IN THE MATTER OF: NORTHERN GATEWAY JOINT REVIEW PANEL
PROPONENT: NORTHERN GATEWAY PIPELINES INC.
APPLICATION: NORTHERN GATEWAY PIPELINE PROJECT NEB FILE OF- FAC-OIL-N304-2010-01 01, FILED 27 MAY 2010
CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
HEARING ORDER OH-4-2011
WRITTEN EVIDENCE OF THE INTERVENOR
COASTAL FIRST NATIONS
December 21, 2011
Northern Gateway Joint Panel Review - CFN Written Evidence 1 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Table of Contents
Table of Contents ...... 2 Part I, Introduction ...... 5 Coastal First Nations (CFN) ...... 5 Declaration of First Nations of the North Pacific Coast ...... 5 CFN Members and Associates ...... 5 Location of CFN Members ...... 6 Sustainable Eco-system Management...... 6 Aboriginal Rights and Title ...... 7 Long-term Effects of an NGP oil Spill ...... 8 Inadequate NGP Consultation...... 8 Part II, Evidence with Respect to the Need for the Project ...... 9 Report Summary ...... 9 Conclusion ...... 11 Part III, David Suzuki - Evidence on Aboriginal Perspectives on Development and Environment ...... 11 Relationship of Nature and Development ...... 11 Relevance of Aboriginal peoples‟ views of the world ...... 11 Environmental Protection ...... 12 Challenges Facing Decision-Makers ...... 13 Coastal First Nations and Sustainable Development ...... 14 Part IV, Evidence with Respect to Spill Prevention ...... 14 Oil Spills are Inevitable ...... 14 Measures Proposed by NGP to prevent Spills ...... 15 Double Hull Tankers do Not Prevent Incidents ...... 15 Limitations of Double Hull Tankers ...... 15 Double Hull Tanker Incidents ...... 15 Double Hull Tankers are Prone to Corrosion ...... 16 Older Tankers have more Incidents ...... 20 Additional Redundancy Features Not proposed by NGP to Reduce Risk ...... 20 Inadequate Tanker Acceptance Program (TAP) Standards ...... 21 Standards ...... 21 Inspections ...... 22 Incidents are caused by Human Error ...... 23 Tanker Captains ...... 23 Incidents attributed to Human Error ...... 24 International Maritime Organization Recommendations ...... 24 Local Experts ...... 25 Need for Drug and Alcohol Testing...... 25 Weather Conditions affect Operational Safety ...... 26 Expert Knowledge ...... 26 Inadequate Measures to avoid Severe Weather Conditions in the OWA ...... 27 Marine Incidents and Weather ...... 28 Lack of Definition on Refuge Area Locations and Decisions on Use ...... 30
Northern Gateway Joint Panel Review - CFN Written Evidence 2 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Pilots Do Not Eliminate the Risk of an Incident...... 32 Dr. Gerald Graham...... 32 Local Expertise ...... 32 Escort Tugs do not eliminate the risk of an incident ...... 32 Dr. Gerald Graham...... 33 Local Expertise ...... 33 Fisheries Liaison Committee does not eliminate the risk of incidents ...... 33 Part V, Evidence with Respect to Inadequate Spill Response ...... 33 Lessons from the Exxon Valdez ...... 34 Lessons from the BP Deepwater Horizon Oil Spill ...... 35 Inadequate Canadian Preparedness ...... 37 Commissioner of the Environment and Sustainable Development...... 37 Analysis of Commissioner‟s Report ...... 38 Transport Canada and CCG Responses to Commissioner‟s Report ...... 39 Recommendations of the Pacific States/BC Oil Spill Task Force ...... 39 Use of Dispersants in Spill Clean Up ...... 44 Gulf Oil Disaster Recovery Group ...... 45 Ji Sayer, Oil Spill Truth, Dispersants & Dispersed Oil ...... 45 Part VI, Evidence with Respect to the Catastrophic Effects of an Oil Spill on the Marine Environment ...... 46 Ecological Damage ...... 46 Deepwater Horizon Oil Spill ...... 46 Exxon Valdez - Long-Term Effects ...... 48 Exxon Valdez Oil Spill Trustees Council (EVOSC) ...... 48 Gail Irvine, a U.S. Geological Survey ...... 49 Part VII, Evidence with Respect to Inadequate Assessment Methodology ...... 50 Lack of Baseline Information ...... 50 The Canadian Environmental Assessment Act ...... 51 David Strong, former President of the University of Victoria ...... 52 Dr. William Sawyer, American Board of Forensic Medicine ...... 53 Congressional Research Service ...... 53 Inadequate Determination of Significance ...... 54 CEAA Reference Guide ...... 54 David Lawrence, Significance criteria ...... 54 Inadequate Cumulative Effects Assessment ...... 55 Part VIII, Evidence with Respect to an Inadequate Risk Assessment ...... 56 Low Probability-High Impact Events ...... 57 Black Swan Events ...... 57 Purpose of the Black Swan Thesis ...... 57 Characteristics of a Black Swan event ...... 57 Examples of Black Swan Events ...... 58 Lessons of the Turkey ...... 58 Estimating Rare Events ...... 58 Methodology ...... 58 Consideration of Consequences or Severity ...... 60 Conclusions ...... 60
Northern Gateway Joint Panel Review - CFN Written Evidence 3 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Applying the Black Swan Theory ...... 61 Part IX, Evidence with Respect to Inadequate Spill Scenarios ...... 62 Shortcomings of NGP Scenarios ...... 62 Dr. Gerald Graham...... 62 Part X, Evidence with Respect to Impacts to Coastal First Nations ...... 66 Executive Summary ...... 67 Values in the PNCIMA ...... 67 Enbridge Northern Gateway Project ...... 69 Enbridge Oil Spill Assessment ...... 70 Exxon Valdez Oil Spill ...... 72 Assessing Potential Impacts of an Oil Tanker Spill Associated with the Enbridge Northern Gateway Project...... 74 Conclusion ...... 79 Part XI, Evidence with Respect to the Inadequacies of the Regime Governing Liability for Oil Spills ...... 79 The US Experience - BP Deepwater Horizon Oil Spill ...... 80 Deepwater Horizon ...... 80 Liability of Multiple Parties ...... 81 Liability Regimes for Black Swan Events ...... 82 Part XII, Evidence with Respect to Marine Use Planning ...... 84 Gunton Report ...... 85 Unilateral DFO Changes to PNCIMA ...... 85 APPENDICES ...... 87 Appendix I - A Public Interest Assessment of the Enbridge Northern Gateway Project, Dr. Thomas Gunton and Sean Broadbent ...... 87 Appendix II - Marine Navigation: Measures to Reduce the Risk of Martine Incidents, Captain Harrison Layton and Michael McGuire ...... 87 Appendix III – Review of Potential Impacts to CFN, Dr. Thomas Gunton and Sean Broadbent ...... 87 Appendix IV - Application Review, Dr. Gerald Graham ...... 87
Northern Gateway Joint Panel Review - CFN Written Evidence 4 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Part I, Introduction
Coastal First Nations (CFN) CFN is an alliance of First Nations on B.C.‟s North and Central Coast and Haida Gwaii that came together in 2000 with the goal of developing a sustainable conservation- based economy for its member First Nations.
Declaration of First Nations of the North Pacific Coast Preamble The North Pacific Coast is a rich, varied and fragile part of the natural world. The connection of land and sea with people has given rise to our ancient Northwest cultures.
We recognize this life source is under threat like never before and that all people must be held accountable.
This united declaration is the foundation for protecting and restoring our culture and the natural world.
We are the ones that will live with the consequences of any actions that take place in our territories.
Declaration We declare our life source is vital to the sustenance and livelihood of our culture and our very existence as a people.
The First Nations of the North Pacific Coast inherit the responsibility to protect and restore our lands, water, and air for future generations.
We commit ourselves: • to making decisions that ensure the well-being of our lands and waters. • to preserving and renewing our territories and cultures through our tradition, knowledge, and authority. • to be honest with each other and respectful of all life.
We will support each other and work together as the original people of the North Pacific Coast, standing together to fulfil these commitments.
Source: Turning Point II Conference
CFN Members and Associates CFN members include: Haida: Old Massett Village Council, Skidegate Band Council, and the Council of the Haida Nation; Haisla: Kitimaat Village; Tsimshian: Kitasoo/Xaixais, Gitga‟at, Metlakatla;
Northern Gateway Joint Panel Review - CFN Written Evidence 5 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Nuxalk; Wuikinuxv; and Heiltsuk.
In addition, CFN works with other coastal First Nations on specific shared interest initiatives: Gitxaala, Kitsumkalum, Lax Kw‟alaams, Kitselas, and the Nanawakolas Council (Gwa‟sala ‟Nakwaxda‟xw, Kwiakah, Da'naxda'xw/Awaetlatla, Mamalilikulla- Qwe'Qwa'Sot'Em, Tlowtsis and K‟ómoks).
Location of CFN Members
Sustainable Eco-system Management CFN‟s strategic approach to development includes: sustainable ecosystem-based management of marine and land resources; increased local control and management of forestry and fisheries operations; coordinated development through regional strategic planning in forestry, fisheries and tourism, and partnerships and cooperative arrangements with governments, industry, ENGOs and other stakeholder groups.
Towards advancing this strategy, CFN has: finalized and implemented land use plans with the Province of BC; established a marine use planning process with Canada and B.C.; identified and advanced economic opportunities in the areas of Tourism, Shellfish Aquaculture, Non-Timber Forest Products and Forestry.
Northern Gateway Joint Panel Review - CFN Written Evidence 6 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011
Evidence of the work done by CFN can be found in the following studies1: Our Future Harvest: A new approach to Commercial Fisheries (2004); A Review of Offshore Oil and Gas Development (2004)2; Keepers of the Land – Eco-system based Management (2007);3 Sea of Change – Integrated Marine Use Planning (2008)4; Into the Deep Blue – Marine Ecosystem-Based Management (2009);5 Ecosystem-Based Management – A Commitment to Our Future (2009);6 Coast Information Team Review Report (2005); Review of Environmental and Socio-economic Impacts of Port Development and Shipping on the North Coast of British Columbia (2008).
Aboriginal Rights and Title We wish, to ensure at the outset, that the Joint Review Panel (“JRP”) clearly appreciates that engagement with CFN ought in no way be considered as fulfilling the consultation obligations which the Crown and Enbridge‟s Northern Gateway Pipeline Project (“NGP”) have with respect to any specific First Nation. Each First Nation has its own Aboriginal Rights and Title interests that are affected by this Project; it is imperative, therefore, that each First Nation is consulted with individually. Furthermore, the Crown must consult with each First Nation on a government to government basis before rendering any decision. To be clear, any meeting with the CFN Board does not meet legal consultation or accommodation obligations with regard to the CFN‟s member First Nations.
Traditionally, First Nations had absolute power over their traditional territories and resources including the right to govern, to make and enforce laws, to decide citizenship and to manage lands, resources and institutions. In British Columbia there are two titles recognized in law – Aboriginal Title and Crown Title. The treaties negotiated throughout Canada did not include BC.
Today, our power as First Nations continues to rest with our communities and like our Aboriginal Rights and Title, it comes from within the people and cannot be taken away. The Coastal First Nations maintain Aboriginal Title and Rights to the lands in its respective Traditional Territories. We believe that our Aboriginal Rights and Title affirm our right to our traditional territories and to maintain and to protect the resources
1 http://www.coastalfirstnations.ca/publications/
2 http://research.rem.sfu.ca/sustainableplanning/CoastalFirstNationsOOGReport.pdf
3 http://www.coastalfirstnations.ca/sites/default/files/imce/KeepersoftheLandEBM.pdf
4 http://www.coastalfirstnations.ca/sites/default/files/imce/seaofchange.pdf
5 http://www.coastalfirstnations.ca/sites/default/files/imce/intothedeepblue.pdf
6 http://www.coastalfirstnations.ca/sites/default/files/imce/Fact_Sheet_1.pdf
Northern Gateway Joint Panel Review - CFN Written Evidence 7 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 within our lands and waters. We will not leave our traditional territories because it is here and only here that our Rights and Title exist.
CFN‟s goals and activities, as well as the Aboriginal Rights & Title of its member First Nations, are threatened by the operations and the potential oil spills resulting from tanker accidents and malfunctions of the NGP.
Long-term Effects of an NGP oil Spill NGP‟s Evidence acknowledges that an oil spill could result in long-term effects that include:
changes in local relationships within communities and stress related to increased uncertainty about the harvest and use of natural resources by community residents. These effects may be more acute in communities whose cultural, social and economic lives are highly dependent upon natural resources. For this reason, these effects would, in turn, affect community wellbeing….in the event that a spill was to occur, such short-term direct and longer-term indirect effects could occur.‖7
Inadequate NGP Consultation NGP‟s consultation effort with First Nations is deficient. The consultation record clearly shows that, because NGP dismissed the possibility of an oil tanker incident occurring in the Open Water Area (OWA), they mistakenly assumed that the First Nations would not be affected by a an oil spill. As a result, NGP‟s consultation efforts were minimal at best.
Furthermore, NGP has acknowledged that it has not bothered to consult with CFN associate First Nations on Vancouver Island because
“it is unlikely that the routine activities would affect the current use of lands and resources for traditional purposes by Aboriginal persons who reside in Northern Vancouver Island. Given the low probability of an oil spill during marine transportation, the use of the southern approach by only a portion of the tankers that would call on the Kitimat Terminal, and the distance of these communities from the southern approach, the likelihood of these communities being affected is remote.”8
The Aboriginal Rights and Title of First Nations on Vancouver Island are potentially affected by an oil spill and should have been consulted with as they are in much closer proximity to NGP‟s proposed Southern Route than the area and distance affected by the Exxon Valdez spill.
7 NGP response to CFN IR 1.2 e
8 NGP response to CFN IR 1.2 c
Northern Gateway Joint Panel Review - CFN Written Evidence 8 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011
Part II, Evidence with Respect to the Need for the Project
CFN commissioned a study on the need for the NGP Project by Professor Tom Gunton, and Sean Broadbent of Simon Fraser University. Dr. Thomas Gunton is Director of the Resource and Environmental Planning Program at Simon Fraser University. He has published over 80 scientific articles and has extensive professional experience including Deputy Minister of Environment for the Government of British Columbia and Assistant Deputy Minister of Energy and Mines for the Government of Manitoba. Dr. Gunton‟s study, A Public Interest Assessment of the Northern Gateway Project, is attached as Appendix I of this submission.
Report Summary 1. The purpose of this report is to assess whether the proposed Enbridge Northern Gateway Project (ENGP) meets the approval criteria as specified in Section 52 of the National Energy Board Act. The National Energy Board (NEB) approval criteria require the applicant to show that:
a) The project is required by the present and future public convenience. b) The project is in the public interest.
2. The ENGP application states that the ENGP is required and in the public interest for the following reasons:
a) Oil production in Western Canada will increase over the next several decades and increased production will require an increase in pipeline capacity to transport the oil to markets. b) Asian oil consumption is expected to grow much faster than US consumption over the next several decades and this faster growth, combined with benefits of market diversification and a higher price of oil in the Asian market, makes Asia a more attractive market for Canadian oil than the US. c) Building the ENGP will generate economic impacts estimated by Enbridge to include an increase in gross domestic product of $270 billion (2009 CAD), increased employment of 558,000 person years, and increased government revenue of $81 billion (2009 CAD).
3. The evidence in the ENGP application that the ENGP is required and meets the public interest is incomplete and deficient in the following respects:
a) The application does not provide evidence of firm shipping contracts or identify with adequate detail refinery specific markets for the product being shipped. b) Although the application contains oil supply and pipeline capacity information, the application does not provide a pipeline demand and supply
Northern Gateway Joint Panel Review - CFN Written Evidence 9 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 analysis and therefore does not demonstrate that the ENGP is needed or required. c) The application includes an estimated benefit from shipping oil to Asia based on a forecast permanent Asian price premium and assumes that reducing oil volumes shipped to the US will result in a permanent increase in Canadian export prices without providing adequate evidence to support either of these claims. d) The application does not measure the contribution of the project to the Canadian public interest. Instead, the submission provides an estimate of gross economic impacts instead of net economic impacts and incorrectly assumes that gross economic impacts are economic benefits. e) The application does not include economic, social, and environmental costs in the public interest analysis despite explicit NEB requirements to do so. f) The application uses inappropriate terminology and methodology that results in significant exaggeration of the economic impacts. Actual net economic and fiscal impact benefits will be much lower than the gross impacts forecast by Enbridge because most of the labour and capital employed on the ENGP would be employed elsewhere in the economy if the ENGP was not built.
4. To assess the need for the ENGP, supply and demand data for pipelines serving the Western Canada Sedimentary Basin (WCSB) from the Canadian Association of Petroleum Producers were examined. The data show that there is currently surplus pipeline capacity and with forecast pipeline additions there is enough capacity to meet demand until after 2020. Therefore, the data show that the ENGP is not needed or required during the forecast period to 2020 and building the ENGP as planned will result in surplus capacity.
5. Forecasting oil transportation requirements is subject to uncertainty. Different forecast assumptions will result in different capacity requirement conclusions and there are potential costs to both over- and under-estimating capacity requirements. The risk assessment indicates that there is greater likelihood that the need for new WCSB transportation capacity will be less than forecast. If demand is higher than forecast, there is sufficient lead-time to provide additional capacity to meet demand without risking shutting in of WCSB production. Further, if and when there is sufficient demand to justify consideration of the ENGP, the ENGP needs to be evaluated relative to other transportation options, many of which involve no risk of major marine oil spills, to ensure that the most cost-effective options are chosen.
6. To assess whether the ENGP meets the NEB public interest criteria, a benefit cost assessment (BCA) was conducted. The first stage of the BCA examined only the costs and benefits to the Canadian oil industry. Twelve different scenarios were tested and under all scenarios the ENGP is forecast to result in a net cost to Canada. The net costs range from $362.4 million to over $2.2 billion (2009 CAD). These estimates do not include any social or environmental costs. If social and
Northern Gateway Joint Panel Review - CFN Written Evidence 10 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 environmental costs such as the cost of oil spills, greenhouse gas emissions, social conflict, and other environmental impacts are included, the net cost of the ENGP to Canada would be significantly higher.
Conclusion 7. It is concluded that the Enbridge application fails to show that the ENGP meets the need and public interest criteria required for NEB approval. The evidence presented in this report also indicates that it is highly unlikely that the ENGP is needed or required within the forecast period to 2020 and that the ENGP is not in the Canadian public interest.
Part III, David Suzuki - Evidence on Aboriginal Perspectives on Development and Environment
In order for the JRP to better understand the views of CFN, CFN would like to provide some contextual evidence from Canada‟s foremost ecologist, David Suzuki.
Relationship of Nature and Development In his book, The David Suzuki Reader9, Suzuki eloquently elaborates on the relationship of nature and development.
The way we see the world shapes the way we treat it. If a mountain is a deity, not a pile of ore; if a river is one of the veins of the land, not potential irrigation water; if a forest is a sacred grove, not timber; if other species are our biological kin, not resources; or if the plant is our mother, not an opportunity – then we will treat each other with greater respect. That is the challenge, to look at the world from a different perspective (page 11), … I believe that one of the reasons we seem unable to respond to the threats of human activity is that we no longer see ourselves as part of the natural world (page 13) ... Slow down and smell the roses. Recognize that we live in a world where everything is connected to everything else and so whatever we do has repercussions. There is a tomorrow and what we do now will influence what tomorrow we arrive at. We owe it future generations to think about them before leaping ahead (page 88).
Relevance of Aboriginal peoples’ views of the world David Suzuki in his book, Wisdom of the Elders10 notes the importance and relevance of aboriginal peoples‟ views of the world:
Traditional Native knowledge about the natural world tends to view all…of nature…as inherently holy rather than profane, savage, wild, or
9 Suzuki, David, The David Suzuki Reader, Greystone Books, 2003 10 Knudson, Peter and Suzuki, David, The Wisdom of the Elders, Stoddart, 1992
Northern Gateway Joint Panel Review - CFN Written Evidence 11 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 wasteland. The landscape itself, or certain regions of it, is seen as sacred and quivering with life. It is inscribed with meaning regarding the origins and unity of all life, rather than seen as mere property to be partitioned legally into commercial real estate holdings. The Native mind is imbued with a deep sense of reverence for nature. It does not operate from an impulse to exercise human dominion over it…Native wisdom tends to assign human beings enormous responsibility for sustaining harmonious relations with the whole natural world rather than granting them unbridled license to follow personal or economic whim…It regards the human obligation to maintain the balance and health of the natural world as a solemn spiritual duty that an individual must perform daily…The Native Mind emphasizes the need for reciprocity…to the natural world in return for the benefits they derive from it-rather than to extract whatever they desire unilaterally. Nature‘s bounty is considered to be precious gifts that remain intimately and inexorably embedded in its living web rather than as ‗natural resources‘ passively awaiting human exploitation. (pp. 13-15).
David Suzuki quotes two Aboriginal people to illustrate their relationship with the environment and how they view it not simply as natural resources to exploit:
“If the water can no longer support the salmon, if the land can‘t support the deer and bear, then why do we think it will support us (Simon Lucas, Nuu-Chah-Nulth chief, page xxvii)
“The river is like our refrigerator that keeps fresh meat. The forest is like our drug store that has our medicines. It is like a supermarket with all of the food and things we need. Why would we poison our water or clear the forest?” (Paiakan, a Kayapo Indian from the Xingu River area page xxxii - iii).
Environmental Protection David Suzuki goes on to discuss the need for environmental protection of areas of ecological importance, such as are found in the area impacted by the NGP Project:
The science of ecology waxes metaphorically eloquent on the intrinsic value of ecological ‗sanctuary.‘ Embedded in the …models of nature…lies an unspoken recognition that certain geographical spaces, species, and processes, within the whole may be exceptionally critical and vulnerable to damage. An Atlantic coastal estuary, for instance, with its spectacular seasonal influxes of shrimp, crab, and fishes may be so vital as a nursery area for future generations that it might be absolutely essential to the well-being of the whole coastal ecosystem to protect it as a breeding ;sanctuary.‘ Similarly, a few groves of trees high in the mountains of central Mexico may turn out to be an absolutely
Northern Gateway Joint Panel Review - CFN Written Evidence 12 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 critical terrestrial reserve that guarantees the survival of the migratory monarch butterfly on its transcontinental pathway (pages 16-161).
Challenges Facing Decision-Makers David Suzuki describes the following issues facing the world and decision-makers such as the JRP:11
a) Need for Environmental Prevention - The challenge of our time is to see that humanity as a whole has become that rampaging alien, to use our foresight and judgement to undertake preventative measures, and to marshal the kind of response we would get if there really was an invasion from outer space. (page 13) b) Need for Informed Decisions - The ever-increasing list of ecological crisis…makes it obvious that we lack enough hard data about the species makeup and their interaction in the planetary biosphere to act in an informed way (page 27). c) Need to Protect Biodiversity - We ought to be putting our effort into determining the extent and importance of this diversity, not destroying it before we have even found it (Page 29). The demand of the industrialized countries for a constantly expanding economy and for more consumer goods is the direct cause of the current species extinction that has no counterpart since the dinosaurs disappeared (page 43). d) Need to not mistake information for knowledge - In past decades, the scientific community has undergone a tremendous expansion and knowledge has increased proportionately. However, too often the accumulation of information is mistaken for knowledge that provides understanding and control. We can‘t afford to make such an assumption, because it fosters the terrible illusion that we can ―manage‖ wilderness and it has resulted in destructive consequences. (page 45). e) Need to consider the effects of climate change - If greenhouse gases are not brought into equilibrium, the consequences will be catastrophic. For the web of life on earth, even small shifts in average global temperatures will have huge repercussions. The atmosphere and air quality will change. Climate and weather will become even more unpredictable (page 63)…The most predictable consequence of warming is the effect on the oceans. When water warms, it expands. When a mass of water as an ocean heats up even a bit, sea levels rise. As a result, ocean currents are changed, marine ecosystems altered, and plankton populations affected. Warmer oceans will increase the intensity of tides, storms, erosion…A sea level rise of even centimetres will greatly affect human societies. Coastal areas will experience storms of greater intensity and frequency. (page 64) f) Need for development to be sustainable - I‘ve long argued that global economics underlies the current wave of ecological destruction and must be altered if we are to have a sustainable future…We live like an advanced nation
11 The David Suzuki Reader, Greystone Books, 2003
Northern Gateway Joint Panel Review - CFN Written Evidence 13 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 and finance the illusion with income generated by exporting raw materials (page 132).
Coastal First Nations and Sustainable Development David Suzuki was an important figure in assisting coastal First Nations to develop a sustainable model of development and in establishing an organizational structure (which has now become known as the Great Bear Initiative) to implement it. He discusses this background in the David Suzuki Reader:
In the mid-1990‘s, the David Suzuki Foundation began to establish relationships with First Nations communities in remote areas along British Columbia‘s north and central coast, including Haida Gwaii. Together, the foundation and the First Nations formed Turning Point (now CFN), an organization of First Nations working together and supporting each other to protect their traditional lands. In April 2001. the B.C. government signed a historic document with the Turning Point First Nations entering into agreements to negotiate the future of the land. Forest companies, environmental groups, ecotourism companies, and local municipalities added their support….It is now time to see whether all the goodwill and support will result in First Nations control over their lands and their use in an ecologically sustainable way (page 49). Part IV, Evidence with Respect to Spill Prevention
Oil Spills are Inevitable The inevitability of oil spills were first identified by Chris Joseph and Dr. T. Gunton, Director of the Resource and Environmental Planning Program at Simon Fraser University, in a report prepared for CFN in 2008.12
Impacts of spills are significant…Consequences of a major oil spill would be catastrophic for the environment… [despite] Mitigation measures to address spills [such as] scheduling and siting shipping routes such that spill impacts are minimized, operational procedures such as regular inspection routines, requiring tankers to be double hulled, adopting regulations such as mandatory tanker speeds near port, and contingency planning to address spills and coordinate clean ups. The key lesson from oil spill research is that while prevention of spills is the best defence, accidental spills are inevitable.
12Chris Joseph & Dr. Thomas Gunton, School of Resource and Environmental Management, Simon Fraser University, Review of Environmental and Socio-economic Impacts of Port Development and Shipping on the North Coast of British Columbia, April 21, 2008, pages i and ii.
Northern Gateway Joint Panel Review - CFN Written Evidence 14 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Measures Proposed by NGP to prevent Spills BGP states that it is committed to „world class standards‟ for its project (Vol. 8A) and that it is committed to “meeting or exceeding minimum regulatory requirements and industry practice to drive the possibility of an accident or malfunction to as close to zero as practical during the life of the Project.‖13
The main measures proposed by NGP to prevent marine oil spills from tankers are: a) The use of double hull tankers; b) Tanker Acceptance Program (TAP) to screen out unacceptable tankers; c) Operational safety limits. d) Pilots on board laden tankers within the CCAA; e) Escort tugs within the CCAA;
Double Hull Tankers do Not Prevent Incidents NGP has committed to use only double hull (DH) tankers. However, while DH tankers may reduce oil spill volumes, they do not eliminate the possibility and risk of an incident.
Limitations of Double Hull Tankers A report prepared by Living Oceans Society, Tanker Technology: limitations of double hulls, notes that DH tankers, while designed to reduce the size of spills, may in fact have design features that may increase the risk of spills themselves. That report concludes that:
DH tankers may reduce the severity of an oil spill but they are susceptible to a range of design, construction, operation, and maintenance issues, some which may actually increase the risk of an oil spill. Furthermore, double hulls do not address the role of human factors in tanker casualties which have been attributed to as much as 80 percent of oil discharges. Poorly designed, constructed, operated and maintained DH tankers have as much, if not more, potential for disaster compared to single-hull designs.”14
Double Hull Tanker Incidents NGP acknowledges that approximately 30 DH tanker incidents with spills have been reported over the past 20 years.15 At least one of these, the Volgoneft, spilled 1300 tonnes of oil in the Black Sea after suffering a structural failure during a storm on November 11, 2007. However, NGP, despite multiple Information Requests, has refused to provide any analysis of these incidents. Therefore, it is difficult to assess the extent to which DH reduces the risk of an oil spill.
13 NGP Response to CFN IR 1.2 j 14 Terhune, K. (2011). Tanker Technology: limitations of double hulls. A Report by Living Oceans Society. Sointula, BC: Living Oceans Society. www.livingoceans.org
15 NGP Response to CFN IR 1.5a
Northern Gateway Joint Panel Review - CFN Written Evidence 15 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 The evidence presented here, clearly shows that there have been numerous DH tanker incidents in similar waters as the OWA and that some of these are attributed to Non Accidental Structural Failure (NASF) incidents.
CFN had Dr. Gerald Graham, an expert in spill response and marine safety, review the NGP Application.16 Dr. Graham reported that there has been a spate of serious oil spill incidents involving double hull tankers over the years including:
Double Hull Tanker Incidents Motor Year Location Cause/Nature of Amount/Type Vessel Incident of Oil Spilled Bunga 25 May, Strait of Malacca Collision 18,325 Kalena 2010 barrels Eagle 23 Jan. Sabine/Neches Collision with 10,714 Otome 2010 shipping barge barrels est. channel, Texas, Volgoneft 11 Nov. Black Sea Structural Failure 1300 tonnes 139 2007 During Storm HFO Limburg 6 Oct. Yemen Suspected ? 2002 Terrorist Attack Baltic March 29, Baltic Sea 2700 tonnes Carrier 2001 HFO
Double Hull Tankers are Prone to Corrosion NGP has consistently claimed that tanker incidents in the OWA are unlikely (has refused to acknowledge the risk or possibility of NASF incidents and consequently, that related oil spills in the OWA are „not credible‟. As a result, NGP has: not consulted with potentially impacted parties; not provided baseline information; not proposed further measures to prevent or mitigate incidents and spills in the OWA; refused to consider incidents caused by structural and mechanical failure.
The evidence presented below illustrates that DH tankers are susceptible to corrosion. Design measures to reduce corrosion and regular thorough inspections are, therefore, important measures to prevent or mitigate the risks of DH tanker incidents and spills.
16 Gerald Graham, B. A., M. A., Ph. D., President, Worldocean Consulting Ltd, Marine Oil Spill Aspects of the Northern Gateway Project, A Review of Enbridge‟s NEB/CEAA Application, Prepared for Living Oceans Society and Coastal First Nations Great Bear Initiative, Final Report, 9/9/2010. Dr. Graham: is a Canadian Coast Guard-trained On Scene Commander for oil spill response; was a Principal Consultant on a program review of the entire federal EARP process; Consultant to the Public Review Panel on Tanker Safety and Marine Spills Response Capability
Northern Gateway Joint Panel Review - CFN Written Evidence 16 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 CORFAT. A report prepared for CORFAT, Cost Effective Corrosion and Fatigue Monitoring for Transport Products Report states that:
Corrosion damages and fatigue cracks are the main causes for structural failures of all surface transport products like ships [emphasis added]…In order to prevent those structural failures, maintenance and inspection has to be carried out… Many examples have been experienced, where weakened structures have failed to withstand severe operating conditions. Accidents of oil tankers have led to tremendous pollution of the environment and subsequent to economical loss in large costal areas. The most well known have been those of the tankers ―Erika‖ and ―Prestige‖...detection and discrimination of corrosion attack on ships (oil tankers) with Acoustic Emission…pointed out, that AE is capable of detecting corrosion inside ballast tanks as well as cargo tanks as cargo tanks.17
European Maritime Safety Agency The European Maritime Safety Agency study18 on corrosion in DH tankers found that a significant number of DH tankers suffer from accelerated corrosion in areas of their cargo and ballast tanks due to a „thermos bottle effect‟, in which heated cargoes retain their loading temperatures for much longer periods, thereby promoting an environment that is more aggressive from the viewpoint of corrosion.
―Individual tankers usually exhibit a unique, but controllable corrosion pattern. However, recent experiences of OCIMF members have indicated problems in new single and double hull tonnage from excessive pitting corrosion of up to 2.0 mm per year in the un-coated bottom plating in cargo tanks due, inter alia, to microbial induced corrosion processes. In addition accelerated general corrosion up to and exceeding 0.24mm per year has been found in vapour spaces. This type of wastage and the increased rate of corrosion, which is much greater than that which would be normally expected, give cause for serious concern [emphasis added].‖
They recommended that the following measures be implemented:
Establish a mandatory performance standard for ballast tank coating systems in new vessels. Establish mandatory provisions for coating the deckhead and tank top structures within the cargo tanks of new vessels.
17 http://www.corfat.eu/background/ 18 European Maritime Safety Agency, Double Hull Tankers, High Level Panel of Experts Report, June 3, 2005 http://www.seas-at-risk.org/1mages/EMSA%20DH%20high%20level%20experts%20report.pdf
Northern Gateway Joint Panel Review - CFN Written Evidence 17 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Establish a mandatory performance standard for cargo tank coating systems in new vessels. Ballast tank coatings should be effectively repaired following breakdown. Double hull tanker structures should be maintained effectively. Fixed hydrocarbon gas detection system to be provided in spaces adjacent to cargo oil tanks (page20).
National Academies, Journal of Protective Coatings & Linings Further evidence is provided by one of the world experts on tanker corrosion, Mr. Rodney Towers, in his report, Accelerated Corrosion in Cargo Tanks of Large, Double-Hull Ships: Causes and Countermeasures. Mr. Towers noted that:
accelerated corrosion in the cargo tanks of large tankers has increasingly caused concerns that have triggered technical reevaluation of both the causes of corrosion as well as countermeasures for achieving better structural preservation. This article looks at … how new corrosion issues can stem from both the hull design and the cargo tank environment. It also proposes a coating specification for the long-term protection of tanks against the effects of corrosion. The generally higher level of temperatures now being sustained within cargo tanks is a consequence of the thermos flask effect. When coupled with uncoated inner tank bottoms, this effect seems to be creating an optimum environment for microbial accelerators of corrosion. Two other factors may play a part in accelerating the corrosion process in double-hull tankers: the thermomechanically controlled process of steel production and the behavior and content of inert gas in ullage spaces…For long- term performance, the best approach to cargo tank specifications is to replace modified epoxies with pure epoxies.19
Maritime Activity Reports The concerns about tanker corrosion have obviously not gone away. More recently (2011), Ed Jensen, of Antwerp-based Expertise en Ingenieursbureau Touw-Jansen, a specialist marine consultancy firm, elaborated on the issue in The Maritime Activity Reports, 2011.
Mr. Jensen notes that corrosion is particularly damaging for ships with high levels of high-tensile steel. Their increased flexing during voyages leads to higher levels of flaking. Flaking exposes fresh areas of steel for the corrosive solubles to do their damage. According to Jansen, "By encouraging flaking, high-tensile steel is its own worst enemy." 20
19 Towers, Rodney, Accelerated Corrosion In Cargo Tanks Of Large, Double-Hull Ships: Causes And Countermeasures, Transportation Research Board of the National Academies, Journal of Protective Coatings & Linings, Volume: 17, Issue Number: 3, 2000-3. http://trid.trb.org/view.aspx?id=651843
20 Maritime Activity Reports, Double Trouble? Double Trouble?, 2011 http://www.maritimecommunications.com/world-ports-~2d-top-20/double-trouble-208900
Northern Gateway Joint Panel Review - CFN Written Evidence 18 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011
When the first generation of double-hulled tankers were taken into service, their owners were startled to find that their state-of-the-art ships were rotting away almost twice as quickly as single- hulled tankers. Pitting corrosion in the inner tank top plating was taking place at an annual rate of between 1 mm and 2 mm. In some instances, pits developed as deep as 7 mm to 9 mm within five years. That's 40 percent of the original plating thickness."
Mr. Jensen goes on to reiterate, and elaborate on, Mr. Tower‟s explanation for the technical reason for corrosion in DH tankers:
Oil in double-hulled tanks takes an average of 20 days to reach sea temperature, he adds. The significance of the longer cooling down period is found in the lifecycle of corrosion inducing bacteria. The bacteria survive longer in the warmer oil in double-hulled ships, lengthening the electrochemical corrosion process that naturally occurs at the bottom of cargo tanks on board oil carriers. Not only do the bottom of tanks on board doublehulled vessels rust more rapidly, under- deck plating and ullage areas are more prone to corrosion as well.
The reason for this is a different one, however. Here, it is the choice of construction material that is significant. To offset the increase in weight due to the extra steel required for double-hulled newbuilds, shipyards incorporated higher levels of high-tensile steel into their designs. "High- tensile steel ships are subject to greater degrees of hull flexing at sea. This is important when you consider the corrosive processes in under- deck and ullage spaces." During ballast voyages, inert gas is pumped into the cargo tanks of tankers to prevent the build up of flammable gases from cargo residues. Inert gas is also used to fill up the ullage space left after a cargo has been loaded. The gas used is generally pumped in at a temperature of roughly 45 degrees Celsius. At night, the natural drop in temperature will cause the gas to cool to around 20 degrees Celsius. Even the thermos-flask characteristics of a doublehulled ship cannot prevent this. As a result, the walls lining the spaces filled with gas are covered in condensation. The condensation dissolves solubles in the inert gas mixture that trigger the corrosion process."
Natural Resource Defence Council Secondly, the corrosive potential in tankers may be increased because of the potential corrosiveness of the DilBit cargo proposed by NGP to be carried on tankers. While NGP has refused, despite Information Requests (e.g. NGP Response to CFN IR1.5 c), to fully explore this issue, we have the evidence presented by the Natural Resources Defence Council. In their study, Tar Sands Pipelines: Presenting Unaddressed Hazards
Northern Gateway Joint Panel Review - CFN Written Evidence 19 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 to Public Safety: Tar Sands Pipeline Safety Backgrounder, NRDC suggests that corrosion is an issue, not only for pipelines, but also tankers. The study notes that DilBit is more highly corrosive to pipelines than conventional crude. It contains fifteen to twenty times higher acid concentrations than conventional benchmark crudes13 and five to ten times as much sulphur as benchmark crudes,14 which can lead to the weakening or embrittlement of pipelines.21
Older Tankers have more Incidents CFN would like to offer evidence to illustrate that younger tankers are less prone to incidents and spill.
NGP has refused CFN‟s requests that to commit to using tankers younger than 10 years old as a way of preventing oil tanker incidents and spills (NGP response to CFN IR 1.3 d) despite claiming that it is committed to „world class standards‟ for its project (Vol. 8A) and that it is committed to “meeting or exceeding minimum regulatory requirements and industry practice to drive the possibility of an accident or malfunction to as close to zero as practical during the life of the Project” (CFN IR 1.2 j).
Conference of Schiffbautechnische Gesellschaft Proceedings A recent study (2009), Assessment of Safety of Crude Oil Transport by Tankers, reports that oil tankers older than ten years tend to have significantly higher Non- Accidental Structural Failure (NASF) frequency rates than younger tankers (about 78% of all Non-Accidental Structural Failure accidents involve ships older than ten years).22
Since the average age of the Double Hull fleet is currently about seven years, it can be expected that typical age-dependent accidents will start to become a significant occurrence after about 2020 (approximately four years after the Project is scheduled to come on stream).
While NGP states that it will not commit to only using tankers less than 10 years old, it is clear that there will be more than a sufficient number of younger tankers available for their use by 2020. The statistics for the world tanker fleet, as of January 2009, indicates that only 12% of the world‟s Aframax tanker fleet was older than 20 years; 10% of the Suezmax fleet; and 5% of the VLCC fleet.23
Additional Redundancy Features Not proposed by NGP to Reduce Risk CFN would like to offer the following evidence to illustrate that there are additional redundancy measures available to reduce the risk of incidents and spills.
21 Natural Resources Defence Council, Tar Sands Pipelines: Presenting Unaddressed Hazards To Public Safety: Tar Sands Pipeline Safety Backgrounder, December 2010. http://dirtyoilsands.org/files/NRDC_TarSandsBitumen.pdf
22 Papanikolaou, A., Eliopoulou, E., Hamann, R., Loer, K., Assessment of Safety of Crude Oil Transport by Tankers, Proc. Annual Main Conference of Schiffbautechnische Gesellschaft (STG2009), Berlin, November, 2009, P. 6. 23 Source: Intertanko Tanker Facts 2009, Chart, labeled “Tanker and combined fleet details as at January 2009 ( above 10,000 dwt ), P. 3.
Northern Gateway Joint Panel Review - CFN Written Evidence 20 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011
NGP, despite acknowledging that using tankers with double engine rooms, double screws and double would reduce the probability of grounding and under certain circumstances also the probability of collision for tankers without tug escort and could reduce the risk of oil spills, refuses to commit to the use of tankers with extra redundancy features (NGP response to CFN IR 1.4a).
Maritime Industry Foundation Knowledge Centre The Maritime Industry Foundation Knowledge Centre identifies that there are oil tankers available to NGP that incorporate other extensive safety features from double hulls, double engine rooms, propulsion and steering equipment currently available and being built. NGP has identified 20 such tankers but has refused to provide information on how many others are being built (NGP Response to CFN IR 1.4 b).24
Alaska Oil Spill Commission The Alaska Oil Spill Commission found that:
Studies suggested that the Alaska spill could have been reduced or eliminated by building in redundant protection: in that case, by equipping tankers with double hulls or double bottoms. A lack of redundancy has emerged as a critical problem in the gulf, where the failure of the Deepwater Horizon's blowout preventer -- designed to instantly seal a well -- has left BP with few alternatives.25
Inadequate Tanker Acceptance Program (TAP) Standards As NGP notes26, the objective of TAP is to prevent substandard tankers from entering and transiting Canadian waters…and to ensure that a “nominated tanker meets the Northern Gateway standards.” TAP is the primary measure that NGP will use to ensure that its commitments for measures to prevent incidents and manage navigation issues and marine safety, are implemented, monitored and enforced. This is important because, while NGP is the proponent of the Project, it is the tanker owners who remain liable for any oil spills outside the port of Kitimat. Accordingly, the tanker standards and operational rules have to maximized to ensure that risks to the marine environment are minimized.
Standards The evidence presented by CFN suggests that close scrutiny must be paid to NGP‟s commitment to adhere to the TAP (Commitment No. J17) and that TAP needs to be expanded to include, among other things: Only using tankers younger than 10 years old;
24 http://www.maritimeindustryfoundation.com/guide/id/194.htm
25 Jo Stephens, The Valdez’s Unheeded Lessons(Washington Post, July 14, 2010). 26 NGP Response to CFN IR1.6 b
Northern Gateway Joint Panel Review - CFN Written Evidence 21 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Only using tankers constructed with anti-corrosion measures; - it should be made clear, whether current standards that exist, and may be adopted by NGP in its TAP, include the recommendations made by the European Maritime Safety Agency report referenced above (page 15). Only use tankers with extra redundancy features; Third party and First Nation oversight to ensure that regular and through inspections for corrosion are conducted.
The evidence suggests inspections and maintenance are key features in reducing the risk of incidents (especially NASF incidents in the OWA).
Inspections NGP‟s notes27 that inspections will be carried out under the Oil Companies International Marine Forum (“OCIMF”) Ship Inspection Report (“SIRE”) based on inspection and information from OCIMF certified inspectors. However, the NGP response goes on to suggest that there may be times when a tanker may be contracted without clear indications of having been thoroughly inspected:
―There are times when the owner‘s clarification may not be clear and additional information is necessary. This information may require a tanker visit by a third party inspector. Depending on the outstanding requirement, the tanker might be boarded by the inspector at the port prior to the Northern Gateway terminal or the inspector might board with the pilot, and complete the inspection before the tanker begins its passage in the Confined Channel Assessment Area.‖
Further, CFN feels strongly, that the JRP in its assessment and its consideration of the adequacy of measures proposed by NGP, consider: The need for third party and First Nation inclusion in decisions on TAP Standards; The need for third party and First Nation oversight of compliance with TAP; The need for third party and First Nation oversight of inspections; The nature of Transport Canada inspections (nature, frequency, qualifications of inspectors, number of inspectors) which NGP notes, in its response to CFN IR1.6 h, that tankers may also be subject to Port State Inspection by Transport Canada.
Canada’s Inadequate Inspection Regime The 2011 December Report of the Commissioner of the Environment and Sustainable Development28identified many deficiencies with Transport Canada‟s monitoring regimes for marine transport, and concluded that:
27 response to CFN IR 1.6 b 28 http://www.oag-bvg.gc.ca/internet/English/parl_cesd_201112_01_e_36029.html#hd3c
Northern Gateway Joint Panel Review - CFN Written Evidence 22 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 1.79 Transport Canada has not designed and implemented the management practices needed to effectively monitor regulatory compliance with the Transportation of Dangerous Goods Act, 1992. Key elements that are missing include a national risk-based regulatory inspection plan and necessary guidance for inspectors. In many instances, the nature and extent of the inspections carried out are not documented. We noted that there was little indication that the Department had followed up on identified instances of non- compliance to ensure that regulated organizations transporting dangerous goods had corrected the problems identified.
1.80 Transport Canada is not adequately reviewing and approving the emergency response assistance plans submitted by regulated organizations. Nearly half the plans submitted have been provided only an interim approval. Many of the organizations shipping dangerous goods have operated with an interim approval for over 5 years, and some for over 10 years.
1.81 Some of the issues contained in this report are not new. A 2006 departmental internal audit identified similar issues. Five years later, the Department has yet to address the identified weaknesses in its management practices.
Incidents are caused by Human Error Human error is a significant cause of marine vessel and oil tanker incidents. Human error was a cause of the two most significant marine vessel incidents that have occurred near the Project area are the Exxon Valdez and the MV Queen of the North incident near Hartley Bay.
Tanker Captains Evidence of human error induced incidents is provided the Danish company, Learning Labs:
Several characteristics serve to classify the oil tanker industry as a risk inducing system…It is up to the individual captains to avoid collisions. Therefore, most of the accidents at sea occur due to human error. Several factors increase the possibility of human error. Captain alone has the responsibility - in contrast to airplanes where the second pilot has more to say. Also, a higher degree of risk acceptance belongs to the traditions of the sea, increasing the irresponsible behaviour of the crew and captain. This was the case when Exxon Valdez struck a reef when the captain was drunk. Captains often work 48 continuous hours and communication failures on the bridge and between ships are frequent, since the crews do not share the same native language.29
29 Learning Labs, Denmark, ID:02, http://www.hazardcards.com/research.php?aid=23
Northern Gateway Joint Panel Review - CFN Written Evidence 23 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Similarly, the evidence of the two experts retained by CFN note in their evidence presented in Appendix 2 of this submission, that there is a further contributing factor to potential incidents: cost considerations affecting navigation decisions taken by vessel Captains and ship owners. This inbuilt bias affects Captain‟s decisions and induces risk-taking.
Tanker owners, their agents and ships captains have a strong monetary interest in minimizing the time involved in transporting their cargo and, therefore, tend to be concerned about measures that can cause delays.
the time – cost factor will be an important consideration when ships captains face severe weather conditions and make decisions about proceeding, finding shelter, waiting or riding out the storm.
Incidents attributed to Human Error Further evidence of the importance of human error in marine incidents is provided by The International Oil Tanker Owners Pollution Federation (ITOPF), a not-for-profit organisation established on behalf of the world's ship owners to promote effective response to marine spills. The ITOPF notes that:
80% of oil tanker accidents which cause oil spills at sea are a result of human errors. 30
International Maritime Organization Recommendations Further evidence of the need to address the issue of human error, is provided by the IMO itself, which recommends that a quantitative human error rate prediction analysis and assessment of the human failure contribution in the collision and/or grounding of oil tankers be done.31. NGP has refused to do such a study.32
Without the information and analysis, it is difficult to determine the adequacy of the measures cited by NGP to deal with human error (certification of ship personnel; compliance with International Maritime Organization standards, the presence of pilots, and the tanker operators‟ own drug and alcohol standards.
Evidence regarding the degree to which NGP is fully committed to, as it states, meet „world class standards‟ for its project (Vol. 8A) and that it is committed to “meeting or exceeding minimum regulatory requirements and industry practice to drive the possibility of an accident or malfunction to as close to zero as practical during the life
30 http://www.itopf.com/. Also see Trends in Oil Tanker Spills from Tanker Ships, 1995-2004, by Keisha Huijer, ITOPF http://www.itopf.com/_assets/documents/amop05.pdf
31 Guidelines for Formal Safety Assessment of the International Maritime Organization http://www.imo.org/Pages/home.aspx http://www.imo.org/ourwork/safety/safetytopics/pages/formalsafetyassessment.aspx
32 Response to CFN IR 1.7 h
Northern Gateway Joint Panel Review - CFN Written Evidence 24 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 of the Project” 33is provided by NGP itself. CFN requested detailed information from NGP (CFN IR1.7 f) on the issue of human error in order to assess the risk of tanker incidents and spills and to identify the type of prevention measures that could be employed to reduce the risk of another Exxon Valdez or Queen of the North incident. However, NGP declined to provide the information stating that “To provide a response would require an extensive manual review of incident specifics, something Northern Gateway is not prepared to undertake.”
Local Experts Further evidence on human error is provided by the two experts retained by CFN whose evidence is provided in Appendix 2 of this submission. The two experts note that:
There may be many reasons for incidents attributable to human error. But in our experience, the main causes are poor communications due to language differences. While, alcohol, drugs, and fatigue may be other factors (e.g. Exxon Valdez), in our experience alcohol is rarely encountered.
While the language of marine transport is English, the primary language of many crew members is not. This can create problems, especially in emergency situations.
Rules of work designed to prevent human error, are not always followed by ship captains, especially in poor weather conditions. We also believe that such rules do not apply to tug captains.
In our experience, it is unusual to see alcohol problems on piloted vessels because, like alcohol related automobile regulations, the worldwide shipping industry has adopted Drug and Alcohol Guidelines. Accordingly, it is not an issue of law so much as one of enforcement. Having pilots on board vessels acts as a deterrent to alcohol and drug use.
While, a pilot leaving Kitimat could refuse to sail if he/she suspected a problem with alcohol or drugs, we understand that in the U.S.A. there are spot checks by regulators to prevent such problems.
We feel that mandatory alcohol and drug testing for all officers and crew on tankers trading in Canadian waters could also serve as a deterrent, and prevent alcohol and drug related problems. If so, then Pilots should also be scrutinized to avoid cries of discrimination.
Need for Drug and Alcohol Testing Evidence suggesting deficiencies in leaving drug and alcohol testing to tanker owners‟ standards is provided by Jeff Gray (The Developing Law around Drug, Alcohol Tests, Globe and Mail, June 15, 2010). Mr. Gray suggests that this runs contrary to the
33 CFN IR 1.2 j
Northern Gateway Joint Panel Review - CFN Written Evidence 25 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 direction Canadian oil companies themselves want to go. He attributes this to the risks and potentially large liabilities oil companies they would face.
Both the BP oil spill in the Gulf of Mexico and the rupture of the Exxon Valdez oil tanker off the coast of Alaska in 1989 left oil-soaked birds, ruined shorelines and economic woes in their wake. But the Valdez accident also had a wider impact on employment law in North America. According to witnesses in the court battles after the Alaska disaster, the captain of the Valdez had downed five double vodkas at waterfront bars before taking the helm. This accounts for the Alaskan catastrophe‘s other legacy: A push by oil companies and other industries to test employees in dangerous jobs for drugs and alcohol.
Some testing, such as in cases when an employer has ―reasonable cause‖ to suspect a worker in a safety-sensitive job is impaired, is generally allowed in Canada. Workers can also be tested as part of a package of conditions for returning to work after being caught for drug or alcohol abuse … Lawyers who act for employers point to a key case, known as John Chiasson v. Kellogg, Brown & Root (Canada) Co., ... In that case, the Alberta Court of Appeal upheld the right of employers to administer drug tests to applicants for safety-sensitive posts even before they are hired, and to choose not to take on casual marijuana users.
Dan Scott, of Seveny Scott Lawyers in Edmonton …believes big oil companies will continue to bring in new testing policies, even if they could face sanctions from human-rights tribunals. The reason, he suggests, is simple: The penalties they face for violating an employee‘s human rights pale in comparison with the millions of dollars in fines or cleanup costs after a major accident.
Weather Conditions affect Operational Safety The following evidence supports other important considerations regarding operational safety: a) Severe weather conditions in the Hecate Strait, Dixon Entrance and Queen Charlotte Sound are a frequent occurrence; b) Severe weather conditions account for a number of marine incidents (i.e. mechanical failure); c) Risk management considerations.
Expert Knowledge Two experts on navigation and weather conditions [see Appendix 2 of this evidence, Marine Navigation: Measures to Reduce the Risk of Martine Incidents] note the following:
Northern Gateway Joint Panel Review - CFN Written Evidence 26 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 In our experience, weather conditions in the Queen Charlotte Sound, Dixon Entrance and Hecate Strait can be severe enough to affect navigation, create vessel problems and increase the risk of incidents:
There is no storm like Haida Gwaii storms during the fall and winter months;
The Dixon Entrance can be one of the worst areas due to the geography and currents in stormy weather;
Hecate Strait is very shallow and strong winds cause large waves and very strong tides;
Severe weather conditions are not limited to the Winter months - „Screaming‟ Northwest winds also occur in the summer;
There are occasions when waves can be large enough to allow the sea to come in thru air intakes creating mechanical failure;
While we do not believe fog to be a problem, mixed rain and snow can create hazardous visibility situations;
Inadequate Measures to avoid Severe Weather Conditions in the OWA Severe weather conditions influence navigation decisions (maintain course, ride out the storm, anchor and drift, find shelter or places of refuge, etc.). Severe weather conditions also can impede the boarding /disembarking of pilots and spill response and can increase the risk of an incident.
NGP proposes to prevent incidents related to navigational issues by establishing Operation Safety Limits sometime after the Project is approved. These Operation Safety Limits will include the identification of anchorages that “would only be necessary in the event of mechanical failure or severe weather conditions.” 34
The reason this evidence is important is that it illustrates that limitations of advance warning to avoid severe sea conditions. Proposed measures to either keep tankers in port or to keep them from entering the CCAA will be of no use should storms arise quickly.
Severe Sea Conditions arise without Warning The evidence of the severe weather conditions in the area, and the fact that they can arise very quickly, is provided by Owen S. Lange, in his book, Living with Weather along the British Columbia Coast.
34NGP response to Gitxaala, IR 1.10.8.3
Northern Gateway Joint Panel Review - CFN Written Evidence 27 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 The highest recorded extreme waves are over 30m (100 feet) recorded at both the South Hecate buoy and the East Delwood buoy. A 30 metre wave was also recorded by the drilling rig Sedco 135F working in Queen Charlotte Sound, south of Cape St. James, on 22 October 1968. While these waves are huge, the more dangerous aspect is the rate that they can build from almost nothing to frightening heights. In the 1968 case the seas rose from three metres to 18 metres in just eight hours.‖[Emphasis added]35
A more recent example of the quicker than expected arrival of storms affecting navigation in the OWA is that of the new BC Ferry, MV Northern Adventure, which was forced by waves exceeding 10 metres to return to port after attempting to ride out the storm for four hours.
Monday, November 23, 2009 04:50 PM, Prince George, B.C. It was toss and turn on high seas between Prince Rupert and the Queen Charlotte Islands last night. The Northern Adventure Ferry left Prince Rupert at 11:00 last night and a predicted storm hit earlier and harder than expected. The Ferry was battling high seas, and stopped engines to ride it out. The ferry was tossed around enough says B.C. Ferries Media spokesperson, Debora Marshall, to throw crew members and some passengers around causing some to suffer bumps and bruises. ―Some dishes smashed in the galley and the gift shop suffered some damage as well.‖ The Northern Adventure turned around at 8:30 this morning and made it back to Prince Rupert. There will be no sailing tonight, Marshall says the cancelled sailing for this evening is to allow crew to get some rest "They haven't had any sleep for 30 hours, so they need to get some rest". The forecast calls for high seas again, with waves of 4-6 metres (19.69 feet) tonight, building to 6-8 metres (26.25 feet) in the morning.36
Marine Incidents and Weather Dr. Gerald Graham, in his review of the Application for CFN noted:
the risk of a catastrophic oil spill is arguably greater in the OWA than within the CCAA…NASF [Non-Accidental Structural Failure] incidents account for a significant percentage of tanker incidents, as well as tanker incidents involving oil spills. In other words, tankers founder not just because they hit a rock, break apart and then sink; they can simply break in two after being buffeted by storms on the high seas, i.e. in ‗open water‘. And while the CCAA may present greater navigational challenges than the OWA, the conditions (winds and waves) in the OWA
35 Owen S. Lange, The Veil of Chaos, Living with Weather Along the British Columbia Coast, Environment Canada, 2003, P. 160. 36 http://www.opinion250.com/blog/view/14701/1/northern+adventure+ferry++cancelled++after++rough+r ide
Northern Gateway Joint Panel Review - CFN Written Evidence 28 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 tend to be worse than in most parts of the CCAA, the OWA is more exposed.
Dr. Graham notes that the International Tanker Owners Pollution Federation (ITOPF) statistics indicate that structural failure, with the tanker breaking in two, occurs not infrequently. For the period from 1970 to 2009, for spills greater than 700 tonnes, hull failure accounted for 12.4% of them.37
Dr. Graham cites another study38 which identified: 151 or 18% of the 858 incidents involving large tankers between 1990 and 2008 were attributed to Non Accidental Structural Failure. a total of 102 incidents (serious and non-serious ) between 1990- 2008 were reported that involved an oil spill from a large tanker (11.888% of the large tanker incidents over that period involved an oil spill); 37% were the result of Non Accidental Structural Failure.
Dr. Graham provides two examples of Non Accidental Structural Failure that occurred in OWA type areas: December 12, 1999 - MV Erika incident broke in two and sank off the coast of Brittany, spilling 20,000 tonnes of Heavy Fuel Oil into the North Atlantic; Nov. 19, 2002 - MV Prestige broke in two and sank off the Spanish coast, spilling an estimated 63,000 tonnes of oil into the ocean off the coast of Galicia.
Consequences of Refuge Decisions The evidence of the importance of refuge areas is provided by Paul Albertson (Deputy, US Port & Environmental Management, U.S. Coast Guard) in a report presented at the International Oil Spill Conference in 2005 he discusses what occurred with the MV Prestige:39
When approximately 25 miles off the west coast of Galicia, Spain, it got caught in a severe storm and rapidly developed a 24-degree list to starboard due to flooding of the #2 aft starboard and #3 starboard wing tanks, which had sustained hull damage. Because of the list, fuel oil began spilling from butterworth openings onto the main deck and into the water. The Prestige also lost propulsion and began to drift. The crew was evacuated by helicopter, while the master, chief mate and chief engineer remained aboard to control the vessel. To right the Prestige
37 From Figure 9: Incidence of Spills > 700 Tonnes By Cause, From 1970 to 2009, ITOPF, Oil Tanker Statistics: 2009, P. 8 38 Papanikolaou, A., Eliopoulou, E., Hamann, R., Loer, K., Assessment of Safety of Crude Oil Transport by Tankers, Proc. Annual Main Conference of Schiffbautechnische Gesellschaft (STG2009), Berlin, November, 2009, Table 1, P. 4.
39 Albertson, LCDR Paul, U.S. Approach to Implementing IMO Guidelines On Places Of Refuge, International Oil Spill Conference, 2005, http://www.iosc.org/papers_posters/IOSC%202005%20a443.pdf
Northern Gateway Joint Panel Review - CFN Written Evidence 29 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 and stop the spillage of oil, the master ballasted the #2 aft port and #3 port wing tanks, which righted the ship and stopped the outflow of oil. This also added stress to the hull. The Prestige requested a place of refuge in order to transfer cargo and make repairs. However, the request was denied. Instead, Spanish authorities ordered the tanker to sea. As later noted by the American Bureau of Shipping, ―the additional dynamic wave loads to which the hull structure would be subject in open waters would lead to a progressive deterioration in the hull structure until ultimate failure.‖ The Prestige was towed seaward until November 19, when it broke in two and sank approximately 130 miles off the coast of Spain. Most of the tanker‘s load, approximately 17,000,000 gallons, is estimated to have spilled from the Prestige, affecting over 600 miles of coastline, fishing grounds, and wildlife. At a depth of 3,500 meters (11,483 feet), the Prestige continued to discharge oil, contributing to an overall slick that drifted in and around the Bay of Biscay and the westernmost reaches of the English Channel, ultimately contaminating the shorelines of six countries…The Prestige brings to light potentially conflicting interests in granting a place of refuge to a ship in need of assistance. If poorly managed, these conflicts can act like a “knot in the line” for efforts to ensure maritime safety and pollution prevention and response. [Emphasis Added]
Lack of Definition on Refuge Area Locations and Decisions on Use Since severe weather conditions can arise quickly in the OWA and tankers may have already entered into the area, the availability of refuge areas is an important consideration both for avoiding the weather and for dealing with mechanical problems or spills. The example of the MV Prestige illustrates the importance of knowing refuge places beforehand and how, under emergency situations on using them will be made. NGP noted there are no pre-designation of places of refuge in the Pacific Region.‖40
Since using refuges for stricken tankers could seriously impact First Nations Rights and Title, this is something of great concern to CFN. On the other hand, it is important to know if there are feasible places of refuge or shelter for tankers during severe weather conditions, as this could reduce the risk of an incident.
The identification of potential refuge areas in all areas of the OWA, and their feasibility for use, needs to occur at the Environmental Assessment stage, not afterward. This is no different than DFO‟s approach to habitat compensation: before a project, requiring fish habitat compensation, is approved, proponents must identify that there are suitable locations available for habitat compensation.
As evidence of the need to know if there are adequate and feasible places of refuge in all areas along tanker routes, we offer the following:
40 NGP response to CFN IR.1.14
Northern Gateway Joint Panel Review - CFN Written Evidence 30 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 International Maritime Organization (IMO) Captain Albertson goes on to note the importance placed on refuge locations in the event of a marine incident and spill by the IMO.
When introducing their guidelines on places of refuge, the IMO asserted the following line of reasoning:
1. ―When a ship has suffered an incident, the best way of preventing damage or pollution from its progressive deterioration would be to lighten its cargo and bunkers; and to repair the damage. Such an operation is best carried out in a place of refuge.
2. However, to bring such a ship into a place of refuge near a coast may endanger the coastal State, both economically and from the environmental point of view, and local authorities and populations may strongly object to the operation.
3. While coastal States may be reluctant to accept damaged or disabled ships into their area of responsibility due primarily to the potential for environmental damage, in fact it is rarely possible to deal satisfactorily and effectively with a marine casualty in open sea conditions.
4. In some circumstances, the longer a damaged ship is forced to remain at the mercy of the elements in the open sea, the greater the risk of the vessel‘s condition deteriorating or the sea, weather or environmental situation changing and thereby becoming a greater potential hazard.
5. Therefore, granting access to a place of refuge could involve a political decision which can only be taken on a case-by- case basis with due consideration given to the balance between the advantage for the affected ship and the environment resulting from bringing the ship into a place of refuge and the risk to the environment resulting from that ship being near the coast.‖ (IMO, 2003)
Pacific States/British Columbia Oil Spill Task Force The importance of places of refuge and the need to identify them is also one of the recommendations made in the report prepared for the Pacific States/British Columbia Oil Spill Task Force in April 2011:41
Canadian Federal and provincial agencies, First Nations, and stakeholders in British Columbia should consider identifying Potential Places of Refuge in
41 The Stakeholder Workgroup Review of Planning and Response Capabilities for a Marine Oil Spill on the U.S./Canadian Transboundary Areas of the Pacific Coast Project Report http://www.oilspilltaskforce.org/docs/notes_reports/Final_US_Canada_Transboundary_Project_Report.p df
Northern Gateway Joint Panel Review - CFN Written Evidence 31 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 their transboundary areas that could be considered (among other locations as appropriate) on an incident-specific basis during POR decision-making.
Pilots Do Not Eliminate the Risk of an Incident NGP proposes using pilots on board tankers in the CCAA but not the OWA (except in possibly a very limited way). The evidence that having Pilots on board vessels does not eliminate the risk of incidents is provided by:
Dr. Gerald Graham Dr. Graham, who, in his review of the Application for CFN, noted that, while pilots undoubtedly lower the overall risk of a casualty, they cannot entirely eliminate it entirely. He notes the following incidents on the West Coast:
MV Westwood Annette incident in Squamish in 2007, where oil spilled into Howe Sound; MV Petersfield incident in Douglas Channel on September 25, 2009; MV Cosco Busan when it rammed a bridge in San Francisco harbour in 2007. Local Expertise b) CFN experts who, in their evidence in Appendix 2 of this submission, note that, while “we feel quite strongly, that the presence of pilots on board tankers serves to reduce risk…incidents with pilots on board seem to occur annually.” This is born out according to information provided to us indirectly from the Pacific Pilotage Authority, there were: 2 incidents in 2010 both caused by high winds during berthing operations; 8 incidents in 2006; 7 incidents in 2008; 6 incidents in 2009.
The experts further note that
expanding the regulated Pilotage area for tankers to include the Queen Charlotte Sound, Hecate Strait and Dixon Entrance would reduce the risk of oil tanker incidents [or alternatively] it may be possible to extend the limits for certain vessels (i.e. laden oil tankers) to embark or retain Pilots on Board to an approved Boarding or Takeoff point beyond current Pilot Station limits.
Escort Tugs do not eliminate the risk of an incident NGP proposes using escort tugs on laden tankers in the CCAA but not the OWA (except in possibly a very limited way). The following evidence suggests that having tugs accompany laden tankers does not eliminate the risk of incidents.
Northern Gateway Joint Panel Review - CFN Written Evidence 32 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Dr. Gerald Graham Dr. Gerald Graham, who, in his Application review for CFN, noted that, while tugs can reduce the risk of a tanker running aground or drifting ashore, they cannot completely eliminate that risk, especially if the tugs themselves are prone to breakdown. As evidence of this, Dr. Graham notes the following incidents on the West Coast:
On March 19, 2007 the American tugboat Sea Voyager ran aground near Bella Bella, British Columbia; On December 23, 2009 the tug Pathfinder ran aground on Bligh Reef in Prince William Sound, the very spot where the Exxon Valdez had run aground twenty years earlier; On July 28, 2010 the tug-barge Commitment lost power in Juan de Fuca Strait, on the American side of the border.
Local Expertise While escort tugs may serve to reduce the risk of incidents, NGP does not propose their use in the OWA (except in a very limited way). The two experts, in their evidence presented in Appendix 2 of this submission, note that:
―the use of escort tugs in the OWA would serve to reduce the risk of incidents in that area and, if they had rescue capability and a sufficiently large containment boom, would provide a measure of protection in case of a vessel breakdown.‖
Fisheries Liaison Committee does not eliminate the risk of incidents The extensive numbers of fishing boats in the area present a risk factor both for collisions and from tankers getting entangled in fishing gear. NGP‟s primary means of preventing such problems is through communication and the establishment of a Fisheries Liaison Committee.
The two experts, in their evidence in Appendix 2 of this submission, while agreeing conceptually with a Fisheries Liaison Committee, note that in their experience:
communications between fishing boats and larger vessels to avoid each other may not always work since fishers are often too busy fishing and may be reluctant to remove their gear and stop fishing…. there is an element of risk in close encounters in which fishing gear is caught in tanker propellers which can jam the shaft causing the tanker to lose propulsion.
Part V, Evidence with Respect to Inadequate Spill Response
Northern Gateway Joint Panel Review - CFN Written Evidence 33 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Many factors come into play when an oil spill occurs which determines the magnitude of its effects and consequences. Among these are: a) the adequacy of oil spill response plans; b) weather conditions which can delay response time and increase the spread of oil; c) the availability of response equipment, materials and trained clean up personnel; d) the availability of containment equipment on board the tanker; e) an effective multi-stakeholder response structure; f) the properties of the oil that has been spilled;
While some oil spill response details may be left to the post-approval - pre-operation stage, the JRP needs enough information for its „whether to” decision to be assured that what NGP and Canada say will be done is adequate and feasible.
Lessons from the Exxon Valdez The following report from the Exxon Valdez Oil Spill Trust Council (EVOSTC) 2009 Status Report illustrates some of the problems that can arise from lack of foresight and planning:42
For almost three days following the spill, the weather in the Sound was unusually quiet. However, Alyeska Pipeline Company, the initial responder under the terms of the Prince William Sound oil spill contingency plan, was not ready and few pieces of equipment were in the area in a timely manner. By the evening of March 24 only two skimmers, both of which were full at the time, were motoring aimlessly around the growing oil slick. There was little or no containment boom deployed. A test burn was conducted, which worked to some extent, but the water content of the oily mousse soon made burning impractical or impossible. Dispersants were a primary response tool and were tested with somewhat inconclusive results, but neither Exxon Corporation nor Alyeska had sufficient dispersant or the equipment to adequately deploy it. On the evening of March 26, a severe winter storm blew into the Sound. The oil slick went from a relatively compact mass to a widely dispersed collection of patches and streaks, and response vessels were forced to run for shelter in the face of the storm. The oil soon hit the beaches in hundreds of places, overwhelming any efforts to stop it, with a few notable exceptions such as in Sawmill Bay.
The following issues identified by EVOSTC are worth considering in assessing the adequacy of spill response information in relation to the NGP application:43
42 Cited in the NGP Application Review prepared for CFN by Tony D. Pearse , An Initial Review of the Northern Gateway Marine Risk Assessment, 10 November 2010
43 Jo Stephens, The Valdez‟s Unheeded Lessons (Washington Post, July 14, 2010) http://mobile.washingtonpost.com/c.jsp;jsessionid=D2141DCABE3D83CE30ECE3EF16BBEC95?item= http%3a%2f%2fwww.washingtonpost.com%2fwp- syndication%2farticle%2f2010%2f07%2f13%2fAR2010071306291_mobile.xml&cid=578815
Northern Gateway Joint Panel Review - CFN Written Evidence 34 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Oil companies cut corners to maximize profits; Systems intended to prevent disaster failed, and no backups were in place; Regulators were too close to the oil industry and approved woefully inadequate accident response and cleanup plans (response plans approved before the accident, had a "serious gap ‗between the spill size that companies said they could contain and their true capacity, which was "ridiculously low).‟[Emphasis Addded] In the immediate aftermath of the Alaska spill, as in the gulf, there was confusion over who was in charge -- oil companies or government officials. Federal authorities eventually asserted themselves but lacked the equipment and personnel to stem the damage; Storms slowed the response and spread contamination; Cleanup technology was old and ineffective; Environmentalists questioned the toxicity of dispersants and asked whether oil companies were using chemicals to hide damage; The U.S. Coast Guard and other government agencies proved "utterly incapable" of containing the oil; Contingency plans amounted to "toothless tigers;" and Equipment shortages and slow responses made a catastrophe inevitable.
EVOSTC concluded that:
the disaster was ‗the result of the gradual degradation of oversight and safety practices.‘ The spill ‗was not an isolated, freak occurrence, but simply one result of policies, habits and practices that for nearly two decades have infused the nation's maritime oil transportation system with increasing levels of risk. The Exxon Valdez was an accident waiting to happen.‘
Lessons from the BP Deepwater Horizon Oil Spill The National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, an independent, non partisan entity, directed to provide a thorough analysis and impartial judgment, presented its report, The Gulf Oil Disaster and the Future of Offshore Drilling,44 to President Obama, January 2011.
The Commission concluded that45:
Deepwater energy exploration and production, particularly at the frontiers of experience, involve risks for which neither industry nor government has been adequately prepared, but for which they can and must be prepared in the future.
44 http://www.oilspillcommission.gov/final-report
45 http://www.oilspillcommission.gov/sites/default/files/documents/OSC_Deep_Water_Summary_Recomm endations_FINAL.pdf
Northern Gateway Joint Panel Review - CFN Written Evidence 35 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 To assure human safety and environmental protection, regulatory oversight of leasing, energy exploration, and production require reforms even beyond those significant reforms already initiated since the Deepwater Horizon disaster. Fundamental reform will be needed in both the structure of those in charge of regulatory oversight and their internal decision-making process to ensure their political autonomy, technical expertise, and their full consideration of environmental protection concerns. The technology, laws and regulations, and practices for containing, responding to, and cleaning up spills lag behind the real risks associated with deepwater drilling into large, high-pressure reservoirs of oil and gas located far offshore and thousands of feet below the ocean‘s surface. Government must close the existing gap and industry must support rather than resist that effort. Scientific understanding of environmental conditions in sensitive environments in deep Gulf waters, along the region‘s coastal habitats, and in areas proposed for more drilling, such as the Arctic, is inadequate. The same is true of the human and natural impacts of oil spills.
Of particular importance for the JRP‟s assessment, are the Deepwater Commission‟s insights on spill response planning. The Commission noted that, there were gaps in the government‟s existing response capacity: the failure to plan effectively for a large-scale spill; difficulties in containing the spill in the environment; difficulty of coordinating with state and local government officials to deliver an effective response; a lack of information and understanding concerning the efficacy of specific response measures, such as dispersants and berms.
The Deepwater Commission made the following recommendations that need to be considered by the JRP:
Need for improved oil spill response planning
a new process for reviewing spill response plans is needed that ensures that all critical information and spill scenarios are included in the plans, including oil spill containment and control methods to ensure that operators can deliver the capabilities indicated in their response plans. In addition, the new entity within Interior that is charged with overseeing offshore safety and environmental protection will have to verify operator capability to perform according to the plans [Emphasis added].
Need for a new approach to handling spills of „National Significance‟
the EPA and the Coast Guard should establish distinct plans and procedures for responding to a ―Spill of National Significance‖ and amend or issue new guidance on the National Contingency Plan to
Northern Gateway Joint Panel Review - CFN Written Evidence 36 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 include, among other things, increased government oversight of the responsible party.
Inadequate Canadian Preparedness Commissioner of the Environment and Sustainable Development. As a result of the Deepwater spill, Canada‟s Commissioner of the Environment and Sustainability did a review of Canada‟s spill response capability and issued a report in 2010, 2010 Fall Report of the Commissioner of the Environment and Sustainable Development.46
The Commissioner found that [Emphasis added]:
knowledge of risks in Canada to spills from ships, which is important for effective emergency planning, is not complete or up to date.
the emergency management plans of the Canadian Coast Guard and Environment Canada—both important players in the federal oil spill response system—are not all up to date.
there is currently no process for providing assurance that the federal component of the oil spill response system is ready to respond effectively.
The Coast Guard has not conducted a comprehensive assessment of its response capacity since 2000. Given the lack of any recent capacity analysis and current information on risks, the Coast Guard is unable to determine how much oil spill response equipment it should have and whether it has appropriate capacity to address the risks.
The results of the Coast Guard‘s response efforts—which range from identifying the source of pollution to full cleanup—are poorly documented.
There are also limitations with the Coast Guard‘s system for tracking oil spills and other marine pollution incidents. These gaps affect its ability to conduct reliable analysis of trends in spills and know how well it is achieving its objectives of minimizing the environmental, economic, and public safety impacts of marine pollution incidents.
A public review panel recommended 20 years ago that the federal government establish a national regime to deal with ship-source chemical spills. Such a regime is not yet in place, and none is expected before 2013. In the meantime, Canada lacks a formal framework with clearly defined roles and responsibilities for responding to chemical spills.
46 http://www.oag-bvg.gc.ca/internet/English/parl_cesd_201012_01_e_34424.html#ex1
Northern Gateway Joint Panel Review - CFN Written Evidence 37 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Analysis of Commissioner’s Report An analysis of the Commissioner‟s report, with a focus on the inadequacies of the CCG to deal with spills, was made by Andrew Maydea of the Postmedia News (Nov. 27, 2010), Report reveals lack of training, aging equipment and limited management. 47
The Canadian Coast Guard lacks the training, equipment and management systems to fulfill its duties to respond to offshore pollution incidents such as oil spills, an internal audit reveals. The audit paints a sobering picture of an agency that would play a key role in Canada's response to a major oil spill off the world's longest coastline. In the event of a spill leaking from a ship, as occurred in 1989 when the Exxon Valdez ran aground off the coast of Alaska, the Coast Guard would be the lead federal agency in the cleanup efforts. However, the audit found that Coast Guard employees are trained on an "ad hoc, regional basis," with no national training strategy. Meanwhile, the Coast Guard is relying on aging equipment -- the operating status of which it is unable to track -- and management controls are "either out-of-date, not functioning or not in place." "As such, assurance cannot be provided that the conditions exist to enable (environmental-response) services to be provided in a national consistent manner," states the audit, which was completed just over a month before an explosion at BP's Macondo well in the Gulf of Mexico unleashed the biggest offshore oil spill in history this spring. Under Canada's patchwork response regime, the lead agency would depend on the nature and location of a spill. Off the East Coast, joint federal-provincial petroleum boards would oversee the cleanup of a spill at a drilling rig, while the National Energy Board would handle that responsibility in Arctic waters. But the Coast Guard would take the lead in any spill from an oil tanker, or a "mystery spill" whose origin is unknown. The audit describes an agency that operates more like a loose alliance of regional offices than a national organization. Internal auditors also found that information about incidents was not recorded in a manner that would allow for the review of incident responses. The Coast Guard hasn't identified the level of knowledge, skills and tools required for all environmental-response staff, and the agency lacks a way to monitor what training has been received by staff. Similar issues dog the Coast Guard's equipment-management system, leaving staff with no "current, reliable, up-to-date information on the operational status of equipment."
47 http://www.ottawacitizen.com/news/Audit+finds+Coast+Guard+unprepared+spills/3893965/stor y.html#ixzz17XkVE5Qs
Northern Gateway Joint Panel Review - CFN Written Evidence 38 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Transport Canada and CCG Responses to Commissioner’s Report The Commissioner‟s report indicated that government departments and agencies [Environment Canada (EC), Canadian Coast Guard (CCG), Transport Canada (TC)] agree with all of our recommendations. With regard to the Commissioner‟s recommendation (1.32) that TC and CCG should conduct a risk assessment related to ship-source oil spills covering Canada‟s three coasts, TC responded that it‟s scoping of this risk assessment will be completed by the end of 2011–12 [emphasis added].
With regard to the Commissioner‟s recommendation (1.41) that CCG and EC update their national emergency management plans and review and update their regional emergency management plans, EC responded that it would update these plans after completing its Strategic Emergency Management Plan, CCG responded that it is currently developing its National Environmental Response Strategy [Emphasis added].
Recommendations of the Pacific States/BC Oil Spill Task Force The proposed northern route passes close to the US –Canada boundary and an oil spill would involve transboundary spill response issues. Accordingly, the recommendations made in report prepared for the Pacific States/British Columbia Oil Spill Task Force in April 2011, The Stakeholder Workgroup Review of Planning and Response Capabilities for a Marine Oil Spill on the U.S./Canadian Transboundary Areas of the Pacific Coast Project Report 48 are relevant to the assessment and consideration of the adequacy of Canada‟s spill response capabilities and the NGP. The recommendations are as follows:
Transport Canada to inventory wildlife and amend the Canada Shipping Act
The inventory of wildlife facilities for the Dixon Entrance should be expanded to include Haida Gwaii (the Queen Charlotte Islands) during the next revision of the CANUSDIX Wildlife Response Guidelines.
Transport Canada should amend the Canada Shipping Act to include Response Organization requirements to develop the capability to address oiled wildlife during a spill response
CCG to assess risks from increased marine traffic
The U.S. and Canadian Coast Guards should work with their Vessel Traffic Services, the British Columbia Chamber of Shipping and the Alaska and Puget Sound Marine Exchanges to periodically assess vessel traffic patterns and volumes in the CANUSPAC and CANUSDIX areas and determine whether there have been any
48 http://www.oilspilltaskforce.org/docs/notes_reports/Final_US_Canada_Transboundary_Project_Report.p df
Northern Gateway Joint Panel Review - CFN Written Evidence 39 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 significant changes in the risk levels for vessel incidents that could lead to oil spills in these areas (page 213);
CCG to take actions with First Nations
The Canadian and U.S. Coast Guards should consider identifying representatives of Federally-recognized tribes and First Nations who could be impacted if a transboundary spill occurred in the CANUSDIX or CANUSPAC areas.
The USCG and CCG should continue inviting representatives of Federally-recognized tribes and First Nations to participate in CANUSDIX and CANUSPAC-related planning activities, exercises and evaluations.
The U.S. and Canadian Coast Guards as well as appropriate state and provincial agencies should work with Federally-recognized Tribes or First Nations to clarify their access to response cost recovery through the U.S. Oil Pollution Act of 1990 or Canada‘s Ship Source Oil Pollution Fund.
U.S. and Canadian Federal agencies should consider initial and continued consultation with Federally-recognized tribes and First Nations on POR and PPOR documents developed to date for use in the CANUSDIX and CANUSPAC transboundary areas.
CCG to improve inter-jurisdictional communications:
The U.S. and Canadian Coast Guards should consider collaborating with the Alaska, Washington and British Columbia emergency response and resource agencies and OSROs to map Transboundary areas where radio, satellite and cell phone communications are not available (black holes), or conversely, are available. This map should be reviewed and updated as needed or at least every five years. For the identified ―black holes‖, these ―communication teams‖ should recommend solutions such as placement of permanent radio repeaters, or identification of locations where portable repeaters would function, or the use of satellite phones.
Oil spill coordination by Transport Canada and CCG:
The U.S. Coast Guard and Transport Canada should consider whether the coordination of U.S. and Canadian authorities to investigate oil spill incidents should be addressed in the Joint Contingency Plan and whether specific investigation protocols are needed in the transboundary geographic annexes.
Northern Gateway Joint Panel Review - CFN Written Evidence 40 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 The U.S. Coast Guard and Transport Canada should undertake a coordinated review of air traffic control coverage, capabilities (including traffic control for low altitude aircraft) and coordination protocols for both transboundary areas. As part of this review, they should determine whether air traffic control capabilities exist in remote areas of the transboundary regions, including identification of available resources and permits needed for access.
Considering the potential for a transboundary spill to originate from an oil handling facility, Transport Canada should correct the omission in the CSA 2001 relating to responder immunity for spills from Oil Handling Facilities as soon as possible.
Transport Canada and the Canadian Coast Guard should develop protocols which allow U.S. Coast Guard approved response organizations to benefit from Canadian responder immunity provisions through mutual aid agreements with Canadian Response Organizations.
Industry actions:
Potential RPs should anticipate the need to have representation in both the U.S. and Canadian command posts during a transboundary response, and should be familiar with the differences in their roles on either side of the border, i.e., as the Incident Commander in Canada and as the RP‘s Incident Commander as part of a Unified Command in the United States.
Recognizing that in a transboundary spill response the ICPs will be staffed and run by the RP and its response organization according to their spill response plans, the shipping industry and oil handling facilities near the Transboundary borders and the response organizations serving these areas should address issues identified in this Project Report, such as: Recognizing the differences between the U.S. and Canadian approaches and capabilities to manage an oil spill; and developing an industry-based position and policy on such matters as using the Incident Command System, endorsing Unified Command, integration of Incident Management Teams, and identifying locations for Incident Command Posts.
To help resolve cost-recovery issues in both the U.S. and Canada, key state, provincial and federal agencies – as well as industry - should endeavor to improve agreement on required response actions. Government agencies‘ advice and directions to the RP should be based on agency authorities and responsibilities, best professional judgment and expert scientific opinion in consideration of the RP‘s legal obligations.
Northern Gateway Joint Panel Review - CFN Written Evidence 41 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011
During both Transboundary exercises and actual response operations, RPs and their representatives should consider working closely with the response organizations, federal, state and provincial agencies and the Finance Sections in both Command Centers to ensure that there is no duplication of activity costs and claims and to ensure timely tracking of all costs
Western Canada Marine Response Corporation (WCMRC) actions
Western Canada Marine Response Corporation (WCMRC) should consider verifying Incident Command Post (ICP) locations in British Columbia on an annual basis and updating ICP information in the eight reference and resource information plans of the Western Canada Marine Response Corporation plan, as necessary. WCMRC should continue to work with local governments and industry to identify ICP locations which could be used in remote areas during a Transboundary response.
BC Ministry of Environment actions
The Waste Management Plans for both transboundary areas should include the following provisions: Mutually-agreeable locations for recycling of oily wastes. Joint plans for the selection of mutually-agreeable locations on both sides of the border for in-situ (at or near site) oily waste treatment that includes (but is not limited to) environmentally-sound and practical oiled woody-debris burning, oiled debris/sediment land-farming, and portable incineration. Locations selected for staging should be available in a GIS format that can be utilized at the operations and planning levels. During a response, facilitate consultation with Operations, Logistics and relevant local governments on the assessment and selection of proposed locations. Identified field equipment units (barges, lined trucks, storage bladders, earth-moving equipment, bins, portable incinerators and supporting resources) dedicated to waste management. Lists of coastal facilities with temporary holding capacities over 100,000 metric tonnes located near the border which can be provided to Operations and Logistics. An agreement for deploying on-site monitoring teams (e.g. custody signage and trained supervisors) to ensure that oily wastes are segregated into waste streams (including recyclable elements) before initiating movement across the border. Protocols for acquiring waste management records (including disposal locations) from all agencies and command posts involved in the response.
Northern Gateway Joint Panel Review - CFN Written Evidence 42 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 After-action reports, lessons learned and any penalties issued from either command post should be made readily available for access by either country for waste/disposal documentation. Legal analyses based on applicable legislation in both countries (and if need be – international law conventions). As the legal issues are predominantly international, the lead federal agencies would be most suited to retain legal counsel and establish a formal legal working group, if needed. Additional legal opinion would be provided by the State/Provincial agencies. Recommendations to facilitate coordination of waste management decisions between both Incident Command Posts should be included in the plans. Waste Management liaisons and specialists should interact extensively with the EU and REET to further develop and adjust the joint waste management plans as required during a specific incident. Border Security agencies should help develop personnel/equipment tracking forms to be included in the waste management plans. Comprehensive provisions in the Waste Management Plans addressing disposal of hazardous wastes from vessel cargoes or supplies (possibly as a separate appendix).
British Columbia response agencies should develop a policy defining protocols to expedite notifications to First Nations of any spills that could impact them. The agreement should include contact information for regional First Nations (including transboundary First Nations), should determine that potentially impacted First Nations be notified immediately and should determine who is responsible for making the notifications.
The U.S. and Canadian Coast Guards as well as appropriate state and provincial agencies should work with Federally-recognized Tribes or First Nations to clarify what funding mechanisms are available to support their participation in Transboundary spill planning and exercises.
The U.S. and Canadian Coast Guards as well as appropriate state and provincial agencies should work with Federally-recognized Tribes or First Nations to clarify their access to response cost recovery through the U.S. Oil Pollution Act of 1990 or Canada‘s Ship Source Oil Pollution Fund.
Canadian Federal and provincial agencies, First Nations, and stakeholders in British Columbia should consider identifying Potential Places of Refuge in their transboundary areas that could be considered (among other locations as appropriate) on an incident-specific basis during POR decision-making.
The Pacific States/British Columbia Oil Spill Task Force members in Alaska, Washington and British Columbia should exercise their 1993 and 1996 Mutual Aid Agreements as part of the annual transboundary exercises. Such tests should be part of exercise templates and plans, with defined objectives for each
Northern Gateway Joint Panel Review - CFN Written Evidence 43 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 exercise. It is particularly recommended that they exercise their 1996 Agreement with regard to establishing conditions whereby contingency plan holders would be allowed to meet temporarily reduced planning standards in order to facilitate the movement of contracted response equipment for mutual aid.
Response organizations and agencies operating in the transboundary areas should determine whether their personnel have adequate insurance coverage to operate outside the ―normal operating area,‖ and what, if any, time limits apply to their operations across the border. They should also ensure that all workers have baseline medical records available.
As part of routine operations, exercises and drills, it is recommended that differences in OELs, procedures, and PPE requirements that potentially inhibit transboundary response continue to be shared by response organizations and agencies as or if they are discovered. If any of the issues can be addressed by conforming to a mutually agreed upon ―best practice‖ that meets the more stringent requirements, it is recommended that written templates be created and distributed to the response community. Incorporation of these practices into routine field training and exercises will promote familiarization with issues. The response organizations‘ and agencies‘ safety officers should facilitate this process.
Response agencies and organizations should continue to evaluate and test their communications equipment through exercises such as CANUSPAC and CANUSDIX.
To help resolve cost-recovery issues in both the U.S. and Canada, key state, provincial and federal agencies – as well as industry - should endeavor to improve agreement on required response actions. Government agencies‘ advice and directions to the RP should be based on agency authorities and responsibilities, best professional judgment and expert scientific opinion in consideration of the RP‘s legal obligations.
Use of Dispersants in Spill Clean Up NGP‟s General Oil Spill Response Plan (GOSRP) submitted in March 2011 identifies the use of dispersants for spill clean up despite the fact that heavily-weathered, emulsified oil resisted chemical dispersion in the BP Gulf spill.49 In the same response, NGP tacitly acknowledges the criticisms of the use of dispersants by suggesting that regulatory bodies need to consider the “Net Environmental Benefits” of the use of dispersants prior to the spill.
Notwithstanding NGP‟s assertion that there are many studies on dispersants, many experts agree that there are many environmental risks in their use. The problems of
49 NGP Response to CFN IR 1.22 j
Northern Gateway Joint Panel Review - CFN Written Evidence 44 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 determining the use of dispersants after a spill has occurred are illustrated with the Deepwater Horizon spill. Determining whether dispersants should be used, and what their effects would be, is needed before the project is approved.
Gulf Oil Disaster Recovery Group PRNewswire reported on the use of dispersants in the Gulf oil spill - Gulf Oil Disaster Recovery Group, Gulf Oil Spill: Dispersants Have Potential to Cause More Harm Than Good, May 11, 2011.50It quotes the following people in its story:
Stuart Smith, Lead Counsel for Gulf Oil Disaster Recovery Group
With respect to marine toxicity and potential human health risks, studies of kerosene exposures strongly indicate potential health risks to volunteers, workers, sea turtles, dolphins, breathing reptiles and all species which need to surface for air exchanges, as well as birds and all other mammals. Additionally, I have considered marine species which surface for atmospheric inhalation such as sea turtles, dolphins and other species which are especially vulnerable to aspiration toxicity of 'Corexit 9500' into the lung while surfacing; [Corexit 9500' and 'Corexit EC9527A are also known as deodorized kerosene].
Co-Counsel Robert McKee of the Gulf Oil Disaster Recovery Group
Toxicity of the petroleum products is increased when it is dissolved into the water by dispersants…In essence, this activity is making aquatic organisms more exposed to chemicals' harm. The attempt to make these floating tars and oils disappear from view by the use of dispersants increases the likelihood of poisonous effects in these oil polluted waters…The use of dispersants not only hides the amount of oil actually being discharged from view, but also serves to undermine damage proof for the unwary victim who chooses to wait to see what is going to happen…What facts supported the decision that dispersants would effectively protect shorelines without significantly impacting the water column and benthic marine populations of the Gulf?" said Mr. Smith. "BP must answer the many questions that arise from the usage of dispersants and be accountable for its actions and the harmful effects they have on marine life, the coastline and the livelihood of those who make their living off the fisheries and tourism industry."
Ji Sayer, Oil Spill Truth, Dispersants & Dispersed Oil Similar concerns about the use of dispersants were made by Ji Sayer, Oil Spill Truth, Dispersants & Dispersed Oil.51
50 http://www.prnewswire.com/news-releases/gulf-oil-spill-dispersants-have-potential-to-cause-more- harm-than-good-93424899.html
51 http://oilspilltruth.wordpress.com/dispersants/
Northern Gateway Joint Panel Review - CFN Written Evidence 45 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011
Ultimately the conflict between the EPA and BP being waged right now on using ―more effective‖ and ―less toxic‖ dispersants, skirts the real issues. Although using ―less toxic‖ dispersants is a good idea, the more ―effective‖ they are, the more harm they do to the life in the Gulf. The focus should not be only on the inherently toxic nature of all dispersants, but on the inherently toxic consequences of dispersing the oil through any means. Dispersing the oil into the water column accelerates the poisoning of all marine life, deep throughout the water column and seabed. Ultimately it results in ―covering-up‖ the extent of the disaster on the surface, while amplifying the damage within our oceans. Also, when the dispersants admix with the crude oil, a third far more toxic product is produced called ―dispersed oil.‖ Dispersed oil has been shown to be more toxic than the sum of its parts. In the EPA fact sheet on Corexit 9500 the dispersant has a toxicity Menidia beryllina fish of 25.20 parts per million, resulting in the death of 50% of the specimen within 96 hours. The test oil (Fuel Oil #23) exhibited the same toxicity at a lower 10.72 parts per million. When the Corexit and oil were mixed, however, the EPA tests revealed an exponential increase in the toxicity of the dispersed oil mixture reaching 2.61 parts per million for a lethal dose of 50% of the fish. We must see beyond the superficial debate over using ―less toxic dispersants‖ and acknowledge that the dispersion techniques – by their very principle – make the problem far worse.
Part VI, Evidence with Respect to the Catastrophic Effects of an Oil Spill on the Marine Environment
Ecological Damage Deepwater Horizon Oil Spill The report, Approaches for Ecosystem Services Valuation for the Gulf of Mexico after the Deepwater Horizon Oil Spill: Interim Report52 November, 2011, was prepared by the Committee on the Effects of the Deepwater Horizon, Mississippi Canyon-252 Oil Spill on Ecosystem Services in the Gulf of Mexico. The National Research Council is the principal operating agency of the National Academy of Sciences and the National Academy of Engineering. The Report notes that,
The unprecedented magnitude of the Deepwater Horizon oil spill presents significant challenges for oil spill responders and those tasked with assessing the impacts of the spill. Evaluating changes to ecosystem
52 http://www.nap.edu/catalog.php?record_id=13141; http://dels.nas.edu/resources/static-assets/materials- based-on-reports/reports-in-brief/Approaches-Ecosystem-Valuation-Report-Brief-Final.pdf
Northern Gateway Joint Panel Review - CFN Written Evidence 46 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 services—the benefits people receive from natural resources and processes—caused by the oil spill could expand the potential to capture and value the full breadth of impacts to the ecosystem and the public. This report assesses the methods and metrics that could help scientists effectively evaluate ecosystem services.
The Report indicates that the magnitude and depth of the Deepwater Horizon oil spill will require an unprecedented effort to determine the extent and severity of ecological damage and to develop restoration plans for affected areas in the Gulf of Mexico. It‟s Chair, Larry A. Mayer, Director of the Center for Coastal and Ocean Mapping, and professor of earth science and ocean engineering at the University of New Hampshire, wrote:
The Gulf of Mexico is a vast, complex ecosystem that provides a wealth of important ecological services -- from seafood to tourism to flood protection through its coastal wetlands…It will be a challenge to assess the full scope of impacts from this spill -- the biggest in U.S. history -- and ensure that valuable services are fully restored for the region and ultimately the nation.
The Report notes that under the US, Oil Pollution Act, a process is created (Natural Resources Damage Assessment) that includes representatives of federal and state governments, tribes, and other "trustees" of the affected ecosystem tasked with attempting to quantify the extent of damages caused by a spill, develop and monitor restoration plans, and seek compensation from the parties deemed responsible.
The Committee notes that, approaches to assess losses in past spills, measured in ecological terms, is inadequate, because the breadth of the Deepwater Horizon spill, and recommends a broader "ecosystem services” approach:
There is growing recognition that taking an ecosystem services approach by linking changes in ecosystems to consequent changes in human well-being would help lead to more informed management and policy. This broader view may be of value for understanding an event of the magnitude, duration, depth, and complexity of the Deepwater Horizon oil spill, and may offer more approaches for restoration projects
The Committee notes that implementing an ecosystem approach to damage assessment requires an understanding of the complex linkages amongst various ecosystem components. This includes the following components:
Determining the impact of human actions on the structure and function of the ecosystem; Establishing how changes in the ecosystem lead to changes in ecosystem services;
Northern Gateway Joint Panel Review - CFN Written Evidence 47 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Establishing how changes in the provision of ecosystem services affect human well-being.
Deepwater Horizon Spill Effects on Fish One of the first studies done on the effects of the Deepwater Horizon spill on fish, Genomic and physiological footprint of the Deepwater Horizon oil spill on resident marsh fishes53, found that fish living in marshes exposed to BP crude showed clear signs of oil-related toxicity, even when only trace amounts of oil could be detected in their tissues and the environment. The fish showed damage to their gills, making it harder for them to get oxygen and adapt to natural changes in salinity and temperature. The study also revealed that the marsh water was toxic to fish eggs, even when it tested clean by conventional sampling. Scientists have found much higher amounts of oil chemicals lingering in the marsh sediments, which could make the marsh a chronically toxic environment for years:
we provide evidence that links biological impacts with exposure to contaminating oil from the DWH spill within coastal marsh habitats. Although body burdens of toxins are not high, consistent with reports indicating that seafood from the Gulf of Mexico is safe for consumption (34), this does not mean that negative biological impacts are absent. Our data reveal biologically relevant sublethal exposures causing alterations in genome expression and tissue morphology suggestive of physiological impairment persisting for over 2 mo after initial exposures. Sublethal effects were predictive of deleterious population- level impacts that persisted over long periods of time in aquatic species following the Exxon Valdez spill (1) and must be a focus of long-term research in the Gulf of Mexico, especially because high concentrations of hydrocarbons in sediments (Dataset S2) may provide a persistent source of exposures to organisms resident in Louisiana marshes (page 4).
The Study concludes that:
These data suggest that heavily weathered crude oil from the spill imparts significant biological impacts in sensitive Louisiana marshes, some of which remain for over 2 months following initial exposures.
Exxon Valdez - Long-Term Effects Exxon Valdez Oil Spill Trustees Council (EVOSC) There have been more recent studies and report showing that the effects of the Exxon Valdez spill have been long term. The Exxon Valdez Oil Spill Trustees Council
53 Andrew Whitehead, et al, Genomic and physiological footprint of the Deepwater Horizon oil spill on resident marsh fishes, Proceedings of the National Academy of Sciences, September, 2011. http://www.pnas.org/content/early/2011/09/21/1109545108.full.pdf+html?sid=60a155c3-9259-4349- 9935-7cda12ccaa92
Northern Gateway Joint Panel Review - CFN Written Evidence 48 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 (EVOSC), Lingering Oil Remains: The Persistence, Toxicity, and Impact of Exxon Valdez Oil54 reports that:
In 2001, researchers at the Auke Bay Laboratories, NOAA Fisheries, conducted a survey of the mid-to-upper intertidal in areas of the sound that were heavily or moderately oiled in 1989. Researchers dug over 9,000 pits, at 91 sites, over a 95-day field season. Over half the sites were contaminated with Exxon Valdez oil. Oil was found at different levels of intensity from light sheening; to oil droplets; to heavy oil where the pit would literally fill with oil. They estimated that approximately 16,000 gallons (60,000 liters), of oil remained. The survey also showed a trend of an increasing number of oiled pits as they surveyed lower into the intertidal zone, indicating that there was more oil to be found lower down the beach. In 2003, additional surveys determined that while the majority of subsurface oil was in the mid-intertidal, a significant amount was also in the lower intertidal. The revised estimate of oil was now more than 21,000 gallons (80,000 liters). Additional surveys outside Prince William Sound have documented lingering oil also on the Kenai Peninsula and the Katmai coast, over 450 miles away.
The amount of Exxon Valdez oil remaining substantially exceeds the sum total of all previous oil pollution on beaches in Prince William Sound, including oil spilled during the 1964 earthquake. This Exxon Valdez oil is decreasing at a rate of 0-4% per year, with only a 5% chance that the rate is as high as 4%. At this rate, the remaining oil will take decades and possibly centuries to disappear entirely.
Following the oil and its impacts over the past 20 years has changed our understanding of the long-term damage from an oil spill. Because of the scope and duration of the restoration program, lingering oil and its effects were discovered and tracked. As a result, we know that risk assessment for future spills must consider what the total damages will be over a longer period of time, rather than only the acute damages in the days and weeks following a spill
Gail Irvine, a U.S. Geological Survey The long term effects of the Exxon Valdez spill is reported by Craig Medred, Shielded by a rocky crust, Exxon Valdez oil still on Katmai beaches, Alaska Dispatch Nov 05, 201155. This article reports on a study by ecologist, Gail Irvine, a U.S. Geological Survey scientist, presented to the 2011 Southwest Alaska Science Symposium, that 22 years after the tanker Exxon Valdez hit a reef outside of Valdez and began gushing oil
54 http://www.evostc.state.ak.us/recovery/lingeringoil.cfm 55 http://www.alaskadispatch.com/article/shielded-rocky-crust-exxon-valdez-oil-still-katmai- beaches?page=0,0
Northern Gateway Joint Panel Review - CFN Written Evidence 49 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 into Prince William Sound, blobs of North Slope crude can still be found buried in the beaches of Alaska's Katmai coast more than 250 miles to the west and south.
prior to this study, oil on exposed, rocky shores was thought to have short residence time, being removed within weeks to a few months by wave action. A different scenario has unfolded on the bouldered beaches of the Katmai coast, however. Oil appears to have infiltrated soils beneath the rock, and there it has been protected against natural weathering. Beaches appear clean, and the oil "is subtle'' but present, she said. Look closely, and you will "see the unexpected,'' she added. Scoop up some of the unexpected and analyze it, and there is even more unexpected. That oil, she said, "has weathered almost not at all.'' She called the phenonenon "remarkable,'' adding that the chemists who analyzed it reported that samples match the chemical profiles of Exxon Valdez crude collected only 11 days after the spill. Certain light, aromatic components of the oil evaporated away in that time, but plenty of noxious chemicals remain, locked in the Katmai beaches. For how long, no one knows. The oil, Irvine said, "could still be there a long time.'' Scientists marked boulders on the beaches to study how much they move. Very little, they discovered. It was Irvine's believe this will make it hard for natural forces to get at the oil in order to degrade it further. Some of the gooey balls of oil buried beneath the rocks still contain chemical components that, in other waters, would have been devoured by microbes in weeks or months. "Our results,'' she said, "I don't believe there are any others like this.'' The good thing, she indicated to the crowd at a National Park Service-sponsored symposium in Anchorage, is that the beaches don't seem to be leaking any of the old oil. Rather, it seems to be preserved in them.
But in the warm, microbe-rich waters of the Gulf of Mexico, the impact of oil in the ocean was far different than what happened in the cold waters of the north. "The Gulf spill is so different,'' Irvine said, and in more ways than one.
Part VII, Evidence with Respect to Inadequate Assessment Methodology
Lack of Baseline Information The Terms of Reference, in Hearing Order OH-4-2011, for the Project state that the JRP will consider “the environmental effects of the project, including the environmental effects of accidents and malfunctions that may occur in connection with the project” [Emphasis added].
NGP has failed to provide the baseline information on the Queen Charlotte Sound, Hecate Strait and Dixon Entrance (OWA) needed to determine the environmental effects, or consequences, of an oil spill resulting from an oil tanker incident. Instead, NGP has used a
Northern Gateway Joint Panel Review - CFN Written Evidence 50 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 probability methodology to justify not providing the baseline information, thereby eliminating a full consideration of the environmental effects of all possible and potential accidents. NGP has, therefore, perverted the requirement to consider accidents that “may” occur, to one of considering only accidents that are “likely” to occur.
The Canadian Environmental Assessment Act The Canadian Environmental Assessment Act (s. 16 (1) specifically notes that review panels must consider “the environmental effects of accidents and malfunctions.” It does not say “accidents or malfunctions that are „likely‟ to occur. The reference to consideration of „likely‟ effects is in reference to cumulative effects.56
Evidence of the need for complete baseline information of the whole area potentially affected by an oil spill resulting from a marine incident is provided by the CEAA Guide CEAA Reference Guide: Determining Whether a Project is Likely to Cause Significant Adverse Environmental Effects. 57 This Guide states that:
The most common way of determining whether a project's environmental effects are adverse is to compare the quality of the existing environment with the predicted quality of the environment once the project is in place…It is the proponent's responsibility to ensure that such information is put before the RA. In most cases, the proponent should be expected to collect and synthesize the available information on baseline environmental quality. In some cases where there are gaps in information, the proponent can be requested to collect new information, depending on the size and nature of the project and the proponent's resources.
Further evidence of the need for complete baseline information of the whole area potentially affected by an oil spill resulting from a marine incident is provided by the CEAA Guide to the Preparation of a Comprehensive Study for Proponents and Responsible Authorities, May 1997, which states:58
This section [Predicted Environmental Effects of the Proposed Project] should also address…effects of possible malfunction or accidents...This section should describe the predicted project effects in a way that will permit evaluation of the accuracy of the predictions…For each environmental component, the report should document all potential
56 “CEAA, s. 16 (1). Every screening or comprehensive study of a project and every mediation or assessment by a review panel shall include a consideration of the environmental effects of the project, including the environmental effects of malfunctions or accidents that may occur in connection with the project and any cumulative environmental effects that are likely to result from the project in combination with other projects or activities that have been or will be carried out.
57 http://www.ceaa-acee.gc.ca/default.asp?lang=En&n=D213D286-1&offset=&toc=hide
58 http://www.ceaa-acee.gc.ca/default.asp?lang=En&n=0DABEB61-1
Northern Gateway Joint Panel Review - CFN Written Evidence 51 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 project-related effects. To the maximum extent possible, this documentation should include an indication of the nature of the effect, mechanism, magnitude, direction, likelihood, duration, frequency and timing, geographic extent, and the degree to which it may be reversible. All of this information may be used to determine the significance of the effect.
The CEAA Guidance document (5: Scope of the Assessment) also notes that
“Faced with a limited budget, time constraints and complex ecosystems, proponents must provide enough information to enable decision-makers to make informed decisions… [and] if information collected during the environmental assessment identifies new potential concerns, the proponent will be responsible for addressing these since they become an issue later in the review.”
Lastly, the CEAA Guidance (7: Description of the Existing Environment) advises proponents that the description of the environment is not only to describe the existing environmental condition but also provides the foundation upon which environmental effects will be predicted and evaluated. It goes on to note that:
However, the inclusion of health, socioeconomic conditions, physical and cultural heritage, and current use of lands and resources for traditional purposes by aboriginal persons, should include only those components that may be affected as a consequence of a change in the biophysical environment attributable to the project. Therefore, effort should focus on those environmental components identified as being most important according to the issues and concerns raised by stakeholders Uses of the environmental component may further influence its perceived or real sensitivity and therefore its treatment in the report. For example, if an environmental component represents a source of country food for local inhabitants of a region, the effect of disrupting it would be greater than if that same resource were not locally consumed. Each of the sources of sensitivity should be described for these environmental components.
David Strong, former President of the University of Victoria Such baseline data was recommended by David Strong, former President of the University of Victoria, in his Report of the Scientific Review Panel on British Columbia Offshore Hydrocarbon Development, 59
Recommendation 3.We recommend that, before any new industry is introduced into a specific marine ecosystem such as the Queen Charlotte
59 British Columbia Offshore Hydrocarbon Development, Report of the Scientific Review Panel January 15, 2002, page 43, http://www.em.gov.bc.ca/OG/offshoreoilandgas/ReportsPresentationsandEducationalMaterial/Reports/D ocuments/chapter5.pdf
Northern Gateway Joint Panel Review - CFN Written Evidence 52 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Basin, action be taken to establish a comprehensive set of pre- perturbation baseline data on the biota, including life-cycle histories of different species and their habitats, so that we can understand and assess which aspects of the marine ecosystem might be most at risk from the proposed development, and evaluate the population- and community- level consequences that may result.(emphasis added)
Dr. William Sawyer, American Board of Forensic Medicine Dr. William Sawyer, a toxicology expert, told the Gulf Oil Disaster Recovery Group that “baseline data on the environmental and ecologic fate of petroleum spills and their effects in the marine environment is substantially deficient... [which] makes many of the decision-making processes pertaining to successful major spill containment and remediation rife with speculation.”60
Congressional Research Service The need for baseline information is also documented in a study prepared for Congress: The Deepwater Horizon Oil Spill: Coastal Wetland and Wildlife Impacts and Response,61
Although events are still at a relatively early stage, a number of questions arise. When will recovery be complete, and how do we define success, or completion? What is an acceptable level of habitat recovery? NOAA regulations (15 C.F.R. § 990.30) state that recovery ―means the return of injured natural resources and services to baseline‖—in other words, a return to conditions as they would have been had the spill not occurred. But what this means in actual terms is open to considerable debate. A conventional definition of recovery is probably ―return to the way things were before the spill.” Unfortunately, this benchmark is vague and hard to quantify. Change is particularly characteristic of coastal areas, which are already subject to significant annual losses in area. In the case of Prince William Sound, for example, it is difficult to apply this standard of recovery because there is little information about ―the way things were‖ before that spill. Multiple variables affect local species and ecosystem services. Similarly, one species at a spill site could have been on the decline at the time of an incident, because of changing water temperatures or other factors. Even in the absence of a major disturbance like an oil spill and cleanup, ecosystems are constantly in transition, and the physical and biological conditions that once characterized any given site are likely to shift considerably over time (page 24).
60 PRNewswire reported on the use of dispersants in the Gulf oil spill - Gulf Oil Disaster Recovery Group, Gulf Oil Spill: Dispersants Have Potential to Cause More Harm Than Good, May 11, 2011
61 Corn, M. Lynne and Copeland, Claudia, The Deepwater Horizon Oil Spill: Coastal Wetland and Wildlife Impacts and Response, Congressional Research Service, August 5, 2010 http://www.fas.org/sgp/crs/misc/R41311.pdf
Northern Gateway Joint Panel Review - CFN Written Evidence 53 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Inadequate Determination of Significance CEAA Reference Guide Evidence that the Panel can determine its own approach to determining significance is noted in the CEAA Guide: Determining Whether A Project is Likely to Cause Significant Adverse Environmental Effects: In larger EAs, such as panel reviews, it may be possible to develop methods and approaches for determining significance for individual projects. 62
David Lawrence, Significance criteria The Panel reviewing the Mackenzie Gas Project commissioned its own report on the assessment of significance. David Lawrence, an expert environmental assessment practitioner, outlined in his report, Significance Criteria and Determination in Sustainability-based Environmental Impact Assessment, the following Best Practices approach: 63 Address significance with and without mitigation; Address significance of positive and negative impacts; Address significance of individual and cumulative effects; Ensure that full use is made of community and traditional knowledge; Place within the context of local and regional issues and challenges; Place within the context of corporate social, environmental and sustainability policies; Link judgements to local perceptions and to local and regional ecological, social, economic and political problems and challenges; Place within the context of community and regional conditions; Place within the context of historical, current and emerging conditions; Ensure that significance determination methods and procedures are appropriate to the culture, and to the social, ecological, economic, legal and political setting; Distinguish, where appropriate, significance of impacts associated with various project phases, for various study areas, and for various time horizons; Distinguish between ecological and socio-economic importance; Make a particular effort to involve those most directly affected, most vulnerable to change, and least likely to be able to participate in the process; Assess in terms of contribution to local and regional land use, environmental management and sustainability plans, policies, strategies and visions.
62 http://www.ceaa-acee.gc.ca/default.asp?lang=En&n=D213D286-1&offset=&toc=hide
63David Lawrence, Significance criteria and determination in sustainability-based environmental impact assessment, a report commissioned and published by the Joint Review Panel for the Mackenzie Gas Project,30 November 2005, 49pp. http://www.ngps.nt.ca/registryDetail_e.asp?CategoryID=265
Northern Gateway Joint Panel Review - CFN Written Evidence 54 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Inadequate Cumulative Effects Assessment Lorne Greig, ESSA Technologies Ltd. and Peter Duinker, Dalhousie University prepared a paper on cumulative effects assessment for the Mackenzie Gas Project Joint Review Panel entitled, Scenarios of Future Developments in Cumulative Effects Assessment64.
Their Report notes that the current practice of CEA (cumulative effects assessment) in Canada is not strong and is fraught with a number of problems that compromise its ability to provide useful information with which to anticipate possible cumulative effects of proposed developments. Determining which future projects to include in assessments has proven especially problematic. Despite the encouragement in the guidance and the policy, proponents usually do not go beyond the requirement to include in their analyses only those projects which are considered certain.
They suggest the use of Scenario Development, focused on developing alternative visions of the future, in order to shift away from trying to estimate what is most likely to occur toward questions of what are the consequences and most appropriate responses under different circumstances…Scenarios usually serve one of two functions: one is risk management, where scenarios enable strategies and decisions to be tested against possible futures, while the other is creativity and sparking new ideas.
More specifically, they note that:
Cumulative effects are the effects that valued ecosystem components (VECs) will experience in reality. VECs are effects integrators in that they must respond to or cope with all the relevant stressors simultaneously. Therefore, the most important part of any EIA, and especially an EIA for a large development such as the MGP, is actually the CEA.
Cumulative effects (positive and negative) of many types clearly depend heavily on government preparedness and choices. Strategic environmental assessments, land use plans and systems of protected areas are instruments with which governments prepare themselves to manage such effects.
The creation and exploration of scenarios of plausible futures that may be associated with implementation of the MGP would provide an opportunity for the stakeholders (proponents, governments and affected peoples) to begin to anticipate and prepare for possible futures. In the absence of such analysis, seeking a sustainable future
64Lorne Greig & Peter Duinker, Scenarios of Future Developments in Cumulative Effects Assessment, Prepared for Mackenzie Gas Project – Joint Review Panel, march 12, 2007. http://www.ceaa.gc.ca/155701CE-docs/ESSA_Technologies-eng.pdf
Northern Gateway Joint Panel Review - CFN Written Evidence 55 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 may require an approach that, in concert with limits on the pace of development, would seek to respond to cumulative effects as they arise.
In conclusion they note that developing scenarios of possible futures helps to cope with uncertainties about the future - the development future, the future of ecosystems, and the future of human communities. It is meant to assist in managing risks - perhaps reducing risks - associated with human actions that inadvertently may compromise VEC sustainability. It is meant to replace blindness caused by unwillingness to peer forward with glimpses of possible outcomes so that we might choose the best among them.
Part VIII, Evidence with Respect to an Inadequate Risk Assessment
The risk of using Kitmat as a port to transport oil is long standing. In 1978, Andrew R. Thompson, Commissioner of the West Coast Oil Port Inquiry, concluded that
If an oil port is established at Kitimat there will inevitably be oil spills on the adjacent coast of British Columbia (page 58). Even if the desirable Canadian energy policy is to construct an oil port at Kitimat, this project should be rejected if the oil spill risks are too high (page 81).65
Subsequently, in 2002, the Pacific States-BC Oil Spill Task Force study found that the risk of vessel collisions increases with traffic density such as will be experienced at Kitimat if the NGP and the proposed LNG projects were to go ahead. 66
NGP, using a probability methodology to assessing risk, characterizes the risks of a marine spill occurring as minimal or extremely low. However, basing predictions on this type of statistical probability ignores the reality that rare events occur regularly (e.g. Exxon Valdez, BP Deep Horizon, Japan Nuclear plant) and should be planned for with appropriate measures to prevent and mitigate adverse effects. This is especially so when the effects of low probability events can have catastrophic consequences to First Nations and the environment that sustains them.
The Black Swan is a surprise event – the idea that a catastrophe can strike without warning. What does NGP plan for: the low consequence high frequency incident or the high consequence low frequency incident?
65 Statement of Proceedings, West Coast Oil Ports Inquiry, February 1978, http://www.em.gov.bc.ca/OG/offshoreoilandgas/ReportsPresentationsandEducationalMaterial/Reports/D ocuments/West-Coast-Oil-Port-Inquiry-Statement-of-Proceedings.pdf
66 Pacific States-BC Oil Spill Task Force, 2002 West Coast Offshore Vessel Traffic Risk Management Project, July 2002. http://www.oilspilltaskforce.org/wcovtrm_report.htm
Northern Gateway Joint Panel Review - CFN Written Evidence 56 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Low Probability-High Impact Events Black Swan Events67 As evidence of a more precautionary approach to risk assessment, we present the wroks and thinkinbg of Nassim Taleb. Mr. taleb has written a best selling book called The Black Swan: The Impact of the Highly Improbable (Random House, 2007). The book focuses on low predictability events with high consequences „that occur more often than we think.‟ Taleb calls these "Black Swans" after the one-time European certainty, based on northern hemisphere experience, that all swans were white.
Mr. Taleb‟s thesis is particularly germane to the JRP‟s considerations because NGP‟s risk assessment:
dismisses any consideration of rare and unlikely or unpredictable events; fails to provide adequate measures to prevent them; fails to provide adequate information on how it would respond to them; and fails to inform the JRP‟s assessment in a fundamental way, since environmental assessment, by its nature, is intended to predict effects and identify ways to prevent or mitigate adverse ones. Or as Taleb states “the rarer the event, the higher the error in estimation of its probability” (page 237) [Emphasis Added].
Purpose of the Black Swan Thesis Taleb‟s thesis was developed to explain: The disproportionate role of high-impact, hard-to-predict, and rare events that are beyond the realm of normal expectations; The non-computability of the probability of the consequential rare events using scientific methods (owing to the very nature of small probabilities); The psychological biases that make people individually and collectively blind to uncertainty and unaware of the massive role of the rare event in historical affairs.
Characteristics of a Black Swan event it is unpredictable; it carries a massive impact; and, after the fact, it is possible to assemble a rationale as to how we should have been able to predict it quite easily.
67 wikipedia - http://en.wikipedia.org/wiki/Black_swan_theory Taleb Web Site - http://www.fooledbyrandomness.com/ U Tube Lecture http://www.youtube.com/watch?v=BDbuJtAiABA Book Links - http://www.amazon.com/Nassim-Nicholas- Taleb/e/B000APVZ7W/ref=ntt_athr_dp_pel_pop_1/185-5866822-0429367 Download - http://www.filestube.com/t/the+black+swan+taleb
Northern Gateway Joint Panel Review - CFN Written Evidence 57 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Examples of Black Swan Events Among the many Black Swan examples he discusses are: the September 11, 2001 attacks; the rise of the Internet (particularly Google); the start of World War I; the sales of the Harry Potter novels; and the story of the turkey
a turkey is fed by the farmer every morning for 1,000 days. Eventually the turkey comes to expect that every visit from the farmer means more good food. After all, that‘s all that has ever happened so the turkey figures that‘s all that can and will ever happen. But then Day 1,001 arrives. It is two days before Thanksgiving and when the farmer shows up, he is not bearing food, but an axe. The turkey learns very quickly that its expectations were catastrophically off the mark. And now Mr. Turkey is dinner… ‗Let‘s not be turkeys.‘ [Keynote Address to the Risk and Insurance Management Society]68
Lessons of the Turkey Apropos to NGP‟s probability risk assessment methodological approach, Taleb, states that the lesson of our doomed turkey illustrates the central problem of unexpected, “black swan” events. We simply do not have enough data to reach empirical conclusions about how a risk will manifest itself and to what degree. “Just because you never died before, doesn‟t make you immortal,” said Taleb. Part of the issue is in the semantics of how we talk about risk. We have created what Taleb called “an illusion of measurement.” By saying, we can “measure” the risk in a particular situation, we are implying that there is a definitive answer. “We should not be using the word „measuring,‟” he said. “We should be using the word „estimating.‟” It‟s a psychological difference that allows us to gauge “riskiness” more appropriately.
Estimating Rare Events Methodology
Professor Terje Aven Terje Aven, Professor of Risk Analysis and Risk Management at the University of Stavanger, Sweden in his paper, Identification of safety and security critical systems and activities.69 Professor Aven notes that “Surprises may occur and by just addressing
68 Taleb, Nassim, Let‟s Not Be Turkeys, Keynote Address, Risk and Insurance Management Society (RIMS) 2000 Conference, April 28, 2010, as reported by Morgan O‟Rourke, Editor, Risk management Monitor, http://www.riskmanagementmonitor.com/lets-not-be-turkeys/
69 Aven, T., Identification of safety and security critical systems and activities, Reliability Engineering & System Safety, 94 (2), 404-411 DOI: 10.1016/j.ress.2008.04.001(2009).
Northern Gateway Joint Panel Review - CFN Written Evidence 58 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 probabilities and expected values, such surprises may be overlooked. . However, taking possible surprises into account from the beginning will allow for a much broader, richer and more comprehensive approach to risk management.”
Professor Aven notes that in traditional risk assessment, risk is defined as a function of probability and consequences, where the probability of an event occurring is linked to the expected consequences if the event occurs (as predicted). This way of thinking only considers a certain set of events; it does not consider the full spectre of possible outcomes. This means that the actual consequences may be very different from the calculated expected consequences.
Consequently, Professor Aven proposes a different approach in which expected consequence are replaced with the following expected disutility approach, in which uncertainties are added so that “true” risk is revealed:
Identify possible initiating events; Define categories of consequences (severity classification); Rank the systems according to vulnerability; Assess uncertainties in underlying phenomena and processes that could result in surprise; and Adjust the ranking based on this assessment.
Nassim Taleb In a subsequent paper, Nassim Taleb elaborates on the methodological problems involved in probability-based risk assessment such as that use by NGP:70
The central idea in The Black Swan is that: rare events cannot be estimated from empirical observation since they are rare. We need an a priori model representation for that; the rarer the event, the higher the error in estimation from standard frequency sampling, hence the higher the dependence on an a priori representation that extrapolates into the tails. Further, we do not care about simple, raw probability (if an event happens or does not happen); we worry about consequences (the size of the event; how much total destruction of lives, wealth or other losses will come from it). Given that the less frequent the event, the more severe the consequence (just consider that the 100 year flood is more severe, and less frequent, than the 10 year flood), our estimation of the contribution of the rare event is going to be massively faulty (contribution is probability times effect; multiply that by estimation error); and nothing can remedy it.
70 Taleb, N., Common Errors in Interpreting the Ideas of The Black Swan and Associated Papers, NYU Poly Institute, October 18, 2009, http://papers.ssrn.com/sol3/papers.cfm?abstract_id=1490769
Northern Gateway Joint Panel Review - CFN Written Evidence 59 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 So the rarer the event, the less we know about its role -and the more we need to make up such deficiency with an extrapolative, generalizing theory. It will lack in rigor in proportion to claims about the rarity of the event. Hence model error is more consequential in the tails and some representations are more fragile than others…this error is more severe in what I call Extremistan, where rare events are more consequential, because of a lack of scale, or a lack of asymptotic ceiling for the random variable.
The small sample properties of rare events as these will be naturally rare in a past sample…For negatively skewed generators (i.e., with a thicker left tail, in other words tends to produce catastrophes), the problem is worse. Clearly, catastrophic events will be necessarily absent from the data –since the survivorship of the variable itself will depend on such effect. Thus such distributions will let the observer become prone to the overestimation of the stability and underestimation of the potential volatility and risk.
Consideration of Consequences or Severity According to Taleb:
The very definition of an "Historical" event lacks a dimension in Extremistan, particularly when we are talking about probabilistic decision-making…In other words, traditional tools lack a significant dimension, much like someone living in 3D space, but only seeing it in 2D. The missing dimension here is the severity of the event.
This absence of ―typical‖ event in Extremistan is what makes prediction markets ludicrous, as they make events look binary. Describing an event as ―a war‖ for decision making or analysis purposes is meaningless: you need to estimate its damage –and no damage is typical. Many predicted that the First War would occur – but nobody predicted its magnitude…it can kill a dozen people, or lead to millions of casualties. You may be able to predict the occurrence of a war, but you will not be able to gauge its effect!
looking at the prediction of events as expressed in the price of war bonds is sounder than simply counting predictions --because a bond is priced to cover the probability of an event times its consequences, not just the probability of an event. So we should not focus on whether someone "predicted" an event without his statement having consequences attached to it.
Conclusions Taleb states that he is not advocating not crossing the street because of extreme risk consciousness:
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“all I will be showing you in this book is how to avoid crossing the street blindfolded (page 49)…If you shed the idea of full predictability, there are plenty of things to do provided you remain conscious of their limits. Knowing that you cannot predict does not mean that you cannot benefit from unpredictability. The bottom line: be prepared…be prepare for all relevant eventualities… [and] know how to rank beliefs not according to their plausibility but by the harm they cause” (page 203).
―it is not easy to compute their [Black Swans] probability, but it is easy to get a general idea about the possibility of their occurrence. We can turn these Black Swans in to Grey Swans, so to speak, by reducing their surprise effect‖71, and making such large events conceivable72– or… You are indeed much safer if you know where the wild animals are.‖ 73
Applying the Black Swan Theory Taleb‟s theory can be especially applied to the area of engineering safety where by acknowledging the potential for an improbable event with massive impact (such as a worst-case oil tanker spill), and being prepared, the impact of such events can be minimized. Taking the example of car travel, if you recognize that there are inherent risks to car travel you can take precautions like: not traveling in poor weather conditions; not drinking and driving; wearing a seat belt; having air bags in the car; traveling at a safe speed; having proper regulations and enforcement.
Avinash Nafday, Ph.D., P.E., an engineer with the California State Lands Commission, discusses how to deal with potential Black Swans from an engineer‟s perspective: 74
The metaphor of black swan refers to unpredictable events like 9/11, the Indian Ocean tsunami, or the Oklahoma City Federal Building bombing, that cause catastrophic consequences for structural system safety. The likelihood of occurrence for such unforeseen events cannot be estimated from the observed data or prognosticated by experts. The absence of event and likelihood information renders futile the application of usual risk- based methods for design. Therefore, a shift from the probabilistic
71 Taleb, N., The Black Swan, Random House, 2007, page 213 72 Ibid, page 262 73 Ibid, page 273 74 Avinash M. Nafday, Consequence-based structural design approach for black swan events, Structural Safety, Volume 33, Issue 1, January 2011, Pages 108-114 http://www.sciencedirect.com/science/article/pii/S0167473010000810
Northern Gateway Joint Panel Review - CFN Written Evidence 61 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 approach to consequence-based structural design is necessary for coping with the unexpected demands. This is accomplished through the conceptual development of a system capacity oriented design approach, where structural members are designed for variable reliabilities based upon their contribution to causing adverse system consequences.
Part IX, Evidence with Respect to Inadequate Spill Scenarios
CFN has raised serious concerns about the inadequacies of NGP‟s mass balance scenarios predicting the effect of spills in the area under study: locations, size, trajectories, etc.
Shortcomings of NGP Scenarios Dr. Gerald Graham Evidence of NGP‟s spill scenario shortcomings, is provided by Dr. Gerald Graham, who, in his review of the Application for CFN, noted the following inadequacies:
There are several issues with respect to these ‗examples‘. For instance, why do the tanker spill examples not include at least one example of an incident involving the Non-Accidental Structural Failure (NASF) of a tanker? Were an incident of this nature to be included in the list of ‗scenarios‘ provided, it is suggested that the ‗approximate maximum credible volume‘ of oil spilled could amount to virtually the entire cargo of oil on board the tanker, i.e. up to two million barrels of oil in the case of a VLCC. The worst tanker spill in history was the MV Atlantic Empress incident off Tobago in 1979, which involved just over two million barrels of oil. Two million barrels would therefore be a better ‗worst case scenario‘ figure for an oil spill within the OWA, with the scenario narrative dealing with the challenges inherent in responding to a spill of this magnitude, and how the proponent intends to overcome what are bound to be the many obstacles to successfully responding to such a catastrophic incident.
Dr. Graham suggested that other scenarios sites be selected such as Gwaii Haanas National Marine Conservation Area Reserve, the Scott Islands off the northern tip of Vancouver Island, one of the sponge reef colonies within the Queen Charlotte Basin and the sea otter colony near Goose Island off the Central Coast.
Dr. Graham, in his submission to the Expert Panel examining the BC off-shore oil and gas moratorium, provided the following scenario:75
75 Probability and Consequence: A Submission to the Royal Society of Canada Expert Panel on the British Columbia Offshore Oil and Gas Moratorium, pages 7-12. http://www.scribd.com/doc/28841457/Probability-and-Consequence
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Our scenario involves a tanker spill of the same order as the Exxon Valdez spill, in the middle of Queen Charlotte Sound. We are attempting to determine whether a credible response can be mounted there, and what might be the consequences for the environment, economy, etc. if the response was either too weak or too late.
For the purposes of our simulation, the spill has occurred in the year 2009, five years after a sensitivity atlas was completed for the Central Coast…Assume that at 4 AM on March 6, a total of 240,000 barrels [or over 32,000 tonnes - 1/10 the capacity of a VLCC] of Athabasca heavy, synthetic crude oil accidentally releases from the holds of a stricken tanker in the Sound. The tanker suffered from structural failure after being hit by a giant, 30-metre wave during a marine bomb.
Using ADIOS2, a spill weathering model developed by NOAA…if we assume that the wind speed is 25 knots from 224 degrees at the time of the spill, that the sea temperature is 4 degrees Celsius, and that the current is 2 knots towards 37 degrees, then of the original 240,000 barrels spilled, 40,000 barrels will disperse, and a further 40,000 barrels will have evaporated after four days. Thus, one will be left with 160,000 barrels of the original cargo to recover and/or clean up.
However, the effect of emulsification will mean that this 160,000 barrels will have actually turned into an oil-water mixture of perhaps twice to three times that amount, compounding the response challenge and increasing the potential for negative impact. Let‘s assume that the nearest spill response depots are located at Bella Bella and Kitimat on the mainland, as well as Port Hardy on Vancouver Island. The resources of these centres would immediately be called upon, as well as those of the rest of Canada, the United States, and probably the international community, e.g. Oil Spill Response Limited in Southampton, England, and East Asia Response Limited in Singapore. However, given the standard weather conditions for this time of year, the relatively short days, the distance from the spill site, and the time required to organise and mount a response effort, it could easily be 48 to 72 hours before anyone is in a position to start containing and recovering oil off the surface, with the appropriate vessels, storage tanks, booms, skimmers, etc. Once in place, the standard response option of containment and recovery at sea, using mechanical equipment will probably not work; poor operating conditions could prevent the effective deployment of these devices for days, if not weeks…Average wind velocities equal or exceed the specification for standard types of mechanical equipment (e.g. booms and skimmers) in each month from December through March.
Northern Gateway Joint Panel Review - CFN Written Evidence 63 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 In the meantime, most of what is going to happen to the oil, e.g. evaporation, dispersion and emulsification, has already happened in that brief, initial period before the response vessels actually arrive on the scene. This severely limits the response options, because burning the oil at sea or using dispersants can typically only be done during a brief window of opportunity‟ and assuming the environmental conditions are conducive to such options. Unfortunately, at this time of year normal conditions are pretty dreadful, thereby eliminating these two options. Dispersants are an option… [but] At present there is no pre-approved use of dispersants anywhere in Canada.‖
Where the oil will end up is anyone‘s guess; this would depend in part on the sea temperature, wind speed and direction, tidal current speeds and direction, etc…. Generally speaking, not accounting for tides, oil spilled in Hecate Strait and Queen Charlotte Sound should tend to drift in a southerly direction in the summer, and in a northerly direction in the winter. As a rule of thumb, oil on the surface will drift at the rate of 3 % of wind speed and 100% of current speed. As the oil follows its trajectory, the response authorities would no doubt be well into the shoreline protection and cleanup phase of operations, conducting assessments of impacted shoreline, and directing the appropriate equipment and resources to sites identified in advance for priority treatment... Unfortunately, as mentioned earlier, worldwide experience demonstrates that even if things go relatively well, on average only 10- 15% of oil spilled at sea is ever recovered; the rest either evaporates, disperses, dissolves or ends up on the shore somewhere….
Adding to the response challenge would be the enormous logistical problems faced in the region. Even at the best of times, there are very few roads, airports, ports or other staging areas from which to launch a coordinated response. At least fifty percent of the central coast consists of rocky shoreline; in high energy environments the oil should naturally degrade as wind and waves combine to break it down eventually. This is what happened in the case of the Braer spill off the Shetlands in 1993. However, in low energy rocky shoreline environments which, according to Bornhold and Harper, comprise about 35% of the shoreline of the North Coast, the oil could remain there for months or years. Another 35% of the shoreline, or 6000 kms, consists of ―…low energy, bedrock shoreline that will have moderate oil residence periods‖ What oil is recovered may have to be stored in vessels or barges and hauled away by sea for eventual recycling or disposal, as there would be little opportunity to bring the oil ashore and haul it away by tank truck.
In the meantime, the marine environment could suffer in many ways from the effects of oil, as the following quote attests: ―Oil spills could affect all species resident, reproducing, or feeding in intertidal areas
Northern Gateway Joint Panel Review - CFN Written Evidence 64 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 and salt marshes. This would include salmon, herring, abalone, sea urchins, sea cucumbers, clams, and sea and land birds and some marine mammals. Spills could affect all plants and animals in the surface and upper layer of the ocean, including most larval fish and planktonic eggs, and marine birds and mammals.‖ The Alan Wood report goes on to state: ―Grazing herbivores such as sea urchins, and probably abalone, limpets, chitons, and snails, are highly impacted by oil,‖ and that: ―Intertidal feeders such as clams, rock scallops, and mussels are impacted by oil. Clams are impacted by oil settling into sand and gravel in their habitat. Beyond mortality, there is a long-term contamination and tainting of mussels‖. Harbo estimates that there are 7000 invertebrate species (sponges, crab, shrimp, sea stars, etc.) in British Columbian waters, plus 400 fishes, 200 marine birds and 30 types of marine mammals. In addition, there are 640 species of seaweeds and seagrasses in this province. Many of these species call the waters of the Queen Charlotte Basin home. Thus, the Strong report, which puts the total number of species in the region at between 500 and 1000, would seem to seriously underestimate the biodiversity of the area, and thus the potential impact of a major spill on marine life. Rather than provide a detailed summary of the species that spills may impact off the Central Coast, such as the Goose Island sea otter population, or the sponge reef colonies, let us highlight the potential impact of oil on just two species in the nearshore area– sand lance and sea mussels.
Sand lance. As Alan Wood Consulting point out in an annex to the Strong report, this small fish, which inhabits shallow water, could be vulnerable to oil spills (p. 105). ―In the Queen Charlotte Basin, sand lance is preferred food for rock sole, petrale sole, pacific cod, chinook, coho, lingcod, halibut and many other fish species and some seabirds.‖ Elsewhere, it is reported that in Puget Sound at least ―…35% of juvenile salmon diets are composed of sand lance. Juvenile Chinook salmon depend on sand lance for 60% of their diet. Minke whales, other marine mammals, and many species of seabirds also prey on sand lance.‖ In short, destroy the sand lance and you could end up destroying salmon populations in the area. Destroying the salmon could produce a domino effect, imperilling not just the marine environment but the coastal forest ecosystem as well.
Sea mussels As the Strong report says: ―The interaction between species are very important to the overall functioning of the ecosystem with some species (the keystone species) playing a more critical role. Any factor that has a negative impact on the keystone species would be expected to have profound impacts on the entire ecosystem. For example, sea mussels form densely aggregated beds from the upper intertidal to subtidal depths. They provide a protective matrix for a very complex community
Northern Gateway Joint Panel Review - CFN Written Evidence 65 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 of more than 300 different species. They are long-lived, and species richness increases with increasing mussel bed age and thickness. However, as filter feeders, mussels are very sensitive to oil contamination and are known to readily accumulate Polycyclic Aromatic Hydrocarbons (PAHs) in areas of urban run-off and oil spills. Consequently, the exposure of sea mussels to oil as the result of frequent small or catastrophic spills would have serious implications for the entire food web, including fish, sea-birds and marine mammals.‖
In other words, a spill of 240,000 barrels could wreak havoc on the marine environment of the Central Coast, and there might be very few options for responding to it at certain times of year.
Part X, Evidence with Respect to Impacts to Coastal First Nations
CFN commissioned a study on the potential impacts of the NGP Project on CFN by Sean Broadbent and Professor Thomas Gunton, of Simon Fraser University. Dr. Gunton is currently Professor and Director of the Resource and Environmental Planning Program at Simon Fraser University, which is recognized as one of the leading international schools providing advanced interdisciplinary training for resource professionals.. Dr. Gunton has had extensive professional experience including holding the positions of Deputy Minister of Environment, Lands and Parks, Deputy Minister of Cabinet Policy Secretariat and Deputy Minister of Finance (Treasury Board) for the Government of British Columbia. He has also held senior positions with the Government of Manitoba, including Assistant Deputy Minister of Energy and Mines where he was in charge of major natural resource project development, Senior Economic Analyst in the Ministry of Economic Development and was visiting professor in resource and environmental economics at the University of Manitoba.
Dr. Gunton regularly provides advice to private sector and public sector clients. His work includes evaluation of resource development projects, regional development strategies and negotiation and collaborative models for resolving resource and environmental conflicts. While working for the BC government he was managed a number of major initiatives including: a new Environmental Assessment Act, a new Forest Practices Code, a forest sector strategy, a new regional land use planning process, a major expansion of the provincial parks system, a redesign of the regulatory and royalty system for oil and gas development and new air pollution regulations. He was also the chief negotiator for the province on a number of major resource development projects including Kemano completion. Dr. Gunton has been an expert witness for various regulatory agencies including the National Energy Board, the Ontario Energy Board, and the Manitoba Public Utilities Commission. He has also been an expert witness before the BC Arbitration Panel providing evidence on natural resource markets and pricing.
Northern Gateway Joint Panel Review - CFN Written Evidence 66 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Dr. Gunton‟s work has included management of problems in a number of resource sectors including forestry, land use, energy, mining and fisheries. He is Chair of the Sustainable Planning Research Group and Chair of the Offshore Oil and Gas Research Group, which is providing advice to First Nations on impacts of oil and gas development. Dr. Gunton also recently prepared a draft of the national Sustainable Development Act for the Suzuki Foundation that was passed unanimously by the Parliament of Canada in 2008. Dr, Gunton has published over 80 refereed articles in scientific journals and over 100 technical reports for private and public sector clients on resource and environmental issues and project development.
Dr. Gunton and Sean Broadbent‟s study, A Review of Potential Impacts to Coastal First Nations from an Oil Tanker Spill Associated with the Northern Gateway Project is attached as Appendix III of this submission.
Executive Summary 1. This report provides an assessment of potential impacts to Coastal First Nations (CFN) from an oil tanker spill associated with the proposed Enbridge Northern Gateway Project (ENGP). The study has three main research objectives: I. Identify economic activities of the CFN, including non-market traditional and subsistence activities II. Evaluate environmental impacts of an oil spill and assess potential impacts of a spill on CFN commercial and traditional activities III. Examine the consequences of approving the ENGP prior to the completion of the PNCIMA planning process.
Values in the PNCIMA 2. The terrestrial region of the study area includes the North and Central Coasts of British Columbia (BC) and Haida Gwaii. The marine environment surrounding the North and Central Coasts and Haida Gwaii is defined as the Pacific North Coast Integrated Management Area (PNCIMA) by the Department of Fisheries and Oceans Canada (DFO). The PNCIMA is an 88,000 km2 marine ecosystem that accounts for 22% of the total marine area in Canada‟s exclusive economic zone on the West Coast. The area contains coastal waters north of Campbell River and Brooks Peninsula on Vancouver Island and includes all salt waters north of these two regions and the freshwater streams that drain into the ocean. The PNCIMA is defined by DFO as one of Canada‟s five priority ocean management areas.
3. The PNCIMA is a diverse ecosystem with 44% of its area identified as ecologically and biologically significant. More than 400 species of marine fish reside off the BC coast and ecosystems in the PNCIMA provide important habitat for many important fish populations. The PNCIMA is home to three of BC‟s five major herring populations, 88% of spawning rivers for eulachon in BC and hundreds of watersheds in the region provide critical spawning habitat for approximately 58% of all anadromous salmon populations on the west coast of Canada. Moreover, over 25 species of dolphins, porpoises, pinnipeds, and whales and over a hundred species of marine bird inhabit the PNCIMA.
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4. The PNCIMA is critical habitat for marine birds: Over one-half of marine bird species in BC (108 species) use habitats in the PNCIMA throughout their lifecycle The region supports 95% of the total breeding seabird population in BC.
5. The PNCIMA provides important habitat for very rare and vulnerable species. The PNCIMA is the only known location in the world for 9,000-year old ancient sponge reefs. Thirty-nine species in PNCIMA are listed as threatened, endangered, or special concern by the Committee on the Status of Endangered Wildlife in Canada (COSEWIC) as recently as 2010. The number of at risk species may be higher because many of the species in the region have not been assessed by COSEWIC.
6. The value of marine dependent resources that could be impacted by an oil spill in the PNCIMA are analyzed with the total economic value (TEV) methodological approach, which assesses all social, economic, and environmental values. Valuation is grouped into three major categories: market based use values such as commercial fishing, non-market use values such as scenic viewing, and non-use values such as existence and preservation values.
7. Estimates of the total annual benefits of marine dependent activities in CFN traditional territories that could be impacted by an oil spill range between $28.9 and $29.9 billion (2010 CAD) (Table ES-1). Current marine dependent market based economic activities generate $386.5 million in revenue per year and support 7,620 jobs. Potential new investments indicate that the magnitude of these marine dependent activities will increase significantly over the next decade as the region continues developing a healthy sustainable economy. Non-market use value in CFN traditional territories consists of FSC salmon harvests ($0.7 million) and ecosystem services ($28.5 billion). The final component of the TEV framework, non-use preservation and existence value in the PNCIMA marine environment, contributes between $67.1 million and $1.0 billion per year in economic benefits. Estimates are generally based on conservative assumptions and therefore underestimate actual values.
Table ES-1: Summary of Marine Dependent Activities in CFN Traditional Territories
Economic Value (annual value in Total Total Economic Value Component millions of 2010 Employment CAD) Market Use Value Current Economic Activities Use Commercial Fishing $134.9 1,310 Value Seafood Processing $88.1 2,470 Aquaculture $18.2 180
Northern Gateway Joint Panel Review - CFN Written Evidence 68 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Marine Tourism $104.3 2,200 Marine Transportation $18.6 800 Other $22.4 660 Subtotal $386.5 7,620 Non-Market Use Value FSC Salmon Harvests $0.7 n/a Ecosystem Services* $28,484.7 n/a Non-Use PNCIMA Marine Environment $67.1 - $1,031.9 n/a Value Total $ 28,938.9 - 29,903.7 7,620 *The value of ecosystem services is very challenging to measure and this value should be interpreted as a very rough order of magnitude of the actual value. Some values cannot be monetized and other values are difficult to measure due to data limitations. Therefore, actual values may be higher or lower than estimated values. As documented in the report, the estimates for market use values, FSC salmon harvests, and non-use values are conservative and actual values are higher.
Enbridge Northern Gateway Project 8. The ENGP consists of an oil export pipeline, condensate import pipeline, and a tank and marine terminal near Kitimat, BC where oil will be transferred into tankers and condensate will be transferred out of tankers. Kitimat terminal currently accounts for 250-300 deep sea vessels per year, and tanker traffic associated with the ENGP is forecasted to add an additional 190 to 250 tankers a year, or an average of 220 vessels, to existing commercial marine traffic accessing Kitimat (Table ES-2).
Table ES-2: Characteristics of Oil and Condensate Tankers Accessing Kitimat Terminal
Tanker Class Characteristic VLCC Suezmax Aframax Maximum Deadweight Tonnage 320,000 160,000 81,000 Overall Length (m) 343.7 274.0 220.8 Average Cargo Capacity (m3) 330,000 160,000 110,000 Average Number of Vessels per 50 120 50 Year
9. Tanker traffic in and out of Kitimat terminal will be restricted to three potential routes: a northern approach, a southern direct approach, and a southern approach via Principe Channel. These proposed tanker routes for the ENGP traverse multiple- use environments characterized by various environmental, economic, social, and traditional assets and uses. The north and south passes that will be navigated by tankers are within seven distinct ecosections, including the Continental Slope, Dixon Entrance, Hecate Strait, North Coast Fjords, Queen Charlotte Sound, Queen Charlotte Strait and Vancouver Island Shelf. Marine ecosections that will be traversed by tankers contain important biological features such as productive plankton communities, migratory corridors and nursery areas for salmon and other
Northern Gateway Joint Panel Review - CFN Written Evidence 69 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 fish, and feeding grounds for several marine mammal and bird populations. Ecosections also contain overlapping anthropogenic uses, including commercial fisheries for many species of fish, marine transportation corridors, important sites for tourism and recreational activities, and culturally-important harvesting areas for many Aboriginal communities.
Enbridge Oil Spill Assessment 10. Five scenarios are identified by Enbridge to illustrate the potential impacts of an oil tanker spill in the region: four spills of 10,000 m3, two of which occur in confined channel areas and two occur in open water areas, and one larger spill of 36,000 m3 in the confined channel area of Wright Sound. The proponent used a mass balance approach that quantitatively determines the fate of hydrocarbons spilled in the environment. A mass balance approach models the various amounts of contaminants from a spill in a defined period of time after the spill has occurred and determines the areas of an affected ecosystem where the contaminants of the spill settle, such as intertidal and subtidal environments. Enbridge also conducted an ecological and human health risk assessment to predict effects of a 36,000 m3 oil spill in the confined channel area of Wright Sound.
11. Enbridge estimates that a 36,000 m3 oil spill in Wright Sound would have the following biophysical impacts: Sand and gravel mixed beaches have the potential for penetration and remobilization of oil where oil might persist The spill would reach many sensitive and commercially important areas in the 240 kms of shoreline where diluted bitumen might strand Diluted bitumen on the water surface, dispersed in water and coating the shoreline would result in short-term impacts to water quality and potentially longer-term effects on sediment quality Rockweed, kelp and other algae and intertidal marine invertebrates would come in contact with shoreline oil Migrating salmon in the summer could increase the presence of predators since marine mammals and birds tend to follow prey Oiled fur or feathers pose the risk of hypothermia and animals could inhale or ingest oil from self-cleaning.
12. Enbridge estimates that a 36,000 m3 oil spill in Wright Sound would have the following impacts on the human environment: Bitumen reaching intertidal and shoreline regions could affect heritage resources and traditional marine uses Aboriginal groups would be particularly sensitive because of their dependence on the sea for food, transportation, social and ceremonial purposes There could be fisheries closures due to contaminant levels, conservation concerns or tainting
Northern Gateway Joint Panel Review - CFN Written Evidence 70 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Effects to traditional uses could include impacts to food harvesting, and impacts to areas of cultural and sacred importance, as well as periodic habitation Diluted bitumen might affect heritage resource sites through contamination or sites could be damaged by cleanup activities A spill would have effects on non-traditional marine uses at the marinas at Stephens Point, although likely effects would be aesthetic disturbances and restricted access to shorelines and marinas during the cleanup Vessels and marine infrastructure in contact with oil would be fouled A spill could temporarily disrupt vessel traffic and cause the loss of fish and shellfish resources over at least one season in communities and First Nation reserves in the area.
13. The risk assessment approach used by Enbridge to predict potential consequences of a large hydrocarbon spill in Wright Sound has the following weaknesses: Failure to assess specific damages and the cost of damages Incomplete summary of impacts from the Exxon Valdez oil spill (EVOS) Insufficient baseline knowledge of traditional marine use by First Nations in the PNCIMA region to assess impacts Failure to adequately address a long-term assessment of the fate and distribution of oil released into the marine environment Failure to assess impacts of a tanker incident greater than 10,000 m3 in the open water area Failure to assess impacts of spills smaller than 10,000 m3 despite evidence showing that spills as small 238 m3 can have significant adverse environmental effects Failure to examine the potential consequences of a catastrophic, worst-case scenario oil spill whereby a very large crude carrier discharges all of its cargo Deficiencies in the quantitative risk assessment of oil spills Failure to identify mechanisms to ensure implementation of proposed mitigation measures Deficiencies in compensation plans to mitigate damages of impacted parties.
14. There is uncertainty regarding estimates of the likelihood of oil spills. Different methodologies, definitions, and assumptions generate significantly different estimates of spill likelihood ranging from very likely to less likely (Table ES-3). The oil spill occurrence estimates in the quantitative risk assessment (QRA) provided by Enbridge have several deficiencies including: Failure to provide confidence levels in the probability assessments Limited sensitivity analysis on how changes in key parameters and assumptions impact oil spill occurrence rates Lack of transparency in how certain judgments are made Lack of evidence to support some key judgments Failure to present information in the form of probabilities of occurrence over the operating life of the project
Northern Gateway Joint Panel Review - CFN Written Evidence 71 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Restriction of consideration to a smaller study region that comprises only a component of potentially impacted areas. Restricting the impact assessment to a limited geographical area leads to an underestimate of the spill risk and is contrary to the Canadian Environmental Assessment Act, which requires consideration of all impacts regardless of where they occur.
These deficiencies need to be addressed and differences in methodologies and results need to be assessed to provide reliable estimates presented in terms of the probability of spills occurring by size over the operating life of the ENGP.
Table ES-3: Range of Spill Occurrences for the ENGP Based on Various Methodologies
Return Rates for Spills Size and Type of Spill (in Methodology (in years) barrels) Unmitigated Mitigated Tanker all spills 78 250 Tanker all spills: sensitivity 53-58 n/a analysis Enbridge QRA Tanker spill exceeding 200 550 31,500* Terminal all spills 29 61 Combined tanker/terminal all 21 49 spills US Oil Spill Risk Oil spills exceeding 1,000 6-10 n/a Model (525 kbpd Oil spills exceeding 10,000 14-30 n/a volume) US Oil Spill Risk Oil spills exceeding 1,000 4-7 n/a Model (800 kbpd Oil spills exceeding 10,000 9-20 n/a volume) * Indicates that 31,500 barrels represents 5,000 m3
Exxon Valdez Oil Spill 15. The Enbridge risk assessment of a major oil spill utilizes findings from the EVOS to identify potential impacts of an oil spill in PNCIMA. It is useful to use findings from the EVOS to assess potential impacts of an oil spill in the PNCIMA because the EVOS occurred in close proximity to PNCIMA in an area with similar biophysical and socioeconomic characteristics. Further there is an extensive scientific research record documenting the impacts of the EVOS. Therefore the EVOS provides a good foundation for predicting impacts of an oil spill in PNICMA.
Northern Gateway Joint Panel Review - CFN Written Evidence 72 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011
16. The Exxon Valdez ran aground on Bligh Reef in Prince William Sound (PWS), Alaska on March 24, 1989. Eight of the 11 cargo tanks in the single-hull vessel were punctured from the initial grounding event, releasing approximately 258,000 of the 1,263,000 barrels (or approximately 41,000 m3) of Alaska North Slope Crude oil, most of which was lost in the first eight hours. Spilled oil contaminated at least 1,900 kms of shoreline and spread over 750 kms from the point of impact.
17. Decades after the initial spill, oil from the EVOS remains on intertidal beaches and in subtidal sediments. Half of the oil spilled from the Exxon Valdez biodegraded on beaches or in the water column, 20% evaporated, 14% was recovered or disposed, 13% was deposited in subtidal sediments, 2% remained on intertidal shorelines, and 1% remained in the water column.
18. Adverse impacts of the EVOS include: 60% to 100% mortality rates for all dominant flora and fauna impacted by shore cleaning activities to remove oil Widespread damage to mussels and clams Reduction of nearly 1.9 million adult pink salmon returns in 1990 due to oil mortality Collapse of the Pacific herring population in PWS in 1993 due in part to EVOS Death of between 100,000 to 300,000 marine birds Mortality rates of 33% and 41%, respectively, in the two impacted orca pods Various degrees of oil contamination for 96% of seals surveyed at 25 haulout areas in PWS Death of over 2,600 or 40% of the approximate 6,500 sea otters that inhabited PWS Emergency fishery closures throughout the EVOS area affecting salmon, herring, crab, shrimp, rockfish, and sablefish fisheries Tourism impacts including a 35% reduction in visitor spending in the summer of 1989 in southwestern Alaska and 8% reduction in southcentral Alaska Average 50% reduction in the production of wild food volumes by Alaska Natives in ten Alutiiq villages in PWS, Lower Cook Inlet, and Kodiak Island in the year after the spill.
19. The EVOS produced catastrophic environmental, economic, and sociocultural impacts, some of which are evident 20 years after the initial grounding of the Exxon Valdez. To date only 10 of the 28 environmental resources assessed have fully recovered from the EVOS and none of the human services (commercial fishing, passive use, recreation and tourism, and subsistence) have recovered. Total estimated economic costs associated with the EVOS range between $12.2 and $131.1 billion (2010 CAD). The EVOS estimates can be used to estimate potential damage costs associated with a large oil tanker spill in CFN traditional territories (Table ES-4). If adjustments are made for Canada‟s smaller population, the damage estimates range between $5.2 and $22.7 billion (2010 CAD) to Canadians for a major spill comparable to the EVOS in CFN traditional territories. If non-Canadians
Northern Gateway Joint Panel Review - CFN Written Evidence 73 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 are included in the damage assessment, the damage costs would be similar to the EVOS estimates. It is also important to emphasize that these estimates exclude many important damage costs such as health of First Nations communities and legal costs, and are conservative estimates of other costs. Therefore the potential costs of a major oil spill in the PNCIMA would be much higher.
Table ES-4: Estimated Damage Costs of an Oil Tanker Spill in CFN Traditional Territories based on the EVOS
Economic Costs (in millions of 2010 Damage Category CAD) Lower Bound Upper Bound Economic Sectors Commercial Fishing $282.1 $1,382.0 Tourism $35.1 $35.1 Recreational Fishing $6.7 $92.0 Non-use Natural Resource Damages Non-use Values $1,118.1 $17,198.1 Wildlife Damages $45.7 $213.0 Sociocultural Impacts Subsistence Use $13.2 $42.5 Cultural and Heritage Impacts $1.4 $1.4 Oil Spill Cleanup Activities Costs Incurred by Exxon $3,691.5 $3,691.5 Total $5,193.8 $22,655.6
Assessing Potential Impacts of an Oil Tanker Spill Associated with the Enbridge Northern Gateway Project 20. The key criterion for assessing whether to approve projects under the Canadian Environmental Assessment Act is stated in Section 37(1)(b) as:
“where, taking into account the implementation of any mitigation measures that the responsible authority considers appropriate, the project is likely to cause significant adverse environmental effects that cannot be justified in the circumstances, the responsible authority shall not exercise any power or perform any duty or function conferred on it by or under any Act of Parliament that would permit the project to be carried out in whole or in part.”
Northern Gateway Joint Panel Review - CFN Written Evidence 74 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011
21. The criteria for determining whether a project causes significant adverse environmental effects are specified in the Federal Environmental Assessment Review Office‟s reference guide entitled Determining Whether a Project is Likely to Cause Significant Adverse Environmental Effects. The criteria are: Magnitude of the adverse environmental effect Geographic extent of the adverse environmental effects Duration and frequency of the adverse environmental effects Degree to which the adverse environmental effects are reversible or irreversible Ecological context defined as whether the region is fragile or vulnerable.
22. The significance of adverse impacts depends on the characteristics of an oil spill including size, chemical characteristics of the oil, location, weather conditions, time of year, ecological characteristics, settlement patterns, economic activities, geology, and other socio-economic and geographical features. Small spills may have more significant impacts than large spills and there is no clear correlation between size and impact.
23. The magnitude of potential adverse environmental effects of an ENGP oil spill is high. Based on the EVOS, impacts of an oil tanker spill associated with the ENGP would severely damage marine vegetation and cause high fatalities to marine invertebrates, fish, marine birds, and marine mammals. In total, an oil tanker spill could result in damages of between $5.2 and $22.7 billion to Canadians (2010 CAD) (Table ES-4) and cause major disruption to the traditional way of life for CFN members and their communities. According to the US environmental impact assessment of potential oil spills in Cook Inlet, even a smaller oil spill in the range of 238 m3 to 731 m3 could have major impacts including deaths of hundreds to tens of thousands of birds, tainting of fish, potential closure of a fishery for an entire season, mortality of several hundred marine and terrestrial mammals, mortality of fish and other organisms, and disproportionately high adverse effects on Native populations resulting from potential contamination of subsistence harvest areas, tainting concerns and disruption of subsistence practices. An oil spill in traditional CFN territories could have similar major adverse environmental effects that could impact economic and cultural values in CFN traditional territories.
24. The geographic distribution of adverse effects of an oil spill caused by the ENGP would be widespread. Accidental hydrocarbon releases from the EVOS contaminated at least 1,900 kms of shoreline and spread over 750 kms from the point of impact. In 2003, researchers at the National Oceanic and Atmospheric Administration documented lingering oil as far away as 700 kms from PWS. Enbridge predicts that 240 kms of shoreline could be oiled from a 36,000 m3 oil spill in the confined channel area of Wright Sound. A smaller spill in the range of 238 m3 to 731 m3 could impact up to 38 kms of shoreline and impact an area of between 618 and 1,100 km2.
Northern Gateway Joint Panel Review - CFN Written Evidence 75 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 25. Based on the EVOS experience, an oil spill in CFN traditional territories would produce long-term adverse environmental effects. After two decades, only 10 of 28 environmental resources that have been assessed have recovered and none of the human services (commercial fishing, passive use, recreation and tourism, and subsistence) have recovered. Long-term economic effects are associated with the collapse of the Pacific herring commercial fishery in PWS, while long-term cultural effects to Alaskan Natives include disruption to the transfer of intergenerational knowledge and more effort and increased costs needed to harvest subsistence resources. Even a smaller spill in the range of 238 m3 to 731 m3 could contaminate shorelines and fish habitats for up to a decade. Similarly, the impacts of an oil spill in CFN traditional territories could also be long-term.
26. There is insufficient evidence to make a determination on whether long-term environmental effects associated with the EVOS are irreversible. After two decades, only 10 of 28 environmental resources that have been assessed have recovered and it is possible that some species impacted by the EVOS may never recover. Similar effects could occur as a result of an oil spill in CFN traditional territories, although as suggested previously, more information on the PNCIMA and its species is needed to develop sufficient baseline data to assess impacts.
27. Adverse environmental effects may be significant if they occur in an area that is ecologically fragile. Coastal marine ecosystems of the PNCIMA provide critical habitats that support a diversity of species in the region and provide important habitat for rare and vulnerable species. The PNCIMA marine ecosystem is therefore highly susceptible to damages from an oil spill.
28. Based on the assessment summarized in Table ES-5, we conclude that the adverse environmental impacts of an oil spill greater than or equal to 238 m3 meet the FEARO criteria for significance.
Table ES-5: Summary of Criteria for Significance of Adverse Environmental Effects for the ENGP
Rating for ENGP Oil Criteria for Defining Significance Spill High Magnitude Yes Geographically Widespread Yes Long-term Yes Irreversible Unknown Ecological Vulnerability Yes Overall Rating Significant
29. The assessment of the likelihood of adverse environmental effects and whether the risk is acceptable is reviewed under five criteria:
Northern Gateway Joint Panel Review - CFN Written Evidence 76 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 I. The risk needs to be accurately assessed and the assessment needs to have the confidence of stakeholders. The assessment of risk is a combination of probability of an event times the magnitude of the impact, which should be described in quantitative terms so that it is comprehensible to decision makers in their determination of the likelihood of adverse significant environmental effects over the life of the project.
There is significant uncertainty regarding the probability of oil spill occurrences, ranging from very likely to less likely. This uncertainty needs to be resolved and oil spill occurrence rates need to be stated in terms of the probability of occurrence over the life of the ENGP, with a range based on confidence levels and sensitivity analysis. This analysis needs to be done in a manner acceptable to stakeholders so that all stakeholders and decision makers have confidence in the findings. There is also insufficient analysis of the magnitude of impacts. The analysis of oil spill impacts needs to cover a greater range of volumes (larger and smaller) than those assessed in the Enbridge application and the magnitude of impacts needs to be defined with greater precision.
II. The definition of acceptable risk must include the values and attitudes of affected parties towards risk and reflect the magnitude of adverse impacts.
Once the probability of occurrence is established, the definition of acceptable risk needs to be determined. The Enbridge QRA references the standards of risk in other jurisdictions in assessing oil spill risk for the ENGP. This is an inappropriate standard. Acceptable risk is a subjective standard defined by the parties that bear the risk and what is acceptable risk to some parties may not be accepted by others. In the case of the ENGP, no assessment has been made of the attitudes of those who will bear the risk and consequently no conclusion can be reached on whether the level of risk is acceptable. The acceptable level of risk also needs to be adjusted for the magnitude of adverse impacts. An acceptable likelihood of occurrence for a major oil spill will be lower than it will be for a less significant adverse environmental impact and may be lower than the risk accepted in other jurisdictions if the attitudes of those impacted are more risk averse and the magnitude of impacts is greater.
III. Are there alternatives that reduce or eliminate risk?
A key factor in determining whether the risk is acceptable is whether there are alternatives that involve less risk. In its regulatory submission, Enbridge has not assessed alternative means of shipping oil from the Western Canada Sedimentary Basin to market that reduce the risk of spills. Evidence produced in other reports shows there are feasible alternative transportation projects for Western Canada Sedimentary Basin oil that involve no risk of oil tanker spills and consequently the risk of tanker spills associated with the ENGP can be
Northern Gateway Joint Panel Review - CFN Written Evidence 77 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 eliminated if these alternatives are chosen. Given that there are viable alternatives that eliminate tanker spill risk, there is no reason to accept any risk of oil tanker spills associated with the ENGP.
IV. Are there appropriate compensation and/or mitigation measures that reduce risk and provide satisfactory remedies to affected parties?
The current mechanisms and processes are inadequate to provide compensation to affected parties. None of the basic elements of a compensation plan have been defined, including but not limited to: Identification of damages that are eligible and ineligible for compensation Identification of who is eligible and ineligible for compensation Identification of the methods that will be used to assess damages Identification of the parties that will pay compensation Source and quantity of funds required to pay compensation up to the level of damages Dispute resolution procedures to resolve conflicts expeditiously Agreement on the compensation plan between stakeholders and the project proponents. We also caution that it may be impossible to compensate for many types of damages. Therefore affected parties bear enormous risk regardless of compensation provisions.
V. Is the risk equitably shared among stakeholders?
The risk of a major oil spill is borne by First Nations and other residents of the PNCIMA, along with other Canadians who value the PNCIMA environment. Some risk is also incurred by the shipper who will bear restricted liability for damages. No risk of a major marine oil spill is borne by the project proponent. Therefore the risk of adverse environmental effects is not equitably shared among stakeholders.
30. In sum, none of the criteria for defining acceptable risk for oil spills have been met for the ENGP (Table ES-6).
Table ES-6: Criteria for Defining Acceptable Risk for Oil Spills for the ENGP
Criteria for Acceptable Risk Criteria Met? Probability and Magnitude Established No Acceptable Levels of Risk Defined No Alternatives Assessed No Appropriate Compensation/Mitigation No
Northern Gateway Joint Panel Review - CFN Written Evidence 78 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 Equitable Sharing of Risk No
Conclusion 31. The conclusion of this report is that an oil spill resulting from the Enbridge Northern Gateway Project would result in significant adverse environmental effects and that there is insufficient evidence to make a determination regarding the likelihood and acceptability of the risk associated with these significant adverse environmental effects.
Further, determining whether the risk of significant adverse environmental effects is likely and whether the risk is acceptable requires resolution of outstanding issues that include but are not restricted to: The assessment of affected stakeholder definitions of acceptable risk The probability of spills The impact of spills Damage cost estimates of spills Better baseline information Assessment of alternative transportation options for oil Development of comprehensive mitigation measures, monitoring and enforcement procedures, and compensation plans.
These issues need to be resolved through a collaborative joint fact finding process before any decision can be made on the ENGP.
Part XI, Evidence with Respect to the Inadequacies of the Regime Governing Liability for Oil Spills
There are serious concerns about the liability regime with respect to the costs of clean up and compensation for the inevitable oil tanker spills: a) difficulties with multiple responsible parties; b) inadequate size of liability funds; c) difficulties receiving compensation.
Northern Gateway Joint Panel Review - CFN Written Evidence 79 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 The US Experience - BP Deepwater Horizon Oil Spill Deepwater Horizon
Washington Post Report The following report on the BP Deepwater Horizon spill illustrates some of the liability issues that occur when costly catastrophic oil spills involve multiple parties:76
Cameron International, the maker of the blowout preventer that failed to stop the massive oil spill in the Gulf of Mexico last year, has agreed to pay $250 million to BP…BP would indemnify Cameron from claims related to the Oil Pollution Act and environmental damage, but not against fines, penalties or certain other types of claims. He warned, however, that BP was ―not out of the woods yet.‖ BP remains at odds with Halliburton, which provided the cement that was supposed to seal the Macondo well, and with Transocean, owner and operator of the $500 million Deepwater Horizon rig…Both contractors have accused BP of missteps leading to the accident, while BP has faulted Halliburton‘s cement mixture and Transocean rig design and operation. Moreover, BP is still mired in litigation that could last years, much as Exxon Mobil remained locked in long-running lawsuits after the 1989 Exxon Valdez oil tanker spill off Alaska.
Pavel Molchanov, oil analyst at financial services company Raymond James [said] ―There will be lingering litigation for years to come. Remember, it took 19 years for the Exxon Valdez litigation to clear up…BP has paid out $7.5 billion to individuals, companies and governments for claims and damages resulting from the spill. It estimates the final cost of the spill, including government fines, will climb to $42 billion.
Cameron chief executive Jack Moore said. ―Cameron is the fourth company to settle with BP and contribute to economic and environmental restoration efforts in the Gulf,‖ BP chief executive Bob Dudley said in a statement. ―Unfortunately, other companies persist in refusing to accept responsibility for their roles in the accident and for contributing to restoration efforts.‖ Oppenheimer‘s Gheit said that BP wants to settle remaining claims as soon as possible. ―BP has made it very clear that they have no interest in litigating this forever, unlike Exxon, which [in the Valdez incident] said I‘ll see you in court. BP has said it is willing to take its share of the blame, but the sooner we settle
76 Cameron International settles with BP on 2010 oil spill claims, Steven Mufson,, Washington Post, December 16, 2011 http://www.washingtonpost.com/business/economy/cameron-settles-with-bp-on-oil-spill- claims/2011/12/16/gIQAnXudyO_story.html
Northern Gateway Joint Panel Review - CFN Written Evidence 80 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 the better off we‘ll be. Its approach is completely the opposite of Exxon‘s.‖
National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling The National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, in its report, The Gulf Oil Disaster and the Future of Offshore Drilling, recommended that:
If liability and financial responsibility limits are not set at a level that will ensure payment of all damages for spills, then another source of funding will be required to ensure full compensation. The federal government could cover additional compensation costs, but this approach requires the taxpayer to foot the bill. Therefore, Congress should raise the Oil Spill Liability Trust Fund per incident limit because the current limits are clearly inadequate….Raising the Oil Spill Liability Trust Fund‘s per-incident limit will require the Fund to grow through an increase of the per-barrel tax on domestic and imported oil production. An alternative would be to increase the Trust Fund through a surcharge by mandatory provisions in drilling leases triggered in the event that there are inadequate sums available in the Fund. An increase in the Oil Spill Liability Trust Fund‘s per-incident limit would not provide an incentive to offshore facilities to mitigate risks, because risks are pooled and the Oil Spill Liability Trust Fund is funded by parties other than those who engage in offshore drilling activities. But raising the limit would help ensure that victims have access to compensation without the need to seek further specific funding from Congress, or otherwise burdening the taxpayer (page 48).
Liability of Multiple Parties As has been amply illustrated by both the Deepwater Horizon and the Exxon Valdez events, oil spills inevitably result in protracted litigation and court cases. A spill related to a NGP tanker will be no different, especially since liability issues are complicated by the facts that:
There are two parties responsible for oil spills: NGP at the Terminal and the tanker owner away from the Terminal;
NGP, despite the tanker owner‟s responsibility for spills away from the Terminal, is assuming „extended responsibility‟ for emergency response along the marine transportation routes (e.g. establishing spill response capability);
The ability of the tanker owner, the responsible party in the event of a spill, to respond to spills is dependent on the spill response capability provided by NGP;
Northern Gateway Joint Panel Review - CFN Written Evidence 81 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011
Through it Tanker Acceptance Program, NGP will be responsible for ensuring tanker meet its requirements; and,
NGP intends to participate in the Integrated Command System for oil spill response at either the terminal or a marine transportation spill (NGP Response to JRP IR 8.23).
Liability Regimes for Black Swan Events Professor W. Kip Viscusi, of Vanderbilt University,77 and his colleagues from Harvard, who, in their paper prepared in response to the two most recent catastrophic incidents, Japan‟s nuclear incident and the BP Deepwater Horizon spill, note that the one central lesson from these two disasters is that it is extremely difficult to predict the nature of or magnitude of catastrophic events (“Black Swans”).
Professor Viscusi and his colleagues provide the following rationale for the need to review liability regimes:
Oil spills impose severe external financial and environmental harms that a profit maximizing firm will not take into full account absent liability and/or government sanctions; Catastrophic environmental risks add an additional dimension to the traditional externalities problem—the potential that even with existing systems of liability a firm may be judgment proof for a significant portion of losses, hence too reckless; Regulation alone will not be sufficient, since it will likely be directed to yesterday‗s problem; Liability schemes that might function well for traditional environmental externalities are not well equipped to deal with extreme potential outcomes. Indeed, given that few corporations have sufficient resources to cover the most extreme outcomes, the efficient control regime must incorporate not merely regulation and liability, but also include some tax charges for any extreme risks imposed on external parties that will not be addressed should the company‗s financial resources be exhausted.
As Professor Viscusi and his colleagues see the issue of liability for Black Swan events (low probability-high consequence) as a choice between two poor choices: impose a modest damages limit or a no limit to liability exposure. The first would lead firm to taking excessive risks, while the second would impose losses exceeding many firms‟
77Viscusi, W. Kip; Vanderbilt University and Zeckhauser, Richard J., Harvard University, Deterring and Compensating Oil Spill Catastrophes: The Need for Strict and Two-Tier Liability, Vanderbilt University Law School Law and Economics, Working Paper Number 11-27, May 12, 2011, http://ssrn.com/abstract=1866391
Northern Gateway Joint Panel Review - CFN Written Evidence 82 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 financial resources. Consequently, Professor Viscusi and his Harvard colleagues propose the following:
One Identifiable responsible party. This ensures that there is one party overseeing the whole process, a party that coordinates and monitors the actions of those beneath it. There is no separate liability for other firms involved. The oil company can establish whatever contractual arrangements it wishes with other firms involved in the drilling operations, and the oil company in turn can recoup costs due to negligence or other specified behavior of its corporate partners based on whatever contractual arrangements it makes with them. The responsible party is strictly liable for all losses due to the spill and there is no need to evaluate the behaviour of other partners; Tax on non-compensable risk. Since no corporation has sufficient resources to cover the most extreme potential losses from a mega-catastrophe, either the government will pay significant amounts and/or losses will go uncompensated. The result is that the operator will essentially be judgment proof for extreme accidents. Absent other arrangements, excess risks will therefore be undertaken. To correct this propensity, the operator should pay a tax for the expected external losses imposed beyond the amount that it will be able to pay; Demonstration of financial capacity. Restrict deepwater oil drilling [or in this case oil export] to firms that can demonstrate either adequate financial resources or insurance to cover the cost of catastrophic spills; Eliminate Cap on Damages. The elimination of the damages cap couple will establish incentives for safety. Because catastrophic oil spills can be readily monitored, additional punitive damages are not needed to establish the efficient level of care. Natural resources damages and restoration. For natural resource damages, the primary emphasis should be on restoration. Restoration should continue until the natural resource benefits of additional restoration no longer exceed their costs; Recipient of net resource value losses. For any shortfall of the restoration from complete restoration, the oil company must pay the government for the natural resource damages that are incurred. Such damages would also include losses for the period before a resource is restored; Regulatory complement. Liability should be coupled with a regulatory regime where the regulation of drilling activities [or in this case oil export] was based on a comparison of the benefits and costs of these efforts, with the goal to maximize benefits less costs. Full adherence to regulatory standards would not protect a firm against damages from accidents; Focused, net economic benefits. In assessing the benefits of deepwater oil drilling [or in this case oil export], there should be no additional premium accorded to the economic benefits associated with national security or employment effects beyond the assessed benefits for other less risky drilling activities, or other sources of energy. Any crediting of oil exploration of any kind with broader economic benefits to the economy must be done on a net benefit basis that also incorporates recognition of the environmental harms
Northern Gateway Joint Panel Review - CFN Written Evidence 83 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 associated with the production and consumption of petroleum products, including the effect on global climate change; Moratorium. Until these proposals (with modifications to be expected) are adopted, there should be a moratorium on all new deepwater drilling activities. Exemptions from the moratorium should be granted to a firm accepting strict liability, demonstrating adequate financial resources to pay for the costs of a major disaster, paying the tax for the expected damages beyond its financial capacity, and subjecting its proposed drilling operations to a safety review.
Professor Viscusi summarizes his proposals as follows:
Our proposal jettisons the current structure of a low damages cap coupled with ineffective regulation. It replaces it with a greatly expanded level of liability coupled with a tax to provide incentives for risks beyond the liability limit, which we call a two-tier liability system. This system creates strong financial incentives for safety. If welcomed by the risk-control community, this structure can provide the framework not only for addressing deepwater drilling risks but for other catastrophic risks. That is, with modest modifications it could be employed to address a broad range of catastrophic environmental risks. Our proposal starts by recognizing that the potential for catastrophic accidents generally, and the BP accident specifically, represents the challenge of effectively controlling risks that impose damages on others in their most extreme form.
Part XII, Evidence with Respect to Marine Use Planning
Integrated marine management is an improved approach to traditional marine management as it addresses inadequate governance practices that contributed to growing instability in marine ecosystems by managing multiple uses and integrating multiple authorities and stakeholders into the decision-making process though the development and implementation of a consensus-based plan based on jointly agreed goals and objectives.
Integrated marine planning also provides environmental protection to ecosystems and the species within them by: completing an inventory of existing and proposed future activities; identifying high value environmental resources; developing a plan that regulates activities while accommodating demand for natural resources and protecting the environment
Mechanisms to protect environmental assets may include: zoning restrictions that allocate specific uses to designated areas and regulations that govern activities in specified zones; and
Northern Gateway Joint Panel Review - CFN Written Evidence 84 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 designating areas of high environmental value as marine protected areas that prohibit damaging activities.
Gunton Report As part of its evidence, CFN has commissioned a study by Dr. T. Gunton and Sean Broadbent of SFU, provided in Appendix III of this submission. This study noted that:
that evaluating a major project such as ENGP in the absence of an integrated marine management plan that is developed and approved by stakeholders and government significantly increases the risks of environmental damage, which will inhibit sustainable development and threaten traditional and cultural practices of First Nations in the region. NCIMA planning process and reduce the scope of the work plan.
Unilateral DFO Changes to PNCIMA PNCIMA marine planning process was formally launched in 2009 to address deficiencies in the current management regime. On September 11, 2011, DFO advised CFN that it was unilaterally withdrawing from the existing Pacific North Coast Integrated Management Area (PNCIMA) Project Support MOU and changing its approach to developing an Integrated Oceans Management Plan for the PNCIMA area “to ensure that the PNCIMA plan is completed on schedule by Dec. 2012. DFO is committed to a final plan that will focus on informing regulatory responsibilities and activities in the area, as well as identifying the key significant and sensitive areas through the existing science and other work.” DFO further advised that it intended to maintain the Collaborative Ocean Governance MOU with First Nations on the Coast as a “framework to govern the development of a focussed, sustainable and effective strategic plan.”
Some people have speculated that the reason for this decision was to prevent the possibility that PNCIMA would result in a consensus against the use of oil tankers in the PNCIMA area that includes the Enbridge OWA and CCAA. As reported by the Vancouver Sun (September 8, 2011):78
They're following conspiracy theories, said New Democratic Party MP Nathan Cullen (Skeena-Bulkley Valley);
While it [the letter] sounds innocent, what it does is fundamentally dismantle the capacity" to create an integrated oceans management plan, said Bill Wareham, senior marine conservation specialist at the David Suzuki Foundation. Wareham ridiculed the notion that the PNCIMA process could ever have resulted in an anti-economic
78 http://www.vancouversun.com/news/Harper+backs+from+initiative+that+threatens+opposition+pipeline/ 5372085/story.html
Northern Gateway Joint Panel Review - CFN Written Evidence 85 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 development plan, given the Harper government's declared support for the oilsands industry. "It's so fear-based."
Since the PNCIMA plan has been gutted by DFO, it is unclear whether or not First Nations will participate in development of the plan since, among other things: PNCIMA is not likely to collect data to assess marine transportation impacts – in fact DFO has avoided in-depth consideration of transportation impacts; the advisory process is not consensus, and, a decision to proceed with the NGP outside the planning process affects Aboriginal Title and Rights. Accordingly, DFO‟s new approach will be deficient in informing JRP considerations.
Instead First Nations are focusing on development of four sub-regional plans and a common regional plan in partnership with the Province.
Northern Gateway Joint Panel Review - CFN Written Evidence 86 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011 APPENDICES
Appendix I - A Public Interest Assessment of the Enbridge Northern Gateway Project, Dr. Thomas Gunton and Sean Broadbent
Appendix II - Marine Navigation: Measures to Reduce the Risk of Martine Incidents, Captain Harrison Layton and Michael McGuire
Appendix III – Review of Potential Impacts to CFN, Dr. Thomas Gunton and Sean Broadbent
Appendix IV - Application Review, Dr. Gerald Graham
Northern Gateway Joint Panel Review - CFN Written Evidence 87 NEB FILE OF-FAC-OIL-N304-2010-01 01 – Hearing Order OH-4-2011
A Public Interest Assessment of the Enbridge Northern Gateway Project
Dr. Thomas Gunton Sean Broadbent
Prepared for Coastal First Nations
Final Report January 2012
Executive Summary 1. The purpose of this report is to assess whether the proposed Enbridge Northern Gateway Project (ENGP) meets the approval criteria as specified in Section 52 of the National Energy Board Act. The National Energy Board (NEB) approval criteria require the applicant to show that: a) The project is required by the present and future public convenience. b) The project is in the public interest.
2. The ENGP application states that the ENGP is required and in the public interest for the following reasons: a) Oil production in Western Canada will increase over the next several decades and increased production will require an increase in pipeline capacity to transport the oil to markets. b) Asian oil consumption is expected to grow much faster than US consumption over the next several decades and this faster growth, combined with benefits of market diversification and a higher price of oil in the Asian market, makes Asia a more attractive market for Canadian oil than the US. c) Building the ENGP will generate economic impacts estimated by Enbridge to include an increase in gross domestic product of $270 billion (2009 CAD), increased employment of 558,000 person years, and increased government revenue of $81 billion (2009 CAD).
3. The evidence in the ENGP application that the ENGP is required and meets the public interest is incomplete and deficient in the following respects: a) The application does not provide evidence of firm shipping contracts or identify with adequate detail refinery specific markets for the product being shipped. b) Although the application contains oil supply and pipeline capacity information, the application does not provide a pipeline demand and supply analysis and therefore does not demonstrate that the ENGP is needed or required. c) The application includes an estimated benefit from shipping oil to Asia based on a forecast permanent Asian price premium and assumes that reducing oil volumes shipped to the US will result in a permanent increase in Canadian export prices without providing adequate evidence to support either of these claims. d) The application does not measure the contribution of the project to the Canadian public interest. Instead, the submission provides an estimate of gross economic impacts instead of net economic impacts and incorrectly assumes that gross economic impacts are economic benefits. e) The application does not include economic, social, and environmental costs in the public interest analysis despite explicit NEB requirements to do so. f) The application uses inappropriate terminology and methodology that results in significant exaggeration of the economic impacts. Actual net economic and fiscal impact benefits will be much lower than the gross
i impacts forecast by Enbridge because most of the labour and capital employed on the ENGP would be employed elsewhere in the economy if the ENGP was not built.
4. To assess the need for the ENGP, supply and demand data for pipelines serving the Western Canada Sedimentary Basin (WCSB) from the Canadian Association of Petroleum Producers were examined. The data show that there is currently surplus pipeline capacity and with forecast pipeline additions there is enough capacity to meet demand until after 2020. Therefore, the data show that the ENGP is not needed or required during the forecast period to 2020 and building the ENGP as planned will result in surplus capacity.
5. Forecasting oil transportation requirements is subject to uncertainty. Different forecast assumptions will result in different capacity requirement conclusions and there are potential costs to both over- and under-estimating capacity requirements. The risk assessment indicates that there is greater likelihood that the need for new WCSB transportation capacity will be less than forecast. If demand is higher than forecast, there is sufficient lead-time to provide additional capacity to meet demand without risking shutting in of WCSB production. Further, if and when there is sufficient demand to justify consideration of the ENGP, the ENGP needs to be evaluated relative to other transportation options, many of which involve no risk of major marine oil spills, to ensure that the most cost-effective options are chosen.
6. To assess whether the ENGP meets the NEB public interest criteria, a benefit cost assessment (BCA) was conducted. The first stage of the BCA examined only the costs and benefits to the Canadian oil industry. Twelve different scenarios were tested and under all scenarios the ENGP is forecast to result in a net cost to Canada. The net costs range from $362.4 million to over $2.2 billion (2009 CAD). These estimates do not include any social or environmental costs. If social and environmental costs such as the cost of oil spills, greenhouse gas emissions, social conflict, and other environmental impacts are included, the net cost of the ENGP to Canada would be significantly higher.
Conclusion 7. It is concluded that the Enbridge application fails to show that the ENGP meets the need and public interest criteria required for NEB approval. The evidence presented in this report also indicates that it is highly unlikely that the ENGP is needed or required within the forecast period to 2020 and that the ENGP is not in the Canadian public interest.
ii Table of Contents 1. INTRODUCTION ...... 1 1.1. NATIONAL ENERGY BOARD APPROVAL CRITERIA ...... 1 1.2. ENBRIDGE SUBMISSION ON PUBLIC INTEREST ...... 1 2. NEED FOR THE ENBRIDGE NORTHERN GATEWAY PROJECT ...... 2 2.1. ENSYS ENERGY PIPELINE EVALUATION ...... 6 2.2. MARKET ASSESSMENT ...... 7 2.3. QUALIFICATIONS AND RISKS TO NEED ASSESSMENT ...... 9 2.4. CONCLUSION ON NEED FOR ENBRIDGE NORTHERN GATEWAY PROJECT ...... 12 3. ECONOMIC IMPACTS AND PUBLIC INTEREST ...... 12 3.1. CONFUSING TERMINOLOGY ...... 13 3.2. GROSS IMPACTS VERSUS INCREMENTAL IMPACTS ...... 15 3.3. ECONOMIC IMPACTS AND ECONOMIC BENEFITS ...... 17 3.4. EXCLUSION OF COSTS ...... 17 3.5. ASIAN PREMIUM AND WCSB NETBACKS ...... 18 4. BENEFIT COST ASSESSMENT OF ENBRIDGE NORTHERN GATEWAY PROJECT ...... 20 5. CONCLUSION ...... 27 REFERENCES ...... 29
List of Figures and Tables
FIGURE 1: HISTORICAL AND FORECAST ASIA PREMIUM PROVIDED BY MUSE STANCIL IN ENBRIDGE (2010A) ...... 19
TABLE 1: WESTERN CANADIAN CRUDE OIL SUPPLY (THOUSANDS OF BPD) ...... 3 TABLE 2: WESTERN CANADIAN PIPELINE CAPACITY ...... 5 TABLE 3: FORECAST OIL PIPELINE SUPPLY AND DEMAND BALANCE (THOUSANDS OF BPD) ...... 6 TABLE 4: ENSYS ANALYSIS OF WCSB PIPELINE SUPPLY AND DEMAND BALANCE (THOUSANDS OF BPD) ...... 7 TABLE 5: BENEFIT COST RESULTS TO WCSB OIL SECTOR- NO SOCIAL-ENVIRONMENTAL COSTS (2009 CAD) ...... 23 TABLE 6: DAMAGE ESTIMATES FOR GHG EMISSIONS FROM ENGP ...... 26 TABLE 7: SUMMARY OF SELECTED ENVIRONMENTAL COSTS ASSOCIATED WITH THE ENGP ...... 27
iii List of Acronyms
BC British Columbia BCA Benefit Cost Analysis BPD Barrels Per Day CAD Canadian Dollar CAPP Canadian Association of Petroleum Producers CV Contingent Valuation ENGP Enbridge Northern Gateway Project ERCB Energy Resources Conservation Board GHG Greenhouse Gas KBPD Thousand Barrels Per Day NEB National Energy Board PADD Petroleum Administration for Defense District PNCIMA Pacific North Coast Integrated Management Area PHRCC Petroleum Human Resources Council of Canada PWS Prince William Sound US United States USD United States Dollar WCSB Western Canada Sedimentary Basin WTA Willingness to Accept WTI West Texas Intermediate WTP Willingness to Pay
iv 1. Introduction The purpose of this report is to assess whether the Enbridge Northern Gateway Project (ENGP) meets the criteria for project approval for pipelines as set out in the National Energy Board Act. The report begins with a review of the approval criteria in the National Energy Board Act. This is followed by an evaluation of the evidence provided in the ENGP application regarding the need and public interest benefits of the ENGP. Additional evidence is then provided to assess if the ENGP meets the approval criteria as specified in the National Energy Board Act. 1.1. National Energy Board Approval Criteria Section 52 of the National Energy Board Act requires the National Energy Board (NEB) to utilize the following criteria when assessing an application for a pipeline. The National Energy Board Act states:
The Board may, subject to the approval of the Governor in Council, issue a certificate in respect of a pipeline if the Board is satisfied that the pipeline is and will be required by the present and future public convenience and necessity and, in considering an application for a certificate, the Board shall have regard to all considerations that appear to it to be relevant, and may have regard to the following: (a) the availability of oil, gas or any other commodity to the pipeline; (b) the existence of markets, actual or potential; (c) the economic feasibility of the pipeline; (d) the financial responsibility and financial structure of the applicant, the methods of financing the pipeline and the extent to which Canadians will have an opportunity of participating in the financing, engineering and construction of the pipeline; and (e) any public interest that in the Board’s opinion may be affected by the granting or the refusing of the application.
The NEB defines the public interest as follows:
The public interest is inclusive of all Canadians and refers to a balance of economic, environmental, and social interests that change as society’s values and preferences evolve over time. The Board estimates the overall public good a project may create and its potential negative aspects, weighs its various impacts, and makes a decision (NEB 2010 p.1). 1.2. Enbridge Submission on Public Interest The Enbridge application states that the ENGP is needed and is in the public interest for the following reasons (Enbridge 2010a Vol. 2, pp. 1-13-1-14): • Oil production in Western Canada will increase over the next several decades and this increased production will require an increase in pipeline capacity to transport the oil to markets
1 • Asian oil consumption is expected to grow faster than United States (US) consumption over the next several decades and this faster growth, combined with the benefits of market diversification and a higher price of oil in the Asian market, makes Asia a more attractive market for Canadian oil than the US • Building the ENGP will generate economic impacts estimated by Enbridge to include an increase in gross domestic product of $270 billion (2009 CAD), increased employment of 558,000 person years, and increased government revenue of $81 billion (2009 CAD) throughout Canada.
2. Need for the Enbridge Northern Gateway Project Enbridge provides a summary of various production forecasts from the NEB, Canadian Association of Petroleum Producers (CAPP), and the Energy Resources Conservation Board (ERCB) that show that Western Canada Sedimentary Basin (WCSB) oil production is forecast to increase. Enbridge acknowledges that the forecasts of increased production vary significantly and that forecasting production is an inexact science (Enbridge 2010a Vol. 2, p. 1-4).
Enbridge relies on an analysis of oil markets completed by Muse Stancil on behalf of Enbridge to identify market opportunities (Enbridge 2010a Vol. 2, App. A). The market analysis uses CAPP 2009 forecasts for oil supply and analyzes the growth in Asian oil consumption, refinery capacity and transportation costs. Based on the analysis, Muse Stancil estimates that the Asian market can absorb 1.75 million barrels per day (bpd) of WCSB exports and therefore there is ample supply and demand to justify the 0.525 million bpd supplied by the ENGP. Muse Stancil also forecasts that netbacks to producers selling into the Asian market will be higher due to an Asian price premium. Enbridge concludes its need assessment by stating that:
Figure 1-3 (ERCB forecast) shows large oil sands supply volumes through 2018 because of significant global demand for oil and steadily rising oil prices. New markets and pipeline capacity to supply them will be needed to support this growth (Enbridge 2010a Vol. 2, p.1-5).
We agree with the conclusion of Enbridge that WCSB production will increase and there is growing demand for oil in Asia. However, the Enbridge analysis is incomplete in the following respects. First, the market analysis by Enbridge is highly aggregated and does not show specific refineries and locations that would take WCSB oil. Given some of the characteristics of the product shipped (heavy oil) it is important to identify the specific refineries willing and able to process the product. Second, although Enbridge includes both production forecasts and pipeline capacity estimates, neither the Enbridge submission nor the Muse Stancil study compare the forecast production with pipeline capacity to document the need for the ENGP project. Therefore, the ENGP does not provide sufficient documentation to justify the need for the ENGP. To justify the need for the ENGP, a more detailed assessment is required that examines the supply/demand balance for pipelines to assess the need for new capacity.
2 To assess the need for ENGP we have compared production forecasts with current and forecast pipeline capacity based on the most recent 2011 CAPP forecast. CAPP provides a forecast to 2025 for oil production and oil supply (CAPP 2011). The supply forecast represents the volume of oil that needs to be transported and is higher than the production forecast because the transformation of the product to be shipped (primarily the addition of diluent) increases its volume. Two oil supply forecasts are provided: an operating/under construction case and a growth case (Table 1). The operating and under construction case includes production from existing capacity plus incremental capacity based on projects currently under construction. The growth case adds incremental production from both projects under construction and anticipated projects not yet started. The operating and under construction case provides a reliable estimate of the minimum supply that will be produced because investments are already in process. The growth forecast is more uncertain because the anticipated projects not yet started may proceed faster or slower depending on demand and supply constraints. In assessing the accuracy of this forecast it is interesting to note that previous CAPP forecasts made between 2000 and 2008 for the year 2010 consistently overestimated actual 2010 production, in some cases by about 500,000 bpd (Enbridge Vol. 2, p. 1-4). CAPP WCSB supply forecasts for 2020 also exhibit a wide fluctuation depending on the year they were done. The 2020 forecast provided in the most recent CAPP report (2011), for example, is approximately 500,000 bpd higher than the 2009 CAPP forecast. We also note that the 2011 CAPP forecasts are higher than the 2011 NEB reference case forecast released in November of 2011 (NEB 2011 p. 18).
Table 1: Western Canadian Crude Oil Supply (thousands of bpd)
2011 2015 2020 2025 Operating and in 2,822 3,508 3,552 3,394 Construction Forecast Growth Forecast 2,822 3,549 4,466 5,245 Less Intra-Western Canada 462 542 542 542 Consumption* Equals WCSB Exports-Growth Forecast 2,270 2,917 3,834 4,613 Plus Bakken exports on Enbridge and 161 430 430 430 TCPL** Equals Net Forecast Pipeline 2,521 3,437 4,354 5,133 Demand*** Source: CAPP (2011) * Intra-Western Canada consumption consists of deliveries to western Canada refineries. CAPP’s forecast for intra-Western Canada refinery consumption is 632 kbpd for 2015. CAPP does not provide forecasts beyond 2015 so it is conservatively assumed that intra- Western Canada refinery consumption remains constant at 632 kbpd for the forecast period to 2025. The CAPP 632 kbpd intra- Western Canada refinery consumption is adjusted for volumes of crude delivered to refineries and refined products by deducting 55 kbpd delivered to the Chevron refinery and deducting the net refined products delivered to Vancouver on the KM TX system (net refined products on KM TX are the total refined deliveries (46 kbpd) less the crude deliveries (11kbpd) supplied to the KM TX system by the Pembina pipeline). The crude supply to the Consumers Cooperatives refinery and the Moose Jaw asphalt plant have been included in the intra-Western consumption because although they take crude deliveries from the Enbridge mainline, they are located upstream of the proposed Cromer Bakken connection and will not displace forecast Bakken crude to be shipped on the Enbridge line. ** Forecast Bakken exports transported on Enbridge are not provided by CAPP. The forecast for Bakken is based on the existing and forecast capacity of the Enbridge pipelines connecting Bakken to the Enbridge mainline as provided by CAPP (2011) including the North Dakota Pipeline (expanding from 161 kbpd to 185 kbpd) and the recently approved Enbridge Bakken expansion project (145 kbpd) expected to be in operation in 2013. We have also included an additional expansion of 100 kbpd representing either the proposed Keystone connection or a further expansion of the Enbridge Bakken system. *** Net forecast pipeline demand is the CAPP growth forecast less intra-Western Canada consumption plus Bakken exports.
3 To estimate the demand for WCSB pipeline capacity, several additional adjustments to the WCSB supply forecast are required. First, the volume of oil consumed within Western Canada needs to be deducted from the oil supply estimate to derive the oil export volume. CAPP estimates oil consumed in Western Canada refineries at 552,000 bpd in 2010, rising to 632,000 in 2015 (CAPP 2011 p.9). CAPP does not provide forecasts for intra-Western Canada consumption beyond 2015 so we assume no increase beyond 2015. The CAPP intra-Western refinery consumption estimate is adjusted to reflect crude and refined product exports from Alberta.
The next adjustment is to include demand for Canadian pipeline capacity from oil producers in the US Bakken region. Currently, production in the Bakken region is just under 500 kbpd (NDMR 2011a). This region is experiencing increased oil production with forecasts ranging up to just over 1,000 kbpd by 2020, and then declining (NEB 2011b, p. 10). The current oil transportation capacity is comprised of two major pipelines (Butte and Enbridge North Dakota) and rail facilities. Proposed and under construction rail and pipeline expansions have the potential to increase total oil transportation capacity to about 1,500 kbpd, which is well in excess of forecast production (Ensys 2011 p. 48, p.83). Therefore, there is substantial competition among shippers and not all transportation projects are likely to proceed. We assume that Bakken oil will continue to be shipped on the Enbridge North Dakota Pipeline, which connects to the Enbridge mainline at Clearbrook, Minnesota. Current capacity of this pipeline is being increased to 185 kbpd (CAPP 2011 p.19). Enbridge recently received NEB approval to expand its Bakken pipeline capacity to transport an additional 145 kbpd of Bakken oil connecting to its mainline by 2013 and TransCanada is proposing to transport 100 kbpd on Keystone. Based on this, we assume that there will be a total of 430 kbpd of Bakken oil transported on either the Enbridge or Keystone systems by 2020. Bakken oil not transported on the Canadian export pipeline system will be consumed by the Tesoro refinery (58 kbpd), shipped on an expanded Butte pipeline and/or the expanding rail oil transportation systems.
CAPP also provides an estimate of existing and forecast pipeline capacity (CAPP 2011). The estimates of pipeline capacity vary with the type of product moved. The capacity to move heavy oil is lower than lighter oil of the same volume. Estimates of current and forecast capacity and the assumptions about the quantity of heavy versus light oil underlying the CAPP capacity estimates are provided in Table 2.
4 Table 2: Western Canadian Pipeline Capacity
Annual Capacity Pipeline Crude Type (1,000 bpd) Existing Capacity Light 1,069 Enbridge Heavy 796 Express Light (35%)/Heavy (65%) 280 Trans Mountain Light (80%)/Heavy (20%) 300 Alberta Clipper Heavy 450 Keystone Light (25%)/Heavy (75%) 591 Rangeland* Light 85 Bow River* 129 Total Existing Capacity 3,690 Proposed Capacity Alberta Clipper 350 Keystone XL** 700 Northern Gateway 525 Kinder Morgan TMX2 80 Kinder Morgan TMX3 300 Total Proposed Capacity 1,955 Total Existing and Proposed Capacity 5,645 Source: CAPP (2011) Figures may not add due to rounding * Rangeland and Bow River are included on pipeline maps by CAPP but their capacity is not included in the CAPP report. Capacity numbers for these two pipelines were provided by ENSYS (2011). ** Ensys (2011 p.19) reports that Keystone XL has potential to expand to 830 kbpd.
The supply/demand for pipeline scenarios are summarized in Table 3. The forecasts show that existing capacity is sufficient to meet demand to 2015. Under CAPP’s growth scenario, there may be a capacity shortage by 2020, equivalent to 664,000 bpd. If Enbridge expands Clipper to its full potential of 800,000 bpd and if Keystone XL is built, there is potential surplus capacity of 386,000 bpd in 2020 and a capacity shortfall of 393,000 bpd in 2025. These forecasts indicate that there is sufficient pipeline capacity without ENGP to meet demand until after 2020 and building ENGP as planned will result in surplus capacity. We caution that forecast of supply and demand and pipeline capacity requirements is subject to uncertainty and that different assumptions will lead to different estimates of capacity requirements. We also caution that managing supply and demand for oil transportation is a complex undertaking subject to engineering and marketing constraints. Therefore pipeline capacity utilization may be higher or lower than forecast. We address the implications of this uncertainty later in this report.
5
Table 3: Forecast Oil Pipeline Supply and Demand Balance (thousands of bpd)
2011 2015 2020 2025 Demand 2,521 3,437 4,354 5133 Current Capacity 3,690 3,690 3,690 3,690 Surplus/Deficit +1,169 +253 -664 -1,443 Clipper Expansion 350 350 350 Keystone XL 700 700 700 Surplus/Deficit +1,169 +1303 +386 -393 Kinder Morgan TMX 2, 3 and ENGP 905 905 Surplus/Deficit +1,169 +1303 +1,291 +512 % Capacity Use 68% 73% 77% 91%
2.1. Ensys Energy Pipeline Evaluation Another assessment of Canadian oil pipeline capacity has been completed by Ensys Energy (2010; 2011) for the US Department of Energy. Ensys used its Oil Refining Logistics & Demand (WORLD) model to assess potential impacts of alternative pipeline scenarios on WCSB oil production, market destination of Canadian oil, and US supply and demand for oil. Although the study was done primarily to assess the impacts of building or not building the Keystone pipeline, the study assesses the impact of the ENGP as part of its scenarios.
The study uses the following key inputs: • Two international oil demand and supply scenarios (reference case and low demand case) based on the US Energy Information Administration Annual Energy Outlook for 2010 • Canadian oil supply projections generated by the Canadian Association of Petroleum Producers in 2010 • Existing and proposed oil pipeline and other oil transportation projects.
The study tests the impact of six scenarios involving construction of new pipeline capacity and one scenario involving no new capacity on Canadian production and US supply and demand flows for oil to 2030. The seven scenarios identified by Ensys are:
1. Keystone XL 2. Keystone XL, Trans MountainX2, Trans MountainX3, 3. Keystone XL, Trans MountainX2, Trans MountainX3, ENGP 4. Trans MountainX2, Trans MountainX3 (no new pipelines from PADD 2 to PADD3) 5. Trans MountainX2, Trans MountainX3, (plus US expansion from PADD2 to PADD3) 6. Trans MountainX2, Trans MountainX3, ENGP 7. No new pipelines.
6 The principal findings from the study are: • All scenarios including no new pipelines and lower US demand result in the same quantity of production in the WCSB to 2020 • The only scenarios that result in a decline in WCSB production after 2020 are the no new pipelines (scenario 7) and construction of TMX2 and TMX3 with no new pipelines between PADD2 and PADD3 (scenario 4) to increase access to the Gulf Coast. Lower US demand has no impact on Canadian production.
The findings are driven by two factors. First there is sufficient demand in the US market to absorb the forecasted increase in WCSB production. Second, existing pipeline capacity is sufficient to meet Western Canadian oil export demand to 2020 and only 185,000 bpd of additional capacity is required to meet Canadian crude export demand by 2025. If Keystone XL is built there will be significant excess pipeline capacity to 2025 even if no other WCSB projects are built (Table 4). The findings show that not building the ENGP has no impact on WCSB oil production and that the ENGP would result in surplus capacity.
Table 4: Ensys Analysis of WCSB Pipeline Supply and Demand Balance (thousands of bpd)
2011 2015 2020 2025 Current WCSB Capacity 3,881 3,881 3,881 3,881 WCSB Crude Supply 2,293 2,813 3,349 4,006 Surplus/Deficit Capacity +1,588 +1068 +532 -185 Keystone XL Capacity 700 700 700 Surplus/Deficit Capacity +1,588 +1,768 +1,232 +515 Source: Ensys (2010) p. 30
Ensys updated their study in 2011 (Ensys 2011) to include the following developments that had occurred subsequent to their 2010 study, particularly the release of the 2011 CAPP forecasts and emergence of new transportation options for shipping WCSB oil to markets. The new CAPP forecasts in 2011 forecast higher oil supply for the WCSB. Based on the higher supply forecasts, Ensys concludes that additional pipeline export capacity of between 200,000 and 400,000 bpd will be required by 2020 and 900,000 bpd of additional pipeline capacity is required by 2025. Ensys identifies partial pipeline expansion option scenarios to include expansion of the Enbridge Clipper Line by 350,000 bpd and expansion of the Kinder Morgan TMX system. Ensys considers these likely scenarios because the regulatory approvals, economics, and logistics of expanding these existing lines make them more attractive than greenfield pipeline options. Ensys also identifies new options in rail and barge, which it concludes are increasingly competitive with pipelines. The conclusion of the updated report is that no new pipeline capacity other than expanded capacity on Enbridge’s Clipper Line and Kinder Morgan’s TMX line is required to meet WCSB export requirements to 2025. If Keystone XL is built, there would again be excess capacity to 2030, without the ENGP. 2.2. Market Assessment Our assessment of pipeline supply and demand forecasts for the WCSB and the Ensys assessment show that there is sufficient capacity to meet transportation requirements
7 beyond 2020 with an expansion of the Enbridge Clipper and construction of Keystone XL. Another question is whether there is sufficient demand in the US market to absorb the oil shipped on these US bound pipelines.
Evidence of the ability of the US market to absorb increased WCSB exports is provided by the investments by TransCanada and Enbridge to increase pipeline capacity to the US and the commitment of producers to ship on both the existing pipelines and the proposed Keystone XL, all of which have been assessed and approved by the NEB as needed and justified projects. These market assessments by Canadian producers/transporters are based on the fact that the US is the largest consumer of oil and recent forecasts by the US market forecast an annual growth rate in oil consumption of 0.4% per year from 2008 to 2035 (US EIA 2011a). US imports of crude oil are forecast to decline slightly from 9.01 million bpd of crude oil in 2009 to 8.28 million bpd in 2025 (reference case). However, US import demand is and will remain well in excess of Canadian crude oil exports. Further, Mexican production is forecast to decline by 2.4% per year to 2035, with much of the decline occurring from 3.0 million bpd in 2009 to 1.8 million bpd in 2020 (US EIA 2011a). According to CAPP market analysis, the decline in Mexican production and decline in imports from countries in the Organization of the Petroleum Exporting Countries creates an opportunity for Canada to increase its exports into the US market, particularly the Gulf Region. As CAPP notes in its 2011 oil market assessment (CAPP 2011 p. 11):
Although overall US crude oil demand is not expected to increase significantly, western Canadian crude oil should supply a growing share of this market if the necessary pipeline infrastructure is put in place to enable greater access to major US markets. Declines in imports from other major suppliers to the US is expected in the near term due to a combination of falling production, increased domestic consumption, or a focus on expansion into new export markets such as Asia.
The Ensys report for the US Department of Energy (2010) reviewed in the previous section also documents the ability of the US market to absorb increased Canadian oil production. The report observes that “All pipeline scenario results indicate a clear potential for a sustained increase in US imports of Canadian crudes” (Ensys 2010, p.90). The Ensys report includes the US Energy Information Administration reference case and a low growth forecast for oil consumption. The analysis shows that under the pipeline scenarios involving no expansion to the British Columbia (BC) west coast, the US market has the capacity to absorb the entire increase in Canadian exports during the forecast period to 2030 even under the lower US demand scenario.
The Muse Stancil study on behalf of Enbridge provides additional market assessments for WCSB exports (Enbridge 2010a Vol. 2, App. A). To assess the benefits of the ENGP, Muse Stancil runs two scenarios: one with ENGP and one without. In the ENGP scenario, WCSB exports are shipped to the Asian and US market. In the no ENGP scenario, WCSB exports are shipped to the US market only. The results of the no ENGP option indicate that the US market is capable of absorbing the WCSB exports and
8 production in the WCSB is unaffected by the decision to build or not build the ENGP. Muse Stancil therefore concludes that there will be sufficient pipeline capacity to transport WCSB exports in the US with just the additions of the Keystone (including Keystone XL) and Enbridge Clipper expansions and therefore demonstrates that the ENGP is not needed to meet forecast WCSB export demand during the forecast period to 2025. We acknowledge that the Muse Stancil study concludes that there is a benefit of building the ENGP because the netbacks are forecast to be higher in the Asian market compared to the US market. This Asian premium is discussed in more detail in the section on project benefits.
Another issue is the risk of relying exclusively on the US market. The delay of US approval of the Keystone XL, potential regulatory restrictions on imports of oil sands oil, and bottlenecks on the US distribution to the Gulf Coast market that are depressing WCSB oil export prices are challenges affecting the export of WCSB oil to the US market. The outcome of these potential restrictions is unknown. However recent developments including announcements by Enbridge to increase pipeline capacity to the Gulf and TransCanada to modify its Keystone proposal to make it more acceptable to the US suggest that these challenges may be in the process of being resolved (Vanderklippe and McCarthy 2011). Any decision on the ENGP needs to await the outcome of these recent developments to assess the need for new pipeline capacity. 2.3. Qualifications and Risks to Need Assessment The pipeline supply and demand analyses indicate that there will be sufficient pipeline capacity to accommodate WCSB forecast oil transportation needs until after 2020. This analysis, however, is based on pipeline capacity and oil export and demand forecasts that may or may not be accurate. We acknowledge that different supply and demand assumptions will result in different estimates of capacity requirements. We note, however, that both the Muse Stancil study in the Enbridge application and the independent Ensys analysis (2010, 2011) are consistent with our supply/demand conclusions that there is sufficient existing and planned pipeline capacity to meet demand without building the ENGP. Nonetheless, given the uncertainties, it is important to assess risks to the forecasts and the implications of these risks for pipeline capacity requirements.
The pipeline capacity forecasts in Table 3 assume two expansions: expanding Enbridge Clipper to its potential capacity of 800,000 bpd and constructing the new 700,000 bpd Keystone XL pipeline. Risks and costs involved in expanding existing pipelines are relatively low and Enbridge Clipper expansions are highly likely to proceed if additional capacity is required. Risks in constructing new greenfield projects like the Keystone XL are higher than expansions, as indicated by the deferral of a decision to approve the Keystone XL pipeline. However, the advanced state of the Keystone project, rerouting decisions to resolve environmental issues and US import requirements increase the likelihood that Keystone XL will ultimately be approved. Recent announcements by Enbridge regarding the Seaway crude pipeline and TransCanada to commence construction of the southern portion of Keystone XL from Cushing to the Gulf (McCarthy and Vanderklippe 2011), as well as back-up barge and railway options (Ensys 2011)
9 make it likely that capacity will be expanded from Cushing (PADD 2) to the Gulf (PADD 3) to resolve current bottlenecks. Therefore there is a high probability that the pipeline capacity additions forecast in Table 3 will transpire. Further, there are additional pipeline projects and other transportation options such as rail and barge that are potentially viable options if Keystone XL is not built (Ensys 2011). For example, several pipeline projects are excluded from our capacity forecasts including: expanding Keystone XL beyond 700,000 bpd to 830,000, expanding KM TMX 2 and KM TMX3 (up to 400,000 bpd), and rail and barge options (Ensys 2011 p. 19). These options reduce the risk that oil transportation capacity will be deficient. Therefore we view the pipeline capacity forecasts assumptions as being conservative because they exclude some 530,000 bpd of additional pipeline capacity and any rail and barge capacity.
What are the risks to the oil export volume forecast? There are three components to the oil export volume forecast: WCSB production, intra-WCSB processing, and Bakken oil shipments on the Canadian pipeline systems. As CAPP (2011) points out, the risks to the production forecast for 2015 are minimal because the forecast is based on existing capacity and new capacity under construction. Due to the lag times in developing new capacity, it is unlikely that production will be higher than the forecast for 2015, although it may be lower than the forecast if construction is delayed or existing production is constrained. The forecasts for 2020 and 2025 are less certain. Although higher production is possible, the likelihood based on past forecasts is that production is more likely to be lower. The past CAPP forecasts have shown a consistent upward bias. Further, the 2011 forecast is at the high end of the range of recent CAPP forecasts, significantly above the previous 2010 and 2009 forecasts. Given past experience, there is a higher probability that actual production could be well below forecast production. Multiyear delays and cost escalations in existing projects such as the Kearl mine1 and the recent cancellation of the previously announced 200,000 bpd Syncrude expansion, which was supposed to be built by 2020, illustrate the downside risks in oil sands forecasts (Healing 2011). A related uncertainty in forecasting oil supply is forecasting the product type. Increasing the proportion of oil that is upgraded will reduce the volume that needs to be shipped by reducing the diluent content.
The risk assessment suggests that it is unlikely that the demand/supply balance will change during the forecast period by sufficient margin to require ENGP. Based on past forecast bias and the availability of other feasible oil transportation projects, it is more likely that surplus capacity and the opportunity costs of maintaining surplus capacity will be higher than forecast. However, it is possible that if Keystone XL is not built and/or pipeline demand is higher than forecast, additional capacity may be required before 2020. Given these risks, what is a rational pipeline strategy? There are two options:
1 The 345 kbpd Kearl mine was originally scheduled to be in production by 2010 (phase 1) and 2012 (phase2) at a cost of $5-8 billion (Imperial, 2005). The project is now forecast to cost $20 billion and phase 1 (145 kbpd) is forecast to commence production in 2012 and the expansion phase (110 kbpd) in 2015, followed by a debottlenecking phase designed to allow for production of 345 kbpd. No date is provided for achieving full production (Imperial 2011).
10 • Option one is to approve the ENGP as proposed by Enbridge in case it is needed • Option two is to defer approval of the ENGP and only consider the application if and when there is a much higher likelihood of sufficient demand to justify its construction.
Pursuing option one - approving the ENGP as planned – entails a potentially significant cost. If the ENGP is built and the capacity is surplus to demand, the maintenance of this surplus capacity will impose unavoidable incremental costs to the entire WCSB transportation system equivalent to the opportunity cost of unused capital.
Enbridge states in its submission that it would not build the project unless there was sufficient demand reflected in contractual commitments to justify construction (Enbridge 2010a Vol. 2, p. 1-6). The implication of Enbridge’s commitment is that approval would not necessarily result in surplus capacity because the decision to build would be deferred until the capacity is required. However, approving the project and allowing Enbridge the discretion when to commence construction still carries a significant risk of surplus capacity being created for several reasons. First, Enbridge does not indicate the type, quantity, and certainty of the contractual commitments it requires to make a decision to commence construction. Decisions can be made to commence pipeline projects on a range of contractual commitments from common carrier arrangements to long-term contracts. Therefore, until the structure of the demand is confirmed by legally binding irrevocable contracts, it is not possible to assess how firm the demand for ENGP is and what the risks of unused capacity are. Secondly, if ENGP is built and Enbridge is correct in its forecast of the preference of producers to ship into the Asian market, producers who may be using other existing pipelines into the US would redirect shipments to the ENGP, resulting in surplus capacity on these other pipelines. Therefore, even if Enbridge had sufficient binding contractual commitments before constructing the project, the building of ENGP would result in creation of surplus pipeline capacity elsewhere in the pipeline system. Third, pipeline companies are regulated utilities provided with a regulated return to cover costs and capital. Therefore, depending on the regulator’s decision, it is possible for pipeline companies to earn a market return on surplus capacity and shift the cost of the extra capacity onto producers in the form of higher tolls. This is why the National Energy Board Act requires pipelines to demonstrate clearly the need for the pipeline as a condition of approval as opposed to approving pipelines for which need is not documented.
Pursing option two - deferring a decision on the ENGP - is a lower risk and less costly option. If the forecasts change - Keystone is not approved or production is higher than forecast - there is sufficient time to make required additions to capacity to avoid transportation constraints. The Keystone decision should be known by 2013 and the 2020 forecast will be relatively firm by 2015 when investment decisions on new production will have been made. Even in the unlikely case that there are short-term transportation constraints, the costs of shutting in production need to be compared to
11 the costs irreversible opportunity cost of unused surplus pipeline capacity in a rational risk assessment.
Therefore the rational strategy is to defer approval of the ENGP and only consider the application if and when there is sufficient demand. Further, if and when there is need for new capacity, the ENGP application needs to be assessed relative to the many other transportation options to ensure the most cost-effective outcome. In this way, the irreversible costs imposed by surplus capacity can be avoided and the most cost- effective transportation options for WCSB can be provided. 2.4. Conclusion on Need for Enbridge Northern Gateway Project The Enbridge submission justifies the need for the ENGP based on forecast increased oil production in Western Canada without examining the overall balance of pipeline supply and demand. Therefore Enbridge does not provide sufficient documentation to justify the need for the ENGP. The assessment in this report as well as the independent assessment prepared by Ensys for the US Department of Energy both come to the same conclusion: there is currently excess pipeline capacity that will likely persist beyond 2020 if Enbridge Clipper expands to its planned capacity and the Keystone XL is completed. Further, Enbridge’s commitment that it will not build the pipeline until there is sufficient demand as demonstrated by contractual commitments will not prevent the creation of excess pipeline capacity. We again acknowledge that supply and demand forecasts for pipeline capacity involve uncertainty and that different assumptions will produce different supply/demand assessments. We urge the NEB to do additional analysis of the supply/demand of the WCSB oil pipeline system to identify the need for and the combination of the most cost-effective transportation options for shipping WCSB oil before making any decision on the ENGP.
3. Economic Impacts and Public Interest Part of Enbridge’s public interest justification for the ENGP is that the project will generate positive economic impacts. In its submission, Enbridge includes a study by its consultants - Wright Mansell - to estimate economic benefits (Enbridge 2010a Vol. 2, App. B). Enbridge summarizes the economic impacts over a 30-year operating period as follows (Enbridge 2010a Vol. 2, p. 1-14): • 558,000 person years of employment • $270 billion of economic activity measured by Canadian gross domestic product • $81 billion in government revenue • $28 billion in net incremental oil industry revenue • $48 billion in additional labour income
Based on this impact assessment, Enbridge concludes in its submission that “from an economic perspective, the project is clearly in the Canadian interest (Enbridge 2010a Vol. 2, p. 1-14).
12 The estimation of economic impacts is a normal component of project planning that helps stakeholders and governments identify and prepare plans to manage project development. The estimation of the timing and size of large construction workforces, for example, allows for the planning of services to minimize disruptive impacts. The estimation of the quantity and location of permanent employment allows communities to plan for potential expansion. Often Impact Benefit Agreements are prepared based on the economic impact assessment to allow local stakeholders to participate in project development opportunities. However, there are several issues and deficiencies with the way the Enbridge submission presents and interprets the economic impact findings. 3.1. Confusing Terminology One issue in reviewing economic impact estimates is clear understanding of the terminology. A common source of confusion is the definition of employment and person years. The Enbridge study references the creation of 558,000 person years of employment and 62,700 person years of construction employment in the overview provided in Volume 1 and the economic review provided in Volume 2. In Volume 6, however, Enbridge states that the ENGP will create only 104 direct permanent operating jobs (Enbridge 2010a Vol. 6, p. 4-24). The direct permanent employment is not provided in either the project overview (Volume 1) or in the public benefits discussion in Volume 2. The failure to provide direct employment data in the public interest section of the submission can lead to a significant misinterpretation of the number of jobs that the ENGP will create and to its potential contribution to the public interest.
An obvious question is what is the relationship between the 104 direct permanent operating jobs provided in Volume 6 and the 558,000 person years of employment cited in the public interest section in Volume 2? How do 104 direct operating jobs turn into 558,000 person years of employment and which number provides a more accurate estimate of the number of jobs generated by ENGP?
The first step in the escalation from 104 direct jobs to 558,000 person years is the inclusion of the “multiplier effects” of direct operating jobs. Direct employment creation generates additional indirect employment by the purchase of goods and services by the project and induced employment by the purchase of goods and services by those employed by the project. If calculated accurately, indirect and induced multiplier effects provide a valid estimate of total employment. Enbridge uses projected purchase data for the ENGP and the Canadian input output model to estimate indirect and induced employment and concludes that the ENGP will generate a total of 1,146 jobs in Canada, comprised of 104 direct jobs, 370 indirect jobs based on direct input purchases, 251 indirect jobs and 421 induced jobs. We have not attempted to evaluate the validity of these estimates but the concepts and methodology underlying these calculations appear sound. The only questionable component of this part of Enbridge’s analysis is the inclusion of two separate categories of indirect impacts: one based on direct purchases and one based on the indirect purchases in the input output model. Depending on how this is done in the analysis, it may double count some
13 indirect employment effects and lead to an overestimation. We cannot assess whether there is double counting or not based on the information provided.
The next step in the employment escalation is to estimate the employment impacts of the oil price premium. According to the Wright Mansell study, the oil price premium will increase the cash flow to producers, which will in turn be reinvested back into the energy sector and will generate 16,556 annual person years of employment. As noted later in this report, the assumption that there will be a permanent price premium to the year 2046 is highly uncertain. Nonetheless, Enbridge assumes the existence of this premium in its benefit and employment estimates. Enbridge then assumes that the premium will generate incremental employment by increasing the cash flow of producers, which will in turn stimulate incremental investment in the energy sector.
The assumption that increased cash flow necessarily results in higher investment ignores the fact that investment decision are based on the supply side availability of investment opportunities that meet investors’ hurdle rates of return. Increased cash flow from existing operations does not necessarily result in an increase in new investment opportunities. If there are attractive investment opportunities that exceed internal cash flow of Canadian operations, external cash either from other non- Canadian operations within the firm or external to the firm will flow into the sector to exploit the opportunities. Therefore, the inclusion of employment benefits generated by increased cash flows from an uncertain forecast price premium is a methodologically unsound step in the analysis2.
The next step in escalating the number is to change the definition of person year from an annual average person year to a total person year for the entire project period by multiplying the annual average by the number of years the project is operating. Assuming the project operates for 30 years, one permanent job is reported as 30 person years of employment even though it is one job. By changing the definition, Enbridge increases employment estimates by a multiple of 30 to generate the 558,000 person years of employment. Although this may be technically correct to report total person years over the entire life of the project, the way in which the information is presented and the failure to include direct annual average employment in the public interest section of the submission and in the overview of the project in Volume 1 can easily lead to an exaggeration of the economic impacts. For example, the Enbridge submission forecasts that ENGP will create 260,810 person years of employment in Alberta (Enbridge 2010a Vol. 2, App. A p. 32), which is equivalent to about 12% of the entire Alberta workforce in 2011.
The Enbridge submission contributes to this misunderstanding by comparing the total person years over the entire life of the project to annual employment indicators in an attempt to show the relative contribution of the project. For example, the Wright
2 It is possible that increased prices will result in more investment by making previously uneconomic reserves economic. This is not however the basis for the Enbridge analysis. The estimate of impacts of higher prices on production would require additional analysis of the response of supply to price changes.
14 Mansell report states that the project will result in “An increase of 558 thousand person years of employment (equivalent to about 3.3 per cent of total Canadian employment in 2009) or an annual average increase of over 16,000 person years of employment (equal to approximately 5 per cent of the average annual increase in Canadian employment over the pre-recession years of 2005 to 2008)” (Enbridge 2010a Vol. 2, App. B p. 8). In this statement 558,000 total person years over a 30-34 year period are compared to one year of employment and the 16,000 person year number is defined as an average annual increase in employment even though this is not an annual increase but is the average annual employment over the period to 2046. These comparisons therefore contribute to the misunderstanding of the economic impacts.
In sum, the economic impact assessment presentation of 558,000 person years of employment can lead to a misinterpretation of economic impacts. In viewing employment impacts it is more appropriate to focus on the 1,146 average annual employment than 558,000 person years because the 1,146 jobs estimate represents the average number of people that will be permanently employed over the life of the project. Indeed, the Enbridge website uses only the person years of construction employment and the permanent annual average operating employment of 1,150 (rounded up from 1,146) in its description of employment benefits and makes no reference to the 558,000 person year estimate that is included in the Enbridge application (Enbridge 2011a). 3.2. Gross Impacts versus Incremental Impacts The Enbridge economic impact analysis correctly refers to its economic impacts estimates as total (or gross) impacts, not net impacts. However, in evaluating project impacts it is important to estimate net economic impacts because it is the net impacts that measure the incremental contribution of the project to the economy. Unfortunately, the Enbridge submission estimates only the gross impacts and makes no attempt to estimate or even clearly distinguish between net and gross economic impacts for the project other than in its discussion of the incremental price benefits of shipping to the Asian market. The failure to clearly distinguish between gross and incremental benefits can lead to a misinterpretation that the ENGP will result in the Canadian economy expanding by $270 billion (2009 CAD), creating 1,146 jobs and generating $81 billion (2009 CAD) more in government revenue than would occur without the project.
The assumption that gross impacts are equal to net impacts assumes that all the labour and capital employed in the ENGP would otherwise be unemployed until 2046. While there may be uncertainty in predicting exactly how the labour and capital would be allocated in the absence of the ENGP, the assumption that all labour and capital would be otherwise unemployed to 2046 is not a realistic assumption.
The standard starting principle in project evaluation is that there is an opportunity cost of labour and capital defined as what the labour and capital would earn in their alternative use (see for example Pearce et al. 2006; Shaffer 2010; Ward 2006). In a well functioning economy, labour and investment capital will be close to fully
15 employed over the long term. Under this assumption, the labour and capital that would have been employed by the ENGP would be employed elsewhere in the economy if ENGP did not occur and the net economic impacts of the ENGP would be zero. Hence, resources are simply reallocated between sectors and regions. We do note however that although there may be no net increase in economic activity, the geographic location of economic activity may be different with and without the ENGP. Therefore, there may be a net increase in local employment, even if there is no net increase in national employment.
Adjustments are made to the full employment assumption in project evaluation if the economy is not performing to capacity and there are unemployed resources. Under these conditions a project may generate some incremental employment. The question then is how likely is it that the resources employed by the ENGP would be otherwise unemployed. Currently there are alternative oil transportation projects available to replace the ENGP if it is not built. Consequently, it is reasonable to assume that another pipeline or other transportation projects will be built to ship WCSB oil as required. Therefore resources that would have been employed by the ENGP will likely be employed on these other projects. Further, even if an alternative project is not built or the alternative project employs fewer resources, the BC government forecasts an overall shortage of labour in the Northeast and North Coast/Nechako regions of BC over the next decade due to the large number of other projects planned for this region (BC 2009) and the NEB also forecasts (NEB 2011) potential labour shortages in the oil and gas sector. The NEB states:
According to the Petroleum Human Resources Council of Canada (PHRCC), the oil and gas industry faces a major challenge in the coming years. There is evidence that a shortage of skilled workers is developing as the workforce ages and overall demand for labour increases. Many of the oil and gas industry’s most experienced and skilled workers will be retiring in the next decade. At the same time, the Canadian labour force is shrinking. Under a scenario of high oil and gas prices, the PHRCC is predicting a requirement of 130,000 new hires by 2020. This challenge is being addressed through a number of government and industry initiatives, but a potential labour shortage may increase construction costs and (affect) the pace of oil development (NEB 2011 p.25)
Therefore it is unlikely that the ENGP will generate much if any incremental employment given the alternatives to the project and tight labour markets in the oil and gas sector. Further, even if the ENGP did generate incremental employment because some of the resources used would otherwise be unemployed, the incremental employment would be only a small fraction of the gross economic impacts. Therefore it is inaccurate to cite gross economic impacts as the incremental economic impacts of the project.
The same logic applies to fiscal benefits to government. If capital and labour employed by the ENGP would otherwise be employed in alternative projects in Canada, these alternative projects would generate tax revenue to government. Therefore the gross
16 revenue estimates presented in the Enbridge submission do not measure the incremental or net government revenue gains. The net gains will be close to zero if all the labour and capital is otherwise employed. If some of the labour or capital is otherwise unemployed, the incremental government revenue from ENGP is the taxes that would have been paid by the otherwise unemployed resources. Also if the ENGP does increase oil prices higher than they would otherwise be, there may be incremental government revenue based on these higher prices. However, even in these circumstances of unemployed resources, the net revenue to government would be only a fraction of the gross revenue estimated by Enbridge. 3.3. Economic Impacts and Economic Benefits The economic benefits analysis in the Enbridge regulatory submission is actually an economic impact assessment: not a benefit assessment. The submission incorrectly assumes that economic impacts are benefits that measure the contribution of the ENGP to the public interest. While the creation of jobs and stimulation of economic activity is certainly a desirable public policy goal, economic impacts of projects are not considered an economic benefit in project evaluation unless they are incremental. As discussed above, the ENGP is unlikely to generate incremental impacts. Further, even if the ENGP generated incremental economic impacts, the incremental jobs and economic activity has to be assessed relative to the value of the product or services produced. If Enbridge was correct in it is assumption that creation of employment and economic activity is an appropriate measure of the benefits of the ENGP, these so called benefits of the ENGP could be increased significantly by, for example, using a longer pipeline route or simply employing more workers and less mechanized equipment to build the pipeline. Obviously, increasing economic impacts in these ways would not enhance the public interest. The key to measuring public interest therefore is the value of what the labour and resources produce, not the employment of labour and resources. As Shaffer states in his recent text on project evaluation (Shaffer 2010 p. 9):
Proponents of large projects commonly cite the number of jobs and income generated in construction and operation as major benefits of their project. However, for there to be an economic benefit, the persons hired would have to earn more than they would otherwise or to realize some other advantage…In benefit-cost analysis the benefit is not the jobs themselves, but rather the incremental income or value that the new jobs offer relative to what the persons hired would otherwise earn or do. The creation of jobs that simply attract people from comparable employment in other projects or industries offers no net benefit. 3.4. Exclusion of Costs The NEB public interest criterion clearly states that determination of whether a project is in the public interest is based on “the overall public good a project may create and its potential negative aspects…” (NEB 2010, p. 1). Enbridge’s submission on the public interest contained in Volume 2 includes only gross economic impacts of the ENGP without discussion of any potential environmental and social costs and opportunity costs of labour and capital. An assessment of the contribution of the ENGP
17 to the public interest requires an assessment and inclusion of all relevant costs to determine if there is a net benefit. Enbridge’s exclusion of costs in its assessment of whether the ENGP is in the public interest is therefore a significant omission that results in the consideration of only one side of the public interest, contrary to the requirements of the NEB review process. 3.5. Asian Premium and WCSB Netbacks One of the alleged benefits of the ENGP specified in the Enbridge submission is that shipping to Asia will result in higher netbacks to all WCSB producers. The Muse Stancil study contracted by Enbridge identifies two factors increasing the netback (Enbridge 2010a Vol. 2, App. A). The first factor is that oil prices are forecast to be higher in Asia than the US. Muse Stancil forecasts an Asian price premium of $3.63 in 2025 for heavy oil and $2.79 for light oil (Enbridge 2010a Vol. 2, App. A p. 45). The price premium in the Asian market results in higher netbacks for the oil shipped to Asia. The second factor is that reducing the quantity of oil shipped to the US results in a northward shift of the pricing point from the Gulf. It is assumed that the more northerly prices will be higher because of the extra transportation charges for foreign non-Canadian oil delivered to the Gulf to be shipped northward into the US. Consequently, all Canadian oil delivered to the more northerly points will realize higher netbacks. The study then deducts the cost of higher oil to Canadian refiners from the benefit calculation. The study estimates net benefits to be $1.47 billion (2009 CAD) in 2016 rising to $3.34 billion (2009 CAD) in 2025. The net present value (NPV) of the price benefit is estimated at $21 billion to 2025 based on a 5% discount rate (Enbridge 2010a Vol. 2, App. A p. 37). The major proportion of the price benefit is from higher prices to the US.
The estimated pricing benefits of shipping to Asia through the ENGP are highly uncertain. Forecasting oil prices is extremely challenging. The NEB price forecasts (NEB 2011 Table A1.1) for Cushing for West Texas Intermediate (WTI) in 2020 range from $72 (2010 USD per barrel) to $142 (2010 USD per barrel). The US EIA (2011b p.168) weighted average price forecasts for imported crude for 2025 range from $56 to $232 for imported crude (US nominal per barrel). Given the enormous uncertainty over average future oil prices, there is even greater uncertainty forecasting price differentials between geographic locations. Another complication is that the much of the product that will be shipped from Canada is diluted bitumen. As the Alberta Royal Review Panel observed, the price of bitumen is difficult to assess because there are few buyers and sellers and prices historically have fluctuated by wide margins around the price of WTI (ARRP 2007). Further, no evidence is provided by Enbridge supporting the forecast of a permanent Asian premium in oil prices. The only data that are provided compares historical premiums from 2000 to 2009 and this data show significant variation in the estimated premium (Figure 1). In two of the ten years, the prices are actually higher in the US Gulf and the premium overall varies from a low of - $1.08 to a high of $3.88 for Arab heavy, with an average premium of $1.60 for heavy and an average of $1.25 for light (Enbridge 2010a Vol. 2, App. A p. 45). There is no discernable trend line. Therefore the logic of forecasting a permanent premium averaging $3.42 (for heavy oil) and $2.63 for light over the forecast period from 2016- 2025 is not supported by the evidence presented. In fact, market forces should reduce
18 if not eliminate the premium as world producers redirect oil to the higher price markets, until netbacks are equalized. There can be short-term premiums caused by transportation or supply constraints, but a permanent premium is unlikely unless it is cost based. In the case of WCSB exports, there does not appear to be a cost advantage to Canadian producers shipping to Asia versus the US Gulf. Ensys (2011 p. 68) estimates that the costs of pipeline and tanker to China are the same as pipeline to the US Gulf ($7 per barrel).
Figure 1: Historical and Forecast Asia Premium Provided by Muse Stancil in Enbridge (2010a)
Source: Enbridge 2010a Vol. 2 p. App. A p. 45
The forecast that a shift to the Asian market of some 500,000 bpd of Canadian oil will result in a rise in prices for all Canadian oil is also highly dubious. The diversion of a small quantity of Canadian oil from the US should not impact the prices or destinations of the remaining Canadian oil. If netbacks are higher in some locations, the remaining oil should have already been shipped to the location with the higher netback prices. Also the assumption that the prices for Canadian oil will be higher the further inland from the Gulf due the higher transport charges from the Gulf is also highly uncertain. Currently, prices at Cushing have been much lower than prices at the Gulf and the planned expansion of pipeline capacity to ship Canadian oil to the Gulf will result in an increase in prices for Canadian oil, not a reduction (McCarthy and Vanderklippe 2011). Therefore the current actual geographical price differentials contradict the Muse Stancil model results. Further, even if there is a higher price based on the higher transportation cost of shipping oil from the Gulf to interior US locations, this does not mean that Canadian suppliers will receive the higher price for interior deliveries. The buyers of oil can buy from either Canadian suppliers or non-Canadian suppliers. The buyers are aware that the option for Canadian suppliers is to ship the oil further at a higher transport cost or sell it to them. Consequently the buyers will try to bid the
19 price down for the Canadian oil and reap as much of the transportation cost advantages enjoyed by Canadian suppliers as they can, given that Canadian suppliers’ only other option is to incur the higher cost and ship further. In other words, the distribution of any geographical price premiums will be determined by complex bargaining between buyers and sellers with no assurance that Canadian suppliers will end up realizing the full transportation cost advantage and higher netbacks. The outcome of the bargaining is uncertain. Therefore, although price differentials are possible, it would be imprudent to include a permanent price premium in the analysis of benefits for all Canadian oil production due to the ENGP. The key to increasing WCSB prices in the US market is increasing access to the Gulf by eliminating bottlenecks at Cushing.
Finally, even if there is a price premium, the full premium is not a benefit to Canada unless it accrues to Canadians (Canada TBCS 2007 p. 12). Based on the Enbridge analysis estimates, approximately 65% of the estimated incremental revenue accrues to producers and 35% to governments (Enbridge 2010a Vol. 2, App. 2 p. 41). The proportion accruing to Canadian governments is a Canadian benefit. However, the proportion of the incremental producer returns accruing to non-Canadian shareholders is not a Canadian benefit and would have to be deducted. We have not attempted to estimate the distribution of producer returns between Canadian and non- Canadian owners of oil assets, but the proportion of returns accruing to non-Canadians would be significantly less than the full amount given the high degree of foreign ownership in the oil and gas sector3.
4. Benefit Cost Assessment of Enbridge Northern Gateway Project The method used by Enbridge to assess whether the ENGP is in the public interest is deficient and incomplete. The assessment uses gross economic impacts as the primary measure of the contribution of the project to the public interest instead of net impacts and the method incorrectly assumes that economic impacts are a measure of benefits without taking into account the value of the product or services produced. The Enbridge analysis also excludes costs in its estimate of benefits to the public interest.
A more comprehensive and widely accepted method for evaluating whether projects are in the public interest is benefit-cost analysis (BCA). The objective of BCA is to identify all the positive and negative impacts of a project and to aggregate these impacts to determine whether a project creates a net gain or loss in society’s overall well-being. BCA is based on a well-developed theoretical foundation, its methodology and application is outlined in numerous publications and it is required in project approvals in many jurisdictions (Boardman et al. 2006; Canada TBCS 2007; Pearse et al. 2006; Shaffer 2010; Zerbe and Bellas 2006). Consequently, we will apply a BCA framework to the ENGP to assess whether the project is in the public interest.
3 Statistics Canada estimates foreign ownership in the oil and gas sector based on operating profits at 41% in 2009 (Statistics Canada 2011).
20 The basic steps in BCA are: (1) specify project options and scenarios, (2) determine standing, (3) catalogue all types of potential impacts of the project as benefits or costs, (4) predict impacts quantitatively over life of project, (5) monetize any non-monetary impacts being tracked, (6) discount benefits and costs, (7) compute net benefits, (8) perform sensitivity analyses, and (9) make a recommendation (Boardman et al. 2006).
For the ENGP BCA, we assume all Canadians have standing and therefore evaluate the ENGP from the perspective of Canada. The impacts of the project have been identified in the Enbridge submission. The principal benefits of the project are transporting WCSB oil to market and the principal costs are the capital and operating costs of transporting the oil plus external environmental costs such as greenhouse (GHG) emissions, alteration of landscapes and ecological systems, potential damages from oil spills, and other social and environmental costs.
We begin the BCA by identifying the costs and benefits of transporting oil to the WCSB oil and gas sector, including producers, workers, and transporters. The costs are the capital costs and operating costs of transporting the oil as specified by Enbridge in its submission: $5.54 billion (2009 CAD) in capital costs and $192 million (2009 CAD) per year in operating costs. The proposed decision timetable for the NEB is now late 2013, so the timing of construction and operation is as specified in the Enbridge submission but deferred one year to reflect the delayed decision date - construction now starts in 2014 and is completed by 2018. For the preliminary BCA we have not included any environmental costs.
The benefits are the transportation of oil to market. We assume that the value of the benefits is equal to the willingness of producers to pay in the form of toll charges and other charges for the product that needs to be shipped. Toll charges paid are the revenue requirements to cover the operating and capital costs of the ENGP. For the evaluation we assume that there is a benefit for only the oil that is shipped. Unused pipeline capacity therefore does not generate a benefit because it is not needed. We also run a scenario with 95% capacity utilization on the assumption that producers may be willing to pay for some surplus capacity.
The estimate of oil that needs to be shipped is based on the supply and demand analysis summarized in Table 3. It is assumed in all scenarios that Enbridge Clipper is expanded to full capacity of 800,000 bpd. We also assume that Keystone XL is built in all scenarios, with the exception of one. Given the uncertainty surrounding the Keystone XL pipeline, we conduct a sensitivity analysis on the scenario that Keystone XL is not built and thus 700,000 bpd are not added to the pipeline system exiting the WCSB. We do not include any other new projects other than the Clipper expansion, Keystone XL, and the ENGP in the analysis. The benefits generated by ENGP commence when the ENGP capacity is required. ENGP may be used before the date that its capacity is required if shippers switch from existing pipelines to ENGP. In this case the unused capacity shows up elsewhere in the transportation system, but it still does not generate a benefit until the capacity is required to ship oil. Given uncertainty over demand for pipeline capacity, we conduct a sensitivity analysis on oil export volumes of +/-10%. We also include an Asian oil price premium in a
21 sensitivity analysis even though we consider the assumption of a permanent Asian oil price premium in an investment decision as imprudent. We assume an Asian premium is generated until 2025 for light and heavy based on the average premium experienced from 2000 to 2009 and use the same ratio of light to heavy oil shipped on the ENGP as provided in the Enbridge submission (Enbridge 2010a Vol. 2 App. A p. 45-46). We assume the Asian premium is realized starting in 2018 as oil is redirected from other pipelines to be shipped on ENGP.
Although we consider it unlikely that workers employed on the ENGP would otherwise be unemployed, we do include an employment benefit scenario in which it is assumed that some proportion of the workers engaged in construction may be otherwise unemployed. There are different approaches that can be used to define the employment benefits. We use a relatively simple approach to show the general order of magnitude of the benefits under an assumption of unemployed resources. We define the proportion of workers who may be otherwise unemployed by the difference in the unemployment rate during strong economic periods compared to weaker economic periods based on a review of unemployment rates in the BC construction industry from 2000 to 2010. During the strong periods from 2005 to 2008, unemployment averaged 4.4% and during the weaker periods from 2000-2002 and 2009 to 2010, unemployment averaged 10.1% (BC Stats 2011). Based on this difference we assume that full employment for the industry at 4.4% and therefore during a period of high unemployment (10.1%) we assume that 6.7% of the construction work force would otherwise be unemployed. We estimate the employment benefit of ENGP by assuming a zero opportunity cost for construction workers directly employed on the project who would otherwise be unemployed. This overestimates the employment benefit because the opportunity cost of unemployed labour would be greater than zero. Nonetheless, it shows the general order of magnitude of employment benefit impacts on the overall net benefits of the project if the project is built during a period of high unemployment.
In the case of regulated pipelines, tolls paid by those shipping product are set to cover all costs of transportation including a return to capital. Therefore we have estimated toll charge revenue as operating costs plus a market return on investment. For our base case analysis we use the real before tax opportunity cost of capital of 8% recommended in Canada’s benefit cost guidelines (Canada TBCS 2007). We also conduct sensitivity analyses using discount rates of 6% and 10%. We also include a sensitivity analysis on capital cost of +/-10%. Based on past experience, we note the propensity for actual construction costs to exceed forecast construction costs, so the higher cost scenario is more likely (Flyvbjerg et al. 2003; Gunton 2003). The recently approved Kearl oil sands mine, for example, has seen capital costs (CAPEX) rise significantly above original estimates (see footnote 1) and costs for the Mackenzie Gas Project have also experienced escalation (Park 2011)4.
Although feasibility of the project is based on the oil pipeline we have not completed a supply/demand analysis of the condensate market to assess when and if the condensate
4 We acknowledge that Enbridge’s Clipper expansion is reported to have come in on budget, but this may not be indicative of building a new greenfield project such as the ENGP (Enbridge 2010b p.50). However, the Enbridge experience shows that costs overruns are not a certainty.
22 pipeline capacity is required. We conduct a sensitivity analysis based on just the oil pipeline component of the project, which shows the results if the condensate pipeline capacity is required before the oil pipeline is required. In the absence of a breakdown in the costs of the oil pipeline alone, we have estimated construction and operating costs associated with the oil pipeline by using the proportion of total capacity for both the oil and condensate pipelines that will be utilized exclusively by the oil pipeline. The entire analysis is done in constant 2009 Canadian dollars.
The results of the BCA are summarized in Table 5. The results show that under no scenario will the ENGP generate a net benefit to Canada, even when including an Asian price premium. Under the base case assumption, the ENGP generates a net cost to Canada of over $1.5 billion (2009 CAD). We believe that the base case is a conservative estimate because the surplus capacity assumptions are conservative and there is a propensity for actual capital costs to exceed forecast capital costs for large projects. Under the various sensitivities, the net costs to Canada range from a cost of $362.4 million to over $2.2 billion (2009 CAD). The results are driven by the opportunity cost of surplus capacity that would be created in the Canadian pipeline system with the construction of the ENGP. Note that the net cost is reduced by the presence of an Asian price premium. However, as discussed above, the Asian price premium, if it exists, needs to be reduced by the proportion of the price benefit accruing to non-Canadians.
Table 5: Benefit Cost Results to WCSB Oil Sector- No Social-Environmental Costs (2009 CAD)
BCA Scenario NPV of ENGP Base Case -$1,562.7 95% Pipeline Capacity Utilization -$1,008.6 No Keystone XL -$362.4 10% Lower Export Volumes -$2,249.1 10% Higher Export Volumes -$697.9 Asian Premium -$409.2 Employee Benefits -$1,518.4 6% Discount Rate -$1,424.9 10% Discount Rate -$1,678.8 10% Lower Capital Costs -$1,406.4 10% Higher Capital Costs -$1,718.9 Oil Pipeline Only -$1,142.6 *Construction and operating costs associated with the oil pipeline are estimated by the proportion of total capacity of the project used exclusively by the oil pipeline.
The next step in the BCA is to include social and environmental costs and make adjustments for potential market imperfections. Given that the preliminary assessment shows net costs to Canada without inclusion of environmental costs and resource constraints on our research budget, we have not attempted to complete this next step in the BCA. However, it is useful to provide a limited discussion of some of these additional costs to indicate the general order of magnitude of their effect on the ENGP’s contribution to the public interest.
23 An obvious environmental cost that needs to be included in the analysis is the risk of oil spills. One method for assessing the costs of a potential spill is contingent valuation (CV) techniques that assess how much people would pay to prevent a spill. There are many challenges and issues involved in CV but the general consensus is that if CV is conducted according to best practices, it provides a valid measure of the value of non-market resources (Pearse et al. 2006).
An indication of the magnitude of what people are willing to pay to prevent a major oil spill is provided by a study by Carson et al. (2003) of the Exxon Valdez oil spill in Prince William Sound (PWS) originally prepared for the State of Alaska. The CV study prepared by Carson et al. (2003) uses methodological best practices that withstood the scrutiny of the courts and independent experts. Best practices include a comprehensive pretesting program to refine the survey instrument, rigorous probability sampling to capture a representative sample of the US population, in-person interviews, double-bounded discrete choice willingness to pay (WTP) questions, detailed description of the program inclusive of photographs and maps, and checks of respondents to ensure their comprehension. The courts and independent experts scrutinized the study’s results and the study underwent the peer review process for refereed publications when it was published in Environmental and Resource Economics in 2003. For these reasons, the Carson et al. study is widely considered among the most sophisticated CV studies for assessing oil spill damages to natural resources (ARI 1993). Carson et al. (2003) estimate WTP values between $4.9 and $7.2 billion (1991 USD). Both estimates were developed under the assumption that the entire US population suffered non-use damages from the Exxon Valdez oil spill.
The CV study by Carson et al. (2003) was a conservative application of CV. Researchers were mandated by the legal proceedings to use a survey that elicited WTP to prevent another oil spill, instead of willingness to accept (WTA) a loss of environmental assets from another oil spill, even though WTA may be more appropriate in the case of an oil spill (Carson et al. 2003; Rutherford et al. 1998). If WTA is used instead of WTP, the damage estimates could increase by 10.4 times, which is the average ratio of WTA to WTP for CV studies of environmental benefits (Horowitz and McConnell 2002). Based on this ratio, the WTA values to avoid an oil spill in PWS range up to $74.9 billion (1991 USD). Adjusting the Carson et al. (2003) findings to the size of the Canadian population and translating the estimates into 2010 Canadian dollars yields a WTP estimate to prevent a major oil spill the Pacific North Coast Integrated Management Area (PNCIMA) of between $1.1 and $1.7 billion (2010 CAD) and a WTA estimate from $11.6 to $17.2 billion (2010 CAD). It should be emphasized that these estimates are based on the US population for PWS and Canadian estimates of non-use damages may be higher or lower. It should also be emphasized that actual damage costs for non-use values would be considerably higher because non- Canadians would be willing to pay as well as Canadians for protection of the PNCIMA.
Another component of the cost of an oil spill is the potential damage to direct users and clean up costs to the responsible parties that may result if a spill occurs. Damage costs would have to be estimated for various types of spills and an expected value would have to be calculated by multiplying the damage costs by the probability of occurrence. Enbridge experienced an average of 74 oil spills per year based on the last five years between 2006
24 and 2010 (Enbridge 2011b pp. 55-60). We note that the cost to Enbridge of pipeline spills in 2010 is estimated to be $642 million for 80 spills totaling 34,122 barrels of oil. Although this is an unusual year involving several major spills it shows that the cost of pipeline spills is a significant factor that must be included in the BCA. For marine spills, we have estimated the costs of a major oil spill equivalent to the Exxon Valdez in the PNCIMA at between $5.2 and $22.7 billion (2010 CAD), which include the non-use cost estimates based on the Carson et al. (2003) study (Gunton and Broadbent 2011). If we deduct the non-use costs based on the Carson et al. study, which have been provided above, the direct costs of a spill range between $4.1 billion and $5.5 billion. The estimated cost would have to be adjusted for probability of occurrence to estimate an expected value for inclusion in the BCA. In addition, the damage costs of other size marine as well as pipeline spills would need to be incorporated. We also caution that these estimated damage costs are a low estimate of actual damages because they exclude many of the costs associated with a spill that are difficult to monetize.
A third major environmental cost are GHG emissions. There are many challenges in estimating the cost of GHG emissions for the ENGP and we have not attempted to complete such an analysis. However, to again show the relative significance of this factor we have estimated GHG emissions for the operating life of the project. We estimate GHG emissions for four scenarios with data from IHS CERA (2010) and Tol (2005). The four scenarios are: 1. Total emissions to the end of processing in Canada, which include crude production, upgrading, and transport 2. Total emissions to the end of refining, which include crude production, upgrading, transport, and refining, as well as distribution of refined products 3. Total life cycle emissions, which include crude production, upgrading, transport, refining, distribution, fuel combustion, 4. The incremental life cycle emissions from diluted bitumen relative to non-oil sands oil, which in this case is the average US barrel consumed.
To determine total GHG emissions for each scenario, we use emissions factors provided by IHS (CERA) and a range of damage estimates for GHG emissions of $16 to $50 per tonne from Tol (2005). Our calculations are based on oil pipeline throughput for the ENGP according to our supply/demand assumptions. This volume is lower than the capacity of the ENGP because the capacity is surplus to WCSB requirements and therefore the incremental contribution of the ENGP is based only on the volume of capacity required during the project’s 30-year operating period. Table 6 presents total tonnes of GHG emissions produced and the NPV values for the four GHG emission scenarios based on a 30- year operating life. All figures are adjusted for inflation between 2005 and 2010 and converted to Canadian dollars. Based on GHG emissions of 109.7 to 2,290.1 million tonnes over the life of the project, GHG damage estimates range from $949.1 million to $61.9 billion (2010 CAD). It should reiterated that GHG costs are merely presented to illustrate the potential cost of damages from GHG emissions associated with the ENGP. If GHG emissions were included as a component in the BCA, the incremental emissions from the ENGP would have to be estimated. The incremental emissions assessment would assess whether the ENGP project results in: no incremental oil sands production (it just replaces other projects), incremental oil sands production that displaces other lower GHG
25 generating non-oil sands production, or incremental oil sands production that is a net increase in world oil production. These various scenarios would all involve different estimates of the GHG emissions from the ENGP. We make no attempt within this analysis to assess which assumption or combination of assumptions is correct. Nonetheless, the GHG estimates in Table 6 show that there are potentially significant GHG emissions costs associated with the project that need to be evaluated in a comprehensive BCA of the ENGP.
Table 6: Damage Estimates for GHG Emissions from ENGP
Emissions Total Tonnes of NPV of GHG Damages*** Factor GHG Emissions Scenario CO2e produced (2010 CAD in millions) (kg CO e 2 (in millions) per barrel) Lower Bound Upper Bound 1. End of Processing* 55.5 248.4 $2,150.0 $6,718.7 2. End of Refining* 127.6 571.2 $4,943.0 $15,447.0 3. Total Life Cycle * 511.6 2,290.1 $19,818.6 $61,933.2 4. Incremental Life Cycle** 24.5 109.7 $949.1 $2,965.9 Source: Computed from data in IHS CERA (2010) and Tol (2005). Note: CO2e represents carbon dioxide equivalent * Based on Canadian oil sands SAGD dilbit. ** Based on difference between Canadian oil sands SAGD dilbit and average US barrel consumed 2005. *** A 4.5% discount rate is used based on common standard practice for social costs (Tol 2005).
Another potential cost is the socio-economic cost of major conflict over the building of the ENGP. There is strong opposition to the project that will likely manifest itself in legal actions, other activities to oppose the project, and psychological stress associated with the conflict. This incurs a potentially significant cost in the form of both direct costs associated with resolving disputes and indirect costs resulting from impairment of Canada’s international reputation. Indirect costs can include reduced investment and resistance to purchasing Canadian products.
There are many other environmental costs associated with the ENGP that need to be included in a full BCA. There are also some costs that cannot be successfully monetized but should be incorporated into the evaluation in a multiple accounts framework so all the costs and benefits are clearly assessed (Shaffer 2010). One important factor, for example, is the distribution of impacts, which Enbridge has not addressed in their assessment of the public interest. Coastal First Nations are expected to incur the potential costs and risks of the project without receiving benefits. Meanwhile, potential benefits are earned by the oil producers, and Enbridge. Such an asymmetrical distribution of costs and benefits is inequitable and contrary to the public interest.
In sum, the BCA based on costs and benefits to only the oil and gas sector indicates that the ENGP likely imposes a net cost if constructed as planned. We acknowledge that there will be differences in the estimates of the benefits and costs of the ENGP based on different assumptions and forecasts. We have attempted to address some of these differences by providing sensitivity analyses. We also emphasize that more analysis is required to refine environmental cost estimates. Nonetheless, the preliminary assessment of environmental costs shows that the inclusion of just a subset of social-environmental costs summarized in
26 Table 7 will significantly increase the net costs to Canada. The methodologies for estimating these costs are well developed in many cases and it is important to complete a full BCA to estimate the total social and environmental costs to Canada prior to making a decision on the ENGP. It is also important for decision makers to complete an evaluation of alternatives to shipping WCSB oil to ensure that the most cost-effective options are chosen. Evaluating one option in isolation simply because it is submitted for review can result in failure to assess the relative costs and benefits of alternatives and a failure to choose the option or combination of options that maximizes the Canadian public interest.
We also caution that BCA is merely a guide to assist decision makers in identifying the public interest. In a democratic society the public interest is ultimately determined by the values and preferences of the public. Therefore even if the BCA showed that ENGP generated a net benefit to Canada, the ENGP could only be considered to be in the public interest if it had the broad support of the public and more specifically of those most impacted by the project.
Table 7: Summary of Selected Environmental Costs Associated with the ENGP
Damage Estimates Type of Cost (2010 CAD in millions) Lower Bound Upper Bound Oil Spill Non-use Value Damages* $1,118.1 $17,198.1 Oil Spill Use Values Damages* $4,075.7 $5,457.5 Damages from GHG Emissions** $949.1 $61,933.2 Other Social-environmental Costs unknown unknown Sources: Gunton and Broadbent (2011); IHS CERA (2010); Tol (2005) Notes: Socio-economic costs unavailable. * Non-use and use value damage costs are based on one major oil tanker spill and need to be estimated as an expected value based on the probability of spills for a range of marine oil spill sizes. The expected damage costs of terrestrial pipeline spills need to be estimated and included as well. ** Costs associated with GHG emissions represent the NPV of potential GHG emissions over the 30-year life of the project discounted at 4.5% based on the incremental volumes that would use the incremental capacity of the ENGP.
5. Conclusion The NEB criteria for project approval requires the project to be needed and in the public interest. Enbridge’s submission states that the project is needed and in the public interest because it will provide needed pipeline capacity to accommodate increasing oil production in the WCSB, it will provide access to Asian markets which will reduce risk through market diversification, earn higher returns for oil producers, and it will generate significant economic activity.
Enbridge’s submission on need and the public interest is deficient and incomplete in several respects. First, Enbridge does not complete a supply/demand assessment of pipeline capacity to demonstrate that the ENGP is needed. Second, Enbridge assumes a continuation of a permanent Asian price premium to 2046 and assumes a permanent increase in price to 2046 for all Canadian oil exports to the US without sufficient documentation to support the claim. Third, Enbridge estimates gross instead of net impacts and incorrectly defines gross economic impacts as benefits without assessing the
27 value of what is being produced. Fourth, Enbridge omits consideration of costs in its public interest analysis, contrary to the requirements explicitly specified by the NEB. Therefore Enbridge does not provide sufficient evidence to show that the ENGP is needed or is in the public interest. Further, there has been no attempt to assess the ENGP relative to other viable transportation options to ensure that the most cost-effective options are selected.
To assess the need for the ENGP we completed a supply/demand analysis that shows that it is highly unlikely that the ENGP is required within the forecast period to 2020. To assess the public interest we completed a benefit cost analysis that shows that the ENGP will result in a net cost to Canada. We therefore conclude that the ENGP does not meet the NEB criteria for project approval.
28 References
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32 Appendix II, Marine Navigation: Measures to Reduce the Risk of Martine Incidents
This evidence is provided by, Captain Harrison J. Layton and Michael M. McGuire based upon our review of Coastal First Nations (CFN) Information Request #1 and NGP responses to it.
I, Captain Harrison J. Layton, have recently retired from BC Coastal Pilots after over 40 years experience in the marine industry. I have direct experience with the proposed tanker routes being proposed by Northern Gateway.
I, Michael McGuire, have recently retired from the Pacific Pilotage Authority, where I was Manager of Dispatch Operations and Community Liaison and Special Projects Manager. My role at the Pilotage Authority included on-going Safety and Operations with pilots and agents for industry representatives.
Weather Conditions 1. In our experience, weather conditions in the Queen Charlotte Sound, Dixon Entrance and Hecate Strait can be severe enough to affect navigation, create vessel problems and increase the risk of incidents:
There is no storm like Haida Gwaii storms during the fall and winter months;
The Dixon Entrance can be one of the worst areas due to the geography and currents in stormy weather;
Hecate Strait is very shallow and strong winds cause large waves and very strong tides;
Severe weather conditions are not limited to the Winter months - ‘Screaming’ Northwest winds also occur in the summer;
There are occasions when waves can be large enough to allow the sea to come in thru air intakes creating mechanical failure;
While we do not believe fog to be a problem, mixed rain and snow can create hazardous visibility situations;
2. We, therefore, agree with the proposal of establishing conservative Operating Safety Limits to ensure that weather considerations inform vessel management and contribute to vessel and environmental safety. Business Considerations Affecting Vessel Management 3. Tanker owners, their agents and ships captains have a strong monetary interest in minimizing the time involved in transporting their cargo and, therefore, tend to be concerned about measures that can cause delays (e.g. government regulations, conservative operating limits, shortage or unavailability of pilots and tugs).
4. Ship owners, or their agents, while accepting the costs of delays as part of the business of conducting safe shipping, are the primary stakeholder consulted with in the development of regulatory limits and in the event of delay situations occurring.
5. In our experience, the time – cost factor will be an important consideration when ships captains face severe weather conditions and make decisions about proceeding, finding shelter, waiting or riding out the storm. Accordingly, there is an inbuilt bias in their decisions which can increase risk.
6. Similarly, cost factors also play an important part in pilotage, as pilotage operating costs are born by the shipping industry on a cost recovery basis. This makes cost a factor in the establishment of new pilot stations.
7. Proposals to extend the regulated pilotage area in the OWA, would result in an increased cost to ship owners. For the Pacific Pilotage Authority, while costs are recovered from ship owners, it would potentially require recruitment and training of additional pilots. Extending the Pilotage areas beyond existing pilot stations would result in extending the period of time that pilots would be unavailable for the next assignment because of mandatory rest periods.
Pilotage 8. Our experience has been that BC Coastal pilots are professional and capable of piloting large vessels, including VLCCs.
9. World class training for piloting VLCCs is available in countries such as France and Poland. As well, opportunities for actual training B.C. Pilots on board VLCCs can be arranged with the Atlantic Pilotage Authority for VLCCs entering and departing Port Hawkesbury. These training sites are currently used.
10. The need for additional pilots on each vessel transit of a tanker into or out of Kitimat will have a negative effect on BC Coast Pilot strength. Current levels of pilot replacement and training would have to increase to keep up to the anticipated demand. This is exacerbated by the fact that two pilots will be required to be on board any transit to Kitimat due to the distance piloted exceeding 105 miles and the duration of the transit exceeding 8 hours. The Pacific Pilotage Authority and the BC Coast Pilots maintain pilot strength by attrition. A pilot is replaced when he retires by a qualified apprentice pilot from a pool of applicants who have passed the Pilotage Exams. Currently 5 apprentice pilots are actively training as of recent appointment.
11. Pilots are capable of boarding or disembarking vessels in most weather and sea conditions, although we find it preferable. In such conditions to do so by helicopter.
12. We recognize that the use of helicopters for pilot boarding and disembarking is dependent upon: helicopter availability, the vessel’s ability to accommodate helicopters, and pilots trained for helicopter boarding.
13. We agree that marine traffic delays attributed to pilots does not occur too often in the Prince Rupert area. When it does occur, MCTS in Prince Rupert will suggest the vessel remain at sea until such a time that conditions improve to allow pilot boarding/disembarking.
14. The more likely causes of vessel delays are cargo delays or terminal breakdowns for vessels at berth. These occurrences may make it necessary for vessels to alter planned schedules and cause a domino effect of such delays.
15. We feel quite strongly, that the presence of pilots on board tankers serves to reduce risk and that disagreements between Ship Captains and Pilots are rare and can be prevented by pre-embarkation discussions. If they do arise during transit, Pilot’s can remind a Ship’s Captain that they could be subject to a $5000.00 fine.
16. However, we know that the presence of pilots does not eliminate the risk of an incident and that there have been many incidents in the past.
17. Based on information supplied by the Pacific Pilotage Authority (PPA), the number of marine vessel incidents that have occurred between 2006-2009 with pilots on board is: 2006 – 8; 2007 – 7; 2008 – 4; 2009 – 6
18. We are unsure of the reasons for all of these incidents but we are aware that occasionally ship masters are reluctant to accept a Pilot’s advice.
Tugs 19. We agree that escort tugs are imperative in reducing the risk of incidents. However, to the best of our knowledge, there are not enough suitable tugs in the Prince Rupert area.
20. We also note that the use of escort tugs is not proposed for the Open Water Area (OWA) except possibly in a very limited area. We feel that in a perfect world, the use of escort tugs in the OWA would also serve to reduce the risk of incidents in that area...
21. We believe that escort tugs would not be capable of carrying sufficient containment booms to completely enclose a V.L.C.C and that an S.R.V. (spill response vessel) should accompany all loaded tankers when underway in confined waters.
22. Should escort tugs not be used in the OWA, we believe it would take a rescue tug to get from Kitimat to Pine Island or Dixon Entrance at least 12 hours to 17 hours, depending on location, speed and sea conditions.
Fisheries Liaison Committee 23. We understand that there are many fishing vessels operating in, or transiting, along the proposed tanker routes. In our experience, communications between fishing boats and larger vessels to avoid each other may not always work since fishers are often too busy fishing and may be reluctant to remove their gear and stop fishing.
24. While it may be true that most fishing vessels are too small to rupture a tanker in the event of a collision, there is an element of risk in close encounters in which fishing gear is caught in tanker propellers which can jam the shaft causing the tanker to lose propulsion.
25. While, in our experience, there have been few incidents involving collision with fishing boats, we feel a Fisheries Liaison Committee is a good plan to reduce the risk of collisions and entanglement with fishing gear, providing it would be maintained.
Human Error 26. There may be many reasons for incidents attributable to human error. But in our experience, the main causes are poor communications due to language differences. While, alcohol, drugs, and fatigue may be other factors (e.g. Exxon Valdez), in our experience alcohol is rarely encountered.
27. While the language of marine transport is English, the primary language of many crew members is not. This can create problems, especially in emergency situations.
28. Rules of work designed to prevent human error, are not always followed by ship captains, especially in poor weather conditions. We also believe that such rules do not apply to tug captains.
29. In our experience, it is unusual to see alcohol problems on piloted vessels because, like alcohol related automobile regulations, the worldwide shipping industry has adopted Drug and Alcohol Guidelines. Accordingly, it is not an issue of law so much as one of enforcement. Having pilots on board vessels acts as a deterrent to alcohol and drug use.
30. While, a pilot leaving Kitimat could refuse to sail if he/she suspected a problem with alcohol or drugs, we understand that in the U.S.A. there are spot checks by regulators to prevent such problems.
31. We feel that mandatory alcohol and drug testing for all officers and crew on tankers trading in Canadian waters could also serve as a deterrent, and prevent alcohol and drug related problems. If so, then Pilots should also be scrutinized to avoid cries of discrimination.
Kitimat 32. Anchorage in Kitimat is not a great idea. The holding ground is not good and the water depth does not allow a minimum of 4-5 to 1 shackles of cable to be used.
33. Currently, there is not an established Port Authority in Kitimat responsible for monitoring risk and safety factors. But we understand that a Harbour Safety Committee has been discussed. Either of these could provide a body to monitor risk and safety factors for the harbour area and its approaches.
Expanded Pilotage Area 34. We agree that expanding the regulated Pilotage area for tankers to include the Queen Charlotte Sound, Hecate Strait and Dixon Entrance would reduce the risk of oil tanker incidents (recognizing that this has cost implications for ship owners and staffing implications for the PPA).
35. There already is a pilot station at Pine Island (Vancouver Island) that is used year round for travelling from Vancouver to Kitimat. Its use for NGP tankers would mean that establishing a new one at Camaano Sound would not be necessary.
36. In order to establish new pilot stations on Haida Gwaii, the PRMM process established following the Canadian Transportation Agency report (2009), Ministerial Review of Outstanding Pilotage Issues, would have to be followed. Alternatively, it may be possible to extend the limits for certain vessels (i.e. laden oil tankers) to embark or retain Pilots on Board to an approved Boarding or Takeoff point beyond current Pilot Station limits.
37. BC Coast pilots are licensed for all B.C waters with the exception of the Fraser River.
Traffic Separation Schemes (TSS). 38. While we feel that TSS in narrow channels can create, rather than reduce, risks, in our experience, it would be a good idea to establish TSS in the Dixon Entrance.
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P)81)(<1*!$<0<1&!D)/(2C)41)<08!B2C<17<(C)!5=1)7S!E>$!DB5F-!"##:-!580&'0)!V(8!$@(88! N(C2141*(0<(C)!B2Ca17@*0<1-!VQQ(71!CQ!U1&1027M!0)*!?1/18C@41)<+! 30&M()= ! ""#! WORLDOCEAN CONSULTING LTD Marine Oil Spill Aspects of the Northern Gateway Project A Review of Enbridge’s NEB/CEAA Application Prepared for Living Oceans Society and Coastal First Nations Great Bear Initiative by Gerald Graham, B. A., M. A., Ph. D. President Worldocean Consulting Ltd Final Report Submitted 9/9/2010 i Contents List of Acronyms ...... iii List of Figures, Tables and Annexes ...... v List of Incidents Referred to in the Body of the Report, In Order of Mention ...... vi Introduction ...... 1 Marine Component of the Proposed Project...... 2 Marine Oil Spill Prevention and Response Filing Requirements ...... 5 Introduction ...... 5 The JRPA ...... 5 Scope of the Factors Document ...... 5 Procedural Direction ...... 6 Marine Oil Spill Prevention and Response Elements of the Proposal ...... 7 Introduction ...... 7 Measures to Prevent a Spill from Occurring ...... 7 Measures To Be Taken In Response to a Spill Incident ...... 7 Detailed Review of the Marine Oil Spill Prevention and Response Elements of the Filing ...... 12 General Comment ...... 12 Volume 7C- Risk Assessment and Management of Spills- Kitimat Terminal ...... 15 3 Probability of Hydrocarbon Spills, Pp. 3-1, 3-2 ...... 15 5 Incident Prevention and Response, P. 5-1 ...... 15 5.6 Equipment and Personnel, P. 5-11 ...... 16 5.7.1 Environmental Sensitivity Atlas, P. 5-13 ...... 16 5.8 Shoreline Response, P. 5-15 ...... 17 9.1 Introduction, P. 9-1 ...... 17 9.3 General Mitigation Measures, P. 9-2 ...... 17 9.4 Selection of Examples Pp. 9-2 through 9-15 ...... 18 Appendices A, B, C and D ...... 18 Volume 8A: Overview and General Information- Marine Transportation...... 19 1.1 Overview of Tanker Operations and Environmental Protection, P. 1-1, 1-2 ...... 19 4.1.3.2 Double Hulls, P. 4-4 ...... 19 ii 4.1.3.4 Machinery, P. 4-6 ...... 21 4.1.6 Terminal Regulations for Vessel Acceptance, P. 4-13 ...... 21 4.2.4, Geographic and Geological Factors, P. 4-19 ...... 22 4.2.10.2 Escort Tug Services, P. 4-28 ...... 22 4.8.1.2 Marine Shipping Network Analysis and Marine Terminal Incident Analysis, PP. 4-78 – 4-83 23 Volume 8B: Environmental and Socio-Economic Assessment ( ESA )- Marine Transportation ...... 25 2.3 Oil and Condensate Tanker Specifications and Traffic, Pp. 2-2, Page 2--3 ...... 25 Section 2: Description of Marine Transportation Activities, Pp. 2-2 – 2-9...... 26 3.1.2 Prevailing Climate Conditions, P. 3-2 ...... 26 3.1.4 Winds, p. 3-3 ...... 26 3.1.6 Waves, P. 3-4 ...... 26 4.2.3.2 Project Inclusion List, Pp. 4-13 - 4-15 ...... 27 13.5.3 Climate and Oceanographic Factors, P. 3-15 ...... 27 14.2 Effects of Severe Weather on Marine Transportation, Page 14-1 ...... 28 Volume 8C: Risk Assessment and Management of Spills- Marine Transportation ...... 29 General ...... 29 2 Operational Measures to Prevent Tanker-based Hydrocarbon Spills, P. 2-1 ...... 29 3 Probability of Hydrocarbon Spills, Pp. 3-1 -3-4 ...... 29 5.2 Response Approaches and Capabilities, pp. 5-3 – 5-7 ...... 33 5.5 Equipment and Personnel, Pp. 5-10 -5-13 ...... 33 10 Mass Balance Examples for Response Planning, PP. 10-1 -10-39 ...... 35 Summary ...... 38 Explanatory Note ...... 38 General ...... 38 Volume 7C ...... 38 Volume 8A ...... 39 Volume 8B ...... 39 Volume 8C ...... 40 Annex 1: Major Oil Spills Since 1967, in Tonnes* ...... 42 Bibliography ...... 44 iii List of Acronyms BCO Burrard Clean Operations CCAA Confined Channel Assessment Area CCG Canadian Coast Guard CEAA Canadian Environmental Assessment Agency CSA Canadian Standards Association DH Double Hull DNV Det Norske Veritas DWT Deadweight Tonnage EDRC Effective Daily Recovery Capacity ESA Environmental and Socio-Economic Assessment FOSET Fishermen’s Oil Spill Emergency Team GOSRP General Oil Spill Response Plan HFO Heavy Fuel Oil IFO Intermediate Fuel Oil INTERTANKO International Association of Independent Tanker Owners ITOPF International Tanker Owners Pollution Federation JRP Joint Review Panel JRPA Joint Review Panel Agreement ( short form ) MV Motor Vessel NASF Non-Accidental Structural Failure NEB National Energy Board NOAA National Oceanographic and Atmospheric Administration OBO Ore Bulk Oil Carrier iv OSRL Oil Spill Response Limited OSRP Oil Spill Response Plan OSRV Oil Spill Response Vessel OWA Open Water Area PAR Primary Area of Response PPA Pacific Pilotage Authority PNCIMA Pacific North Coast Integrated Management Area QRA Quantitative Risk Assessment RP Responsible Party RO Response Organisation SH Single Hull TERMPOL Technical Review Process of Marine Systems and Transshipment Sites TOR Terms of Reference VLCC Very Large Crude Carrier v List of Figures, Tables and Annexes Table 1 Overview of OSRP Equipment Table 2 Comparing Enbridge’s Tiered Response Proposal to Current CCG Requirements for ROs Table 3 Proposed Hydrocarbon Recovery Capability Table 4: Notable Marine Oil Spills Involving Double Hulled Tankers, OBOs and/or Tank Barges Table 5: Casualty data, covered period 1990-2008 ( without accidents in Shipyards & Dry Docks ) Table 6: Causes of accidents ( for both single and double hull tankers ) Table 7 Missing Data for the Open Water Area ( OWA ) Figure 1: PNCIMA Area Map Annex 1: Major Oil Spills Since 1967, in Tonnes vi List of Incidents Referred to in the Body of the Report In Order of Mention1 MV Westwood Anette MV Limburg Sea Voyager tug Pathfinder tug Commitment tug-barge Ted Leroy tug-barge MV Petersfield MV Cosco Busan MV Queen of the North MV Selendang Ayu MV Northern Adventure MV Erika MV Krymsk MV Prestige MV Braer MV Exxon Valdez MV Atlantic Empress 1 Many other incidents are listed in Table 4 and Annex 1. 1 Introduction This report is a critical analysis of the marine oil spill prevention and response aspects of Enbridge’s Northern Gateway project application which was filed with the National Energy Board ( NEB ) and Canadian Environmental Assessment Agency ( CEAA ) on May 27, 2010. It is submitted in fulfillment of the Terms of Reference appended to the contract between Worldocean Consulting Ltd and Living Oceans Society, on behalf of Living Oceans Society and Coastal First Nations Great Bear Initiative, which entered into force on July 28, 2010. The report consists of a detailed review of the marine oil spill sections from the following volumes of the application: o Volume 7C: Risk Assessment and Management of Spills- Kitimat Terminal; o Volume 8A: Overview and General Information- Marine Transportation; o Volume 8B: Environmental and Socio-Economic Assessment ( ESA )- Marine Transportation; and o Volume 8 C: Risk Assessment and Management of Spills- Marine Transportation. 2 Marine Component of the Proposed Project According to the Terms of Reference for the Joint Review Panel ( hereafter referred to as the JRP ), Enbridge’s Northern Gateway project consists of, inter alia: two pipelines ( one westbound for Alberta oil and one eastbound for condensate ); a tank terminal; two marine loading and unloading berths ( one each for oil and condensate ); marine transportation of oil and condensate; plus all related works and activities. 2 The oil pipeline being proposed will have an initial capacity of 525,000 barrels per day. According to Enbridge, it will be designed to transport conventional light and heavy oil synthetic oil, bitumen blended with condensate and bitumen blended with synthetic oil.3 The condensate pipeline would have a capacity of 193,000 barrels per day.4 The marine transportation component includes the use of various types and sizes of tankers to transport oil out of Kitimat, and condensate into Kitimat and points inland. According to the proponent, between 190 and 250 tankers will visit Kitimat each year, for an average of 220 tanker visits per year. On average, there are expected to be 1.2 transits per day in the Confined Channel Assessment Area ( CCAA ).5 A breakdown of the 220 tanker visits by route and type of cargo transported ( condensate or oil ), is summarised here: The oil and condensate would be transported in Aframax6, Suezmax7 and Very Large Crude Carrier ( VLCC )8 tankers; 70 of the 220 tanker visits to Kitimat will be by condensate tankers and one hundred and fifty by oil tankers9; 2 Agreement between the National Energy Board and the Minister of the Environment Concerning the Joint Review of the Northern Gateway Pipeline Project, Pp. 9, 10. 3 Volume 1: Overview and General Information, P. 1-1. 4 Ibid. 5 Volume 8B: Environmental and Socio-Economic Assessment ( ESA )- Marine Transportation, P. 2-9. 6 Aframax tankers are in the 80,000- 119,99 DWT range. Enbridge estimates each Aframax tanker will carry approximately 691,000 barrels of oil per voyage. Table 2-2, Oil and Condensate Tanker Specifications and Traffic, Volume 8B, P. 2-2. 7 Suezmax tankers are in the 120,000- 199,999 DWT range, and will carry approximately one million barrels of oil per voyage. Ibid. 8 VLCCs are in the 200,000-320,000 DWT range, and will carry approximately two million barrels of oil per voyage. Ibid. There is a larger size of tanker plying the seas- the Ultra Large Crude Carrier, or ULCC. However, the private port of Kitimat is only approved to receive tankers up to and including the VLCC 320,000 DWT range. Kitimat Arm is apparently not considered wide enough for tankers larger than VLCCs to safely maneuver in and out of a terminal. 9 Ibid., P. 2-9. On P. 3-2 of Volume 8C, Risk Assessment and Management of Spills- Marine Transportation, slightly different figures are given- 71 condensate vs. 149 oil tankers. 3 o 50 of these 220 port calls will involve VLCC class tankers, 120 Suezmax class and 50 Aframax class.10 The condensate will only be transported in the smaller Aframax and Suezmax tankers, whereas the largest tanker class- the VLCCs, will only carry oil.11 The tankers would follow either a northern route, referred to by the proponent as the Northern Approach, or a southern route- the so-called Southern Approach. The Southern Approach actually consists of two routes- one entering and exiting Douglas Channel via Caamaño Sound, and the other via Browning Entrance and Principe Channel. 12 The Northern Approach, which encompasses Dixon Entrance and parts of Hecate Strait, would be used for tankers arriving from or departing to Asian ports13. o The proponent estimates that thirty three percent of the 220 tankers visiting Kitimat will use the Northern Approach 14; in effect, then, approximately sixty seven tankers will take the northern route. o We are told that all of the condensate will be imported from Asia ( & the Middle East )15. o As mentioned above, in Bullet 2, a total of seventy condensate tankers will be coming to Kitimat each year.16 o It is unclear whether the condensate tankers will take the Northern Approach via Dixon Entrance and Browning Entrance.17 The Southern Approach would be used for condensate tankers arriving from Asia as well as oil tankers transporting oil to destinations south of Kitimat on the North American west coast18. 10 Vol. 8B, P. 2-9. 11 Table 2-2, Oil and Condensate Tanker Specifications and Traffic, ibid., Pp. 2-2, 2-3. 12 Figure 1, ibid., P. 2-4. 13 Ibid., P. 2-3. 14Ibid., P. 2-8. 15 Volume 1, Overview and General Information, P. 1-3. 16 Ibid., P. 2-9. 17 Footnote 1, Table 3-1, Return Period of a Spill Associated with the Tanker Traffic for the Northern Gateway Project, Volume 8C: Risk Assessment and Management of Spills- Marine Transportation, P. 3-4 indicates that condensate tankers will not take the Northern Route at all. However, on Page 2-3 of Volume 8B, P. 2-3 the following statement appears: “Tankers arriving from or departing to Asian ports will use the Northern Approach, which passes the Haida Gwaii through Dixon Entrance, and continues through Hecate Strait, Browning Entrance, Principe Channel, etc…” As mentioned above, Enbridge states that all the condensate will be imported from Asian and/or Middle Eastern ports. Thus, there is an apparent contradiction in these two statements. 18 Volume 8B, P. 2-5. The term ‘ports on the west coast of North America’ is assumed to include ports in California. It is unclear whether the proponent intends to ship the oil to terminals in Puget Sound, or Burrard Inlet, for that matter. 4 o Sixty seven percent of the tankers will follow the Southern Approach- thirteen percent via the Browning Entrance and Principe Channel option, and fifty four percent via the Caamaño Sound option19 to and from west coast ports south of Kitimat20. Finally, the proponent divides the project area into two components- the CCAA and the Open Water Area ( OWA ). In a nutshell, the CCAA includes everything east of Hecate Strait, whereas the OWA includes everything else within the PNCIMA area, to the outer edge of the 12-mile Territorial Sea of Canada. Fifty percent of tankers will enter the CCAA through Principe Channel from Browning Entrance, while the other fifty percent will enter the CCAA via Caamaño Sound.21 19 Ibid., P. 2-8. 20 Ibid., P. 2-5. 21 Ibid., P. 13-11. 5 Marine Oil Spill Prevention and Response Filing Requirements Introduction This section focuses on what the proponent is required to file in support of its application, and in order for the JRP to conduct its assessment of the project. The main documents in which these requirements are set out are: the 15 January, 2010 Agreement between the National Energy Board and the Minister of the Environment Concerning the Joint Review of the Northern Gateway Pipeline Project ( hereafter referred to as the JRPA ); the August 2009 Scope of the Factors22 document from the Canadian Environmental Assessment Agency ( hereafter CEAA ); and the July 5, 2010 Procedural Direction23 from the JRP. The JRPA The Terms of Reference ( TOR ) annexed to the JRPA outline the scope of the project, the factors to be considered in the course of the review, etc. In terms of the scope of the project, the document states on Page 9 that the project includes the “…construction, operation, decommissioning and abandonment of the following components:” Of particular interest to this review, no mention is made of the potential expansion of the facilities. Thus, it is a moot point whether the panel will include potential expansion of the pipeline in its deliberations. Under Part II- Factors to be Considered During the Joint Review ( P. 11 ), among the matters the Panel is to consider are “Environmental protection, environmental monitoring, and contingency and emergency response plans.” This requirement has to be viewed in conjunction with a similar ( though by no means identical ) provision in the Scope of the Factors document which will be examined below, and another similar clause from the JRP’s Procedural Direction. Scope of the Factors Document Because the NEB’s Filing Manual does not include instructions specific to the marine components of project applications, specific guidance was issued to the proponent in this respect by CEAA in August 2009. This document is referred to as the “Scope of the Factors” document. The Sections in this document which concern us the most are “7.5 Potential Accidents and Malfunctions” and “7.6 Effects of the Environment on the Project” 7.5 Potential Accidents and Malfunctions Here the proponent is required to, inter alia, “…present a preliminary emergency measures plan and environmental protection plan making it possible to react adequately in the event of an accident”. The document then goes on to list a number of very specific items the plans are supposed to include, including a sample pollution emergency plan to be maintained on board each tanker, “persons in charge, equipment available”, etc. ( P. 14 ). There are several differences between what the afore- 22 Scope of the Factors- Northern Gateway Pipeline Project, Canadian Environmental Assessment Agency, August 2009. 23 Procedural Direction, Enbridge Northern Gateway Project, Joint Review Panel, July 5, 2010 6 mentioned JRPA requires in this respect as compared to the Scope of the Factors document. First, the former requires ‘plans’, whereas the latter requires only “preliminary” plans. However, the latter document also goes into some detail as to the types of information the plans should contain. Later in the report we will deal with the matter as to whether or not the proponent has met the information requirements in respect of contingency planning. 7.6 Effects of the Environment on the Project Here the proponent is required, inter alia, to consider how severe and extreme weather conditions, such as exceptionally strong winds, may affect the project. This is another issue which we will be dealing with later on, in an effort to determine whether the proponent has submitted sufficient information to fulfill this reporting requirement. Procedural Direction The Procedural Direction seeks input from the public regarding the issues the panel should examine, plus “…additional information which Northern Gateway should be required to file;”.24 etc. A Draft List of Issues is presented in Appendix 1 of the Procedural Direction. The list includes a section on Page 8 entitled “Safety, Mitigation and Prevention”. A total of four questions are included in the draft list: “What safety measures are in place to protect people and the environment? What are the consequences of hydrocarbon releases from the project? Are the proposed risk assessment, mitigation and prevention measures appropriate for the design, construction, operation and abandonment of the proposed facilities? Are the proposed plans and measures for emergency preparedness and response appropriate?” 24 Ibid., P. 1. A list of the additional information the proponent should be required to file is provided in a summary at the end of this report. 7 Marine Oil Spill Prevention and Response Elements of the Proposal Introduction The main features of Enbridge’s Northern Gateway project in terms of its marine oil spill response plan can basically be divided into two types of measures: those intended to prevent a spill from occurring, and those intended to be taken in response to a spill incident. Both types of measures apply to the marine terminal as well as the marine transportation component of the project, with some obvious differences in terms of specifics. Measures to Prevent a Spill from Occurring At the Terminal The proponent is proposing a number of measures to prevent an oil spill from occurring at the marine terminal, including the use of harbor and escort tugs, as well as placing a containment boom around the tanker as it loads. Other measures taken to prevent tanker spills generally should apply equally at the terminal. On the Water Numerous measures are planned to prevent marine oil spills from tankers, including: Use of ‘modern’, double hull tankers A screening process designed to select only safe tankers and weed out those that are unsafe Use of trained crews Having a pilot on board fully-laden tankers within the CCAA Use of harbor and escort tugs at the terminal, and escort tugs within the CCAA Use of radar and improvement of navigational aids all along the transportation route Safe transit speeds Speed limits within CCCA Operational safety limits that cover visibility, wind and sea conditions Automated Identification System for tracking vessels Measures To Be Taken In Response to a Spill Incident The proponent is also pledging to take a number of steps to mitigate the damage if a spill were to occur, including: Escort tugs to double as response and firefighting vessels First response capability in the region, including the placement of at least four response depots at strategic locations within the project area Rapid and effective response to spill incidents Compensation for damage The commitments Enbridge makes in the application with respect to response equipment and personnel can be summarized as follows (from Section 5.5, Equipment and Personnel, Pp. 5-11 – 5-13, Volume 8C): 8 Tier 1 ( onsite ) response capability for a Primary Area of Response ( PAR ) designed to exceed Canadian Standards Association ( CSA ) standards by mobilising personnel and equipment immediately and deploying them well before the required six hours. ‘Onsite’ is meant to include resources at the Kitimat Terminal and at Response Organisation ( hereafter RO ) -designated equipment depots. Commitment to placing response equipment in caches at 4 locations throughout the CCAA that will provide response times from 6 to 12 hours on water. The proposed response capacity is depicted by the proponent in the following table: 9 Table 1 Overview of OSRP Equipment Location Boom Boats Skimmers Primary Shuttle Tanks Storage Kitimat 2000 m 2 escort tugs 3 2 Terminal 2 harbour tugs 2 terminal line boats Kitimat RO 3000 m 2 OSRVs* 4 Minimum 6 barge capacity 2 tank shuttle 3 of 350 m boats 2 RO booming boats Kitimat Estuary 3000 m 4 booming boats 2 log mini-tugs PAR Pre-staged 2000 m 16 big local 2 Minimum 4 1 ( four boats** barge capacity locations of 350 m3 within the CCAA ) Escort Tug 1 400 m 1 escort tug 1 500 m3 (Tanker 1) internal Escort Tug 2 400 m 1 escort tug 1 500 m3 (Tanker 2) internal Note: Local craft will be selected and incorporated under an arrangement such as the Fishermen’s Oil Spill Emergency Team (FOSET). Source: Reproduced from Table 5-3, Volume 8C, P. 5-12. *OSRVs = Oil Spill Response Vessels ** The proponent should be asked to define the term “big local boats”. 10 The response capability Enbridge is proposing, as compared to what the current CCG requirements are, can be summarised in the following table compiled by the Consultant25: Table 2 Comparing Enbridge’s Tiered Response Proposal to Current CCG Requirements for ROs CCG Tier CCG Maximum Enbridge Northern Quantity of Oil Spilled Gateway Proposal for CCAA Tier 1 Response 150 tonnes* 15000 tonnes Capability in PAR within 6 hours Tier 2 Response 1000 tonnes 2500 tonnes within 6 to Capability in PAR within 12 hours 12 hours Tier 3 Response 2500 tonnes 2500 tonnes within 6 to Capability within 18 12 hours hours Tier 4 Response 10000 tonnes 20000 tonnes within 24 Capability within 72 hours hours National and 10000 tonnes 20000 tonnes International mutual aid request Source: Worldocean Consulting Ltd, 2010, from the following sources- Volume 8C of the application, P. 5-11, and Response Organizations Standards ( 1995 )- TP12401E: http://www.tc.gc.ca/eng/marinesafety/tp-tp12401-menu-2162.htm. * Using this conversion calculator, One tonne equals approximately 7.9 barrels. Thus, 150 tonnes equals 1185 barrels. Thus, the response capability Enbridge is proposing for the CCCA exceeds current requirements for ROs within Canada in virtually every respect, whether viewed from a tonnage or a time perspective. For example, where CCG requires a 150 tonne ( 1185 barrel ) response capacity, Enbridge promises ten times that. And where CCG requires a 2500 tonne ( 19,750 barrel ) response capacity within 18 hours, Enbridge is promising that level of response capacity within six to twelve hours. This is not to say that 25 CCG requirements have been simplified in this table for the sake of brevity. For details, please refer to the original CCG document listed as a source of information. 11 what Enbridge is proposing is either sufficient or meets or exceeds ‘world class’ standards, issues which the JRP will have to consider in the course of its deliberations, and which this report deals with later on. Enbridge’s application also includes a table which details its proposed hydrocarbon recovery capability for various regions within the CCAA: Table 3 Proposed Hydrocarbon Recovery Capability Location of Spill Effective Daily Storage (m3)* Boom (m) Response Equipment Recovery Capacity (EDRC) (m3/day) Escort Tugs 960 1,000 800 Marine and Kitimat 2400 10,500 7,000 Terminal South Douglas Channel 1,440 550 2,000 North CCAA 1,440 550 2,000 South CCAA 1,440 550 2,000 CCAA TOTAL 6,720 12,400 13,000 Source: Table 5-4, Volume 8C, P. 5-13. * One cubic meter equals Thus, Enbridge is proposing a total oil storage capacity of 12,400 m3 ( 77,987 barrels ) for the entire CCAA, or roughly 40,000 barrels less capacity than they are gearing for from a Tier One spill depicted in Table 2 on the previous [age of this report. The question becomes, then- where does Enbridge plan to store the rest of the recovered oil from a Tier One spill, let alone larger spills? As for the proposed capability for the OWA, Enbridge says the following: “Further planning is in progress to determine the response recommendations for the OWA. Response times will be better than Transport Canada standards”.26 A critique of what Enbridge is proposing in terms of response capacity is presented later in this report. 26 Volume 8C, P. 5-3. 12 Detailed Review of the Marine Oil Spill Prevention and Response Elements of the Filing General Comment In conformity with the TOR for this review, the remainder of this part of the report reviews the application volume by volume, line by line, identifying deficiencies of the following types: more Information is required from the proponent in order to assess the analysis and conclusions presented, i.e. information is insufficient; information on certain topics is entirely absent; information is sufficient but where the assumptions, analysis or conclusions can be challenged, with alternative written evidence and expert opinion being presented that contradicts the findings of the application. Then, at the end of the report, in the summary section, a complete list of the information that should be submitted by the proponent in order to fill these deficiency gaps is presented. In terms of the deficiencies themselves, it will be recalled that the Procedural Direction asked for suggestions from the public as to areas where additional information should be supplied by the proponent in its application. One such area is the need for a clear definition of the Project Area, as well as a map clearly delineating that area. The closest one gets to a description of the Project Area is the following statement on P. 1-4 of Volume 8C: “It is assumed that all areas along the Northern and Southern Approaches are at risk of being oiled in the event of a spill. Areas from the border with Alaska to northern Vancouver Island and out to the Territorial Sea of Canada are included in this volume.” On P. 13-5 of Volume 8B, the OWA is defined as follows: “The OWA includes marine waters from the Alaskan border to Brooks Peninsula on Vancouver Island and from the continental shelf landward to the northern fjords. The OWA is based on both ecological and administrative boundaries and is similar to the boundaries of the Pacific North Coast Integrated Management Area ( PNCIMA ).”27 27 The PNCIMA boundaries may be “similar” to the Enbridge’s OWA, but they are not identical. For instance, whereas the OWA claims to extend to the outer edge of the 12 mile territorial sea, the PNCIMA map would seem to indicate a boundary that extends well beyond that. 13 Figure 1: PNCIMA Area Map Source: PNCIMA Web Site: http://www.pncima.org/site/what-is-pncima/the-area.html 14 Requiring the proponent to include a map of the Project Area in the application would graphically depict the 88,000 square kilometre area that could be affected by a marine oil spill incident associated with the marine transportation component of the Northern Gateway project. It could also help to visualise the following items: The area for which the proponent must submit detailed project information in the Environmental and Social Impact Statement ( ESA ); Potential locations for oil spill response depots and equipment; The area within which escort, rescue and harbour tugs may be required, and pilot boarding stations located; Potential sites for JRP hearings, such as northern Vancouver Island communities, stretching as far south as Campbell River. 15 Volume 7C- Risk Assessment and Management of Spills- Kitimat Terminal 3 Probability of Hydrocarbon Spills, Pp. 3-1, 3-2 Probability of Spills associated with Trans-shipment of Operations at the Kitimat Terminal, P. 3-2 In the first paragraph it is stated that” …the risk of a spill resulting from a tanker striking the pier during berthing in ( sic ) negligible.” One deficiency in the application is that there is no mention of the possibility of Bunker C fuel oil spills from a docked tanker. 28 The proponent should take into account the possibility of the vessel’s fuel tanks being ruptured while the vessel is at the terminal. To cite a relatively recent example of such an incident, on August 4, 2006 the general cargo vessel MV Westwood Anette struck a piling at the dock in Squamish, puncturing a fuel tank in the process and releasing a total of 243 barrels of oil into Howe Sound. Information on Bunker C spills is required in order to fully assess the proponent’s conclusion that the risk of an oil spill from this project is low or minimal. As for the table of ‘returns’ presented for various types of terminal spills29, no explanation is provided as to how these figures were arrived at. Are they, for instance, based on a projected fifty year lifespan for the project, and how many tanker visits in total are anticipated over the project’s lifespan? Also, is potential expansion of the pipeline factored in? One has no way of knowing these things. Clarification is necessary. Again, without this basic information, it is not possible to reach the conclusion that the risk of a spill is low or minimal. 5 Incident Prevention and Response, P. 5-1 Enbridge, as owner of the pipeline and marine terminal, would be responsible for spills at both these facilities. As for marine transportation, since Enbridge does not plan to own the tankers, it would not, under the current law, be responsible for tanker spills. Nevertheless, Enbridge makes a corporate commitment here to what it calls “extended responsibility” to cover marine transportation activities. While it does not fully define this concept, an indication as to what it has in mind is provided on P. 5-5 of Volume 8C, under a section entitled “Roles and Responsibilities”, which reads as follows: “Although it is not a regulatory requirement, Northern Gateway is committed to ‘extended responsibility’ for a response on the Northern and Southern Approaches and in the OWA through ownership or direction of the certified RO”. Clarification is required as to what is meant by “…through ownership or direction”. One understands the “ownership” part; however, the “direction” part is unclear. The term ‘responsibility’ on its own has legal implications, being associated as it is with liability as well as with the term “Responsible Party” or RP. Enbridge seems to envisage a more limited role under this concept or principle of extended responsibility. For instance, on Page 5-7 of this same Section 5 there is 28 There is, however, a reference to Bunker C fuel in a table in Vol. 8B, on P. 2-3 29 Table 3-1, Return Period of a Spill from a Tanker at Berth, Volume 7C, P. 3-2. 16 the following statement: “The RP for a release of hydrocarbons from a tanker would be the tanker owner; however, through the response plan…, Northern Gateway will take responsibility that the response, management, and implementation of the response operations meet corporate commitments and objectives.” This seems to fall short of Enbridge committing to paying for cleanup and compensation. On the contrary, Enbridge makes repeated references in the application to the tanker owner being the RP, and as such being responsible for both the response costs and claims.30. Under current law, the only way Enbridge would be legally responsible for tanker spills, and their associated cleanup, restoration and compensation costs, would be for it to own the tankers outright. Enbridge needs to clarify what it means by this term “extended responsibility”, to avoid any confusion. This matter of ‘extended responsibility’ will be revisited later in the report. In this same Section 5 the document also makes reference to various marine oil spill response plans which it proposes to provide at a later stage of the approvals process for the facilities. We shall revisit this issue shortly. 5.6 Equipment and Personnel, P. 5-11 Enbridge makes various claims in this section regarding the emergency response capability planned for the Kitimat terminal. Collectively, it claims that the onsite and offsite recovery capacity will, “…provide a level of response that places ( the Kitimat terminal ) within the top terminal-port operations for oil preparedness worldwide”. Insufficient evidence is presented in the application to substantiate this claim. To fill this gap, the proponent should submit charts and figures which compare what it is proposing to what other terminals, such as the one in Valdez, Prince William Sound in Alaska have on hand, plus the other terminals it profiles on its web site- Mongstad, Norway; Brofjorden, Sweden; and Sullom Voe, United Kingdom. 31 We shall return to this issue later in the report. 5.7.1 Environmental Sensitivity Atlas, P. 5-13 We are informed that a coastal environmental sensitivity atlas has been developed as part of the background studies undertaken in support of the project. This atlas should be part and parcel of the application, so that it can form part of the evidence if and when a Hearing Order is issued in respect of the project. 30 See, for instance, paragraph one on P. 5-16 of Volume 7C, and Section 5.8, “Financial Responsibility for a Spill Response, on P. 5-16 of Volume 8. 31 These terminals are featured in a series of videos, under the banner “Marine safety- seeing is believing”. Url: http://www.northerngateway.ca/newsletter/feb2009/Enbridge-Northern-Gateway-Marine-safety-seeing-is- believing.html 17 5.8 Shoreline Response, P. 5-15 Here there is a brief discussion concerning “remediation endpoints” for shoreline cleanup, and how these will be arrived at. The proponent should be asked how many meters of shoreline it will be in the position to clean up each day. Currently, Response Organisations ( ROs ) are only required to have the capacity to clean up 500 meters of shoreline per day.32 Were a similar standard to be applied to the Northern Gateway project, it would undoubtedly fall far short of public expectations in the event of a major spill event in the Queen Charlotte Basin. 9.1 Introduction, P. 9-1 The proponent mentions that there is the potential for spills at the marine terminal due to extreme natural events, human error, vandalism and equipment failure. ( A similar statement is made for marine transportation generally, on P. 2-1 of Volume 8C ). A brief history of such events around the world would be very helpful. The possibility of terrorist attacks on both the terminal and the tankers should also be considered. There have been at least two reported instances of tankers being the target of terrorist attacks in the past decade- the MV Limburg incident off the coast of Yemen in 2002 and the MV M Star incident in the Strait of Hormuz in July, 2010. The incident involving the Limburg resulted in an undetermined amount of oil entering the marine environment. Another deficiency is that the proponent does not appear to indicate how it intends to prevent and/or respond to large-scale terminal incidents such as the pipeline explosion and resulting oil spill that occurred at a Dalian port in China on July 16, 2010. A spill of this magnitude ( up to 430,000 barrels, according to one expert on the scene ) is not even contemplated in Table 3-1 on Page 3-2 of Volume 7C. 9.3 General Mitigation Measures, P. 9-2 Here it is stated that response equipment will be staged at Kitimat, and that emergency response opportunities have been offered to several First Nations communities, including: Gitgat Lax Kw’alaams Gitxaala Haisla Metlakatla Council of Haida Nation ( including Skidegate, Massett, Kitsaloo and Turning Point ). Details of these proposals are absent in the application. More information should be provided, including the types and amounts of equipment intended for each depot. It also bears mentioning that some equipment is already located in the region, owned by either Burrard Clean ( BCO ) or CCG. CCG should 32Response Organizations Standards ( 1995 )- TP 12401E, Section 4. 18 be asked whether it intends to expand its spill response capacity in the region in the event the project proceeds. 9.4 Selection of Examples Pp. 9-2 through 9-15 Examples of possible spills are presented in this section in connection with the marine terminal at Kitimat. Other examples dealing with potential spills from tankers operating within both the CCAA and OWA are presented in Volume 8C of the application. Issues related to both types of examples are dealt with later on in this report, where Volume 8C is reviewed. Appendices A, B, C and D Tables of contents for various contingency plans are provided in Appendices B through D of Volume 7C. Enbridge is proposing to develop various contingency plans at a later stage of the approvals and development process. This falls short of what is required of it. The Scope of the Factors document requires a “preliminary emergency measures plan and environmental protection plan”, as well as a “sample oil pollution emergency plan that would be carried onboard each tanker”.33 Furthermore, on P. 8 of the Procedural Direction, the JRP is asking for public input as to whether “… the proposed plans and measures for emergency preparedness and response ( are ) appropriate?” Thus, both the JRP’s TOR and the Scope of the Factors document require more than tables of contents for such plans. Enbridge needs to supply much more detailed information than tables of contents to meet these requirements; it needs to supply the plans themselves. 33 Section 7.5, Scope of the Factors document, August 2009, pp. 13, 14. 19 Volume 8A: Overview and General Information- Marine Transportation 1.1 Overview of Tanker Operations and Environmental Protection, P. 1-1, 1-2 In paragraph one Enbridge says it is “…committed to ensuring that tankers transporting condensate to, and oil from, the marine terminal will be operated as models of world-class safety standards and in an environmentally responsible manner.” There are several points to be made regarding this statement. First, as previously stated, and as Enbridge itself states, the company does not plan to either own or operate the tankers. As such, it will not be directly responsible for the marine transportation component of the project; nor can it be held responsible should an accident occur, since it is not the Responsible Party. On the other hand, as mentioned above, it has said that it will adopt a policy of “extended responsibility” vis a vis the project’s marine transportation component through what it terms “ownership or direction of the certified RO”34. So, the question becomes: how does Enbridge intend to honour and implement this commitment, or, put another way, ensure that the tankers and tanker owners respect this pledge? Will this commitment be reflected in some sort of legal document between Enbridge and the tanker owner that would bind the latter in some way? And finally, does Enbridge’s pledge really carry any legal weight, or is it just a statement of corporate policy? In short, the choice of the wording of “extended responsibility” is confusing, and needs to be clarified by the proponent. Elsewhere in this section, Enbridge entertains that the safe passage of marine traffic, which it deems “essential”, will be achieved by taking several steps, including, inter alia, using double-hulled tankers and requiring experienced British Columbia coastal pilots during key parts of the voyage. Purpose-built tugs will also escort the tankers, and safe transit speeds will be imposed. Among the many other safety features promise “Operational safety limits will be established to cover visibility, wind and sea conditions”. These operational safety standards should be included in the application. 4.1.3.2 Double Hulls, P. 4-4 The proponent makes repeated references throughout the application to the fact that it will use only double hull ( DH ) tankers. The first thing to be said about this commitment is that as of 2010 double hulls are a requirement for the international tanker trade, which Enbridge’s Northern Gateway project will be a part of. Thus, assuming the Gateway project were to commence by the fourth quarter of 2015, say, there will be no choice but to employ DH tankers. There has been a spate of serious oil spill incidents involving double hull tankers over the years, as the accompanying table created by the Consultant from publically available information indicates: 34 Volume 8C, P. 5-5. 20 Table 4: Notable Marine Oil Spills Involving Double Hulled Tankers, OBOs and/or Tank Barges35 Motor Vessel Year Location Cause/Nature of Amount/Type Incident of Oil Spilled Bunga Kalena 3 25 May, 2010 Strait of Collision 18,325 barrels Malacca Eagle Otome 23 January, Sabine/Neches Collision with 10,714 barrels 2010 shipping barge est. channel, Texas, USA Volgoneft 139 11 November Black Sea Structural Failure 1300 tonnes 2007 During Storm HFO DBL 152 November 11, Gulf of Mexico Collision with 45,846 barrels ( Barge ) 2005 submerged Bunker fuel remains of pipeline service platform Limburg 6 October, Yemen Suspected ? 2002 Terrorist Attack Aegean Sea December 3, A Coruna, Spain Ran 584,601 ( OBO ) 1992 Aground/Broke in barrels Two Baltic Carrier March 29, Baltic Sea 2700 tonnes 2001 HFO Source: Worldocean Consulting Ltd, 2010 What the table above demonstrates is that using only DH tankers does not guarantee that a spill will not occur. In fact, because double hull tankers tend to require more frequent inspection and maintenance than single hull tankers, and because they are harder and more expensive to maintain, they present their own set of challenges. As this quote from the UNEP marine oil spill web site indicates: “MAINTENANCE & SHIP OWNER RESPONSIBILITY Ship owners must ensure a high standard of maintenance. No matter how well a ship is designed, built and equipped — unless it is properly maintained, it will sooner or later become a maritime safety risk. The responsibility for regular and good maintenance always rests with the ship owner. It is also worth remembering that also double-hulls have their own inherent problems. Many predict that in a few years’ time there will be massive oil spills from double-hull tankers as the maintenance of a double-hull is more 35 As mentioned later in this report, another incident involving a DH tanker occurred on October 20, 2009 near Galveston, Texas, when a supply vessel collided with the tanker MV Krymsk. This incident is not included in this chart because the spilled involved bunker fuel from the tanker’s fuel tanks, which were not protected by DHs. Some of the incidents listed in Table 4 did involve spillage of fuel oil, the difference being that each those spills involved puncturing of the vessel’s cargo tanks, which are supposed to be protected by DHs. 21 difficult than a single-hull, and there is also a problem with gas build up between the two hulls. This will make regular inspections of the vessels even more important.” Enbridge should be asked to provide detailed case histories of these and other DH tanker spills, and explain how the DH tankers it plans to use will escape a similar fate. 4.1.3.4 Machinery, P. 4-6 Paragraph one states that most tankers are powered by one diesel engine, although some may have two engines; ensuing paragraphs in this section refer to the redundancy features of modern tankers. The application also notes that currently tankers are required to have redundant steering systems to prevent accidents in the event that the primary system fails36. In this connection, the proponent does undertake to ensure that the tankers used on the Northern Gateway project feature redundancy in the essential components of the steering system.37 A quote from The Maritime Directory’s Knowledgebase Resources web site, under the heading “Crude oil tankers”, is instructive in this regard. It states: “Some of the latest tanker newbuildings, incorporate other extensive safety features from double hulls, double engine rooms, propulsion and steering equipment.” It is noted in passing that this particular web site is sponsored by Det Norske Veritas ( DNV ), the company which is undertaking the QRA for the marine transportation component of the Enbridge Northern Gateway project. The question for the proponent becomes: “Will Enbridge require that the tankers used to transport oil from the Kitimat terminal are equipped with double engine rooms, double screws and double rudders and, if not, why not?” Failure to obtain such a commitment would provide grounds to challenge Enbridge’s stated commitment to adopting world class safety standards for the tankers that will eventually be used in connection with the project. 4.1.6 Terminal Regulations for Vessel Acceptance, P. 4-13 Enbridge ‘pledges’ that: “Tankers must be less than 20 years old with respect to the original construction completion date.” Looking at the statistics for the world tanker fleet, as of January 2009, only 12% of the world’s Aframax tanker fleet was older than 20 years, vs. 10% of the Suezmax fleet and 5% of the VLCC fleet. 38 In other words, Enbridge’s pledge not to use tankers older than 20 years will only exclude approximately ten percent of the world tanker fleet from the pool of vessels that could be used to transport Northern Gateway oil by sea. Once again, Enbridge’s plan to use relatively old tankers calls into question its commitment to what it calls ‘world class standards’ for its project. Enbridge’s plan to use tankers that could be that old could be challenged on the following grounds: there appears to be a correlation between a tanker’s age and its propensity to be involved in a significant oil spill. For one thing, tankers older than ten years tend to have a significantly higher Non- 36 Volume 8A, P. 4-6. 37 Ibid., P. 4-78. 38 Source: Intertanko Tanker Facts 2009, Chart, labeled “Tanker and combined fleet details as at January 2009 ( above 10,000 dwt ), P. 3. 22 Accidental Structural Failure ( NASF ) frequency rate than younger tankers.39 In fact, statistics reveal that about 78% of all NASF accidents involve ships older than ten years, with the 11-15 year age group accounting for the largest percentage of NASF accidents ( 33% )40. Furthermore, since the average age of the DH fleet is currently about seven years, it can be expected that typical age-dependent accidents ( mainly NASFs ) will start to become a significant occurrence after about 2020, i.e. roughly four years after Enbridge’s Northern Gateway project is scheduled to come on stream.41 In light of these somewhat alarming statistics and projections, the proponent should be asked to justify its reliance on tankers that could be as old as two decades, and to explain how it’s vetting process for tankers- what it refers to as the Tanker Acceptance Program, will guarantee that the ‘bad ones’ will be weeded out. 4.2.4, Geographic and Geological Factors, P. 4-19 Under “Climatic and Oceanographic Factors”, one paragraph is devoted to the extremes of weather and sea states that could affect navigation in the project area, and what the proponent proposes to do to mitigate these conditions. Given the notorious weather that afflicts the region, and the obvious public concerns about the effect of these conditions on tankers transiting the area, far more detail is required on these points. If this kind of data is contained in various TERMPOL reports ( T 3.5, for instance ), then it should be brought forward to this volume ( 8A ) of the NEB/CEAA application. 4.2.10.2 Escort Tug Services, P. 4-28 Enbridge commits itself to the use of escort tugs for all laden tankers within the CCAA. The importance of escort tugs was demonstrated on January 17, 2010 when the MV Sea River Kodiak tanker lost power at the entrance to Prince William Sound in Alaska, and had to be rescued by an escort tug, thereby narrowly averting disaster. Unfortunately, tugs themselves are prone to breakdown and accidents. As evidence of this, there has been a spate of incidents involving tugs of late, within British Columbia, Washington State and Alaska. For instance: On March 19, 2007 the American tugboat Sea Voyager ran aground near Bella Bella, British Columbia; On December 23, 2009 the tug Pathfinder ran aground on Bligh Reef in Prince William Sound, the very spot where the Exxon Valdez had run aground twenty years earlier On July 28, 2010 the tug-barge Commitment lost power in Juan de Fuca Strait, on the American side of the border. 39 Ibid., P. 10. 40 Papanikolaou, A., Eliopoulou, E., Hamann, R., Loer, K., Assessment of Safety of Crude Oil Transport by Tankers, Proc. Annual Main Conference of Schiffbautechnische Gesellschaft (STG2009), Berlin, November, 2009, P. 6. 41 Ibid. 23 Thus, while tugs can reduce the risk of a tanker running aground or drifting ashore, they cannot completely eliminate that risk, especially if the tugs themselves are prone to breakdown. The question for the proponent becomes: How can one be certain that the tugboats Enbridge plans to use will not escape a similar fate?42 In this same section of the application Enbridge also makes the commitment to have local pilots aboard all incoming and outgoing tankers ( Page 4-28 ), principally within the CCAA43. British Columbia coastal pilots have a stellar safety record; in recent years over 99% of voyages in which there was a pilot on board were completed without incident44. Nevertheless, the occasional incident does occur. In the case of the previously-mentioned MV Westwood Anette incident in Squamish in 2007, for instance, where oil spilled into Howe Sound, a pilot was apparently on board at the time of the incident. Also, in the case of the MV Petersfield incident in Douglas Channel on September 25, 2009, a pilot was on board the vessel45. Further afield, a pilot was aboard the MV Cosco Busan when it rammed a bridge in San Francisco harbour in 2007, spilling 1275 barrels of Heavy Fuel Oil into the Bay in the process; in that particular case, the pilot ended up serving time in prison. What these isolated incidents demonstrate is that while pilots undoubtedly lower the overall risk of a casualty, they cannot entirely eliminate it; mechanical failure and/or human error can still occur. Another example of human error on the bridge, though this one involving neither pilots nor tugs but instead BC Ferries crew with supposedly extensive knowledge of local waters, was the MV Queen of the North incident which occurred on the night of March 22, 2006, when the vessel in question ran aground on Gil Island and subsequently sank in Wright Sound, with the loss of two lives and the spilling of an undetermined amount of diesel fuel into the marine environment. The Pacific Pilotage Authority, which governs pilotage on the west coast, should be asked whether requiring coastal pilots on board tankers during the course of their entire journey through the Project Area, i.e. both the CCAA and OWA, rather than just through the CCAA, would appreciably lower the risk of an oil spill occurring in the OWA. 4.8.1.2 Marine Shipping Network Analysis and Marine Terminal Incident Analysis, PP. 4-78 – 4-83 In Bullet One of the “Outcomes from the QRA” section on P. 4-82 of Volume 8A, it is stated that weather and sea conditions in the project area are no worse or more unpredictable than other parts of the globe where there are tankers. Examples given are Norway, the UK and the North Sea. 42 Yet another tug-barge incident in recent years occurred on August 20, 2007 when a barge owned by Ted Leroy Trucking Ltd tipped its load, which included a loaded fuel truck, into an ecological reserve at Robson Bight in Johnstone Strait. In this case a court of law exonerated the tug owner of any responsibility for the incident. Nevertheless, the incident highlights the inherent risk posed by any and all commercial vessel traffic in BC waters, and the need to be extremely vigilant at all times. 43 The precise location of the pilot boarding station for the Southern Approach is apparently under discussion with the Pacific Pilotage Authority. Existing stations at Pine Island and Cape Beale are, according to Enbridge, not suitable because of their distance from the Northern and Southern Approaches. Alternative locations under consideration include a site approximately twelve nautical miles seaward of Caamaño Sound, and another location north of Browning Entrance. Volume 8B, P. 2-5. 44 2009 Annual Report, Pacific Pilotage Authority, Exhibit 7, P. 12. 45 This is in no way to suggest that the pilot was responsible for the incident in question. 24 Insufficient data is provided in the application to support this very broad conclusion. Statistics should therefore be presented in a comparative table so that the reader can compare the examples given and draw his or her own conclusions. Conditions at the tanker terminal at Valdez in Prince William Sound, Alaska and the Whiffen Head Transshipment Terminal in Newfoundland should also be included for comparative purposes. As for Bullet Two on the same page ( 4-82 ), there is a similar lack of hard evidence presented to support the conclusion that there is a higher risk of an incident within the CCAA than the OWA. While it is true that navigation may be trickier within the CCAA than within the OWA, because there are more turns and maneuvers required, and because the channel is narrower, an argument can be made that within the OWA tankers would be more exposed to the elements, and thus more prone to structural failure. And in addition to sea and weather conditions tending to be worse on the open water than in a confined channel such as Douglas Channel, once tankers are outside the CCCA they will, for the most part, not benefit from tanker escort. Enbridge argues that the provision of tethered escort tugs within the CCAA considerably lowers the risk of an oil spill incident occurring in that area. The question then becomes: how much would the risk be lowered in the OWA if tanker tug escorts were required there as well? On Page 4-83 of Volume 8A the following statement is made: “The conclusion of the QRA is that the risk of an oil spill occurring during marine transit or at the terminal can be mitigated to a level comparable with other top tier international tanker and terminal operations where operating practices include tethered and close escort operations during loaded tanker transit and closed loading systems at the marine terminal.” This statement to the effect that the QRA has reached a conclusion on this matter would seem to be premature, given the fact that the proponent repeatedly advises that said QRA is not yet complete. Furthermore, the public is not privy to the QRA itself- only a summary of it, in the form of Volume 8C of the application. All the more reason, then, for the full, final QRA to be included in the application. 25 Volume 8B: Environmental and Socio-Economic Assessment ( ESA )- Marine Transportation 2.3 Oil and Condensate Tanker Specifications and Traffic, Pp. 2-2, Page 2--3 Table 2-2 on Page 2-3 indicates the average number of vessels per year expected to visit Kitimat, for each class of tanker. As mentioned previously, the proponent should also indicate how long the project is expected to last. Knowing the project’s lifespan is crucial in calculating risk. Thus, what lifespan is Enbridge anticipating for the project- is it twenty years, or fifty, or something in between? It is important to know. It should also be made clear whether the expected vessel figures take into account the possible expansion of the pipeline from 525,000 barrels per day to 800,000, as has been reported in the press. Presumably, greater pipeline capacity would mean greater numbers of tankers as well, thereby increasing the environmental risk. Information presented in part of Table 2-2 also indicates that all three classes of tanker Enbridge proposes to use to transport oil and condensate- VLCC, Suezmax and Aframax, will be fueled by No. 6 Bunker C. With somewhere between 190 and 250 tankers per year visiting Kitimat ( 220 on average ), there is, as mentioned before, a risk of an oil spill involving the Bunker C from these ships. Moreover, whereas the condensate tankers are only laden with cargo on their incoming trips, and the oil tankers are only laden with cargo on their outgoing trips, all the tankers carry Bunker C on both incoming and outgoing trips, which means that 220 tankers on average translates into 440 transits of the Project Area where there is a ( as yet undetermined ) risk of a Bunker C-type incident. In terms of assessing the severity of that risk, it is noted that as of 2002, of the 450 spills attended by the International Tanker Owners’ Pollution Federation Limited (ITOPF) over the course of the previous quarter century, about 40 per cent of these spills had involved either medium or heavy grades of fuel oil, whether carried as cargo or used by larger vessels as bunker fuel46. As an example of this type of casualty, on December 8, 2004 the freighter MV Selendang Ayu ran aground and broke in half off the Aleutian Islands in Alaska, accidentally spilling 7670 barrels of Intermediate Fuel Oil ( IFO ) into the ocean in the process. A more recent incident, this one involving a DH tanker, no less, occurred 40 miles southeast of Galveston, Texas on October 20, 2009, when a collision between a supply vessel and the tanker MV Krymsk punctured the latter’s fuel tanks, resulting in the spillage of 18,000 gallons of bunker fuel into the Gulf of Mexico.47 Given the frequency of this type of incident, the proponent should be required to calculate the risk of a Bunker C spill occurring over the lifespan of the Northern Gateway project, however long that may be. 46 “Oil spill experts address high-quality density oil spills”, IMO web site: http://www.imo.org/Environment/mainframe.asp?topic_id=345 47 This incident was brought to the author’s attention through the written comment form submitted to the JRP of Dave Shannon, P. 2. 26 Thus, it is not only the tanker’s cargo of crude oil ( or bitumen in this case ) that poses a threat to the environment, but the fuel that runs the vessels as well; and so, both should be factored into any risk calculations for projected tanker traffic. As far as can be determined, the QRA does not currently take these types of spills into account. The proponent should also be asked to indicate whether a bunkering facility is planned or will be required within the Project Area, so as to refuel the Northern Gateway tankers. Section 2: Description of Marine Transportation Activities, Pp. 2-2 – 2-9. As mentioned above, the proponent needs to clear up the confusion as to which route ( northern or southern ) condensate tankers will take. Also, what determines which of the two Southern Approach routes is taken by a tanker? Is it weather, for instance, or marine mammal migratory patterns, perhaps? And if a seasonal element is at play here, during which season would the northern version of the Southern Approach be used, and during which season the southern version of the Southern Approach? Several references are made in this section to the proposed use of escort and harbor tugs within the CCAA. The proponent should indicate response times for rescue tugs within the OWA. For instance, if a tanker were to lose power at the outer edges of the OWA, how much time would there be for a rescue tug to arrive before the stricken tanker drifted onto the predominantly rocky coastline, potentially discharging hundreds of thousands, if not millions of barrels of oil from its cargo tanks? Would a rescue tug be able to get there in time to prevent a potential catastrophe? And if escort tugs were required in the OWA ( as opposed to just the CCAA ), would this lower the risk of an incident occurring, and if so by how much? There is no mention of salvage tugs in the application. The question for the proponent is: If one were ever needed, where would it come from, since there are none stationed anywhere along the British Columbia coast? Would one come from Alaska or Oregon, perhaps, and if so, how long would it take to arrive on scene in the event of an emergency? 3.1.2 Prevailing Climate Conditions, P. 3-2 This section summarises prevailing climate conditions. The CCCA is mentioned five times, but the OWA is not mentioned once. What are the prevailing conditions for the OWA? 3.1.4 Winds, p. 3-3 In paragraph four, it is mentioned that winds in the region can occasionally reach up to 185 km/h. The application should relate the occurrence of these hurricane-force conditions to the safe navigation of tankers. How do these conditions relate to operational standards for the tankers? Marine scientists from Fisheries and Oceans Canada should also be asked about these sea conditions. 3.1.6 Waves, P. 3-4 Paragraph one mentions that waves of 6 to 8 meters can occur several times each winter within the project area, particularly in Hecate Strait and the Queen Charlotte Basin. These are by no means the 27 maximum winds that can be expected in Hecate Strait, Dixon Entrance or Queen Charlotte Sound. For instance, this is what a book on weather on the British Columbia coast has to say about conditions on the open waters of the North Coast: “The highest recorded extreme waves are over 30m ( 100 feet ) recorded at both the South Hecate buoy and the East Delwood buoy. A 30 metre wave was also recorded by the drilling rig Sedco 135F working in Queen Charlotte Sound, south of Cape St. James, on 22 October 1968. While these waves are huge, the more dangerous aspect is the rate that they can build from almost nothing to frightening heights. In the 1968 case the seas rose from three metres to 18 metres in just eight hours.”48 Under such conditions, how safe will a tanker be, tug escort or no tug escort? Would Enbridge shut down tanker operations during a storm of this force? Would there be enough warning to do so? Would CCG require them to shut down? These are all questions that need to be answered in the operational standards for tankers. Marine scientists from Fisheries and Oceans Canada should also be asked about these sea conditions. 4.2.3.2 Project Inclusion List, Pp. 4-13 - 4-15 The project inclusion list included in Table 4-2 ( Pp. 4-14, 4-15 ) should include CN’s plan to ship Alberta and Saskatchewan oil to west coast ports, called PipelineonRail. CN claims to have the rail infrastructure in place to transport 200,000 barrels of oil per day or more in its double-hulled rail cars. CN is currently transporting condensate by rail to Alberta from Kitimat. Thus, the question is: how many more tankers would CN’s proposal require, and which route(s) would they take? 13.5.3 Climate and Oceanographic Factors, P. 3-15 Extreme weather conditions and their potential effect on navigation are noted in this section. To mitigate the impacts off these conditions, operational safety limits “… to cover visibility, wind and sea conditions” are promised. Consider this real life example of the impact weather can have on a large vessel in the OWA. In the early hours of November 23, 2009 BC Ferries’ MV Northern Adventure was buffeted by a severe storm in the middle of Hecate Strait. Waves up to 10 meters in height were reported. The vessel’s captain attempted to ride out the storm for four hours, but eventually gave up and returned to Prince Rupert. Ninety kilometer winds had apparently been forecast for the area, with the ferry crew aware of the storm before the vessel left Prince Rupert en route for Skidegate. However, a BC Ferries spokesperson is quoted as saying that the storm “…did come in faster than what was predicted, and worse than what was predicted.” In terms of the safety and operational standards we are told are under development, what would the captain of a fully-laden tanker do in a situation similar to the one mentioned above? Would he or she allow the vessel to leave port if a similar weather forecast had been issued? Would the vessel venture out into Hecate Strait under such conditions? If it were buffeted by ten meter waves and winds in excess 48 Owen S. Lange, The Veil of Chaos, Living with Weather Along the British Columbia Coast, Environment Canada, 2003, P. 160. 28 of 90 kilometers an hour in the middle of the Strait, what would it do?; would it try to maintain its course, ride out the storm, continue on its course through the Strait, seek shelter or a safe harbour, or attempt to return to port? And a propos the matter of safe harbours, where would one of the Northern Gateway tankers go if it had to seek refuge? There is little reference in the application to places of refuge for stricken tankers, other than their inclusion as a heading in the outline of the General Oil Spill Response Plan ( GOSRP ) presented in Vol. 7C, as section B.24- “Places of Refuge”, and a reference to the possible need to ride out, heave to, anchor or drift in “…selected areas” in Volume 8A.49 This subject matter needs to be fleshed out by the proponent. Where would a tanker go if it broke down en route, or encountered a hurricane, for example? How many safe harbours are there along this rugged coastline? The proponent should supply a list of safe harbours along the project route for stricken tankers. 14.2 Effects of Severe Weather on Marine Transportation, Page 14-1 In this section the potential impacts of extreme weather events on tanker traffic are once again acknowledged, and the promise is again made of “special measures” to mitigate such risks. However, once again the discussion is limited to the CCCA, with no specific mention of the OWA. As an example of this gap, it is stated that tankers operating within the CCCA can safely operate in wind speeds of 50 knots, with, for instance, the support of tugs. What about the OWA, where, as mentioned above, by the proponent’s own admission wind speeds can occasionally reach 185 kms/hr? 49 P. 4-19. 29 Volume 8C: Risk Assessment and Management of Spills- Marine Transportation General As mentioned above, the Quantitative Risk Assessment ( QRA ), which is summarised in this volume, is incomplete. The final version should be included as part of the application. 2 Operational Measures to Prevent Tanker-based Hydrocarbon Spills, P. 2-1 Paragraph two lists potential causes of tanker incidents. As mentioned previously, terrorism should be included in the list, because of two known or suspected incidents of this nature involving tankers on the high seas. 3 Probability of Hydrocarbon Spills, Pp. 3-1 -3-4 Throughout the report, Enbridge characterises the risks of a marine oil spill occurring as ‘minimal’ or ‘extremely low”. Enbridge’s concept of risk appears to be almost entirely related to the statistical probability of an event occurring. Such a restricted view of risk fails to recognize the other side of the risk coin, i.e. the consequences of an unwanted event, in this case an oil spill. By this is meant that a widely-accepted concept of risk, as applied to oil spills, takes into account not only the probability of a spill occurring, but also the consequences if it does occur. Simply put, risk is defined as the probability of a spill occurring, multiplied by the consequences. Employing this risk paradigm, one could envisage an instance in which the perceived threat of a spill was considered high, even though the event had a small chance of occurring, because if it did occur the consequences could be catastrophic and irreversible. Enbridge should take into account this broader notion of risk, and come up with some scenarios in which it is incorporated. An example would be the total loss through Non-Accidental Structural Failure ( NASF ) of a stricken VLCC in the middle of the OWA. As mentioned earlier in this report, in Section 7.5 of the Scope of the Factors document, entitled “Potential Accidents and Malfunctions”, as well as in Section 7.6, entitled “Effects of the Environment on the Project”, repeated references are made to the need for information from the proponent as to the risks presented by severe and/or extreme weather conditions or events. On P. 3-1 of Volume 8C, the proponent says that : “Weather and sea conditions * on the North Coast + are comparable to or better than other areas around the world that have large amounts of oil tanker traffic”. On Page 3-2 of Volume 8 the role of “environmental forces” in influencing the probability of spills is recognized. Elsewhere ( P. 9-8 of Volume 7C ) the effect of meteorological conditions on the fate of oil on the water is recognized. Finally, operational standards for tankers that take into account weather, sea state, etc. are promised. However, as stated earlier, there is a paucity of hard data in the application on the actual weather and sea conditions, both here and abroad, to substantiate the claim that conditions within the project area are no worse than elsewhere. This information gap needs to be filled. 30 In addition, what is invariably overlooked in the application is the obvious point that weather will also tend to impede cleanup operations. The proponent should acknowledge these considerable operational challenges which go hand in hand with operating in such an extreme and often hostile environment as the Queen Charlotte Basin. The proponent should state, for instance, what percentage of the time a credible response operation would not be possible for various times of the year, given typical conditions at sea and the ineffectiveness of boom, skimmers and other types of spill response equipment during suboptimal operating conditions. Data presented in the QRA, which is summarized in Volume 8C of the application, presents return periods for spills within the project area. They are incomplete, as outlined below. At least one contradiction has to be resolved as well. The apparent contradiction shall be dealt with first. As mentioned in a previous section of this report, Footnote 1 in Table 3-1, Return Period of a Spill Associated with the Tanker Traffic for the Northern Gateway Project indicates that condensate tankers will not use the Northern Approach, i.e. via Dixon Entrance and Browning Entrance. The exact opposite to this is stated on P. 2-3 of Volume 8B. 50 This discrepancy has to be cleared up by the applicant. Other than that, there are several problems related to the QRA data and conclusions. As an example of the statistics presented, the return period for an oil spill of any size within Douglas Channel is estimated at 1500 years, but roughly ten times that for spills within Queen Charlotte Sound, Hecate Strait and Dixon Entrance51. The return period for a bitumen spill of any size, anywhere, is estimated at 350 years52. The predicted return periods for small, medium and large spills ( presented at the bottom of Page 4-82, and also in the second last paragraph on Page 3-2 of Volume 8C ), are 550, 2,800 and 15,000 years respectively. The first question that comes to mind with respect to these return estimates is: how were they calculated? We are told that a “per voyage” methodology was chosen over a “per volume of oil transported” methodology53, and that one of the advantages of the “per voyage” methodology is that it takes into account ship size. If ship size was indeed taken into account, then the risks of transporting oil in the various size tankers should be presented- but they are not. It would be instructive to know, for instance, what the risk is of using, say, one VLCC tanker to transport oil vs., say, two Suezmax tankers to transport the same amount of oil overall. In other words, is it less risky from an environmental perspective to have one large tanker instead of two smaller ones, or is there no appreciable difference between the two options from a risk perspective? As mentioned previously, basic data is also lacking with respect to the project, such as its projected lifespan- is it fifty years, or twenty years perhaps? Also, how many vessel voyages per year were used for 50 Table 3-1, Return Period of a Spill Associated with the Tanker traffic for the Northern Gateway Project, Volume 8C, P. 3-4. 51 Ibid. 52 This figure is repeated on Page 3-2 of Volume 8C, and also included in Table 3-1 of the same document, on Page 3-4. 53 See Volume 8A, P. 4-79. 31 the purposes of the return calculation- 220, which represents the average number expected, or 250, which reflects the maximum? Moreover, was the potential expansion of the oil pipeline capacity to 800,000 barrels per day of oil from the current plan for capacity of 525,000 barrels factored into the calculation? In addition, as mentioned above, what about tanker spills involving No. 6 Bunker C fuel oil which we are told the tankers will run on?; is a spill involving this type of oil factored into the risk assessment calculations? In short, there are a lot of unknown variables involved in these return calculations. More information is needed before one can begin to assess their accuracy. The spill risk statistics provided show the chances of a spill occurring in Hecate Strait being infinitesimally small. The application links the risk of a spill to many things, including “exposure to environmental forces” ( Volume 8C, P. 3-2 ), but the main consideration affecting risk is considered to be “navigational difficulty” ( Ibid. ). According to Enbridge, the risk is lower in straight sections than in sections ( such as Douglas Channel ) that require “ greater navigational input”. As mentioned previously, such a conclusion could be challenged, on the grounds that the risk of a catastrophic oil spill is arguably greater in the OWA than within the CCAA. As indicated below, NASF incidents account for a significant percentage of tanker incidents, as well as tanker incidents involving oil spills. In other words, tankers founder not just because they hit a rock, break apart and then sink; they can simply break in two after being buffeted by storms on the high seas, i.e. in ‘open water’. And while the CCAA may present greater navigational challenges than the OWA, the conditions ( winds and waves ) in the OWA tend to be worse than in most parts of the CCAA, the OWA is more exposed, and because of its remoteness it would take no doubt longer to mount a rescue and response operation there. Moreover, a potentially larger length of coastline could be affected by a spill that happened in the OWA than one in that occurred in the CCAA. The latest International Tanker Owners Pollution Federation ( ITOPF ) statistics indicate that structural failure, with the tanker breaking in two, occurs not infrequently. For the period from 1970 to 2009, for spills greater than 700 tonnes, groundings accounted for 36.3% of all spills; collisions accounted for 29.1%); and hull failure accounted for 12.4%.54 Another study paints a similar picture of hull failure being a significant cause of tanker incidents and spills. According to this particular statistical analysis, between 1990 and 2008 a total of 858 incidents involving large tankers, i.e. tankers greater than 60,000 tonnes ( which means Panamax, Aframax, Suezmax and VLCC class tankers ), were investigated. These accident involved either serious or non- serious consequences. As the following table from the paper in question demonstrates, fully 151 of these incidents, or 18%, involved NASF: 54 From Figure 9: Incidence of Spills > 700 Tonnes By Cause, From 1970 to 2009, ITOPF, Oil Tanker Statistics: 2009, P. 8 32 Table 5: Casualty data, covered period 1990-2008 ( without accidents in Shipyards & Dry Docks ) Category No of accidents % Collisions 288 34 Contact 97 11 Grounding 205 24 Fire 78 9 Explosion 39 5 Non-Accidental Structural Failure 151 18 (NASF) Total 858 100% Source: Papanikolaou, A., Eliopoulou, E., Hamann, R., Loer, K., Assessment of Safety of Crude Oil Transport by Tankers, Proc. Annual Main Conference of Schiffbautechnische Gesellschaft (STG2009), Berlin, November, 2009, Table 1, P. 4. Over that same nineteen year period ( from 1990 to 2008 ) a total of 102 incidents ( serious and non- serious ) were reported that involved an oil spill from a large tanker. Thus, 11.888% of the large tanker incidents over that period involved an oil spill. Significantly, as the following table demonstrates, more than one third of those spills were the result of NASFs. Table 6: Causes of accidents ( for both single and double hull tankers ) Cause # % Collision 28 27 Contact 15 15 Grounding 17 17 Fire 1 1 Explosion 3 3 Non-Accidental Structural Failure 38 37 (NASF) Source: Derived from figures in Papanikolaou, A., Eliopoulou, E., Hamann, R., Loer, K., Assessment of Safety of Crude Oil Transport by Tankers, Proc. Annual Main Conference of Schiffbautechnische Gesellschaft (STG2009), Berlin, November, 2009, Table 2, P. 6. Furthermore, the average frequency of NASF ( serious and non-serious ) incidents is about eleven per year for the current world tanker fleet ( P. 6 ). One relatively recent example of a tanker casualty involving structural failure was the December 12, 1999 MV Erika incident off the coast of Brittany when the 24 year-old Maltese-registered vessel broke in two and sank, spilling 20,000 tonnes of Heavy Fuel Oil into the North Atlantic in the process. An even more recent example involved the MV Prestige, a Bahamian-registered tanker which broke in two and sank off the Spanish coast on November 19, 2002, spilling an estimated 63,000 tonnes of oil into the ocean off the coast of Galicia in the process. 33 Thus, the Northern Gateway project application should specifically address the risk of NASF spills occurring in the OWA, rather than concentrating mainly on groundings, collisions and other incidents related to navigational difficulty within the CCAA. The need for this kind of analysis is particularly needed given Enbridge’s statement that tankers that are up to twenty years old could be used on this project. For, as is stated elsewhere in the report, older tankers have a higher chance of being involved in NASF incidents than younger ones. 5.2 Response Approaches and Capabilities, pp. 5-3 – 5-7 Table 5-1, “Typical Sequence of Initial Response Actions”, mentions Tier 1 through 3 response level actions. The various levels should be defined. Action for Tier 4 level and beyond should also be included. 5.5 Equipment and Personnel, Pp. 5-10 -5-13 As mentioned in a previous section of this report ( Marine Oil Spill Prevention and Response Elements of the Proposal ), Enbridge should first of all do what the Consultant does in Table 2 and spell out in the application the actual figures it is proposing, comparing them in the process to what CCG currently requires for ROs. It is not sufficient to say, for instance, as Enbridge does on P. 5-11 of Volume 8C, that capacity in place will be more than 100 times what CCG requires within the 6 hour timeframe required for a PAR ( Primary Area of Response ). Data is lacking here with respect to the proposed response capability for the OWA. For instance, on P. 5- 11 Northern Gateway mentions placing response equipment at four caches located throughout the CCAA. In Volume C ( P. 9-2 ) it had mentioned the possibility of response depots in various other locations outside the CCAA, i.e. within the OWA, including a number of possible locations on Haida Gwaii. Has it now abandoned such plans, and if not, why does it not mention them here? In Table 5-3 on P. 5-12, the term “big local boats” should be defined. On Page 5-12 the claim is made that “Collectively, the recovery capacity envisioned for the ROs will provide a level of response that places it within the top terminal-port operations for oil preparedness worldwide.” Presumably the proponent had in mind the following terminals, for which it has produced safety videos available from its web site: 1. Brofjorden, Sweden 2. Mongstad, Norway 3. Sullom Voe, United Kingdom Noticeably absent from the videos are: the Valdez marine terminal in Prince William Sound, USA, site of the Exxon Valdez tanker spill in 1989, and now subjected to one the most stringent oil spill prevention and response regimes in the world; and the Newfoundland Transshipment Terminal located at Whiffen Head in Newfoundland, which includes a containment reservoir with a capacity of one million barrels for use in the event of a leak from one or more of the tanks in the tank farm. 34 When one looks at the specifics as to what Enbridge is proposing, on Page 5-11 it is claimed that there will be “…more than two times the CCG recovery capacity for a Tier 4- 10,000 t situation, available in a maximum of 24 hours depending on distance from local response sites (Transport Canada guidelines indicate within 72 hours)”. In Prince William Sound the response capability requirement is for a 300,000 barrel spill within 72 hours, which is almost double the 158,000 barrel capacity Enbridge is promising. It will also be recalled that the MV Exxon Valdez spilled 41,000 m3 of oil, or the equivalent of 257,862 barrels of oil. Thus, not only is Enbridge’s claim to offer a level of response capability that places it within the top tier of terminal-port operations worldwide challengeable- the level of response capability it is proposing for the CCCA would fall approximately 100,000 barrels short of the capacity that would be required to clean up a spill of the magnitude of the MV Exxon Valdez, which, one might add, ‘only’ spilled one fifth of her cargo. Then there is the added question as to where Enbridge plans to store all that recovered oil since, as mentioned earlier in this report, its proposed oil storage capacity falls well short of the upper limit of even a Tier One spill. In light of the above, it is suggested that the proponent be more specific as to what it means by ‘top tier’ ( and ‘world class’, for that matter ) in respect of response capability, and provide hard evidence to support its claim that what it is proposing matches the world’s highest standards. For the OWA there is no indication given as to the proposed response capacity. All we are told is that either response depots or caches of equipment will be located within this ‘vast’ area, and that planning for this area is ongoing. ( Presumably this matter is being discussed within the context of the TERMPOL process. ) Were the response capacity to be based on a worst case scenario, i.e. total loss of cargo form a VLCC, then the figure of two million barrels comes to mind. Two things can be said about the proposed capacity for the Project Area, as outlined in an earlier section of this report. First, all the stockpiled response equipment in the world will not help the situation if the weather conditions are not propitious for its use. So, wind, waves, fog, not to mention short periods of daylight during winter- all work against mounting an effective spill response operation. In other words, just because the resources may be in place to deal with a massive oil spill, such as the total loss of cargo from a VLCC, this does not necessarily mean that the response operation will be effective. Damage could still be catastrophic and irreversible. Second, a relatively small spill can still cause significant damage, whereas a relatively large spill can end up being relatively innocuous. It all depends on when and where the spill occurs, the type of oil involved, the wind and sea conditions, and the speed and efficiency of the response. A case in point is the MV Braer incident which occurred in the Sheltand Isles in 1993, when the tanker of that name lost power and ran aground, spilling its entire cargo ( 85,000 tonnes ) of North Sea crude into the sea. Relatively little environmental damage was caused by this incident, because strong, favourable winds and big waves tended to influence the weathering of the oil, e.g. dispersion, evaporation, etc., and thereby lessen the impact of the spill. And yet the Braer spill is listed as the fourteenth worst spill in history by volume.55 Compare this with the MV Exxon Valdez incident in Prince William Sound, Alaska in 1989, which caused immeasurable damage and was the costliest tanker spill in 55 See Annex 1, Major Oil Spills Since 1967, in Tonnes. 35 history. In spite of its infamous legacy, the Exxon Valdez spill ranks as only the thirty fifth worst tanker spill in history by volume.56 There is also the concept of cascading of resources, which Enbridge alludes to in its application57. Under this mutual aid system, for a very large spill, or a case where there more than one major spill happens around the same time, equipment and resources would be brought in first from other regions of the country and, as necessary, from abroad, e.g., from the Valdez depot in Alaska, plus the Oil Spill Response Ltd ( OSRL ) depots in Southampton and Singapore, etc.. Thus, if a catastrophic spill were to occur in, say, the OWA, and local capacity to respond was exceeded, the call would no doubt go out to send equipment and trained personnel from around the world. This is standard procedure within the oil spill response sector, and so the main issue becomes: What level of response capacity do you require locally, and how much do you rely on foreign sources of support? Enbridge has specified a local capacity to respond to a 20,000 tonne oil spill in the CCAA area within twenty four hours, but has yet to specify a level of local response capacity for the OWA. This gap obviously needs to be corrected before one can judge the adequacy of the total response package being proposed. Thus, the application is deficient in this significant respect. Finally, on P. 5-12 it is stated that trained response personnel will be available 24 hours a day. The proponent should specify whether the command centre be open 24 hours a day, 365 days of the year? 10 Mass Balance Examples for Response Planning, PP. 10-1 -10-39 Hypothetical examples of spills are provided at two points in the application: in Section 9 of Volume 8C with respect to the terminal at Kitimat, and in Sections 10 and 11 of Volume 8C in respect of tanker spills within the CCAA and OWA. With respect to hypothetical spills at the Kitimat marine terminal, one example deals with a medium-size diluted bitumen spill ( Volume 7C, Section 9.5, pp. 9-5 – 9-10 ), while the other deals with a medium-size condensate spill ( Volume 7C, Section 9.6, pp. 9-10 – 9-15 ). As for the hypothetical tanker spills, there are a total of five presented in Volume 8C- four involving spills of 10,000 m3 for various types of oil, and one involving a spill of 36,000 m3. ( NB The 36,000 m3 spill is described in Section 11 of Vol. 8C, PP. 11-1 –29 ). The examples of spills of 10,000 m3 include the following: • Emilia Island (synthetic oil under outflow conditions during winter); • Principe Channel (diluted bitumen under inflow conditions during summer); • Ness Rock in Sound (diluted bitumen under typical winter conditions); • Butterworth Rocks in north Hecate Strait (synthetic oil under typical summer conditions).58 These four examples, we are told, represent the “approximate maximum credible volume of a spill due to grounding or collision of a laden double-hulled tanker.”59 56 Ibid. 57 See P. 5-12 of Volume 8C, for instance, as well as Page 5-11 of Volume 7C. 58 Volume 8C, P. 10-3. 36 The 36,000 m3 example involves a midsummer collision between a VLCC and another vessel in Wright Sound, resulting in a spill of diluted bitumen60. There are several issues with respect to these ‘examples’. For instance, why do the tanker spill examples not include at least one example of an incident involving the Non-Accidental Structural Failure ( NASF ) of a tanker? Were an incident of this nature to be included in the list of ‘scenarios’ provided, it is suggested that the ‘approximate maximum credible volume’ of oil spilled could amount to virtually the entire cargo of oil on board the tanker, i.e. up to two million barrels of oil in the case of a VLCC. The worst tanker spill in history was the MV Atlantic Empress incident off Tobago in 1979, which involved just over two million barrels of oil.61 Two million barrels would therefore be a better ‘worst case scenario’ figure for an oil spill within the OWA, with the scenario narrative dealing with the challenges inherent in responding to a spill of this magnitude, and how the proponent intends to overcome what are bound to be the many obstacles to successfully responding to such a catastrophic incident. In terms of visualizing these “examples”, it would certainly help to have maps of oil spill trajectories projected for each scenario, depicting the track of the oil at various timeframes after the incident occurs. A case in point is Example 1 for Emilia Island, where people living in Hartley Bay might be in a position to better appreciate the implications of this scenario if they could see a map displaying synthetic oil washing up their shores after 72 hours.62 An example of this graphic depiction of potential oil spills is the Oil Spill Model developed by the Living Oceans Society for various types of incidents along British Columbia’s North Coast where medium crude oil is spilled. In the Introduction Section of Volume 8C, on P. 1-1, it is stated that this volume has been put together in response to public concerns related to tanker traffic. In virtually the same breath, the study refers to what it calls “mass balance” examples of spills. The proponent should explain what it means by “mass balance” examples, as very few members of the public are likely to be familiar with this technical term. The application also claims that oil spill incidents from tankers are unlikely, because of the proponent’s commitment to accident prevention. We shall return to this topic later on. Enbridge also informs us, on P. 1-3 of Volume 8C, that the mass balance examples it has chosen “…provide realistic descriptions…” of, among other things, “…effective response plans and equipment”. It is suggested here that it is not realistic to assume that a response is going to be effective. Typical encounter rates for oil recovery at sea are between 10 and 15 percent63 This, then, is a more realistic expectation of the outcome from a spill response operation. The application goes on to state that small spills from tanker operations, such as ballast or bilge water discharges, are unlikely to occur. As mentioned previously, incidents that involve a tanker’s No. 6 Bunker 59 Ibid., P. 1-3 60 Ibid., P. 10-5. 61 See Annex 1 for a list of the worst tanker spills in history. 62 Ibid., P. 10-7. 63 In the case of the recent BP Deepwater Horizon oil spill in the Gulf of Mexico, only 5% of the spilled oil was recovered from skimming, for instance, while a further 8% was chemically dispersed and 5% burned. See, NOAA’s August 4, 2010 report on this subject for details. 37 C fuel oil are entirely within the realm of possibility. Thus, it is suggested that at least one scenario cover the possibility of a tanker’s fuel tanks being ruptured, resulting in a serious spill. It is also disingenuous for the proponent to say that the examples it presents do not include mitigative measures, i.e. cleanup, and that if cleanup efforts are factored in, the spill impacts would not be as significant as the examples project64. Contrary to this rosy forecast, a spill’s impacts are still likely to be serious even if cleanup efforts are factored in, given inherent conditions in the region that are unfavourable to mounting a credible response, such as adverse weather, logistical challenges, remoteness, short periods of daylight during winter, etc. The scenarios provided mention winds/waves only in the sense that they influence weathering of the oil- not the cleanup operation itself. In a similar vein, we are told that the examples will deal with “…a range of environmental conditions (tide and winds) at the time of an incident that reflects seasons during which effects could be greatest”. It is suggested the scenarios include incidents where not only the effects could be the greatest, but where the conditions extant are most likely to cause an incident, and where the cleanup is most likely to be compromised by those conditions. Thus, while fog in the region tends to occur most often during summer months, winds and waves ( coupled with shorter days ) tend to be at their worst in winter. We are also informed that the selection of locations for the mass balance examples was based on the existence of potential navigational hazards and environmentally sensitive areas65. It is suggested that other scenarios be selected as well, that are perhaps more representative of potential incidents along the entire transport route. Candidate sites for inclusion might be: Gwaii Haanas National Marine Conservation Area Reserve in Haida Gwaii; the Scott Islands off the northern tip of Vancouver island; one of the sponge reef colonies within the Queen Charlotte Basin; or perhaps the sea otter colony near Goose Island off the Central Coast . Finally, on Page 10-5 of Volume 8C, no weather restrictions are indicated for the OWA. This gap should be filled. 64 See, for instance, Paragraph one in Section 10.5.1, entitled “Spill Characteristics”, Volume 8C, P. 10-6. 65 Volume 8C, 1 Introduction, 1.1 Background, P. 1-1, Paragraph 5. 38 Summary Explanatory Note A detailed review of the deficiency gaps in the application has been presented in the body of this report- what is there, what is missing, what the claims are and what can be refuted. Advice is also provided by the Consultant as to what would be required in order for those gaps to be filled. This three-page summary highlights the advice provided by the Consultant as to how the proponent should be required to fill each of those forty three gaps. The recommendations are presented sequentially, in the order in which they appear in the report itself. Information gaps for the OWA are dealt with in a separate table at the end of this summary. General Provide a map of the entire 88,000 square kilometer Project Area, being the area potentially affected by a marine oil spill associated with the marine transportation component of the project. Volume 7C Include the possibility of Bunker C spills at the marine terminal. Provide details as to how ‘return’ figures for spills were arrived at. For instance, what is the lifespan of the project? ( Also Volume 8C ) Clarify what is meant by “ownership or direction” or the Response Organisation, as well as the term “extended responsibility”. Substantiate the claim that the proposed response capacity for Kitimat marine terminal is among the best in the world. Include the coastal environmental sensitivity atlas as part of the application. Indicate how many meters of shoreline the proponent will be in a position to clean up each day. Include terrorist attacks as a potential cause of oil spill incidents at the terminal and on tankers. Indicate how potential pipeline explosions resulting in marine oil spills will be dealt with. Provide details of the proposed response depots, including location, equipment, etc. Canadian Coast Guard should be asked what plans it has, if any, for augmenting its response capacity in the region if the Northern Gateway project goes ahead. Supply detailed contingency plans, as per the requirements of the JRPA TOR and Scope of the Factors documents. 39 Volume 8A Specify by what legal means the proponent intends to ensure that tanker owners operate responsibly. Include operational safety standards for the tankers as part of the application. ( Also Volume 8B ) Provide case histories of previous double hull tanker spills, and explain how similar incidents are to be avoided on the Northern Gateway project. Answer the question: “Will Enbridge require double engine rooms, screws and rudders on tankers?” Justify the use of 20 year old tankers, and how this compares to the promise of ‘world class’ standards. Amplify the discussion of the effect of extreme weather and sea conditions on the project. Provide assurances that the tugboats Enbridge plans to use will avoid breakdown/accident issues that have befallen other tugs in the Pacific Northwest in recent years. Ask the Pacific Pilotage Authority to provide expert advice on the need for coastal pilots aboard tankers within the OWA. Back up the assertion that weather and sea conditions in the Project Area are no worse than at other terminals around the world. Provide hard evidence to support the claim that there is a higher risk of a spill within the CCAA than the OWA. Examine whether requiring escort tugs for tankers within the OWA would lower the spill risk. Support the conclusion that that spills can be mitigated to a level comparable to other marine terminals. Submit the final version of the QRA as part of the application. Volume 8B As in the case of Volume 7C, provide project details, such as its lifespan, expansion plans, etc., and include Bunker C spills as a possible by-product of the project. Also, specify whether there are any plans for a bunkering facility within the Project Area. Clarify whether condensate tankers will take the Northern Approach route or not. Specify the criteria used for determining which of the two Southern Approach routes tankers take. Specify response times for rescue tugs within the OWA, as well as plans for salvage tugs throughout the Project Area. Provide a more accurate description of the extreme waves that can be experienced in the OWA, and relate these conditions to operational standards for the tankers. Include CN’s PipelineonRail project in the project inclusion list. 40 Include operational safety standards for tankers as part of the application, including safe harbours and places of refuge. ( Also Volume 8A ) Volume 8C Submit a final version of the Quantitative Risk Assessment ( QRA ). Include more data on adverse and extreme weather and sea conditions, and relate these not only to the risk of incidents, but also to the effectiveness of cleanup and response operations. Incorporate a broader concept of risk than one which relies solely on statistical probability. As in Volume 8B, explain why condensate tankers will not take the Northern Approach route, if that is indeed the case. Provide details as to how ‘return’ figures for spills were arrived at, taking into account data provided in this report on Non-Accidental Structural Failures ( NASF ), for example. Justify the claim that the proposed response capacity for the CCAA will be ‘top tier’ and meet the world’s highest standards. Define the various tier levels for spill response, include Tier 4, and specify plans to deal with spills larger than Tier 4. Indicate the proposed response capacity for the OWA. In Table 5-3, define “big local boats”. Indicate whether the Kitimat command centre will be open twenty four hours per day. Completely revamp the ‘mass balance’ examples section of the application. In particular, include a ‘worst case scenario’ incident involving the total loss of cargo in, say, the middle of Hecate Strait. 41 Table 7 Missing Data for the Open Water Area ( OWA ) Vol. Page Subject Gap Information Request Vol. 8A P. 4-84 Incident prevention and Insufficient info Provide response measures provided for OWA additional data for OWA Vol. 8B P. 14-1 Effects of the info provided for Provide data for environment on marine CCAA only OWA transportation Vol. 8C P. 5-1 Incident prevention and Intended response Provide similar response standards times of 6-12 hrs standards for for CCAA, whereas OWA “Planning in progress” for OWA Vol. 8C Pp. 5-11 – 5-13 Equipment and Information Provide similar personnel, including provided for CCAA data for OWA Tables 5-3 and 5-4 only; “Planning in Progress” for OWA ( P. 5-13 ) Source: Worldocean Consulting Ltd, 2010 42 Annex 1: Major Oil Spills Since 1967, in Tonnes* Spill Size Position Shipname Year Location (tonnes) 1 Atlantic Empress 1979 Off Tobago, West Indies 287,000 2 ABT Summer 1991 700 nautical miles off Angola 260,000 3 Castillo de Bellver 1983 Off Saldanha Bay, South Africa 252,000 4 Amoco Cadiz 1978 Off Brittany, France 223,000 5 Haven 1991 Genoa, Italy 144,000 6 Odyssey 1988 700 nautical miles off Nova Scotia, Canada 132,000 7 Torrey Canyon 1967 Scilly Isles, UK 119,000 8 Sea Star 1972 Gulf of Oman 115,000 9 Irenes Serenade 1980 Navarino Bay, Greece 100,000 10 Urquiola 1976 La Coruna, Spain 100,000 11 Hawaiian Patriot 1977 300 nautical miles off Honolulu 95,000 43 12 Independenta 1979 Bosphorus, Turkey 95,000 13 Jakob Maersk 1975 Oporto, Portugal 88,000 14 Braer 1993 Shetland Islands, UK 85,000 15 Khark 5 1989 120 nautical miles off Atlantic coast of Morocco 80,000 16 Aegean Sea 1992 La Coruna, Spain 74,000 17 Sea Empress 1996 Milford Haven, UK 72,000 18 Nova 1985 Off Kharg Island, Gulf of Iran 70,000 19 Katina P 1992 Off Maputo, Mozambique 66,700 20 Prestige 2002 Off Galicia, Spain 63,000 35 Exxon Valdez 1989 Prince William Sound, Alaska, USA 37,000 Source: Table 3, ITOPF Web Site: http://itopf.com/information-services/data-and- statistics/statistics/#major * One tonne equals 7.33 barrels. 44 Bibliography Agreement between the National Energy Board and the Minister of the Environment Concerning the Joint Review of the Northern Gateway Pipeline Project, January 15, 2010 Enbridge Northern Gateway application, Submitted to NEB/CEAA May 27, 2010: o Volume 7C: Risk Assessment and Management of Spills- Kitimat Terminal; o Volume 8A: Overview and General Information- Marine Transportation; o Volume 8B: Environmental and Socio-Economic Assessment ( ESA )- Marine Transportation; and o Volume 8 C: Risk Assessment and Management of Spills- Marine Transportation. Intertanko Tanker Facts 2009 ITOPF, Oil Tanker Statistics: 2009 Pacific Pilotage Authority, 2009 Annual Report Papanikolaou, A., Eliopoulou, E., Hamann, R., Loer, K., Assessment of Safety of Crude Oil Transport by Tankers, Proc. Annual Main Conference of Schiffbautechnische Gesellschaft (STG2009), Berlin, November, 2009, Procedural Direction, Enbridge Northern Gateway Project, Joint Review Panel, July 5, 2010 Response Organizations Standards ( 1995 )- TP12401E Scope of the Factors- Northern Gateway Pipeline Project, Canadian Environmental Assessment Agency, August 2009. The Veil of Chaos- Living with Weather Along the British Columbia Coast, Owen S. Lange, Environment Canada, 2003.