Combustion Turbine Flexibility

Presentation to: NorthWestern Energy ETAC

June 6, 2013

Why Does NWE Need Flexible Resources?

• Variations in load (within hour flexible capacity)

• Hour-to-hour ramp (10 minutes before to 10 minutes after the hour) to reflect schedule changes

• Forced outage response

• Variable Energy Resource (VER) following –primarily wind

Regional Wind (36 hours)

7000 MW +/-

300 MW +/-

Northwest Resource Flexibility

• Prior to 2003, NW IOUs (PacifiCorp, PGE, PSE, Avista, Idaho Power) enjoyed adequate resource flexibility from Mid C projects and/or utility-owned hydro resources

• BPA, BC Hydro, Mid C PUDs, Seattle, Tacoma operate hydro resources with significant flexibility – second-to-second, daily, seasonal

• The wind revolution and expiry of Mid C contracts (starting in 2004 with Priest Rapids) changed the regional flexibility landscape –PacifiCorp and PGE joined NWE as hydro flexibility “have-nots”

Role of Gas Resources to Meet Flexibility Needs

• PGE, PacifiCorp, NWE, and (to a lesser extent) PSE use gas-fired generation to follow load and resource deviations

• Maintaining load resource balance can be particularly difficult in spring and over winter peak – may need to run gas out-of-merit for regulation margin

• Entities with surplus hydro flexibility (large publics, BC Hydro/Powerex) generally make more money from load factoring (LLH to HLH) than providing regulation service

Types of Open Cycle Gas Turbines

• Frame SCCTs - Primarily capacity (large/fast w/controls)

� GE 7EA, GE 7FA, Siemens 501G, etc.

� 85-350 MW

� Heat Rate = 9400-11,400 Btu/kWh – rarely dispatch (under 2% of hours)

• Reciprocating Engines - Primarily flexibility (small/fast)

� 9-20 MW

� Wärtsilä, Caterpillar (Basin Creek)

� Heat Rate = 8500-9000 Btu/kWh – higher variable O&M limits dispatch

• Aero derivative SCCTs - Capacity and flexibility (fast)

� GE LM6000 (Highwood), GE LS100, P&W FT-8 (DGGS)

� 10-105 MW

� Heat Rate = 8700-9500 Btu/kWh – infrequent dispatch (under 5% of hours)

Open Cycle Turbine Dispatch

• Purchase spot market natural gas

• Infrequent dispatch complicates gas pipeline and transmission strategy – Firm transport way too expensive, but interruptible may be interrupted or reduced over winter peak

�Avista Rathdrum – California storage and exchange via GTN

�Back-up fuel (DGGS)

● Smaller unit size and flat HR curve may make reciprocating engines a better fit for flexibility requirements than other SCCT technologies

● Infrequent CT dispatch increases start-up forced outage risk

Combined Cycle CT Basics

• CCCT utilizes two turbine generator sets, usually with separate shaft for each T-G:

� Gas-turbine generator (GE Frame 7, MHI, or Siemens) – thermal energy from fuel combustion directly spins the turbine

� Steam-turbine generator – uses heat energy from gas-turbine exhaust to create steam to spin a second turbine

• Add additional combustion capability after combustion turbine to increase steam-turbine output (duct-firing)

Duct-burner

CCCT Math

• Large gas turbines have a “heat rate” under 7000 Btu/kWh - describes the conversion of thermal energy into electrical energy.

• Natural gas generally priced in $/MMBtu

• Incremental cost of production =

Heat Rate/1000 x (Gas Price + Variable Transportation) x (1+ End Use Gas Tax Rate) + Variable O&M

• Depending on location of unit, may need to factor incremental transmission and losses into the calculation

CCCT Incremental Cost Example

Heat Rate = 7000 Btu/kWh

Gas Price = $4/MMBtu

Variable Gas Transportation = $.10/MMBtu

WA Gas Tax Rate = .038 (allows me to make a point)

Variable O&M = $3.5/MWH

Incremental Cost = (7000 Btu/kwh) /1000 x ($4/MMBtu +$.10/MMBtu) x (1 + .038) + $3.5/MWH = $33.3/MWH

But CCCT Dispatch Decisions Rarely Straight-forward

• NW CCCT fleet usually sets daily market-clearing price – wind and hydro push CCCTs in/out of the money

• CCCTs often economic HLH but uneconomic LLH -$1.5/MWH in-the-money HLH, -13.0/MWH LLH on 6/1/13

• Start-up requires multi-hour ramp-up/ramp-down –quick start package can shorten the ramp-up

• Maintenance contracts charge for starts after some maximum (around 50/yr) - $3000-$5000/start

• Best CCCT heat rate at full load

� Heat rate increases 1% for every 5% of output reduction between 80% and 100% of rated capacity

� Heat rate increases 2.7% for every 5% of output reduction thereafter to maximum turn-down of 50%

CCCT Ramp (GE Product)

Quickly load GT- Start charge- High HR

Slowly load STG

GE Part Load Performance

+1% HRPer -5%Base Rtg

+2.7% HRPer -5%Base Rtg

CCCT Part-load Performance + LM6000

LM6000

But Wait, There’s More

• Different schedule for gas day (9 AM – 9 AM PPT/MPT 8 AM – 8 AM) versus electric day (midnight to midnight) introduces additional uncertainty on CCCT economics

• Dispatching CCCT up/down to minimize electric imbalance charges could cause imposition of pipeline imbalance charges

• Location on transmission system could limit ability to dispatch on some hours

Note the number of discontinuities and uncertainties inherent in CCCT dispatch decisions!

CCCT Duct-firing

• Standard GE Frame 7FA CCCT GT-STG package includes 22 MW of duct-firing – could be as much as 60 MW for a 1x1 CCCT configuration

• Duct-firing looks like a quick-start SCCT with 9400 Btu/kWh HR

• Duct-burner start and ramp to full output takes about 10 minutes due to need to have plant operator configure equipment

• On the ragged-edge of fast enough to use for spinning reserve.

And Did I Mention Hedging?

• Once you sign the confirm to purchase forward gas, the unit price you paid has no bearing on dispatch decisions

• However, purchasing gas in the forward market at a price well above the ultimate market price will attract attention, and

• Not purchasing gas in the forward market at a price that turns out to be well below the ultimate market price will attract attention

• Depending on hydro conditions, load growth, coal/nuclear performance, etc, a CCCT could dispatch on as few as 30% of the hours in a year and as many as 80% of the hours in a year.

Regardless of hedging strategy deployed, a CCCT operator needs good access to liquid natural gas and electric market hubs and/or suppliers to sell excess and cover deficits

Modeling Implications

• Hard to predict CT actual operation with a dispatch model (requires perfect knowledge)

• Many examples of out-of-merit dispatch –aware of one entity that won’t turn CCCT on unless in the money on a multi-week basis, then doesn’t adjust output until market indicates unit uneconomic on a multi-week basis

• Hydro flexibility often used to keep CCCTs either just in or just out of the money – some dispatch models handle hydro complexity better than others

Integrated Uncertainty

• NWE Standards of Conduct limit ability of NWE Transmission to coordinate flexibility needs of the BAA with NWE Supply

• DGGS provides much of NWE’s BAA balancing needs, with Shell Trading available to buy/sell real-time to “recenter” DGGS – NWE Supply currently receives no information on DGGS operation

• NWE Transmission called NWE Supply for Basin Creek support during DGGS outage as an emergency measure

• NWE would need to change current model for provision of balancing resources to fully utilize flexibility of Supply-controlled natural gas generation resources and to minimize NWE overall expense for natural gas

Final Points

CCCT Operation? Why, yes, it is rocket science!