Appendix H.7 

North Carolina’s Clean Smokestacks Act 

Implementation Plan
Appendix H.7 - 1
Implementation ofthe 

"Clean Smokestacks Act" 

FILED 

JUN fl 1 2007 

Clerk's Office 

N.C. Utilities Commission 

A Report to the 

Environmental Review Commission and the 

Joint Legislative Utility Review Committee 

Submitted by the North Carolina Department 

of Environment and Natural Resources and 

the North Carolina Utilities Commission 

June 1, 2007 

6*0 

(UD 

tic*— 

Appendix H.7 - 2
FILED 

JUN 01 2007 

Clerk's Office 

N.C Utilities Commission 

Implementation ofthe "Clean Smokestacks Act' 

A Report to the 

Environmental Review Commission and the 

Joint Legislative Utility Review Committee 

Submitted by the North Carolina Department of Environment and 

Natural Resources and the North Carolina Utilities Commission 

This report is submitted pursuant to the requirement of Section 14 of 

Session Law 2002-4, Senate Bill 1078 enacted June 20, 2002. The actions taken to 

date by Progress Energy Carolinas, Inc. and Duke Energy Carolinas, LLC appear 

to be in accordance with the provisions and requirements of the Clean 

Smokestacks Act. 

Signed: 

William G. Ross, Jr.TSecretary 

Department of Environment and tural Resources 

Signed: AAJ? J 

Edward S. Finleyr, Jr., Chaiim^n 

North Carolina Utilities Commission 

June 1, 2007 

Appendix H.7 - 3
Implementation ofthe "Clean Smokestacks Act" 

A Report to the 

Environmental Review Commission and the 

Joint Legislative Utility Review Committee 

June 1,2007 

The General Assembly of North Carolina, Session 2001, passed Session 

Law 2002-4, also known as Senate Bill 1078. This legislation is titled "An Act to Improve 

Air Quality in the State by Imposing Limits on the Emission of Certain Pollutants from 

Certain Facilities that Bum Coal to Generate Electricity and to Provide for Recovery by 

Electric Utilities of the Costs of Achieving Compliance with Those Limits" ("the Clean 

Smokestacks Act" or "the Act"). The Clean Smokestacks Act, in Section 14, requires 

the Department of Environment and Natural Resources ("DENR") and the 

Utilities Commission ("Commission") to report annually, i.e., by June 1 of each year, on 

the implementation of the Act to the Environmental Review Commission and the 

Joint Legislative Utility Review Committee. 

The Act, in Section 9, requires Duke Energy Carolinas, LLC ("Duke Energy"), and 

Progress Energy Carolinas, Inc. ("Progress Energy"), to submit annual reports to DENR 

and the Commission containing certain specified information. Duke Energy and 

Progress Energy filed reports, with DENR and the Commission, by cover letters dated 

March 30, 2007. Specifically, such reports were submitted in compliance with the 

requirements of G.S. 62-133.6(1). Duke Energy's and Progress Energy's reports are 

attached, and made part of this report, as Attachments A and B, respectively. 

Additionaily, by letter dated May 9, 2007, the Secretary of DENR wrote to the 

Commission stating that, pursuant to G.S. 62-133.6 (j). DENR has reviewed the 

information provided and determined that the submittals comply with the Act. The 

Secretary further stated that the plans and schedules of the Companies appear 

adequate to achieve the emission limitations set out in G.S. 143-215.107D. 

This report is presented to meet the reporting requirement of the Act pertaining to 

DENR and the Commission, as discussed above, and is submitted jointly by DENR and 

the Commission. The report is structured to address the various actions that have 

occurred pursuant to the provisions of Sections 9, 10, 11, 12, and 13 of the Act. 

Reports of actions under these Sections describe the extent of implementation of the 

Act to this date. 

Appendix H.7 - 4
I. Section 9(c) of the Act, Codified as Section 62-133.6(c) of the North 

Carolina General Statutes 

G.S. 62-133.6(c) provides: The investor-owned public utilities shall file their 

compliance plans, including initial cost estimates, with the Commission and the 

Department of Environment and Natural Resources not later than 10 days after the date 

on which this section becomes effective. The Commission shall consult with the 

Secretary of Environment and Natural Resources and shall consider the advice of the 

Secretary as to whether an investor-owned public utility's proposed compliance plan is 

adequate to achieve the emissions limitations set out in G.S. 143-215.107D. 

Status: North Carolina's investor-owned electric utilities, Progress Energy and 

Duke Energy, filed their initial compliance plans as required in June and July of 2002, 

respectively, in accordance with G.S. 62-133.6(c), Section 9(c) of Session Laws 2002-4, 

the Clean Smokestacks Act. DENR reviewed this information and determined that the 

submittals comply with the Act and, as proposed, appear adequate to achieve the 

emission limitations set out in G.S. 143-215.107D. 

II. Section 9(i) ofthe Act, Codified as Section 62-133.6(i) ofthe North Carolina 

General Statutes 

G.S. 62-133.6(i) provides: An investor-owned public utility that is subject to the 

emissions limitations set out in G.S. 143-215.107D shall submit to the Commission and 

to the Department of Environment and Natural Resources on or before 1 April of each 

year a verified statement that contains all of the following [specified information]: 

The following are the eleven subsections of G.S. 62-133.6(i) and the related 

responses from Progress Energy and Duke Energy for each subsection: 

1. G.S. 62-133.6(i)(1) requires: A detailed report on the investor-owned 

public utility's plans for meeting the emissions limitations set out in G.S. 143-215.107D. 

Progress Energy Response: "The initial plan for Progress Energy Carolinas, 

Inc. was submitted on July 29, 2002. Appendix A [of the attached Progress Energy 

submittal dated March 30, 2007, i.e., Attachment B] contains an updated version ofthis 

plan, effective April 1, 2007." 

Duke Energy Response: "Exhibits A and B [of the attached Duke submittal 

dated March 30, 2007, i.e., Attachment A, outline the updated plan as of April 1, 2007, 

for] . . . current unit specific technology selections, projected operational dates, 

expected emission rates, and the corresponding tons of emissions that demonstrate 

compliance with the legislative requirements to the best of Duke Energy Carolinas' 

knowledge at this time." 

2. G.S. 62-133.6(i)(2) requires: The actual environmental compliance 

costs incurred by the investor-owned public utility in the previous calendar year, 

including a description of the construction undertaken and completed during that year. 

Appendix H.7 - 5
Summary of Progress Energy Report: The actual environmental compliance 

costs (capital costs) incurred by Progress Energy in calendar year 2006 were 

$272.82 million. Progress Energy performed a significant amount of work at the 

Asheville and Roxboro plants. Progress Energy successfully placed the wet scrubber 

on Asheville Unit 2 into service in May 2006. Additionally, mechanical and electrical 

work for the Asheville Unit 1 selective catalytic reduction (SCR) project was completed 

in preparation for placing the SCR into service in the Spring of 2007. At the Roxboro 

plant, construction for the scrubber project continued on the four units in 2006. Specific 

unit construction activities included, but were not limited to: Unit 1 - completion of 

foundations for the absorber, recycle pump house, primary hydro cyclone tank, and 

electrical building; Unit 2 - completion ofthe recycle pump house, installation of induced 

draft fans and associated ducting, and installation of the hydro cyclone tank and 

transformers; Unit 3 - started installation of ducting from the existing stack to new 

induced draft fans, started construction of foundations for duct support steel, and 

continued installation of the absorber; Unit 4 - completed the absorber and started the 

erection of the recycle pump house and primary hydro cyclone tank. At the Lee plant, 

procurement and installation of the low-NOx burners for Unit 2 were completed in 2006. 

Also, construction activities associated with the Unit 3 Rotamix concluded. At the Mayo 

plant, engineering and design work continued in 2006 and contracts associated with the 

absorber tower and chimney were executed. At the Sutton plant, procurement and 

installation of the low-NOx burners for Unit 2 were completed in 2006. 

Summary of Duke Energy Report: The actual environmental compliance 

costs incurred by Duke Energy in calendar year 2006 were $427.98 million. Significant 

construction occurred in 2006 at the Belews Creek Steam Station. Construction of the 

major foundations and the concrete shell for the two new chimneys for the flue gas 

desulfurization (FGD) system was completed. Approximately 72% of the overall project 

was completed (54% of the construction activities) in 2006. At the Marshall Steam 

Station, tie-in of the Unit 4 absorber was completed, while initial tie-in of the Unit 3 

ductwork and installation of the blanking plate were completed in 2006. All ductwork, 

with the exception of Unit 1 and Unit 2 tie-in, was set in 2006. At Allen Steam Station, 

contracts were awarded for the stack construction and wastewater treatment system 

associated with the FGD system. Other activities included, but were not limited to: 

relocation of a transmission line; site clearing, grubbing and earthwork; relocation of an 

ash line; relocation of coal handling railroad spurs; and placing purchase orders for all 

major electrical and mechanical equipment. 

For the remaining Steam Stations (Cliffside, Buck, Dan River, and Riverbend), 

the Company reported that costs were incurred for a variety of things such as detailed 

engineering, material procurement and delivery, equipment installations, etc. 

Appendix H.7 - 6
3. G.S. 62-133.6(i)(3) requires: The amount of the investor-owned 

public utility's environmental compliance cost amortized in the previous calendar year. 

Summary of Progress Energy and Duke Energy Reports: In 2006, Progress 

Energy amortized $140 million and Duke Energy amortized $225.2 million. As indicated 

in the June 1, 2006 report to the Environmental Review Commission and the Joint 

Legislative Utility Review Committee ("the June 1,2006 report"), Progress Energy, in 

response to a data request submitted by the Commission, had projected - assuming 

certain ratable amortization - that it would amortize $87 million of environmental 

compliance costs in 2006. However, Progress Energy also noted that the Act grants 

Progress Energy the flexibility to vary the amortization schedule for 2006 and 2007 from 

$0 to $174 million per year. Also, as indicated in the June 1, 2006 report, Duke Energy, 

in response to a Commission data request, had projected that it would amortize $250 

million of environmental compliance costs in 2006. 

4. G.S. 62-133.6(i)(4) requires: An estimate of the investor-owned 

public utility's environmental compliance costs and the basis for any revisions of those 

estimates when compared to the estimates submitted during the previous year. 

Summary of Progress Energy Report: Progress Energy reported that its total 

estimated net capital costs (that is, excluding the portion for which the Power Agency is 

responsible) are currently projected to be between $1.1 billion and $1.4 billion, with the 

current point estimate being $1,355 billion, a slight decrease from the 2006 cost 

estimate of $1,362 billion. While costs of materials and labor continue to increase 

according to Progress Energy, it continues to refine the compliance strategy weighing a 

number of factors such as system load projections, expected fuel selection, available 

control equipment, anticipated performance and costs of emissions controls, and 

knowledge of and experience with emissions control options. For example, Progress 

Energy continues to evaluate the potential use of Furnace Sorbent Injection (FSI) 

technology at the Cape Fear Plant. The FSI technology may offer a more cost-effective 

compliance solution for Cape Fear than the original plan to use a wet scrubber. The 

North Carolina Division of Air Quality (DAQ) submitted an informational request to 

Progress Energy on April 25, 2007. The information requested of Progress Energy, 

among other things, concerned the evaluation of the FSI technology and whether there 

would be sufficient time to pursue alternatives to the FSI if the testing does not support 

its installation at Cape Fear. Progress Energy responded that, "if the testing at 

Robinson (SC) results in a conclusion that FSI will not be used at Cape Fear, PEC will 

have sufficient time to pursue alternatives prior to the CSA 2013 deadline." Finally, 

other more cost effective compliance solutions submitted by Progress Energy include 

the use of a dry scrubber at Sutton Unit 3 and use of Rotamix technology with 

combustion optimization at Lee Unit 3 for NOx control. 

Progress Energy's current cost estimate of $1,355 billion is $542 million, or 

67 percent, higher than the original 2002 cost estimate of $813 million. 

Appendix H.7 - 7
Summary of Duke Energy Report: Duke Energy reported that its currently 

expected costs are higher than the estimates provided in 2006. More specifically, in its 

2007 report, the Company estimated its compliance costs to be $1,965 billion, as 

compared to the $1,732 billion reflected in its 2006 report, an increase of $233 million, 

or 13 percent (detailed in Exhibit C of Attachment A of the Duke Energy report). As 

stated by Duke Energy, the reasons for this increase were: 

• Allen FGD Project - The Allen FGD estimate has increased since the 

previous 2006 filing, with this increase attributable to continued ramp up in the 

power generation and/or environmental retrofit construction market and 

continued escalation of labor and commodity costs. 

• Cliffside Unit 5 FGD Project - Like Allen, the Cliffside Unit 5 FGD estimate is 

primarily affected by labor, commodity and market escalation and thus shows 

an increase in total forecasted cost as compared to the estimate included in 

the 2006 filing. In addition, the current estimate now includes a larger portion 

of the costs associated with common FGD equipment and infrastructure 

assuming only one new Cliffside unit is built, versus assuming two new units 

are built as in the previous year's plan. 

• Selective Non-Catalytic Reduction (SCNR) & Burner Projects - While there 

has been no significant change to the scope or timing of the NOx related 

projects remaining to be installed, all ofthe current forecasts have increased 

as compared to the 2006 filing. In each case, these increases approach 10% 

as compared to prior estimates and take into account the continued 

escalation of labor costs and ramp up in the environmental retrofit 

construction market as noted for the larger projects. 

• Marshall Unit 4 SNCR Project - The Marshall Unit 4 SNCR equipment was 

installed in late 2006 at a cost significantly less than estimated in the previous 

year's plan. The decision to add the SCR technology to Marshall Unit 3 

allowed for this reduction in costs as selected SNCR equipment in service on 

Unit 3 was redeployed to Unit 4. 

Duke Energy's current cost estimate of $1,965 billion is $465 million, or 

31 percent, higher than the original 2002 cost estimate of $1.5 billion. 

5. G.S. 62-133.6(i)(5) requires: A description of all permits required in 

order to comply with the provisions of G.S. 143-215.107D for which the investor-owned 

public utility has applied and the status of those permits or permit applications. 

Summary of Progress Energy Response: 

Asheville Plant 

• Notified that air permit change for SO3 mitigation system will be treated as an 

off permit change. 

• Several erosion and sedimentation control plan updates were submitted. 

Appendix H.7 - 8
Roxboro Plant 

• Updates for air permit for coal handling and limestone handling were issued. 

• Several erosion and sedimentation control plan updates were submitted. 

• NPDES Permit - Authorization to Construct (ATC) relating to the gypsum 

settling pond and the bioreactor was received. 

Mayo Plant 

• Air permit was issued for construction of the FGD system. 

• NPDES Permit modification for wastewater system received. 

• Erosion and sedimentation control plan update was approved. 

Lee Plant 

• A prevention of significant deterioration (PSD) air permit was approved for 

installation of low NOx burners. Air permit approved for construction of the 

Rotamix System NOx control. 

• NPDES permit amendment approved for Rotamix Urea Injection System on 

Units. 

Summary of Duke Energy Response: 

Belews Creek 

• NPDES Permit modification received. 

• Landfill site suitability approved. 

• Landfill construction plan - permit received. 

• Air permit for FGD project received. 

• Authorization to Construct (ATC) application for the wastewater treatment 

system was approved. 

• Received permit to construct sanitary waste lagoon. 

• Received permit to decommission existing sewage lagoon. 

• Several soil erosion and sedimentation control plans have been approved. 

Cliffside 

• Air permit received for Unit 5 FGD. 

Marshall 

• Several soil erosion and sedimentation control plans have been approved. 

• Landfill construction plan application received - Landfill (lining) permit 

received - Permit to operate Marshall FGD landfill received. 

• Authorization to Construct (ATC) application for solids removal system was 

approved. 

• ATC application for constructed wetlands was approved. 

• Air permits received for SNCRs on Units 1-4. 

Allen 

NPDES Permit modification received. 

DENR/ACOE Permit received. 

Appendix H.7 - 9
• Air permit received for FGD and SNCRs on Units 2, 3, 4, and 5. 

• Authorization to Construct (ATC) application for the wastewater treatment 

system was approved. 

• Several soil erosion and sedimentation control permits have been received 

Riverbend 

• Air permits received for SNCRs on Units 4-7. Burner permits received for 

Units 5 and 6. 

Dan River 

• Air permits received for Burners on Units 1-3. 

Buck 

• Air permits received for Burners on Units 3 and 4 and for SNCRs on Units 5 

and 6. 

6. G.S. 62-133.6(i)(6) requires: A description of the construction 

related to compliance with the provisions of G.S. 143-215.107D that is anticipated 

during the following year. 

Summary of Progress Energy Response: See Appendix C of the attached 

letter from Progress Energy dated March 30, 2007 (Attachment B of this report) for 

details of construction and installation of equipment. The Division of Air Qualify (DAQ) 

submitted an informational request to Progress Energy on April 25, 2007. The 

information requested of Progress Energy, among other things, concerned the 

operational date of the SCR on Asheville Unit 1 and the Rotamix at Lee Unit 3. 

Progress Energy responded that "Installation of the Asheville Unit 1 SCR is being 

completed during the current outage. The unit is expected to be back on-line on or 

about May 7 (2007), and the SCR is expected to be in operation on or about 

May 10 (2007). The Lee #3 Rotamix system is online and is operating. Initial operation 

of the Rotamix system began in January 2007. Initial checkout and testing of the 

Rotamix system continued into February and March with final tuning and normal 

operation occurring in March 2007." 

Summary of Duke Energy Response: See attached letter from Duke Energy 

dated March 30, 2007 (Attachment A), for details of construction anticipated for the next 

year. 

7. G.S. 62-133.6(i)(7) requires: A description of the applications for 

permits required in order to comply with the provisions of G.S. 143-215.107D that are 

anticipated during the following year. 

Progress Energy Response: 

Asheville Plant 

Air Permit 

• "Current opacity rules pre-date saturated gas streams from wet scrubbers and 

7 

Appendix H.7 - 10
require representative measurements where condensed water vapor is not 

present. We will request revisions to the permit and underlying rules for 

opacity monitoring to include references to current federal regulations that 

exempt units with wet scrubbers from continuous opacity monitoring 

requirements." 

NPDES Permit 

• "A request for Sampling Reduction at the internal Outfall 005 (treated FGD wet 

scrubber wastewater) was submitted January 25, 2007. A response is 

expected by end of first quarter." 

Roxboro Plant 

Air Permit 

• "A permit application for the emergency fire water diesel engine was submitted 

in January 2007. Authorization to construct the fire water diesel engine has 

been received; however, the operating permit must be received to support 

operation of the Unit 2 scrubber during the second quarter 2007." 

• "Current opacity rules pre-date saturated gas streams from wet scrubbers and 

require representative measurements where condensed water vapor is not 

present. We will request revisions to the permit and underlying rules for 

opacity monitoring to include references to current federal regulations that 

exempt units with wet scrubbers from continuous opacity monitoring 

requirements." 

Mayo Plant 

NPDES Permit 

• "An ATC request for the wastewater treatment system is expected to be 

submitted in the first quarter with response desired by the end of the second 

quarter." 

• "An ATC request for a new oil/water separator is expected to be submitted by 

the end of the first quarter with response expected by the end of the third 

quarter." 

Erosion and Sedimentation Control Plan 

• "Rev F. for the increase in disturbed land (from 35 acres to 98 acres for the 

flue gas desulfurization system was submitted January 29, 2007. Additional 

plan revisions will be necessary as construction plans are developed." 

Lee Plant 

• "A Title V permit application is due to be submitted in July 2007 in accordance 

with permit requirements associated with the low-NOx burner installation." 

Duke Energy Response: 

Belews Creek Steam Station FGD 

• Permit to operate the FGD Residue Landfill - Submit certification report 

August 13, 2007, expect permit to operate by October 23, 2007. 

Appendix H.7 - 11
Cliffside Steam Station Unit 5 FGD 

• Authorization to Construct (ATC) application anticipated September 2007. 

8. G.S. 62-133.6(i)(8) requires: The results of equipment testing 

related to compliance with G.S. 143-215.107D. 

Summary of Progress Energy Response: Progress Energy conducted 

performance testing of the SO2 scrubbers at Asheville Units 1 and 2 in 2006. The 

testing confirmed the scrubbers had achieved their performance guarantee of 

97 percent removal efficiency. 

Progress Energy also tested the low-NOx burners (LNBs) at Sutton Unit 2 and 

Lee Unit 2 in 2006. The testing demonstrated that the LNBs met their respective 

performance guarantees. 

Duke Energy Response: "No additional equipment related testing occurred in 

2006." Duke Energy included SNCR and SCR tests done in prior years in the 2007 

report for reference. 

9. G.S. 62-133.6(i)(9) requires: The number of tons of oxides of 

nitrogen (NOx) and sulfur dioxide (SO2) emitted during the previous calendar year from 

the coal-fired generating units that are subject to the emissions limitations set out in 

G.S. 143-215.107D. 

Progress Energy Response: "The total calendar year 2006 emissions from 

the affected coal-fired Progress Energy units are: 

• NOx 46,501 [tons] 

• SO2 175,226 [tons]" 

Summary of Duke Energy Response: In the 2006 calendar year, the 

following were emitted from the North Carolina based Duke Energy coal-fired units: 

• NOx 54,335.5 tons 

• SO2 286,639.2 tons 

10. G.S. 62-133.6(0(10) requires: The emissions allowances described 

in G.S. 143-215.107D(i) that are acquired by the investor-owned public utility that result 

from compliance with the emissions limitations set out in G.S. 143-215.107D. 

Progress Energy Response: "During 2006, PEC did not acquire any 

allowances as a result of compliance with the emission limitations set out in N.C. 

General Statute 143-215.1070." 

Duke Energy Response: "No emissions allowances have been acquired by 

Duke Energy Carolinas resulting from compliance with the emissions limitations set out 

in G.S. 143-215.1070." 

9 

Appendix H.7 - 12
11. G.S. 62-133.6(0(11) requires: Any other information requested by 

the Commission or the Department of Environment and Natural Resources. 

Summary of DENR/DAQ Request: The DENR/DAQ submitted informational 

requests to Progress Energy and Duke Energy on April 25, 2007. The information 

requested, along with the information contained in the original March 30, 2007 

submittals from Progress Energy and Duke Energy, support DENR/DAQ's conclusion 

that the plans and schedules of the companies appear adequate to achieve the 

emission limitations set out in G.S 143-215.107D. 

The information requested on April 25, 2007, among other things, concerned: 

operational dates for control units at Progress Energy (answers outlined in Number 6 

above); plan and timing if furnace sorbent injection (FSI) testing does not support the 

FSI installation at Cape Fear (answer outlined in Number 4 above); whether plans for 

maintaining NOx emissions at or below the cap(s) consider, for example, growth in 

energy sales; and an inquiry on how year-to-year meteorological variability affects 

energy demand and thus affects production from the coal-fired units and the related 

SO2 and NOx emissions. 

Progress Energy Response: in response to the DENR/DAQ question, "What 

are your plans for maintaining NOx emissions at or below the final (2007) cap 

considering, for example, growth in energy sales," Progress Energy noted, "PEC fully 

intends to comply with the annual NOx emissions cap. Planning for NOx emissions is 

included with planning for unit generation, fuel consumption, and fuel and operations 

costs. Year-to-date actual emissions with year-end projections are continuously 

monitored and are updated weekly to ensure annual compliance. High and low cases 

(energy, outages, performance, etc.) are continuously evaluated and monitored to 

provide PEC with a range of potential scenarios in order to prepare for additional 

actions to curb emissions, if needed." 

In response to the DENR/DAQ question on how year-to-year meteorological 

variability affects energy demand and thus affects production from the coal-fired units 

and the related SO2 and NOx emissions, Progress Energy noted, "PEC's base case 

forecast uses a weather-normalized load and energy forecast. Deviations from normal 

weather conditions increase or decrease system energy demand (depending on the 

specific deviation) and thus can result in an increase or decrease in actual emissions. 

For example, a hotter than normal summer would likely result in an increase in 

emissions while a milder summer would likely result in lower emissions." 

Duke Energy Response: In response to the DENR/DAQ question, "What are 

your plans for maintaining NOx emissions at or below the final (2009) cap considering, 

for example, growth in energy sales," Duke Energy noted, "The projections above 

represent a system average capacity factor of 73%. To put this in perspective, the 

highest annual fossil system capacity factor Duke has ever achieved was 69% in 2005. 

The projection also includes a substantial amount of bulk power marketing (BPM) sales. 

If we had BPM sales at a historical high, this could increase NOx emissions in the 

10 

Appendix H.7 - 13
900 tons range to account for this load." Duke stated that they expect to have a 

comfortable compliance margin even with off system sales. 

In response to the DENR/DAQ question on how year-to-year meteorological 

variability affects energy demand and thus affects production from the coal-fired units 

and the related SO2 and NOx emissions, Duke Energy noted, "...we are planning to a 

very high system average capacity factor. Historically, we have had very hot summers 

and very cold winters but have never achieved the 73% annual CF we are currently 

planning to. 

"In developing the appropriate compliance margin multiple scenarios were 

considered that increased NOx emissions, including forced outages at the nuclear units 

and units with SCR, increase in BPM sales. Through this analysis it was determined 

that a 1,000 to 1,500 tons compliance margin was needed going into any year. Though 

we are installing the Marshal! 3 SCR for the Charlotte 8 hour ozone attainment 

demonstration, it also provides compliance margin for the North Carolina Clean 

Smokestack Act (NC CSA). 

"The total NOx emissions and how each unit is performing is trended on a weekly 

basis. If the system total NOx emissions were trending above the firm NC CSA cap, we 

would attempt to achieve lower NOx emissions from our generation stations without 

consideration of performance. We would have the option to change the dispatch of 

units, limit BPM sales and at a last resort, purchase power and shut down the highest 

emitting generation units. Our plan is not to exceed the NC CSA firm cap unless under a 

force majeure situation." 

Summary of Commission Request: The Commission submitted discovery 

requests to Progress Energy and Duke Energy on April 12, 2007. The information 

requested, among other things, concerned current projected amortization schedules 

over the remaining years ofthe seven-year accelerated cost-recovery period. 

Progress Energy Response: The Act requires Progress Energy to amortize 

$569 million, which represents 70% ofthe original cost estimate of $813 million, by the 

end of 2007. The Company indicated that $535.2 million had been amortized as of 

December 31, 2006, leaving a total of $33.8 million to be amortized during 2007. 

With regard to the amounts to be amortized in 2008 and 2009, Progress Energy 

indicated in response to the Commission's April 12, 2007 discovery request that it 

projected estimated amortization of $122 million per year for each of those two years. 

However, in a Petition filed in Docket No. E-2, Sub 900, Progress Energy, among other 

things, has requested that the Commission satisfy the requirements of G.S. 62-133.6(d) 

by allowing it to amortize a total of $244 million during calendar years 2008 and 2009, 

the result being that Progress Energy has requested the discretion to amortize up to 

$174 million in either year, as currently permitted by G.S. 62-133.6(b), according to 

Progress Energy. 

11 

Appendix H.7 - 14
Progress Energy stated that it currently has no plans to write off or amortize any 

amounts above $813 million in 2007 through 2009. Rather, Progress Energy has 

proposed that the environmental compliance costs incurred by Progress Energy in 

excess of $813 million be included in its rate base. [DENR/COMWIISSION NOTE: As 

previously indicated, Progress Energy currently estimates its total net environmental 

compliance costs to be approximately $1.355 billion.] 

Subsection (d) of G.S. 62-133.6, in pertinent part, provides as follows: 

Subject to the provisions of subsection (f) of this section, the 

Commission shall hold a hearing to review the environmental compliance 

costs set out in subsection (b) of this section. The Commission may 

modify and revise those costs as necessary to ensure that they are just, 

reasonable, and prudent based on the most recent cost information 

available and determine the annual cost recovery amounts that each 

investor-owned public utility shall be required to record and recover during 

calendar years 2008 and 2009. . . . The Commission shall issue an order 

pursuant to this subsection no later than December 31, 2007. 

Commission proceedings are currently ongoing with respect to the requirements 

of G.S. 62-133.6(d) as highlighted above. Therefore, the Commission has not yet ruled 

regarding the annual amounts of environmental compliance costs to be amortized by 

Progress Energy in 2008 and 2009. However, the Commission will do so not later than 

December 31, 2007. 

Duke Energy Response: The Act requires Duke Energy to amortize 

$1,050 billion, which represents 70% ofthe original cost estimate of $1.5 billion, by the 

end of 2007. The Company indicated that $862 million had been amortized as of 

December 31, 2006, leaving a total of $188 million to be amortized during 2007. 

With regard to the amounts to be amortized in 2008 and 2009, Duke Energy 

indicated, in response to the Commission's April 12, 2007 discovery request, that such 

amounts were to be determined in Docket No. E-7, Sub 829. That docket was initiated 

by the Commission, by Order issued March 9, 2007, for the purpose of allowing the 

Commission to comply with the provisions of G.S. 62-133.6(d) as such statutory 

provisions pertain to Duke Energy. 

Regarding Duke Energy's plan to write off or amortize any amounts above 

$1.5 billion, Duke Energy stated that it" will, no later than June 1, 2007, file testimony 

and exhibits with the Commission setting forth the information and data supporting its 

position regarding recovery of the remaining clean air compliance expenditures, that is, 

presumably, the environmental compliance costs incurred by Duke Energy in excess of 

$1.5 billion. [DENR/COMWIISSION NOTE: As previously indicated, Duke Energy 

currently estimates its total net environmental compliance costs to be approximately 

$1,965 billion.] 

12 

Appendix H.7 - 15
Commission proceedings are currently ongoing with respect to the foregoing 

matters. Therefore, the Commission has not yet ruled regarding the annua! amounts of 

environmental compliance costs to be amortized by Duke Energy in 2008 and 2009. 

However, the Commission will do so not later than December 31, 2007. 

III. Section 10 of the Act provides: It is the intent of the General Assembly that 

the State use all available resources and means, including negotiation, participation in 

interstate compacts and multistate and interagency agreements, petitions pursuant to 

42 U.S.C § 7426, and litigation to induce other states and entities, including the 

Tennessee Valley Authority, to achieve reductions in emissions of oxides of nitrogen 

(NOx) and sulfur dioxide (SO2) comparable to those required by G.S. 143-215.107D, as 

enacted by Section 1 of this act, on a comparable schedule. The State shall give 

particular attention to those states and other entities whose emissions negatively impact 

air quality in North Carolina or whose failure to achieve comparable reductions would 

place the economy of North Carolina at a competitive disadvantage. 

DENR/DAQ and Department of Justice (Attorney General) Activities to 

Implement this Section: 

The State continues to pursue opportunities to carry forward the Legislature's 

objectives in Section 10 ofthe Act. The State reports the following recent activities and 

developments: 

1) On January 30, 2006, the State, through the Attorney General, sued the 

Tennessee Valley Authority (TVA) in federal district court in Asheville. The suit alleges 

that emissions of SO2 and NOx from TVA's fleet of coal-fired power plants are 

inadequately controlled and therefore create a public nuisance. The Attorney General 

has asked the Court to require TVA to install NOx and SO2 controls to abate the public 

nuisance. In July 2006 the District Court denied TVA's motions to dismiss the case, but 

TVA has appealed these rulings to the U.S. Court of Appeals in Richmond, Virginia. 

Oral argument has not yet been scheduled and it is uncertain when the appeal will be 

decided. Meanwhile, the parties are continuing to prepare for and are on schedule for a 

trial in Asheville in October 2007. TVA has recently announced plans to install NOx and 

SO2 controls on its John Sevier plant, which is the closest TVA facility to North Carolina. 

2) On July 8, 2005, the Attorney General filed in the United States Court of Appeals 

for the District of Columbia Circuit (D.C. Circuit) a petition for review of the United States 

Environmental Protection Agency's (EPA) Clean Air Interstate Rule (CAIR). Among 

other things, the State is alleging that CAIR fails to take into account significant air 

quality problems in North Carolina, fails to guarantee a remedy to North Carolina 

because the rule relies too heavily on the trading of pollution credits, and fails to require 

controls to be installed expeditiously. The Court will likely hear arguments in this matter 

in late 2007 or early 2008. 

3) Also on July 8, 2005, the Attorney General filed a petition with the EPA 

requesting that the EPA administratively reconsider certain aspects of CAIR. EPA 

13 

Appendix H.7 - 16
denied this petition. The Attorney General has asked the D.C. Circuit to review this 

action as well, and this request will be heard along with the CAIR case.. 

4) On March 18, 2004, the State filed a petition under §126 of the Clean Air Act 

requesting that EPA impose NOx and/or SO2 controls on large coal-fired utility boilers in 

13 upwind states that impact North Carolina's air quality. On March 15, 2006, the EPA 

denied the State's petition. The Attorney General has filed a petition in the D.C. Circuit 

seeking review of the denial of the petition. The matter will likely be heard by the Court 

in early 2008. The Attorney General also petitioned EPA for administrative 

reconsideration ofthe §126 petition. 

5) Since the enactment of the Clean Smokestacks Act, the Attorney General and 

the Department of Environment and Natural Resources have on several occasions 

presented the Clean Smokestacks Act to other jurisdictions to demonstrate leadership 

and prompt similar actions in surrounding areas that impact North Carolina. On 

April 6, 2006, Governor Ehrlich of Maryland signed into law the Healthy Air Act 

(2006 Md. Laws 301) - a Clean Smokestacks-type law that significantly limits emissions 

of SO2 and NOx from large coal-fired utility boilers in Maryland. Maryland also is in the 

process of promulgating rules that will further tighten controls on large NOx and SO2 

sources. 

6) The Attorney General is also seeking a prompt resolution about whether large 

stationary sources of NOx in Georgia must comply with the summertime NOx cap under 

EPA's "NOx SIP Call" rule, which is designed to help downwind States reduce ambient 

levels of ozone. This aspect of the NOx SIP Call has been under review by EPA and 

EPA has failed to resolve the issue in a timely manner. 

IV. Section 11 of the Act provides: The Environmental Management Commission 

shall study the desirability of requiring and the feasibility of obtaining reductions in 

emissions of oxides of Nitrogen (NOx) and Sulfur Dioxide (SO2) beyond those required 

by G.S. 143-215.107D, as enacted by Section 1 of this act. The Environmental 

Management Commission shall consider the availability of emission reduction 

technologies, increased cost to consumers of electric power, reliability of electric power 

supply, actions to reduce emissions of oxides of nitrogen (NOx) and sulfur dioxide (SO2) 

taken by states and other entities whose emissions negatively impact air quality in North 

Carolina or whose failure to achieve comparable reductions would place the economy of 

North Carolina at a competitive disadvantage, and the environment, and the natural 

resources, including visibility. In its conduct of this study, the Environmental 

Management Commission may consult with the Utilities Commission and the Public 

Staff. The Environmental Management Commission shall report its findings and 

recommendations to the General Assembly and the Environmental Review Commission 

annually beginning 1 September 2005. 

Note: Session Law 2006-79 changed the beginning date of the requirements of this 

Section to September 1, 2007. 

14 

Appendix H.7 - 17
Environmental Management Commission and DENR Response: A letter 

was submitted to the Environmental Review Commission from Dr. David Moreau, 

Environmental Management Commission Chairman, dated April 3, 2006, which stated 

the following: 

Since the Clean Smokestacks Act was passed in June 2002, 

significant Federal regulatory changes have occurred. Specifically, the 

Clean Air Interstate Rule (CAIR) requires North Carolina's neighboring 

states to achieve major reductions in NOx and SO2 -- reductions that 

require installation of state-of-the-art control equipment. Although there 

may be questions about the timing and emissions reductions of CAIR, the 

Division of Air Quality (DAQ) believes CAIR will ultimately require Duke 

Energy and Progress Energy to enhance existing or add new controls that 

are consistent with the latest technology. 

The Clean Smokestacks Act already requires that state of the art 

control equipment be installed on many units in North Carolina. CAIR 

annual NOx and SO2 emissions budgets are even lower than those set by 

the Clean Smokestacks Act and this could result in even more units in 

North Carolina having state ofthe art control equipment applied. 

Given the recent action by the Federal government regarding 

power plant emissions, it is recommended that the study as to whether or 

not further State action is required be extended while evaluation is made 

of the progress of North Carolina in complying with both the clean 

Smokestacks Act and CAIR. 

The DENR/DAQ generally believes the current compliance plans 

represent a suite of state-of-the-art controls, taking into consideration both 

emissions reductions and costs of control. The Environmental 

Management Commission and DENR/DAQ will continue to evaluate 

control options through the requirements ofthis section as both the Clean 

Smokestacks Act compliance dates and the CAIR compliance dates draw 

near. 

V. Section 12 of the Act provides: The General Assembly anticipates that 

measures implemented to achieve the reductions in emissions of oxides of nitrogen 

(NOx) and sulfur dioxide (SO2) required by G.S. 143-215.107D, as enacted by Section 1 

of this act, will also result in significant reductions in the emissions of mercury from coalfired generating units. The Division of Air Quality of the Department of Environment and 

Natural Resources shall study issues related to monitoring emissions of mercury and 

the development and implementation of standards and plans to implement programs to 

control emissions of mercury from coal-fired generating units. The Division shall 

evaluate available control technologies and shall estimate the benefits and costs of 

alternative strategies to reduce emissions of mercury. The Division shall annually report 

its interim findings and recommendations to the Environmental Management 

15 

Appendix H.7 - 18
Commission and the Environmental Review Commission beginning 1 September 2003. 

The Division shall report its final findings and recommendations to the Environmental 

Management Commission and the Environmental Review Commission no later than 

1 September 2005. The costs of implementing any air quality standards and plans to 

reduce the emission of mercury from coal-fired generating units below the standards in 

effect on the date this act becomes effective, except to the extent that the emission of 

mercury is reduced as a result of the reductions in the emissions of oxides of nitrogen 

(NOx) and sulfur dioxide (SO2) required to achieve the emissions limitations set out in 

G.S. 143-215.107D, as enacted by Section 1 of this act, shall not be recoverable 

pursuant to G.S. 62-133.6, as enacted by Section 9 ofthis act. 

DAQ Actions to Implement this Section: The DAQ submitted reports in 

September of 2003, 2004, and 2005, as required by this Section. The first report 

primarily focused on the "state of knowledge" of the co-benefit of mercury control that 

will result from the control of NOx and SO2 from coal-fired utility boilers. Also, 

preliminary estimates were made for this co-benefit for North Carolina utility boilers 

based on the initial plans submitted by Progress Energy and Duke Energy. The second 

report primarily focused on "definition of options". The Division has also submitted the 

third and final report titled Mercury Emissions and Mercury Controls for Coal-Fired 

Electrical Utility Boilers. In 2006, DAQ developed a state mercury rule that goes beyond 

the federal Clean Air Mercury Rule (CAMR) that took effect in November 2006. The 

North Carolina mercury rules, contained in Section 15A NCAC 02D .2500, became 

effective January 1, 2007. The coal-fired units of Duke Energy and Progress Energy 

have two sets of independent requirements that they have to meet. First, they have to 

satisfy the requirement set out in the EPA guideline rule, which has been incorporated 

into the State's mercury regulation. This requirement is that each unit's account 

contains enough allowances at the end of the year to equal or exceed its actual 

emissions for that year. Second, these units have to meet a State-only requirement. 

This requirement is that the emissions of mercury from each coal-fired unit at Duke 

Energy and Progress Energy have to be controlled to the maximum degree that is 

technically and economically feasible or shut down by a prescribed date. Both 

requirements are independent of each other. Meeting the first requirement does not 

relieve the company from the need to meet the second requirement. However, meeting 

the second requirement, the State-only requirement, will greatly aid the companies in 

meeting the first requirement. 

VI. Section 13 of the Act provides: The Division of Air Quality of the 

Department of Environment and Natural Resources shall study issues related to the 

development and implementation of standards and plans to implement programs to 

control emissions of carbon dioxide (CO2) from coal-fired generating units and other 

stationary sources of air pollution. The Division shall evaluate available control 

technologies and shall estimate the benefits and costs of alternative strategies to 

reduce emissions of carbon dioxide (CO2). The Division shall annually report its interim 

findings and recommendations to the Environmental Management Commission and the 

Environmental Review Commission beginning 1 September 2003. The Division shall 

report its final findings and recommendations to the Environmental Management 

16 

Appendix H.7 - 19
Commission and the Environmental Review Commission no later than 

1 September 2005. The costs of implementing any air quality standards and plans to 

reduce the emission of carbon dioxide (CO2) from coal-fired generating units below the 

standards in effect on the date this act becomes effective, except to the extent that the 

emission of carbon dioxide (CO2) is reduced as a result of the reductions in the 

emissions of oxides of nitrogen (NOx) and sulfur dioxide (SO2) required to achieve the 

emissions limitations set out in G.S. 143-215.107D, as enacted by Section 1 ofthis act, 

shall not be recoverable pursuant to G.S. 62-133.6, as enacted by Section 9 ofthis act. 

DENR Actions to Implement this Section: The DAQ submitted reports in 

September of 2003, 2004, and 2005, as required by this Section. The first report 

primarily focused on the "state of knowledge" and actions being taken or planned 

elsewhere regarding CO2 control from coal-fired utility boilers. The second report 

primarily focused on "definition of options". The DAQ submitted the third and final report 

titled, "Carbon Dioxide (CO2) Emission Reduction Strategies for North Carolina", to the 

Environmental Management Commission and the Environmental Review Commission 

as required. Numerous recommendations were set forth in this report, including a 

recommendation for a North Carolina Climate Action Plan. 

The North Carolina Global Warming/Climate Change Bill (HB 1191/SB 1134) was 

enacted during the 2005 Session of the General Assembly. Along with the passage of 

the bill, the North Carolina 2005 Session of the General Assembly passed the Global 

Climate Change Act. This act established a Legislative Commission on Global Climate 

Change (LCGCC). Additionally, a formalized stakeholder group, the Climate Action 

Plan Advisory Group (CAPAG), was formed by DENR. The CAPAG's purpose is to 

evaluate, discuss, and formalize consensus-based recommendations for CO2 and other 

greenhouse gas reductions through a formal stakeholder process. Determination of 

economic benefits to North Carolina will be assessed for each prospective 

recommendation. The CAPAG will work in conjunction with the LCGCC in providing 

periodic updates. The inaugural meeting ofthe CAPAG was held on February 16, 2006. 

The CAPAG is now in the final stages of utilizing technical workgroups. These technical 

workgroups contain experts in the following five sectors: 1) Agriculture, Forestry, and 

Waste; 2) Energy Supply; 3) Transportation and Land Use; 4) Residential, Commercial, 

and Industrial; and 5) Cross Cutting (for issues that cut across different sectors, such as 

establishing a greenhouse gas registry). The CAPAG is working diligently towards a 

comprehensive North Carolina Climate Action Plan, with a current target to complete it 

by the end of 2007. 

VII. Supplementary Information: As noted in earlier reports, the Public Staff - North 

Carolina Utilities Commission (Public Staff) will audit the books and records of Progress 

Energy and Duke Energy on an ongoing basis in regard to the costs incurred and 

amortized in compliance with the provisions of the Act. The Public Staff has undertaken 

such a review, focusing on the verification of costs related to complying with the Act, the 

amortization of those costs, and the operating results of emission reduction equipment 

installed by Progress Energy and Duke Energy. 

17 

Appendix H.7 - 20
The Public Staff filed its most recent reports in the present regard with the 

Commission on May 25, 2007. (The report regarding PEC was subsequently revised on 

May 29, 2007.) Such reports, which are a continuation of the Public Staffs ongoing 

review, present an overview of certain work performed by the Public Staff and its 

findings for the 12-month period ending December 31, 2006. Attached, and made part 

of this report, are the Public Staff's reports for Duke Energy and Progress Energy, 

Attachments C and D, respectively. 

Vlll. Conclusions 

The DENR/DAQ carefully reviewed and considered the information provided by 

Progress Energy and Duke Energy in their March 30, 2007 compliance plan submittals 

and their May 2007 supplemental submittals in response to informational requests from 

DENR/DAQ on April 25, 2007. The information in the submittals, including the 

construction undertaken and completed through the past year and consideration of the 

fraction of construction remaining and permits received and applied for in the past year, 

point toward steady progress in meeting the prescribed goals of the Clean Smokestacks 

Act. DENR/DAQ staff also analyzed the emissions projections and assumptions on 

growth in energy sales. A specific analysis of the NOx emissions relative to the 2007 

cap was completed using data from the submittals along with publicly available 2006 

emissions data from USEPA's Clean Air Markets Division Web Site. Similar analysis of 

SO2 emissions will be possible in future reports as the first SO2 cap in 2009 

approaches. Additionaily, DENR/DAQ notes that, as emission controls have come 

online for both Progress Energy and Duke Energy, their ability to refine the expected 

future year emission rates for controls yet to be installed is enhanced based on 

operational performance of similar technologies already put into service. 

The Commission has also carefully reviewed and considered the information and 

data provided by the investor-owned public utilities in their 2007 Clean Smokestacks 

annual reports and in response to the Commission's discovery requests of 

April 12, 2007. Based upon such information, it appears that both Progress Energy and 

Duke Energy are on track to meet the statutorily imposed 70% accelerated amortization 

requirement during the five-year rate freeze period in the amounts of $569.1 million and 

$1,050 billion, respectively. Further, as required by the Act, the Commission has 

scheduled hearings for the purpose of (1) determining the annual cost recovery 

amounts that each investor-owned public utility shall be required to record and recover 

during calendar years 2008 and 2009; (2) reviewing the investor-owned public utilities' 

current estimates of total projected environmental compliance costs and revising such 

costs, if necessary, to ensure that they are just, reasonable, and prudent based on the 

most recent cost information available; and (3) consulting with the Secretary of DENR to 

receive advice as to whether the investor-owner public utilities' actual and proposed 

modifications and permitting and construction schedule are adequate to achieve the 

emissions limitations set out in G.S. 143-215.107D. The Commission will rule on the 

aforesaid matters not later than December 31, 2007. 

18 

Appendix H.7 - 21
In summary, it appears that the actions taken to date by Progress Energy and 

Duke Energy are in accordance with the provisions and requirements of the Clean 

Smokestacks Act. Further, the compliance plans and schedules proposed by Progress 

Energy and Duke Energy appear adequate to achieve the emissions limitations set out 

in G.S. 143-215.107D. 

19 

Appendix H.7 - 22
ATTACHMENTS 

Attachment A: Duke Energy Carolinas, LLC, Clean Smokestacks Compliance Plan 

Annual Update for 2007, Submitted by Cover Letter Dated 

March 30, 2007 

Attachment B: Progress Energy Carolinas, Inc. Annual North Carolina Clean 

Smokestacks Act Compliance Report, Submitted by Cover Letter 

Dated March 30, 2007 

Attachment C: Report of the Public Staff on Costs Incurred and Amortized by Duke 

Energy Carolinas, LLC in Compliance with Session Law 2002-4, 

Filed on May 25, 2007 

Attachment D: Report of the Public Staff on Costs Incurred and Amortized by 

Progress Energy Carolinas, Inc. in Compliance With Session 

Law 2002-4, Filed on May 25, 2007 (Revised on May 29, 2007) 

20 

Appendix H.7 - 23
f i 

ATTACHMENT A 

PAGE 1 OF 17 

nfllfr-O

 DUK E ENERG Y

 CAROLINAS, LLC 

EnerOy?

 22 5

 HiUsborough Street. Suite 160 

* * * Raleigh, NC 27603 

919 235 0995 

919 828 5240 fax 

March 30, 2007 

Ms. Renne C. Vance, Chief Clerk p | | 

North Carolina Utilities Commission 

4325 Mail Service Center 3 0 2007 

Raleigh, NC 27699-4325 ..

 Uf 

Subject: Docket No. E-7, Sub 718

 m'Ss'0n 

Duke Energy Carolinas, LLC NOx and SO2 Compliance Plan Annual Update 

Record No. NC CAP 006 

Dear Ms. Vance: 

Duke Energy Carolinas, LLC is required by Senate Bill 1078 (the "North Carolina Clean Air 

Legislation") to file infonnation on or before April 1 of each year to update the North Carolina 

Utilities Commission on ("Commission*') ofthe progress to date, upcoming activities and 

expected plans to achieve the emissions limitations set out in G.S. 143-215.107D. Enclosed for 

filing are the original and thirty (30) copies of Duke Energy Carolinas' Compliance Plan Annual 

Update for 2007 that fully describe the Company's efforts to comply with the North Carolina 

Clean Air Legislation. 

The current plan to meet the emission requirements for NOx and SO2 includes: 

NOx Control - The installation of Selective Catalytic Reduction (SCR) on Cliffside Steam 

Station Unit 5 and Belews Creek Steam Station Units 1 &2 has been completed. Our NOx 

plans continue to include the installation of Selective Non-Catalytic Reduction (SNCR) on 15 

units and burner work at our remaining smaller units with the exception of Cliffside Units 1 -

4. With these installations, the company can demonstrate compliance with the 2007 and 

2009 NOx caps under Senate Bill 1078. 

SO2 Control - The installation of wet scrubbers on our twelve largest generating units 

continues to be our plan for compliance with the 2009 and 2013 SO2 caps under the North 

Carolina Clean Air Legislation. The company continues to work under an accelerated 

schedule with respect to the Allen scrubber project to maintain design and construction 

continuity throughout the scrubber program and also assure compliance with the federal 

Clean Air Interstate Rule. Estimated costs for the scrubber projects at Cliffside Unit 5 and 

Plant Allen continue to rise due to escalation of labor and commodity prices as well as the 

continued run up of costs in the power generation and environmental retrofit construction 

market. 

www. duke-energy, com 

Appendix H.7 - 24
ATTACHMENT A 

PAGE 2 OF 17 

Exhibits A and B outline current unit specific technology selections, projected operational dates, 

expected emission rates, and the corresponding tons of emissions that demonstrate compliance 

with the legislative requirements to the best of Duke Energy Carolinas' knowledge at this time. 

The current estimate of Environmental Compliance Costs for these pollution control projects are 

included in Exhibit C. 

Duke Energy Carolinas will continue to examine the technology selection, implementation 

schedule and associated costs. Annual updates will be provided to the Commission as required. 

If you have questions regarding any aspect of our plan, please do not hesitate to contact my 

office at 919-235-0955. 

Sincerely, 

A 

George T. Everett, Ph.D. 

Director, Environmental/Legislative Affairs 

Duke Energy Carolinas 

Enclosures 

cc: Robert P. Gruber 

Executive Director - Public Staff 

4326 Mail Service Center 

Raleigh, NC 27699-4326 

Appendix H.7 - 25
ATTACHMENT A 

PAGE 3 OF 17 

VERIFICATION 

I, C^&^t.A^ i outA^C'

 5 state and attest that the attached information 

updating the North Carolina Utilities Commission on progress to date, upcoming activities, 

and expected strategies to achieve the emissions limitations set out in N.C.G.S. 143-

215.107.D (Annual Update) is filed on behalf of Duke Energy Carolinas, LLC; that I have 

reviewed said Annual Update and, in the exercise of due diligence, have made reasonable 

inquiry into the accuracy ofthe information provided therein; and that, to the best of my 

knowledge, information, and belief, all of the information contained therein is accurate and 

true, and no material information or fact has been knowing omitted or misstated therein. 

qdorge T. Everett, Ph.D. 

Director, Environmental and Legislative Affairs 

l)ate 

Subscribed and sworn before me this the 3® day of Algfc> QsC~-- ,2007 

• • • /^ AA? > 

Notary Public \ \ / / 

My commission expires 3 / ^ / 2. £>£> ff ^-^P^S- ^ 

Appendix H.7 - 26
ATTACHMENT A 

PAGE 4 OF 17 

Duke Energy Carolinas. LLC 

General Assembly of North Carolina Session 2001 

Senate Bill 1078 - Improve Air Quality/Electric Utilities (NC Clean Air Legislation) 

2007 Annual Data Submittal 

1. A detailed report on the investor-owned public utility's plans for meeting the emissions 

limitations set out in G.S. 143-215.107D. 

Exhibits A and B outline the plan as of this date for technology selections by facility and unit, 

projected operational dates, expected emission rates, and the corresponding tons of emissions that 

demonstrate compliance with the provisions of G.S. 143-215.107D. Changes to the expected plan 

for meeting these emissions limitations as compared to past compliance plans are described below: 

NOx Compliance 

• Emission Rate Changes - Expected rates have been adjusted in this 2007 update 

based on 2006 operational performance: 

• Emission rates for the Allen units were adjusted based on 2006 ozone season 

performance of the Units 1, 3 & 4 SNCR equipment. Expected rates were 

increased by 0.01 for Units 1 & 2 and 0.02 for Units 3,4 & 5. 

• The Belews Creek Unit 1 expected rate was increased by 0.01 based on 2006 

operational results. 

• The Buck Units 3 & 4 expected rates in 2009 were increased by 0.01 based on 

operation of the similar Dan River Unit 2 with new Separated Over-fired Air 

(SOFA) burner equipment in early 2007. The Buck Unit 3 expected rate in 

2007 was decreased by 0.02 based on the timing ofthe SOFA installation. 

• The Buck Units 5 & 6 expected rates were increased by 0.02 based on the 

early 2007 performance of the recently installed SNCR equipment. 

• Cliffside Units 1 - 4 expected rates were changed based on 2006 performance. 

• The Dan River Units 1 & 2 expected rates were increased slightly based on 

operations of the SOFA equipment on Unit 2 in early 2007. 

• The Marshall Units 1 - 4 expected rates were increased by 0.01 based on 

operation in 2006 and the effect on baseline NOx of the coals used with the 

scrubber. 

• The 2009 expected rate for Marshall Unit 3 was decreased significantly based 

on the expected addition of SCR equipment. This SCR addition is expected to 

be operational in 2009 primarily in support of the 8-hour ozone attainment 

demonstration for the Charlotte region. Increased mercury removal in support 

of the federal Clean Air Mercury Rule (CAMR) and improved ability to support 

existing NOx emission limitations are added benefits associated with this 

project. Similar to other SCR additions attributed primarily to compliance with 

regulations other than the North Carolina Clean Air Legislation, costs 

associated with this Marshall Unit 3 SCR project are not "environmental 

compliance costs" within the meaning of that term as used in the North 

Carolina Clean Air Legislation. 

• The Riverbend Units 4- 7 expected rates were changed based on 2006 and 

early 2007 operational results. 

Appendix H.7 - 27
ATTACHMENT A 

PAGE 5 OF 17 

SO? Compliance 

• New Pulverized Coal (PC) Unit - This 2007 update assumes the addition of one 

new 800 MW coal unit at the Cliffside Steam Station. The 2013 expected 

compliance plan includes this unit along with the corresponding retirement of 

Cliffside Units 1-4. 

• Schedule Changes - Optimization of the 2009 scrubber tie-in outages for the Allen 

Units 1 - 5 has resulted in some minor changes to the expected emission rates for 

the 2009 year. 

• Emission Rate Changes - Expected rate changes have been adjusted in this 2007 

update for the Buck and Cliffside stations: 

• The Buck Units 3- 6 expected rates were increased. These new rates 

assume that the use of lower sulfur Colombian coal is discontinued given that it 

is not cost competitive in the current market. Forecasted prices for this coal do 

not currently provide a cost effective solution as compared to domestic options. 

• The Cliffside Units 1 - 5 rates were adjusted based on the expected sulfur 

content in the coal. 

2. The actual environmental compliance costs incurred by the investor-owned public utility in 

the previous calendar year, including a description of the construction undertaken and 

completed during that year. 

In the 2006 calendar year, Duke Energy Carolinas spent $427,984,400 on activities in support of 

compliance with the provisions of G.S. 143-215.107D. Exact amounts associated with each project 

are provided in Exhibit C, and a description of the associated activities is provided below: 

Allen Steam Station FGD 

• Provided Limited Notice to Proceed (LNTP) to EPC Contractor 4/3/06 

• Provided Full Notice to Proceed (FNTP) to EPC Contractor 8/31/06 

• Awarded Wastewater Treatment engineering contract 3/1/06 

• Awarded Wastewater Treatment construction contract 12/22/06 

• Awarded Stack construction contract 5/16/06 

• Completed relocation of 230kV Transmission Line 8/1/06 

• Started site clearing, grubbing and earthwork 

• Completed relocation of ash line 12/22/06 

• Completed relocation of coat handling railroad spurs 11/29/06 

• Placed purchase orders for all major electrical and mechanical equipment 

Belews Creek Steam Station FGD 

• Completed construction of the major foundations for the FGD System 

• Completed construction of the concrete shell for the two new chimneys 

• Completed 95% of construction for the Constructed Wetlands (part of the waste 

water treatment system) 

• Achieved a completion status of 72% on the overall project (54% of construction 

activities) 

Appendix H.7 - 28
ATTACHMENT A 

PAGE 6 OF 17 

Cliffside Steam Station Unit 5 FGD 

• Continued preliminary construction planning and development of conceptual site 

layout 

Marshall Steam Station FGD 

• Completed tie-in of the Unit 4 Absorber; began initial operations of Unit 4 and 

common equipment on 10/30/06; achieved substantial completion on 12/20/06 

• Completed initial tie-in of the Unit 3 ductwork and installation of blanking plate 

• Completed setting all ductwork with the exception of Unit 1 and Unit 2 tie-in 

sections 

• Completed lining of FGD gypsum landfill 

• Completed engineered wetlands installation 

• Completed Unit 4 CEMS RATA testing and certification 

• Completed NSPS testing of material handling systems per air permit 

Allen Steam Station SNCR. Unit 2 

• Completed detailed engineering 

• Completed procurement, installation and commissioning associated with the site's 

reagent storage equipment 

Allen Steam Station SNCR, Unit 3 

• Completed remaining small close-out activities 

Allen Steam Station SNCR, Unit 4 

• Completed material delivery and installation of the Unit 4 SNCR equipment 

including supporting plant air and dilution water equipment 

Allen Steam Station SNCR. Unit 5 

• No significant activity completed in 2006 

Buck Steam Station Burners. Unit 3 

• Completed detailed engineering and material procurement in preparation for 2007 

installation 

Buck Steam Station Burners, Unit 4 

• Completed detailed engineering and material procurement in preparation for 2007 

installation 

Buck Steam Station SNCR, Unit 5 

• Completed detailed engineering 

• Completed material delivery and installation of the Unit 5 SNCR equipment 

including plant air, dilution water and reagent storage equipment required for SNCR 

operation 

Buck Steam Station SNCR, Unit 6 

• Completed detailed engineering, material delivery and installation of the Unit 6 

SNCR equipment 

Appendix H.7 - 29
ATTACHMENT A 

PAGE 7 OF 17 

Dan River Steam Station Burners. Unit 2 

• Completed installation of burners in fall of 2006 

Dan River Steam Station Burners. Unit 3 

• Completed installation of burners in fall of 2006 

Marshall Steam Station SNCR. Unit 1 

• Completed installation ofthe Unit 1 SNCR equipment 

Marshall Steam Station SNCR, Unit 2 

• Completed material procurement and delivery in preparation for 2007 installation 

• Completed procurement, installation and commissioning associated with the site's 

reagent storage equipment 

Marshall Steam Station SNCR, Unit 3 

• Completed remaining small close-out activities 

Marshall Steam Station SNCR. Unit 4 

• Completed detailed engineering, material procurement and delivery, and 

installation of the Unit 4 SNCR equipment 

Riverbend Steam Station SNCR. Unit 4 

• Completed detailed engineering, material procurement and delivery in preparation 

for 2007 installation 

Riverbend Steam Station SNCR. Unit 5 

• Completed detailed engineering, material procurement and delivery in preparation 

for 2007 installation 

Riverbend Steam Station SNCR. Unit 6 

• Completed detailed engineering, material procurement and delivery, and 

installation ofthe Unit 6 SNCR equipment 

• Completed procurement, installation and commissioning associated with the site's 

reagent storage equipment 

Riverbend Steam Station SNCR. Unit 7 

• Completed detailed engineering, material procurement and delivery, and 

installation ofthe Unit 7 SNCR equipment 

• Completed installation of plant air and dilution water equipment required for SNCR 

operation 

Appendix H.7 - 30
ATTACHMENT A 

PAGE 8 OF 17 

3. The amount of the investor-owned public utility's environmental compliance costs amortized 

in the previous calendar year. 

In the 2006 calendar year, $225,236,000 was amortized related to construction work activity in 

support of compliance with the provisions of G.S. 143-215.107D. $862,665,143 has now been 

amortized in total for the program through year-end 2006. 

4. An estimate of the investor-owned public utility's environmental compliance costs and the 

basis for any revisions of those estimates when compared to the estimates submitted during 

the previous year. 

The estimated 'environmental compliance costs' as defined in G.S. 143-215.107D are provided in 

Exhibit C. Changes to the expected costs as compared to past compliance plans are described 

below: 

• Allen FGD Project - The Allen FGD estimate has increased since the previous 

2006 filing and is attributable to continued ramp up in the power generation and/or 

environmental retrofit construction market, and continued escalation of labor and 

commodity costs. 

• Cliffside Unit 5 FGD Project - Like Allen, the Cliffside 5 FGD estimate is primarily 

affected by labor, commodity and market escalation and thus shows an increase in 

total forecasted cost as compared to the estimate included in the 2006 filing. In 

addition, the current estimate now includes a larger portion of the costs associated 

with common FGD equipment and infrastructure assuming only one new Cliffside 

unit is built, versus assuming two new units are built as in the previous year's plan. 

• SNCR & Burner Projects - While there has been no significant change to the scope 

or timing of the NOx related projects remaining to be installed, all of the current 

forecasts have increased as compared to the 2006 filing. In each case, these 

increases approach 10% as compared to prior estimates and take into account the 

continued escalation of labor costs and ramp up in the environmental retrofit 

construction market as noted for the larger projects. 

• Marshall Unit 4 SNCR Project - The Marshall Unit 4 SNCR equipment was 

installed in late 2006 at a cost significantly less than estimated in the previous 

year's plan. The decision to add the SCR technology to Marshall Unit 3 allowed for 

this reduction in costs as selected SNCR equipment in service on Unit 3 was 

redeployed to Unit 4. 

5. A description of all permits required in order to comply with the provisions of G.S. 143-

215.107D for which the investor-owned public utility has applied and the status of those 

permits or permit applications. 

Allen Steam Station FGD 

• Request to revise NPDES Permit to include FGD wastewater - Submitted 1 /24/06; 

received revision 9/11/06 

• Submittal to DENR/ACOE regarding stream crossing of entrance road - Received 

permits 5/25/06 

• Air Permit Application - Submitted 4/10/06; received Permit 6/30/06 

Appendix H.7 - 31
ATTACHMENT A 

PAGE 9 OF 17 

• Authorization to Construct (ATC) application for Wastewater Treatment System -

Submitted 9/14/06; received Permit to Construct 12/15/06 

• NOTE: all erosion control permits are in EPC contractor's scope for the Allen FGD 

Project and were received in 2006 (7/13/06 and 12/18/06). EPC contractor has 

also applied for air permit associated with flue liner fabrication on 11/1/06 and 

expects to receive permit in early 2007. 

Belews Creek Steam Station FGD 

• Request to revise NPDES Permit to include FGD wastewater - Submitted 6/30/04; 

received Permit Revision 5/16/05 

• Initial Erosion Control Permit - Submitted 2/4/05; received Permit 3/7/05 

• Landfill Site Suitability Application - Submitted 3/30/05; received Site Suitability 

Approval Letter 6/19/06 

• Air Permit Application for Belews Creek FGD project - Submitted 4/18/05; received 

Air Permit 2/6/06 

• Authorization to Construct (ATC) application for Wastewater Treatment System -

Submitted 7/21/05; received Permit to Construct 12/27/05 

• Authorization to Construct (ATC) appiication for Constructed Wetlands - Submitted 

7/21/05; received Permit to Construct 12/27/05 

• Revised Landfill Construction Plan Application - Submitted 9/30/05; received 

Permit to Construct 6/29/06 

• Air Permit - Notice of Intent to Construct - Submitted 10/11/05; received Permit to 

Construct 10/24/05 

• Authorization to Construct Sanitary Waste Lagoon - Submitted 3/23/06; received 

Permit to Construct 9/1/06 

• Existing Sewage Lagoon Approval to Decommission - Submitted 10/31/06; 

received permit 1/25/07 

• NOTE: Revisions to Erosion Control Permit submitted on various dates; most 

recent revised permit received 3/30/06 

Cliffside Steam Station Unit 5 FGD 

• Air Permit Application - Submitted 12/16/05; received 12/15/06 

Marshall Steam Station FGD 

• Landfill Construction Plan Application - Submitted 4/1/04; received 2/4/05 

• Sedimentation and Erosion Control Plan Permits 

• Limestone/Gypsum Conveyor - Submitted 6/17/04; received 7/9/04 

• Limestone/Gypsum Conveyor Expansion - Submitted 12/15/04; received 

12/30/04 

• Constructed Wetland Treatment System - Submitted 7/26/04; received 8/18/04 

• Gypsum Landfill - Submitted 3/31/04; received 4/21/04 

• Authorization to Construct (ATC) application for Solids Removal System -

Submitted 11/19/04; received 12/22/04 

• Authorization to Construct (ATC) application for Constructed Wetlands - Submitted 

5/21/04; received 8/10/04 

Appendix H.7 - 32
ATTACHMENT A 

PAGE 10 OF 17 

• Air Permit Revisions (for material handling issues) - Submitted 9/2/05; received 

12/7/05 

• Landfill Permit Documents (to line landfill) - Submitted 12/15/05; received 6/5/06 

• Permit to Operate Marshall FGD Landfill - Submitted 10/27/06; received 11/21/06 

Allen Steam Station SNCR. Unit 2 

• Air Permit Application - Submitted 4/24/06; Received 6/30/06 

Allen Steam Station SNCR. Unit 3 

• Air Permit Application - Submitted 7/15/04; Received 2/5/05 

Allen Steam Station SNCR. Unit 4 

• Air Permit Application - Submitted 7/15/05; Received 1/15/06 

• Building/Plumbing permit from Gaston County Building and Standards - Received 

4/27/06 for municipal water tie-ins 

Allen Steam Station SNCR. Units 

• Air Permit Application - Submitted 4/24/06; Received 6/30/06 

Buck Steam Station Burners. Unit 3 

• Air Permit Application - Submitted 9/15/06; Received 2/15/07 

Buck Steam Station Burners. Unit 4 

• Air Permit Application-Submitted 9/15/06; Received 2/15/07 

Buck Steam Station SNCR. Unit 5 

• Air Permit Application - Submitted 3/10/06; Received 5/16/06 

Buck Steam Station SNCR. Unit 6 

• Air Permit Application - Submitted 3/10/06; Received 5/16/06 

Dan River Steam Station Burners. Unit 1 

• Air Permit Application - Submitted 2/23/06; Received 9/11/06 

Dan River Steam Station Burners. Unit 2 

• Air Permit Application - Submitted 2/23/06; Received 9/11/06 

Dan River Steam Station Burners. Unit 3 

• Air Permit Application - Submitted 2/23/06; Received 9/11/06 

Marshall Steam Station SNCR, Unit 1 

• Air Permit Application - Submitted 9/18/05; Received 12/20/05 

Marshall Steam Station SNCR. Unit 2 

• Air Permit Application - Submitted 9/18/05; Received 12/20/05 

Appendix H.7 - 33
ATTACHMENT A 

PAGE 11 OF 17 

Marshall Steam Station SNCR. Unit 3 

• Air Permit Application - Submitted 5/14/04; Received 10/13/04 

Marshall Steam Station SNCR. Unit 4 

• Air Permit Application - Submitted 4/28/06; Received 9/12/06 

Riverbend Steam Station SNCR. Unit 4 

• Air Permit Application - Submitted 3/20/05; Received 8/1/05 

Riverbend Steam Station Burners, Unit 5 

• Air Permit Application - Submitted 4/2/04; Received 4/30/04 

Riverbend Steam Station SNCR. Unit 5 

• Air Permit Application - Submitted 3/20/05; Received 8/1/05 

Riverbend Steam Station Burners. Unit 6 

• Air Permit Application - Submitted 5/14/03; Received September 2003 

Riverbend Steam Station SNCR. Unit 6 

• Air Permit Application - Submitted 11/5/05; Received 1/1/06 

Riverbend Steam Station SNCR. Unit 7 

• Air Permit Application - Submitted 11/5/05; Received 1/1/06 

6. A description of the construction related to compliance with the provisions of G.S. 143-

215.107D that is anticipated during the following year. 

Allen Steam Station FGD 

• Complete relocation of fuel oil tank and transfer system 

• Complete construction of stack shell 

• Complete construction of new access driveway 

• Complete all major building foundations and steel erection 

• Complete initial duct tie-in outages for Units 1-5 

• Complete all major equipment foundations 

• Mobilize FRP liner fabrication facility 

• Complete major process equipment procurement 

• Receive auxiliary transformer on site 

Belews Creek Steam Station FGD 

• Complete construction and commissioning of all FGD Systems 

• Place new Sanitary Waste System into operation 

• Achieve Unit 1 FGD Substantial Completion - Expect in February 2008 

Cliffside Steam Station Unit 5 FGD 

• Complete clearing and grubbing required to begin FGD construction 

• Begin earthwork excavation, blasting and hauling activities 

Appendix H.7 - 34
ATTACHMENT A 

PAGE 12 OF 17 

Begin structural/foundation work for FGD equipment 

Complete Unit 5 chimney foundation 

Marshall Steam Station FGD 

Complete construction, turnover and commissioning of Unit 3 FGD systems 

Complete final tie-in of Unit 3 ductwork; remove blanking plate; and begin 

operations, testing and tuning of Unit 3 FGD systems 

Achieve substantial completion for Unit 3 

Complete construction, turnover and commissioning of Unit 1/2 FGD systems 

Complete final tie-in of Unit 2 ductwork and begin operations, testing and tuning of 

Unit 1/2 FGD systems 

Complete final tie-in of Unit 1 ductwork 

Achieve Substantial Completion for Unit 1/2 

Achieve Marshall FGD Project Completion 

Allen Steam Station SNCR, Unit 2 

• Complete material procurement, installation and commissioning of SNCR 

equipment in time to support operation in summer 2007 

Allen Steam Station SNCR. Unit 5 

• Complete detailed engineering and material procurement activities 

• Begin equipment installation activities in support of a 2008 project completion date 

Buck Steam Station Burners. Unit 3 

• Complete installation of burners in early 2007 

Buck Steam Station Classifiers. Unit 3 

• Complete installation of classifiers in early 2007 

Buck Steam Station Burners. Unit 4 

• Complete installation of burners in early 2007 

Buck Steam Station Classifiers. Unit 4 

• Complete installation of classifiers in early 2007 

Dan River Steam Station Burners. Unit 1 

• Complete detailed engineering and material procurement activities 

• Complete installation of burners in late 2007 

Dan River Steam Station Classifiers. Unit 1 

• Complete installation of classifiers in late 2007 

Marshall Steam Station SNCR. Unit 2 

• Complete installation and commissioning of SNCR equipment in preparation for 

operation in summer 2007 

Appendix H.7 - 35
ATTACHMENT A 

PAGE 13 OF 17 

Riverbend Steam Station SNCR, Unit 4 

• Complete installation and commissioning of SNCR equipment in preparation for 

operation in summer 2007 

Riverbend Steam Station SNCR, Unit 5 

• Complete installation and commissioning of SNCR equipment in late 2007 

Riverbend Steam Statbn SNCR. Unit 6 

• Complete commissioning and small project close-out activities 

Riverbend Steam Station SNCR. Unit 7 

• Complete commissioning and small project close-out activities 

7. A description of the applications for permits required in order to comply with the provisions 

of G.S. 143-215.107D that are anticipated during the following year. 

Belews Creek Steam Station FGD 

• Permit to operate the FGD Residue Landfill - Submit Certification Report 8/13/07, 

Expect permit to operate by 10/23/07 

Cliffside Steam Station Unit 5 FGD 

• Authorization to Construct (ATC) application anticipated September 2007 

8. The results of equipment testing related to compliance with G.S. 143-215.107D. 

No additional equipment related testing occurred in 2006. The SNCR and SCR tests that occurred in 

prior years that were used in evaluating technology selections are repeated in this 2007 report for 

reference. 

Allen Steam Station SNCR. Unit 1 

• SNCR Equipment installation was completed in May 2003 followed by equipment 

acceptance testing in late 2003. During this test run, it was determined that the 

SNCR system met all commercial performance guarantees with approximately a 

25% reduction in NOx with ammonia slip of less than 5 ppm at full load. 

• During the 2004 ozone season, Allen Unit 1 achieved a 0.162# NOx/MMBTU outlet 

rate, 5% better than the 0.17#/MMBTU target established for the unit. 

Belews Creek Steam Station SCR 

• SCR Equipment installation was completed in 2003 in support of the EPA/SIP Call 

requirements for NOx reduction. While Belews Creek had operational problems in 

the first half of the 2004 ozone season, many of these issues were addressed on 

Belews Creek Unit 1 by August, 2004. Subsequently, tests performed during the 

months of August and September showed that when the SCR Equipment was in 

service during this time, emissions averaged 0,07# NOx/MMBTU 

Appendix H.7 - 36
ATTACHMENT A 

PAGE 14 OF 17 

9. The number of tons of oxides of nitrogen (NOx) and sulfur dioxide (SO2) emitted during the 

previous calendar year from the coat-fired generating units that are subject to the emissions 

limitations set out in G.S. 143-215.107D. 

In the 2006 calendar year, 54,335.5 tons of NOx and 286,639.2 tons of SO2 were emitted from the 

North Carolina based Duke Energy Carolinas coal-fired units located in North Carolina and subject 

to the emissions limitations set out in G.S 143-215.107D. 

10. The emissions allowances described in G.S. 143-215.107D(i) that are acquired by the 

investor-owned public utility that result from compliance with the emissions limitations set 

outinG.S.143-215.107D. 

No emissions allowances have been acquired by Duke Energy Carolinas resulting from compliance 

with the emissions limitations set out in G.S. 143-215.107D. 

11. Any other information requested by the Commission or Department of Environment and 

Natural Resources. 

No additional information has been requested to be included in this annual data submittal. 

Appendix H.7 - 37
ATTACHMENT A 

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Appendix H.7 - 40
O Progress Energy 

ATTACHMENT B 

PAGE 1 OF 20 

I L E 

March 30. 2007 MA R 3 fl 200 7 

Clerk's Office 

N.C. Utilities Commission 

Ms. Renne Vance 

Chief Clerk 

North Carolina Utilities Commission 

4325 Mail Service Center 

Raleigh, NC 27699-4325 

Re: Annual NC Clean Smokestacks Act Compliance Report 

DocketNo.E-2, Sub815 

Dear Ms. Vance: 

Progress Energy Carolinas, Inc. submits the attached report for calendar year 

2006 regarding the status of compliance with the provisions of the North Carolina Clean 

Smokestacks Act. Section 9(i) of the Act requires that an annual report of compliance 

progress be submitted to the Commission by April 1 of each year for the previous 

calendar year. 

Very truly yours, 

Len S. Anthony 

Deputy General Counsel-Regulatory Affairs 

LSA:mhm 

Attachment 

232822 

Progress Energy Service Company, LLC 

Haieigh, NC m m 

Appendix H.7 - 41
ATTACHMENT B 

PAGE 2 OF 20 

C ^ Progress Energy 

March 30, 2007 

Mr. William G. Ross, Jr. 

Secretary 

North Carolina Department of Environment and Natural Resources 

1601 Mail Service Center 

Raleigh, NC 27699-1601 

Dear Sec ^jJi 

Progress Energy Carolinas, Inc. (PEC, Company) submits the attached report for calendar 

year 2006 regarding the compliance status with the provisions of the North Carolina Clean 

Smokestacks Act (Act). 

As you know, 2007 is a significant year for the Clean Smokestacks Act - the first year in 

which the nitrogen oxides (NOx) emissions cap is effective. Beginning this year, the 

Company's annual NOx emissions from its coal units in North Carolina cannot exceed 

25,000 tons. We have developed plans and processes to assure we meet the requirement, 

and we are on track to achieve this milestone. 

While the Act established stringent NOx and sulfur dioxide (SO2) emissions limits from 

coal-fired power plants, it also allowed the affected utilities to determine how to meet the 

emissions limitations. We regularly review and refine our compliance strategy, weighing 

a number of factors such as system load projections, expected fuel selection, available 

control equipment, and anticipated performance and costs of emissions controls. For 

example, since our last filing, we have continued our evaluation of Furnace Sorbent 

Injection (FSI) technology. FSI may offer a more cost-effective compliance solution for 

our Cape Fear Plant than the original plan to use scrubbers. We plan to test the FSI 

technology at our Robinson Plant in Florence, S.C., in fall 2007. Since Robinson Unit 1 is 

similar in design to the Cape Fear units, we believe that the FSI test will indicate whether 

this technology will be effective at Cape Fear. We are happy to provide you and your 

staff more detail about our plans and the test results. 

Progress Energy Service Company, LLC 

I'.O Box ifiSl 

Huleiyli, NC 'm m 

Appendix H.7 - 42
ATTACHMENT B 

PAGE 3 OF 20 

We appreciate the excellent work of the Department staff, particularly those in the Air 

Quality and Water Quality divisions, who support our efforts to complete the projects in a 

timely manner to assure compliance with the Act's requirements. We look forward to 

continuing our positive working relationship to facilitate fulfillment ofthe Company's 

obligations with this important law. 

Please don't hesitate to contact me at (919) 546-3775 if you have any questions. 

Sincerely, 

Caroline Choi 

Director, Energy Policy and Strategy 

c: North Carolina Utilities Commission 

Keith Overcash, DAQ 

Alan Klimek, DWQ 

Appendix H.7 - 43
ATTACHMENT B 

PAGE 4 OF 20 

VERIFICATION 

STATE OF NORTH CAROLINA ) 

) 

COUNTY OF WAKE ) 

NOW, BEFORE ME, the undersigned, personally came and appeared, 

E. Michael Williams, who first duly sworn by me, did depose and say: 

That he is E. Michael Williams, Senior Vice President-Power 

Operations of Carolina Power & Light Company, d/b/a Progress Energy 

Carolinas, Inc.; he has the authority to verify the foregoing Progress Energy 

Carolinas, Inc. North Carolina Clean Smokestacks Act Calendar Year 2006 

Progress Report; that he has read said Report and knows the contents 

thereof; are true and correct to the best of his knowledge and beliefs. 

E. Michael Williams 

Senior Vice President-Power Operations 

Progress Energy Carolinas, Inc. 

Subscribed and sworn to me 

thist^da y of March, 2007. 

Notary Ptftblic 

0 &^&&^5';c2-0D% 

>«> , *fa 

NOTARY 

PUBLIC 

- # • ^C0UH^ X N ^ 

'////MllW ^ 

246373 

Appendix H.7 - 44
ATTACHMENT B 

PAGE 5 OF 20 

Progress Energy Carolinas, Inc. (PEC) 

North Carolina Clean Smokestacks Act 

Calendar Year 2006 Progress Report 

On June 20, 2002, North Carolina Senate Bill 1078, also known as the "Clean 

Smokestacks Act," was signed into effect. This law requires significant reductions in the 

emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2) from utility owned coalfired power plants located in North Carolina. Section 9(1), which is now incorporated as 

Section 62-133.6(1) ofthe North Carolina General Statutes, requires that an annual 

progress report regarding compliance with the Clean Smokestacks Act be submitted on or 

before April 1 of each year. The report must contain the following elements, taken 

verbatim from the statute: 

1. A detailed report on the investor-owned public utility's plans for meeting the 

emissions limitations set out in G.S. 143-215.107D. 

2. The actual environmental compliance costs incurred by the investor-owned public 

utility in the previous calendar year, including a description ofthe construction 

undertaken and completed that year. 

3. The amount ofthe investor-owned public utility's environmental compliance 

costs amortized in the previous calendar year. 

4. An estimate ofthe investor-owned public utility's environmental compliance 

costs and the basis for any revisions of those estimates when compared to the 

estimates submitted during the previous year. 

5. A description of all permits required in order to comply with the provisions of 

G.S. 143-215.107D for which the investor-owned public utility has applied and 

the status of those permits or permit applications. 

6. A description ofthe construction related to compliance with the provisions of 

G.S. 143-215.107D that is anticipated during the following year. 

7. A description ofthe applications for permits required in order to comply with the 

provisions of G.S. 143-215.107D that are anticipated during the following year. 

8. The results of equipment testing related to compliance with G.S. 143-215.107D. 

9. The number of tons of oxides of nitrogen (NOx) and sulfur dioxide (SO2) emitted 

during the previous calendar year from the coal-fired generating units that are 

subject to the emissions limitations set out in G.S. 143-215.107D. 

10. The emissions allowances described in G.S. 143-215.107D(i) that are acquired by 

the investor-owned public utility that result from compliance with the emissions 

limitations set out in G.S. 143-215.107D. 

11. Any other information requested by the Commission or the Department of 

Environment and Natural Resources. 

Infonnation responsive to each of these report elements follows. The responses are given 

by item number in the order in which they are presented above. 

Appendix H.7 - 45
ATTACHMENT B 

PAGE 6 OF 20 

1. A detailed report on the investor-owned public utility's plans for meeting the 

emissions limitations set out in G.S. 143-215.107D. 

Under G.S. § 143-215.107D(f), "each investor-owned public utility. ..may determine how 

it will achieve the collective emissions limitations imposed by this section." PEC 

originally submitted its compliance plan on July 29, 2002. Appendix A contains an 

updated version ofthis plan, effective April 1, 2007. We continue to evaluate various 

design, technology and generation options that could affect our future compliance plans. 

2. The actual environmental compliance costs incurred by the investor-owned 

public utility in the previous calendar year, including a description ofthe 

construction undertaken and completed that year. 

In 2006, Progress Energy Carolinas, Inc. incurred actual capital costs of $272,819,000. 

Asheville 

We successfully placed in service the wet scrubber on Asheville Unit 2 in May 2006. A 

significant amount of work was performed at the Asheville plant in 2005 and 2006 in 

order to accomplish this milestone. This work included the installation of electrical power 

and control cables and circuits, piping, pumps, valves, oxidation air compressors, 

instruments and controls, agitators, absorber tower outlet hood, spray headers, trays and 

other tower internals. Work efforts also included completing ductwork from the 

precipitator to the scrubber tower and from the scrubber tower to the stack. The stack 

liner was connected in 2006. Mechanical and electrical work for the Unit 1 SCR was 

completed in preparation for placing the SCR into service in spring 2007. 

Lee 

We completed procurement and installation ofthe low-NOx burners for Unit 2, placing 

them in service in 2006. We also completed design, procurement and installation ofthe 

Rotamix equipment for NOx control at Unit 3. Construction activities related to Unit 3 

Rotamix concluded in 2006, with operational status expected in early 2007. 

Mayo 

Contracts for the absorber tower and chimney were executed, along with contracts for the 

overall engineering and construction. Engineering and design work continued throughout 

the year, and in mid-October contractors mobilized and began construction activities. 

Long-lead procurement activities continued in order to ensure timely receipt of 

equipment on-site in support of a spring 2009 in-service date. During the fourth quarter 

of 2006, on-site activities focused on excavation and backfill ofthe scrubber island area, 

installation of rebar, and placement of base slabs for the auxiliary and startup 

transformers and bus supports. 

Appendix H.7 - 46
ATTACHMENT B 

PAGE 7 OF 20 

Roxboro 

Construction work for the scrubber project continued on the four units in 2006. In the 

Common area, installation ofthe pipe bridge was completed as well as installation ofthe 

equipment in the limestone prep building and gypsum dewatering building. The 

limestone unloading pit was completed, and work was started on installation of 

conveyors. The limestone slurry storage tanks, vacuum filter feed tanks, filtrate tanks, 

service water tanks, blow-down tank, and emergency storage tank were completed as 

well as the electrical equipment building and the oxidation air blower building. 

Commissioning began on most ofthe common systems in support ofthe Unit 2 outage 

scheduled for spring 2007. Specific unit construction activities completed include the 

following: 

Unitl 

Significant construction included completion of foundations forthe absorber, recycle 

pump house, primary hydro cyclone tank, and electrical building. 

Unit 2 

Significant construction included completion of the'recycle pump house, final assembly 

ofthe absorber discharge to the stack, installation ofthe induced draft fans and associated 

flue gas ducting, installation ofthe hydro cyclone tank, and installation ofthe 

transformers. In addition, we started commissioning Unit 2 systems in preparation for the 

spring 2007 outage during which time the final scrubber tie-in will be completed and the 

scrubber placed into service. 

Unit 3 

Significant construction included starting installation of ducting from the existing stack to 

the new induced draft fans. Construction was started on foundations for duct support steel 

from the new induced draft fans to the absorber. We continued installation ofthe 

absorber and started assembly ofthe booster fan. Work also started on fabrication ofthe 

new flue gas ducting. 

Unit 4 

Significant construction included completion ofthe absorber and the start of erection of 

the recycle pump house and primary hydro cyclone tank. 

Wastewater Project 

Significant construction activity included starting the wastewater settlement and flush 

ponds which are scheduled for completion in early 2007. In December, we issued a 

request for bids on construction ofthe bioreactor facilities. 

Sutton 

We completed procurement and installation ofthe low-NOx burners for Unit 2 and 

placed them in service during 2006. 

Appendix H.7 - 47
ATTACHMENT B 

PAGE 8 OF 20 

3. The amount ofthe investor-owned public utility's environmental compliance 

costs amortized in the previous calendar year. 

Progress Energy Carolinas, Inc. amortized $140 million in 2006. 

4. An estimate ofthe investor-owned public utility's environmental compliance 

costs and the basis for any revisions of those estimates when compared to the 

estimates submitted during the previous year. 

Appendix B contains the capital costs incurred toward compliance with G.S. § 143-

215.107D through 2006 and the projected costs for future years through 2013. The costs 

shown are the net costs to PEC, excluding the portion for which the Power Agency is 

responsible. The estimated total capital costs, including escalation, are currently projected 

to be between $1.1 and $1.4 billion. The current point estimate is $1,355 billion, a slight 

decrease from the 2006 cost estimate of $1,362 billion. Prior reports have discussed the 

cost impact of project scope changes and the impact of significant increases in the cost of 

materials and labor which have impacted construction projects across the Southeast. 

These factors continued to impact the cost ofthe projects during 2006 as indicated by the 

current estimates for Roxboro, Mayo, and Sutton. 

The current estimates also reflect updates to PEC's compliance plan based on the 

expected performance ofthe scrubbers at Asheville, Roxboro, and Mayo, current 

resource plans, current fuel forecasts, and advancements in SO2 removal technology. 

Under G.S. § 143-215.107D(f), "each investor-owned public utility...may detennine how 

it will achieve the collective emissions limitations imposed by this section." We regularly 

review and refine our compliance strategy, weighing a number of factors such as system 

load projections, expected fuel selection, available control equipment, anticipated 

performance and costs of emissions controls, and knowledge of and experience with 

emissions control options. 

For example, since our last filing, PEC has continued its evaluation ofthe potential to use 

Furnace Sorbent Injection (FSI) technology at our Cape Fear Plant. FSI technology may 

offer a more cost-effective compliance solution for Cape Fear Plant than the original plan 

to use scrubber technology. Use ofthe FSI technology also eliminates the need for a 

costly wastewater treatment system. We plan to test the FSI technology at PEC's 

Robinson Unit 1 in fall 2007. Since Robinson Unit 1 is similar in design to the Cape Fear 

units, the Robinson test will indicate whether the use ofthis technology will be effective 

at Cape Fear. 

The current compliance plan also contemplates the use of a dry scrubber at Sutton Unit 3. 

A dry scrubber at that unit represents a more cost effective compliance solution and also 

eliminates the need for a costly wastewater treatment system. 

Lastly, the compliance plan calls for the use of Rotamix technology with combustion 

optimization at Lee 3 for NOx control. Prior plans had contemplated the use of rotating 

opposed-fired air (ROFA) and Rotamix technology at that unit. Engineering studies 

Appendix H.7 - 48
ATTACHMENT B 

PAGE 9 OF 20 

completed in early 2006 indicated that combustion optimization combined with the 

existing Low-NOx burners with overfired-air would provide benefits equivalent to the 

ROFA and at less cost. 

5. A description of all permits required in order to comply with the provisions of 

G.S. 143-215.107D for which the investor-owned public utility has applied and the 

status of those permits or permit applications. 

Progress Energy Carolinas, Inc. applied for the following permits in 2006: 

Asheville Plant 

Air Permit 

• Notification of 502(b)(10) permit change for SO3 mitigation system submitted 

April 5, 2006. Notification that the permit change will be treated as an "off permit 

change" rather than a 502(b)(10) received June 30, 2006. 

Erosion and Sedimentation Control Plan 

• Several updates were submitted. Rev J for the construction ofthe de-mineralized 

pipe, pump and duct bank was approved in January 2006. 

Roxboro Plant 

Air Permit 

• An update for coal handling and limestone handling was issued on February 9, 

2006. An additional update was requested on November 10, 2006. The revised air 

permit incorporating this revision was issued on March 15, 2007. 

• Revisions to address fugitive emissions of hydrogen sulfide from the wastewater 

treatment system were approved June 23, 2006. 

NPDES Permit 

• An Authorization to Construct (ATC) for the gypsum settling pond was received 

March 3, 2006. 

• An ATC for the bioreactor was received July 5, 2006. 

Erosion and Sedimentation Control Plan 

Several updates were submitted: 

• Rev K for the haul road, transformer, main plant area wastewater pipe trench and 

gypsum conveyor foundations was submitted January 18, 2006, and approved 

February 10,2006. 

• Rev L for burying the wastewater pipeline was submitted April 19, 2006, and 

approved May 2, 2006. 

• Rev M for increased disturbed areas for wastewater pond construction borrow and 

stockpile area, construction parking area, and construction road widening was 

submitted June 7, 2006, and approved June 26, 2006. 

Appendix H.7 - 49
ATTACHMENT B 

PAGE 10 OF 20 

Mavo Plant 

Air Permit 

• Construction permit application for the flue gas desulfurization system was 

submitted May 25, 2006, and the permit was issued July 28, 2006. 

NPDES Permit 

• Permit modification for wastewater treatment system was received September 14, 

2006. 

Erosion and Sediment Control Plan 

• Rev D for the installation ofthe flue gas desulfurization system was approved 

November 9, 2006. 

Lee Plant 

Air Permil 

• A prevention of significant deterioration (PSD) permit for the installation of low 

NOx burners was approved March 21, 2006. 

• Construction permit application for the installation ofthe Rotamix System for 

NOx control was submitted April 5, 2006, and was approved June 30, 2006. 

NPDES Permit 

• A permit application amendment for the Rotamix Urea Injection System on Unit 3 

was submitted May 15, 2006. A revised amendment was then submitted October 

24, 2006, and approved December 18, 2006. 

6. A description of the construction related to compliance with the provisions of 

G.S. 143-215.107D that is anticipated during the following year. 

Asheville 

Construction activities will continue in 2007 for the Asheville Unit 1 SCR. Construction 

activities related to installation of electrical power, control cables and circuits, piping, 

instruments and controls will occur. Installation ofthe additional urea-to-ammonia 

system modifications for Unit 1 SCR is planned. The Unit 1 SCR is scheduled to be 

operational in spring 2007. 

Lee 

For Unit 3, we will complete tuning ofthe Rotamix equipment for NOx emissions control 

and place the system in service in early 2007. 

Appendix H.7 - 50
ATTACHMENT B 

PAGE 11 OF 20 

Mavo 

During 2007, construction activities will focus on completion ofthe chimney and 

absorber foundations and subsequent erection ofthe absorber and chimney structures. 

Concurrently, equipment such as pumps, ball mills, induced draft fans, and conveyors 

will begin to arrive on-site. In support of major equipment installation, numerous 

foundations will be placed during 2007 including foundations for the recycle pump 

house, limestone prep and dewatering buildings. Engineering activities will continue 

during 2007, with the focus during the latter half of the year shifting from scrubber to 

wastewater treatment process flows and equipment. 

Roxboro 

For 2007, significant construction activities planned in the Common area include 

completion ofthe limestone conveyors. Specific unit activities are described below: 

Unitl 

Significant construction activities planned include construction of Unit 1 absorber, 

electrical building, primary hydro-cyclone tank, recycle pump house, and induced draft 

fan foundations. 

Unit 2 

Significant activities planned include completion of commissioning and startup activities 

to support the tie-in ofthe new flue gas duct to the absorber. The scrubber will be placed 

in service in spring 2007. 

Unit 3 

Significant construction activities planned include completing the installation ofthe 

booster fans, final assembly of flue gas duct from the existing stack to the absorber, and 

the start of duct insulation. Additionally, work on the foundation for the recycle pump 

house will start in spring 2007. The expected start-up ofthe scrubber is spring 2008. 

Unit 4 

Significant construction activities planned include completion ofthe absorber internals, 

installation of all equipment associated with the recycle pump house, and installation of 

booster fans and associated flue gas ducting from the existing stack to the absorber. 

Commissioning of Unit 4 equipment in support of scrubber start-up planned for fall 2007 

will be completed as well. 

Wastewater 

Significant construction activities planned for wastewater include completion ofthe 

wastewater settlement and flush ponds, construction and commissioning ofthe bioreactor 

facilities, and completion ofthe wastewater piping from the plant. 

Appendix H.7 - 51
ATTACHMENT B 

PAGE 12 OF 20 

7, A description ofthe applications for permits required in order to comply with 

the provisions of G.S. 143-215.107D that are anticipated during the following 

year. 

We appreciate the collaborative efforts the DAQ and DWQ staff has made to assure our 

construction and installation schedules remain on track. However, the potential for longer 

permit processing times continues to be a serious concern for future projects. PEC wishes 

to work collaboratively with the Department to prevent delays from occurring. 

The following permit applications and permit approvals are anticipated for 2007: 

Asheville Plant 

Air Permit 

• Current opacity rules pre-date saturated gas streams from wet scrubbers and 

require representative measurements where condensed water vapor is not present. 

We will request revisions to the permit and underlying rules for opacity 

monitoring to include references to current federal regulations that exempt units 

with wet scrubbers from continuous opacity monitoring requirements. 

NPDES Permit 

• A request for Sampling Reduction at the internal Outfall 005 (treated FGD wet 

scrubber wastewater) was submitted January 25, 2007. A response is expected by 

end of first quarter. 

Roxboro Plant 

Air Permit 

• A pennit application for the emergency fire water diesel engine was submitted in 

January 2007. Authorization to construct the fire water diesel engine has been 

received; however, the operating permit must be received to support operation of 

the Unit 2 scrubber during the second quarter 2007. 

• Current opacity rules pre-date saturated gas streams from wet scrubbers and 

require representative measurements where condensed water vapor is not present. 

We will request revisions to the permit and underlying rules for opacity 

monitoring to include references to current federal regulations that exempt units 

with wet scrubbers from continuous opacity monitoring requirements. 

Mavo Plant 

NPDES Permit 

• An ATC request for the wastewater treatment system is expected to be submitted 

in the first quarter with response desired by the end ofthe second quarter. 

• An ATC request for a new oil/water separator is expected to be submitted by the 

end ofthe first quarter with response expected by the end ofthe third quarter. 

Appendix H.7 - 52
ATTACHMENT B 

PAGE 13 OF 20 

Erosion and Sedimentation Control Plan 

• Rev F. for the increase in disturbed land (from 35 acres to 98 acres) for the flue 

gas desulfurization system was submitted January 29, 2007. Additional plan 

revisions will be necessary as construction plans are developed. 

Lee Plant 

Air Permit 

• A Title V permit application is due to be submitted in July 2007 in accordance 

with permit requirements associated with the low-NOx burner installation. 

8. The results of equipment testing related to compliance with G.S. 143-215.107D. 

During 2006, performance testing ofthe SO2 scrubbers at Asheville Units 1 and 2 was 

completed. The testing confirmed that the scrubbers had achieved their performance 

guarantee of 97% removal efficiency. 

During 2006, performance testing ofthe low-NOx burners (LNBs) at Sutton Unit 2 and 

Lee Unit 2 was completed. The testing demonstrated that the LNBs met their respective 

performance guarantees. 

9. The number of tons of oxides of nitrogen (NOx) and sulfur dioxide (SO2) emitted 

during the previous calendar year from the coal-fired generating units that are 

subject to the emissions limitations set out in G.S. I43-215.107D. 

The total calendar year 2006 emissions from the affected coal-fired Progress Energy 

Carolinas units are: 

NOx 46,501 tons 

SO2 175,226 tons 

10. The emissions allowances described in G.S. 143-215.107D(i) that are acquired by 

the investor-owned public utility that result from compliance with the emissions 

limitations set out in G.S. 143-215.107D. 

During 2006, PEC did not acquire any allowances as a result of compliance with the 

emission limitations set out in N.C. General Statute 143-215.107D. 

11. Any other information requested by the Commission or the Department of 

Environment and Natural Resources. 

There have been no additional requests for information from the North Carolina Utilities 

Commission or the Department of Environment and Natural Resources since the last 

report. 

Appendix H.7 - 53
ATTACHMENT B 

PAGE 14 OF 20 

Appendix A 

Progress Energy Carolinas, Inc's (PEC) Air Quality Improvement Plan Supplement 

April 1, 2007 

On June 20, 2002, Governor Easley signed into law SB 1078, which caps emissions of 

nitrogen oxides (NOx) and sulfur dioxide (SO2) from utility owned coal-fired power 

plants located in North Carolina. Under the law, G.S. § 143-215.107D, PEC's annual 

NOx emissions must not exceed 25,000 tons beginning in 2007 and annual SO2 emissions 

must not exceed 100,000 tons beginning in 2009 and 50,000 tons beginning in 2013. 

These caps represent a 56% reduction in NOx emissions from 2001 levels and a 74% 

reduction in SO2 emissions from 2001 levels for PEC. 

PEC owns and operates 18 coal-fired units at seven plants in North Carolina. The 

locations of these plants are shown on Attachment 1. Under G.S. § 143-215.107D(f), 

"each investor-owned public utility.. .may determine how it will achieve the collective 

emissions limitations imposed by this section." 

Nitrogen Oxides Emissions Control Plan 

PEC has been evaluating and installing NOx emissions controls on its coal-fired power 

plants since 1995 in order to comply with Title IV ofthe Clean Air Act and the NOx SIP 

Call rule adopted by the Environmental Management Commission (EMC). Substantial 

NOx emissions reductions have already been achieved (46,500 tons of NOx in 2006 

compared with 112,000 tons in 1997) and further reductions will ensure compliance with 

the Clean Smokestacks Act's 25,000 ton cap in calendar year 2007. This target will be 

achieved with a mix of combustion controls (which minimize the formation of NOx), 

such as low-NOx burners and over-fire air technologies, and post-combustion controls 

(which reduce NOx produced during the combustion of fossil fuel to molecular nitrogen), 

such as selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) 

technologies. 

Attachment 2 details PEC's North Carolina coal-fired electric generating units, their 

name plate generation capacity, installed NOx control technologies and those planned for 

installation. As technologies evolve or other circumstances change, a different mix of 

controls may be selected. Attachment 2 also projects annual NOx emissions on a unit-byunit basis based on the energy demand forecast and expected efficiencies ofthe NOx 

emissions controls employed. This information is provided only to show how compliance 

may be achieved and is not intended in any way to suggest unit-specific emission limits. 

Actual emissions for each unit may be substantially different. 

Appendix H.7 - 54
ATTACHMENT B 

PAGE 15 OF 20 

Sulfur Dioxide Emissions Control Plan 

PEC will be installing wet flue gas desulfurization systems (FGD or "scrubbers") to 

remove 97% ofthe SO2 from the flue gas of its Asheville, Roxboro and Mayo boilers. 

Since our last filing, PEC has continued its evaluation ofthe potential to use Furnace 

Sorbent Injection (FSI) technology at our Cape Fear Plant. FSI technology may offer a 

more cost-effective compliance solution for the Cape Fear Plant than the original plan to 

use scrubber technology. Use ofthe FSI technology also eliminates the need for a costly 

wastewater treatment system. We plan to test the FSI technology at PEC's Robinson Unit 

1 in fall 2007. Since Robinson Unit 1 is similar in design to the Cape Fear units, the 

Robinson test will indicate whether the use ofthis technology will be effective at Cape 

Fear. The current compliance plan also contemplates the use of a dry scrubber at Sutton 

Unit 3. A dry scrubber at that unit represents a more cost effective compliance solution 

and also eliminates the need for a costly wastewater treatment system. 

Wet scrubbers produce unique waste and byproduct streams. Issues related to wastewater 

permitting and solid waste disposal are being addressed for each site. PEC is treating the 

scrubber wastewater stream at the Asheville Plant using an innovative constructed 

wetlands treatment system to ensure compliance with discharge limits. A bioreactor 

technology will be used for the Roxboro and Mayo Plants. 

A contract has been executed with a gypsum product end-user that will construct a 

facility near the Roxboro Plant to use the synthetic gypsum produced by the Roxboro and 

Mayo Plants for the manufacture of drywall products. PEC also has entered into an 

agreement that enables PEC to market and sell synthetic gypsum produced at the 

Asheville Plant. 

Attachment 3 details PEC's North Carolina coal-fired electric generating units, their 

name plate generation capacity, installed SO2 control technologies and those planned for 

installation. As technologies evolve or other circumstances change, a different mix of 

controls may be selected. Attachment 3 also projects annual SO2 emissions on a unit-byunit basis based on the energy demand forecast and expected efficiencies ofthe SO2 

emissions controls employed. These projections are based on the planned removal 

technologies and PEC's current fuel and operating forecasts. This information is provided 

only to show how compliance may be achieved and is not intended in any way to suggest 

unit-specific emission limits. Actual emissions for each unit may be substantially 

different. 

Appendix H.7 - 55
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Appendix H.7 - 60
ATTACHMENT C 

PAGE 1 OF 3 

REPORT OF THE PUBLIC STAFF ON COSTS 

INCURRED AND AMORTIZED BY DUKE ENERGY CAROLINAS, LLC 

IN COMPLIANCE WITH SESSION LAW 2002-4 

Docket No. E-7, Sub 718 

May 25, 2007 

Section 14 of Session Law 2002-4 ("the Clean Smokestacks Act" or "the Act") 

requires the Department of Environment and Natural Resources {"DENR") and the 

Utilities Commission ("Commission") to report, by June 1 of each year, on the 

implementation of the Act to the Environmental Review Commission and the Joint 

Legislative Utility Review Committee. The May 30, 2003, report of DENR and the 

Commission states that the Public Staff will audit the books and records of the investor 

owned utilities on an ongoing basis in regard to the costs incurred and amortized in 

compliance with the Act. The Public Staff has undertaken such a review, focusing on 

the verification of costs related to complying with the Act, the amortization of those 

costs, and the operating results of emission reduction equipment installed by Duke 

Energy Carolinas, LLC ("Duke"). This report presents the Public Staff's findings for the 

twelve months ended December 31, 2006. 

I. Compliance Plan Summary 

Duke's original plan to install Selective Non-catalytic Reduction ("SNCR") 

technology to remove NOx and flue-gas desulfurization technology ("scrubbers") to 

remove SO2 to comply with the Act remains practically the same with only minor 

changes to the compliance schedule and plan. Duke has indicated that it is installing 

Selective Catalytic Reduction ("SCR") technology at its Marshall Unit 3 to comply with 

other regulatory requirements for NOx reductions in the Charlotte region. The new SCR 

replaces the SNCR equipment that was installed at Marshall Unit 3 to comply with the 

Act. Duke has redeployed the SNCR equipment from Marshall Unit 3 to Unit 4. The 

Public Staff is not aware of other similar modifications to the compliance plan. 

II. Environmental Compliance Costs 

Duke is required by the Act to submit a report to the Commission and to DENR 

on or before April 1 of each year containing its actual environmental compliance costs 

incurred during the previous calendar year. As defined by G.S. 62-133.6(a)(2), 

"environmental compliance costs" include only capital costs. 

In its Compliance Plan Annual Update for 2007 ("2007 Compliance Update"), 

Duke reported that its actual environmental compliance costs in calendar year 2006 

were $427,984,429. The cumulative environmental compliance costs incurred by Duke 

through 2006 were $901,380,056, as follows: 

Appendix H.7 - 61
ATTACHMENT C 

PAGE 2 OF 3 

Year 2001 $ 692,433 

Year 2002 1,024,223 

Year 2003 18,424.921 

Year 2004 106,834,479 

Year 2005 346,420,000 

Year 2006 427,984.429 

Total $901,380,485 

Duke's expenditures to date involve emission reduction technologies at its Allen, 

Belews Creek, Buck, Cliffside, Dan River, Marshall, and Riverbend facilities. 

Environmental compliance costs were incurred primarily for engineering, equipment 

procurement, contracting, construction, and field performance testing. 

As part of its review, the Public Staff requested information from Duke on the 

project costs, invoices documenting costs, and the purpose ofthe costs. Duke provided 

project cost sheets delineating actual project costs by year into the following categories: 

(1) direct labor costs; (2) labor loads; (3) contract costs; (4) material costs; (5) overhead 

costs; and, (6) other costs. These costs are as follows: 

Direct Labor $ 4,579,146 

Labor Loads 1,306,856 

Contracts 407,124,522 

Materials 1,419,497 

Overheads 213,822 

Other 13.340.586 

Total $427,984,429 

The project cost sheets were supported by project detail reports that incorporated 

all expenditures for a particular category or group. The Public Staff selected invoices in 

each category from the detailed spreadsheets and requested Duke to provide specific 

information on the selected costs. The Public Staff also had discussions with Duke 

personnel to gain a better understanding of the cost items charged to each specific 

project. Duke provided documentation to support each selected cost. 

Duke has estimated its environmental compliance costs at $1,965,260,200, as 

set forth on Exhibit C in its 2007 Compliance Update, compared to an estimate of 

$1,731,510,400 filed as part of Duke's 2006 update. The 2007 projection represents an 

increase of $465,260,200 or 31% over Duke's original estimate of $1,500,000,000, as 

set forth in G.S. 62-133.6(b). According to Duke personnel, several factors have 

contributed to the increase in the estimate, including an industry-wide ramp-up of similar 

environmental compliance work nationwide and its effect on labor availability, and 

increases in the prices for materials. 

Duke is using third party verification to ensure that its fixed price estimates for 

each project are consistent with market prices. The Public Staff will review the 

Appendix H.7 - 62
ATTACHMENT C 

PAGE 3 OF 3 

verifications and will continue to monitor the factors causing increases in the 

environmental compliance cost estimates. 

III. Amortization of Costs 

In Section 9 of the Act [G.S. 62-133.6(b)], the investor owned utilities are allowed 

to accelerate the recovery of their estimated environmental compliance costs over a 

seven-year period, beginning January 1, 2003, and ending December 31, 2009. The 

statute requires that a minimum of 70% of the environmental compliance costs be 

amortized before December 31, 2007, when the rate freeze period expires. In Duke's 

case, this amount is $1,050,000,000. The annual levelized amount is $214,285,714. 

The maximum amount that can be amortized in any given year is 150% of the annual 

levelized environmental compliance costs or $321,428,000. 

Using the protocols established by the Act and subsequent Commission orders, 

Duke reported that its environmental compliance costs amortization for 2006 was 

$225,236,000. The Public Staff reviewed Duke's quarterly amortization filings and 

supporting journal entries and concluded that the amounts appear to be accurate. The 

cumulative amortization to date is $862,665,142. 

IV. Contracts 

No contracts were reviewed during this audit period. 

V. Site Inspections 

On May 8, 2007, the Public Staff conducted an inspection of Duke's Marshall 

Steam Station in Mooresville, North Carolina. All but one of the scrubbers were 

completed and operational. The remaining scrubber is scheduled for tie-in later by the 

end of May. All of the related facilities (reagent storage and processing, wastewater 

disposal system, and byproduct removal) for SNCRs and scrubbers were installed and 

operational. Once the remaining scrubber is brought online, all ofthe work intended for 

the Marshall Steam Station to comply with the Act will have been completed. 

The Public Staff will continue to inspect other facilities as Duke implements its 

compliance plan. 

Appendix H.7 - 63
ATTACHMENT D 

PAGE 1 OF 4 

REPORT OF THE PUBLIC STAFF ON COSTS 

INCURRED AND AMORTIZED BY PROGRESS ENERGY CAROLINAS, INC. 

IN COMPLIANCE WITH SESSION LAW 2002-4 

Docket No. E-2, Sub 815 

May 25, 2007 

Section 14 of Session Law 2002-4 ("the Clean Smokestacks Act" or "the Act") 

requires the Department of Environment and Natural Resources ("DENR") and the 

Utilities Commission to report, by June 1 of each year, on the implementation of the Act 

to the Environmental Review Commission and the Joint Legislative Utility Review 

Committee. The May 30, 2003, report of DENR and the Commission states that the 

Public Staff will audit the books and records of the investor owned utilities on an 

ongoing basis in regard to the costs incurred and amortized in compliance with the Act. 

The Public Staff has undertaken such a review, focusing on the verification of costs 

related to complying with the Act, the amortization of those costs, and the operating 

results of emission reduction equipment installed by Progress Energy Carolinas, Inc. 

("PEC"). This report presents the Public Staff's findings for the twelve months ended 

December 31, 2006. 

I. Compliance Plan Summary 

PEC's original plan to install Selective Catalytic Reduction ("SCR") technology to 

remove NOx and flue-gas desulfurization technology ("scrubbers") to remove SO2 to 

comply with the Act, remains practically the same with minor changes being made to the 

compliance schedule and plan. 

The scrubber at Asheville Unit 2 was placed into operation in May 2006. The 

SCR on Asheville Unit 1 is expected to be online in 2007. The Roxboro (Units 1, 3, and 

4) and Mayo scrubber construction projects continue with substantial work being done 

at both facilities. The scrubber for Roxboro Unit 2 started operation in May 2007. 

Lee Unit 2 and Sutton Unit 2 initiated operation of low NOx burners in 2006. Lee 

Unit 3 is expected to begin operation of a "Rotamix" system in 2007. 

PEC is also looking into installing Furnace Sorbent Injection (FSI) technology that 

promises a lower cost means of SO2 removal. PEC indicates that testing of similar 

equipment at its Robinson facility in South Carolina will affect its decision to pursue FSI 

technology rather than scrubbers at the Cape Fear units. 

II. Environmental Compliance Costs 

PEC is required by the Act to submit a report to the Commission and to DENR on 

or before April 1 of each year containing the actual environmental compliance costs 

Appendix H.7 - 64
ATTACHMENT D 

PAGE 2 OF 4 

incurred during the previous calendar year. As defined by G.S. 62-133.6(a)2, 

"environmental compliance costs" include only capital costs. 

In its calendar year 2006 Progress Report ("2006 Report"), PEC reported that its 

actual environmental compliance costs in calendar year 2006 were $272,819,398. The 

cumulative environmental compliance costs incurred by PEC through 2006 are 

$560,410,636, as follows: 

Year 2002 $ 1,391,7311 

Year 2003 26,604,199 

Year 2004 78,321,742 

Year 2005 181,273,566 

Year 2006 272.819.398 

Total $560,410,6362 

PEC's expenditures to date involve emission reduction technologies at its 

Asheville, Mayo, Roxboro, Sutton, and Lee facilities. Environmental compliance costs 

were incurred for project studies and investigations, engineering, contracting, 

construction, and equipment acquisition. 

As part of its review, the Public Staff requested information from PEC on the 

project costs, invoices documenting costs, and the purpose of the costs. PEC provided 

project cost sheets delineating actual project costs by year into the following categories: 

(1) company labor costs; (2) materials costs; (3) outside services costs; (4) burdens; 

and (5) other costs. These costs are as follows: 

Company Labor $ 2,964,099 

Material 128,130,618 

Outside Services 126,479,796 

Labor Loads/Overheads 4,877,740 

Other 10.367.145 

Total $272,819,398 

The project cost sheet was supported by detailed spreadsheets for a particular 

category. The Public Staff selected invoices from the detailed spreadsheets and 

1

 Per Appendix B, costs for 2002, 2003, and 2004 are slightly different from the costs reported for those 

years in previous reports. For 2004, a majority of the difference relates to a Company adjustment to 

include Asheville wastewater treatment {WWT) costs in the FGD line items for Asheville. In 2005, PEC 

began reporting WWT project costs separately. 

2

 PEC's estimated and reported environmental compliance costs exclude certain costs attributable to the 

portions of its Mayo and Roxboro facilities that are owned by the NC Eastern Municipal Power Agency 

(NCEMPA). According to PEC's FERC Form No. 1 for 2005, PEC entered into an agreement with 

NCEMPA in 2005 to limit its aggregate cost associated with PEC's environmental compliance costs to 

approximately $38,000,000. In a November 2, 2006, filing with the Commission in this docket, PEC stated 

that its estimated compliance costs have now further increased and that the $37.9 million cap is $29.1 

million less than NCEMPA's full ownership share of the total Clean Smokestacks costs. 

Appendix H.7 - 65
ATTACHMENT D 

PAGE 3 OF 4 

REVISED 

requested PEC to provide specific information on the selected costs. The Public Staff 

has had discussions with PEC personnel regarding the cost items charged to projects. 

PEC has provided documentation to support the selected costs. 

PEC has estimated its environmental compliance costs at $1,354,577,000, as set 

forth on Appendix B in its 2006 Report. This represents an increase of $541,577,000 

or 66.6% over PEC's original estimate of $813,000,000, as set forth in G.S. 62-133.6(b). 

According to PEC personnel, several factors continue to contribute to the 

increase in the estimate, including significant increases in the price of skilled labor and 

materials, increases in equipment costs due to the limited number of suppliers available, 

and adjustments of future costs based on actual costs of projects already completed or 

substantially completed. 

PEC has previously cited its decision to change the scrubber technology on its 

units from a dry scrubber to a wet scrubber. This decision has further increased the 

costs because of the need for wastewater treatment. In its 2006 Report, PEC has 

indicated that it is now considering a dry scrubber for Sutton Unit 3, and that this 

represents a more cost effective compliance solution. While no expenditures have been 

made to date on developing the scrubber for Sutton Unit 3, the Public Staff understands 

that unit specific criteria, system-wide emission targets, existing scrubber performance, 

and costs are all factors involved in the decision-making process. The Public Staff will 

continue to monitor this development. 

III. Amortization of Costs 

In Section 9 ofthe Act [G.S. 62-133.6(b)], the investor owned utilities are allowed 

to accelerate the cost recovery of their estimated environmental compliance costs over 

a seven-year period, beginning January 1, 2003, and ending December 31, 2009. The 

statute requires that a minimum of 70% of the environmental compliance costs be 

amortized before December 31, 2007, when the rate freeze period expires. In PEC's 

case, this amount is $569,100,000. The annual levelized amount is $116,142,857. The 

maximum amount that can be amortized in any given year is 150% of the annual 

levelized environmental compliance costs or $174,214,285. 

Using the protocols established by the Act and subsequent Commission orders, 

PEC reported that its environmental compliance costs amortization for 2006 is 

$140,000,000. The Public Staff has reviewed PEC's quarterly amortization filings, as 

well as the journal entries recorded, and concluded that the reported amounts appear to 

be accurate. The cumulative amortization to date is $535,218,808. 

IV. Contracts 

No contracts were reviewed during this audit period. 

Appendix H.7 - 66
ATTACHMENT D 

PAGE 4 OF 4 

V. Site Inspections 

On May 21, 2007, the Public Staff conducted a site inspection of PEC's Mayo 

and Roxboro facilities in Person County, North Carolina. Significant construction is 

occurring at both facilities. Roxboro Unit 2 is now being scrubbed, with gypsum being 

temporarily trucked to a holding area until the wallboard facility is completed. The 

wallboard facility will take ownership of the gypsum once it is conveyed across the 

intake canal. Most of the other support equipment common to all scrubbers is in place 

and the remaining units will be placed in service as each unit enters a scheduled outage 

period over the next two years. 

With respect to the Mayo facility, foundation work is progressing on the scrubber 

itself, the building housing the equipment, and the stack. Construction on limestone 

handling and gypsum removal facilities has not yet started. PEC plans to truck 

limestone and gypsum to and from the Mayo facility to the Roxboro facility. 

It is the intent of the Public Staff to continue inspections of other coal-fired 

generating facilities as PEC continues to install emission reduction equipment in its 

boiler units. 

Appendix H.7 - 67