-iREPORT TO THE LEGISLATURE 

ON EMISSIONS REDUCTION PROJECTS 

UNDER MINNESOTA STATUTES 216B.1692 

Submitted by the 

Minnesota Public Utilities Commission 

March 2008
-iiREPORT TO THE LEGISLATURE 

ON EMISSIONS REDUCTION PROJECTS 

UNDER MINNESOTA STATUTES §216B.1692

Introduction

In 2001, Minnesota Statutes §216B.1692, Emissions Reduction Rider, was enacted The statute 

allows a utility to file with the Public Utilities Commission (Commission) for a rider to collect, 

outside of a general rate case, the costs of emissions reduction programs utilities choose to pursue, 

if the programs meet certain qualifications in the statute1

. Projects needed to comply with new 

state or federal air quality standards (such as the Regional Haze Rule, Clean Air Interstate Rule, 

and Clean Air Mercury Rule) or as a corrective action as a part of any state or federal enforcement 

actions are not eligible for recovery under this rider. 

 In 2006, the sunset date for §216B.1692 was extended from June 30, 2006 to December 31, 2013 

and cost recovery provisions were expanded, in conjunction with the adoption of the Mercury 

Emissions Reduction Act [Minn. Stat. §§216B.68-.688], discussed below. 

In 2006, Minnesota Statutes §216B.682, Mercury Emissions Reduction Plans, and Minnesota 

Statutes §216B.683, Cost Recovery and Financial Incentives, were enacted. Section 216B.682 

requires Minnesota Power and Xcel Energy to submit plans most likely to result in the reduction 

of mercury emissions by ninety percent at their largest coal-fired electric generating units. In 

addition, the Act requires the Minnesota Pollution Control Agency (PCA) to evaluate these plans 

and the Commission to review, evaluate, and approve these plans. 

 Section 216B.683 expands the cost recovery provisions of § 216B.1692 to include cost recovery 

for utility mercury reduction plans and for other emissions reduction activities undertaken along 

with the mercury reductions, even if those other emissions reductions are needed to comply with 

federal or state laws or actions. 

 

1

 In 2003, the legislature clarified that the three projects comprising the primary proposal filed 

with the Commission in July 2002 by Xcel Energy, known as the Metropolitan Emissions 

Reduction Project (MERP), qualified under §216B.1692. [First Special Session 2003, Chapter 

11, Article 3, Section 12.] 
-iiiSubdivision 7 of §216B.1692 directs the Commission, in consultation with the Commissioners of 

Commerce and Pollution Control Agency, to submit a report to the legislature which discusses: 

(1) the number of participating public utilities; 

(2) the total cost of each project and any associated incentives; 

(3) the reduction in air emissions achieved; 

(4) rate impacts of the cost recovery mechanisms; and 

(5) an assessment of the effectiveness of the cost recovery mechanism in accomplishing 

power plant emissions reductions in excess of those required by law. 

This report discussed the items required above, as well as related items associated with the 2006 

Mercury Reduction Act. 

Summary of Emissions Reduction Projects 

Xcel - King, High Bridge and Riverside Plants 

Xcel Energy was the first utility to file under Minn. Stat. §216B.1692. In July 2002, Xcel Energy 

filed its proposed metropolitan emissions reduction plan (MERP) with the Commission. 

(Commission docket number E-002/M-02-633)2 Xcel’s primary proposal consisted of changes to 

three of its coal-fired electric generating plants. 

Allen S King Plant, Bayport: Xcel proposed to install new emissions control devices on 

the King plant to significantly reduce emissions and to rehabilitate elements of plant 

equipment to extend the useful life of the plant until at least 2032. Generation capacity at 

the site would be increased by 60 MW. The King Plant project has been completed and 

the plant and went into service in July of 2007. 

High Bridge Plant, St. Paul: Xcel proposed to demolish the existing coal plant and replace 

it with a natural gas-fired combined cycle plant. This would increase generation capacity 

at the site by 268 MW. The High Bridge project is scheduled for a May 2008 commercial 

operation date. 

 2

 Public copies of all filings cited in this report are accessible via the Commission’s web 

page (www.puc.state.mn.us). Click on “eDockets & eFiling” under Quick Links. On the eFiling 

home page, click on “Search documents” (left margin). On the Search Documents page, enter the 

last two sets of digits in the “Docket Number” boxes; e.g., for MERP enter (02) under “Year” and 

(633) under “Number”. Click on “Search.” Chose document of interest and click on “Public” in 

left margin. 
-ivRiverside Plant, Minneapolis: Xcel proposed to replace the existing coal-fired units 6 and 

7 with a natural gas combined-cycle plant. This would increase generation capacity at the 

site by 79 MW. The Riverside project is well underway and is scheduled for completion 

in May 2009. 

Xcel – Sherco 1 and 2 

In December of 2007, Xcel submitted a revised proposed Emissions Reduction Plan for Units 1 

and 2 at its Sherco facility. (Commission docket number E-002/M-07-002) Xcel has indicated 

that it intends to submit in early 2008 a rate rider petition pursuant to section 216B.1692. Xcel 

expects the projects to be completed in the 2012-2013 time-frame. Xcel states that while the 

projects will affect several different emissions, a primary goal of the plan is to control mercury, 

and therefore proposes that the plan be recognized as its Mercury Emissions Reduction Plan for 

those units as well. This project also will expand generating capacity by about 69 MW from the 

units. 

Minnesota Power – Laskin Units 1 & 2 and Taconite Harbor 

On October 14, 2005, Minnesota Power (MP) filed its Arrowhead Region Emission Abatement 

Plan (AREA) plan. (Commission docket number E-015/M-05-1678) MP proposed to install 

technology to reduce the amount of nitrogen oxides (NOx) emitted from both generators at the Syl 

Laskin Energy Center (Laskin) and to reduce NOx, sulfur dioxide (SO2) and mercury (Hg) emitted 

from the three generators of the Taconite Harbor Energy Center (Taconite Harbor). Neither 

project was expected to change any plant’s generating capacity [Laskin, 100MW; Taconite 

Harbor; 225MW]. 

On March 27, 2007, MP reported that the status of these projects: 

Laskin Unit 2 has been retrofitted and was placed back in service in November 2006. 

Laskin Unit 1 has been retrofitted and was placed back in service in April 2007. 

Taconite Harbor Unit 2 was placed back in service in mid- 2007. MP plans to retrofit the 

second unit in the spring of 2008 and the third unit in the fall of 2008. 

Summary of Mercury Emission Reduction Projects 

Minnesota Power – Boswell Unit 3

In October of 2006, MP filed its Boswell 3 Environmental Improvement Plan and Rider. 
-v- 

(Commission docket numbers E-015/M-06-1501 & E-015/M-07-1430) This was the first filing to 

be considered by the Commission under the Mercury Emissions Reduction Act. This plan 

involves retrofits to reduce emissions through application of mercury control technology and Best 

Available Control Technology for NOx, SO2, and PM. This filing was made under Minnesota 

Statutes §216B.6851, Utility Option. MP projects an in-service date of late 2009. 

Xcel – Sherco Unit 3 and King Plant 

In December of 2007, Xcel filed a proposed Mercury Emissions Reduction Plan for Sherco Unit 3 

and the King Plant. (Commission docket numbers E-002/M-07-1601 and E-002/M-07-1602, 

respectively) Xcel plans to install sorbent injection systems in these plants. Xcel is anticipating 

completion by December 2009 and December 2010, respectively. 

Discussion of Topics Listed in §216B.1692, Subivision 7

A. The Cost of Each Project and Associated Incentives

Xcel - MERP 

Xcel Energy originally estimated that the total capital cost of its three-project MERP proposal 

would be $1.04 billion. Under the settlement agreement approved by the Commission in March 

of 2004, the total capital cost benchmark for the three projects was estimated to be slightly under 

$1 billion, broken down as follows: 

 King: $381,560,000 

 High Bridge: 394,840,000 

 Riverside: 212,785,000

 Total: $988,785,000 

In an October, 2007 filing, Xcel estimated that capital costs for the King Plant are about $44 

million over budget; the High Bridge Plant is expected to be about $48 million under budget; and 

the Riverside Plant is expected to be about $30 million over budget. Under the 2007 tariff 

approved for the MERP, Xcel is to reduce its return on equity for exceeding budgeted costs and 

can receive a greater return on equity for completing work under budget. In its October 2007 

filing, Xcel proposed to adjust the return on equity associated with these projects in a manner 

consistent with the approved tariff provisions. 

Xcel – Sherco Units 1 & 2 

The project-related capital costs for the two units are estimated to be $1.1 billion; $517 million for 
-viUnit 1 and $542 for Unit 2. 

MP - AREA 

In its initial filing, MP estimated that the AREA plan will require an investment of $53.9 million, 

plus $4.07 million annually for operation and maintenance. The Commission capped MPs rate 

rider for the projects at these estimated levels. 

Subsequent filings by MP provided the following information regarding the capital and O & M 

costs of the project completed thus far: 

Description Laskin Unit 2 Laskin Unit 1 Taconite Harbor 

Unit 2 Total 

Capital $2,622,0003 $1,878,000 $24,700,0004 $29,200,000 

Operations & 

Maintenance $36,000 $36,000 $1,400,000 $1,472,000 

 

Total $2,658,000 $1,914,000 $26,100,000 $30,672,000 

Mercury Emission Projects: 

MP – Boswell Unit 3 

The project-related capital costs are estimated to be $203 million and operations and maintenance 

costs to be $11.6 million. MP is recovering costs for the project through the Boswell 3 Rider to 

the expected year-end 2009 in-service date. MP did not propose a performance-based incentive. 

Xcel – Sherco Unit 3 and King 

The project-related capital cost is estimated to be $9 million (i.e., $4.5 million for each project); 

and $9.3 million ($5.5 million for Sherco and $3.8 million for King) for operations and 

maintenance. 

 3

 Laskin Unit 2 capital cost is 17.5 percent higher than initially projected by MP. This is 

due to slightly higher than expected installation costs. MP noted that experience gained on Unit 2 

will allow installation on Unit 1 to offset the increased costs of Unit 2. 

4

 This total includes capital costs for facilities and system common to all three Taconite 

Harbor units. Consequently, it is higher than the $16,508,000 per unit capital cost MP initially 

estimated. Per unit costs on Units 1 and 3 are expected to be correspondingly lower. This total 

also includes costs of addressing the PCA’s concerns about particulate matter. 
-viiAs regards all projects, fuel costs continue to be somewhat of an unknown factor. Natural gas 

prices, in particular, have demonstrated volatility and a clear upward trend. Coal prices are less 

volatile but are also exhibiting an upward trend. 

B. The Reductions in Air Emissions 

Xcel - MERP 

In its December 30, 2002 report, as updated on February 21, 2003, the PCA estimated the 

emissions reductions to be expected from the primary MERP project: 

 SO2 

tons/year

NOx 

tons/year

PM10 

tons/year

CO2 

tons/year

CO 

tons/year

Pb 

lbs/year

Hg 

lbs/year

Current 

Emissions 34,178 24,206 954 6,545,727 860 266 232 

Change in 

Emissions -31,880 -22,017 -610 -813,603 -50 -60 -178 

Percentage 

Change -93.3 -91 -64 -12 -1 -22.5 -76.0 

The PCA, using the Commission’s externality values out to 2040, estimated that the MERP plan 

environmental and health benefits were in the $200 to $500 million range. The PCA further 

stated that these numbers understate the actual environmental and health benefits, because they do 

not include the value of reductions in such other pollutants as fine particulate matter (PM25, acid 

rain, ground level ozone, regional haze and mercury. 

As of early 2008, the King plant is completing startup and performing compliance tests as 

required in its air emissions permit issued by the PCA. Reports will be submitted to the MPCA 

and compliance with air emission limits will be demonstrated by 2009. Current operating 

information from the NOx and SO2 continuous emissions monitors indicate that the required 

reductions are being achieved.

Xcel – Sherco Units 1 & 2 

The table on the following page provides Xcel’s estimate of reductions to be expected from the 

project from its December 2007 filing: 
-viiiAnnualized 

Emissions 

SO2

Tons/yr 

NOx

Tons/yr 

CO2

Tons/yr 

PM 

Tons/yr 

Hg

Lbs/yr 

Before 13,050 11,600 9,900,000 920 610 

After 5,460 7,450 10,200,000 750 80 

Sherco Change -7,590 -4,150 300,000 -170 -530 

CO2 Offsets -300,000 

Total Project 

Changes 0 

Percent Reduction 58% 36% 0% 18% 87% 

Efficiency gains are expected to increase capacity by approximately 70 MWs. These estimates 

have not yet been reviewed by the PCA. 

MP - AREA 

In its January 2006 report, the PCA estimated the following emissions reductions from the MP 

AREA project: 

SO2 

tons/year

NOx

tons/year

PM 

tons/year

PM10 

tons/year

Hg

lbs/year

Current 

annual 

emission from 

the two plants 

7,138 5,694 398 443 94 

Emissions 

after retrofits 3,589 1,949 398 443 25.8 

Percent 

reduction 50% 66% None None 72% 

The PCA estimated benefits incorporating information from recent federal benefit estimates for 

the Clear Air Act reduction program. That examination indicates that, to the extent benefits can 

be quantified, AREA’s benefits approximate, and most likely exceed, the projected costs. Parties 

to the proceeding supported this conclusion. The PCA expressed some concern that the method 

MP proposed to reduce SO2 emission is likely to increase emissions of fine particulates (PM). 

MP recently reported to the Commission that NOx reduction goals are being realized. The 

company also reported that SO2 reductions at the Taconite Harbor project have been less than 

anticipated and that the company has taken steps to improve performance. Also, MP reported that 

mercury reductions at the Taconite Harbor project have not met expectations and that the 

company is working with the technology vendor to determine solutions. In the meantime, MP has 

pursued alternative approaches for mercury removal. Final results on these alternative approaches 

are not yet available. MP indicated that it plans to file a complete status report with the 
-ixCommission in March of 2008. 

Mercury Emission Projects: 

MP – Boswell Unit 3 

MP and MPCA expect these retrofits to achieve a 90% reduction in mercury emissions. 

Xcel – Sherco 3 & King 

Xcel estimates the sorbent injection technology will reduce mercury emission by 81 to 90 percent 

on a fuel basis, or 77 to 88 percent on a flue gas basis, for the Sherco unit; and 87 to 90 percent on 

a fuel basis, or 58 to 69 percent on a flue gas basis, for the King Plant. 

 

C. The Rate Impacts of the Cost Recovery Mechanisms

Xcel - MERP 

As noted above, the capital costs of these projects are projected to be close to $1 billion. The 

following chart shows the projected dollar amounts to be collected through the Environmental 

Improvement Rider for seven years, starting in 2006. 

Rate Rider Revenue Cumulative Increase over 

Present Rates 

2006 $ 33,716,199 1.8 % 

2007 $ 68,737,013 3.6 % 

2008 $ 99,787,345 5.1 % 

2009 $ 111,097,977 5.5 % 

2010 $ 107,048,196 5.2 % 

2011 $ 102,811,979 5.0 % 

2012 $ 9 8,756,777 4.7 % 
-xCollections from Xcel ratepayers started in 2006, with commencement of work on the King Plant. 

For 2006, the estimated rate impact was $0.00126 per kWh, or about $11.40 for the year for a 

residential customer using 750 kWh a month. It was noted at that time that this amount was 

expected to increase as work on the other projects advances. Xcel’s October 2007 filing provided 

information on the costs for 2008 and reflected work on all three projects. Xcel estimated the 

Environmental Improvement Rider for 2008 at $0.00291 per kWh, or about $26.26 for the year 

for a residential customer using 750 kWh a month. 

Xcel – Sherco Units 1 & 2 

Xcel’s estimate of the rate effects of its proposal are as follows: 

Year Revenue Requirements 

($000) 

Rate Impact 

($/kWh) 

Average Annual 

Rate Impact for 

Residential 

Customer 

($/year) 

Average Rate 

Increase 

(%) 

2009 $1,302 $0.000039 $0.36 0.0 

2010 $19,484 $0.000576 $5.16 0.7 

2011 $30,784 $0.000898 $8.04 1.0 

2012 $66,986 $0.001928 $17.40 2.1 

2013 $117,613 $0.003350 $30.12 3.5 

2014 $139,768 $0.003939 $35.40 4.1 

2015 $134,326 $0.003744 $33.72 3.8 

MP - AREA 

MP originally estimated the cost of these projects at $53.9 million for capital costs and $4.07 

million annually for operation and maintenance. While the financial consequence to customers of 

the AREA Plan will vary over time, MP estimated that the rider for the completed project will 

increase the cost of electricity for an average household no more than $11.40 annually. 

Subsequent filings by MP have provided the following cost information: 
-xiYear 

Revenue 

Requirements 

($000) 

Rate Impact - 

Residential 

($/kWh) 

Average Annual 

Rate Impact for 

Residential 

Customer 

($/year) 

Average Rate 

Increase 

(%) 

2006 $4,831 $0.00048 $4.08 0.7 

2007 $9,476 $0.00094 $8.04 1.3 

2008 $13,426 $0.00133 $11.40 1.85 

Recent information filed by MP indicates that the average annual rate impact for an MP 

residential customer for the work done so far is $5.64 as of June 30, 2008 (a 0.91% increase). 

Mercury Emission Projects: 

Xcel – Sherco 3 & King 

Xcel estimates the average rate impact of the King project for a residential customer will be $0.06 

per month; for the Sherco Unit 3 project, the impact for an average residential customer is 

expected to be $0.10 per month. 

MP – Boswell Unit 3 

MP estimates an average increase for a residential customer of $1.15 per month (2.24%) for 2008, 

$1.70 per month (3.32%) for 2009, and $3.44 per month (6.7%) in 2010. 

D. An Assessment of the Effectiveness of the Cost Recovery 

Mechanisms

The cost recovery mechanism for stand-alone emission reduction projects under §216B.1692 

provides for a utility to recover costs of voluntary initiatives to reduce emission levels, initiatives 

which they would not otherwise be required to undertake at all or at least would not be required to 

do as soon or as completely. Therefore, it is logical to assume that the existence of this cost 

recovery provision was effective in influencing the scope and timing of Xcel’s MERP and MP’s 

AREA projects. 

The cost recovery mechanism for mercury reduction projects under §216B.683, provides for a 

utility to recover the costs of a mandatory program to reduce mercury emissions. Whether the 
-xiiexistence of a cost recovery mechanism for a mandatory program has a significant influence on 

the program is more problematic to determine. The existence of this cost recovery mechanism 

may have influenced the timing of MP’s mercury reduction plan for Boswell 3, since it was filed 

earlier than the December 31, 2007 date required by the statute, and possibly had some influence 

on the scope of the program.. 

It is likely that the existence of both of these rider provisions would influence the timing of 

potential rate case filings. The capital costs and on-going expenses associated with emissions and 

mercury reduction programs are significant, and assurance of recovery of prudently-incurred 

expenditures in a timely manner is certainly important to the covered utilities. 

It is important to recognize that the special rate riders incorporated in Minnesota Statutes Sections 

216B.1692 and 216B.683 join a number of special recovery mechanisms in Minnesota statutes. 

There are currently at least 18 different special cost recovery mechanisms required or allowed by 

Minnesota statutes that permit utilities to adjust their rates outside of a general rate case. The 

number of such mechanisms has increased significantly in the last several years, with no fewer 

than five new ones enacted as part of 2007 legislation alone. 

The theoretical rationale for such special rate mechanisms is to allow recovery of costs outside of 

a utility’s control (such as the fuel clause adjustment) or of the costs of publicly mandated 

programs or objectives (such as renewable energy standards) which may not have been reflected 

already in existing utility rates. These mechanisms allow companies to increase rates without 

having to go through a full rate case review, and thus to begin to recover the costs more quickly 

from their ratepayers. They also reduce the financial and business risk for the utility, which 

should be accounted for in a general rate proceeding. However, under these cost recovery 

mechanisms, utilities recover new or increased specific costs without a review of the 

reasonableness of their overall rates. In a rate case, all costs (i.e., those that increase as well as 

those that decrease) are considered in arriving at a just and reasonable overall level of utility rates 

for recovery from ratepayers 

In evaluating these special recovery mechanisms, the Legislature has the difficult task of 

balancing the potential benefits that such rate riders may enable versus the potential costs to 

ratepayers and the resultant marginalization of the Commission’s overall rate-making processes. 

Before granting new special recovery authority or broadening the scope of existing recovery 

riders, the Legislature should take great care to assess whether such measures are really necessary 

or likely to be effective in achieving desired goals.