Cogeneration & Carbon Management - CMC Research...

January 28th and 29th, Calgary, Alberta, Canada

Cogeneration & Carbon Management

Paula McGarrigle Managing Director Solas Energy Consulting Inc. Suite 119, 2137 33 Avenue S.W. Calgary Alberta T2T 1Z7 T: (403) 542-9463 E: [email protected]

Key Issues in the Design of Carbon Management Policies and Regulations in Alberta

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• History of Cogeneration in Alberta

• Drivers behind Cogeneration development in Alberta

• Economics of Cogeneration

• The future of Cogeneration in Alberta

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Defining Cogeneration

Cogeneration produce electricity and steam

Facilities often integrate waste energy into the production of power or steam. Facilities are built to either match steam or match power requirements.

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Standalone

Integrated

TransCanda Carseland

Alberta has experienced significant growth in Cogeneration 4,588 MW of installed capacity ~ 30% of total generation capacity

Oil Sands development & Cogen Represents 67% of total installed Cogen capacity

Other applications for Cogen in AB Chemical industry, conventional oil and gas, pulp and paper as well as hospitals, educational institutions

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Alberta’s Cogen focused on Oil Sands in the North East


Central 12%

Edmonton 1%

NE 78%

NW 2%

South 7%

Geographic Area

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Cogeneration Capacity (MW) by Owner

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21 owners

REF: AESO

REF: AESO

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Cogen driven by 3 main factors

1. Regulatory changes,

2. Improved economics, and

3. Demand growth requiring reliable power sources

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Alberta Upgrading Capacity (MBPD)

Alberta SAGD Production (MBPD)

Class 43.2

SGER

Alberta Cogeneration (MW)

#1 Changing Regulatory Landscape

Electricity market deregulation, and “industrial site designation” were major drivers

#2 Improved Economics


ATCO - Muskeg River Plant

Federal Tax Changes Accelerated capital cost depreciation; Class 43.2 - depreciation rate increased to 50% until 2020.

High Heat Rates Alberta’s market heat rates have been above cogeneration physical heat rate and therefore cogeneration facilities have generated positive cash flow.

Industrial Site Designation Reduction in the ancillary service costs associated with power generation or load

Alberta Specified Gas Emitters Regulation (SGER) – Emissions Performance Credits • SGER compares stand alone cogeneration to a reference technology. The use of the

reference technology method has resulted in EPCs for cogeneration facilities. • Combined Cycle electricity plant is compared to a target of 0.418 tonnes CO2e/MWh. • No reduction target is placed on the emissions associated with the electricity generated. • The baseline for heat calculation assumes an 80% efficient boiler.

#3 Demand Growth & Reliability


Cogen concentrated in industries with high power demand

Oil Sands upgrading, Steam Assisted Gravity Drainage (SAGD) and the chemical industry in Alberta have significant requirements for steam and power. SAGD has experienced exponential growth CAGR of 34.2% Oil Sands upgrading has more than doubled since 2001

ATCO Scotford Cogeneration Facility

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$55

$84$92

$114

$157$163

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$68$74

$92

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Cogen Wind Coal CCGT SCGT CoalwithCCS Hydro

Levelized

Cost($/M

Wh)

LevelizedCost

FirstYearCostofPower

Cogeneration has the lowest levelized costs compared to alternatives in Alberta. (2016) Levelized cost of energy from a new cogeneration facility is higher than the Alberta forward power pool price.

Solas Energy Consulting – Wind Vision Technical Overview Report

LEVELIZED COST OF POWER

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• Carbon revenue is positive (reducing levelized costs) however is not a significant factor.

• ISD’s calculate their tariff using “net generation” and this creates savings compared to a standalone generation facility.

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Wind - CF=40%

Simple C.- CF =20%

Comb. C.- CF =50%

Cogen -CF =95%

Coal - CF=93%

Coal wCCS - CF

=90%

Hydro -CF =50%

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$/M

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Levelized Cost of Power (2016)

Taxes

Repower Cost

Capex

CO2 Compliance Costs

Generator Losses

Fixed and Variable O&M

Fuel Costs

Offset Revenue

Solas Energy Consulting – Wind Vision Technical Overview Report

LEVELIZED COST OF POWER - Components

Oil Sands Growth Alberta’s cogeneration development is indirectly

dependent on Canada’s climate change regulatory regime, because Oil sands growth is dependent on market access that is linked to climate policy.

Transmission Availability/Reliability/Cost Northern AB could be susceptible to transmission contingencies. Delay in the Fort McMurray to Edmonton 500 kV Transmission line may increase the interest in self-generation, with cogen preferred. Transmission costs and therefore DTS charges are on the rise. This may stimulate additional cogeneration ISDs to reduce the cost of delivered power.

Regulatory Treatment Potential changes in the treatment of cogeneration at the Provincial or Federal level may have profound impacts on size and continued investment in cogeneration.

Air Quality Regional air shed limitations (Lower Athabasca) may impede extensive cogeneration development. Additional cogeneration in the region may tax the currently strained air shed.

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Addi ons(MW)

Alberta Cogeneration (MW)

AESO Long Term Outlook

(2012)

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AESO Long Term Outlook (2012)

The Oil Sands Developers Group 2011 Co-Gen Survey resulted in an estimate of 3,500 MW of additional cogeneration by 2021. (Estimate is higher than the AESO)

Cogeneration capacity additions by 2022 are expected to total 6,200 MW or 29 per cent of supply mix. – Same as current mix.

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Cogeneration treatment under SGER is critical for Alberta compliance Cogeneration represents approximately 40 per cent (14,850 kT/39,930 kT) of the total avoided emissions since the SGER program was created.

ALL FACILITIES COMPLIANCE Alberta’s Carbon Compliance

Future AB SGER Treatment

• Current treatment uses the following as baseline. – 0.418 tonnes CO2e/MWh (Assumption for

Electricity) – 80% boiler efficiency

• Discussion on changing the assumptions – 0.375 tonnes CO2e/MWh – 85% boiler efficiency

• Impact – Reduced compliance or “avoided emissions” – Reduction in economics of cogeneration.

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Nexen – Balzac Power Station

Federal Greenhouse Gas Emissions Regulations

• Cogeneration is considered a cross cutting issue since the technology is applied in multiple sectors.

• Treatment, or reduction required may vary by the type of industry that cogeneration is a part of.

• May result in cogeneration facilities also having an obligation to reduce emissions.

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• Are EPC’s critical for incenting cogeneration in the Oil Sands industry?

• Is cogeneration business as usual?

• If cogeneration is considered business as usual what are the implications for SGER and cascading ramifications such as oil sands economics and Alberta’s greenhouse gas emission reduction plan?

• Does the new Lower Athabasca Regional Plan (“LARP”) and pending federal air quality regulations restrict CCGT facilities as viable alternatives for oil sands upgrading and SAGD?

• Should Alberta policy makers

consider emphasizing higher efficiency heat and power generation technology? - Fuel cells?

• Should renewable energy

integration in oil sands be incented through policies directed at further reducing air quality and GHG emissions?

Recommendations


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• Integrity of the system is paramount.

– Evaluate if cogeneration meets business as usual.

– If so, look to include cogeneration into the baseline.

– If not, ensure baseline used for cogen is representative.

Cogeneration & Carbon Management - CMC Research...

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