At March 31, 2012, the remaining weighted-average contractual term was 1.7 years. The weighted-average grant-date fair value of shares granted was $18.71 and $22.31 for the three months ended March 31, 2012 and 2011, respectively. At March 31, 2012, there was $5.2 million of total unrecognized compensation expense, net of forfeiture rates, related to performance shares granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term. There were no performance shares earned and paid for the three months ended March 31, 2012. The total fair value of performance shares earned and paid for the three months ended March 31, 2011, was $0.8 million.
Fair Value of Long-Term Debt
The fair value of long-term debt is categorized as a Level 2 liability within the fair value hierarchy as it is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices are not available. At March 31, 2012, and December 31, 2011, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, were $3.5 billion and $3.9 billion, respectively. At March 31, 2012, and December 31, 2011, the book value and fair value of KCP&L’s long-term debt, including current maturities, were $1.9 billion and $2.2 billion, respectively.
Remarketing of Great Plains Energy Equity Units Subordinated Notes
In May 2009, Great Plains Energy issued $287.5 million of Equity Units. Equity Units, each with a stated amount of $50, initially consisted of a 5% undivided beneficial interest in $1,000 principal amount of 10.00% subordinated notes due June 15, 2042, and a purchase contract requiring the holder to purchase the Company’s common stock by June 15, 2012 (the settlement date).
In March 2012, Great Plains Energy remarketed $287.4 million of its 10% subordinated notes that were originally issued as components of the Equity Units as senior notes at a new interest rate of 5.292%. The 5.292% Senior Notes mature in June 2022.
Great Plains Energy did not receive any proceeds from the remarketing. Proceeds from the remarketing were used to purchase a portfolio of U.S. Treasury securities that is pledged as collateral to secure the Equity Unit holders’ obligation under the purchase contract. There were also $0.1 million of purchase contracts that settled early and did not participate in the remarketing. On June 15, 2012, Great Plains Energy will issue to the holders of the Equity Units newly issued shares of common stock equal to the settlement rate. The settlement rate will vary according to the applicable market value of the Company’s common stock at the settlement date.
| 10. | COMMITMENTS AND CONTINGENCIES |
Environmental Matters
Great Plains Energy and KCP&L are subject to extensive federal, state and local environmental laws, regulations and permit requirements relating to air and water quality, waste management and disposal, natural resources and health and safety. In addition to imposing continuing compliance obligations and remediation costs, these laws, regulations and permits authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is expected to be material to Great Plains Energy and KCP&L. Failure to comply with environmental requirements or to timely recover environmental costs through rates could have a material effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.
The following discussion groups environmental and certain associated matters into the broad categories of air and climate change, water, solid waste and remediation.
Air and Climate Change Overview
The Clean Air Act and associated regulations enacted by the Environmental Protection Agency (EPA) form a comprehensive program to preserve air quality. States are required to establish regulations and programs to address all requirements of the Clean Air Act and have the flexibility to enact more stringent requirements. All of Great Plains Energy’s and KCP&L’s generating facilities, and certain of their other facilities, are subject to the Clean Air Act.
Great Plains Energy’s and KCP&L’s current estimate of capital expenditures (exclusive of Allowance for Funds Used During Construction (AFUDC) and property taxes) to comply with the currently-effective Clean Air Interstate Rule (CAIR), the replacement to CAIR or the Cross-State Air Pollution Rule (CSAPR), the best available retrofit technology (BART) rule, the SO2 National Ambient Air Quality Standard (NAAQS), the industrial boiler rule and the Mercury and Air Toxics Standards (MATS) rule that would reduce emissions of toxic air pollutants, (all of which are discussed below) is approximately $1 billion. The actual cost of compliance with any existing, proposed or future rules may be significantly different from the cost estimate provided.
The approximate $1 billion current estimate of capital expenditures reflects the following capital projects:
| · | KCP&L’s La Cygne No. 1 scrubber and baghouse installed by June 2015; |
| · | KCP&L’s La Cygne No. 2 full air quality control system (AQCS) installed by June 2015; |
| · | KCP&L’s Montrose No. 3 full AQCS installed by approximately 2020; and |
| · | GMO’s Sibley No. 3 scrubber and baghouse installed by approximately 2017. |
In September 2011, KCP&L commenced construction of the La Cygne project. Other capital projects at KCP&L’s Montrose Nos. 1 and 2 and GMO’s Sibley Nos. 1 and 2 and Lake Road No. 4/6 are possible but are currently considered less likely. In connection with KCP&L’s and GMO’s Integrated Resource Plan (IRP) filings with the MPSC in April 2012, the economics around Montrose No. 2 and Lake Road No. 4/6 have improved. Pending further evaluation, these projects may move from less likely to more likely but it is not expected to materially impact the overall $1 billion current estimate of capital expenditures. Any capacity and energy requirements resulting from a decision not to proceed with these less likely projects is currently expected to be met through renewable energy additions required under Missouri and Kansas renewable energy standards, demand side management programs, construction of combustion turbines and/or combined cycle units, and/or power purchase agreements.
The estimate does not reflect the non-capital costs the Companies incur on an ongoing basis to comply with environmental laws, which may increase in the future due to the Companies’ ongoing compliance with current or future environmental laws. The Companies expect to seek recovery of the costs associated with environmental requirements through rate increases; however, there can be no assurance that such rate increases would be granted. The Companies may be subject to materially adverse rate treatment in response to competitive, economic, political, legislative or regulatory pressures and/or public perception of the Companies’ environmental reputation.
Clean Air Interstate Rule (CAIR) and Cross-State Air Pollution Rule (CSAPR)
The CAIR requires reductions in SO2 and NOx emissions in 28 states, including Missouri. The reductions in SO2 and NOx emissions are accomplished through statewide caps for NOx and SO2. Great Plains Energy’s and KCP&L’s fossil fuel-fired plants located in Missouri are subject to CAIR, while their fossil fuel-fired plants in Kansas are not.
In July 2008, the D.C. Circuit Court of Appeals vacated CAIR in its entirety and remanded the matter to the EPA to promulgate a new rule consistent with its opinion. In December 2008, the court issued an order reinstating CAIR pending EPA’s development of a replacement regulation on remand.
In July 2011, the EPA finalized the CSAPR to replace the currently-effective CAIR. The CSAPR requires the states within its scope to reduce power plant SO2 and NOx emissions that contribute to ozone and fine particle nonattainment in other states. The geographical scope of the CSAPR includes Kansas, Missouri and other states. Kansas and Missouri are included in the annual SO2 and NOx programs for the control of fine particulate matter in the CSAPR. Missouri is included for ozone season NOx control but not Kansas. The EPA will address the inclusion of Kansas in a separate action and revisit Kansas’ status in the CSAPR at that time. In the CSAPR, the EPA set an emissions budget for each of the affected
states. The CSAPR allows limited interstate emissions allowance trading among power plants; however, it does not permit trading of SO2 allowances between the Companies’ Kansas and Missouri power plants. There are additional reductions in SO2 allowances allocable to the Companies’ Missouri power plants taking effect in 2014. There is no such 2014 additional reduction in SO2 allowances allocable to the Companies’ Kansas power plants. In February 2012, the EPA finalized technical adjustments to the final CSAPR. The rules amend the assurance penalty provisions, which would further restrict interstate trading of emission allowances, to start in 2014 instead of 2012. The EPA revised certain unit-level allocations in certain states, including Kansas and Missouri, which would re-allocate allowances to assist KCP&L in compliance with the CSAPR. In April 2012, the EPA indicated it has reviewed the comments submitted in response to one of the February 2012 technical adjustments and intends to withdraw it and take final action in the future.
Compliance with the CSAPR was to begin in 2012. Multiple states, utilities and other parties, including KCP&L, filed requests for reconsideration and stays with the EPA and/or the D.C. Circuit Court. In December 2011, the D.C. Circuit Court issued an order staying the CSAPR pending the Court's resolution of the petitions for review of the rule. The order requires the EPA to continue administering the CAIR while the CSAPR is stayed.
The Companies project that they may not be allocated sufficient SO2 or NOX emissions allowances to cover their currently expected operations when the rule becomes effective. Any shortfall in allocated allowances is anticipated to be addressed through a combination of permissible allowance trading, installing additional emission control equipment, changes in plant processes, or purchasing additional power in the wholesale market.
Best Available Retrofit Technology (BART) Rule
The EPA BART rule directs state air quality agencies to identify whether visibility-reducing emissions from sources subject to BART are below limits set by the state or whether retrofit measures are needed to reduce emissions. BART applies to specific eligible facilities including KCP&L’s La Cygne Nos. 1 and 2 in Kansas, KCP&L’s Iatan No. 1, in which GMO has an 18% interest, KCP&L’s Montrose No. 3 in Missouri, GMO’s Sibley Unit No. 3 and Lake Road Unit No. 6 in Missouri and Westar Energy, Inc.’s (Westar) Jeffrey Unit Nos. 1 and 2 in Kansas, in which GMO has an 8% interest. Both Missouri and Kansas have submitted BART plans to the EPA. In December 2011, the EPA issued a proposal that would approve the CSAPR as an alternative to BART. As a result, states in the CSAPR would be able to substitute participation in the CSAPR for source-specific BART. In December 2011, the EPA approved the Kansas BART plan. In February 2012, the EPA proposed a limited approval of the Missouri BART plan.
Mercury and Air Toxics Standards (MATS) Rule
In January 2009, the EPA issued a memorandum stating that new electric steam generating units (EGUs) that began construction while the Clean Air Mercury Rule (CAMR) was in effect are subject to a new source maximum achievable control technology (MACT) determination on a case-by-case basis. In July 2009, the EPA sent a letter notifying KCP&L that a MACT determination and schedule of compliance is required for coal and oil-fired EGUs that began actual construction or reconstruction after December 15, 2000, and identified Iatan No. 2 as an affected EGU. This was an outcome of the D.C. Circuit Court of Appeals’ vacatur of both the CAMR and the contemporaneously promulgated rule removing EGUs from MACT requirements. It is not currently known how the MACT determination and schedule of compliance will impact the permitting or operating requirements for Iatan No. 2, but it is possible a MACT determination may ultimately require additional emission control equipment and permit limits.
In December 2011, the EPA finalized the MATS Rule that will reduce emissions of toxic air pollutants, also known as hazardous air pollutants, from new and existing coal- and oil-fired EGUs with a capacity of greater than 25 MWs. The rule establishes numerical emission limits for mercury, particulate matter (a surrogate for non-mercury metals), and hydrochloric acid (a surrogate for acid gases). The rule establishes work practices, instead of numerical emission limits, for organic air toxics, including dioxin/furan. Compliance with the rule would need to be achieved by installing additional emission control equipment, changes in plant operation, purchasing additional power in the wholesale market or a combination of these and other alternatives. The rule allows three years for compliance with authority for state permitting authorities to grant an additional year as needed for technology installation. The EPA indicated that it expects this option to be broadly available.
Industrial Boiler Rule
In February 2011, the EPA issued a final rule that would reduce emissions of hazardous air pollutants from new and existing industrial boilers. In May 2011, the EPA announced it would stay the effective date of the final rule during reconsideration; although in January 2012, the D.C. Circuit Court vacated the stay and remanded the stay to the EPA. The EPA issued a proposed revised rule in December 2011 and intends to issue a final rule in the spring of 2012. The proposed revised rule establishes numeric emission limits for mercury, particulate matter (as a surrogate for non-mercury metals), hydrogen chloride (as a surrogate for acid gases), and carbon monoxide (as a surrogate for non-dioxin organic hazardous air pollutants). The final rule establishes emission limits for KCP&L’s and GMO’s existing units that produce steam other than for the generation of electricity. The existing boiler rule and its proposed revisions do not apply to KCP&L’s and GMO’s electricity generating boilers, but would apply to most of GMO’s Lake Road boilers, which also serve steam customers, and to auxiliary boilers at other generating facilities.
New Source Review
The Clean Air Act’s New Source Review program requires companies to obtain permits and, if necessary, install control equipment to reduce emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in regulated emissions.
In 2010, Westar settled a lawsuit filed by the Department of Justice on behalf of the EPA. The lawsuit asserted that certain projects completed at the Jeffrey Energy Center violated certain requirements of the New Source Review program. The Jeffrey Energy Center is 92% owned by Westar and operated exclusively by Westar. GMO has an 8% interest in the Jeffrey Energy Center and is generally responsible for its 8% share of the facility’s operating costs and capital expenditures. The settlement agreement required, among other things, the installation of a selective catalytic reduction (SCR) system at one of the three Jeffrey Energy Center units by the end of 2014. Westar has estimated the cost of this SCR at approximately $240 million. Depending on the NOx emission reductions attained by that SCR and attainable through the installation of other controls at the other two units, the settlement agreement may require the installation of a second SCR system on one of the other two units by the end of 2016. GMO expects to seek recovery of its share of these costs through rate increases; however, there can be no assurance that such rate increases would be granted.
KCP&L had received requests for information from the Kansas Department of Health and Environment (KDHE) pertaining to a past La Cygne No. 1 scrubber project. In April 2012, KCP&L and KDHE agreed to resolve this matter with KCP&L completing supplemental environmental projects in the amount of $800,000 and paying a penalty in the amount of $350,000.
Collaboration Agreement
In March 2007, KCP&L, the Sierra Club and the Concerned Citizens of Platte County entered into a Collaboration Agreement under which KCP&L agreed to pursue a set of initiatives including energy efficiency, additional wind generation, lower emission permit levels at its Iatan and La Cygne generating stations and other initiatives designed to offset CO2 emissions. Full implementation of the terms of the Collaboration Agreement will necessitate approval from the appropriate authorities, as some of the initiatives in the agreement require regulatory approval.
In 2006, KCP&L installed 100 MWs of wind generation at its Spearville wind site. KCP&L agreed in the Collaboration Agreement to pursue increasing its wind generation capacity to 500 MWs in total by the end of 2012, subject to regulatory approval. KCP&L and GMO have added 379 MWs of wind generation and KCP&L is evaluating options to fulfill the remaining MWs agreed to under the Collaboration Agreement.
KCP&L has a consent agreement with the KDHE incorporating limits for stack particulate matter emissions, as well as limits for NOx and SO2 emissions, at its La Cygne Station that, consistent with the Collaboration Agreement, will be below the presumptive limits under BART. KCP&L further agreed to use its best efforts to install emission control technologies to reduce those emissions from the La Cygne Station prior to the required compliance date under BART, but in no event later than June 1, 2015. In August 2011, KCC issued its order on KCP&L’s predetermination request that would apply to the recovery of costs for its 50% share of the environmental equipment required to comply with BART at the La Cygne Station. In the order, KCC stated that KCP&L’s decision to retrofit La Cygne was reasonable, reliable, efficient and prudent and the $1.23 billion cost estimate is reasonable. If the cost for the project is at or below the $1.23 billion estimate, absent a showing of fraud or other intentional imprudence, KCC stated that it will not re-evaluate the prudency of the cost of the project. If the cost of the project exceeds the $1.23 billion estimate and KCP&L seeks to recover amounts exceeding the estimate, KCP&L will bear the burden of proving that any additional costs were prudently incurred. KCP&L’s 50% share of the estimated cost is $615 million. KCP&L began the project in September 2011.
Also in the Collaboration Agreement, KCP&L agreed to offset an additional 711,000 tons of CO2 by the end of 2012, which it has done.
Climate Change
The Companies are subject to existing greenhouse gas reporting regulations and certain greenhouse gas permitting requirements. Management believes it is possible that additional federal or relevant state or local laws or regulations could be enacted to address global climate change. At the international level, while the United States is not a current party to the international Kyoto Protocol, it has agreed to undertake certain voluntary actions under the non-binding Copenhagen Accord and pursuant to subsequent international discussions relating to climate change, including the establishment of a goal to reduce greenhouse gas emissions. International agreements legally binding on the United States may be reached in the future. Such new laws or regulations could mandate new or increased requirements to control or reduce the emission of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels. The Companies’ current generation capacity is primarily coal-fired and is estimated to produce about one ton of CO2 per MWh, or approximately 25 million tons and 18 million tons per year for Great Plains Energy and KCP&L, respectively.
Laws have been passed in Missouri and Kansas, the states in which the Companies’ retail electric businesses are operated, setting renewable energy standards, and management believes that national clean or renewable energy standards are also possible. While management believes additional requirements addressing these matters will possibly be enacted, the timing, provisions and impact of such requirements, including the cost to obtain and install new equipment to achieve compliance, cannot be reasonably estimated at this time. In addition, certain federal courts have held that state and local governments and private parties have standing to bring climate change tort suits seeking company-specific emission reductions and monetary or other damages. While the Companies are not a party to any climate change tort suit, there is no assurance that such suits may not be filed in the future or as to the outcome if such suits are filed. Such requirements or litigation outcomes could have the potential for a significant financial and operational impact on Great Plains Energy and KCP&L. The Companies would likely seek recovery of capital costs and expenses for compliance through rate increases; however, there can be no assurance that such rate increases would be granted.
Legislation concerning the reduction of emissions of greenhouse gases, including CO2, is being considered at the federal and state levels. The timing and effects of any such legislation cannot be determined at this time. In the absence of new Congressional mandates, the EPA is proceeding with the regulation of greenhouse gases under the existing Clean Air Act.
In March 2012, the EPA proposed new source performance standards for emissions of CO2 for new affected fossil-fuel-fired electric utility generating units. This action pursuant to the Clean Air Act would, for the first time, set national limits on the amount of CO2 that power plants built in the future can emit. The proposal would not apply to Great Plains Energy’s and KCP&L’s existing units including modifications to those units.
At the state level, a Kansas law enacted in May 2009 required Kansas public electric utilities, including KCP&L, to have renewable energy generation capacity equal to at least 10% of their three-year average Kansas peak retail demand by 2011. The percentage increases to 15% by 2016 and 20% by 2020. A Missouri law enacted in November 2008 required at least 2% of the electricity provided by Missouri investor-owned utilities (including KCP&L and GMO) to their Missouri retail customers to come from renewable resources, including wind, solar, biomass and hydropower, by 2011, increasing to 5% in 2014, 10% in 2018, and 15% in 2021, with a small portion (estimated to be about 2MW for each of KCP&L and GMO) required to come from solar resources.
KCP&L and GMO project that they will be compliant with the Missouri renewable requirements, exclusive of the solar requirement, through 2023 for KCP&L and 2018 for GMO. KCP&L and GMO project that the purchase of solar renewable energy credits will be sufficient for compliance with the Missouri solar requirements for the foreseeable future. KCP&L also projects that it will be compliant with the Kansas renewable requirements through 2015.
Greenhouse gas legislation or regulation has the potential of having significant financial and operational impacts on Great Plains Energy and KCP&L, including the potential costs and impacts of achieving compliance with limits that may be established. However, the ultimate financial and operational consequences to Great Plains Energy and KCP&L cannot be determined until such legislation is passed and/or regulations are issued. Management will continue to monitor the progress of relevant legislation and regulations. SO2 NAAQS
In June 2010, the EPA strengthened the primary NAAQS for SO2 by establishing a new 1-hour standard at a level of 0.075 ppm and revoking the two existing primary standards of 0.140 ppm evaluated over 24 hours and 0.030 ppm evaluated over an entire year. In July 2011, the Missouri Department of Natural Resources (MDNR) recommended to the EPA that part of Jackson County, Missouri, which is in the Companies’ service territory, be designated a nonattainment area for the new 1-hour SO2 standard.
Water
The Clean Water Act and associated regulations enacted by the EPA form a comprehensive program to preserve water quality. Like the Clean Air Act, states are required to establish regulations and programs to address all requirements of the Clean Water Act, and have the flexibility to enact more stringent requirements. All of Great Plains Energy’s and KCP&L’s generating facilities, and certain of their other facilities, are subject to the Clean Water Act.
In March 2011, the EPA proposed regulations pursuant to Section 316(b) of the Clean Water Act regarding cooling water intake structures pursuant to a court approved settlement. KCP&L generation facilities with cooling water intake structures would be subject to a limit on how many fish can be killed by being pinned against intake screens (impingement) and would be required to conduct studies to determine whether and what site-specific controls, if any, would be required to reduce the number of aquatic organisms drawn into cooling water systems (entrainment). The EPA agreed to finalize the rule by July 2012. Although the impact on Great Plains Energy’s and KCP&L’s operations will not be known until after the rule is finalized, it could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.
KCP&L holds a permit from the MDNR covering water discharge from its Hawthorn Station. The permit authorizes KCP&L to, among other things, withdraw water from the Missouri river for cooling purposes and return the heated water to the Missouri river. KCP&L has applied for a renewal of this permit and the EPA has submitted an interim objection letter regarding the allowable amount of heat that can be contained in the returned water. Until this matter is resolved, KCP&L continues to operate under its current permit. KCP&L cannot predict the outcome of this matter; however, while less significant outcomes are possible, this matter may require KCP&L to reduce its generation at Hawthorn Station, install cooling towers or both, any of which could have a significant impact on KCP&L. The outcome could also affect the terms of water permit renewals at KCP&L’s Iatan Station and at GMO’s Sibley and Lake Road Stations.
Additionally, the EPA plans to revise the existing standards for water discharges from coal-fired power plants with a proposal of the rule in November 2012 and final action in April 2014. Until a rule is proposed and finalized, the financial and operational impacts to Great Plains Energy and KCP&L cannot be determined.
Solid Waste
Solid and hazardous waste generation, storage, transportation, treatment and disposal is regulated at the federal and state levels under various laws and regulations. In May 2010, the EPA proposed to regulate coal combustion residuals (CCRs) under the Resource Conservation and Recovery Act (RCRA) to address the risks from the disposal of CCRs generated from the combustion of coal at electric generating facilities. The EPA is considering two options in this proposal. Under the first option, the EPA would regulate CCRs as special wastes subject to regulation under subtitle C of RCRA (hazardous), when they are destined for disposal in landfills or surface impoundments. Under the second option, the EPA would regulate disposal of CCRs under subtitle D of RCRA (non-hazardous). The Companies use coal in generating electricity and dispose of the CCRs in both on-site facilities and facilities owned by third parties. The cost of complying with the proposed CCR rule has the potential of having a significant financial and operational impact on Great Plains Energy and KCP&L. However, the financial and operational consequences to Great Plains Energy and KCP&L cannot be determined until an option is selected by the EPA and the final regulation is enacted.
Remediation
Certain federal and state laws, including the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), hold current and previous owners or operators of contaminated facilities and persons who arranged for the disposal or treatment of hazardous substances liable for the cost of investigation and cleanup. CERCLA and other laws also authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment. GMO is named as a potentially responsible party at two disposal sites for polychlorinated biphenyl (PCB) contamination, and retains some environmental liability for several operations and investments it no longer owns. In addition, GMO also owns, or has acquired liabilities from companies that once owned or operated, former manufactured gas plant (MGP) sites, which are subject to the supervision of the EPA and various state environmental agencies.
At March 31, 2012, and December 31, 2011, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site. At March 31, 2012, and December 31, 2011, Great Plains Energy had $0.4 million accrued for environmental remediation expenses, which includes the $0.3 million at KCP&L, and additional potential remediation and ground water monitoring costs relating to two GMO sites. The amounts accrued were established on an undiscounted basis and Great Plains Energy and KCP&L do not currently have an estimated time frame over which the accrued amounts may be paid.
In addition to the $0.4 million accrual above, at March 31, 2012, and December 31, 2011, Great Plains Energy had $2.1 million accrued for the future investigation and remediation of certain additional GMO identified MGP sites, PCB contaminated sites and retained liabilities. This estimate was based upon review of the potential costs associated with conducting investigative and remedial actions at identified sites, as well as the likelihood of whether such actions will be necessary. This estimate could change materially after further investigation, and could also be affected by the actions of environmental agencies and the financial viability of other potentially responsible parties; however, given the uncertainty of these items the possible loss or range of loss in excess of the amount accrued is not estimable.
GMO has pursued recovery of remediation costs from insurance carriers and other potentially responsible parties. As a result of a settlement with an insurance carrier, approximately $2.4 million in insurance proceeds less an annual deductible is available to GMO to recover qualified MGP remediation expenses. GMO would seek recovery of additional remediation costs and expenses through rate increases; however, there can be no assurance that such rate increases would be granted.
KCP&L Spent Nuclear Fuel and Radioactive Waste
In January 2004, KCP&L and the other two Wolf Creek owners filed a lawsuit against the United States in the U.S. Court of Federal Claims seeking $14.1 million of damages resulting from the government’s failure to begin accepting spent nuclear fuel for disposal in January 1998, as the government was required to do by the Nuclear Waste Policy Act of 1982. The Wolf Creek case was tried before a U.S. Court of Federal Claims judge in June 2010 and a decision was issued in November 2010 granting KCP&L and the other two Wolf Creek owners $10.6 million ($5.0 million KCP&L share) in damages. In January 2011, KCP&L and the other two Wolf Creek owners as well as the United States filed appeals of the decision to the U.S. Court of Appeals for the Federal Circuit. Briefing to the court was completed in December 2011 and oral argument occurred in March 2012. The parties are awaiting a decision from the court.
GMO Western Energy Crisis
In response to complaints of manipulation of the California energy market, The Federal Energy Regulatory Commission (FERC) issued an order in July 2001 requiring net sellers of power in the California markets from October 2, 2000, through June 20, 2001, at prices above a FERC determined competitive market clearing price, to make refunds to net purchasers of power in the California market during that time period. Because MPS Merchant was a net purchaser of power during the refund period, it has received approximately $8 million in refunds through settlements with certain sellers of power. MPS Merchant estimates that it is entitled to approximately $12 million in additional refunds under the standards FERC has used in this case. FERC has stated that interest will be applied to the refunds but the amount of interest has not yet been determined. However, in December 2001, various parties appealed the FERC order to the United States Court of Appeals for the Ninth Circuit seeking review of a number of issues, including changing the refund period to include periods prior to October 2, 2000. MPS Merchant was a net seller of power during the period prior to October 2, 2000. On August 2, 2006, the U.S. Court of Appeals for the Ninth Circuit issued an order finding, among other things, that FERC did not provide a sufficient justification for refusing to exercise its remedial authority under the Federal Power Act to determine whether market participants violated FERC-approved tariffs during the period prior to October 2, 2000, and imposing a remedy for any such violations. The court remanded the matter to FERC for further consideration. In May 2011, FERC issued an order which clarified the scope of the hearing in the refund proceeding and ruled on requests for rehearing and motions to dismiss. An evidentiary hearing began on April 11, 2012, and is expected to conclude in May 2012. If FERC ultimately includes the period prior to October 2, 2000, MPS Merchant could be found to owe refunds.
A separate proceeding was also initiated, generally referred to as the Pacific Northwest refund proceeding, to determine if any refunds were warranted related to the potential impact of the California market issues on buyers in the Pacific Northwest between December 25, 2000, and June 20, 2001. FERC rejected the refund requests, but its decision was remanded by the Court of Appeals for FERC to consider whether any acts of market manipulation support the imposition of refunds. Claims against MPS Merchant total $5.1 million for the period addressed under the Pacific Northwest refund proceedings.
| 12. | RELATED PARTY TRANSACTIONS AND RELATIONSHIPS |
KCP&L employees manage GMO’s business and operate its facilities at cost. These costs totaled $26.2 million and $29.5 million, respectively, for the three months ended March 31, 2012 and 2011. Additionally, KCP&L and GMO engage in wholesale electricity transactions with each other. KCP&L and GMO are also authorized to participate in the Great Plains Energy money pool, an internal financing arrangement in which funds may be lent on a short-term basis to KCP&L and GMO. The following table summarizes KCP&L’s related party receivables and payables.
The fair values of Great Plains Energy’s and KCP&L’s open derivative positions are summarized in the following tables. The tables contain both derivative instruments designated as hedging instruments as well as non-hedging derivatives under GAAP. The fair values below are gross values before netting agreements and netting of cash collateral.
The following tables summarize the amount of gain (loss) recognized in OCI or earnings for interest rate and commodity hedges.
