BACKPRESSURE STEAM TURBINE-GENERATORS: TECHNOLOGY AND MARKET

OPPORTUNITIESPresentation to

Regional CHP Center/Initiative Face-to-Face MeetingOak Ridge National Laboratory

Washington DCMay 2, 2006

Sean CastenChief Executive Officer

161 Industrial Blvd.Turners Falls, MA 01376

www.turbosteam.com

Creating Value from Steam Pressure

Understanding 75% of US power generation in 30 seconds or less…

Rankine Power PlantRankine Power Plant

Fuel(Coal, oil, nuclear, gas, etc.)

High Pressure Steam

Heat to atmosphere

Low Pressure

Steam

Low Pressure

Water

Pump

Boiler

Cooling Tower

High Pressure

Water

Electricity to Grid

Steam Turbine Generator

Understanding thermal energy plants in 30 seconds or less…

Thermal Energy PlantThermal Energy PlantPressure Reduction Valve(s)

Fuel

High Pressure Steam

Heat to load

Low Pressure

Steam

Low Pressure

Water

Boiler Pump

Boiler

Thermal load (kiln, dormitory, etc.)

High Pressure

Water

The opportunity

Fuel

Heat to load

Boiler Pump

Boiler

Thermal Load

Electricity to Plant Bus

IsolationValve Isolation

Valve

Steam Turbine Generator

Several non-intuitive benefits of this approach.

• Operating Savings: The presence of the thermal load makes this generation ~ 3X as efficient as the central power it displaces.• More efficient than most other CHP technologies because all of input

energy is recovered (comparable to a gas turbine that uses 100% of hot exhaust gas as hot air for a process).

• Capital Savings: Since 75% of the power plant is already built, the effective (marginal) capital costs are quite low.• 1,000 MW Rankine plant typical capital costs ~ $1 billion ($1,000/kW)• 1 MW steam turbine generator integrated into existing facility typical

installed capital costs ~ $500,000 ($500/kW) • Turbosteam has done fully installed systems for as little as $300/kW

• Similar logic applies to non-fuel operating costs, since most of Rankine cycle O&M are in the boiler and cooling tower. Turbine-generator O&M costs are negligible.• Long term Turbosteam service contract on 1 MW unit ~ 0.1 c/kWh

Key differences from other CHP technologies.

• Defined by how the downstream thermal energy is used, not by the technology itself• Backpresssure = use LP steam. Condensing = dump LP steam

• Nationally, the dominant power generation technology• 75% of US power-only plants are steam turbines (MW basis)• 32% of all US CHP plants are steam turbines (MW basis)

• System economics depend upon heat recovery• Only regulated utilities (or waste heat/fuel applications) install

condensing turbines; all others rely on backpressure

• T:E ratio usually >10 for BPTGs (compare to 2 – 5 for other prime movers). • BPTG target markets fundamentally different from engines,

turbines, etc.

Operational and design considerations are backwards from “power first” CHP

• Design for thermal load, take power as near-free byproduct– Power-first approaches design for power need, take heat as byproduct

• “Recycled” commodity is the kWh, but heat costs $– In a power-first approaches heat is the recycled commodity

• Can design to 100% of thermal load, but rare to be able to design for 100% of electrical load.

– Power-first can be sized to electric demand, only recover heat that can be locally used.

• Power production can be base-loaded or thermal following depending on size relative to thermal load, but generally cannot follow electric load

– Power-first is exactly inverted from this approach

BUT – the two approaches can be synergistic. UMCP gas turbine + HRSG+ backpressure steam turbine is a great example.

Other design possibilities

• Thermal balance & fuel costs sometimes lead to excess steam in certain applications. When this happens, can make economic sense to combine BP and CX approaches to maximize power.

ElectricityHP Steam

LLP Steam to condenser

HP Steam

Condensing (CX) Configuration Backpressure/Condensing (BP+CX) Configuration

Electricity

LLP Steam to condenserLP Steam

to load

• Thermal plants are usually suboptimally designed for CHP. BPTG design often includes increases in boiler pressure and/or reductions in distribution pressure to boost power output. At the (confusing)extreme, this can enable condensing turbines in backpressure operation.

• Like all CHP, STGs (both CX and BP) can be designed to provide ancillary benefits in addition to kWh savings (e.g., enhance reliability, power factor)

We have installed 111 systems in the U.S., and 178 worldwide since 1986.

>10,000 kW

5001 – 10000 kW

1001 – 5000 kW

501 – 1000 kW

1 – 500 kW

NonNon--U.S.U.S.

• 17 countries• 67 installations• 37,091 kW

Worldwide installations, by industry

• Chemical/Pharmaceuticals 28• Food processing 21• Lumber & Wood Products 20• District Energy 19• Petroleum/Gas Processing 17• Colleges & Universities 16• Pulp & Paper 11• Commercial Buildings 10• Hospitals 8• Waste-to-Energy 6• Military Bases 5• Prisons 2• Textiles 1• Auto manufacturing 1

Some (heavily qualitative) thoughts on market opportunities

• Historically, market has been dominated by big energy users. Very common to see existing, 50+ year old BP (or extraction) installations of 10+ MW in integrated pulp & paper mills, big chemical plants, petroleum refineries.

• Conventional wisdom has long been that the economics don’t make sense at < 10 MW size range.– CW driven by a combination of historic utility hassle, the relative lack of

system integrators (like Turbosteam) who are interested in <10 MW projects and the relative lack of focus on energy costs in other industries

• CW is no longer valid. The market opportunity is therefore in those industries that:1. Have appropriate thermal/electrical needs2. Have not historically considered BPTGs because of CW

Where Turbosteam sees the biggest market opportunities

• In industries where individual facilities are big enough to have steady thermal loads, but not so big as to have historically focused on energy.– Paper mills (pulp and paper mills are more likely to have already invested)– Mid size (petro)chemical plants: formaldehyde, carbon black, etc.– Ethanol dry mills (wet mills are more likely to have already invested)– <10 MW opportunities in big facilities that flew under the radar of previous energy

investments

• In institutional applications where energy costs, reliability and environmental impact are becoming more important drivers.– Universities– Hospitals– Prisons

• In regions where there have been recent sudden increases either in energy costs or regulatory friendliness through barrier removal or incentive creation (ACEEE: volatility drives efficiency investments more than absolute energy cost)– Southeastern US – recent electric rate spikes– Ontario – big new gov’t incentives– VT, CT: states to watch

However, the design challenge posed by opportunities is different from that of power-first CHP.

• In a power-first application, the power generation is a fairly standard device, but the heat recovery unit requires custom-engineering

– Can pick a prime mover and power output fairly quickly, but then have an infinite number of ways to design the heat-recovery unit: there is no such thing as a standard, mass-produced heat recovery steam generator.

• In a heat-first application, the steam boiler is a fairly standard device,but the power-recovery unit requires custom engineering

– Boilers can be picked by frame size, but then have an infinite # of ways to design the steam turbine-generator, each with unique capital & operating cost characteristics: there is no such thing as a standard, mass-produced steam turbine.

Example of turbine-generator design complexities

Midwest Steel Mill PRV reduces 900 psig steam down to 150 psig for plant-wide distribution

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Stea

m F

low

, mlb

s/hr

640

660

680

700

720

740

760

780

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820

Inle

t Ste

am T

emp,

o F

Steam FlowSteam Temperature

Design for Peak flow?• 11.9 MW rated power• 43.3 million kWh/yr• $1.4 million annual savings• 3 year simple payback

Design for baseload?• 2.4 MW rated power• 21.0 million kWh/yr• $672 K annual savings• 2.7 year simple payback

Sample customer’s financial optimization

0%5%

10%15%20%25%30%35%40%45%50%

150 200 250 300

Design Steam Flow (mlbs/hr)

15-y

ear R

OA

Gross ROAMarginal ROA

6.5 MW$1.44 million/year savings

10 MW$1.59 million/year savings

Optimal system is designed here to balance desires for rapid capital recovery, high annual cash generation AND effective use of free cash.

Rules of thumb for opportunity screening

Typical ValuesTypical Values Extreme ValuesExtreme Values

Target Financial Return <2 years simple payback from energy savings

Above-market returnsand/or

Non-financial drivers

Inlet Steam Pressure >150 psig 15 psig

Pressure drop across turbine-generator

>100 psig(P-ratio >3) 15 psig

Steam flow >10,000 lbs/hr 2,500 lbs/hr

Annual steam load factor >6 months/year 3 months/year

Local electricity rate >6 c/kWh >1.7 c/kWh