUC for recovery through OTP’s Minnesota Renewable Resource Adjustment (MNRRA) were moved to base rates as of October 1, 2011 under the MPUC’s April 25, 2011 general rate case order with the exception of the remaining balance of the MNRRA regulatory asset. A request for an updated rate to be effective October 1, 2012 was initially filed on June 28, 2012, followed by a revised filing on July 25, 2012. Because the request to extend the period of the new rate for 18 months was still under review, a supplemental filing was submitted on February 15, 2013, requesting that the current rate be retained until a majority of the remaining costs were recovered and that the MNRRA rate be set to zero effective May 1, 2013. The MPUC approved the February 15, 2013 request on April 4, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case. Effective May 1, 2013 the resource adjustment on OTP’s Minnesota customers’ bills no longer includes MNRRA costs.

Transmission Cost Recovery (TCR) Rider—In addition to the MNRRA rider, the Minnesota Public Utilities Act provides a similar mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a CON proceeding, certified by the MPUC as a Minnesota priority transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service ~~areas. A decrease~~to the utility’s retail customers, or exempt from the requirement to obtain a Minnesota CON. The MPUC may also authorize cost recovery via such TCR riders for charges incurred by a utility under a federally approved tariff that accrue from other transmission owners’ regionally planned transmission projects that have been determined by the MISO to benefit the utility or integrated transmission system. The 2013 legislature passed legislation that also authorizes TCR riders to recover the costs of new transmission facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed to the extent approval is required by the laws of that state and determined by the MISO to benefit the utility or integrated transmission system. Such TCR riders allow a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule. OTP’s initial request for approval of a TCR rider was granted by the MPUC on January 7, 2010, and became effective February 1, 2010.

OTP requested recovery of its transmission investments being recovered through its Minnesota TCR rider rate as part of its general rate case filed on April 2, 2010. In its April 25, 2011 general rate case order, the MPUC approved the transfer of transmission costs then being recovered through OTP’s Minnesota TCR rider to recovery in base rates. Final rates went into effect on October 1, 2011. OTP continues to utilize the TCR rider cost recovery mechanism to recover the remaining balance of current transmission projects and to recover costs associated with new transmission projects determined eligible for TCR rider recovery by the MPUC.

OTP filed a request for an update to its Minnesota TCR rider on October 5, 2010. In this TCR rider update, the MPUC addressed how to handle utility investments in transmission facilities that qualify for regional cost allocation under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff). MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from the other MISO utilities. On March 26, 2012 the MPUC approved the update to OTP’s Minnesota TCR rider along with an all-in method for MISO regional cost allocations in which OTP’s retail customers would be responsible for the entire investment OTP made with an offsetting credit for revenues received from other MISO utilities under the MISO Tariff for projects included in the TCR. OTP’s updated Minnesota TCR rider went into effect April 1, 2012.

On May 24, 2012 OTP filed a petition with the MPUC to seek a determination of eligibility for the inclusion of twelve additional transmission related projects in subsequent Minnesota TCR rider filings. On February 20, 2013 the MPUC approved three of the additional projects as eligible for recovery through the TCR rider. OTP filed its annual update to the TCR rider on February 7, 2013 to include the three new projects as well as updated costs associated with existing projects. On January 30, 2014 the MPUC approved OTP’s 2013 TCR rider update but disallowed TCR rider recovery of capitalized internal labor costs and costs in excess of CON estimates. These costs will be removed from OTP’s Minnesota TCR rider effective as of the date of the MPUC’s order. OTP will be allowed to seek recovery of these costs in a future rate case.

Big Stone Air Quality Control System (AQCS)—Minnesota law authorizes a public utility to petition the MPUC for an Advance Determination of Prudence (ADP) for a project undertaken to comply with federal or state air quality standards of states in which the utility’s electric generation facilities are located if the project has an ~~increase~~expected jurisdictional cost to Minnesota ratepayers of at least $10 million. On January 14, 2011 OTP filed a petition asking the MPUC for ADP for costs associated with the design, construction and operation of the Best-Available Retrofit Technology (BART) compliant air quality control system at Big Stone Plant attributable to serving OTP’s Minnesota customers. The MPUC granted OTP’s petition for ADP for the AQCS in ~~expenses related~~a written order issued on January 23, 2012. OTP’s share of the costs for the Big Stone Plant AQCS is expected to ~~our~~be $218 million.

On May 24, 2013 legislation was enacted in Minnesota which allowed OTP to file for an emission-reduction rider for recovery of the revenue requirements of the AQCS. The legislation authorizes the rider to allow a current return on investment (including Construction Work in Progress (CWIP)) at the level approved in OTP’s most recent general rate case, unless a different return is determined by the MPUC to be in the public interest. On July 31, 2013 OTP filed for a Minnesota Environmental Cost Recovery (ECR) rider with the MPUC for recovery of its Minnesota jurisdictional share of the revenue requirements of its investment in the AQCS under construction at Big Stone Plant. The ECR rider recoverable revenue requirements include a current return on the project’s CWIP balance. The MPUC granted approval of OTP’s Minnesota ECR rider on December 18, 2013 with an effective date of January 1, 2014. The rate will be updated in an annual filing with the MPUC until the costs are rolled into base rates at an undetermined future date.

Big Stone II Project—OTP and a coalition of six other electric ~~operations may reduce~~providers filed an application for a CON for the Minnesota portion of the Big Stone II transmission line project on October 3, 2005 and filed an application for a Route Permit for the Minnesota portion of the Big Stone II transmission line project with the MPUC on December 9, 2005. On January 15, 2009 the MPUC approved a motion to grant the CON and Route Permit for the Minnesota portion of the Big Stone II transmission line project.

The MPUC granted the CON subject to a number of additional conditions, including but not limited to: (1) fulfilling various requirements relating to renewable energy goals, energy efficiency, community-based energy development projects and emissions reduction; (2) that the generation plant be built as a “carbon capture retrofit ready” facility; (3) that the applicants report to the MPUC on the feasibility of building the plant using ultra-supercritical technology; and (4) that the applicants achieve specific limits on construction costs at $3,000/kW and CO2 costs at $26/ton.

The CON and Route Permit, required by state law, would have allowed the Big Stone II utilities to construct and upgrade 112 miles of electric transmission lines in western Minnesota for delivery of power from the Big Stone site and from numerous other planned generation projects, most of which are wind energy.

Following OTP’s September 11, 2009 withdrawal from the Big Stone II project and the remaining Big Stone II participants’ November 2, 2009 cancellation of the project, the suitability of the route permits and easements obtained by OTP as a MISO transmission owner for other interconnection customers backfilling through the MISO interconnection process into the Big Stone area continued to be evaluated. OTP requested recovery of the Minnesota portion of its Big Stone II development costs over a five-year period as part of its general rate case filed in Minnesota on April 2, 2010. In a written order issued on April 25, 2011, the MPUC authorized recovery of the Minnesota portion of Big Stone II generation development costs from Minnesota ratepayers over a 60-month recovery period which began on October 1, 2011. The amount of ~~funds available for our existing and future businesses, which could result~~Big Stone II generation costs incurred by OTP that were deemed recoverable from Minnesota ratepayers as part of rates established in increased financing requirements, impair our ability to make expected distributions to shareholders or impair our ability to make scheduled payments on our debt obligations, or to meet covenants under our borrowing agreements.that proceeding was $3.2 million (which excluded $3.2 million of transmission-related project costs).

~~Operation~~sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one day suspension period, subject to ultimate approval by the FERC.

Effective January 1, 2010 the FERC authorized OTP’s implementation of a forward looking formula transmission rate under the MISO Tariff. OTP was also authorized by the FERC to recover in its formula rate (1) 100% of prudently incurred CWIP in rate base and (2) 100% of prudently incurred costs of transmission facilities that are cancelled or abandoned for reasons beyond OTP’s control (Abandoned Plant Recovery), as determined by the FERC subsequent to abandonment, specifically for three regional transmission CapX2020 projects in which OTP is investing: the Fargo Project, the Bemidji Project and the Brookings Project.

On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in MISO called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing. On June 7, 2013, in response to a challenge to the MVP cost allocation heard before the United States Court of Appeals, Seventh Circuit, the Court ruled in favor of MISO and MISO transmission owners, issuing an order affirming the FERC’s approval of the MVP cost allocation. On October 7, 2013 certain parties submitted a petition for writ of certiorari to the U.S. Supreme Court seeking review of the Seventh Circuit decision. As of February 14, 2014 the U.S. Supreme Court had not acted on the petition.

On November 12, 2013, a group of industrial customers and other stakeholders filed a complaint at the FERC seeking to reduce the return on equity component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants are seeking to reduce the current 12.38% return on equity used in MISO’s transmission rates to a proposed 9.15%. MISO and a group of MISO transmission owners have filed responses to the complaint seeking its dismissal and defending the current return on equity. The complaint is pending at the FERC.

Effective on January 1, 2012 the FERC authorized OTP to recover 100% CWIP and Abandoned Plant Recovery on two projects approved by MISO as MVPs in MISO’s 2011 Transmission Expansion Plan: the Big Stone South–Brookings MVP and the Big Stone South-Ellendale MVP.

The Big Stone South – Brookings Project—This planned 345 kV transmission line will extend 70 miles between a proposed substation near Big Stone City, South Dakota and the new Brookings County Substation near Brookings, South Dakota. OTP is jointly developing this project with Xcel Energy. MISO approved this project as an MVP under the MISO Tariff in December 2011. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. A portion of this line is anticipated to use previously obtained Big Stone II transmission route permits and easements and is expected to be in service in 2017. On July 31, 2012 the SDPUC approved the transfer of the Big Stone II transmission route permits to OTP. In December 2012, a request was filed with the SDPUC for recertification of a portion of the line route that was approved as part of the Big Stone II transmission development. The SDPUC approved the certification for the northern portion of the route on April 9, 2013. OTP and Xcel Energy jointly submitted an application to the SDPUC for a route permit for the southern portion of the Big Stone South to Brookings line on June 3, 2013. A decision on the permit application for the southern half of this route is expected in the first quarter of 2014. If the proposed project receives all the necessary approvals, OTP anticipates the line will be completed in 2017. OTP’s total capital investment in this project is expected to be approximately $109 million.

The Big Stone South – Ellendale Project—This transmission line is a proposed 345 kV line that will extend 160 to 170 miles between a proposed substation near Big Stone City, South Dakota and a proposed substation near Ellendale, North Dakota. OTP is jointly developing this project with Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc. (MDU). MISO approved this project as an MVP under the MISO Tariff in December 2011. OTP and MDU jointly filed an NICF with the SDPUC in March of 2012. On August 25, 2013 the NDPSC granted Certificates of Public Convenience and Necessity to OTP and MDU for the ten miles of the proposed line to be built in North Dakota. A joint route permit application was filed by OTP and MDU on August 23, 2013 with the SDPUC. OTP and MDU jointly filed an Application for a Certificate of Corridor Compatibility along with an application for a route permit with the NDPSC on October 18, 2013. If the proposed project receives all the necessary approvals, OTP anticipates the line will be completed in 2019. OTP’s total capital investment in this project is expected to be approximately $184 million.

CapX2020 Brookings Project—In June 2011 the MISO board of directors granted conditional approval of the MVP cost allocation designation under the MISO Tariff for the Brookings Project, and the project was granted unconditional approval in December 2011 as an MVP. This project is anticipated to be completed in the first quarter of 2015.

NAEMA

OTP is a member of the North American Energy Marketers Association (NAEMA) which is an independent, non-profit trade association representing entities involved in the marketing of energy or in providing services to the energy industry. NAEMA has over 130 members with operations in 48 states and Canada. NAEMA was formed as a successor organization of the Power and Energy Market (PEM) of the Mid-Continent Area Power Pool (MAPP) in recognition that PEM had outgrown the MAPP region. Power pool sales are conducted continuously through NAEMA in accordance with schedules filed by NAEMA with the FERC.

MRO

OTP is a member of the Midwest Reliability Organization (MRO). The MRO is a non-profit organization dedicated to ensuring the reliability and security of the bulk power system in the north central region of North America, including parts of both the United States and Canada. MRO began operations in 2005 and is one of eight regional entities in North America operating under authority from regulators in the United States and Canada through a delegation agreement with the North American Electric Reliability Corporation. The MRO is responsible for: (1) developing and implementing reliability standards, (2) enforcing compliance with those standards, (3) providing seasonal and long-term assessments of the bulk power system’s ability to meet demand for electricity, and (4) providing an appeals and dispute resolution process.

The MRO region covers roughly one million square miles spanning the provinces of Saskatchewan and Manitoba, the states of North Dakota, Minnesota, Nebraska and the majority of the territory in the states of South Dakota, Iowa and Wisconsin. The region includes more than 100 organizations that are involved in the production and delivery of power to more than 20 million people. These organizations include municipal utilities, cooperatives, investor-owned utilities, a federal power marketing agency, Canadian Crown Corporations, independent power producers and others who have interests in the reliability of the bulk power system. MRO assumed the reliability functions of the MAPP and Mid-America Interconnected Network, both former voluntary regional reliability councils.

MISO

OTP is a member of the MISO. As the transmission provider and security coordinator for the region, the MISO seeks to optimize the efficiency of the interconnected system, provide regional solutions to regional planning needs and minimize risk to reliability through its security coordination, long-term regional planning, market monitoring, scheduling and tariff administration functions. The MISO covers a broad region containing all or parts of 15 states and the Canadian province of Manitoba. The MISO has operational control of OTP’s transmission facilities above 100 kV, but OTP continues to own and maintain its transmission assets.

The MISO Energy Markets commenced operation on April 1, 2005. Through its Energy Markets, MISO seeks to develop options for energy supply, increase utilization of transmission assets, optimize the use of energy resources across a wider region and provide greater visibility of data. MISO aims to facilitate a more cost-effective and efficient use of the wholesale bulk electric system.

The MISO Ancillary Services Market (ASM) commenced on January 6, 2009. The ASM facilitates the provision of Regulation, Spinning Reserve and Supplemental Reserves. The ASM integrates the procurement and use of regulation and contingency reserves with the existing Energy Market. OTP has actively participated in the market since its commencement.

Other

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

Competition, Deregulation and Legislation

Electric sales are subject to competition in some areas from municipally owned systems, rural electric cooperatives and, in certain respects, from on-site generators and cogenerators. Electricity also competes with other forms of energy. The degree of competition may vary from time to time depending on relative costs and supplies of other forms of energy.

The Company believes OTP is well positioned to be successful in a competitive environment. A comparison of OTP’s electric retail rates to the rates of other investor-owned utilities, cooperatives and municipals in the states OTP serves indicates OTP’s rates are competitive.

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

OTP is unable to predict the impact on its operations resulting from future regulatory activities, from future legislation or from future taxes that may be imposed on the source or use of energy.

Environmental Regulation

Impact of Environmental Laws —OTP’s existing generating ~~facilities involves risks~~plants are subject to stringent federal and state standards and regulations regarding, among other things, air, water and solid waste pollution. In the five years ended December 31, 2013 OTP invested approximately $103.2 million in environmental control facilities. The 2014 and 2015 construction budgets include approximately $82 million and $61 million, respectively, for environmental equipment for existing facilities.

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

The primary fuels burned by OTP’s steam generating plants are North Dakota lignite coal and western subbituminous coal. Electrostatic precipitators have been installed at the principal units at the Hoot Lake Plant. Hoot Lake Plant Unit 1, which ~~can adversely affect energy output~~is the smallest of the three coal-fired units at Hoot Lake Plant, was retired as of December 31, 2005. As a result, OTP believes the units at the Hoot Lake Plant currently meet all presently applicable federal and ~~efficiency levels. Most~~state air quality and emission standards.

The South Dakota Department of Environment and Natural Resources (DENR) issued a Title V Operating Permit to the Big Stone site on June 9, 2009 allowing for operation of Big Stone Plant. The Big Stone Plant continues to operate under Title V permit provisions. The Big Stone Plant is currently operating within all presently applicable federal and state air quality and emission standards.

The Coyote Station is equipped with sulfur dioxide (SO2) removal equipment. The removal equipment—referred to as a dry scrubber—consists of a spray dryer, followed by a fabric filter, and is designed to desulfurize hot gases from the stack. The fabric filter collects spray dryer residue along with the fly ash. The Coyote Station is currently operating within all presently applicable federal and state air quality and emission standards.

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

The national SO2 emission reduction goals are achieved through a market based system under which power plants are allocated “emissions allowances” that require plants to either reduce their SO2 emissions or acquire allowances from others to achieve compliance. Each allowance is an authorization to emit one ton of SO2. SO2 emission requirements are currently being met by all of OTP’s generating ~~capacity is coal-fired. OTP relies~~facilities without the need to acquire other allowances for compliance with the acid deposition provisions of the CAA.

The national NOx emission reduction goals are achieved by imposing mandatory emissions standards on individual sources. All of OTP’s generating facilities met the NOx standards during 2013.

The EPA Administrator signed the Clean Air Interstate Rule (CAIR) on March 10, 2005. The EPA has concluded that SO2 and NOx are the chief emissions contributing to interstate transport of particulate matter less than 2.5 microns (PM2.5). The EPA also concluded that NOx emissions are the chief emissions contributing to ozone nonattainment. Twenty-three states and the District of Columbia were found to contribute to ambient air quality PM2.5 nonattainment in downwind states. On that basis, the EPA proposed to cap SO2 and NOx emissions in the designated states. Minnesota was included among the twenty-three states subject to emissions caps; North Dakota and South Dakota were not included. Twenty-five states were found to contribute to downwind 8-hour ozone nonattainment. None of the states in OTP’s service territory were slated for NOx reduction for 8-hour ozone nonattainment purposes. On July 11, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated CAIR and the CAIR federal implementation plan in its entirety.

On December 23, 2008, the court reconsidered its order vacating CAIR, instead remanding the rule to the EPA to conduct further proceedings consistent with the court’s prior opinion invalidating CAIR. On January 16, 2009, the EPA proposed a ~~limited~~rule that would stay the effectiveness of CAIR and the CAIR federal implementation plan for sources in Minnesota while the EPA conducted notice-and-comment rulemaking on remand from the D.C. Circuit’s decisions in the litigation on CAIR. Remanding the issue to the EPA for further consideration, the court held that the EPA had not adequately addressed errors alleged by Minnesota Power in the EPA’s analysis supporting inclusion of Minnesota. Neither the EPA nor any other party sought rehearing of this part of the court’s CAIR decision. Public Notice of the final rule staying the implementation of CAIR in Minnesota appeared in the November 3, 2009 Federal Register.

On July 6, 2010, the EPA proposed the Transport Rule that essentially would replace the CAIR, but which (unlike CAIR) proposed to include Minnesota sources due to a finding that Minnesota’s emissions contribute to PM2.5 nonattainment in downwind states. However, its impact on Hoot Lake Plant and OTP’s Solway combustion turbine under the initial proposal would have been less than what had been contemplated under CAIR. The EPA released the final Transport Rule, renamed as the Cross-State Air Pollution Rule (CSAPR), on July 8, 2011. The final rule made several changes as compared to the proposed rule, including a substantial change in the allowance allocation methodology. A number of ~~suppliers~~states and industry representatives challenged the rule. On December 30, 2011, the U.S. Court of ~~coal, making it vulnerable~~Appeals for the D.C. Circuit granted motions to ~~increased prices~~stay CSAPR pending the court’s resolution of the petitions for ~~fuel as existing contracts expire or~~review. The Court issued an order on August 21, 2012 vacating CSAPR. The order required the EPA to continue administering CAIR pending the promulgation of a valid replacement rule. The United States sought Supreme Court review of the D.C. Circuit’s decision vacating CSAPR, and the Supreme Court granted review. Briefing and oral argument took place in late 2013, and a decision on whether CSAPR will be reinstated is expected before July 2014. In the meantime, because no party sought a stay of the issuance of the mandate in the ~~event of unanticipated interruptions~~D.C. Circuit pending Supreme Court review, CSAPR remains invalidated, and regulated parties must continue to abide by CAIR pending a Supreme Court decision. Since CAIR is currently stayed for Minnesota, and does not apply to North or South Dakota, there is no impact to OTP at this time.

Air Quality – Hazardous Air Pollutants—On December 16, 2011 the EPA signed a final rule to reduce mercury and other air toxics emissions from power plants known as the Mercury and Air Toxics Standards (MATS) rule. The final rule became effective on April 16, 2012, and plants will have until April 16, 2015 to comply. However, the EPA is encouraging state permitting authorities to broadly grant a one-year compliance extension to plants that need additional time to install controls. The DENR granted Big Stone Plant a one-year compliance extension in ~~fuel supply. OTP~~August 2013. The EPA is also providing a ~~captive rail shipper~~pathway for reliability-critical units to obtain an additional year to achieve compliance; however, the EPA has indicated that it believes there will be few, if any situations, in which this pathway is needed. Based on OTP’s review of the ~~BNSF Railway~~final rule, it appears that OTP’s affected units will meet the requirements by installing the AQCS system at Big Stone, by upgrading the electrostatic precipitators on Hoot Lake Units 2 and 3, by installing activated carbon injection on all units, and by possibly installing dry sorbent injection at Hoot Lake Plant. Emissions monitoring equipment and/or stack testing will also be needed to verify compliance with the standards. Numerous petitions were filed in the United States Court of Appeals for ~~shipments~~the D.C. Circuit challenging the MATS rule. The matter has been fully briefed and argued, and a decision is expected in the spring of ~~coal~~2014. Because no stay of the rule was obtained, MATS continues to govern pending resolution of the judicial challenges to the rule.

Air Quality – EPA New Source Review Enforcement Initiative—In 1998 the EPA announced its New Source Review Enforcement Initiative targeting coal-fired utilities, petroleum refineries, pulp and paper mills and other industries for alleged violations of the EPA’s New Source Review rules. These rules require owners or operators that construct new major sources or make major modifications to existing sources to obtain permits and install air pollution control equipment at affected facilities. The EPA is attempting to determine if emission sources violated certain provisions of the CAA by making major modifications to their facilities without installing state-of-the-art pollution controls. On January 2, 2001 OTP received a request from the EPA, pursuant to Section 114(a) of the CAA, to provide certain information relative to past operation and capital construction projects at the Big Stone Plant. OTP responded to that request. In March 2003 the EPA conducted a review of the plant’s outage records as a follow-up to its January 2001 data request. A copy of the designated documents was provided to the EPA on March 21, 2003.

On January 8, 2009, OTP received another request from EPA Regions 5 and 8, pursuant to Section 114(a) of the CAA, to provide certain information relative to past operation and capital construction projects at the Big Stone Plant, Coyote Station and Hoot Lake ~~plants, making it vulnerable~~Plant. OTP filed timely responses to ~~increased prices~~the EPA’s requests on February 23, 2009 and March 31, 2009. In July 2009, EPA Region 5 issued a follow-up information request with respect to certain maintenance and repair work at the Hoot Lake Plant. OTP responded to the request. The EPA has not set forth any additional follow-up requests at this time. OTP cannot determine what, if any, actions will be taken by the EPA.

Air Quality – Regional Haze Program—The EPA promulgated the Regional Haze Rule in 1999, and on June 15, 2005 the EPA provided final guidelines for ~~coal transportation~~conducting BART determinations under the rule. The Regional Haze Rule requires emissions reductions from BART-eligible sources that are deemed to contribute to visibility impairment in Class I air quality areas. Big Stone Plant is BART eligible, and the South Dakota DENR determined that the plant is subject to emission reduction requirements based on the modeled contribution of the plant emissions to visibility impairment in downwind Class I air quality areas. Based on the South Dakota DENR’s BART determination and the final South Dakota Regional Haze State Implementation Plan (SIP) approved by the EPA on March 29, 2012, Big Stone must install Selective Catalytic Reduction (SCR) and separated over-fire air to reduce NOx emissions, dry flue gas desulfurization to reduce SO2 emissions, and a ~~sole supplier. Higher fuel prices result in higher electric rates~~new baghouse for particulate matter control. Big Stone Plant must install and operate the BART compliant air quality control system as expeditiously as practicable, but not later than five years after the EPA’s final approval of May 29, 2012. The current project cost is estimated to be approximately $405 million (OTP’s share would be $218 million).

The North Dakota Regional Haze SIP requires that Coyote Station reduce its NOx emissions. On March 14, 2011 the North Dakota Department of Health (NDDOH) issued a construction permit to Coyote Station requiring installation of control equipment to limit its NOx emissions to 0.5 pounds per million Btu as calculated on a 30-day rolling average basis beginning on July 1, 2018. The current estimate of the total cost of the project is $9 million ($3.2 million for OTP’s ~~retail customers through fuel clause adjustments~~share). On March 1, 2012 the EPA signed a final rule for partial approval of the North Dakota SIP that included the NOx emission rate permit conditions for Coyote Station as proposed by the NDDOH. The rule became effective on May 7, 2012.

In June 2012 the Sierra Club and ~~could make it less competitive~~National Parks Conservation Association (NPCA) filed an appeal of the EPA’s approval of the North Dakota Regional Haze SIP to the U.S. Court of Appeals for the Eight Circuit. On the same day Sierra Club/NPCA also separately filed a petition for reconsideration with the EPA. In the petition for reconsideration filed with the EPA, Sierra Club/NPCA did not take issue with the Coyote Station NOx emission limit. However, in ~~wholesale electric markets. Operational risks also include facility shutdowns due~~the Eighth Circuit appeal, Sierra Club/NPCA filed a brief on October 5, 2012 that included a challenge to ~~breakdown or failure~~the EPA’s determinations relative to Coyote Station. The groups requested the Eighth Circuit reverse and remand the EPA’s SIP approval. An amicus brief was submitted to the Eighth Circuit on behalf of ~~equipment or processes, labor disputes, operator error~~the Coyote Station on December 18, 2012. Oral arguments were held before the Eighth Circuit on May 14, 2013, and ~~catastrophic events such as fires, explosions, floods, intentional acts~~on September 23, 2013 the Eighth Circuit denied the Sierra Club/NPCA appeal with respect to Coyote Station.

Air Quality – Greenhouse Gas (GHG) Regulation—Combustion of ~~destruction or other similar occurrences affecting OTP’s electric generating facilities. The loss~~fossil fuels for the generation of electricity is a major ~~generating facility would require OTP to find other sources~~stationary source of ~~supply, if available, and expose it to higher purchased power costs.~~

OTP monitors and evaluates the ~~direction and scope~~possible adoption of ~~U.S. policy on~~national, regional, or state climate change and ~~regulation of GHGs.~~GHG legislation or regulations that would affect electric utilities. Congress ~~has~~previously considered but has not adopted GHG legislation which would require a reduction in GHG emissions, and there is no legislation under active consideration at this time. The likelihood of any federal mandatory CO2 emissions reduction program being adopted by Congress in the near future, and the specific requirements of any such program, ~~are~~is uncertain. ~~The~~

In April 2007, however, the U.S. Supreme Court issued a decision that determined that the EPA has ~~begun~~authority to regulate CO2 and other GHGs from automobiles as “air pollutants” under the CAA. The Supreme Court directed the EPA to conduct a rulemaking to determine whether GHG emissions ~~under its “endangerment” finding. The EPA has adopted its first GHG emission control rules for~~contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” While this case addressed a provision of the CAA related to emissions from motor vehicles, a parallel provision of the CAA applies to stationary sources such as electric generators; according to the EPA, that parallel provision would be automatically triggered once the EPA began regulating motor vehicle GHG emissions. The first step in the EPA rulemaking process was the publication of an endangerment finding in the December 15, 2009 Federal Register where the EPA found that CO2and five other GHGs – methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride – threaten public health and the environment.

The EPA’s final findings respond to the 2007 U.S. Supreme Court decision that GHGs fit within the CAA’s definition of air pollutants. The findings do not in and of themselves impose any emission reduction requirements but rather allowed the EPA to finalize the GHG standards for new ~~source review~~light-duty vehicles as part of the joint rulemaking with the Department of Transportation. These standards apply to motor vehicles as of January 2011, which makes GHGs “subject to regulation” under the CAA. This, then, triggered the Prevention of Significant Deterioration (PSD) and Title V operating permits programs for stationary sources of GHGs. The question of whether the regulation of motor vehicle emissions does in fact automatically trigger regulation of stationary sources of ~~GHGs,~~the same pollutant is presently under review by the Supreme Court. The case is fully briefed, and oral argument will be held on February 24, 2014. A decision is not expected until June or July 2014.

On June 6, 2010 the EPA published a final “tailoring rule” that phases in application of its PSD and Title V programs to GHG emission sources, including power plants. The PSD program applies to existing sources if there is a physical change or change in the method of operation of the facility that results in a significant net emissions increase of any pollutant. As a result, PSD does not apply on a set timeline as is the case with other regulatory programs, but is triggered depending on what activities take place at a major source. If triggered, the owner or operator of an affected facility must undergo a review which ~~became applicable~~requires the identification and implementation of best-available control technology (BACT) for the regulated air pollutants for which there is a significant net emissions increase, and an analysis of the ambient air quality impacts of the facility.

As of July 2011, sources emitting more than 100,000 tons per year of “CO2e”, a measure that converts emissions of each GHG into its carbon dioxide equivalent, are considered “major sources” subject to ~~motor vehicles~~PSD requirements if they propose to make modifications resulting in a net GHG emissions increase of 75,000 tons per year or more of CO2e. OTP does not anticipate making modifications at any of its facilities that would trigger PSD requirements. The South Dakota DENR reviewed OTP’s projected emissions, including GHG emissions, as a result of the Big Stone Plant AQCS Project and ~~stationary sources, respectively,~~the DENR agreed that the emissions did not trigger the need for a PSD permit. Consequently, the DENR issued an Air Quality Construction Permit for the Big Stone Plant AQCS Project on January ~~2, 2011. The~~6, 2012.

Concurrently, the EPA is developing ~~standards~~New Source Performance Standards (NSPS) for GHGs from fossil fuel-fired electric generating ~~units and~~units. The EPA proposed a rule on ~~April 13, 2012~~January 8, 2014 that would ~~require certain~~subject large new ~~fossil fuel generating plants~~coal-fired units to ~~meet~~ a GHG emission limit of 1,100 lbs. of CO2~~output~~ per megawatt-hour (mwh) averaged over a 12-month period, or possibly a limit of 1,000-1,050 pounds of CO2 averaged over a period of seven years. This limit is based ~~standard.~~on emission reductions the EPA believes could be achieved through the installation and operation of partial carbon capture and sequestration technology. Certain new natural gas-fired units would be subject to a limit of 1,000 or 1,100 pounds of CO2 per mwh, dependent on unit size, which is the emissions level the EPA believes natural gas combined cycle units can currently achieve with no additional add-ons. Unlike traditional NSPS rules, the proposed GHG NSPS would not apply to modifications at existing units. ItUnder Section 111(b) of the CAA, the EPA must finalize the standard within a year of its proposal, or by January 8, 2015. However, it is expected ~~that~~the EPA will issue a final rule in the ~~first~~second half of 2014. If finalized, the NSPS would apply to any unit the construction of which commences after the date of the proposal, or January 8, 2014.

The EPA also intends to develop GHG performance standards for existing sources under CAA Section 111(d) (111(d) Standard). A 111(d) Standard, unlike a NSPS, applies to existing sources of a pollutant. Under Section 111(d), the EPA does not itself issue the standards. Rather, the EPA promulgates emission guidelines, and the states are then given a period of time to develop plans to implement the standard. The EPA reviews each state-developed standard and then approves it if the state’s plan comports with the federal emission guidelines; if the state does not submit a plan, or if the EPA finds that the plan is inadequate, the EPA will prescribe a plan for that state. The EPA has indicated that it intends to sign proposed emission guidelines by June 1, 2014, to finalize those guidelines by June 1, 2015 and to require state submissions by June 30, 2016.

For both new and existing sources, the EPA must develop a “standard of performance,” which is defined as:

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

For existing sources, Section 111(d) also requires the EPA to consider, “among other factors, remaining useful lives of the sources in the category of sources to which such standard applies.” In general, the standards ultimately developed are more stringent for new sources than for existing sources, because existing source standards need to consider the issues involved in retrofitting plants considering what can be achieved under their existing design, as well as the cost of implementing the standard relative to the remaining useful life of the facility. The standards also need to be capable of attainment across the category of sources regulated by the standard.

While the potential impact of a 111(d) Standard on OTP’s facilities is not yet known, standards of performance for existing sources of GHGs are anticipated to focus on efficiency improvements rather than add-on controls. The cost of efficiency improvements that achieve generation of the same amount of power with less fuel used could be offset in whole or in part by reduced fuel costs. It is also possible that the EPA will allow the states to claim credit for reductions in GHG emissions that are achieved through programs designed to reduce end-user demand and that it will allow the states, either separately or together, to establish emission averaging and emission credit banking and trading systems (i.e., a cap-and-trade program).

Litigation over both the NSPS and the emission guidelines for existing sources is expected. Thus, uncertainty over whether the standards will be enforced or, if so, what will be permitted, may continue for a number of years.

Several states and regional organizations are also developing, or already have developed, state-specific or regional legislative initiatives to reduce GHG emissions through mandatory programs. In 2007, the state of Minnesota passed legislation regarding renewable energy portfolio standards that requires retail electricity providers to obtain 25% of the electricity sold to Minnesota customers from renewable sources by the year 2025. Additionally, in 2013 the state of Minnesota passed a provision that requires public utilities to generate or procure sufficient electricity generated by solar energy to serve its retail electricity customers in Minnesota so that by the end of 2020, at least 1.5% of the utility’s total retail electric sales to retail customers in Minnesota is generated by solar energy. Regarding CO2, the Minnesota legislature set a January 1, 2008 deadline for the MPUC to establish an estimate of the likely range of costs of future CO2 regulation on electricity generation. The legislation also set state targets for reducing fossil fuel use, included goals for reducing the state’s output of GHGs, and restricted importing electricity that would contribute to statewide power sector CO2 emission. The MPUC, in its order dated December 21, 2007, established an estimate of future CO2 regulation costs at between $4/ton and $30/ton emitted in 2012 and after. However, annual updates of the range are required, and for 2012 and 2013 the range was revised to $9-$34/ton, and the start date to begin using CO2 costs in resource planning decisions was moved from 2012 to 2017.

The states of North Dakota and South Dakota currently have no proposed or pending legislation related to the regulation of GHG emissions, but North Dakota and South Dakota have 10% renewable energy objectives.

While the eventual outcome of proposed and pending climate change legislation and GHG regulation is unknown, OTP is taking steps to reduce its carbon footprint and mitigate levels of CO2 emitted in the process of generating electricity for its customers through the following initiatives:

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Supply efficiency and reliability: OTP’s efforts to increase plant efficiency and add renewable energy to its resource mix have reduced its CO2 intensity. Between 1985 and 2013 OTP decreased its overall system average CO2 emissions intensity by approximately 23%. Further reductions are expected with the additional purchase of 62.4 MW of wind-powered generation under the Ashtabula Wind III wind power purchase agreement, under which energy delivery commenced in October 2013, and with the anticipated replacement of Hoot Lake Plant generation likely with natural gas in the 2020 timeframe.

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Conservation: Since 1992 OTP has helped its customers conserve nearly 600 MW of demand and nearly 2.8 million cumulative mwhs of electricity, which is roughly equivalent to the amount of electricity that 232,000 average homes would use in a year. OTP continues to educate customers about energy efficiency and demand-side management and to work with regulators to develop new programs. OTP’s 2014-2028 IRP calls for an additional 106 MW of conservation and demand side management impacts by 2028.

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Renewable energy: Since 2002, OTP’s customers have been able to purchase 100% of their electricity from wind generation through OTP’s TailWinds program. OTP has access to 102.9 MW of wind powered generation under power purchase agreements and owns 138 MW of wind powered generation.

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Other: OTP is a participating member of the EPA’s SF6 (sulfur hexafluoride) Emission Reduction Partnership for Electric Power Systems program, which proactively is targeting a reduction in emissions of SF6, a potent GHG. SF6 has a global-warming potential 23,900 times that of CO2. Methane has a global-warming potential over 20 times that of CO2. OTP participates in carbon sequestration research through the Plains CO2 Reduction Partnership (PCOR) through the University of North Dakota’s Energy and Environmental Research Center. The PCOR Partnership is a collaborative effort of approximately 100 public and private sector stakeholders working toward a better understanding of the technical and economic feasibility of capturing and storing anthropogenic CO2 emissions from stationary sources in central North America.

In late 2009, two federal circuit courts of appeal reversed dismissals of GHG suits and remanded them to district court for trial. OTP was not a party to any of these suits, and does not have an indication that it will be the subject of such a lawsuit. The circuit court opinions, however, opened utility companies and other GHG emitters to these actions, which had previously been dismissed by the district courts as nonjustifiable based on the political question doctrine. In 2010, the U.S. Supreme Court took review of one of these cases, while declining review of another. On June 20, 2011, the Supreme Court ruled unanimously that states cannot invoke federal law to force utilities to cut GHG emissions, which was in agreement with the position of utilities and the EPA.

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

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

Effluent limits specific to Hoot Lake Plant and Coyote Station are incorporated into their National Pollutant Discharge Elimination System (NPDES) permits. Big Stone Plant is a zero discharge facility and therefore does not have a NPDES permit. The EPA announced its decision to proceed with further possible revisions to steam effluent guidelines on September 15, 2009, and published a proposed rulemaking on June 7, 2013. ~~Specific~~The proposed rulemaking primarily focuses on discharge restrictions applicable to fly ash transport water, bottom ash transport water, and flue gas desulfurization wastewater. Since the steam effluent guidelines rule is not final, at this time OTP is unable to determine how it will affect our facilities, but it appears that the rule could have minimal effect since the facilities do not discharge fly ash transport water, bottom ash transport water, or flue gas desulfurization wastewater into waters of the United States.

On February 16, 2004 the EPA Administrator signed the final Phase II rule implementing Section 316(b) of the Clean Water Act establishing standards for cooling water intake structures for certain existing facilities. A proposed 316(b) rule was issued on April 20, 2011 to replace the 2004 Phase II rule for existing facilities following its remand by the U.S. Court of Appeals in 2007. Unlike the 2004 Phase II rule, the proposed rule has the potential to affect both Hoot Lake Plant and Coyote Station with the greatest potential effect on Hoot Lake Plant. The final rule is expected to be signed in early 2014, though the EPA has repeatedly missed self-imposed deadlines for finalizing the rule. OTP is uncertain of the impact on the potentially affected facilities until the EPA releases the final rule, and likely until after discussions with state regulatory agencies.

OTP has all federal and state water permits presently necessary for the operation of the Coyote Station, the Big Stone Plant and the Hoot Lake Plant. OTP owns five small dams on the Otter Tail River, which are subject to FERC licensing requirements. A license for all five dams was issued on December 5, 1991. Total nameplate rating (manufacturer’s expected output) of the five dams is 3,450 kW.

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

On June 21, 2010 the EPA published a proposed rule that outlines two possible options to regulate disposal of coal ash generated from the combustion of coal by electric utilities under the Resource Conservation and Recovery Act (RCRA). In one option, the EPA would propose to list coal ash destined for disposal in landfills or surface impoundments as “special wastes” subject to regulation under Subtitle C of RCRA. Subtitle C regulations set forth the EPA’s hazardous waste regulatory program, which regulates the generation, handling, transport and disposal of wastes.

The proposal would create a new category of special waste under Subtitle C, so that coal ash would not be classified as hazardous waste, but would be subject to many of the regulatory requirements applicable to hazardous waste. This option would subject coal ash to technical and permitting requirements from the point of generation to final disposal. The EPA is considering whether to impose disposal facility requirements such as liners, groundwater monitoring, fugitive dust controls, financial assurance, corrective action, closure of units, and post-closure care. This option also includes potential requirements for dam safety and stability for surface impoundments, land disposal restrictions, treatment standards for coal ash, and a prohibition on the disposal of treated coal ash below the natural water table. Beneficial re-uses of coal ash would not be subject to these requirements.

Under the second proposed regulatory option, the EPA would regulate the disposal of coal ash under Subtitle D of RCRA, the regulatory program for non-hazardous solid wastes. In this option, the EPA is considering issuing national minimum criteria to ensure the safe disposal of coal ash, which would subject disposal units to location standards, composite liner requirements, groundwater monitoring and corrective action standards for releases, closure and post-closure care requirements, and requirements to address the stability of surface impoundments. Within this option, the EPA is also considering not requiring existing surface impoundments to close or install composite liners and allowing them to continue to operate for their useful life.

This option would not regulate the generation, storage, or treatment of coal ash prior to disposal, and no federal permits would be required. The EPA’s proposal also states that the EPA is considering whether to list coal ash as a hazardous substance under the Comprehensive Environmental Response, Compensation, and Liability Act, and includes proposals for alternative methods to adjust the statutory reportable quantity for coal ash. The EPA has not decided which regulatory approach it will take with respect to the management and disposal of coal ash. It has suggested, however, that if it finalizes a related Clean Water Act rule regarding effluent limitation guidelines for the steam electric power generating category that are expected to drive utilities to dry-handle their coal combustion residues, then an RCRA rule allowing coal ash to be treated as non-hazardous solid waste may be adequate.

Additional requirements may be imposed as part of the EPA’s pending rule, which could increase the capital and operating costs of OTP’s facilities. Identification of specific costs is contingent on the requirements of ~~regulation~~the final rule. The most costly option in the EPA proposal is the option that would regulate all coal ash destined for disposal as special waste. For example, under this option, OTP estimates an annual cost of approximately $5.75 million at its Big Stone Plant. If the ~~CAA’s~~EPA chooses the other option, it would impose less cost than this estimate. It is also possible the new regulations would not require change in the current operation and cost of OTP’s coal ash disposal sites.

At the request of the Minnesota Pollution Control Agency (MPCA), OTP has an ongoing investigation at its former, closed Hoot Lake Plant ash disposal sites. The MPCA continues to monitor site activities under its Voluntary Investigation and Cleanup (VIC) Program. OTP provided a revised focus feasibility study for remediation alternatives to the MPCA in October 2004. OTP and the MPCA have reached an agreement identifying the remediation technology and OTP completed the projects in 2006. The effectiveness of the remediation is under ongoing evaluation and OTP has notified the MPCA of an additional project in 2014 with plans to remove the ash from one VIC area and place it in OTP’s permitted disposal area.

The EPA has promulgated various ~~programs,~~solid and ~~thus their~~hazardous waste regulations and guidelines pursuant to, among other laws, the Resource Conservation and Recovery Act of 1976, the Solid Waste Disposal Act Amendments of 1980 and the Hazardous and Solid Waste Amendments of 1984, which provide for, among other things, the comprehensive control of various solid and hazardous wastes from generation to final disposal. The states of Minnesota, North Dakota and South Dakota have also adopted rules and regulations pertaining to solid and hazardous waste. To date, OTP has incurred no significant costs as a result of these laws. The future total impact on OTP ~~are uncertain~~of the various solid and hazardous waste statutes and regulations enacted by the federal government or the states of Minnesota, North Dakota and South Dakota is not certain at this time.

In 1980, the United States enacted the Comprehensive Environmental Response, Compensation and Liability Act, commonly known as the Federal Superfund law, which was reauthorized and amended in 1986. In 1983, Minnesota adopted the Minnesota Environmental Response and Liability Act, commonly known as the Minnesota Superfund law. In 1988, South Dakota enacted the Regulated Substance Discharges Act, commonly known as the South Dakota Superfund law. In 1989, North Dakota enacted the Environmental Emergency Cost Recovery Act. Among other requirements, the federal and state acts establish environmental response funds to pay for remedial actions associated with the release or threatened release of certain regulated substances into the environment. These federal and state Superfund laws also establish liability for cleanup costs and damage to the environment resulting from such release or threatened release of regulated substances. The Minnesota Superfund law also creates liability for personal injury and economic loss under certain circumstances. OTP has not incurred any significant costs to date related to these laws. OTP is not presently named as a potentially responsible party under the federal or state Superfund laws.

Capital Expenditures

OTP is continually expanding, replacing and improving its electric facilities. During 2013, approximately $149 million in cash was invested for additions and replacements to its electric utility properties. During the five years ended December 31, 2013 gross electric property additions, including construction work in progress, were approximately $474 million and gross retirements were approximately $60 million. OTP estimates that during the five-year period 2014-2018 it will invest approximately $657 million for electric construction, which includes $131 million for OTP’s share of the Big Stone Plant AQCS and $304 million for transmission projects including $243 million for MVPs and $26 million for CapX2020 transmission projects ($7 million for the Brookings to Southeast Twin Cities CapX2020 MVP project is included with the $243 million for MVP projects). The remainder of the 2014-2018 anticipated capital expenditures is for asset replacements, additions and improvements across OTP’s generation, transmission, distribution and general plant. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Requirements” section for further discussion.

Franchises

At December 31, 2013 OTP had franchises to operate as an electric utility in substantially all of the incorporated municipalities it serves. All franchises are nonexclusive and generally were obtained for 20-year terms, with varying expiration dates. No franchises are required to serve unincorporated communities in any of the three states that OTP serves. OTP believes that its franchises will be renewed prior to expiration.

Employees

At December 31, 2013 OTP had 668 equivalent full-time employees. A total of 397 OTP employees are represented by local unions of the International Brotherhood of Electrical Workers under two separate contracts expiring in the fall of 2014 and 2016. OTP has not experienced any strike, work stoppage or strike vote, and considers its present relations with employees to be good.

MANUFACTURING

General

Manufacturing consists of businesses engaged in the following activities: contract machining, metal parts stamping and fabrication, and production of material handling trays and horticultural containers.

The Company derived 23%, 24% and 23% of its consolidated operating revenues and 21%, 26% and 22% of its consolidated operating income from the Manufacturing segment for the years ended December 31, 2013, 2012 and 2011, respectively. Following is a brief description of each of these businesses:

BTD Manufacturing, Inc. (BTD), with headquarters located in Detroit Lakes, Minnesota, is a metal stamping and tool and die manufacturer that provides its services mainly to customers in the Midwest. BTD stamps, fabricates, welds and laser cuts metal components according to manufacturers’ specifications primarily for the recreational vehicle, agricultural, lawn and garden, industrial equipment, health and fitness and enclosure industries in its facilities in Detroit Lakes, Otsego and Lakeville, Minnesota, and Washington, Illinois. BTD’s Illinois facility also manufactures and fabricates parts for off-road equipment, mining machinery, oil fields and offshore oil rigs, wind industry components, broadcast antennae and farm equipment, and serves several major equipment manufacturers in the Peoria, Illinois area and nationwide, including Caterpillar, Komatsu and Gardner Denver.

T. O. Plastics, Inc. (T.O. Plastics), located in Otsego and Clearwater, Minnesota, manufactures and sells thermoformed products for the horticulture industry throughout the United States. In addition, T.O. Plastics produces products such as clamshell packing, blister packs, returnable pallets and handling trays for shipping and storing odd-shaped or difficult-to-handle parts for customers in the consumer products, food packaging, electronics, industrial and medical industries, among others. T.O. Plastics’ Otsego thermoforming facility achieved an AIB International (formerly American Institute of Baking) compliance rating for producing food-contact packaging materials in its operations.

Competition

The various markets in which the Manufacturing segment entities compete are characterized by intense competition from both foreign and domestic manufacturers. These markets have many established manufacturers ~~the price and availability of raw materials and general economic conditions could affect the revenues and earnings of our manufacturing businesses.~~

~~Our manufacturing businesses are subject to intense risks associated~~ with ~~competition from foreign and domestic manufacturers, many of whom have~~ broader product lines, greater distribution capabilities, greater capital resources, excess capacity, labor advantages and larger marketing, research and development staffs and facilities than the Company’s manufacturing entities.

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

Raw Materials Supply

The companies in ~~our~~the Manufacturing segment use ~~a variety of~~ raw materials in the products they manufacture, including steel, aluminum and ~~Polystyrene (PS)~~polystyrene and other plastics resins. ~~Costs for~~Both pricing increases and availability of these ~~items have increased significantly and may continue to increase. If our manufacturing businesses~~raw materials are ~~not able~~concerns of companies in the Manufacturing segment. The companies in the Manufacturing segment attempt to pass increases in the costs of these raw materials on ~~cost increases~~ to their customers. Increases in the costs of raw materials that cannot be passed on to customers it could have a negative effect on profit margins in ~~our~~the Manufacturing segment.

~~Each~~Backlog

The Manufacturing segment has backlog in place to support 2014 revenues of ~~our~~approximately $136 million compared with $124 million one year ago.

Capital Expenditures

Capital expenditures in the Manufacturing segment typically include additional investments in new manufacturing equipment or expenditures to replace worn-out manufacturing equipment. Capital expenditures may also be made for the purchase of land and buildings for plant expansion and for investments in management information systems. During 2013, cash expenditures for capital additions in the Manufacturing segment were approximately $7 million. Total capital expenditures for the Manufacturing segment during the five-year period 2014-2018 are estimated to be approximately $81 million.

Employees

At December 31, 2013 the Manufacturing segment had 1,059 full-time employees. There are 932 full-time employees at BTD and 127 full-time employees at T.O. Plastics.

PLASTICS

General

Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The Company derived 18%, 18% and 15% of its consolidated operating revenues and 25%, 32% and 15% of its consolidated operating income from the Plastics segment for the years ended December 31, 2013, 2012 and 2011, respectively. Following is a brief description of these businesses:

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

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

Together these companies ~~has significant~~have the current capacity to produce approximately 300 million pounds of PVC pipe annually.

Customers

PVC pipe products are marketed through a combination of independent sales representatives, company salespersons and customer service representatives. Customers for the PVC pipe products consist primarily of wholesalers and distributors throughout the northern, midwestern, south-central and western United States.

Competition

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

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

Manufacturing and Resin Supply

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

The PVC resins are acquired in bulk and ~~concentrated sales~~shipped to point of use by rail car. There are a limited number of third party vendors that supply the PVC resin used by Northern Pipe and Vinyltech. Two vendors provided approximately 93% and 90% of total resin purchases in 2013 and 2012, respectively. The supply of PVC resin may also be limited primarily due to manufacturing capacity and the limited availability of raw material components. A majority of U.S. resin production plants are located in the Gulf Coast region, which is subject to risk of damage to the plants and potential shutdown of resin production because of exposure to hurricanes that occur in that part of the United States. The loss of a key vendor, or any interruption or delay in the supply of PVC resin, could disrupt the ability of the Plastics segment to manufacture products, cause customers to cancel orders or require incurrence of additional expenses to obtain PVC resin from alternative sources, if such ~~customers. If our~~sources were available. Both Northern Pipe and Vinyltech believe they have good relationships with ~~significant customers should change materially, it would be difficult to immediately and profitably replace lost sales.~~their key raw material vendors.

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

Capital Expenditures

Capital expenditures in the Plastics segment typically include investments in extrusion machines, land and buildings and management information systems. During 2013, cash expenditures for capital additions in the Plastics segment were approximately $3 million. Total capital expenditures for the five-year period 2014-2018 are estimated to be approximately $14 million to replace existing equipment.

Employees

At December 31, 2013 the Plastics segment had 136 full-time employees. Northern Pipe had 89 full-time employees and Vinyltech had 47 full-time employees as of December 31, 2013.

CONSTRUCTION

General

~~A significant failure~~

Construction consists of businesses involved in commercial and industrial electric contracting and construction of fiber optic and electric distribution systems, water, wastewater and HVAC systems primarily in the central United States.

The Company derived 17%, 17% and 22% of its consolidated operating revenues and 3%, (15)% and (4)% of its consolidated operating income from the Construction segment for each of the years ended December 31, 2013, 2012 and 2011, respectively. Following is a brief description of the businesses included in this segment:

Foley Company (Foley), headquartered in Kansas City, Missouri, provides mechanical and prime contracting services for water and wastewater treatment plants, power generation plants, hospital and pharmaceutical facilities, and other industrial and manufacturing projects across a multi-state service area in the United States.

Aevenia, Inc. (Aevenia), located in Moorhead, Minnesota, has divisions that provide a full spectrum of electrical design and construction services for the industrial, commercial and municipal business markets, including government, institutional, utility communications and electric distribution.

Competition

Each of the construction companies is subject to competition, as well as the effects of general economic conditions in their respective disciplines and geographic locations. The construction companies must compete with other construction companies primarily in the Upper Midwest and the Central regions of the United States, including companies with greater financial resources, when bidding on new projects. The Company believes the principal competitive factors in the Construction segment are price, quality of work and customer service.

Backlog

The construction companies have backlog in place of $77 million for 2014 compared with $151 million one year ago.

Capital Expenditures

Capital expenditures in this segment typically include investments in additional construction equipment. During 2013, cash expenditures for capital additions in the Construction segment were approximately $5 million. Capital expenditures during the five-year period 2014-2018 are estimated to be approximately $17 million for the Construction segment.

Employees

At December 31, 2013 there were 426 full-time employees in the Construction segment. There are 232 full-time employees at Foley and 194 full-time employees at Aevenia. Foley has 178 employees represented by various unions, including Carpenters and Millwrights, Laborers, Operating Engineers, Pipe Fitters, Plumbers, Teamsters and Cement Masons. Foley has several labor contracts with various expiration dates in 2014 (124 employees), one contract that expires in March 2015 (14 employees), one contract that expires in April 2017 (8 employees) and one contract that expires in May 2018 (11 employees). Foley also employs 21 people under contracts held by the Tennessee Valley Authority. Foley has not experienced any strike, work stoppage or ~~an inability~~strike vote, and considers its present relations with employees to ~~properly bid~~be good.

Item 1A. RISK FACTORS

RISK FACTORS AND CAUTIONARY STATEMENTS

Our businesses are subject to various risks and uncertainties. Any of the risks described below or ~~perform~~elsewhere in this Annual Report on ~~projects~~Form 10-K or ~~contracts by~~in our ~~construction businesses~~other SEC filings could ~~lead to adverse~~materially adversely affect our business, financial condition and results ~~and could lead to the possibility~~ of ~~delay or liquidated damages.~~operations.

~~The profitability~~GENERAL

Federal and ~~success of our construction companies~~state environmental regulation could require us to ~~identify, estimate~~incur substantial capital expenditures and timely bid on profitable projects or contracts. The quantity and quality of projects up for bid at any time is uncertain. Additionally, once a project or contract is awarded, we must be able to perform within cost estimates that were set when the bid was submitted and accepted. A significant failure or an inability to properly bid or perform on projects or contracts could lead to adverse financial results and could lead to the possibility of delay or liquidated damages.increased operating costs.

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

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

Volatile financial markets and changes in our debt ratings could restrict our ability to access capital and increase borrowing costs and pension plan and postretirement health care expenses.

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

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

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

Discretionary contributions totaling $20.0 million were made to our defined benefit pension plan in January 2014. We could be required to contribute additional capital to the pension plan in the future if the market value of pension plan assets significantly declines, plan assets do not ~~within~~earn in line with our ~~control,~~long-term rate of return assumptions or relief under the Pension Protection Act is no longer granted.

Any significant impairment of our goodwill would cause a decrease in our asset values and a reduction in our net operating income.

We had approximately $39.0 million of goodwill recorded on our consolidated balance sheet as of December 31, 2013. We have recorded goodwill for businesses in each of our business segments except Electric. If we make changes in our business strategy or if market or other conditions adversely affect operations in any of these businesses, we may be forced to record an impairment charge, which would lead to decreased assets and a reduction in net operating performance. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying amount of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including changes in economic, industry or market conditions, changes in business operations, future business operating performance, changes in competition or changes in technologies. Any changes in key assumptions, or actual performance compared with key assumptions, about our business and its future prospects or other assumptions could affect the fair value of one or more business segments, which may result in an impairment charge.

Declines in projected operating cash flows at any of our reporting units may result in goodwill impairments that could adversely affect our results of operations and financial position, as well as financing agreement covenants.

We currently have $7.3 million of goodwill and a $1.1 million indefinite-lived trade name recorded on our consolidated balance sheet related to the acquisition of Foley in 2003. Foley net earnings improved $10.4 million between 2012 and 2013. If future expected operating profits do not meet our projections, reductions in anticipated cash flows from Foley may indicate its fair value is less than its book value, resulting in an impairment of some or all of the goodwill and indefinite-lived intangible assets associated with Foley along with a corresponding charge against earnings.

The inability of our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and debt covenants and pay dividends to our shareholders could have an adverse effect on the Company.

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

Under our $150 million revolving credit agreement we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00. OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 under its $170 million revolving credit agreement. Both credit agreements contain restrictions on the payment of cash dividends on a default or event of default. As of December 31, 2013 we were in compliance with the debt covenants.

Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials. The MPUC indirectly limits the amount of dividends OTP can pay to us by requiring an equity-to-total-capitalization ratio between 44.8% and 54.8%. OTP’s equity-to-total-capitalization ratio was 50.2% as of December 31, 2013.

While these restrictions are not expected to affect our ability to pay dividends at the current level in the foreseeable future, there is no assurance that adverse financial results would not reduce or eliminate our ability to pay dividends. Our dividend payout ratio has exceeded our earnings (losses) in four of the last five years.

Economic conditions could negatively impact our businesses.

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

If we are unable to achieve the organic growth we expect, our financial performance may be adversely affected.

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

Our plans to grow and realign our business mix through capital projects, acquisitions and dispositions may not be ~~recoverable~~successful, which could result in poor financial performance.

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

We may, from time to time, sell assets to provide capital to fund investments in our electric utility business or for other corporate purposes, which could result in the recognition of a loss on the sale of any assets sold and other potential liabilities. The sale of any of our businesses also exposes us to additional risks associated with indemnification obligations under the applicable sales agreements and any related disputes.

As part of our business strategy, we continually assess our business portfolio to determine if our operating companies continue to meet our portfolio criteria. A loss on the sale of a business would be recognized if a company is sold for less than its book value.

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

Our plans to grow and operate our manufacturing and infrastructure businesses could be limited by state law.

Our plans to grow and operate our manufacturing and infrastructure businesses could be adversely affected by legislation in one or more states that may attempt to limit the amount or level of diversification permitted in a holding company structure that includes a regulated utility company or affiliated nonelectric companies.

Significant warranty claims and remediation costs in excess of amounts normally reserved for such items could adversely affect our results of operations and financial condition.

Depending on the specific product or service, we may provide certain warranty terms against manufacturing defects and certain materials. We reserve for warranty claims based on industry experience and estimates made by management. For some of our products we have limited history on which to base our warranty estimate. Our ~~construction companies frequently provide services pursuant~~assumptions could be materially different from any actual claim and could exceed reserve balances.

Expenses associated with remediation activities of our former wind tower manufacturer, could be substantial. The potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to ~~fixed-price contracts. Revenues recognized on jobs~~repair or replace the defective part is highly disproportionate to the original cost of the part. If we are required to cover remediation expenses in ~~progress under fixed-price contracts were $309 million at December 31, 2012~~addition to our regular warranty coverage, we could be required to accrue additional expenses and ~~$343 million at December 31, 2011. Under those contracts,~~experience additional unplanned cash expenditures which could adversely affect our consolidated results of operations and financial condition.

We are subject to risks associated with energy markets.

Our businesses are subject to the risks associated with energy markets, including market supply and increasing energy prices. If we ~~agree~~are faced with shortages in market supply, we may be unable to ~~perform the contract for a fixed price and, as a result, can improve~~fulfill our ~~expected profit by superior contract performance, productivity, worker safety~~contractual obligations to our retail, wholesale and other ~~factors resulting~~customers at previously anticipated costs. This could force us to obtain alternative energy or fuel supplies at higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher than expected energy or fuel costs would negatively affect our financial performance.

We are subject to risks and uncertainties related to the timing of recovery of deferred tax assets which could have a negative impact on our net income in ~~cost savings. However, we could incur cost overruns above the approved contract price, which may not be recoverable.~~future periods.

~~Fixed-price contract prices are established based largely on estimates~~If taxable income is not generated in future periods in certain tax jurisdictions the recovery of deferred taxes related to accumulated tax benefits may be delayed and assumptions relating to project scope and specifications, personnel and material needs. These estimates and assumptions may prove inaccurate or conditions may change due to factors out of our control, resulting in cost overruns, which we may be required to record a reserve related to the uncertainty of the timing of recovery of deferred tax assets related to accumulated taxable losses in those tax jurisdictions. This would have a negative impact on the Company’s net income in the period the reserve is recorded.

We rely on our information systems to conduct our business, and failure to protect these systems against security breaches or cyber-attacks could adversely affect our business and results of operations. Additionally, if these systems fail or become unavailable for any significant period of time, our business could be harmed.

Our electric utility company, OTP, owns electric transmission and generation facilities subject to mandatory and enforceable standards advanced by the North American Electric Reliability Corporation (NERC). These bulk electric system facilities provide the framework for the electrical infrastructure of OTP’s service territory and interconnected systems, the operation of which is dependent on information technology systems. Further, the information systems that operate OTP’s electric system are interconnected to external networks. Parties that wish to disrupt the U.S. bulk power system or OTP’s operations could view OTP’s computer systems, software or networks as attractive targets for cyber-attack. Also, our businesses require us to collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss. We also use third-party vendors to electronically process certain of our business transactions. The efficient operation of our business is dependent on computer hardware and software systems. Information systems, both ours and those of third-party information processors, are vulnerable to security breach by computer hackers and cyber terrorists.

A successful cyber-attack on the systems that control our generation, transmission, distribution or other assets could severely disrupt business operations, preventing us from serving customers or collecting revenues. The breach of certain business systems could affect our ability to correctly record, process and report financial information and transactions. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. We maintain property and casualty insurance that may cover certain physical damage or third party injuries caused by potential cybersecurity incidents. However, other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available.

OTP is subject to mandatory cybersecurity regulatory requirements. OTP implements the NERC standards for operating its transmission and generation assets and stays abreast of best practices within business and the utility industry to protect its computers and computer controlled systems from outside attack. We rely on industry accepted security measures and technology to securely maintain confidential and proprietary information maintained on our information systems. In an effort to reduce the likelihood and severity of cyber intrusions, we have cybersecurity processes and controls designed to protect and preserve the confidentiality, integrity and availability of data and systems. However, all these measures and technology may not adequately prevent security breaches or cyber-attacks. In addition, the unavailability of the information systems or failure of these systems to perform as anticipated for any reason could disrupt our business and could result in decreased performance and increased overhead costs, causing our business and results of operations to suffer. Any significant interruption or failure of our information systems or any significant breach of security due to cyber-attacks, hacking or internal security breaches could adversely affect our business and results of operations.

ELECTRIC

We may experience fluctuations in revenues and expenses related to our electric operations, which may cause our financial results to fluctuate and could impair our ability to make distributions to shareholders or scheduled payments on our debt obligations, or to meet covenants under our borrowing agreements.

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

Actions by the regulators of our electric operations could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures.

We are subject to federal and state legislation, government regulations and regulatory actions that may have a negative impact on our business and results of operations. The electric rates that OTP is allowed to charge for its electric services are one of the most important items influencing our financial position, results of operations and liquidity. The rates that OTP charges its electric customers are subject to review and determination by state public utility commissions in Minnesota, North Dakota and South Dakota. OTP is also regulated by the FERC. An adverse decision by one or more regulatory commissions concerning the level or method of determining electric utility rates, the authorized returns on equity, implementation of enforceable federal reliability standards or other regulatory matters, permitted business activities (such as ownership or operation of nonelectric businesses) or any prolonged delay in rendering a decision in a rate or other proceeding (including with respect to the recovery of capital expenditures in rates) could result in lower revenues and net income.

Depending on the outcome of the U.S. Supreme Court review of the 7th Circuit U.S. Court of Appeals decision relating to MVPs, OTP could be required to absorb a disproportionate share of costs for transmission investments if the MISO MVP cost allocation changes. These costs may not be recoverable through a transmission tariff and could result in reduced returns on invested capital and/or increased rates to OTP’s retail electric customers. Depending on the outcome of a November 12, 2013 FERC complaint filed by a group of industrial customers and other stakeholders seeking to reduce the return on equity component of the transmission rates that MISO transmission owners, including OTP, may collect under the relevant MISO tariff, OTP may receive a lower return on equity on its MISO transmission rates and this may impact future revenues for transmission services provided in MISO.

OTP’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

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

Changes to regulation of generating plant emissions, including but not limited to CO2 emissions, could affect our operating costs and the costs of supplying electricity to our customers.

Existing or new laws or regulations passed or issued by federal or state authorities addressing climate change or reductions of greenhouse gas emissions, such as mandated levels of renewable generation, mandatory reductions in CO2 emission levels, taxes on CO2 emissions or cap and trade regimes, could require us to incur significant new costs, which could negatively impact our net income, financial position and operating cash flows if such costs cannot be recovered through rates granted by ratemaking authorities in the states where OTP provides service or through increased market prices for electricity. Debate continues in Congress on the direction and scope of U.S. policy on climate change and regulation of GHGs. Congress has considered but has not adopted GHG legislation which would require a reduction in GHG emissions and there is no legislation under active consideration at this time. The likelihood of any federal mandatory CO2 emissions reduction program being adopted by Congress in the near future, and the specific requirements of any such program, are uncertain. The EPA has begun to regulate GHG emissions under its “endangerment” finding. The EPA has adopted its first GHG emission control rules for motor vehicles and new source review of stationary sources of GHGs, which became applicable to motor vehicles and stationary sources, respectively, on January 2, 2011. The EPA is developing CAA Section 111 standards for GHGs from electric generating units and proposed a rule on September 20, 2013 that would require certain new fossil fuel generating plants to meet a CO2 output based standard. Unlike traditional NSPS rules, the proposed GHG NSPS would not apply to modifications at existing units. It is expected the EPA will issue a final new source rule in 2014. For existing units, the EPA is slated to propose Section 111(d) emission guidelines by June 1, 2014, finalize the guidelines by June 1, 2015, and require states to develop 111(d) plans by June 30, 2016. Specific requirements of the CAA Section 111(d) regulation, and thus their impact on OTP, are uncertain at this time.

MANUFACTURING

Competition from foreign and domestic manufacturers, the price and availability of raw materials and general economic conditions could affect the revenues and earnings of our manufacturing businesses.

Our manufacturing businesses are subject to intense risks associated with competition from foreign and domestic manufacturers, many of whom have broader product lines, greater distribution capabilities, greater capital resources, larger marketing, research and development staffs and facilities and other capabilities that may place downward pressure on margins and profitability. The companies in our Manufacturing segment use a variety of raw materials in the products they manufacture, including steel, aluminum and polystyrene and other plastics resins. Costs for these items have increased significantly and may continue to increase. If our manufacturing businesses are not able to pass on cost increases to their customers, it could have a ~~material adverse~~negative effect on profit margins in our ~~business, financial condition and results~~Manufacturing segment.

Each of our ~~operations. In addition,~~manufacturing companies has significant customers and concentrated sales to such customers. If our ~~profits from these contracts could decrease~~relationships with significant customers should change materially, it would be difficult to immediately and we could experience losses if we incur difficulties in performing the contracts or are unable to secure fixed-pricing commitments from our suppliers and subcontractors at the time we enter into fixed-price contracts with our customers.profitably replace lost sales.

PLASTICS

Our plastics operations are highly dependent on a limited number of vendors for PVC resin and a limited supply of PVC resin. The loss of a key vendor, or any interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for our plastics business.

We rely on a limited number of vendors to supply the PVC resin used in our plastics business. Two vendors accounted for approximately 93% of our total purchases of PVC resin in 2013 and approximately 90% of our total purchases of PVC resin in ~~2012 and approximately 97% of our total purchases of PVC resin in 2011.~~2012. In addition, the supply of PVC resin may be limited primarily due to manufacturing capacity and the limited availability of raw material components. A majority of U.S. resin production plants are located in the Gulf Coast region, which may increase the risk of a shortage of resin in the event of a hurricane or other natural disaster in that region. The loss of a key vendor or any interruption or delay in the availability or supply of PVC resin could disrupt our ability to deliver our plastic products, cause customers to cancel orders or require us to incur additional expenses to obtain PVC resin from alternative sources, if such sources are available.

We compete against a large number of other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish our products from those of our competitors.

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

Reductions in PVC resin prices can negatively affect our plastics business.

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

CONSTRUCTION

A significant failure or an inability to properly bid or perform on projects or contracts by our construction businesses could lead to adverse financial results and could lead to the possibility of delay or liquidated damages.

The profitability and success of our construction companies require us to identify, estimate and timely bid on profitable projects or contracts. The quantity and quality of projects up for bid at any time is uncertain. Additionally, once a project or contract is awarded, we must be able to perform within cost estimates that were set when the bid was submitted and accepted. A significant failure or an inability to properly bid or perform on projects or contracts could lead to adverse financial results and could lead to the possibility of delay or liquidated damages.

We enter into construction contracts which could expose us to unforeseen costs and costs not within our control, which may not be recoverable and could adversely affect our results of operations and financial condition.

Our construction companies frequently provide services pursuant to fixed-price contracts. Revenues recognized on jobs in progress under fixed-price contracts were $368 million at December 31, 2013 and $309 million at December 31, 2012. Under those contracts, we agree to perform the contract for a fixed price and, as a result, can improve our expected profit by superior contract performance, productivity, worker safety and other factors resulting in cost savings. However, we could incur cost overruns above the approved contract price, which may not be recoverable.

Fixed-price contract prices are established based largely on estimates and assumptions relating to project scope and specifications, personnel and material needs. These estimates and assumptions may prove inaccurate or conditions may change due to factors out of our control, resulting in cost overruns, which we may be required to absorb and that could have a material adverse effect on our business, financial condition and results of our operations. In addition, our profits from these contracts could decrease and we could experience losses if we incur difficulties in performing the contracts or are unable to secure fixed-pricing commitments from our suppliers and subcontractors at the time we enter into fixed-price contracts with our customers.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 2. PROPERTIES

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

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

Located near Fergus Falls, Minnesota, the Hoot Lake Plant is comprised of three separate generating units. The oldest Hoot Lake Plant generating unit, constructed in 1948 (7,500 kW nameplate rating), was retired on December 31, 2005. A second unit was added in 1959 (53,500 kW nameplate rating) and a third unit was added in 1964 (75,000 kW nameplate rating) and modified in 1988 to provide cycling capability, allowing this unit to be more efficiently brought online from a standby mode. The two generating units in operation have a combined nameplate rating of 128,500 kW.

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

As of December 31, ~~2012~~2013 OTP’s transmission facilities, which are interconnected with lines of other public utilities, consisted of 76 miles of 345 kV lines; 487 miles of 230 kV lines; ~~862~~878 miles of 115 kV lines; and ~~3,977~~3,965 miles of lower voltage lines, principally 41.6 kV. OTP owns the uprated portion of 48 miles of the 345 kV lines, with Minnkota Power Cooperative retaining title to the original 230 kV construction. OTP owns an undivided interest in the remaining 345 kV line miles. OTP is a joint owner, with other regional utilities, in CapX2020 transmission lines with the following ownership interests: 14.8% in the 70 mile Bemidji-Grand Rapids 230 kV line and 13.3% of 29 miles of energized line of the Fargo-Monticello 345 kV Project.

In addition to the properties mentioned above, all of which are utilized by the Electric segment, the Company owns and has investments in offices and service buildings utilized by each of its manufacturing and infrastructure business segments. The Company’s subsidiaries own construction equipment, tools and facilities and equipment used in: the manufacture of PVC pipe, thermoformed products, heavy metal fabricated products, metal parts stamping, fabricating and contract machining.

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

Item 3. LEGAL PROCEEDINGS

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

Item 3A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF ~~FEBRUARY 27, 2013)~~MARCH 3, 2014)

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


NAME AND AGE	DATES ELECTED TO OFFICE	PRESENT POSITION AND BUSINESS EXPERIENCE
Edward J. McIntyre ~~(62)~~(63)	9/8/11	Present:	President and Chief Executive Officer
George A. Koeck ~~(60)~~(61)	4/10/00	Present:	Senior Vice President, General Counsel and Corporate Secretary
Kevin G. Moug ~~(53)~~(54)	4/9/01	Present:	Chief Financial Officer and Senior Vice President
Charles S. MacFarlane ~~(48)~~(49)	5/1/03	Present:	Senior Vice President, Electric Platform
Shane N. Waslaski ~~(37)~~(38)	4/11/11	Present:	Senior Vice President, Manufacturing and Infrastructure Platform

Mr. MacFarlane was appointed President and Chief Operating Officer of the Company effective April 14, 2014.

On September 8, 2011 ~~on the resignation of John Erickson as President and Chief Executive Officer,~~ the Company’s Board of Directors appointed current director Edward J. (Jim) McIntyre to serve as interim President and Chief Executive Officer. On January 3, 2012, the Company’s Board of Directors appointed Mr. McIntyre to serve as permanent President and Chief Executive Officer of the Company. Mr. McIntyre, ~~62,~~63, is retired Vice President and former Chief Financial Officer of Xcel Energy, Inc. He has been a member of the Board of Directors since 2006.

Mr. Waslaski has worked as a Vice President within the Company’s Manufacturing and Infrastructure platform since 2007 and became an executive officer of the Company on April 11, 2011.

The term of office for each of the executive officers is one year and any executive officer elected may be removed by the vote of the Board of Directors at any time during the term. There are no family relationships between any of the executive officers or directors.

Item 4.

~~Item 4.~~

MINE SAFETY DISCLOSURES

Not Applicable.

PART II

Item 5.

MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company’s common stock is traded on the NASDAQ Global Select Market under the NASDAQ symbol “OTTR”. The information required by this Item can be found on Page 38 of this Annual Report on Form 10-K under the heading “Selected Financial Data,” on Page ~~100~~103 under the heading “Retained Earnings and Dividend Restriction” and on Page ~~120~~125 under the heading “Supplementary Financial Information.” The Company does not have a publicly announced stock repurchase program. In addition, the Company did not repurchase any equity securities during the three months ended December 31, ~~2012.~~2013.

PERFORMANCE GRAPH

COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN

This graph compares the cumulative total shareholder return on the Company’s common shares for the last five fiscal years with the cumulative return of The NASDAQ Stock Market Index and the Edison Electric Institute Index (EEI) over the same period (assuming the investment of $100 in each vehicle on December 31, ~~2007,~~2008, and reinvestment of all dividends).

2007 2008 2009 2010 2011 2012
OTC $100.00 $  70.07 $  78.76 $  75.73 $  78.26 $  93.54
EEI $100.00 $  74.10 $  82.03 $  87.80 $105.35 $107.55
NASDAQ $100.00 $  61.67 $  87.93 $104.13 $104.69 $123.85

	2008		2009		2010		2011		2012		2013
OTC	$	100.00	$	112.40	$	108.08	$	111.68	$	133.49	$	162.95
EEI	$	100.00	$	110.71	$	118.50	$	142.18	$	145.15	$	164.03
NASDAQ	$	100.00	$	143.74	$	170.23	$	171.23	$	202.46	$	281.91

Item 6.SELECTED FINANCIAL DATA

~~SELECTED FINANCIAL DATA~~

(thousands, except number of shareholders and per-share data)	2012			2011			2010			2009			2008			2013			2012			2011			2010			2009
Revenues
Electric	$	350,765		$	342,727		$	344,379		$	314,666		$	340,075		$	373,540		$	350,765		$	342,727		$	344,379		$	314,666
Manufacturing		208,965			189,459			143,072			119,255			156,699			204,997			208,965			189,459			143,072			119,255
Plastics																	164,957			150,517			123,669			96,945			80,208
Construction		149,092			184,657			134,222			103,831			157,053			149,910			149,092			184,657			134,222			103,831
Plastics		150,517			123,669			96,945			80,208			116,452
Corporate Revenues and Intersegment Eliminations		(100	)		(343	)		(721	)		(275	)		(440	)
Intersegment Eliminations																	(91	)		(100	)		(343	)		(721	)		(275	)
Total Operating Revenues	$	859,239		$	840,169		$	717,897		$	617,685		$	769,839		$	893,313		$	859,239		$	840,169		$	717,897		$	617,685

Net Income from Continuing Operations	$	38,968		$	34,910		$	26,280		$	22,131		$	30,700		$	50,174		$	38,968		$	34,910		$	26,280		$	22,131
Net (Loss) Income from Discontinued Operations		(44,241	)		(48,153	)		(27,624	)		3,900			4,425
Net (Loss) Income	$	(5,273	)	$	(13,243	)	$	(1,344	)	$	26,031		$	35,125
Net Income (Loss) from Discontinued Operations																	691			(44,241	)		(48,153	)		(27,624	)		3,900
Net Income (Loss)																$	50,865		$	(5,273	)	$	(13,243	)	$	(1,344	)	$	26,031

Operating Cash Flow from Continuing Operations	$	168,986		$	93,678		$	105,934		$	125,646		$	92,767		$	150,283		$	168,986		$	93,678		$	105,934		$	125,646
Operating Cash Flow - Continuing and Discontinued Operations		233,547			104,383			105,017			162,750			111,321			147,781			233,547			104,383			105,017			162,750
Capital Expenditures - Continuing Operations		115,762			67,360			58,264			160,501			217,604			164,463			115,762			67,360			58,264			160,501
Total Assets		1,602,337			1,700,522			1,770,555			1,754,678			1,692,587			1,596,019			1,602,337			1,700,522			1,770,555			1,754,678
Long-Term Debt		421,680			471,915			430,807			431,083			333,940			389,589			421,680			471,915			430,807			431,083
Basic Earnings Per Share - Continuing Operations (1)		1.06			0.95			0.71			0.60			0.95			1.37			1.06			0.95			0.71			0.60
Basic (Loss) Earnings Per Share - Total (1)		(0.17	)		(0.40	)		(0.06	)		0.71			1.09
Basic Earnings (Loss) Per Share - Total (1)																	1.39			(0.17	)		(0.40	)		(0.06	)		0.71
Diluted Earnings Per Share - Continuing Operations (1)		1.05			0.95			0.71			0.60			0.95			1.37			1.05			0.95			0.71			0.60
Diluted (Loss) Earnings Per Share - Total (1)		(0.17	)		(0.40	)		(0.06	)		0.71			1.09
Return on Average Common Equity		(1.1	)%		(2.3	)%		(0.3	)%		3.8	%		6.0	%
Diluted Earnings (Loss) Per Share - Total (1)																	1.39			(0.17	)		(0.40	)		(0.06	)		0.71
Return on Average Common Equity (2)																	9.5	%		(1.1	)%		(2.3	)%		(0.3	)%		3.8	%
Dividends Declared Per Common Share		1.19			1.19			1.19			1.19			1.19			1.19			1.19			1.19			1.19			1.19
Dividend Payout Ratio		—			—			—			168	%		109	%		86	%		—			—			—			168	%
Common Shares Outstanding - Year End		36,168			36,102			36,003			35,812			35,385			36,272			36,168			36,102			36,003			35,812
Number of Common Shareholders (2)		14,584			14,687			14,848			14,923			14,627
Number of Common Shareholders (3)																	14,252			14,584			14,687			14,848			14,923

OTTER TAIL CORPORATION
Consolidated Balance Sheets, December 31
(in thousands)	2013		2012

ASSETS

Current Assets
Cash and Cash Equivalents	$	1,150	$	52,362
Accounts Receivable:
Trade (less allowance for doubtful accounts of $1,177 for 2013 and $1,279 for 2012)		83,572		91,170
Other		9,790		7,684
Inventories		72,681		69,336
Deferred Income Taxes		35,452		30,964
Unbilled Revenues		18,157		15,701
Costs and Estimated Earnings in Excess of Billings		4,063		3,663
Regulatory Assets		17,940		25,499
Other		7,747		8,161
Assets of Discontinued Operations		38		19,092
Total Current Assets		250,590		323,632

Investments		9,362		9,471
Other Assets		28,834		26,222
Goodwill		38,971		38,971
Other Intangibles--Net		13,328		14,305

Deferred Debits
Unamortized Debt Expense		4,188		5,529
Regulatory Assets		83,730		134,755
Total Deferred Debits		87,918		140,284

Plant
Electric Plant in Service		1,460,884		1,423,303
Nonelectric Operations		194,872		186,094
Construction Work in Progress		187,461		77,890
Total Gross Plant		1,843,217		1,687,287
Less Accumulated Depreciation and Amortization		676,201		637,835
Net Plant		1,167,016		1,049,452

Total Assets	$	1,596,019	$	1,602,337

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION
Consolidated Balance Sheets, December 31
(in thousands, except share data)	2013			2012

LIABILITIES AND EQUITY

Current Liabilities
Short-Term Debt	$	51,195		$	--
Current Maturities of Long-Term Debt		188			176
Accounts Payable		113,457			88,406
Accrued Salaries and Wages		19,903			20,571
Billings In Excess Of Costs and Estimated Earnings		13,707			16,204
Accrued Taxes		12,491			12,047
Derivative Liabilities		11,782			18,234
Other Accrued Liabilities		6,532			6,334
Liabilities of Discontinued Operations		3,637			11,156
Total Current Liabilities		232,892			173,128

Pensions Benefit Liability		69,743			116,541
Other Postretirement Benefits Liability		45,221			58,883
Other Noncurrent Liabilities		25,209			22,244

Commitments and Contingencies (note 9)

Deferred Credits
Deferred Income Taxes		195,603			171,787
Deferred Tax Credits		28,288			31,299
Regulatory Liabilities		73,926			68,835
Other		718			466
Total Deferred Credits		298,535			272,387

Capitalization (page 74)
Long-Term Debt, Net of Current Maturities		389,589			421,680

Cumulative Preferred Shares Authorized 1,500,000 Shares Without Par Value; Outstanding 2013—None; 2012—155,000 Shares		--			15,500

Cumulative Preference Shares – Authorized 1,000,000 Shares Without Par Value; Outstanding - None		--			--

Common Shares, Par Value $5 Per Share--Authorized, 50,000,000 Shares;
Outstanding, 2013—36,271,696 Shares; 2012—36,168,368 Shares		181,358			180,842
Premium on Common Shares		255,759			253,296
Retained Earnings		99,441			92,221
Accumulated Other Comprehensive Loss		(1,728	)		(4,385	)
Total Common Equity		534,830			521,974

Total Capitalization		924,419			959,154

Total Liabilities and Equity	$	1,596,019		$	1,602,337

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION
Consolidated Statements of Income--For the Years Ended December 31
(in thousands, except per-share amounts)	2013		2012			2011

Operating Revenues
Electric	$	373,459	$	350,679		$	342,633
Product Sales		369,952		359,474			313,020
Construction Services		149,902		149,086			184,516
Total Operating Revenues		893,313		859,239			840,169

Operating Expenses
Production Fuel - Electric		71,248		66,284			69,017
Purchased Power - Electric System Use		52,006		49,184			43,451
Electric Operation and Maintenance Expenses		133,395		121,069			115,863
Cost of Products Sold (depreciation included below)		283,260		270,041			248,021
Cost of Construction Revenues Earned (depreciation included below)		133,427		147,097			173,629
Other Nonelectric Expenses		51,930		52,621			49,296
Asset Impairment Charge		--		432			470
Depreciation and Amortization		59,885		59,764			58,335
Property Taxes - Electric		11,311		10,720			10,190
Total Operating Expenses		796,462		777,212			768,272

Operating Income		96,851		82,027			71,897

Interest Charges		26,978		31,905			35,629
Loss on Early Retirement of Debt		10,252		13,106			--
Other Income		4,096		4,085			2,763
Income Before Income Taxes – Continuing Operations		63,717		41,101			39,031
Income Tax Expense – Continuing Operations		13,543		2,133			4,121
Net Income from Continuing Operations		50,174		38,968			34,910
Discontinued Operations
Income (Loss) - net of Income Tax Expense (Benefit) of $9 in 2013, $6,231 in 2012 and ($1,811) in 2011		481		(6,603	)		(14,294	)
Impairment Loss - net of Income Tax (Benefit) of ($21,213) in 2012 and ($17,444) in 2011		--		(32,107	)		(42,533	)
Gain (Loss) on Disposition - net of Income Tax Expense of $6 in 2013, $315 in 2012 and $5,851 in 2011		210		(5,531	)		8,674
Net Gain (Loss) from Discontinued Operations		691		(44,241	)		(48,153	)
Total Net Income (Loss)		50,865		(5,273	)		(13,243	)
Preferred Dividend Requirement and Other Adjustments		513		736			1,058
Earnings (Loss) Available for Common Shares	$	50,352	$	(6,009	)	$	(14,301	)

Average Number of Common Shares Outstanding--Basic		36,151		36,048			35,922
Average Number of Common Shares Outstanding--Diluted		36,355		36,242			36,082

Basic Earnings (Loss) Per Common Share:
Continuing Operations (net of preferred dividend requirement)	$	1.37	$	1.06		$	0.95
Discontinued Operations	$	0.02	$	(1.23	)	$	(1.35	)
	$	1.39	$	(0.17	)	$	(0.40	)
Diluted Earnings (Loss) Per Common Share:
Continuing Operations (net of preferred dividend requirement)	$	1.37	$	1.05		$	0.95
Discontinued Operations	$	0.02	$	(1.22	)	$	(1.35	)
	$	1.39	$	(0.17	)	$	(0.40	)

Dividends Declared Per Common Share	$	1.19	$	1.19		$	1.19

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION
Consolidated Statements of Comprehensive Income--For the Years Ended December 31
(in thousands)	2013			2012			2011
Net Income (Loss)	$	50,865		$	(5,273	)	$	(13,243	)
Other Comprehensive Income (Loss):
Unrealized (Loss) Gain on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period		(27	)		--			--
(Losses) Gains Arising During Period		(77	)		154			(121	)
Income Tax Benefit (Expense)		36			(53	)		48
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax		(68	)		101			(73	)
Reversal of Foreign Currency Translation Adjustment Unrealized Gain:
Unrealized Net Change During Period		--			--			303
Reversal of Previously Recognized Gains Realized on Sale of IPH in 2011		--			--			(6,068	)
Income Tax Benefit		--			--			1,787
Reversal of Foreign Currency Translation Adjustment Unrealized Gain – net-of-tax		--			--			(3,978	)
Pension and Postretirement Benefit Plans:
Actuarial Gains (Losses) Net of Regulatory Allocation Adjustment		3,986			(2,133	)		(1,686	)
Amortization of Unrecognized Postretirement Benefit Costs (note 12)		555			376			239
Income Tax (Expense) Benefit		(1,816	)		703			579
Pension and Postretirement Benefit Plans – net-of-tax		2,725			(1,054	)		(868	)

Total Other Comprehensive Income (Loss)		2,657			(953	)		(4,919	)

Total Comprehensive Income (Loss)	$	53,522		$	(6,226	)	$	(18,162	)

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION

Consolidated Statements of Common Shareholders’ Equity
(in thousands, except common shares outstanding)	Common Shares Outstanding			Par Value, Common Shares			Premium on Common Shares			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)				Total Common Equity
Balance, December 31, 2010		36,002,739		$	180,014		$	251,919		$	198,443		$	1,487			$	631,863
Common Stock Issuances, Net of Expenses		154,225			771			2,671										3,442
Common Stock Retirements		(55,269	)		(276	)		(906	)									(1,182	)
Net Loss											(13,243	)						(13,243	)
Other Comprehensive Loss														(4,919	)			(4,919	)
Tax Benefit – Stock Compensation								(875	)									(875	)
Employee Stock Incentive Plan Expense								606										606
Premium on Purchase of Stock for Employee Purchase Plan								(292	)									(292	)
Premium on Purchase of Subsidiary Class B Stock and Options											(322	)						(322	)
Cumulative Preferred Dividends											(735	)						(735	)
Common Dividends ($1.19 per share)											(42,895	)						(42,895	)
Balance, December 31, 2011		36,101,695		$	180,509		$	253,123		$	141,248		$	(3,432	)	(a)	$	571,448
Common Stock Issuances, Net of Expenses		71,745			359			148										507
Common Stock Retirements		(5,072	)		(26	)		(85	)									(111	)
Net Loss											(5,273	)						(5,273	)
Other Comprehensive Loss														(953	)			(953	)
Tax Benefit – Stock Compensation								(103	)									(103	)
Employee Stock Incentive Plan Expense								435										435
Premium on Purchase of Stock for Employee Purchase Plan								(222	)									(222	)
Cumulative Preferred Dividends											(736	)						(736	)
Common Dividends ($1.19 per share)											(43,018	)						(43,018	)
Balance, December 31, 2012		36,168,368		$	180,842		$	253,296		$	92,221		$	(4,385	)	(a)	$	521,974
Common Stock Issuances, Net of Expenses		112,512			562			2,095										2,657
Common Stock Retirements		(9,184	)		(46	)		(177	)									(223	)
Net Income											50,865							50,865
Other Comprehensive Income														2,657				2,657
Tax Benefit – Stock Compensation								299										299
Employee Stock Incentive Plan Expense								418										418
Premium on Purchase of Stock for Employee Purchase Plan								(258	)									(258	)
Cumulative Preferred Dividends											(427	)						(427	)
Preferred Stock Issuance Expenses Transferred to Retained Earnings on Redemption of Preferred Shares								86			(86	)						--
Common Dividends ($1.19 per share)											(43,132	)						(43,132	)
Balance, December 31, 2013		36,271,696		$	181,358		$	255,759		$	99,441		$	(1,728	)	(a)	$	534,830

(a) Accumulated Other Comprehensive Loss on December 31 is comprised of the following:
(in thousands)	2013			2012			2011
Unrealized Gain on Marketable Equity Securities:
Before Tax	$	73		$	177		$	23
Tax Effect		(26	)		(62	)		(9	)
Unrealized Gain on Marketable Equity Securities – Net-of-Tax		47			115			14
Unamortized Actuarial Losses, Prior Service Costs and Transition Obligation Related to Pension and Postretirement Benefits:
Before Tax		(2,959	)		(7,500	)		(5,743	)
Tax Effect		1,184			3,000			2,297
Unamortized Actuarial Losses and Transition Obligation Related to Pension and Postretirement Benefits – Net-of-Tax		(1,775	)		(4,500	)		(3,446	)
Accumulated Other Comprehensive Loss:
Before Tax		(2,886	)		(7,323	)		(5,720	)
Tax Effect		1,158			2,938			2,288
Net Accumulated Other Comprehensive Loss	$	(1,728	)	$	(4,385	)	$	(3,432	)

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION

Consolidated Balance Sheets, December 31

(in thousands) 2012 2011

ASSETS

Current Assets
  Cash and Cash Equivalents $ 52,362 $ 15,994
  Accounts Receivable:
    Trade (less allowance for doubtful accounts of $1,279 for 2012 and $1,114 for 2011) 91,170 93,392
    Other 7,684 8,660
  Inventories 69,336 68,743 ��
  Deferred Income Taxes 30,964 9,523
  Unbilled Revenue 15,701 13,719
  Costs and Estimated Earnings in Excess of Billings 3,663 12,211
  Regulatory Assets 25,499 27,391
  Other 8,161 15,009
  Assets of Discontinued Operations 19,092 209,929
    Total Current Assets 323,632 474,571

Investments 9,471 11,093
Other Assets 26,222 26,997
Goodwill 38,971 39,118
Other Intangibles--Net 14,305 15,286

Deferred Debits
  Unamortized Debt Expense 5,529 6,458
  Regulatory Assets 134,755 124,137
    Total Deferred Debits 140,284 130,595

Plant
  Electric Plant in Service 1,423,303 1,372,534
  Nonelectric Operations 186,094 177,328
  Construction Work in Progress 77,890 52,751
    Total Gross Plant 1,687,287 1,602,613
  Less Accumulated Depreciation and Amortization 637,835 599,751
    Net Plant 1,049,452 1,002,862

      Total Assets $ 1,602,337 $ 1,700,522

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION
Consolidated Statements of Cash Flows—For the Years Ended December 31
(in thousands)	2013			2012			2011
Cash Flows from Operating Activities
Net Income (Loss)	$	50,865		$	(5,273	)	$	(13,243	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Net (Gain) Loss from Sale of Discontinued Operations		(210	)		5,531			(8,674	)
Net (Income) Loss from Discontinued Operations		(481	)		38,710			56,827
Depreciation and Amortization		59,885			59,764			58,335
Asset Impairment Charge		--			432			470
Premium Paid for Early Retirement of Long-Term Debt		9,889			12,500			--
Deferred Tax Credits		(1,925	)		(2,091	)		(2,386	)
Deferred Income Taxes		15,902			11,459			10,661
Change in Deferred Debits and Other Assets		56,720			(4,802	)		(25,053	)
Discretionary Contribution to Pension Fund		(10,000	)		(10,000	)		--
Change in Noncurrent Liabilities and Deferred Credits		(42,226	)		32,718			35,178
Allowance for Equity/Other Funds Used During Construction		(1,823	)		(1,168	)		(861	)
Change in Derivatives Net of Regulatory Deferral		8			718			72
Stock Compensation Expense – Equity Awards		1,456			1,311			2,177
Other—Net		641			4,500			6,496
Cash Provided by (Used for) Current Assets and Current Liabilities:
Change in Receivables		8,335			2,430			(7,952	)
Change in Inventories		(3,345	)		(687	)		(5,286	)
Change in Other Current Assets		(4,216	)		7,019			(1,072	)
Change in Payables and Other Current Liabilities		11,321			30,056			(4,775	)
Change in Interest Payable and Income Taxes Receivable/Payable		(513	)		(14,141	)		(7,236	)
Net Cash Provided by Continuing Operations		150,283			168,986			93,678
Net Cash (Used in) Provided by Discontinued Operations		(2,502	)		64,561			10,705
Net Cash Provided by Operating Activities		147,781			233,547			104,383
Cash Flows from Investing Activities
Capital Expenditures		(164,463	)		(115,762	)		(67,360	)
Proceeds from Disposal of Noncurrent Assets		3,764			4,889			1,923
Net Increase in Other Investments		(1,845	)		(1,037	)		(40	)
Net Cash Used in Investing Activities - Continuing Operations		(162,544	)		(111,910	)		(65,477	)
Net Proceeds from Sale of Discontinued Operations		12,842			42,229			107,310
Net Cash Provided by (Used in) Investing Activities - Discontinued Operations		505			(13,896	)		(36,410	)
Net Cash (Used in) Provided by Investing Activities		(149,197	)		(83,577	)		5,423
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		--			--			(7,268	)
Net Short-Term Borrowings (Repayments)		51,195			--			(79,490	)
Proceeds from Issuance of Common Stock		1,821			--			--
Common Stock Issuance Expenses		(3	)		(370	)		--
Payments for Retirement of Capital Stock		(15,723	)		(111	)		(1,182	)
Proceeds from Issuance of Long-Term Debt		40,900			--			142,006
Short-Term and Long-Term Debt Issuance Expenses		(522	)		(897	)		(1,666	)
Payments for Retirement of Long-Term Debt		(72,981	)		(50,224	)		(100,796	)
Premium Paid for Early Retirement of Long-Term Debt		(9,889	)		(12,500	)		--
Dividends Paid and Other Distributions		(43,818	)		(43,976	)		(43,923	)
Net Cash Used in Financing Activities - Continuing Operations		(49,020	)		(108,078	)		(92,319	)
Net Cash Used in Financing Activities - Discontinued Operations		--			(4,278	)		(3,184	)
Net Cash Used in Financing Activities		(49,020	)		(112,356	)		(95,503	)
Net Change in Cash and Cash Equivalents - Discontinued Operations		(776	)		(1,246	)		2,015
Effect of Foreign Exchange Rate Fluctuations on Cash – Discontinued Operations		--			--			(324	)
Net Change in Cash and Cash Equivalents		(51,212	)		36,368			15,994
Cash and Cash Equivalents at Beginning of Period		52,362			15,994			--
Cash and Cash Equivalents at End of Period	$	1,150		$	52,362		$	15,994

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION

Consolidated Balance Sheets, December 31
(in thousands, except share data) 2012 2011

LIABILITIES AND EQUITY

Current Liabilities
  Current Maturities of Long-Term Debt $ 176 $ 165
  Accounts Payable 88,406 80,457
  Accrued Salaries and Wages 20,571 15,862
  Billings In Excess Of Costs and Estimated Earnings 16,204 9,175
  Accrued Taxes 12,047 11,696
  Derivative Liabilities 18,234 18,770
  Other Accrued Liabilities 6,334 5,540
  Liabilities of Discontinued Operations 11,156 50,691
    Total Current Liabilities 173,128 192,356

Pensions Benefit Liability 116,541 106,818
Other Postretirement Benefits Liability 58,883 48,263
Other Noncurrent Liabilities 22,244 18,102

Commitments and Contingencies (note 9)

Deferred Credits
  Deferred Income Taxes 171,787 173,312
  Deferred Tax Credits 31,299 33,182
  Regulatory Liabilities 68,835 69,106
  Other 466 520
    Total Deferred Credits 272,387 276,120

Capitalization (page 70)
  Long-Term Debt, Net of Current Maturities 421,680 471,915

  Cumulative Preferred Shares
Authorized 1,500,000 Shares Without Par Value;
Outstanding 2012 and 2011 – 155,000 Shares
15,500 15,500

  Cumulative Preference Shares – Authorized 1,000,000 Shares Without Par Value;
Outstanding - None
-- --

  Common Shares, Par Value $5 Per Share--Authorized, 50,000,000 Shares;
   Outstanding, 2012—36,168,368 Shares; 2011—36,101,695 Shares 180,842 180,509
  Premium on Common Shares 253,296 253,123
  Retained Earnings 92,221 141,248
  Accumulated Other Comprehensive Loss (4,385 ) (3,432 )
    Total Common Equity 521,974 571,448

      Total Capitalization 959,154 1,058,863

        Total Liabilities and Equity $ 1,602,337 $ 1,700,522

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION

Consolidated Statements of Income--For the Years Ended December 31

(in thousands, except per-share amounts) 2012 2011 2010

Operating Revenues
  Electric $ 350,679 $ 342,633 $ 344,264
  Nonelectric 508,560 497,536 373,633
    Total Operating Revenues 859,239 840,169 717,897

Operating Expenses
  Production Fuel - Electric 66,284 69,017 73,102
  Purchased Power - Electric System Use 49,184 43,451 44,788
  Electric Operation and Maintenance Expenses 121,069 115,863 112,174
  Cost of Goods Sold - Nonelectric (excludes depreciation; included below) 417,138 421,650 309,507
  Other Nonelectric Expenses 52,621 49,296 46,715
  Asset Impairment Charge 432 470 --
  Depreciation and Amortization 59,764 58,335 57,647
  Property Taxes - Electric 10,720 10,190 9,364
    Total Operating Expenses 777,212 768,272 653,297

Operating Income 82,027 71,897 64,600

Loss on Early Retirement of Debt 13,106 -- --
Interest Charges 31,905 35,629 36,848
Other Income 4,085 2,763 1,759
Income Before Income Taxes – Continuing Operations 41,101 39,031 29,511
Income Tax Expense – Continuing Operations 2,133 4,121 3,231
Net Income from Continuing Operations 38,968 34,910 26,280
Discontinued Operations
  Loss - net of Income Tax Expense (Benefit) of $6,231, ($1,811) and $4,834 for the respective periods
(6,603 ) (14,294 ) (11,998 )
  Impairment Loss - net of Income Tax (Benefit) of ($21,213), ($17,444) and ($4,114) for the respective periods
(32,107 ) (42,533 ) (15,626 )
  (Loss) Gain on Disposition - net of Income Tax Expense of $315 in 2012 and $5,851 in 2011
(5,531 ) 8,674 --
Net Loss from Discontinued Operations (44,241 ) (48,153 ) (27,624 )
Total Net Loss (5,273 ) (13,243 ) (1,344 )
Preferred Dividend Requirement and Other Adjustments 736 1,058 833
Loss Available for Common Shares $ (6,009 ) $ (14,301 ) $ (2,177 )

Average Number of Common Shares Outstanding--Basic 36,048 35,922 35,784
Average Number of Common Shares Outstanding--Diluted 36,242 36,082 36,012

Basic Earnings (Loss) Per Common Share:
  Continuing Operations (net of preferred dividend requirement) $ 1.06 $ 0.95 $ 0.71
  Discontinued Operations (net of other adjustments) $ (1.23 ) $ (1.35 ) $ (0.77 )
$ (0.17 ) $ (0.40 ) $ (0.06 )
Diluted Earnings (Loss) Per Common Share:
  Continuing Operations (net of preferred dividend requirement) $ 1.05 $ 0.95 $ 0.71
  Discontinued Operations (net of other adjustments) $ (1.22 ) $ (1.35 ) $ (0.77 )
$ (0.17 ) $ (0.40 ) $ (0.06 )
Dividends Declared Per Common Share $ 1.19 $ 1.19 $ 1.19

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION

Consolidated Statements of Comprehensive Income--For the Years Ended December 31

(in thousands) 2012 2011 2010
Net Loss $ (5,273 ) $ (13,243 ) $ (1,344 )
Other Comprehensive Income (Loss):
Unrealized Gain (Loss) on Available-for-Sale Securities:
Net Gain (Loss) Arising During Period 154 (121 ) 50
Income Tax (Expense) Benefit (53 ) 48 (20 )
Net Gain (Loss) on Available-for-Sale Securities – net-of-tax 101 (73 ) 30
Foreign Currency Translation Adjustment Gain (Loss):
Unrealized Net Change During Period -- 303 1,335
Reversal of Previously Recognized Gains Realized on Sale of IPH in 2011 -- (6,068 ) --
Income Tax Benefit (Expense) -- 1,787 (15 )
Foreign Currency Translation Adjustment (Loss) Gain – net-of-tax -- (3,978 ) 1,320
Pension and Postretirement Benefit Plans:
Actuarial (Losses) Gains Net of Regulatory Allocation Adjustment (2,133 ) (1,686 ) 1,738
Amortization of Unrecognized Postretirement Benefit Costs 376 239 682
Income Tax Benefit (Expense) 703 579 (968 )
Pension and Postretirement Benefit Plans – net-of-tax (1,054 ) (868 ) 1,452
Total Other Comprehensive (Loss) Income (953 ) (4,919 ) 2,802
Total Comprehensive (Loss) Income $ (6,226 ) $ (18,162 ) $ 1,458

See accompanying notes to consolidated financial statements.

~~OTTER TAIL CORPORATION~~

~~Consolidated~~ ~~Statements of Common Shareholders’~~ ~~Equity~~

(in thousands, except common shares outstanding) Common
Shares
Outstanding Par Value,
Common
Shares Premium
on
Common
Shares Retained
Earnings Accumulated
Other
Comprehensive
Income/(Loss) Total
Common
Equity
Balance, December 31, 2009 35,812,280 $ 179,061 $ 250,398 $ 243,352 $ (1,315 ) (a) $ 671,496
  Common Stock Issuances, Net of Expenses 208,333 1,042 2,054 3,096
  Common Stock Retirements (17,874 ) (89 ) (312 ) (401 )
  Net Loss (1,344 ) (1,344 )
  Other Comprehensive Income 2,802 2,802
  Tax Benefit – Stock Compensation (1,404 ) (1,404 )
  Stock Incentive Plan Performance Award Accrual 1,415 1,415
  Premium on Purchase of Stock for Employee Purchase Plan (232 ) (232 )
  Premium on Purchase of Subsidiary Class B Stock and Options (98 ) (98 )
  Cumulative Preferred Dividends (736 ) (736 )
  Common Dividends (42,731 ) (42,731 )
Balance, December 31, 2010 36,002,739 $ 180,014 $ 251,919 $ 198,443 $ 1,487 (a) $ 631,863
  Common Stock Issuances, Net of Expenses 154,225 771 2,671 3,442
  Common Stock Retirements (55,269 ) (276 ) (906 ) (1,182 )
  Net Loss (13,243 ) (13,243 )
  Other Comprehensive Loss (4,919 ) (4,919 )
  Tax Benefit – Stock Compensation (875 ) (875 )
  Employee Stock Incentive Plan Expense 606 606
  Premium on Purchase of Stock for Employee Purchase Plan (292 ) (292 )
  Premium on Purchase of Subsidiary Class B Stock and Options (322 ) (322 )
  Cumulative Preferred Dividends (735 ) (735 )
  Common Dividends (42,895 ) (42,895 )
Balance, December 31, 2011 36,101,695 $ 180,509 $ 253,123 $ 141,248 $ (3,432 )(a) $ 571,448
  Common Stock Issuances, Net of Expenses 71,745 359 148 507
  Common Stock Retirements (5,072 ) (26 ) (85 ) (111 )
  Net Loss (5,273 ) (5,273 )
  Other Comprehensive Loss (953 ) (953 )
  Tax Benefit – Stock Compensation (103 ) (103 )
  Employee Stock Incentive Plan Expense 435 435
  Premium on Purchase of Stock for Employee Purchase Plan (222 ) (222 )
  Cumulative Preferred Dividends (736 ) (736 )
  Common Dividends (43,018 ) (43,018 )
Balance, December 31, 2012 36,168,368 $ 180,842 $ 253,296 $ 92,221 $ (4,385 )(a) $ 521,974

(a) Accumulated Other Comprehensive Income (Loss) on December 31 is comprised of the following:
  (in thousands) 2012 2011 2010
Unrealized Gain on Marketable Equity Securities:
   Before Tax $ 177 $ 23 $ 145
   Tax Effect (62 ) (9 ) (58 )
    Unrealized Gain on Marketable Equity Securities – Net-of-Tax 115 14 87
Foreign Currency Exchange Translation – Net-of-Tax:
   Before Tax -- -- 5,765
   Tax Effect -- -- (1,787 )
     Foreign Currency Exchange Translation – Net-of-Tax -- -- 3,978
Unamortized Actuarial Losses and Transition Obligation Related to Pension and Postretirement Benefits:
   Before Tax (7,500 ) (5,743 ) (4,296 )
   Tax Effect 3,000 2,297 1,718
     Unamortized Actuarial Losses and Transition Obligation Related to Pension and Postretirement Benefits – Net-of-Tax (4,500 ) (3,446 ) (2,578 )
Accumulated Other Comprehensive (Loss) Income:
   Before Tax (7,323 ) (5,720 ) 1,614
   Tax Effect 2,938 2,288 (127 )
     Net Accumulated Other Comprehensive (Loss) Income $ (4,385 ) $ (3,432 ) $ 1,487

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION
Consolidated Statements of Cash Flows--For the Years Ended December 31

(in thousands) 2012 2011 2010
Cash Flows from Operating Activities
  Net Loss $ (5,273 ) $ (13,243 ) $ (1,344 )
  Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities:
    Net Loss (Gain) from Sale of Discontinued Operations 5,531 (8,674 ) --
    Net Loss from Discontinued Operations 38,710 56,827 27,624
    Depreciation and Amortization 59,764 58,335 57,647
    Asset Impairment Charge 432 470 --
    Deferred Tax Valuation Adjustments and Tax Rate Reduction -- -- 8,300
    Premium Paid for Early Retirement of Long-Term Debt 12,500 -- --
    Deferred Tax Credits (2,091 ) (2,386 ) (2,715 )
    Deferred Income Taxes 11,459 10,661 10,990
    Change in Deferred Debits and Other Assets (4,802 ) (25,053 ) 30
    Discretionary Contribution to Pension Fund (10,000 ) -- (20,000 )
    Change in Noncurrent Liabilities and Deferred Credits 32,718 35,178 2,786
    Allowance for Equity (Other) Funds Used During Construction (1,168 ) (861 ) (4 )
    Change in Derivatives Net of Regulatory Deferral 718 72 208
    Stock Compensation Expense – Equity Awards 1,311 2,177 2,923
    Other—Net 4,500 6,496 5,847
  Cash Provided by (Used for) Current Assets and Current Liabilities:
    Change in Receivables 2,430 (7,952 ) (31,094 )
    Change in Inventories (687 ) (5,286 ) (8,167 )
    Change in Other Current Assets 7,019 (1,072 ) (6,559 )
    Change in Payables and Other Current Liabilities 30,056 (4,775 ) 16,256
    Change in Interest Payable and Income Taxes Receivable/Payable (14,141 ) (7,236 ) 43,206
      Net Cash Provided by Continuing Operations 168,986 93,678 105,934
      Net Cash Provided by (Used in) Discontinued Operations 64,561 10,705 (917 )
        Net Cash Provided by Operating Activities 233,547 104,383 105,017
Cash Flows from Investing Activities
  Capital Expenditures (115,762 ) (67,360 ) (58,264 )
  Proceeds from Disposal of Noncurrent Assets 4,889 1,923 827
  Net Increase in Other Investments (1,037 ) (40 ) (2,855 )
      Net Cash Used in Investing Activities - Continuing Operations (111,910 ) (65,477 ) (60,292 )
      Net Proceeds from Sale of Discontinued Operations 42,229 107,310 --
      Net Cash Used in Investing Activities - Discontinued Operations (13,896 ) (36,410 ) (24,875 )
    Net Cash (Used in) Provided by Investing Activities (83,577 ) 5,423 (85,167 )
Cash Flows from Financing Activities
  Change in Checks Written in Excess of Cash -- (7,268 ) 7,268
  Net Short-Term (Repayments) Borrowings -- (79,490 ) 71,905
  Proceeds from Issuance of Common Stock -- -- 549
  Proceeds from Issuance of Class B Stock of Subsidiary -- -- 153
  Common Stock Issuance Expenses (370 ) -- (142 )
  Payments for Retirement of Common Stock (111 ) (1,182 ) (401 )
  Payments for Retirement of Class B Stock and Options of Subsidiary -- -- (1,012 )
  Proceeds from Issuance of Long-Term Debt -- 142,006 --
  Short-Term and Long-Term Debt Issuance Expenses (897 ) (1,666 ) (1,699 )
  Payments for Retirement of Long-Term Debt (50,224 ) (100,796 ) (58,451 )
  Premium Paid for Early Retirement of Long-Term Debt (12,500 ) -- --
  Dividends Paid and Other Distributions (43,976 ) (43,923 ) (43,698 )
      Net Cash Used in Financing Activities - Continuing Operations (108,078 ) (92,319 ) (25,528 )
      Net Cash (Used in) Provided by Financing Activities - Discontinued Operations (4,278 ) (3,184 ) 1,812
    Net Cash Used in Financing Activities (112,356 ) (95,503 ) (23,716 )
Net Change in Cash and Cash Equivalents - Discontinued Operations (1,246 ) 2,015 (2,495 )
Effect of Foreign Exchange Rate Fluctuations on Cash – Discontinued Operations -- (324 ) (566 )
Net Change in Cash and Cash Equivalents 36,368 15,994 (6,927 )
Cash and Cash Equivalents at Beginning of Period 15,994 -- 6,927
Cash and Cash Equivalents at End of Period $ 52,362 $ 15,994 $ --
See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION

Consolidated Statements of Capitalization, December 31

(in thousands, except share data) 2012 2011

Long-Term Debt
Obligations of Otter Tail Corporation
9.000% Notes, due December 15, 2016 $ 100,000 $ 100,000
Senior Unsecured Note 8.89%, due November 30, 2017, retired early on July 13, 2012 -- 50,000
North Dakota Development Note, 3.95%, due April 1, 2018 393 458
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 1,332 1,431
Total – Otter Tail Corporation 101,725 151,889

Obligations of Otter Tail Power Company
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 33,000 33,000
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017 5,065 5,090
Senior Unsecured Notes 4.63%, due December 1, 2021 140,000 140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022 20,070 20,105
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000
Total – Otter Tail Power Company 320,135 320,195

Total 421,860 472,084
Less:
Current Maturities – Otter Tail Corporation 176 165
Unamortized Debt Discount – Otter Tail Corporation 4 4
Total Long-Term Debt 421,680 471,915
Cumulative Preferred Shares—Without Par Value (Stated and Liquidating Value $100 a Share)—
Authorized 1,500,000 Shares; nonvoting and redeemable at the option of the Company:

Series Outstanding: Call Price December 31, 2012
$3.60, 60,000 Shares $ 102.2500   6,000 6,000
$4.40, 25,000 Shares $ 102.0000   2,500 2,500
$4.65, 30,000 Shares $ 101.5000   3,000 3,000
$6.75, 40,000 Shares $ 100.3375   4,000 4,000
    Total Preferred 15,500 15,500
Cumulative Preference Shares--Without Par Value, Authorized 1,000,000 Shares; Outstanding: None

Total Common Shareholders’ Equity 521,974 571,448
Total Capitalization $ 959,154 $ 1,058,863

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION

Consolidated Statements of Capitalization, December 31
(in thousands, except share data)		2013		2012
Short-Term Debt
Otter Tail Power Company Credit Agreement		$	51,195	$	--
Total Short-Term Debt		$	51,195	$	--

Long-Term Debt
Obligations of Otter Tail Corporation
9.000% Notes, due December 15, 2016		$	52,330	$	100,000
North Dakota Development Note, 3.95%, due April 1, 2018			325		393
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021			1,223		1,332
Total – Otter Tail Corporation			53,878		101,725

Obligations of Otter Tail Power Company
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015			40,900		--
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017			33,000		33,000
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017, retired early on March 1, 2013			--		5,065
Senior Unsecured Notes 4.63%, due December 1, 2021			140,000		140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022			30,000		30,000
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022, retired early on March 1, 2013			--		20,070
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027			42,000		42,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037			50,000		50,000
Total – Otter Tail Power Company			335,900		320,135

Total			389,778		421,860
Less:
Current Maturities – Otter Tail Corporation			188		176
Unamortized Debt Discount – Otter Tail Corporation			1		4
Total Long-Term Debt			389,589		421,680
Cumulative Preferred Shares—Without Par Value (Stated and Liquidating Value $100 a Share)— Authorized 1,500,000 Shares; nonvoting and redeemable at the option of the Company:
	Series Outstanding December 31, 2012:
$3.60, 60,000 Shares; redeemed on March 1, 2013			--		6,000
$4.40, 25,000 Shares; redeemed on March 1, 2013			--		2,500
$4.65, 30,000 Shares; redeemed on March 1, 2013			--		3,000
$6.75, 40,000 Shares; redeemed on March 1, 2013			--		4,000
Total Preferred			--		15,500
Cumulative Preference Shares--Without Par Value, Authorized 1,000,000 Shares; Outstanding: None
Total Common Shareholders’ Equity			534,830		521,974
Total Capitalization		$	924,419	$	959,154
See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Notes to Consolidated Financial Statements

For the years ended December 31, 2013, 2012 ~~2011~~ and ~~2010~~2011

1. Summary of Significant Accounting Policies

Principles of Consolidation

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

Regulation and ASC 980

The Company’s regulated electric utility company, Otter Tail Power Company (OTP), accounts for the financial effects of regulation in accordance with ASC 980. This standard allows for the recording of a regulatory asset or liability for costs and revenues that will be collected or refunded through the ratemaking process in the future. In accordance with regulatory treatment, OTP defers utility debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. See note 4 for further discussion.

OTP is subject to various state and federal agency regulations. The accounting policies followed by this business are subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the Company’s nonelectric businesses.

Plant, Retirements and Depreciation

Utility plant is stated at original cost. The cost of additions includes contracted work, direct labor and materials, allocable overheads and allowance for funds used during construction. The amount of interest capitalized on electric utility plant was $1,002,000 in 2013, $656,000 in 2012 and $628,000 in ~~2011 and $76,000 in 2010.~~2011. The cost of depreciable units of property retired less salvage is charged to accumulated depreciation. Removal costs, when incurred, are charged against the accumulated reserve for estimated removal costs, a regulatory liability. Maintenance, repairs and replacement of minor items of property are charged to operating expenses. The provisions for utility depreciation for financial reporting purposes are made on the straight-line method based on the estimated service lives of the ~~properties.~~properties (5 to 70 years). Such provisions as a percent of the average balance of depreciable electric utility property were 2.96% in 2013, 2.98% in 2012 and 2.94% in ~~2011 and 3.01% in 2010.~~2011. Gains or losses on group asset dispositions are taken to the accumulated provision for depreciation reserve and impact current and future depreciation rates.

Property and equipment of nonelectric operations are carried at historical cost or at the then-current replacement cost if acquired in a business combination accounted for under the purchase method of accounting, and are depreciated on a straight-line basis over the assets’ estimated useful lives (3 to 40 years). The cost of additions includes contracted work, direct labor and materials, allocable overheads and capitalized interest. No interest was capitalized on nonelectric plant in 2013, 2012 ~~2011~~ or ~~2010.~~2011. Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of operating income.

Jointly Owned ~~Plants~~Facilities

The consolidated balance sheets include OTP’s ownership interests in the assets and liabilities of Big Stone Plant (53.9%) and Coyote Station (35.0%). The following amounts are included in the Company’s December 31, ~~2012~~2013 and ~~2011~~2012 consolidated balance sheets:

(in thousands)	2012			2011			2013			2012
Big Stone Plant:
Electric Plant in Service	$	141,221		$	143,993		$	142,780		$	141,221
Construction Work in Progress		22,335			2,674			94,913			22,335
Accumulated Depreciation		(80,588	)		(87,669	)		(83,005	)		(80,588	)
Net Plant	$	82,968		$	58,998		$	154,688		$	82,968
Coyote Station:
Electric Plant in Service	$	160,617		$	156,213		$	162,095		$	160,617
Construction Work in Progress		578			1,533			303			578
Accumulated Depreciation		(93,564	)		(97,090	)		(96,907	)		(93,564	)
Net Plant	$	67,631		$	60,656		$	65,491		$	67,631


MINNESOTA		27-0383995
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

215 SOUTH CASCADE STREET, BOX 496, FERGUS FALLS,MINNESOTA		56538-0496
~~(Address~~ (Address of principal executive offices)	~~(Zip~~	(Zip Code)


	Title of each class		Name of each exchange on which registered
	COMMON SHARES, par value $5.00 per share		The NASDAQ Stock Market LLC


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
	Large Accelerated Filer x	Accelerated Filer o
	Non-Accelerated Filer o	Smaller Reporting Company o
	(Do not check if a smaller reporting company)

		~~Description~~	~~Page Numbers~~
	Description	Page
	Definitions	2
PART I
ITEM 1.		Business	4
ITEM 1A.		Risk Factors	2928
ITEM 1B.		Unresolved Staff Comments	35
ITEM 2.		Properties	35
ITEM 3.		Legal Proceedings	36
ITEM 3A.		Executive Officers of the Registrant (as of ~~February 27, 2013)~~March 3, 2014)	36
ITEM 4.		Mine Safety Disclosures	36

PART II
ITEM 5.		Market for Registrant’s Common Equity, Related Stockholder Matters And Issuer Purchases of Equity Securities	37
ITEM 6.		Selected Financial Data	38
ITEM 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
ITEM 7A.		Quantitative and Qualitative Disclosures About Market Risk	6165
ITEM 8.		Financial Statements and Supplementary Data:
		Report of Independent Registered Public Accounting Firm	6367
		Consolidated Balance Sheets	6468
		Consolidated Statements of Income	6670
		Consolidated Statements of Comprehensive Income	6771
		Consolidated Statements of Common Shareholders’ Equity	6872
		Consolidated Statements of Cash Flows	6973
		Consolidated Statements of Capitalization	7074
		Notes to Consolidated Financial Statements	7175
		Supplementary Financial Information - Quarterly Information	~~120~~125
ITEM 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~121~~126
ITEM 9A.		Controls and Procedures	~~121~~126
ITEM 9B.		Other Information	~~121~~126

PART III
ITEM 10.		Directors, Executive Officers and Corporate Governance	~~122~~127
ITEM 11.		Executive Compensation	~~122~~127
ITEM 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~123~~127
ITEM 13.		Certain Relationships and Related Transactions and Director Independence	~~123~~127
ITEM 14.		Principal Accountant Fees and Services	~~123~~127

PART IV
ITEM 15.		Exhibits and Financial Statement ~~Schedules:~~Schedules	~~124~~128

Signatures			~~132~~137

~~Resource~~	~~Proposed~~
~~Natural gas~~	~~213 MW~~
~~Demand Response/Conservation~~	~~70 MW~~
~~Wind~~	~~50 MW~~


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


ADP		Advance Determination of Prudence
Aevenia		Aevenia, Inc.
AFUDC		Allowance for Funds Used During Construction
AQCS		Air Quality Control System
ARO		Accumulated Asset Retirement Obligation
ASC		Accounting Standards Codification
ASC 980		ASC Topic 980 - Regulated Operations
ASM		Ancillary Services Market
Aviva		Aviva Sports, Inc.
BACT		Best-Available Control Technology
BART		Best-Available Retrofit Technology
Bemidji Project		Bemidji-Grand Rapids 230 kV Project
Brookings Project		Brookings-Southeast Twin Cities 345 kV Project
BTD		BTD Manufacturing, Inc.
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CapX2020		Capacity Expansion 2020
Cascade		Cascade Investment LLC
Cascade Note		$50 million 8.89% Senior Unsecured Note due November 30, 2017
CCMC		Coyote Creek Mining Company, L.L.C.
~~CCRA~~	~~Conservation Cost Recovery Adjustment~~
CO2		Carbon Dioxide
CON		Certificate of Need
CSAPR		Cross-State Air Pollution Rule
CWIP		Construction Work in Progress
DENR		Department of Environment and Natural Resources
~~DMI~~DMS	~~DMI Industries, Inc.~~
~~DMS~~	DMS Health Technologies, Inc.
~~ECRR~~ECR		Environmental Cost Recovery ~~Rider~~
EEI		Edison Electric Institute Index
EEP		Energy Efficiency Plan
EPA		Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas
ESSRP		Executive Survivor and Supplemental Retirement Plan
Fargo Project		Fargo-Monticello 345 kV Project
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Foley		Foley Company
GAAP		Generally Accepted Accounting Principles
GHG		Greenhouse Gas
IMD		IMD, Inc.
IPH		Idaho Pacific Holdings, Inc.
IRP		Integrated Resource Plan
JPMS		J.P. Morgan Securities
kV		kiloVolt
kW		kiloWatt
kwh		kilowatt-hour
LSA		Lignite Sales Agreement
MAPP		Mid-Continent Area Power Pool
MATS		Mercury and Air Toxics Standards
MDU		MDU Resources Group, Inc.
MEI		Moorhead Electric, Inc.
MISO	~~Midwest~~	Midcontinent Independent ~~Transmission~~ System Operator, Inc.
MISO Tariff		MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff
MNCIP		Minnesota Conservation Improvement Program
MNDOC		Minnesota Department of Commerce

	~~Minnesota Office of Attorney General~~
MNRRA		Minnesota Renewable Resource Adjustment
MPCA		Minnesota Pollution Control Agency

MPUC		Minnesota Public Utilities Commission
MRO		Midwest Reliability Organization
MVP		Multi-Value Project
MW		Megawatt
mwh		Megawatt-hour
NAEMA		North American Energy Marketers Association
NDDOH		North Dakota Department of Health
NDPSC		North Dakota Public Service Commission
NDRRA		North Dakota Renewable Resource ~~Cost Recovery Rider~~ Adjustment
NICF		Notice of ~~Interest~~Intent to Construct Facilities
NPCA		National Parks Conservation Association
NPDES		National Pollutant Discharge Elimination System
Northern Pipe		Northern Pipe Products, Inc.
NOx		Nitrogen Oxide
NSPS		New Source Performance Standards
NYMEX		New York Mercantile Exchange
OTESCO		Otter Tail Energy Services Company
OTP		Otter Tail Power Company
~~PACE~~PCOR	~~Partnership in Assisting Community Expansion~~
~~PCOR~~	Plains CO2Reduction Partnership
PEM		Power and Energy Market
PM2.5		Particulate Matter Less Than 2.5 Microns
PSPSD	~~Polystyrene~~
~~PSD~~	Prevention of Significant Deterioration
PTC		Production Tax Credit
PVC		Polyvinyl Chloride
RCRA		Resource Conservation and Recovery Act
SCR		Selective Catalytic Reduction
SDPUC		South Dakota Public Utilities Commission
SEC		Securities and Exchange Commission
SF6		Sulfur Hexaflouride
~~ShoreMaster~~Shrco	~~ShoreMaster,~~	Shrco, Inc.
SIP		State Implementation Plan
SO2		Sulfur Dioxide
T.O. Plastics		T.O. Plastics, Inc.
Tariff		Energy and Operating Reserve Markets Tariff
TCR		Transmission Cost Recovery
Trinity		Trinity Industries, Inc.
~~VaR~~Varistar	~~Value at Risk~~
~~Varistar~~	Varistar Corporation
VIC		Voluntary Investigation and Cleanup
VIE		Variable Interest Entity
Vinyltech		Vinyltech Corporation
Wylie		E.W. Wylie Corporation


Baseload Plants
Big Stone Plant	~~256,600~~256,700		kW
Coyote Station		~~149,100~~149,000
Hoot Lake Plant		~~141,600~~148,900
Total Baseload Net Plant	~~547,300~~554,600		kW
Combustion Turbine and Small Diesel Units	~~108,000~~104,900		kW
Hydroelectric Facilities	~~2,800~~2,600		kW
Owned Wind Facilities (rated at nameplate)
Luverne Wind Farm (33 turbines)	49,500		kW
Ashtabula Wind Center (32 turbines)		48,000
Langdon Wind Center (27 turbines)		40,500
Total Owned Wind Facilities	138,000		kW

	2007	2008	2009	2010	2011	2012
OTC	$100.00	$ 70.07	$ 78.76	$ 75.73	$ 78.26	$ 93.54
EEI	$100.00	$ 74.10	$ 82.03	$ 87.80	$105.35	$107.55
NASDAQ	$100.00	$ 61.67	$ 87.93	$104.13	$104.69	$123.85


2013 Earnings Per Share Guidance Range December 2, 2013			2013 Earnings Per Share	2012 Earnings Per Share
	Low	High	2013 Earnings Per Share	2012 Earnings Per Share
Electric	$1.02	$1.04	$1.05	$1.06
Manufacturing	$0.30	$0.33	$0.32	$0.29
Plastics	$0.35	$0.37	$0.38	$0.39
Construction	$0.03	$0.05	$0.04	($0.21)
Corporate – Recurring Costs	($0.32)	($0.29)	($0.25)	($0.22)
Subtotal – Non-GAAP Basis1	$1.38	$1.50	$1.54	$1.31
Corporate – Loss on Debt Extinguishment	($0.17)	($0.17)	($0.17)	($0.22)
Corporate – Interest on Debt Related to Discontinued Operations				($0.04)
Total – Continuing Operations - GAAP Basis	$1.21	$1.33	$1.37	$1.05
1In November 2013 we retired early $47.7 million of our previously outstanding $100 million 9.000% Notes due December 15, 2016 from available cash. In July 2012 we retired early our $50 million, 8.89% Senior Unsecured Note due November 30, 2017 from proceeds generated in connection with the divestiture of IMD. Generally Accepted Accounting Principles require that in order for debt retirement premiums and related interest expense to be reported as discontinued operations, a company must be required by the lender to repay the related debt as a result of the disposition. Although we were not legally obligated to repay the aforementioned $50 million note, management believes it is appropriate to associate the 2012 debt prepayment premium and interest expense with its discontinued operations to provide a better indication of future earnings. Management understands that there are material limitations on the use of Non-GAAP measures. Non-GAAP measures are not substitutes for GAAP measures for the purpose of analyzing financial performance. Non-GAAP measures are not in accordance with, or an alternative for, measures prepared in accordance with, generally accepted accounting principles and may be different from Non-GAAP measures used by other companies. In addition, Non-GAAP measures are not based on any comprehensive set of accounting rules or principles. This information should not be construed as an alternative to the reported results, which have been determined in accordance with GAAP.

2012 Earnings Per Share Guidance Range November 5, 2012			2012 GAAP Earnings Per Share	2012 Non- GAAP Items	2012 Non-GAAP Earnings Per Share
	Low	High	2012 GAAP Earnings Per Share	2012 Non- GAAP Items	2012 Non-GAAP Earnings Per Share
Electric	$1.01	$1.06	$1.06	--	$1.06
Manufacturing (without ShoreMaster)	$0.26	$0.30	$0.29	--	$0.29
Net Loss from ShoreMaster	($0.08)	($0.07)	--	--	--
Construction	($0.23)	($0.18)	($0.21)	--	($0.21)
Plastics	$0.32	$0.37	$0.39	--	$0.39
Corporate – Recurring Costs	($0.22)	($0.17)	($0.26)	$0.04	($0.22)
Subtotal	$1.06	$1.31	$1.27	$0.04	$1.31
Corporate – Premium Paid on Debt Extinguishment	($0.22)	($0.22)	($0.22)	$0.22	--
Total – Continuing Operations	$0.84	$1.09	$1.05	$0.26	$1.31
Discontinued Operations:
Net Losses from Discontinued Operations	($1.00)	($0.95)	($1.22)	--	($1.22)
Premium Paid on Debt Extinguishment in Connection with DMI Disposition1	--	--	--	($0.22)	($0.22)
2012 Interest Expense on Debt Extinguished in Connection with DMI Disposition1	--	--	--	($0.04)	($0.04)
Total – Discontinued Operations	($1.00)	($0.95)	($1.22)	($0.26)	($1.48)
Total	($0.16)	$0.14	($0.17)	--	($0.17)
1We retired early the Cascade Note from proceeds generated in connection with the divestiture of DMI. Generally Accepted Accounting Principles require that in order for debt retirement premiums and related interest expense to be reported as discontinued operations, a company must be required by the lender to repay the related debt as a result of the disposition. Although we were not legally obligated to repay the aforementioned note, we believe it is appropriate to associate the 2012 debt prepayment premium and interest expense with our discontinued operations to provide a better indication of future earnings.

Intersegment Eliminations (in thousands)	2012		2011		2010
Operating Revenues:
Electric	$	86	$	94	$	115
Nonelectric		14		249		606
Cost of Goods Sold		68		122		(57	)
Other Nonelectric Expenses		32		221		778

(in thousands)	2012		% change			2011		% change			2010
Retail Sales Revenues	$	308,530		1		$	304,181		--		$	305,146
Wholesale Revenues – Company Generation		12,951		(11	)		14,518		(28	)		20,053
Net Revenue – Energy Trading Activity		1,426		(39	)		2,319		(26	)		3,144
Other Revenues		27,858		28			21,709		35			16,036
Total Operating Revenues	$	350,765		2		$	342,727		--		$	344,379
Production Fuel		66,284		(4	)		69,017		(6	)		73,102
Purchased Power – System Use		49,184		13			43,451		(3	)		44,788
Other Operation and Maintenance Expenses		121,069		4			115,863		3			112,174
Asset Impairment		432		(8	)		470		--			--
Depreciation and Amortization		42,051		4			40,283		--			40,241
Property Taxes		10,720		5			10,190		9			9,364
Operating Income	$	61,025		(4	)	$	63,453		(2	)	$	64,710


FORM 10-K
(Mark One)

Electric kilowatt-hours (kwh) Sales (in thousands)	2012		% change			2011		% change			2010
Retail kwh Sales		4,240,789		(1	)		4,291,637		1			4,262,748
Wholesale kwh Sales – Company Generation		476,637		(7	)		510,978		(18	)		624,153
Wholesale kwh Sales – Purchased Power Resold		88,637		(28	)		122,430		(64	)		336,875

	For the Year Ended December 31,									For the Year Ended December 31,
(in thousands)	2012			2011			2010			2013			2012			2011
Tax Computed at Federal Statutory Rate	$	14,385		$	13,661		$	10,329		$	22,301		$	14,385		$	13,661
Increases (Decreases) in Tax from:
Federal Production Tax Credit		(6,695	)		(7,281	)		(6,441	)
Federal Production Tax Credit (PTC)											(6,612	)		(6,695	)		(7,281	)
State Income Taxes Net of Federal Income Tax Benefit											1,667			(849	)		798
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(891	)		(996	)		(1,163	)		(863	)		(891	)		(996	)
State Income Taxes Net of Federal Income Tax Benefit		(849	)		798			(1,186	)
Corporate Owned Life Insurance											(856	)		(585	)		(388	)
Allowance for Funds Used During Construction - Equity											(638	)		(409	)		(301	)
Dividend Received/Paid Deduction											(632	)		(656	)		(677	)
Investment Tax Credit Amortization		(720	)		(855	)		(926	)		(597	)		(720	)		(855	)
Dividend Received/Paid Deduction		(656	)		(677	)		(692	)
Corporate Owned Life Insurance		(585	)		(388	)		(556	)
Impact of Medicare Part D Change		(584	)		(599	)		1,692
Allowance for Funds Used During Construction - Equity		(409	)		(301	)		(1	)
Tax Depreciation - Treasury Grant for Wind Farms		(304	)		(507	)		(845	)		(304	)		(304	)		(507	)
Differences Reversing in Excess of Federal Rates		(143	)		680			989			(100	)		(143	)		680
Impact of Medicare Part D Change											--			(584	)		(599	)
Permanent and Other Differences		(416	)		586			2,031			177			(416	)		586
Total Income Tax Expense – Continuing Operations	$	2,133		$	4,121		$	3,231		$	13,543		$	2,133		$	4,121
Effective Income Tax Rate – Continuing Operations		5.2	%		10.6	%		10.9	%		21.3	%		5.2	%		10.6	%

	For the Year Ended December 31, 2012
(in thousands)	DMI			Wylie			ShoreMaster			DMS			IPH			Intercompany transactions adjustment			Total
Operating Revenues	$	186,151		$	--		$	32,563		$	16,362		$	--		$	(2,017	)	$	233,059
Operating Expenses		184,462			179			36,163			14,741			--			(2,017	)		233,528
Asset Impairment Charge		45,573			--			7,747			--			--			--			53,320
Other Income		135			--			15			122			--			--			272
Interest Expense		5,787			--			1,553			279			--			(7,444	)		175
Income Tax (Benefit) Expense		(15,792	)		13			(4,021	)		1,734			106			2,978			(14,982	)
Net Loss from Operations		(33,744	)		(192	)		(8,864	)		(270	)		(106	)		4,466			(38,710	)
Loss on Disposition Before Taxes		--			(62	)		--			(5,154	)		--			--			(5,216	)
Income Tax Expense (Benefit) on Disposition		--			460			--			(145	)		--			--			315
Net Loss on Disposition		--			(522	)		--			(5,009	)		--			--			(5,531	)
Net Loss	$	(33,744	)	$	(714	)	$	(8,864	)	$	(5,279	)	$	(106	)	$	4,466		$	(44,241	)

	For the Year Ended December 31, 2011
(in thousands)	DMI			Wylie			ShoreMaster			DMS			IPH			Intercompany transactions adjustment			Total
Operating Revenues	$	201,921		$	49,884		$	39,863		$	89,558		$	28,125		$	(6,016	)	$	403,335
Operating Expenses		218,542			55,927			41,478			85,244			24,046			(6,016	)		419,221
Asset Impairment Charge		3,142			--			456			56,379			--			--			59,977
Other (Deductions) Income		(46	)		18			1			281			(228	)		(3	)		23
Interest Expense		6,852			709			1,580			1,726			11			(10,636	)		242
Income Tax (Benefit) Expense		(4,768	)		(2,683	)		(1,462	)		(16,058	)		1,462			4,254			(19,255	)
Net (Loss) Income from Operations		(21,893	)		(4,051	)		(2,188	)		(37,452	)		2,378			6,379			(56,827	)
(Loss) Gain on Disposition Before Taxes		--			(946	)		--			--			15,471			--			14,525
Income Tax Expense on Disposition		--			2,854			--			--			2,997			--			5,851
Net (Loss) Gain on Disposition		--			(3,800	)		--			--			12,474			--			8,674
Net (Loss) Income	$	(21,893	)	$	(7,851	)	$	(2,188	)	$	(37,452	)	$	14,852		$	6,379		$	(48,153	)

	For the Year Ended December 31, 2013
(in thousands)	IMD			Wylie			Shrco			DMS			IPH		Intercompany Transactions Adjustment		Total
Operating Revenues	$	--		$	--		$	2,016		$	--		$	--	$	--	$	2,016
Operating Expenses		(988	)		640			2,622			(269	)		--		--		2,005
Other Income		412			--			67			--			--		--		479
Income Tax Expense (Benefit)		370			(256	)		(213	)		108			--		--		9
Net Income (Loss) from Operations		1,030			(384	)		(326	)		161			--		--		481
Gain on Disposition Before Taxes		--			--			16			200			--		--		216
Income Tax Expense on Disposition		--			--			6			--			--		--		6
Net Gain on Disposition		--			--			10			200			--		--		210
Net Income (Loss)	$	1,030		$	(384	)	$	(316	)	$	361		$	--	$	--	$	691

	For the Year Ended December 31, 2010																			For the Year Ended December 31, 2011
(in thousands)	DMI			Wylie		ShoreMaster			DMS		IPH			Intercompany transactions adjustment			Total			IMD			Wylie			Shrco			DMS			IPH			Intercompany Transactions Adjustment			Total
Operating Revenues	$	143,603		$	54,143	$	35,624		$	100,301	$	77,412		$	(5,830	)	$	405,253		$	201,921		$	49,884		$	39,863		$	89,558		$	28,125		$	(6,016	)	$	403,335
Operating Expenses		159,646			52,311		41,351			98,794		65,261			(5,830	)		411,533			218,542			55,927			41,478			85,244			24,046			(6,016	)		419,221
Asset Impairment Charge		--			--		19,740			--		--			--			19,740			3,142			--			456			56,379			--			--			59,977
Other (Deductions) Income		(734	)		8		21			331		(326	)		--			(700	)		(46	)		18			1			281			(228	)		(3	)		23
Interest Expense		5,614			522		1,492			1,289		111			(8,844	)		184			6,852			709			1,580			1,726			11			(10,636	)		242
Income Tax (Benefit) Expense		(356	)		511		(7,058	)		369		3,716			3,538			720			(4,768	)		(2,683	)		(1,462	)		(16,058	)		1,462			4,254			(19,255	)
Net (Loss) Income from Operations																					(21,893	)		(4,051	)		(2,188	)		(37,452	)		2,378			6,379			(56,827	)
(Loss) Gain on Disposition Before Taxes																					--			(946	)		--			--			15,471			--			14,525
Income Tax Expense on Disposition																					--			2,854			--			--			2,997			--			5,851
Net (Loss) Gain on Disposition																					--			(3,800	)		--			--			12,474			--			8,674
Net (Loss) Income	$	(22,035	)	$	807	$	(19,880	)	$	180	$	7,998		$	5,306		$	(27,624	)	$	(21,893	)	$	(7,851	)	$	(2,188	)	$	(37,452	)	$	14,852		$	6,379		$	(48,153	)

(in thousands)	Line Limit		In Use on December 31, 2012		Restricted due to Outstanding Letters of Credit		Available on December 31, 2012		Available on December 31, 2011		Line Limit		In Use on December 31, 2013		Restricted due to Outstanding Letters of Credit		Available on December 31, 2013		Available on December 31, 2012
Otter Tail Corporation Credit Agreement	$	150,000	$	--	$	733	$	149,267	$	198,776	$	150,000	$	--	$	659	$	149,341	$	149,267
OTP Credit Agreement		170,000		--		3,189		166,811		165,950		170,000		51,195		1,830		116,975		166,811
Total	$	320,000	$	--	$	3,922	$	316,078	$	364,726	$	320,000	$	51,195	$	2,489	$	266,316	$	316,078


(in millions)	2011		2012		2013		2014		2015		2016		2017		2018		Total for 2014-2018
Electric	$	50	$	102	$	149	$	172	$	145	$	141	$	97	$	102	$	657
Manufacturing		10		9		7		17		12		20		15		17		81
Plastics		2		3		3		4		3		3		2		2		14
Construction		3		2		5		2		4		3		3		5		17
Corporate		2		--		--		--		--		--		--		--		--
Total	$	67	$	116	$	164	$	195	$	164	$	167	$	117	$	126	$	769

(in millions)	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years		Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Coal Contracts (required minimums)	$	797	$	43	$	37	$	43	$	674	$	761	$	50	$	42	$	47	$	622
Long-Term Debt Obligations		422		--		1		138		283
Interest on Long-Term Debt Obligations		250		26		53		43		128
Debt Obligations												441		92		53		33		263
Capacity and Energy Requirements		170		31		30		32		77		347		23		53		48		223
Interest on Debt Obligations												202		21		42		30		109
Other Purchase Obligations												108		85		23		--		--
Postretirement Benefit Obligations		91		4		9		10		68		74		4		8		9		53
Other Purchase Obligations		79		45		12		22		--
Operating Lease Obligations		42		8		13		8		13		37		8		11		6		12
Total Contractual Cash Obligations	$	1,851	$	157	$	155	$	296	$	1,243	$	1,970	$	283	$	232	$	173	$	1,282

(in thousands)	Line Limit		In Use on December 31, 2012		Restricted due to Outstanding Letters of Credit		Available on December 31, 2012		Available on December 31, 2011		Line Limit		In Use on December 31, 2013		Restricted due to Outstanding Letters of Credit		Available on December 31, 2013		Available on December 31, 2012
Otter Tail Corporation Credit Agreement	$	150,000	$	--	$	733	$	149,267	$	198,776	$	150,000	$	--	$	659	$	149,341	$	149,267
OTP Credit Agreement		170,000		--		3,189		166,811		165,950		170,000		51,195		1,830		116,975		166,811
Total	$	320,000	$	--	$	3,922	$	316,078	$	364,726	$	320,000	$	51,195	$	2,489	$	266,316	$	316,078


	2012 EPS by Segment	2013 EPS Guidance		2013 EPS by Segment		2014 EPS Guidance
	2012 EPS by Segment	Low	High	2013 EPS by Segment			Low	High
Electric	$1.06	$1.06	$1.11		$1.05		$1.19	$1.23
Manufacturing	$0.29	$0.31	$0.36		$0.32		$0.29	$0.33
Plastics					$0.38		$0.25	$0.29
Construction	($0.21)	$0.06	$0.11		$0.04		$0.07	$0.11
Plastics	$0.39	$0.16	$0.21
Corporate	($0.26)	($0.29)	($0.24)		($0.25)		($0.25)	($0.21)
Subtotal – Continuing Operations	$1.27	$1.30	$1.55		$1.54		$1.55	$1.75
Corporate – Premium Paid on Debt Extinguishment	($0.22)
Corporate – Loss on Debt Extinguishment					($0.17)
Total – Continuing Operations	$1.05	$1.30	$1.55		$1.37		$1.55	$1.75

(in thousands)		1st Quarter 2013				1st Quarter 2014
Net Gain		$	49			$	115

(in thousands)	December 31, 2012			December 31, 2011			December 31, 2013			December 31, 2012

Current Asset – Marked-to-Market Gain	$	502		$	3,803		$	338		$	502
Regulatory Asset – Current Deferred Marked-to-Market Loss		7,949			5,208			3,008			7,949
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		10,050			10,749			8,674			10,050
Total Assets		18,501			19,760			12,020			18,501

Current Liability – Marked-to-Market Loss		(18,234	)		(18,770	)		(11,782	)		(18,234	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		(8	)		(96	)		(6	)		(8	)
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(210	)		--			(117	)		(210	)
Total Liabilities		(18,452	)		(18,866	)		(11,905	)		(18,452	)

Net Fair Value of Marked-to-Market Energy Contracts	$	49		$	894		$	115		$	49

(in thousands)	Year ended December 31, 2012			Year ended December 31, 2011			Year ended December 31, 2013			Year ended December 31, 2012
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Period	$	894		$	763		$	49		$	894
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(861	)		(356	)		(49	)		(861	)
Changes in Fair Value of Contracts Entered into in Prior Periods		(33	)		(86	)		--			(33	)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--			321			--			--
Changes in Fair Value of Contracts Entered into in Current Period		49			573			115			49
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	49		$	894		$	115		$	49

	Year Ended December 31,							Year Ended December 31,
(in thousands)	2012			2011		2010		2013		2012			2011
Net (Losses) Gains on Forward Electric Energy Contracts	$	(61	)	$	926	$	2,135
Net Gains (Losses) on Forward Electric Energy Contracts								$	432	$	(61	)	$	926

(in thousands, except common shares outstanding)	Common Shares Outstanding			Par Value, Common Shares			Premium on Common Shares			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Total Common Equity
Balance, December 31, 2009		35,812,280		$	179,061		$	250,398		$	243,352		$	(1,315	) (a)	$	671,496
Common Stock Issuances, Net of Expenses		208,333			1,042			2,054									3,096
Common Stock Retirements		(17,874	)		(89	)		(312	)								(401	)
Net Loss											(1,344	)					(1,344	)
Other Comprehensive Income														2,802			2,802
Tax Benefit – Stock Compensation								(1,404	)								(1,404	)
Stock Incentive Plan Performance Award Accrual								1,415									1,415
Premium on Purchase of Stock for Employee Purchase Plan								(232	)								(232	)
Premium on Purchase of Subsidiary Class B Stock and Options											(98	)					(98	)
Cumulative Preferred Dividends											(736	)					(736	)
Common Dividends											(42,731	)					(42,731	)
Balance, December 31, 2010		36,002,739		$	180,014		$	251,919		$	198,443		$	1,487	(a)	$	631,863
Common Stock Issuances, Net of Expenses		154,225			771			2,671									3,442
Common Stock Retirements		(55,269	)		(276	)		(906	)								(1,182	)
Net Loss											(13,243	)					(13,243	)
Other Comprehensive Loss														(4,919	)		(4,919	)
Tax Benefit – Stock Compensation								(875	)								(875	)
Employee Stock Incentive Plan Expense								606									606
Premium on Purchase of Stock for Employee Purchase Plan								(292	)								(292	)
Premium on Purchase of Subsidiary Class B Stock and Options											(322	)					(322	)
Cumulative Preferred Dividends											(735	)					(735	)
Common Dividends											(42,895	)					(42,895	)
Balance, December 31, 2011		36,101,695		$	180,509		$	253,123		$	141,248		$	(3,432	)(a)	$	571,448
Common Stock Issuances, Net of Expenses		71,745			359			148									507
Common Stock Retirements		(5,072	)		(26	)		(85	)								(111	)
Net Loss											(5,273	)					(5,273	)
Other Comprehensive Loss														(953	)		(953	)
Tax Benefit – Stock Compensation								(103	)								(103	)
Employee Stock Incentive Plan Expense								435									435
Premium on Purchase of Stock for Employee Purchase Plan								(222	)								(222	)
Cumulative Preferred Dividends											(736	)					(736	)
Common Dividends											(43,018	)					(43,018	)
Balance, December 31, 2012		36,168,368		$	180,842		$	253,296		$	92,221		$	(4,385	)(a)	$	521,974

OTTER TAIL CORPORATION
Consolidated Statements of Cash Flows--For the Years Ended December 31
(in thousands)	2012			2011			2010
Cash Flows from Operating Activities
Net Loss	$	(5,273	)	$	(13,243	)	$	(1,344	)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities:
Net Loss (Gain) from Sale of Discontinued Operations		5,531			(8,674	)		--
Net Loss from Discontinued Operations		38,710			56,827			27,624
Depreciation and Amortization		59,764			58,335			57,647
Asset Impairment Charge		432			470			--
Deferred Tax Valuation Adjustments and Tax Rate Reduction		--			--			8,300
Premium Paid for Early Retirement of Long-Term Debt		12,500			--			--
Deferred Tax Credits		(2,091	)		(2,386	)		(2,715	)
Deferred Income Taxes		11,459			10,661			10,990
Change in Deferred Debits and Other Assets		(4,802	)		(25,053	)		30
Discretionary Contribution to Pension Fund		(10,000	)		--			(20,000	)
Change in Noncurrent Liabilities and Deferred Credits		32,718			35,178			2,786
Allowance for Equity (Other) Funds Used During Construction		(1,168	)		(861	)		(4	)
Change in Derivatives Net of Regulatory Deferral		718			72			208
Stock Compensation Expense – Equity Awards		1,311			2,177			2,923
Other—Net		4,500			6,496			5,847
Cash Provided by (Used for) Current Assets and Current Liabilities:
Change in Receivables		2,430			(7,952	)		(31,094	)
Change in Inventories		(687	)		(5,286	)		(8,167	)
Change in Other Current Assets		7,019			(1,072	)		(6,559	)
Change in Payables and Other Current Liabilities		30,056			(4,775	)		16,256
Change in Interest Payable and Income Taxes Receivable/Payable		(14,141	)		(7,236	)		43,206
Net Cash Provided by Continuing Operations		168,986			93,678			105,934
Net Cash Provided by (Used in) Discontinued Operations		64,561			10,705			(917	)
Net Cash Provided by Operating Activities		233,547			104,383			105,017
Cash Flows from Investing Activities
Capital Expenditures		(115,762	)		(67,360	)		(58,264	)
Proceeds from Disposal of Noncurrent Assets		4,889			1,923			827
Net Increase in Other Investments		(1,037	)		(40	)		(2,855	)
Net Cash Used in Investing Activities - Continuing Operations		(111,910	)		(65,477	)		(60,292	)
Net Proceeds from Sale of Discontinued Operations		42,229			107,310			--
Net Cash Used in Investing Activities - Discontinued Operations		(13,896	)		(36,410	)		(24,875	)
Net Cash (Used in) Provided by Investing Activities		(83,577	)		5,423			(85,167	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		--			(7,268	)		7,268
Net Short-Term (Repayments) Borrowings		--			(79,490	)		71,905
Proceeds from Issuance of Common Stock		--			--			549
Proceeds from Issuance of Class B Stock of Subsidiary		--			--			153
Common Stock Issuance Expenses		(370	)		--			(142	)
Payments for Retirement of Common Stock		(111	)		(1,182	)		(401	)
Payments for Retirement of Class B Stock and Options of Subsidiary		--			--			(1,012	)
Proceeds from Issuance of Long-Term Debt		--			142,006			--
Short-Term and Long-Term Debt Issuance Expenses		(897	)		(1,666	)		(1,699	)
Payments for Retirement of Long-Term Debt		(50,224	)		(100,796	)		(58,451	)
Premium Paid for Early Retirement of Long-Term Debt		(12,500	)		--			--
Dividends Paid and Other Distributions		(43,976	)		(43,923	)		(43,698	)
Net Cash Used in Financing Activities - Continuing Operations		(108,078	)		(92,319	)		(25,528	)
Net Cash (Used in) Provided by Financing Activities - Discontinued Operations		(4,278	)		(3,184	)		1,812
Net Cash Used in Financing Activities		(112,356	)		(95,503	)		(23,716	)
Net Change in Cash and Cash Equivalents - Discontinued Operations		(1,246	)		2,015			(2,495	)
Effect of Foreign Exchange Rate Fluctuations on Cash – Discontinued Operations		--			(324	)		(566	)
Net Change in Cash and Cash Equivalents		36,368			15,994			(6,927	)
Cash and Cash Equivalents at Beginning of Period		15,994			--			6,927
Cash and Cash Equivalents at End of Period	$	52,362		$	15,994		$	--
See accompanying notes to consolidated financial statements.

(in thousands)
Long-Lived Assets (net of accumulated depreciation)	$	45,285
Goodwill		288
Total Asset Impairment Charges	$	45,573

(in thousands)
Long-Lived Assets (net of accumulated depreciation)	$	5,859
Inventory		782
Accrued Selling Costs		1,106
Total Impairment Charges	$	7,747

	December 31,			December 31,			December 31,			December 31,
(in thousands)	2012			2011			2013			2012
Costs Incurred on Uncompleted Contracts	$	307,085		$	321,346		$	361,487		$	307,085
Less Billings to Date		(321,388	)		(340,418	)		(377,608	)		(321,388	)
Plus Estimated Earnings Recognized		1,762			22,108			6,477			1,762
	$	(12,541	)	$	3,036
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts							$	(9,644	)	$	(12,541	)