11. COMMITMENTS AND CONTINGENCIES

We are a party to various claims and legal proceedings arising out of the normal course of our business. We regularly analyze this information, and provide accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is not probable, given the company's defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows.

Coal, Natural Gas and Transportation Contracts

The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of December 31, 2014 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
January 1, 2015 through December 31, 2015	$	26.6	$	26.2
January 1, 2016 through December 31, 2017	$	42.9	$	29.5
January 1, 2018 through December 31, 2019	$	33.3	$	22.8
January 1, 2020 and beyond	$	49.6		—

We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be used at our plants, the gas would be placed in storage. The firm physical gas and transportation commitments are detailed in the table above.

We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for our coal and coal transportation contracts as of December 31, 2014 are detailed in the table above.

Purchased Power

We currently supplement our on-system (native load) generating capacity with purchases of capacity and energy from other entities in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules.

The Plum Point Energy Station (Plum Point) is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We own, through an undivided interest, 50 megawatts of the unit's capacity. We also have a long-term (30 year) agreement for the purchase of an additional 50 megawatts of capacity from Plum Point. Commitments under this agreement are approximately $289.9 million through August 31, 2039, the end date of the agreement. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. We evaluated this purchase option as part of our Integrated Resource Plan (IRP), which was filed with the MPSC on July 1, 2013. It is not currently our intention to exercise this option in 2015.

We have a 20-year purchased power agreement, which began on December 15, 2008, with Cloud County Windfarm, LLC, owned by EDP Renewables North America LLC, Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. We do not own any portion of the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost.

We also have a 20-year contract, which began on December 15, 2005, with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. We do not own any portion of the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $16.9 million based on a 20-year average cost.

Payments for these agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in the operating lease obligations shown below.

New Construction

In December 2014 we completed an environmental retrofit at our Asbury plant. The retrofit project included the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This new equipment enables us to comply with the Mercury and Air Toxics Standard (MATS). Construction costs through December 31, 2014 were $110.9 million for the project to date, excluding AFUDC. Final cost is expected to be approximately $112 million, excluding AFUDC.

We also have in place a contract with a third party vendor to complete engineering, procurement, and construction activities at our Riverton plant to convert Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The conversion will include the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. The Air Emission Source Construction Permit necessary for this project was issued by Kansas Department of Health and Environment on July 11, 2013. This conversion is currently scheduled to be completed in mid-2016 at a cost estimated to range from $165 million to $175 million, excluding AFUDC. This amount is included in our five-year capital expenditure plan. Construction costs, consisting of pre-engineering, site preparation activities and contract costs incurred project to date through December 31, 2014 were $88.5 million, excluding AFUDC.

See "Environmental Matters" below for more information on both of these projects.

Leases

We have purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC, which are considered operating leases for GAAP purposes. Details of these agreements are disclosed in the Purchased Power section of this note.

We also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for one office facility related to our gas segment. In addition, we have capital leases for certain office equipment and 108 railcars to provide coal delivery for our ownership and purchased power agreement shares of the Plum Point generating facility.

The gross amount of assets recorded under capital leases total $5.3 million at December 31, 2014.

Our lease obligations over the next five years are as follows (in thousands):

	Capital Leases		Operating Leases
2015	$	553	$	730
2016		549		720
2017		547		682
2018		547		645
2019		546		485
Thereafter		3,006		—

Total minimum payments		5,748	$	3,262
Less amount representing interest		1,581

Present value of net minimum lease payments	$	4,167

Expenses incurred related to operating leases were $0.8 million, $0.8 million and $0.9 million for 2014, 2013, and 2012, respectively, excluding payments for wind generated purchased power agreements. The accumulated amount of amortization for our capital leases was $1.5 million and $1.3 million at December 31, 2014 and 2013, respectively.

Environmental Matters

We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and hazardous and other wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as remediation of contaminated sites and other environmental matters. We believe that our operations are in material compliance with present environmental laws and regulations. Environmental requirements have changed frequently and become more stringent over time. We expect this trend to continue. While we are not in a position to accurately estimate compliance costs for any new requirements, we expect any such costs to be material, although recoverable in rates.

Electric Segment

The Federal Clean Air Act (CAA) and comparable state laws regulate air emissions from stationary sources such as electric power plants through permitting and/or emission control and related requirements. These requirements include maximum emission limits on our facilities for sulfur dioxide (SO2), particulate matter, nitrogen oxides (NOx), carbon monoxide (CO), and hazardous air pollutants including mercury. In the future they will include limits on greenhouse gases (GHG) such as carbon dioxide (CO₂).

Compliance Plan

In order to comply with current and forthcoming environmental regulations, we are taking actions to implement our compliance plan and strategy (Compliance Plan). The Mercury Air Toxic Standards (MATS) and the Clean Air Interstate Rule (CAIR), replaced by the Cross State Air Pollution Rule (CSAPR), which we discuss further below, are the drivers behind our Compliance Plan and its implementation schedule. The MATS require reductions in mercury, acid gases and other emissions considered hazardous air pollutants (HAPS). They became effective in April 2012 and require full compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). The CSAPR was first proposed by the Environmental Protection Agency (EPA) in July 2010 as a replacement of CAIR and came into effect on January 1, 2015. We anticipate compliance costs associated with the MATS, CAIR and CSAPR regulations to be recoverable in our rates.

Our Compliance Plan largely follows the preferred plan presented in our Integrated Resource Plan (IRP), filed in mid-2013 with the MPSC. As described above under New Construction, the process of installing a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant has been completed. This addition required the retirement of Asbury Unit 2, a steam turbine rated at 14 megawatts that was used for peaking purposes. Asbury Unit 2 was retired on December 31, 2013.

In September 2012, we completed the transition of our Riverton Units 7 and 8 from operation on coal and natural gas to operation solely on natural gas. Riverton Unit 7 was permanently removed from service on June 30, 2014. Riverton Unit 8 and Riverton Unit 9, a small combustion turbine that requires steam from Unit 8 for start-up, are planned to be retired upon the conversion of Riverton Unit 12, a simple cycle combustion turbine, to a combined cycle unit. This conversion is currently scheduled to be completed in mid-2016.

See "New Construction" above for project costs for both of these projects.

Air Emissions

The CAA regulates the amount of NOx and SO2 an affected unit can emit. As currently operated, each of our affected units is in compliance with the applicable NOx and SO2 limits. Through the end of 2014, NOx emissions were regulated by the CAIR and National Ambient Air Quality Standard (NAAQS) rules for ozone (discussed below). Beginning January 1, 2015, NOx emissions are regulated by CSAPR and NAAQS rules for ozone. Through the end of 2014, SO2 emissions were regulated by the Title IV Acid Rain Program and the CAIR. Beginning January 1, 2015, SO2 emissions are regulated by the Title IV Acid Rain Program and the CSAPR.

CAIR:

The CAIR generally calls for fossil-fueled power plants greater than 25 megawatts to reduce emission levels of SO2 and/or NOx in 28 eastern states and the District of Columbia, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located. Kansas was not included in CAIR and our Riverton Plant was not affected. Arkansas, where our Plum Point Plant is located, was included for ozone season NOx but not for SO2. At this time we believe we are in compliance with CAIR, which was in its final year in 2014.

CSAPR:

The CSAPR requires 23 states to reduce annual SO2 and NOx emissions to help downwind areas attain NAAQS for fine particulate matter. Twenty-five states are required to reduce ozone season NOx emissions to help downwind states attain NAAQS for ozone. The CSAPR NOx annual program impacts our Missouri and Kansas units while the CSAPR NOx ozone season program impacts our units in these two states plus our unit in Arkansas.

The CSAPR divides the states required to reduce SO2 into two groups. Both groups must reduce their SO2 emissions in Phase 1. Group 1 states, which include our sources in Missouri and Arkansas, must make additional SO2 reductions for Phase 2 in order to eliminate their significant contribution to air quality problems in downwind areas. Empire's units in Kansas are in Group 2 of the CSAPR SO2 program.

Under the CSAPR Program, in our most current five-year business plan (2015 – 2019), which assumes normal operations while maintaining compliance with permit conditions, we anticipate that it may be economically beneficial to purchase allowances for some of these pollutants if needed, but at the time of this writing the allowance markets have not been fully developed. We are in position to comply with CSAPR in 2015.

Mercury Air Toxics Standard (MATS):

As described above, the MATS standard became effective in April 2012, and requires compliance by April 2015 (with flexibility for extensions for reliability reasons). For all existing and new coal-fired electric utility steam generating units (EGUs), the MATS standard will be phased in over three years, and allows states the ability to give facilities a fourth year to comply. On March 28, 2013, the EPA finalized updates to certain emission limits for new power plants under the MATS. The new standards affect only new coal and oil-fired power plants that will be built in the future. The update does not change the final emission limits or other requirements for existing power plants. We are in position to comply with MATS in 2015.

National Ambient Air Quality Standards (NAAQS):

Under the CAA, the EPA sets NAAQS for certain emissions considered harmful to public health and the environment, including particulate matter (PM), NOx, CO, SO2, and ozone which result from fossil fuel combustion. Our facilities are currently in compliance with all applicable NAAQS.

In January 2013, the EPA finalized the revised PM 2.5 primary annual standard at 12 ug/m3 (micrograms per cubic meter of air). States are required to meet the primary standard in 2020. The standard should have no impact on our existing generating fleet because the regional ambient monitor results are below the PM 2.5 required level. However, the PM 2.5 standards could impact future major modifications/construction projects that require additional permits.

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. Based on the current standard, our service territory is designated as attainment, meaning that it is in compliance with the standard. A revised ozone NAAQS was proposed by the EPA on November 25, 2014 and the final rule is expected in October 2015. We believe this revised Ozone NAAQS would affect our region but it's too early to determine what, if any, impact it would have on our generating plants at this time.

Greenhouse Gases (GHGs):

As the EPA began to prepare for future regulations, GHG emissions have been reported for several years under the Mandatory GHG Reporting Rule. EDE and EDG's GHG emissions for each year, since 2013, have been reported to the EPA as required.

A series of actions and decisions including the Tailoring Rule, which regulates carbon dioxide and other GHG emissions from certain stationary sources, have further set the foundation for the regulation of GHGs. However, because of the uncertainties regarding the final outcome of the GHG regulations (discussed below), the ultimate cost of compliance cannot be determined at this time. In any case, we expect the cost of complying with any such regulations to be recoverable in our rates.

In April 2012, the EPA proposed a Carbon Pollution Standard for new power plants to limit the amount of carbon emitted by EGUs. This standard was rescinded, and a re-proposal of standards of performance for affected fossil fuel-fired EGUs was published in January 2014. The proposed rule applies only to new EGUs and sets separate standards for natural gas-fired combustion turbines and for fossil fuel-fired utility boilers. The proposal would not apply to existing units, including modifications such as those required to meet other air pollution standards which are currently being undertaken at our Asbury facility and at the Riverton facility with the conversion of simple cycle Unit 12 to combined cycle. The final rule is expected in the summer of 2015.

On June 2, 2014, the EPA released the proposed rule for limiting carbon emissions from existing power plants. The "Clean Power Plan" requires a 30% carbon emission reduction from 2005 baseline levels by 2030 and requires fossil-fuel fired power plants across the nation, including those in Empire's fleet, to meet state-specific goals to lower carbon levels. The EPA has identified four building block strategies to achieve the best system of emission reduction (BSER). Included in these strategies are the following: efficiency improvements at fossil fuel power plants; using lower-emitting sources (such as natural gas combined cycle units); using more renewables and keeping nuclear sources; and using power more efficiently. States will use the building blocks to craft their compliance plans or may work with other states in developing a regional approach to compliance, in which case additional time is given for implementation.

The EPA is scheduled to issue the final rule for existing power plants by summer of 2015. Each state must submit its initial compliance plan by the summer of 2016 with additional time available by request until the summer of 2017 for a single state or the summer of 2018 for a multi-state approach. The EPA received greater than 2 million public comments by the December 1, 2014 closure of the comment period. State, federal and industry representatives voiced their concerns with the regulation as written and the potential impact on electric grid reliability and the cost to implement. State and industry representatives including Empire continue to evaluate potential paths forward if the rule is finalized as proposed by the EPA.

Also, on June 2, 2014, the EPA released the proposed carbon pollution standards for modified and reconstructed stationary EGUs. The proposed rule focuses on electric utility steam generating units and natural gas-fired stationary combustion turbines. The comment period ended October 16, 2014 and the EPA anticipates issuing a final rule in June 2015.

Water Discharges

We operate under the Kansas and Missouri Water Pollution Plans pursuant to the Federal Clean Water Act (CWA). Our plants are in material compliance with applicable regulations and have received all necessary discharge permits.

The Riverton Units 7 and 8 and Iatan Unit 1, which utilize once-through cooling water, were affected by regulations for Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) Phase II. In 2007, the United States Court of Appeals remanded key sections of these CWA regulations to the EPA. The EPA suspended the regulations. Following a series of court approved delays, the EPA published the final rule on August 15, 2014 with an effective date of October 14, 2014. Court challenges are expected. We expect the regulations to have a limited impact at Riverton given the planned retirement of unit 8 scheduled in 2016. A new intake structure design and cooling tower will be constructed as part of the Unit 12 conversion at Riverton. Impacts at Iatan 1 could range from flow velocity reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower retrofit. Our new Iatan Unit 2 and Plum Point Unit 1 are covered by the proposed regulation, but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally affected by the final rule.

Surface Impoundments

We own and maintain a coal ash impoundment located at our Asbury Power Plant. Additionally, we own a 12% interest in a coal ash impoundment at the Iatan Generating Station and a 7.52% interest in a coal ash impoundment at Plum Point. As a result of the transition from coal to natural gas fuel for Riverton Units 7 and 8, the former Riverton ash impoundment has been capped and closed. Final closure as an industrial (coal combustion waste) landfill was approved on June 30, 2014 by the Kansas Department of Health and Environment (KDHE).

On April 19, 2013, the EPA signed a notice of proposed rulemaking to revise its wastewater effluent limitation guidelines and standards under the CWA for coal-fired power plants. The proposal calls for updates to operating permits beginning in July 2017. Once the new guidelines are issued, the EPA and states would incorporate the new standards into wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs that might result from any new standards. All of our coal ash impoundments are compliant with existing state and federal regulations.

In June 2010, the EPA proposed to regulate coal combustion residuals (CCRs) under the Federal Resource Conservation and Recovery Act (RCRA). In the proposal, the EPA presented two options: (1) regulation of CCR under RCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRA subtitle D as a non-hazardous waste. On December 19, 2014 the EPA finalized the requirements under the subtitle D solid waste provisions. We expect compliance to result in the need to construct a new landfill and the conversion of existing ash handling from a wet to a dry system(s) at a potential cost of up to $15 million at our Asbury Power Plant. This preliminary estimate was developed before the rule was finalized and will be updated to conform to the final rule. We expect resulting costs to be recoverable in our rates.

We have received preliminary permit approval in Missouri for a new utility waste landfill adjacent to the Asbury plant. Our Detailed Site Investigation (DSI) has been completed and was submitted to MDNR for review and approval in on January 21, 2015. Receipt of the final construction permit for the waste landfill is expected in early 2016.

Renewable Energy

On November 4, 2008 Missouri voters approved the Clean Energy Initiative (Proposition C) which currently requires Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase Renewable Energy Credits (RECs), in amounts equal to at least 5% of retail sales in 2014, increasing to at least 15% by 2021. We are currently in compliance with this regulatory requirement as a result of generation from our Ozark Beach Hydroelectric Project and purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas, and Elk River Windfarm, LLC, located in Butler County, Kansas. Proposition C also requires that 2% of the energy from renewable energy sources must be solar; however, we believed that we were exempted by statute from the solar requirement. On January 20, 2013 the Earth Island Institute, d/b/a Renew Missouri, and others challenged our solar exemption by filing a complaint with the MPSC. The MPSC dismissed the complaint and Renew Missouri filed a notice of appeal seeking review by the Missouri Supreme Court. On February 10, 2015 the Missouri Supreme Court issued an opinion holding that the legislature had the authority to adopt the statute providing the exemption but reversed the MPSC's holding that the two laws could be harmonized. The statute providing the exemption (which was enacted in August 2008) was impliedly repealed by the adoption of Proposition C because it conflicted with the latter law. We believe the matter will return to the MPSC for further action. While we are not in a position to accurately estimate the impact of this requirement, we expect any future costs to be recoverable in rates.

Kansas established a renewable portfolio standard (RPS), effective November 19, 2010. It requires 10% of our Kansas retail customer peak capacity requirements to be sourced from renewables in 2012, increasing to 15% by 2016, and to 20% by 2020. We are currently in compliance with this regulatory requirement as a result of purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas and Elk River Windfarm, LLC, located in Butler County, Kansas.