We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has provided 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, individually or in the aggregate, will have a material adverse effect upon our financial condition, or results of operations or cash flows.

On May 22, 2009, a suit was filed in the Circuit Court of Platte County Missouri by several individuals and Class Representatives alleging damages to land, structures, equipment and devastation of crops due to inappropriate management of the levee system around the Iatan Generating Station, of which we are a 12% owner. This matter was set for trial beginning November 7, 2011, but has now been rescheduled for March 14, 2012. We are unable to predict the outcome of the law suit or estimate the amount of damages, if any.

A lawsuit has been filed in Jasper County Circuit Court against us by three of our residential customers, purporting to act on behalf of all Empire customers. These customers are seeking a refund of certain amounts paid for service provided by Empire between January 1, 2007, and December 13, 2007. We will vigorously defend against the claims made against us by these three residential customers. At all times, we charged the three plaintiffs, and all of our customers, the rates approved by and on file with the MPSC.

The rates charged by us during the time period at issue were approved by the MPSC in our 2006 rate case. The orders of the MPSC in that case were appealed by the OPC, acting on behalf of the public, and certain industrial customers. The Missouri Court of Appeals affirmed all decisions entered by the MPSC in our 2006 rate case.

	Firm physical gas and transportation contracts		Coal and coal transportation contracts

	(in millions)
January 1, 2012 through December 31, 2012	$	30.9	$	35.3
January 1, 2013 through December 31, 2014		43.5		46.7
January 1, 2015 through December 31, 2016		24.5		31.3
January 1, 2017 and beyond		17.8		—

In addition to the above, we have an agreement with Southern Star Central Pipeline, Inc. to purchase one million Dths of firm gas storage service capacity for our electric business for a period of five years, which began in April 2011. The reservation charge for this storage capacity is approximately $1.1 million annually.

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 liquidated at market price. 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. We entered into a contract in the second quarter of 2010 to transport coal beginning June 30, 2010, which replaced a contract that expired June 29, 2010. The contract term is for six and one-half years and includes minimum payments totaling approximately $91.9 million. The minimum requirements for our coal and coal transportation contracts are detailed in the table above.

We currently supplement our on-system 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.

We have a long term (30 year) agreement for the purchase of capacity from the Plum Point Energy Station, a 665-megawatt, coal-fired generating facility near Osceola, Arkansas. We began receiving purchased power on September 1, 2010. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. Commitments under this contract total approximately $35.0 million through August 30, 2015.

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.

We own a 50 megawatt, 7.52%, undivided interest in the Plum Point Energy Station described above. Our share of the Plum Point initial construction costs through December 31, 2011 was $86.8 million plus AFUDC of $16.5 million. The Plum Point Energy Station entered commercial operation on September 1, 2010.

We also own an undivided ownership interest in the coal-fired Iatan 2 generating facility operated by Kansas City Power & Light Company (KCP&L) and located at the site of the existing Iatan Generating Station (Iatan 1) near Weston, Missouri. We own 12%, or approximately 102 megawatts, of the 850-megawatt unit, which entered commercial operation on December 31, 2010. Our share of the initial construction costs through December 31, 2011 was $233.3 million plus AFUDC of $19.1 million.

The recovery of these construction costs has been sought through rate cases filed with the regulators in each of our jurisdictions. These construction costs, as well as other construction costs, are subject to prudency reviews by our regulators. The prudency of the construction costs for Iatan 1, Iatan 2 and Plum Point was not addressed in our most recent Missouri rate case, but may be considered in a future rate proceeding. See Rate Matters in Note 3 for the details of each case.

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 $5.5 million at December 31, 2011.

Capital Leases	Capital Leases		Operating Leases

2012	$	618	$	939
2013		595		758
2014		553		720
2015		553		720
2016		549		720
Thereafter		4,646		1,813

Total minimum payments		7,514		5,670
Less amount representing interest		2,483		—

Present value of net minimum lease payments	$	5,031	$	5,670

Expenses incurred related to operating leases were $1.0 million, $0.8 million and $1.4 million for 2011, 2010, and 2009, respectively, excluding payments for wind generated purchased power agreements. The accumulated amount of amortization for our capital leases was $1.0 million and $0.6 million at December 31, 2011 and 2010, respectively.

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.

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, and nitrogen oxides (NOx). In the future they are also likely to include limits on emissions of mercury, other hazardous pollutants (HAPs) and so-called greenhouse gases (GHG) such as carbon dioxide (CO₂) and methane.

Under the CAA we have obtained, and renewed as necessary, site operating permits, which are valid for five years, for each of our plants.

In order to comply with forthcoming environmental regulations, Empire is taking actions to implement its compliance plan and strategy (Compliance Plan). While the Cross State Air Pollution Rule (CSAPR) that was set to take effect on January 1, 2012 was stayed at the last minute in late December 2011 by the District of Columbia Circuit Court of Appeals, the Mercury and Air Toxics Standards (MATS) Rules were signed by the Environmental Protection Agency (EPA) Administrator on December 16, 2011. MATS is set to become effective and will require compliance within a three year timeframe (with flexibility for extensions for reliability reasons). This Compliance Plan largely follows the preferred plan presented in our most recent Integrated Resource Plan. The Compliance Plan calls for the installation of a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant by early 2015 at a cost ranging from $112 million to $130 million. The addition of this air quality control equipment will require the retirement of Asbury Unit 2, an 18 megawatt steam turbine that is currently used for peaking purposes. The Compliance Plan also calls for the transition of our Riverton Units 7 and 8 from operation on coal to full operation on natural gas after the summer of 2013. Riverton Units 7 and 8, along with Riverton Unit 9, a small combustion turbine that requires steam from Unit 7 for start-up, will be retired upon the conversion of Riverton Unit 12, a recently installed simple cycle combustion turbine, to a combined cycle unit. This conversion is currently scheduled for the 2016 timeframe.

The CAA regulates the amount of SO₂ an affected unit can emit. Currently SO₂ emissions are regulated by the Title IV Acid Rain Program and the Clean Air Interstate Rule (CAIR). On January 1, 2012, CAIR was to have been replaced by the Cross-State Air Pollution Rule (CSAPR- formerly the Clean Air Transport Rule). But, on December 30, 2011 the District of Columbia Circuit Court of Appeals issued a stay of the CSAPR. CAIR will remain in effect while the case is reviewed. The Title IV Acid Rain Program will still remain in effect.

The Mercury Air Toxics Standards (MATS), discussed below, was signed on December 16, 2011, and will affect SO₂ emission rates at our facilities. In addition, the compliance date for the revised SO₂ National Ambient Air Quality Standards (NAAQS) is August of 2017; this will also affect SO₂ emissions from our facilities. The SO₂ NAAQS is discussed in more detail below.

Under the Title IV Acid Rain Program, each existing affected unit has been allocated a specific number of emission allowances by the U.S. Environmental Protection Agency (EPA). Each allowance entitles the holder to emit one ton of SO₂. Covered utilities, such as Empire, must have emission allowances equal to the number of tons of SO₂ emitted during a given year by each of their affected units. Allowances in excess of the annual emissions are banked for future use. In 2010, our SO₂ emissions exceeded the annual allocations. This deficit was covered by our banked allowances. When our Title IV Acid Rain Program SO₂ allowance bank is exhausted, currently estimated to be late 2012, we will need to purchase additional SO₂ allowances, blend more low sulfur coal at our facilities or transition our coal-fired Riverton Units 7 and 8 to natural gas or a combination of the above. Long-term compliance with this program will be met by the Compliance Plan detailed above along with possible procurement of additional S0₂ allowances. We expect the cost of compliance to be fully recoverable in our rates.

In 2005, the EPA promulgated CAIR under the CAA. 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.

In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR and remanded it back to EPA for further consideration, but also stayed its vacatur. As a result, CAIR became effective for NOx on January 1, 2009 and for SO₂ on January 1, 2010 and required covered states to develop State Implementation Plans (SIPs) to comply with specific SO₂ state-wide annual budgets.

SO₂ allowance allocations under the Title IV Acid Rain Program are used for compliance in the CAIR SO₂ Program. Beginning in 2010, SO₂ allowances were utilized at a 2:1 ratio for our Missouri units. As a result, based on current SO₂ allowance usage projections, we expected to have sufficient allowances to take us into the latter part of 2012.

In order to meet CAIR requirements for SO₂ and NOx emissions (NOx is discussed below in more detail) and as a requirement for the air permit for Iatan 2, a Selective Catalytic Reduction system (SCR), a FGD scrubber system and baghouse were installed at our jointly-owned Iatan 1 plant and a SCR was installed at our Asbury plant in 2008. Our jointly-owned Iatan 2 and Plum Point plants were originally constructed with the above technology.

On July 6, 2010, the EPA published a proposed CAIR replacement rule entitled the Clean Air Transport Rule (CATR). As proposed and supplemented, the CATR included Missouri and Kansas under both the annual and ozone season for NOx as well as the SO₂ program while Arkansas remained in the ozone season NOx program only. The final CATR was released on July 7, 2011 under the name of the CSAPR, and was set to become effective January 1, 2012. However, as mentioned above, the District of Columbia Circuit Court of Appeals stayed the rule and as of January 1, 2012, the CAIR will be in effect while the court reviews the case. When it was published, the final CSAPR required a 73% reduction in SO₂ from 2005 levels by 2014. The SO₂ allowances allocated under the EPA's Title IV Acid Rain Program cannot be used for compliance with CSAPR but would continue to be used for compliance with the Title IV Acid Rain Program. Therefore, new SO₂ allowances would be allocated under CSAPR and retired at one allowance per ton of SO₂ emissions emitted. We would receive fewer SO₂ allowances than we currently emit. Long-term compliance with this Rule will be met by the Compliance Plan detailed above along with possible procurement of additional SO₂ allowances. A number of states, including Kansas, electric utilities and industrial organizations commenced litigation with the District of Columbia Court of Appeals challenging the CSAPR being stayed. The court has ordered that the parties submit briefs for an April 2012 hearing. We expect compliance costs to be recoverable in our rates.

Proposed by the EPA on March 16, 2011 and signed on December 16, 2011, the MATS regulation does not include allowance mechanisms, but would establish alternative standards for certain pollutants, including SO₂ (as a surrogate for hydrogen chloride (HCI)), which must be met to show compliance with hazardous air pollutant limits (see additional discussion in the MATS section below).

In June 2010, the EPA finalized a new 1-hour SO₂ NAAQS which, for areas with no SO₂ monitor, will require modeling to determine attainment and non-attainment areas within each state. This modeling of emission sources is to be completed by June 2013 with compliance with the SO₂ NAAQS required by August 2017. Draft guidance for 1-hour SO₂ NAAQS has been published by the EPA to assist states as they prepare their SIP submissions. The EPA is also planning a rulemaking to address some of the 1-hour SO₂ NAAQS implementation program elements. It is likely coal-fired generating units will need scrubbers to be capable of meeting the new 1-hour SO₂ NAAQS. In addition, units will be required to include SO₂ emissions limits in their Title V permits or execute consent decrees to assure attainment and future compliance.

The CAA regulates the amount of NOx an affected unit can emit. As currently operated, each of our affected units is in compliance with the applicable NOx limits. Currently, revised NOx emissions are limited by the CAIR (subject to the outcome of the CSAPR proceedings) and by ozone NAAQS rules (discussed below) which were established in 1997 and in 2008.

In 2005, the EPA promulgated CAIR under the CAA. CAIR generally calls for fossil-fueled power plants greater than 25 megawatts to reduce emission levels of NOx in 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located and Arkansas where the Plum Point Energy Station is located. Kansas was not included in CAIR and our Riverton Plant was not affected.

The CAIR required covered states to develop SIPs to comply with specific annual NOx state-wide allowance allocation budgets. Based on existing SIPs, we had excess NOx allowances during 2010 which were banked for future use and will be sufficient for compliance at least through the end of 2012. The CAIR NOx program also was to have been replaced by the CSAPR program January 1, 2012 but because of the court stay will remain in effect while the case is reviewed.

As published, the final rule requires a 54% reduction in NOx from 2005 levels by 2014. The NOx annual and ozone season allowances that were allocated and banked under CAIR cannot be used for compliance under CSAPR. New allowances will be issued under CSAPR.

To address NOx annual and NOx ozone season compliance, our options range from increasing the level of control with the Asbury SCR, the transition of our Riverton Plant coal-fired units to natural gas, or purchasing emission allowances. We expect the cost of compliance to be fully recoverable in our rates.

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. On January 6, 2010, the EPA proposed to lower the primary NAAQS for ozone designed to protect public health to a range between 60 and 70 ppb and to set a separate secondary NAAQS for ozone designed to protect sensitive vegetation and ecosystems.

On September 2, 2011, President Obama ordered the EPA to withdraw proposed air quality standards lowering the 2008 ozone standard pending the CAA 2013 scheduled reconsideration of the ozone NAAQS (the normal 5 year reconsideration period). States will move forward with area designations based on the 2008 75 ppb standard using 2008-2010 quality assured monitoring data. Our service territory will be designated as attainment, meaning it will be in compliance with the standard. In the interim, the 1997 ozone NAAQS will remain in effect.

In 2005, the EPA issued the Clean Air Mercury Rule (CAMR) under the CAA. It set limits on mercury emissions by power plants and created a market-based cap and trade system expected to reduce nationwide mercury emissions in two phases. New mercury emission limits for Phase 1 were to go into effect January 1, 2010. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia vacated CAMR. This decision was appealed to the U.S. Supreme Court which denied the appeal on February 23, 2009.

The EPA issued an Information Collection Request (ICR) for determining the National Emission Standards for Hazardous Air Pollutants (NESHAP), including mercury, for coal and oil-fired electric steam generating units on December 24, 2009. This ICR included our Iatan, Asbury and Riverton plants. All ICRs were submitted as required. The EPA ICR was intended for use in developing regulations under Section 112(r) of the CAA maximum achievable emission standards for the control of the emission of hazardous air pollutants (HAPs), including mercury. The EPA proposed the first ever national mercury and air toxics standards (MATS) in March 2011. It was signed by EPA Administrator on December 16, 2011 and establishes numerical emission limits to reduce emissions of heavy metals, including mercury (Hg), arsenic, chromium, and nickel, and acid gases, including HCl and hydrogen fluoride (HF). For all existing and new coal-fired electric utility steam generating units (EGUs), the proposed standard will be phased in over three years, and allows states the ability to give facilities a fourth year to comply.

The MATS regulation of HAPs in combination with CSAPR is the driving regulation behind our Compliance Plan and its implementation schedule. We expect compliance costs to be recoverable in our rates.

Our coal and gas plants, vehicles and other facilities, including EDG (our gas segment), emit CO2 and/or other Greenhouse Gases (GHGs) which are measured in Carbon Dioxide Equivalents (CO2e).

On September 22, 2009, the EPA issued the final Mandatory Reporting of Greenhouse Gases Rule under the CAA which requires power generating and certain other facilities that equal or exceed an emission threshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually commencing in September 2011. GHG emissions have been reported as required to the EPA in 2011 for EDE and EDG. On January 11, 2012 EPA released the greenhouse gas data reported from large facilities and suppliers across the U.S. economy for the year 2010.

On December 7, 2009, responding to a 2007 U.S. Supreme Court decision that determined that GHGs constitute "air pollutants" under the CAA, the EPA issued its final finding that GHGs threaten both the public health and the public welfare. This "endangerment" finding does not itself trigger any EPA regulations, but is a necessary predicate for the EPA to proceed with regulations to control GHGs. On May 13, 2010, the EPA issued under the CAA its final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule) to address GHG emissions from stationary sources, which became effective January 2, 2011. The rule sets thresholds for GHG emissions that determine when permits will be required under the New Source Review Prevention of Significant Deterioration (PSD) and title V Operating Permit programs applicable to new and existing power plants and other covered sources. Under the PSD program, required controls for GHG emissions would be determined based on Best Available Control Technology (BACT). EPA issued a BACT permitting guidance document on November 11, 2010. Missouri and Kansas have been delegated GHG permitting authority by EPA. Several parties have filed petitions with the EPA and lawsuits have been filed challenging the EPA's Endangerment Finding and the Tailoring Rule.

In addition, on December 23, 2010 the EPA entered into an agreement with a number of state and environmental petitioners to settle litigation pending in the U.S. Court of Appeals for the District of Columbia Circuit that requires EPA to propose New Source Performance Standards (NSPS) for GHGs for fossil-fuel fired steam generating units by September 30, 2011 and to issue final GHG NSPS standards by May 26, 2012. The EPA has not to date issued a proposed GHG emissions rule for stationary sources.

A variety of proposals have been and are likely to continue to be considered by Congress to reduce GHGs. Proposals are also being considered in the House and Senate that would delay, limit or eliminate EPA's authority to regulate GHGs. At this time, it is not possible to predict what legislation, if any, will ultimately emerge from Congress regarding control of GHGs.

Certain states have taken steps to develop cap and trade programs and/or other regulatory systems which may be more stringent than federal requirements. For example, Kansas is a participating member of the Midwestern Greenhouse Gas Reduction Accord (MGGRA), one purpose of which is to develop a market-based cap and trade mechanism to reduce GHG emissions. The MGGRA has announced, however, that it will not issue a CO2e regulatory system pending federal legislative developments. Missouri is not a participant in the MGGRA.

The ultimate cost of any GHG regulations cannot be determined at this time. However, we would expect the cost of complying with any such regulations to be recoverable in our rates.

We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Clean Water Act (CWA). Our plants are in material compliance with applicable regulations and have received 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. The regulations became final on February 16, 2004. In accordance with these regulations, we submitted sampling and summary reports to the Kansas Department of Health and Environment (KDHE) which indicate that the effect of the cooling water intake structure on Empire Lake's aquatic life is insignificant. KCP&L, who operates Iatan Unit 1, submitted the appropriate sampling and summary reports to the Missouri Department of Natural Resources (MDNR). In 2007 the United States Court of Appeals for the Second Circuit remanded key sections of these CWA regulations to the EPA. As a result, the EPA suspended the regulations and revised and signed a pre-publication proposed regulation on March 28, 2011 and is obligated to finalize the rule by July 27, 2012.

We will not know the full impact of these rules until they are finalized. If adopted in their present form, we expect regulations of Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) to have an impact at Riverton ranging from minor improvements to the cooling water intake structure to retirement of units 7 and 8. 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 impacted by the final rule.

We own and maintain coal ash impoundments located at our Riverton and Asbury Power Plants. Additionally, we own a 12 percent interest in a coal ash impoundment at the Iatan Generating Station and a 7.52% interest in a coal ash impoundment at Plum Point. The EPA has announced its intention to revise its wastewater effluent limitation guidelines under the CWA for coal-fired power plants sometime in 2012. 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 the coal ash impoundments are compliant with existing state and federal regulations.

On June 21, 2010, the EPA proposed a new regulation pursuant to the Federal Resource Conservation and Recovery Act (RCRA) governing the management and storage of Coal Combustion Residuals (CCR). In the proposal, the EPA presents 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. The public comment period closed in November 2010. It is anticipated that the final regulation will be published in mid to late 2012. We expect compliance with either option as proposed 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 and Riverton Power Plants. This preliminary estimate will likely change based on the final CCR rule and its requirements. We expect resulting costs to be recoverable in our rates.

On September 23, 2010 and on November 4, 2010 representatives from GEI Consultants, on behalf of the EPA, conducted on-site inspections of our Riverton and Asbury coal ash impoundments, respectively. The consultants performed a visual inspection of the impoundments to assess the structural integrity of the berms surrounding the impoundments, requested documentation related to construction of the impoundments, and reviewed recently completed engineering evaluations of the impoundments and their structural integrity. In response to the inspection comments, a qualified engineering firm has been selected to complete the recommended geotechnical studies and install new flow monitoring devices and settlement monuments at both coal ash impoundments. The project is expected to be completed by December 2012. The project will comply with all corrective measures and recommendations made by the EPA in its site assessment reports.

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 (formerly Horizon Wind Energy), Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. 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 either windfarm. More than 15% of the energy we put into the grid comes from these long-term Purchased Power Agreements (PPAs). Through these PPAs, we generate about 900,000 renewable energy certificates (RECs) each year. A REC represents one megawatt-hour of renewable energy that has been delivered into the bulk power grid and "unbundles" the renewable attributes from the associated energy. This unbundling is important because it cannot be determined where the renewable energy is ultimately delivered once it enters the bulk power grid. As a result, RECs provide an avenue for renewable energy tracking and compliance purposes.

On November 4, 2008, Missouri voters approved the Clean Energy Initiative (Proposition C). This initiative requires us 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 RECs, at the rate of at least 2% of retail sales by 2011, increasing to at least 15% by 2021. Two percent of this amount must be solar. We believe we are exempted from the solar requirement. A challenge to our exemption, brought by two of our customers and Power Source Solar, Inc., was dismissed on May 31, 2011 by the Missouri Western District Court of Appeals. The plaintiffs filed in the Missouri Supreme Court for transfer of the case from the Missouri Western District to the Missouri Supreme Court. The transfer was denied.

Renewable energy standard compliance rules were published by the MPSC on July 7, 2010. Missouri investor-owned utilities and others initiated litigation to challenge these rules. On June 30, 2011, a Cole County Circuit Court judge ruled that portions of the MPSC rules were unlawful and unreasonable, in conflict with Missouri statute and in violation of the Missouri Constitution. Subsequent to that decision, a portion of the appeal was dropped and the entire order was stayed. On December 27, 2011 the judge issued another order identical to the one that was stayed except that the rulings with regard to the constitutionality issue had been omitted. We have satisfied the current compliance requirements of the rule requiring us and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources at the rate of at least 2% of retail sales by 2011, increasing to at least 15% by 2021.

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 by 2011, 15% by 2016, and 20% by 2020. In addition, there are several proposals currently before the U.S. Congress to adopt a nationwide RPS.

We have been selling the majority of our RECs and plan to continue to sell all or a portion of them moving forward. As a result of these REC sales, we cannot claim the underlying energy is renewable. Once a REC has been claimed or retired, it cannot be used for any other purpose. At the end of 2011, sufficient RECs, including hydro, were retired to comply with the Missouri and Kansas requirements through the end of November 2011. Additional RECs will be retired in January of 2012 to complete the process for 2011. In the future, we will continue to retain a sufficient amount of RECs to meet any current or future RPS.

The acquisition of our natural gas distribution assets in June 2006 involved the potential future remediation of two former manufactured gas plant (FMGP) sites. FMGP Site #1 in Chillicothe, Missouri is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri. No remediation of this site is expected to be required in the near term. We have received a letter stating no further action is required from the MDNR with respect to FMPG Site #2 in Marshall, Missouri. We have incurred $0.2 million in remediation costs and estimate further remediation costs at these two sites to be minimal.