12. ENVIRONMENTAL MATTERS

We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot always be precisely estimated.

A. HAZARDOUS AND SOLID WASTE

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the U.S. Environmental Protection Agency (EPA) to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina, the state of Florida, or potentially responsible party (PRP) groups as described below in greater detail. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses. Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of potential and pending claims cannot be predicted. A discussion of sites by legal entity follows.

The EPA and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, primarily ash, from each of the Utilities' coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. In June 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residues management and disposal as hazardous waste. The other option would have the EPA set performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residues that are recycled. A final rule is expected in 2012. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter.

We measure our liability for environmental sites based on available evidence, including our experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. For all sites, as assessments are developed and analyzed, we will accrue costs for the sites in O&M expense on the Income Statements to the extent our liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, we cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future.

The following tables contain information about accruals for probable and estimable costs related to various environmental sites, which were included in other current liabilities and other liabilities and deferred credits on the Balance Sheets:

PROGRESS ENERGY
(in millions)		MGP and Other Sites		Remediation of Distribution and Substation Transformers		Total
Balance, December 31, 2010		$	20	$	15	$	35
Amount accrued for environmental loss contingencies^(a)			-		3		3
Expenditures for environmental loss contingencies^(b)			(2)		(9)		(11)
Balance, June 30, 2011^(c)		$	18	$	9	$	27

Balance, December 31, 2009		$	22	$	20	$	42
Amount accrued for environmental loss contingencies^(a)			4		10		14
Expenditures for environmental loss contingencies^(b)			(7)		(9)		(16)
Balance, June 30, 2010^(c)		$	19	$	21	$	40

^(a)	Amounts accrued are for the six months ended June 30, 2011 and 2010. For the three months ended June 30, 2011, our accruals for environmental loss contingencies were not material. For the three months ended June 30, 2010, our accruals were $2 million for the remediation of MGP and other sites and were $8 million for the remediation of distribution and substation transformers.
^(b)	Expenditures are for the six months ended June 30, 2011 and 2010. For the three months ended June 30, 2011, our expenditures for environmental loss contingencies were not material. For the three months ended June 30, 2010, our expenditures were $5 million for the remediation of MGP and other sites and were $5 million for the remediation of distribution and substation transformers.
^(c)	Expected to be paid out over one to 15 years.

PEC
(in millions)						MGP and Other Sites
Balance, December 31, 2010						$	12
Amount accrued for environmental loss contingencies^(a)							-
Expenditures for environmental loss contingencies^(b)							-
Balance, June 30, 2011^(c)						$	12

Balance, December 31, 2009						$	13
Amount accrued for environmental loss contingencies^(a)							2
Expenditures for environmental loss contingencies^(b)							(3)
Balance, June 30, 2010^(c)						$	12

^(a)	Amounts accrued are for the six months ended June 30, 2011 and 2010. For the three months ended June 30, 2011 and 2010, PEC's accruals for the remediation of MGP and other sites were not material.
^(b)	Expenditures are for the six months ended June 30, 2011 and 2010. For the three months ended June 30, 2011 and 2010, PEC's expenditures for the remediation of MGP and other sites were not material.
^(c)	Expected to be paid out over one to five years.

PEF
(in millions)		MGP and Other Sites		Remediation of Distribution and Substation Transformers		Total
Balance, December 31, 2010		$	8	$	15	$	23
Amount accrued for environmental loss contingencies^(a)			-		3		3
Expenditures for environmental loss contingencies^(b)			(2)		(9)		(11)
Balance, June 30, 2011^(c)		$	6	$	9	$	15

Balance, December 31, 2009		$	9	$	20	$	29
Amount accrued for environmental loss contingencies^(a)			2		10		12
Expenditures for environmental loss contingencies^(b)			(4)		(9)		(13)
Balance, June 30, 2010^(c)		$	7	$	21	$	28

^(a)	Amounts accrued are for the six months ended June 30, 2011 and 2010. For the three months ended June 30, 2011, PEF's accruals for environmental loss contingencies were not material. For the three months ended June 30, 2010, PEF's accruals were $2 million for the remediation of MGP and other sites and were $8 million for the remediation of distribution and substation transformers.
^(b)	Expenditures are for the six months ended June 30, 2011 and 2010. For the three months ended June 30, 2011, PEF's expenditures for environmental loss contingencies were not material. For the three months ended June 30, 2010, PEF's expenditures were $4 million for the remediation of MGP and other sites and were $5 million for the remediation of distribution and substation transformers.
^(c)	Expected to be paid out over one to 15 years.

PROGRESS ENERGY

In addition to the Utilities' sites discussed under “PEC” and “PEF” below, we incurred indemnity obligations related to certain pre-closing liabilities of divested subsidiaries, including certain environmental matters (See discussion under Guarantees in Note 13B).

PEC

PEC has recorded a minimum estimated total remediation cost for all of its remaining MGP sites based upon its historical experience with remediation of several of its MGP sites. The maximum amount of the range for all the sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future.

In 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site in Raleigh, N.C. (Ward). The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA's past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. At June 30, 2011 and December 31, 2010, PEC's recorded liability for the site was approximately $5 million. In 2008 and 2009, PEC filed civil actions against PRPs seeking contribution for and recovery of costs incurred in remediating the Ward site, as well as a declaratory judgment that defendants are jointly and severally liable for response costs at the site. PEC has settled with a number of the PRPs and is in active settlement negotiations with others. In March 2010, the federal district court in which this matter is pending denied motions to dismiss filed by a number of defendants, but granted several other motions filed by state agencies and successor entities. The court also set a trial date for May 7, 2012. In June 2010, the court entered a case management order and discovery is proceeding. The outcome of these matters cannot be predicted.

In 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for the operable unit for further investigation at the Ward facility and certain adjacent areas (Ward OU2). The EPA's estimate for the selected remedy for Ward OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the opportunity to negotiate implementation of a response action for Ward OU1 and a remedial investigation and feasibility study for Ward OU2, as well as reimbursement to the EPA of approximately $1 million for the EPA's past expenditures in addressing conditions at the site. In 2009, PEC and several of the other participating PRPs at the Ward site submitted a letter containing a good faith response to the EPA's special notice letter. Another group of PRPs separately submitted a good faith response, which the EPA advised would be used to negotiate implementation of the required actions. The other PRPs' good faith response was subsequently withdrawn. Discussions among representatives of certain PRPs, including PEC, and the EPA are ongoing. Although a loss is considered probable, an agreement among the PRPs for these matters has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC's obligation, if any, for Ward OU1 and Ward OU2.

PEF

The accruals for PEF's MGP and other sites relate to two former MGP sites and other sites associated with PEF that have required, or are anticipated to require, investigation and/or remediation. The maximum amount of the range for all the sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future.

PEF has received approval from the FPSC for recovery through the Environmental Cost Recovery Clause (ECRC) of the majority of costs associated with the remediation of a population of distribution and substation transformers. Under agreements with the Florida Department of Environmental Protection (FDEP), PEF has reviewed these distribution transformer sites and substation sites for mineral oil-impacted soil caused by equipment integrity issues. Should additional distribution transformer sites be identified outside of this population, the distribution O&M expense will not be recoverable through the ECRC. At June 30, 2011 and December 31, 2010, PEF has recorded a regulatory asset for the probable recovery of costs through the ECRC related to the sites included under the agreement with the FDEP.

B. AIR AND WATER QUALITY

We are subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expense. These compliance laws and regulations included the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR), the North Carolina Clean Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) and mercury air regulation. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the Clean Smokestacks Act. The air quality controls installed to comply with nitrogen oxides (NOx) requirements under certain sections of the Clean Air Act and the Clean Smokestacks Act, as well as PEC's plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address the CAIR requirements for NOx for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of CAIR.

In 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) initially vacated the CAIR in its entirety and subsequently remanded the rule without vacating it for the EPA to conduct further proceedings consistent with the court's prior opinion. In 2010, the EPA published the proposed Clean Air Transport Rule, which was the regulatory program proposed to replace the CAIR. On July 7, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR) as the final version of the proposed Clean Air Transport Rule. The CSAPR replaces the CAIR effective January 1, 2012. The CSAPR contains new emissions trading programs for nitrogen oxides and sulfur dioxide (SO2) emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO2 Group 1 trading program and the SO2 Group 2 trading program. North Carolina and South Carolina are included in the NOx and SO2 annual trading programs, as well as the NOx ozone season program. North Carolina remains classified as a Group 1 state, which will require additional NOx and SO2 emission reductions beginning in January 2014. South Carolina remains classified as a Group 2 state with no additional reductions required. Florida is subject only to the NOx ozone season program. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe both PEC and PEF are relatively well positioned to comply with the CSAPR. Because of the D.C. Court of Appeals' decision that remanded the CAIR, implementation of the CAIR fulfilled best available retrofit technology (BART) for NOx and SO2 for BART-affected units under the CAVR. Under subsequent implementation of the CSAPR, CAVR compliance eventually may require consideration of NOx and SO2 emissions in addition to particulate matter emissions for BART-eligible units. We are currently evaluating the impacts of the CSAPR.

In 2008, the D.C. Court of Appeals vacated the Clean Air Mercury Rule (CAMR). As a result, the EPA subsequently announced that it will develop a maximum achievable control technology (MACT) standard. The U.S. District Court for the District of Columbia issued an order requiring the EPA to issue a final MACT standard for power plants by November 16, 2011. On March 16, 2011, the EPA issued its proposed MACT standards for coal-fired and oil-fired electric steam generating units (EGU MACT), and the proposed EGU MACT was formally published in the Federal Register on May 3, 2011. The proposed EGU MACT contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units. Following a 90-day public comment period, the EPA is scheduled to issue a final rule in November 2011. In addition, North Carolina adopted a state-specific mercury requirement. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. We are currently evaluating the impact of the EPA's proposed EGU MACT standard and the North Carolina state-specific requirement. The outcome of these matters cannot be predicted.

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at Crystal River Units No. 4 and No. 5 (CR4 and CR5), which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire Crystal River Units No. 1 and No. 2 (CR1 and CR2) as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 will be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was originally anticipated to be around 2020. As discussed in Note 4B, major construction activities for Levy are being postponed until after the NRC issues the Levy COL. As required, PEF has advised the FDEP of these developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF's compliance with environmental regulations. We cannot predict the outcome of this matter.

We account for emission allowances as inventory using the average cost method. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. The CSAPR establishes new NOx annual and seasonal ozone programs and a new SO2 trading program. NOx and SO2 emission allowances applicable to the current CAIR cannot be used to satisfy the new CSAPR programs effective January 1, 2012. At June 30, 2011 and December 31, 2010, PEC had approximately $5 million and $8 million, respectively, in SO2 emission allowances and an immaterial amount of NOx emission allowances. At June 30, 2011 and December 31, 2010, PEF had approximately $5 million in SO2 emission allowances and approximately $25 million and $28 million, respectively, in NOx emission allowances. Emission allowances are included on the Balance Sheets in inventory and in other assets and deferred debits. SO2 emission allowances will be utilized by the Utilities to comply with existing Clean Air Act requirements. PEF believes the purchases of NOx emission allowances to meet the requirements of the CAIR were prudent and expects to recover the costs of these allowances through its ECRC. We cannot predict the outcome of this matter.

Enviromental Matters Disclosure [Line Items]

Environmental Matters

12. ENVIRONMENTAL MATTERS

We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot always be precisely estimated.

A. HAZARDOUS AND SOLID WASTE

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the U.S. Environmental Protection Agency (EPA) to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina, the state of Florida, or potentially responsible party (PRP) groups as described below in greater detail. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses. Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of potential and pending claims cannot be predicted. A discussion of sites by legal entity follows.

The EPA and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, primarily ash, from each of the Utilities' coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. In June 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residues management and disposal as hazardous waste. The other option would have the EPA set performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residues that are recycled. A final rule is expected in 2012. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter.

We measure our liability for environmental sites based on available evidence, including our experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. For all sites, as assessments are developed and analyzed, we will accrue costs for the sites in O&M expense on the Income Statements to the extent our liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, we cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future.

The following tables contain information about accruals for probable and estimable costs related to various environmental sites, which were included in other current liabilities and other liabilities and deferred credits on the Balance Sheets:

PEF
(in millions)		MGP and Other Sites		Remediation of Distribution and Substation Transformers		Total
Balance, December 31, 2010		$	8	$	15	$	23
Amount accrued for environmental loss contingencies^(a)			-		3		3
Expenditures for environmental loss contingencies^(b)			(2)		(9)		(11)
Balance, June 30, 2011^(c)		$	6	$	9	$	15

Balance, December 31, 2009		$	9	$	20	$	29
Amount accrued for environmental loss contingencies^(a)			2		10		12
Expenditures for environmental loss contingencies^(b)			(4)		(9)		(13)
Balance, June 30, 2010^(c)		$	7	$	21	$	28

^(a)	Amounts accrued are for the six months ended June 30, 2011 and 2010. For the three months ended June 30, 2011, PEF's accruals for environmental loss contingencies were not material. For the three months ended June 30, 2010, PEF's accruals were $2 million for the remediation of MGP and other sites and were $8 million for the remediation of distribution and substation transformers.
^(b)	Expenditures are for the six months ended June 30, 2011 and 2010. For the three months ended June 30, 2011, PEF's expenditures for environmental loss contingencies were not material. For the three months ended June 30, 2010, PEF's expenditures were $4 million for the remediation of MGP and other sites and were $5 million for the remediation of distribution and substation transformers.
^(c)	Expected to be paid out over one to 15 years.

PEF

The accruals for PEF's MGP and other sites relate to two former MGP sites and other sites associated with PEF that have required, or are anticipated to require, investigation and/or remediation. The maximum amount of the range for all the sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future.

PEF has received approval from the FPSC for recovery through the Environmental Cost Recovery Clause (ECRC) of the majority of costs associated with the remediation of a population of distribution and substation transformers. Under agreements with the Florida Department of Environmental Protection (FDEP), PEF has reviewed these distribution transformer sites and substation sites for mineral oil-impacted soil caused by equipment integrity issues. Should additional distribution transformer sites be identified outside of this population, the distribution O&M expense will not be recoverable through the ECRC. At June 30, 2011 and December 31, 2010, PEF has recorded a regulatory asset for the probable recovery of costs through the ECRC related to the sites included under the agreement with the FDEP.

B. AIR AND WATER QUALITY

We are subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expense. These compliance laws and regulations included the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR), the North Carolina Clean Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) and mercury air regulation. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the Clean Smokestacks Act. The air quality controls installed to comply with nitrogen oxides (NOx) requirements under certain sections of the Clean Air Act and the Clean Smokestacks Act, as well as PEC's plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address the CAIR requirements for NOx for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of CAIR.

In 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) initially vacated the CAIR in its entirety and subsequently remanded the rule without vacating it for the EPA to conduct further proceedings consistent with the court's prior opinion. In 2010, the EPA published the proposed Clean Air Transport Rule, which was the regulatory program proposed to replace the CAIR. On July 7, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR) as the final version of the proposed Clean Air Transport Rule. The CSAPR replaces the CAIR effective January 1, 2012. The CSAPR contains new emissions trading programs for nitrogen oxides and sulfur dioxide (SO2) emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO2 Group 1 trading program and the SO2 Group 2 trading program. North Carolina and South Carolina are included in the NOx and SO2 annual trading programs, as well as the NOx ozone season program. North Carolina remains classified as a Group 1 state, which will require additional NOx and SO2 emission reductions beginning in January 2014. South Carolina remains classified as a Group 2 state with no additional reductions required. Florida is subject only to the NOx ozone season program. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe both PEC and PEF are relatively well positioned to comply with the CSAPR. Because of the D.C. Court of Appeals' decision that remanded the CAIR, implementation of the CAIR fulfilled best available retrofit technology (BART) for NOx and SO2 for BART-affected units under the CAVR. Under subsequent implementation of the CSAPR, CAVR compliance eventually may require consideration of NOx and SO2 emissions in addition to particulate matter emissions for BART-eligible units. We are currently evaluating the impacts of the CSAPR.

In 2008, the D.C. Court of Appeals vacated the Clean Air Mercury Rule (CAMR). As a result, the EPA subsequently announced that it will develop a maximum achievable control technology (MACT) standard. The U.S. District Court for the District of Columbia issued an order requiring the EPA to issue a final MACT standard for power plants by November 16, 2011. On March 16, 2011, the EPA issued its proposed MACT standards for coal-fired and oil-fired electric steam generating units (EGU MACT), and the proposed EGU MACT was formally published in the Federal Register on May 3, 2011. The proposed EGU MACT contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units. Following a 90-day public comment period, the EPA is scheduled to issue a final rule in November 2011. In addition, North Carolina adopted a state-specific mercury requirement. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. We are currently evaluating the impact of the EPA's proposed EGU MACT standard and the North Carolina state-specific requirement. The outcome of these matters cannot be predicted.

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at Crystal River Units No. 4 and No. 5 (CR4 and CR5), which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire Crystal River Units No. 1 and No. 2 (CR1 and CR2) as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 will be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was originally anticipated to be around 2020. As discussed in Note 4B, major construction activities for Levy are being postponed until after the NRC issues the Levy COL. As required, PEF has advised the FDEP of these developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF's compliance with environmental regulations. We cannot predict the outcome of this matter.

We account for emission allowances as inventory using the average cost method. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. The CSAPR establishes new NOx annual and seasonal ozone programs and a new SO2 trading program. NOx and SO2 emission allowances applicable to the current CAIR cannot be used to satisfy the new CSAPR programs effective January 1, 2012. At June 30, 2011 and December 31, 2010, PEC had approximately $5 million and $8 million, respectively, in SO2 emission allowances and an immaterial amount of NOx emission allowances. At June 30, 2011 and December 31, 2010, PEF had approximately $5 million in SO2 emission allowances and approximately $25 million and $28 million, respectively, in NOx emission allowances. Emission allowances are included on the Balance Sheets in inventory and in other assets and deferred debits. SO2 emission allowances will be utilized by the Utilities to comply with existing Clean Air Act requirements. PEF believes the purchases of NOx emission allowances to meet the requirements of the CAIR were prudent and expects to recover the costs of these allowances through its ECRC. We cannot predict the outcome of this matter.