COMMITMENTS AND CONTINGENCIES

Purchase Orders and Contracts

As part of our ongoing operations and capital expenditure program, we have purchase orders and contracts, excluding fuel and transmission, which are discussed below under “—Fuel and Purchased Power Commitments.” These commitments relate to purchase obligations issued and outstanding at year-end.

The yearly detail of the aggregate amount of required payments as of December 31, 2016, was as follows.



	Committed Amount
	(In Thousands)
2017	$	310,711
2018	73,149
2019	25,411
Thereafter	8,100
Total amount committed	$	417,371

Environmental Matters

Set forth below are descriptions of contingencies related to environmental matters that may impact us or our financial results. Our assessment of these contingencies, which are based on federal and state statutes and regulations, and regulatory agency and judicial interpretations and actions, has evolved over time. Since his inauguration in January 2017, reports and other information that have been released suggest that President Trump may alter federal environmental policy, including through executive orders and influencing changes to statutes, regulations and agency priorities. Due in part to the preliminary nature of information that is available to us, as well as the complex nature of environmental regulation, we are unable to assess the impact of potential changes that may develop with respect to the environmental contingencies described below.

Federal Clean Air Act

We must comply with the federal Clean Air Act (CAA), state laws and implementing federal and state regulations that impose, among other things, limitations on emissions generated from our operations, including sulfur dioxide (SO₂), particulate matter (PM), nitrogen oxides (NOx), carbon monoxide (CO), mercury and acid gases.

Emissions from our generating facilities, including PM, SO₂ and NOx, have been determined by regulation to reduce visibility by causing or contributing to regional haze. Under federal laws, such as the Clean Air Visibility Rule, and pursuant to an agreement with the Kansas Department of Health and Environment (KDHE) and the Environmental Protection Agency (EPA), we are required to install, operate and maintain controls to reduce emissions found to cause or contribute to regional haze.

Sulfur Dioxide and Nitrogen Oxide

Through the combustion of fossil fuels at our generating facilities, we emit SO₂ and NOx. Federal and state laws and regulations, including those noted above, and permits issued to us limit the amount of these substances we can emit. If we exceed these limits, we could be subject to fines and penalties. In order to meet SO₂ and NOx regulations applicable to our generating facilities, we use low-sulfur coal and natural gas and have equipped the majority of our fossil fuel generating facilities with equipment to control such emissions.

We are subject to the SO₂ allowance and trading program under the federal Clean Air Act Acid Rain Program. Under this program, each unit must have enough allowances to cover its SO₂ emissions for that year. In 2016, we had adequate SO₂ allowances to meet generation and we expect to have enough to cover emissions under this program in 2017.

Cross-State Air Pollution Update Rule

In September 2016, the EPA finalized the Cross-State Air Pollution Update Rule. The final rule addresses interstate transport of NOx emissions in 22 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the final rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. We do not believe this rule will have a material impact on our operations and consolidated financial results.

National Ambient Air Quality Standards

Under the federal CAA, the EPA sets NAAQS for certain emissions known as the “criteria pollutants” considered harmful to public health and the environment, including two classes of PM, ozone, NOx (a precursor to ozone), CO and SO₂, which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.

In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 parts per billion (ppb) to 70 ppb. In September 2016, the KDHE recommended to the EPA that they designate the state of Kansas as in attainment or in attainment/unclassifiable with the standard. The EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. If the EPA agrees with an attainment or attainment/unclassifiable designation for the state of Kansas, we do not believe this will have a material impact on our consolidated financial results.

In December 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We do not believe this will have a material impact on our operations or consolidated financial results.

In 2010, the EPA revised the NAAQS for SO₂. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO₂ emissions criteria for certain electric generating plants that, if met, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants. Tecumseh Energy Center is our only generating station that meets this criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable, completing the second round of the designation process. In addition, in January 2017, KDHE formally recommended to the EPA a 2,000 ton per year limit for Tecumseh Energy Center Unit 7 in order to satisfy the requirements of the 1-hour SO₂ Data Requirements Rule which governs the next round of the designations. By agreeing to the ton per year limitation, no further characterization of the area surrounding the plant is required. We continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated financial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.

Greenhouse Gases

Burning coal and other fossil fuels releases carbon dioxide (CO₂) and other gases referred to as greenhouse gases (GHG). Various regulations under the federal CAA limit CO₂ and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.

In October 2015, the EPA published a rule establishing new source performance standards that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour depending on various characteristics of the units. Also in October 2015, the EPA published a rule establishing guidelines for states to regulate CO₂ emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our Company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015. In February 2016, after the U.S. Court of Appeals for the D.C. Circuit denied requests to stay the CPP, the U.S. Supreme Court issued an order granting a stay of the rule pending resolution of the legal challenges. In September 2016, oral arguments were heard before the U.S. Court of Appeals for the D.C. Circuit to review the CPP and to conduct the review en banc. Despite the stay, the EPA issued a proposed rule formalizing the details of the CPP’s Clean Energy Incentive Program. In January 2017, the EPA denied our Petition for Reconsideration and Administrative Stay of the CPP. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with the CPP could be material.

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual (CCR) handling. Implementation timelines for these requirements will vary from 2019 to 2023. We are evaluating the final rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material.

In October 2014, the EPA’s final standards for cooling intake structures at power plants to protect aquatic life took effect. The standards, based on Section 316(b) of the federal Clean Water Act (CWA), require subject facilities to choose among seven best available technology options to reduce fish impingement. In addition, some facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. Our current analysis indicates this rule will not have a significant impact on our coal plants that employ cooling towers. Biological monitoring may be required for La Cygne and Wolf Creek. We are currently evaluating the rule’s impact on those two plants and cannot predict the resulting impact on our operations or consolidated financial results, but we do not expect it to be material.

In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states have filed lawsuits challenging the rule and, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. It is believed the stay will last into 2017. We are currently evaluating the final rule. We do not believe the rule will have a material impact on our operations or consolidated financial results.

Regulation of Coal Combustion Residuals

In the course of operating our coal generation plants, we produce CCRs, including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCRs in April 2015, which we believe will require additional CCR handling, processing and storage equipment and closure of certain ash disposal ponds. Impacts to operations will be dependent on the development of groundwater monitoring of CCR units being completed in 2017. We have recorded an ARO for our current estimate for closure of ash disposal ponds but may be required to record additional AROs in the future due to changes in existing CRR regulations, changes in interpretation of existing CCR regulations or changes in the timing or cost to close ash disposal ponds. If additional AROs are necessary, we believe the impact on our operations or consolidated financial results could be material. See Note 15, “Asset Retirement Obligations,” for additional information.

SPP Revenue Crediting

We are a member of the Southwest Power Pool, Inc. (SPP) RTO, which coordinates the operation of a multi-state interconnected transmission system. The SPP has recently completed the process of allocating revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are those that are not financed through general rates paid by all customers and that result in additional revenue to the SPP. The SPP has determined sponsors are entitled to revenue credits for previously completed upgrades, and members are obligated to pay for revenue credits attributable to these historical upgrades. As a result, we paid the SPP in November 2016 $7.6 million related to revenue credits attributable to historical upgrades from March 2008 to August 2016. Most of the related charges will be recovered from our customers in future prices.

Nuclear Decommissioning

Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with NRC requirements. The NRC will terminate a plant’s license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that sufficient funds required for nuclear decommissioning will be accumulated prior to the expiration of the license of the related nuclear power plant. Wolf Creek files a nuclear decommissioning site study with the KCC every three years.

The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the updated nuclear decommissioning study including the estimated costs to decommission the plant. Phase two involves the review and approval of a funding schedule prepared by the owner of the plant detailing how it plans to fund the future-year dollar amount of its pro rata share of the decommissioning costs.

In 2014, Wolf Creek updated the nuclear decommissioning cost study. Based on the study, our share of decommissioning costs, including decontamination, dismantling and site restoration, is estimated to be approximately $360.0 million. This amount compares to the prior site study estimate of $296.2 million. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in regulations and technologies as well as changes in costs for labor, materials and equipment.

We are allowed to recover nuclear decommissioning costs in our prices over a period equal to the operating license of Wolf Creek, which is through 2045. The NRC requires that funds sufficient to meet nuclear decommissioning obligations be held in a trust. We believe that the KCC approved funding level will also be sufficient to meet the NRC requirement. Our consolidated financial results would be materially affected if we were not allowed to recover in our prices the full amount of the funding requirement.

We recovered in our prices and deposited in an external trust fund for nuclear decommissioning approximately $5.0 million in 2016, $2.8 million in 2015 and $2.8 million in 2014. We record our investment in the NDT fund at fair value, which approximated $200.1 million and $184.1 million as of December 31, 2016 and 2015, respectively.

Storage of Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. In 2010, the DOE filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE’s application. The NRC has not yet issued its decision.

Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. Wolf Creek is in discussions with the DOE to determine which of its incremental costs may be reimbursable. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.

Nuclear Insurance

We maintain nuclear liability, property and accidental outage insurance for Wolf Creek. These policies contain certain industry standard terms, conditions and exclusions, including, but not limited to, ordinary wear and tear and war. An industry aggregate limit of $3.2 billion for nuclear events ($1.8 billion of non-nuclear events) plus any reinsurance, indemnity or any other source recoverable by Nuclear Electric Insurance Limited (NEIL), our property and accidental outage insurance provider, exists for acts of terrorism affecting Wolf Creek or any other NEIL insured plant within 12 months from the date of the first act. In addition, we are required to participate in industry-wide retrospective assessment programs as discussed below.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, we insure against public nuclear liability claims resulting from nuclear incidents to the required limit of public liability, which is approximately $13.4 billion. This limit of liability consists of the maximum available commercial insurance of $375.0 million and the remaining $13.0 billion is provided through mandatory participation in an industry-wide retrospective assessment program. For incidents after January 1, 2017, this commercial insurance limit increased to $450.0 million. Under this retrospective assessment program, the owners of Wolf Creek are jointly and severally subject to an assessment of up to $127.3 million (our share is $59.8 million), payable at no more than $19.0 million (our share is $8.9 million) per incident per year per reactor for any commercial U.S. nuclear reactor qualifying incident. Both the total and yearly assessment is subject to an inflationary adjustment every five years with the next adjustment in 2018. In addition, Congress could impose additional revenue-raising measures to pay claims.

Nuclear Property and Accidental Outage Insurance

The owners of Wolf Creek carry decontamination liability, nuclear property damage and premature nuclear decommissioning liability insurance for Wolf Creek totaling approximately $2.8 billion. Insurance coverage for non-nuclear property damage accidents total approximately $2.3 billion. In the event of an extraordinary nuclear accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. Our share of any remaining proceeds can be used to pay for property damage or, if certain requirements are met, including decommissioning the plant, toward a shortfall in the NDT fund. The owners also carry additional insurance with NEIL to help cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If significant losses were incurred at any of the nuclear plants insured under the NEIL policies, we may be subject to retrospective assessments under the current policies of approximately $37.5 million (our share is $17.6 million).

Nuclear Insurance Considerations

Although we maintain various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, our insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable in our prices, would have a material effect on our consolidated financial results.

Fuel and Purchased Power Commitments

To supply a portion of the fuel requirements for our power plants, the owners of Wolf Creek have entered into various contracts to obtain nuclear fuel and we have entered into various contracts to obtain coal and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. As of December 31, 2016, our share of Wolf Creek’s nuclear fuel commitments was approximately $16.5 million for uranium concentrates expiring in 2017, $2.5 million for conversion expiring in 2017, $80.3 million for uranium hexafluoride expiring in 2024, $81.6 million for enrichment expiring in 2027 and $29.7 million for fabrication expiring in 2025. In January 2017, Wolf Creek entered into a new nuclear fuel agreement resulting in an additional commitment, at our share, of approximately $16.4 million for uranium concentrates expiring 2024 and $1.7 million for conversion expiring 2024.

As of December 31, 2016, our coal and coal transportation contract commitments under the remaining terms of the contracts were approximately $659.4 million. The contracts are for plants that we operate and expire at various times through 2020.

As of December 31, 2016, our natural gas transportation contract commitments under the remaining terms of the contracts were approximately $105.8 million. The natural gas transportation contracts provide firm service to several of our natural gas burning facilities and expire at various times through 2030.

We have power purchase agreements with the owners of nine separate wind generation facilities with installed design capabilities of approximately 1,328 MW expiring in 2028 through 2036. Each of the agreements provide for our receipt and purchase of energy produced at a fixed price per unit of output. We estimate that our annual cost of energy purchased from these wind generation facilities will be approximately $140.1 million.

FERC Proceedings

See Note 4, “Rate Matters and Regulation - FERC Proceedings,” for information regarding a settlement of a complaint that was filed by the KCC against us with the FERC.