Cumulative Effects of Greenhouse

Gas Emissions in Project

Environmental Assessments

Dean O’Gorman

Barr Engineering and Environmental Science Canada

June 2017

Introduction

Where might we be going on cumulative effects

assessment of greenhouse gases (GHGs) in energy

sector environmental assessments (EAs)?

– Do current climate policy documents and recent energy

sector EAs offer any clues?

Focus is GHG emissions, NOT climate change impacts

This presentation not advocating any particular policy

directions

Climate change/GHG emissions is the mother of all

cumulative effects challenges…

Source: IPCC 5th Assessment Report, Working Group 2 Technical Summary

…but they don’t fit well in our current cumulative effects

framework for project environmental assessments

Canadian Environmental Assessment Agency (CEAA) cumulative effects guidance

– Paragraph 19(1)(a) of CEAA 2012 specifies that a project EA must take into account environmental effects, including cumulative environmental effects that are likely to result from the designated project in combination with other physical activities that have been or will be carried out.

Spatial and temporal boundaries?

Other physical activities?

Thresholds for significance?

1. Will governments start to enforce GHG reduction targets?

Source: Canada’s National Inventory Report 2015, Environment and Climate Change Canada

The Pan-Canadian Framework (PCF) on Clean Growth

and Climate Change is a start

• PCF (November 2016):

• projected impacts realistic?

• Other forecasts less rosy (National Energy

Board, Canadian Ass’n of Petroleum

Producers)

• Alberta’s Climate Leadership Plan:

• aggressive, but no big reductions by

2030

• How much from international purchases?

Source: Canada’s National Inventory Report

2015, Environment and Climate Change

Canada

2. Will regulators start to use project environmental

assessment as a tool of climate policy?

Just because they haven’t, doesn’t mean they won’t

Current federal CEAA2012, National Energy Board reviews

Pacific NorthWest LNG EA

– GHG limit in EA conditions (later)

Alberta oil sands 100 Mt limit

– Changes to the Process for Project Approvals and Approval Renewals and Extensions: OSAG recommends requiring that: (i) the approval process for new projects (both new facilities and expansions of existing facilities) and extensions or renewals of approved projects not currently under construction all be amended to introduce both a BATEA determination and require the submission of a GHG management plan that contains specified information, (ii) … (iii) current BATEA principles used by the GoA be reviewed/updated within the context of these recommendations.

Facility 2015 GHGs

(Mt)

TransAlta Sundance coal generation 14.4

Syncrude oil sands mine 11.5

Capital Power Genesee coal generation 10.0

Suncor oil sands mine 8.7

TransAlta Keephills coal generation 8.7

SaskPower Boundary Dam coal

generation

5.7

Imperial Cold Lake in-situ oil sands 5.5

Suncor Firebag in-situ oil sands 5.0

ArcelorMittal Dofasco steel 4.8

ATCO Sheerness coal generation 4.2

SaskPower Poplar River coal generation 4.0

CNRL Horizon oil sands mine 3.9

Nexen Long Lake in-situ oil sands 3.5

Shell Scotford upgrader 3.2

CNRL Wolf Lake in-situ oil sands 3.2

Irving refinery 3.0

ATCO Battle River coal generation 2.9

NOVA Chemicals plant Joffre 2.9

TransCanada NGTL pipeline system 2.8

US Steel Lake Erie steel 2.7

Current approaches to integrating GHGs into EA don’t

reflect the evolving CC policy framework

Most projects follow a common approach

– Estimate future activity levels (fuel consumption, fugitives, land use change, etc), apply emission factors

– Compare to provincial/national totals -> project not significant

– Generic discussion of GHG management, no firm commitments

Guidance exists…

– 2003 CEAA guidelines, current effort to update

– Ontario consulting on new guidance

– Test-Climat in Quebec – new, could be significant

– US Council on Environmental Quality NEPA guidelines

– Calculation guidance e.g. CAPP 2003, USEPA AP-42

… but need climate change policy clarity to drive change

What could the coming shifts look like?

1. Significance threshold, with potential need for justification?

– 1 Mt/yr for ‘high’ significance?

2. Detailed GHG Management Plan up front; prescriptive technology/best practices, or project emission limits, as conditions?

3. Limit, with ability to buy Internationally Transferred Mitigation Outcomes (ITMOs)?

4. Federal CEAA trigger for “GHG emissions of national significance”?

5. Carbon budget approach? (next slide)

A carbon budget approach might align with the science,

but would be particularly challenging to implement

Intergovernmental Panel on Climate Change (IPCC) 5th

Assessment Report Working Group 1 Summary for Policy Makers (2013):

Note: world currently emits about 10 GtC/yr (about 40 GtCO2/yr), and the table below is already a few years old

Chance of staying

<2o above pre-

industrial

Max total anthropogenic

emissions, considering

other climate forcings (GtC)

Total already

emitted (GtC)

Available

carbon budget

(GtC)

Years left at

current rate

33% 900 515 385 ~38

50% 820 515 305 ~30

66% 790 515 275 ~27

What can we learn from recent energy sector

environmental assessments?

Liquefied Natural Gas (LNG) projects: does Pacific

NorthWest point to the new standard?

Submitted 2013; coordinated review by CEAA and BC

– Production 19.2 million tonnes/yr of LNG

– Estimated 5.3 Mt/yr GHGs at full build-out, primarily from natural gas consumption, marine fuel use, fugitives

– Project GHG intensity 0.27 t CO2e/t LNG, below industry average of 0.33

– Mitigation: develop GHG management plan; fugitives program; engineering for best-in-class; minimizing venting of methane; comply with BC carbon tax

September 2016: approved by feds

– CEAA Decision Statement: significant adverse environmental effects

– See next slide

Liquefied Natural Gas projects: does Pacific NorthWest

point to the new standard?

3.1. At the commissioning of Train 2, the Proponent shall adhere to an annual average emissions intensity of less than or equal to 0.22 tonnes of equivalent carbon dioxide per tonne of LNG produced and shall emit no more than a total of 3.2 million tonnes of equivalent carbon dioxide per calendar year. At the commissioning of Train 3, the Proponent shall adhere to an annual average emissions intensity of less than or equal to 0.21 tonnes of equivalent carbon dioxide per tonne of LNG produced and shall emit no more than a total of 4.3 million tonnes of equivalent carbon dioxide per calendar year. The Proponent shall quantify and report to Environment and Climate Change Canada greenhouse gas emissions in a manner that is consistent with British Columbia’s Greenhouse Gas Industrial Reporting and Control Act and its regulations.

The Proponent shall implement mitigation measures during all phases of the Designated Project to

reduce and control air emissions and greenhouse gas emissions, including by: – 3.1.5. using high-efficiency aero-derivative gas turbines, or an equally or more efficient turbine or other equipment, to

drive refrigerant compressors;

– 3.1.6. implementing a comprehensive annual leak detection and repair system for fugitive emissions at the site of the

Designated Project throughout operation;

– 3.1.7. incorporating waste heat recovery systems to recover waste heat during operation;

– 3.1.8. capturing and re-using boil off gas from liquefied natural gas storage tanks and the carrier loading system;

– 3.1.9. using non-emitting pneumatic devices for Designated Project-related activities; and

– 3.1.10. measuring compressor vent flow rates from hydrocarbon gas compression systems on, at least, an annual basis,

taking corrective action on any identified sign of packing deterioration for reciprocating compressors, and ensuring that

seal systems for centrifugal compressors emit at a rate equal to or less than the rate of emissions from a dry seal

system.

Oil sands mines: are the goalposts moving?

1. Shell Jackpine Mine Expansion

– Submitted 2007 (+updates), 100 kbbl/d, estimated operating phase GHGs ~1.2 Mt/yr; mitigation - principles for GHG management

– EIA reviewed by Alberta first, then Joint Review Panel (JRP) with feds

2 explicit SIRs about GHGs from gov’t (mitigation options; cumulative emissions from others); 0 from JRP; brief responses

JRP Report: “The Panel is of the view that the Project meets existing GHG regulatory requirements and is not likely to result in significant adverse environmental effects from GHG emissions, provided that the mitigation measures proposed are completed and implemented.”

Feds approved 2013; CEAA Decision Statement – no GHG conditions

Oil sands mines: are the goalposts moving?

2. Teck Frontier

– Submitted 2011 (+updates), 260 kbbl/d, estimated operating phase GHGs ~3.8 Mt/yr

– EIA reviewed jointly by Alberta and feds from the beginning, currently with Joint Review Panel

– No decision yet

11* explicit SIRs from gov’t about GHGs (calculations, mitigation measures, fugitives, comparisons to other projects, etc.)

After all this, JRP asked 4 explicit GHG questions, including the following which elicited a 21 page response all by itself…

Oil sands mines: are the goalposts moving?

3.15. Teck states that it will develop a comprehensive greenhouse gas (GHG) management plan during the feasibility

and detailed engineering stages of the Project. Teck describes its current plan for managing GHG emissions as

including: (another page of preamble)

a) Describe those elements of the GHG management plan (both the current and proposed detailed versions) that

would support the statement that the Project is "best in-class" relative to similar oil sands mining projects.

b) Provide a discussion of the efficacy of leading and emerging GHG mitigation technologies.

c) Provide details for the development and implementation of an energy management system to achieve the

objective of continual improvement in energy efficiency and related GHG emissions mitigation.

d) Summarize how Teck will quantify all sources of GHGs and the quality controls to ensure credible data is

gathered.

e) Provide a comparison of the project’s estimated emission intensity to the historical intensities of currently

operating, comparable oil sands mines.

f) Discuss the potential implications to the Project of the Government of Alberta’s proposed 100 MT annual cap on

GHG emissions from the oil sands and 45% reduction in methane emissions from the oil and gas sector by 2025.

What technologically and economically feasible management actions would be available to respond to future

GHG and methane emission reduction policies?

In-situ oil sands: what happens if the feds get involved?

MEG Energy Surmont in-situ project (123 kbbl/d)

– EA complete November 2014

ConocoPhillips Surmont 3 in-situ project (135 kbbl/d)

– EA complete August 2016

Not on CEAA2012 project list, so only reviewed by Alberta

Both projects:

– fairly standard estimate of GHG emissions – about 4 Mt/yr

– no firm commitments to particular mitigation measures

– review process: each was asked 2 SIRs about GHGs

• MEG: units in calculations; learnings from other project

• CPC: construction vs decommissioning; Global Warming Potentials

Neither project is approved yet by the Alberta Energy Regulator

Closing thoughts

Very interesting time on the CC and EA policy front

Federal and provincial initiatives in play that could

change the rules and expectations for energy sector

project proponents, in terms of how they address GHG

emissions up front and in project planning