Energy Business Solutions Michigan IRP Working Group Meeting June 10, 2005

Energy Business Solutions

Michigan IRP Working Group Meeting

June 10, 2005


Objectives and Agenda

The objective is to close out a number of data and modeling assumptions so that we can move on the next milestone – Representative Market Model of Michigan (6/27/2005)

Agenda Data Assumptions

Transmission Interface Limits Model Representation Fuel Forecast Firm Gas Transportation Requirements for CC’s and CT’s Emissions – SO2, NOX, Hg Unit Retirements Demand Side Alternatives Blocks for Land Fill Gas and Digestion

Modeling Assumptions Objective Function and Constraints External Capacity Matrix of Scenarios and Sensitivities


Transmission Interface Capability

ISSUE: The Michigan to ROW transmission interface limits are highly dependent upon loop flows through Michigan and into Ontario

Assumption to Resolve

Do we take a conservative approach? Assume that 1500 MW of loop flow occurs all the time

Do we take a “problem resolved” approach? Assume that loop flow problem does not exist or is corrected by

phase shifters

Do we take an “in-between” approach? Assume that loop flow happens half the time and take an

average of the two previous numbers

Do we know a seasonal pattern of loop flow? Assume that loop flow happens for a schedule of particular

months


Transmission Interface Capability

Example: Interface Capability from the Southern Market into Michigan

Assumption effects

Do we take a conservative approach? 1,450 MW

Do we take a “problem resolved” approach? 3,000 MW

Do we take an “in-between” approach? 2,225 MW

Do we know a seasonal pattern of loop flow?

0

500

1000

1500

2000

2500

3000

1 2 3 4 5 6 7 8 9 10 11 12


Model Representation

MAPP

MAAC

Ontario

Upper Peninsula

ITC

METC- Areas

- Tie Lines

MAIN

TVA VACAR

TN

TN

TN

??

?

?0

Interfaces based On Conservative Estimate

1400? 1350

14501450

14501450

1450


Fuel Forecasts

ISSUE: The EIA Annual Energy Outlook does not represent the recent run up in Appalachian Coal, Gas and Oil prices

June 1 2005 NYMEX Henry Hub futures Forecast adjusted monthly based on Platt’s shape

Gas Prices

0

2

4

6

8

100

4

05

06

07

08

09

10

Time

$/M

MB

TU

History HHForecast WHNYMEX HH


Fuel Forecasts

ISSUE: The EIA Annual Energy Outlook does not represent the recent run up in Appalachian Coal, Gas and Oil prices.

based on May 31, 2004 NYMEX Central Appalachian Coal Futures adjusted for an average heat content of 25.01 MBTU/Ton and .40

$/MMBTU for transportation for a delivered price to PJM

Coal Prices

00.5

11.5

22.5

33.5

Time

$/M

MB

TU

History App

Forecast App

NYMEX C.App


Fuel Forecasts

Recommendation

Use current NYMEX Strip for Appalachian Coal, Henry Hub Gas, and Oil Escalate beyond strip using EIA escalation assumptions, roughly 2.3% Scale Midwest Coal forecast according to ratio of Platt’s Appalachian Coal

to Platt’s Midwest Coal The EIA forecast for Powder River Basin looks consistent, use as

forecasted.


Firm Gas Transportation - CC

ISSUE: The current economic assumptions for new Combined Cycle Technology do not include any provisions for reserving firm pipeline capacity to ensure delivery of gas to support CC operations.

Failure to reserve gas pipeline capacity may limit energy operations for CC’s.

RECOMMENDATION:

Include a Firm Gas Transportation charge of $1.71/kW-Month in the CC’s Fixed O&M expenses (represents a blend of reservation charges for ANR and Trunkline).

Include a Commodity charge of .014 $/MBTU to CC fuel.


Firm Gas Transportation - CT

ISSUE: The current economic assumptions for new Combustion Turbine Technology do not include any provisions for reserving firm pipeline capacity to ensure delivery of gas to support CT operations.

Failure to reserve gas pipeline capacity may limit energy operations for CT’s

Options:

Assume dual fuel capability on all new CT’s. This provides CT’s with an alternative fuel to support quick start reserves and peak operation needs.

Assume a Firm Gas Transportation charge of $1.71/kW-Month in the CT’s Fixed O&M expenses (represents a blend of reservation charges for ANR and Trunkline) for peak requirement months.

Summer Summer and Winter


Emissions – SO2, NOX, Hg

Verification of Emission Spreadsheets

Mercury Emissions


Unit Retirements

ISSUE: We have attempted to extend the life of units, such that, we are not seeking capacity alternatives to unit retirements. However, several Michigan unit’s retire prior to the study period and during the study period.

The Participants desire to not replace retiring units as a part of this study.

RECOMMENDATION: Set retirements of all existing units to beyond the study horizon.


Demand Side Alternatives


Blocks for Land Fill Gas and Digestion


Objective Function and Constraints

OBJECTIVE FUNCTION

Minimize Utility Cost Minimize Average Rate

Subject To:

Minimum Reserve Margin of Maximum Reserve Margin of Combinations Restricted Combinations


External Capacity

ISSUE: Are capacity purchases, external to Michigan, available as resource alternatives to count toward the reserve requirements of Michigan?

Point of Clarification: in the Capacity Need Forum Proposed Integration Scenarios there is a footnote associated with a Max Import Sensitivity that indicates capacity pricing based on 50% CT and 50% CC.

NewEnergy can generate a capacity and energy price for the various markets represented as an alternative.


Other Critical Data Needs

Data Review by Lansing Water & Board and Wolverine

Review of Assumptions and Model Development

Documents

Energy Business Solutions Michigan IRP Working Group Meeting June 10, 2005