Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

Commitments and Contingencies

Commitments and Contingencies

Note 7— Commitments and Contingencies

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 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 Plaintiff crops due to inappropriate management of the levee system around Iatan, of which we are a 12% owner. Written discovery and depositions are now underway. This matter is set for trial beginning November 7, 2011, and we are unable to predict the outcome of the law suit.

On March 12, 2010, we filed Generation Formula Rate (GFR) tariffs with the FERC which we propose to be utilized for our wholesale customers. On May 28, 2010, the FERC issued an order that conditionally approved our GFR filing subject to refund effective June 1, 2010. On June 30, 2010, three of our on-system wholesale customers were granted intervention in the GFR rate case. On September 15, 2010, the parties agreed to a settlement in principle and on May 24, 2011, we, the Missouri Public Utility Alliance and the cities of Monett, Mt. Vernon and Lockwood, Missouri filed a Settlement Agreement and Offer of Settlement with the FERC. We expect to refund approximately $1.2 million as a result of this settlement.

Coal, Natural Gas and Transportation Contracts

(in millions)	Firm physical gas and transportation contracts		Coal and coal transportation contracts
July 1, 2011 through December 31, 2011	$	24.0	$	21.2
January 1, 2012 through December 31, 2013	56.9		57.0
January 1, 2014 through December 31, 2015	29.4		36.9
January 1, 2016 and beyond	25.8		15.9

In addition to the above, we have signed 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. The minimum requirements for our coal and coal transportation contracts are detailed in the table above.

Purchased Power

We currently supplement our on-system generating capacity with purchases of capacity and energy from other utilities 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 operated by North America Energy Services near Osceola, Arkansas which met its in-service criteria on August 13, 2010. 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 $39.6 million through August 30, 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 (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 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. Although these agreements are considered operating leases under GAAP, payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in our operating lease obligations.

New Construction

We purchased 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 met its in-service criteria on August 26, 2010 and entered commercial operation on December 31, 2010. Our share of the Iatan 2 construction costs are expected to be in a range of approximately $237 million to $240 million, excluding AFUDC. Our share of the Iatan 2 costs through June 30, 2011 was $232.2 million plus AFUDC of $19.1 million. Current projections estimate $7.8 million being spent during the remainder of 2011 for our remaining share of expected expenditures for Iatan 2. These construction costs will be subject to prudency reviews by our regulators. We have requested or been granted recovery with respect to certain of these costs as set forth in the following section.

Recovery of construction costs

On September 28, 2010, we filed a rate increase request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $36.5 million, or 9.2% to recover the Iatan 2 costs and other cost of service items not included in our 2009 Missouri rate case that was effective September 10, 2010. A settlement agreement was filed on May 27, 2011, reflecting an overall annual increase in rates of $18.7 million, or approximately 4.7%. As part of the settlement, regulatory amortization expense of $14.5 million annually and construction accounting terminated as of June 15, 2011. The MPSC approved the settlement agreement on June 1, 2011 and the new rates became effective on June 15, 2011. The prudency of the construction costs for Iatan 1, Iatan 2 and Plum Point was not addressed in this case but may be considered in a future rate proceeding.

On August 30, 2010, we were granted a two-phase Capital Reliability Rider (CRR) by the Oklahoma Corporation Commission (OCC) with the first phase effective September 1, 2010. In total, the CRR revenue has been specifically limited by the OCC to an overall annual revenue increase of $2.6 million, or 27.67% increase. The CRR revenue being collected is subject to refund/true-up in the next general rate case. On June 30, 2011, we filed a request with the OCC for an annual increase in base rates for our Oklahoma electric customers (which would replace the CRR with permanent rates) in the amount of $0.6 million, or 4.1%, over the base rate and CRR revenues that are currently in effect.

A stipulated agreement in our 2009 Kansas rate case was filed on May 4, 2010, and approved by the KCC on June 25, 2010, calling for a $2.8 million, or 12.4%, increase in base rates effective July 1, 2010. We are deferring depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date of the rates from the next Kansas case, which was filed on June 17, 2011 as an abbreviated case seeking a rate increase of $1.5 million, or 6.39%. This case includes a request to recover the Iatan and Plum Point cost deferrals over a 3 year period.

On August 19, 2010, we filed a rate increase request with the Arkansas Public Service Commission (APSC) for an annual increase in base rates for our Arkansas electric customers in the amount of $3.2 million, or 27.3%. On February 2, 2011 we entered into a unanimous settlement agreement with the parties involved. The settlement includes a general rate increase of $2.1 million, or 19%. The APSC approved the settlement on April 12, 2011 with the new rates effective April 13, 2011.

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.

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

Air

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.

Permits

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

SO2 Emissions

The CAA regulates the amount of SO2 an affected unit can emit. Currently SO2 emissions are limited by the Title IV Acid Rain Program and the Clean Air Interstate Rule (CAIR). In 2012, CAIR will be replaced by the Cross-State Air Pollution Rule (CSAPR- formerly the Clean Air Transport Rule) however; the Title IV Acid Rain Program will still remain in effect.

The Power Plant Mercury and Air Toxics Standards Rule (Toxics Rule), discussed below, will become effective November 16, 2014 and will affect SO2 emission rates at our facilities. In addition, the compliance date for existing sources with the revised SO2 National Ambient Air Quality Standards (NAAQS) is August of 2017, which will also affect SO2 emissions. The SO2 NAAQS is discussed in more detail below.

Title IV Acid Rain Program:

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 allows 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 early 2012, we will need to purchase additional SO2 allowances, blend more low sulfur coal at our facilities or fuel switch to natural gas at our coal-fired Riverton Units 7 and 8. The longer term solution may be some combination of the above until a Flue Gas Desulphurization (FGD) scrubber system at our Asbury Plant can be constructed. We expect the cost of compliance to be fully recoverable in our rates.

CAIR:

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 expect to have sufficient allowances to take us up to the beginning of the CSAPR program, which replaces CAIR and is set to begin January 1, 2012 (CSAPR is discussed in more detail below).

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.

CSAPR- formerly the Clean Air Transport Rule:

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 becomes effective January 1, 2012. The final rule requires 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 will continue to be used for compliance with the Title IV Acid Rain Program. Therefore, new SO2 allowances will be allocated under CSAPR and will be retired at one allowance per ton of SO2 emissions emitted. We will receive fewer SO2 allowances than we currently emit. Compliance options range from purchasing additional emission allowances to using more low sulfur coal to installing a FGD scrubber at our Asbury facility (see estimated construction costs below) and potential forced retirement or fuel switching to natural gas of our coal-fired Riverton Units 7 and 8. We expect compliance costs to be recoverable in our rates.

Toxics Rule

Proposed by EPA on March 16, 2011 and scheduled to take effect November 16, 2011, this 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 Toxics Rule section below).

SO2 National Ambient Air Quality Standard (NAAQS):

In June 2010, the EPA finalized a new one 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. States are awaiting modeling guidance from the EPA. It is likely coal-fired generating units will need scrubbers to be capable of meeting the new one hour SO2 NAAQS.

NOx Emissions

The CAA regulates the amount of NOx an affected unit can emit. Each of our affected units is in compliance with the NOx limits applicable to it as currently operated. Currently revised NOx emissions are limited by the CAIR and will be limited by the CSAPR beginning in 2012 and ozone NAAQS rules which are scheduled to be issued by the end of 2011.

CAIR:

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 State SIPs, we had excess NOx allowances during 2010 which were banked for future use and will be sufficient for compliance through the end of the CAIR program in 2011. The CAIR NOx program will also be replaced by the CSAPR program January 1, 2012.

CSAPR:

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, options range from increasing the level of control with the Asbury SCR, fuel switching to natural gas at our Riverton Plant coal-fired units, or purchasing emission allowances. We expect the cost of compliance to be fully recoverable in our rates.

Ozone NAAQS:

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. The EPA has delayed publication of the final standards until mid-August 2011 or later. Until the EPA finalizes the proposed standard, states will continue to identify and designate all non-attainment areas based on the 2008, 75 ppb standard.

Toxics Rule

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 HAPs, including mercury. The EPA proposed the first ever national mercury and air toxics standards (Power Plant Mercury and Air Toxics Standards Rule) in March 2011. It would establish 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.

Absent a successful legal challenge or changes to applicable legislation, we expect the Toxics Rule regulation of HAPs in combination with CSAPR to ultimately require a scrubber, baghouse and powder activated carbon injection system to be added to our Asbury facility at a cost ranging from $120 million to $180 million and to force retirement of our Riverton coal-fired assets or a switch to natural gas fuel. Our Riverton coal-fired units were designed to combust either coal or natural gas. We expect compliance costs to be recoverable in our rates.

Green House Gases

Our coal and gas plants, vehicles and other facilities, including EDG (our gas segment), emit CO2 and/or other 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. We will report our GHG emissions as required to the EPA in 2011 for EDE and EDG.

On December 7, 2009, responding to a 2007 US 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.

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.

Water Discharges

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.

Surface Impoundments

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 before 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 late 2011 or in 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. We received final reports on the Asbury and the Riverton impoundments on July 28, 2011 and July 26, 2011, respectively. We are reviewing the reports and are required to respond to the reports’ recommendations by August 29, 2011.

Renewable Energy

We currently purchase more than 15% of our energy through long-term Purchased Power Agreements (PPAs) with Elk River Windfarm, LLC and Cloud County Windfarm, LLC. 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 have filed in the Missouri Supreme Court for transfer of the case from the Missouri Western District to the Missouri Supreme Court.

Renewable energy standard compliance rules were published by the MPSC on July 7, 2010.  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. We will comply with the portions of the rule left intact.

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. Over time, we expect to retain a sufficient amount of RECs to meet any current or future RPS.

Gas Segment

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.