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Studies and Reports > 2011 MN Biennial Report >Transmission Planning Zones


Transmission Projects Report 2011
Chapter 7: Transmission-Owning Utilities
 
pp. 96-104

8.0 Renewable Energy Standards

           8.1    Introduction

Minnesota Statutes § 216B.2425, subd. 7, states that in the Biennial Report the utilities shall address necessary transmission upgrades to support development of renewable energy resources required to meet upcoming Renewable Energy Standard milestones.  In its May 30, 2008, Order approving the 2007 Biennial Report and Renewable Energy Standards Report, the Commission said, “Future biennial transmission projects reports shall incorporate and address transmission issues related to meeting the standards and milestones of the new renewable energy standards enacted at Minn. Laws 2007, ch. 3.”

In response to the Commission’s direction, the utilities are reporting on their best estimates for how much renewable generation will be required in future years and what efforts are underway to ensure that adequate transmission will be available to transmit that energy to the necessary market areas.  A Gap Analysis is provided to illustrate the amount of renewable generation that is already available and how much will be required in the future to meet the standard. 

8.2    Reporting Utilities

It should be pointed out that the utilities that are required to submit the Biennial Transmission Projects Report are not identical to those that are required to meet the Renewable Energy Standards.  The information in this chapter reflects the work of all the utilities that are required to meet RES milestones, regardless of whether they own transmission lines and are required to participate in the Biennial Report.  A list of those utilities participating in the Biennial Transmission Projects Report can be found in Chapter 2.0.  The utilities participating in this part of the 2011 Biennial Report on renewable energy are the following. 

Investor-owned Utilities

Interstate Power and Light Company
Minnesota Power
Northern States Power Company
Otter Tail Power Company

Generation and Transmission Cooperative Electric Associations

Basin Electric Power Cooperative
Dairyland Power Cooperative
East River Electric Power Cooperative
Great River Energy
L&O Power Cooperative
Minnkota Power Cooperative

Municipal Power Agencies

Central Minnesota Municipal Power Agency
Minnesota Municipal Power Agency
Rochester Public Utilities
Southern Minnesota Municipal Power Agency
Western Minnesota Municipal Power Agency/Missouri River Energy Services

Power District

Heartland Consumers Power District

8.3    Compliance Summary

The utilities have made substantial progress with respect to meeting future RES milestones.  The present analysis shows that the utilities are on course to meet the RES milestones for 2012 and 2016. The analysis continues to show that the CapX2020 Group 1 projects are crucial to meeting the 2016 Minnesota RES and non-Minnesota RES milestones. The utilities recognize that additional transmission and generation will be necessary for 2020 and beyond in Minnesota, and that other demands for renewable energy will impact Minnesota’s compliance status.

8.4    Gap Analysis

A Gap Analysis is an estimate of how many more megawatts of renewable generating capacity a utility expects to need beyond what is presently available to obtain the required amount of renewable energy that must come from renewable sources at a particular time in the future.  The Gap Analysis presented here, and those presented in the 2007 and 2009 Biennial Reports, is not an exercise intended to verify the validity of forecasted energy sales and associated capacity needs.  It is done for transmission planning purposes only.

8.4.1 2012 Base Capacity and RES/REO Forecast

The chart below presents a system-wide overview of existing capacity in 2012 (used as a base figure throughout the various milestone periods) and forecasted renewable capacity requirements to meet Minnesota RES as well as non-Minnesota RES/REO needs.  Each utility provided its own forecast of Minnesota RES and non-Minnesota RES/REO renewable energy needs, and converted such estimates into capacity based on their own mix of renewable resources (wind, biomass, hydropower) using the most appropriate capacity factors unique to their specific generating resources.  Table 1 on the following page shows a more specific breakdown of each utility’s Minnesota RES and non-Minnesota RES/REO capacity forecast.

2012 MTO MW Base: RES capacity acquired, actually installed and operational (“in the ground and running”) regardless of geographic location.  Does not include projects under contract but not yet under construction, and it does not include projects under construction but not yet completed.  Needed MW MN RES: Renewable capacity required to meet the RES energy goals for each utility serving customers in Minnesota. Needed MW Other Jurisdictions: Gross non-MN renewable capacity required to meet RES requirements or REO goals in states served by the reporting utility other than Minnesota.

    

Table 1.  MN & Non-MN RES Forecast (MW)*

Utility

2012

2016

2020

2025

 

MN RES

Non-MN RES

MN RES

Non-MN RES

MN RES

Non-MN RES

MN RES

Non-MN RES

Basin Electric**

39.8

14.2

65.4

361.1

88.7

430.5

130.1

534.5

CMMPA

13.8

0

21

0

28.9

0

39

0

Dairyland

19.3

109.8

32.7

167.3

41.8

194.4

50.3

260

GRE

346

0.4

486

1.5

589

1.5

800

1.5

Heartland

16.5

0

14.1

6.5

4.7

6.8

6.2

7.2

IPL

34

50

51

50

63

50

82

50

Minnkota

59

0

90

67

114

72

164

82

MN Power

368

10

537

19

646

20

832

21

MRES

44

22

79

42

110

45

141

47

SMMPA

117

0

180.5

0

229

0

308

0

Otter Tail

72

0

120.7

67.8

158.1

71.3

196.6

75.8

RPU

1.9

0

4.2

0

6.8

0

12.2

0

Xcel Energy

1,914

183.6

2,387

375.5

3,065

413.6

3,479

477.1

Total

3,045.3

390

4,068.6

1,157.7

5,145

1,305.1

6,240.4

1,556.1

 * Capacity factor assumptions established by each utility
**Basin Electric response includes East River Electric and L&O


8.4.2  Capacity Acquisitions & Expirations

This chart presents a system-wide overview of additional renewable capacity that will be acquired by individual utilities beginning as early as 2012 and capacity that will expire between 2016 and 2025. Such losses are attributable primarily to the expiration of various power purchase agreements for renewable energy generation. 


8.4.3  RES Capacity Acquired and Net RES/REO Need

This chart represents the total renewable capacity system-wide that will be acquired and lost between 2012 and 2025, as well as the total Minnesota RES and non-Minnesota RES/REO needs between 2012 and 2025. 

As can be seen, the Minnesota RES utilities have sufficient capacity acquired to meet the Minnesota RES needs through 2016.  When considering the RES needs, including other jurisdictions outside of Minnesota, the Minnesota RES utilities have almost enough capacity to meet RES needs through 2016.  In addition, some utilities with less than sufficient capacity to meet the Minnesota RES need may use renewable energy credits to fulfill their requirement.  Focusing back on just Minnesota RES needs, Table 2 on the following page provides a more specific breakdown of each utility’s forecast.

Table 2.  RES Capacity Acquired &

Net MN RES Capacity Need (MW)*

Utility

2012

2016

2020

2025

RES Cap Acq.

MN RES Net

RES Cap Acq.

MN RES Net

RES Cap Acq.

MN RES Net

RES Cap Acq.

MN RES Net

Basin Electric**

589.9

0

738.3

0

738.3

0

731

0

CMMPA

33.1

0

27.1

0

27.1

0

20.8

0

Dairyland

129.1

-110

200.1

-167

236.3

-194

310.3

-260

GRE

511

0

507

0

489

99

486

314

Heartland

36

0

36

0

36

0

36

0

IPL

26

13

26

24

24

36

22

56

Minnkota

359

-300

359

-269

359

-245

359

-195

MN Power

454

-85

636

-98

636

10

636

196

MRES

85.3

-41.3

121.4

-42.4

121.4

-11.4

121.4

19.6

SMMPA

125.6

0

125.6

0

125.6

100

125.6

200

Otter Tail

196.6

0

196.6

0

196.6

0

196.6

0

RPU

12.5

0

12.5

0

12.5

0

12.5

0

Xcel Energy

1,973

-59

1,973

414

1,839

1,226

1,551

1,927

Total***

4,531

-582.3

4,958.6

-138.4

4,840.8

1,020.4

4,608.2

2,257

*Capacity factor assumptions established by each utility
**Basin Electric response includes East River Electric and L&O
***Some utilities with less than sufficient capacity to meet the MN RES need may use renewable energy credits to fulfill their requirement

Note that the “Needed MW MN RES” bar in the bar chart in this section represents the total level of RES need in Minnesota.  Conversely, the column in Table 2 that is labeled “MN RES Net” represents the additional RES capacity that is presently identified to meet RES need (a negative value means the utility has a surplus of RES capacity).  The shortfall, or “gap”, between MN RES need and the additional RES capacity identified points to the need for some utilities to seek additional renewable capacity and when they need to do so.  Alternatively, some utilities may use renewable energy credits to fulfill their RES requirements.

8.5   Corridor Upgrade Project

In its May 28, 2010, Order, the Public Utilities Commission directed the MTO to discuss system considerations affecting the timing of the Corridor Upgrade Project.  The Corridor Upgrade Project is an upgrade of the 230 kV line between the Hazel Creek Substation near Granite Falls, Minnesota, and the Blue Lake Substation in Shakopee, Minnesota to a double circuit 345 kV system. 

This upgrade would provide significant new transmission capacity from the Dakotas, southwestern Minnesota and western Minnesota to the Twin Cities, at a cost estimated in 2009 to be approximately $350 million.  Previously the project was expected to be needed in the 2016-2018 timeframe based on constructability and ability to take transmission system outages as the generation delivery from SW Minnesota increased, and was expected to be the next transmission project pursued after the CapX2020 Group 1 lines.

However, the planned transmission system has changed in the last two years with the addition of the MISO MVP Group 1 portfolio of projects, expected to be approved by the MISO Board of Directors in December of 2011, as well as a shift in generation locations in the MISO queue.  Based on these changes, the Corridor Upgrade study, originally completed in March 2009, was updated in the summer of 2011 to determine if the regional system changes had affected the need and/or timing of the project.

Based on the results of this re-study, it has been determined that the need for the Corridor Upgrade project has likely moved out past the 2016-2018 timeframe previously assumed.  The change in timing is due mostly to the new parallel path transmission lines through Iowa as part of the MVP Group 1 portfolio which alleviates the need to construct the Corridor Upgrade before the Brookings 345 kV line is loaded.  In 2012, the amount of generation installed in the Dakotas, southwestern Minnesota and western Minnesota is expected to be approximately 3,500 MW.  The re-study results show that the transmission system can handle close to an additional 3,500 MW of generation in the Dakotas, southwestern Minnesota and western Minnesota before an upgrade to the 230 kV line to 345 kV is needed for that purpose.  The re-study results additionally point out that if the Corridor Upgrade project is not completed, there are some transmission limitations which will need to be addressed individually or as part of another project as load and generation in the region grow. However, the cost for these upgrades is considerably less than the estimated cost for the Corridor Upgrade and on their own do not justify the rebuild.  If the need for the Corridor Upgrade is triggered, similar to previous studies, the utilities anticipate there would be some curtailment risk during the time of construction of the project.

8.6  FERC Order 1000

In section 8.9.1 of the 2009 Biennial Report, the MTO identified that a key issue with regard to transmission development was the allocation of the costs of transmission.  On July 21, 2011, the Federal Energy Regulatory Commission issued its Order 1000, entitled Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities. The Order was issued in FERC Docket No. RM-10-23-000 and can be found in the August 11, 2011, Federal Register.  76 Fed. Reg. 49842.  The Order became effective on October 11, 2011. 

FERC Order  1000 requires that each public utility transmission provider must do the following:

  • Participate in a regional transmission planning process that produces a regional transmission plan
  • Amend its OATT to describe the procedures for consideration of transmission needs driven by public policy requirements in local and regional transmission planning processes
  • Remove from Commission-approved tariffs and agreements a federal right of first refusal (“ROFR”) to construct new transmission facilities, subject to certain limits
  • Amend its OATT to improve coordination between neighboring transmission planning regions for new interregional transmission facilities
  • Participate in a regional transmission planning process that has a regional cost allocation method or methods for the costs of new transmission facilities selected in a regional transmission plan for purposes of cost allocation
  • Participate in a regional transmission planning process that has an interregional cost allocation method for the costs of certain new transmission facilities that are located in two or more neighboring transmission planning regions and are jointly evaluated by the regions in their interregional coordination procedures

The Order establishes deadlines for transmission providers to respond, as follows: 

  • Each public utility transmission provider must submit a compliance filing within 12 months of the effective date of the Final Rule to address the regional planning and cost allocation requirements (including elimination of ROFR).  October 11, 2012
  • Each public utility transmission provider must submit a compliance filing within 18 months of the effective date of the Final Rule to address the interregional planning and cost allocation requirements.  April 11, 2013

The majority of MTO utilities do not expect that FERC Order 1000 will impact them given that they are not public utility transmission providers.