FOR THE YEAR ENDEDDECEMBER31, 2009 RCERPROGRESS REPORT RESPONSIBLE CANADIANENERGY CE RESPONSIBLE CANADIAN ENERGY™ KEY PERFORMANCE INDICATORS The Responsible Canadian Energy key performance indicators provide a window on the performance of Canadian Association of Petroleum Producers member companies, but they do not provide the complete picture. Readers are invited to review the additional data published in this report and on our website (www.capp.ca/rce), where there are links to other sources of information.
This is the first Responsible Canadian Energy report. This report is based on data reported by CAPP members in the reporting year ending December 31, 2009. As an association-wide performance reporting program, data collected through the Responsible Canadian Energy program does not represent the entire upstream oil and gas industry, and as such, may not align with other reports accounting for the total industry. Work continues on the development of metrics discussed in this report. This process is an evolution and we will continue to improve upon our performance reporting.
ABOUT CAPP The Canadian Association of Petroleum Producers (CAPP) represents companies, large and small, that explore for, develop and produce natural gas and crude oil throughout Canada. CAPP’s member companies produce more than 90 per cent of Canada’s natural gas and crude oil. CAPP’s associate members provide a wide range of services that support the upstream crude oil and natural gas industry. Together CAPP’s members and associate members are an important part of a national industry with revenues of about $100 billion-a-year. CAPP’s mission is to enhance the economic sustainability of the Canadian upstream petroleum industry in a safe and environmentally and socially responsible manner, through constructive engagement and communication with governments, the public and stakeholders in the communities in which we operate.
ABOUT THIS REPORT Responsible Canadian Energy is an association-wide performance reporting program based on data reported by the CAPP membership, annual measurement and analysis of this data, as well as tools and resources for CAPP members to support continual performance improvement. The program is designed to track progress in the areas of environmental, health, safety and social performance. The program builds on nearly a decade of achievements through our Stewardship initiative, addressing key areas for performance improvement, with a renewed focus on transparency in how we assess and communicate our performance. Central to the program is the Responsible Canadian Energy progress report. This is the first Responsible Canadian Energy progress report, based on 2009 performance data. It provides data, trends and performance analysis, including descriptions of the significance and relevance of the program’s key performance indicators that we have chosen to monitor. The report aims to put performance data into context to support an understanding of what the numbers are telling us and where we need to improve. As an association-wide performance reporting program, data collected through the Responsible Canadian Energy program does not represent the entire upstream oil and gas industry, and as such, may not align with other reports accounting for the total industry. Development of the Responsible Canadian Energy program is ongoing; our analysis of the data has identified areas where we are currently not measuring industry performance, and we need to do so. This is a critical part of the process underway to ensure the program, and this report by extension, responds to the range of issues that matter to our stakeholders. Future reports will include an expansion of the data to include additional metrics and enhancements in reporting, including supporting analysis and interpretations. We are also providing tools and resources to assist our members in implementing the Responsible Canadian Energy program.
RESPONSIBLE CANADIAN ENERGY: EVOLVING OUR STEWARDSHIP MANDATE The Responsible Canadian Energy Program is an important next step in the evolution of steward- ship for CAPP member companies. It provides common metrics for performance measurement and reporting, supporting tools to assist CAPP members in the design and implementation of their internal systems and processes, and an opportunity to share success stories and best practices to elevate overall industry performance. A critical component of the Responsible Canadian Energy program is the measurement, reporting and analysis of data to demonstrate where the industry is making progress and where more focus is needed to achieve the desired results.
2 RESPONSIBLE CANADIAN ENERGY : Progress Report Sustainable and responsible development of natural resources always has been a hallmark of the oil and gas industry’s commitment to our stakeholders. Our stakeholders want ongoing assurance that our industry is responsibly developing our country’s natural resources. Responsible Canadian Energy is an opportunity for us to demonstrate our progress, be candid about our challenges and encourage a collaborative approach in pursuit of solutions. It represents a unified approach by CAPP’s membership, focusing our efforts on continuous performance improvement and achievement of the high standards of performance our stakeholders expect of the Canadian oil and gas industry. CAPP’s oil and gas producers are involved in an industry that ranks as the fifth largest energy producer in the world. With five billion barrels of conven- tional oil reserves and 170 billion barrels of oil sands reserves, Canada ranks third in total global oil reserves. We are also the largest single private sector investor in Canada, investing approximately $34 billion in 2009 and making $15 billion in payments to federal and provincial governments. Additionally, Canada is the third largest producer of natural gas. Natural gas is an abundant and a naturally occurring petroleum product in Canada. The oil and gas industry touches many Canadians. There are over 500,000 employees, contractors and suppliers employed directly and indirectly to provide Canada and its trading partners with the energy we need to heat our homes, run our cars and travel. We manufacture more than 3,000 products made with hydrocarbons as an original source compound. With this breadth and reach comes responsibilities and we are challenged every day to work smarter and better. Reducing our impact on the environment is a key driver for technological innovation. Responsible Canadian Energy represents a collective commitment by CAPP’s members to measure our performance and to find new and innovative approaches to reduce our environmental footprint, to ensure every worker returns home safely every day, and to continue to improve the ways in which we communicate and engage the public and other stakeholders. In a world that continues to evolve its understanding of the environmental responsibilities of individuals and corporations, we have developed the Responsible Canadian Energy Program to address the expectations of our stakeholders, incorporating learnings from the sustainability programs of other leading industry associations. The oil and gas industry’s commitment to responsible resource develop- ment is at the heart of the Responsible Canadian Energy program.
Drilling for petroleum in the Canadian Foothills. OUR REPORT CARD
HERE’S WHAT WE SAID, AND HOW WE ARE DOING
CAPP’s Board of Governors has endorsed the following Vision and Principles for the Responsible Canadian Energy program.
Our Vision: We will conduct our business activities in a safe and sustainable manner, balancing social, economic and environmental considerations. We will hold each other accountable and measure ourselves against the following Principles:
: Provide a safe and healthy workplace for our employees, contractors and for the communities in which we work, with a goal to do no harm; : Conduct our activities in an environmentally responsible manner; : Engage our stakeholders in open and responsive communications; : Create opportunities for economic and social benefits in the communities in which we operate, at a local and national level; and : Conduct our business activities with integrity, ensuring all people are treated with dignity, fairness and respect.
This is the first Responsible Canadian Energy report and the program’s key performance indicators are aligned with the above principles. The reporting year ending December 31, 2009, discussed in this report, will serve as industry’s baseline year as companies begin to use Responsible Canadian Energy metrics and align their internal management systems.
Here’s how we are doing: PEOPLE : Our safety performance improved significantly, with Total Recordable Injury Frequency in 2009 dropping to the lowest level since reporting began in 1999. The downward trend is attributable to a number of factors: companies are emphasizing a safety culture within the operating and contracting community, companies are learning from incidents that do occur, and a reduction in industry activity resulted in the most highly skilled and trained individuals comprising a larger proportion of the workforce. : On an individual basis, CAPP member companies continue to reach out to stakeholders through community consultation, community investments, reports and initiatives to establish and encourage open lines of communication.
LAND : Over the past five years, the number of annual reclamation certificates issued by governments across the oil and gas industry has fluctuated based largely on industry activity. The economic recession experienced throughout 2008-2009 had a significant impact on overall budgets, and in consequence, affected reclamation budgets. The pace of reclamation is largely determined by the economic climate within a budget year, and that is evidenced in the sharp decline in certificates during this period. However, reclamation remains a priority and all lands must be returned to an equivalent capability. Land reclamation is a regulatory requirement.
4 RESPONSIBLE CANADIAN ENERGY : Progress Report AIR : Canada’s oil and gas sector produces 17 per cent of the country’s greenhouse gas (GHG) emissions. In the global context, this represents 0.4 per cent of GHGs. : As shown through life cycle analysis, Canadian crude oil production including oil sands production creates GHG emissions that are similar to all other forms of crude oil imported or sourced by the United States. : Absolute GHG emissions increased as a result of production shifting from conventional reserves to unconventional reserves. Unconventional reserves require enhanced production techniques. These techniques require more energy and consequently generate more GHGs than would be generated through the production of conventional reserves. Technological development will continue to focus on energy efficiency and minimizing GHG intensities, defined as emissions per unit of production.
: Nitrogen oxide (NOX) emissions are primarily caused by fuel consumption – both in stationary fired equipment and in mine fleet vehicles. Additional energy requirements in near-depleted reservoirs and in unconventional production result in more emissions-intensive production. With respect to mining, as mine-fleet vehicle usage increases, NOX emissions also will increase. However, improved vehicle fuel efficiencies combined with technological improvements have kept NOX emission increases to a minimum. Overall emissions increased two per cent and emission intensity increased one per cent between 2008 and 2009.
: Sulphur dioxide (SO²) is primarily emitted in sour gas processing and bitumen upgrading. Over the past five years, total SO² emissions have dropped seven per cent as a result of improving operating efficiencies, installation of emissions control equipment at sour gas processing facilities, and an overall decrease in sulphur processed. SO² emissions increased three per cent in 2009 over 2008 levels for CAPP’s oil and gas producers. Aggregate numbers were impacted by changes in CAPP membership, reporting anomalies and facility outages.
WATER : In 2009, CAPP introduced mandatory water reporting to provide a more complete picture of member performance as it pertains to water. For this reason, reliable aggregate historical CAPP data is unavailable. For the purpose of this report and to establish trends we have therefore also accessed information from government sources to supplement the new CAPP data. The upstream oil and gas industry has been increasing its use of non-fresh water (saline, brackish) sources for oil and gas production and will meet government policy requirements to use non-fresh water sources as much as possible. Although fresh water still represented 75 per cent of the total water used by CAPP members in 2009, Alberta government data indicates that the ratio of non-fresh water to fresh water for injection (uses other than mining) has improved over the past three decades.
We see this report as the starting point, providing industry with a new set of parameters for measuring performance. We will continue to modify and expand the metrics as we identify areas where we need to track more and different parameters. Our commitment will remain focused on measuring performance, clearly analyzing the trends, and reporting on action taken to mitigate adverse impacts. « This program reflects the oil and gas industry’s ongoing commitment to transparency in performance reporting and to continuous improvement in areas that matter to Canadians. »
A Message from the President On behalf of the Canadian Association of Petroleum Producers (CAPP) and all of our member companies, I am pleased to introduce the first Responsible Canadian Energy (RCE) report for the year ending December 31, 2009. The Canadian oil and gas industry is focused on the “3Es” – environmental performance, economic growth and energy security and reliability. We are proud of our industry achievements and track record in delivering the 3Es, for the benefit of all Canadians. We also understand that our reputation and social license to develop and operate is dependent on both continuous performance improve- ment and effective communication regarding our activities. The Responsible Canadian Energy program represents an evolution of the CAPP Stewardship program. It is being developed to measure our performance as an industry in the areas of environ- mental, health, safety and social performance, to assess whether we are achieving our goal of continuous performance improvement, and to demonstrate transparency in the reporting of industry performance. We strongly believe that all our stakeholders should have timely access to credible, objective information about our industry. The Responsible Canadian Energy program highlights the strategic environmental, health, safety and social performance of the Canadian oil and gas sector in the areas of greatest relevance to our industry and to our stakeholders. Specifically, the Responsible Canadian Energy Program currently focuses on key performance indicators in four areas: people, land, air and water. This is the first Responsible Canadian Energy report using a focused set of performance indicators and, as with any “first,” the data and reporting will be refined and improved with time. This report will serve as industry’s baseline year, as companies begin to use Responsible Canadian Energy metrics and align their internal management systems. Development of the program is ongoing and future reports will reflect enhancements in both the metrics and the supporting analysis.
2 RESPONSIBLE CANADIAN ENERGY : Progress Report As part of the program’s development, our objective is to ensure our performance reporting is both credible and transparent. To that end, CAPP is creating an independent advisory group – a body of objective stakeholders from a range of fields representing Aboriginal peoples, aca- demia/research, communities, contractors, investors, government/regulators, non-government organizations, labour and business. One of the responsibilities of the group will be to review this report and its recommendations will be considered for next year’s and subsequent reports. In a supplement to this report, we also provide an in-depth look at Canada’s oil sands – one of our country’s greatest natural resources. The oil sands resource is a very important source of economic growth and energy security and reliability for North America. The development of the oil sands also brings with it environmental and social challenges. Our industry’s objective is to advance oil sands development in a manner that provides jobs, economic growth and energy security and reliability, while at the same time continuing to ensure responsible environmental and social outcomes. The oil sands report provides our current perspective in this regard. In summary, Canada’s oil and gas industry is committed to delivering energy to Canada and the world in a responsible way, every day. This Responsible Canadian Energy report provides an opportunity to demonstrate our progress, to be candid about our challenges and to encourage a collaborative approach in pursuit of solutions. We welcome your feedback.
Sincerely,
DAVE COLLYER, President Canadian Association of Petroleum Producers January 2011
RESPONSIBLE CANADIAN ENERGY : Progress Report 3 In 2009, the upstream oil and gas industry directly and indirectly employed 500,000 Canadians, directly invested approximately $34 billion in the Canadian economy and paid in excess of $15 billion to governments. The economic impact of oil and gas activity extends across Canada, with many areas of the country providing the goods, materials and services used in the oil and gas sector.
4 RESPONSIBLE CANADIAN ENERGY : Progress Report Roxanne Hodgson is a Senior Surface Land Agent at Shell Canada. Part of Roxanne’s role is to liaise with external stakeholders whose interest in surface land may be affected by operations. Trappers are a key stakeholder group in the Athabasca region as many make their living on trap lines which can intersect industry operations. As a certified junior trapper herself, Roxanne has proven that creative relationship building along with regulatory compliance can go a long way in overcoming challenges in the industry.
While the industry provides significant local and national benefits, there are also challenges. Activity in rural areas impacts the lives and mobility of local residents. Rapid development in some areas puts a significant strain on local infrastructure, which impacts the entire community. The industry works to mitigate these impacts and to lend support to communities when stresses occur. We continue to seek ways to minimize social and environmental impacts, while contributing to the economic well-being of Canadians. Our number one priority is health and safety. We are committed to safeguarding the public from negative impacts of our operations through active engagement and honest discourse of issues and concerns. A key component is the Emergency Response plans our members establish and maintain. Public safety is the primary mandate of these plans. We are also committed to protecting our employees and contractors. We recognize work in our industry can be dangerous, often involving the operation of heavy, moving equipment in a continu- ally changing environment. The risk of employees harming themselves due to lack of training, lack of experience or poor supervision is mitigated through training programs and supervision policies. This Responsible Canadian Energy program is intended to provide a window on how well we are doing in meeting these objectives. We looked at a number of key performance indicators, including overall injury frequency and fatalities for CAPP members and within the oil sands sector as a subset. We are gratified to see the total injury frequency rate in 2009 decline to its lowest level since we began reporting in 1999; and the 22 per cent decrease in 2009 from 2008 was the largest year- over-year decline ever recorded. Does this mean our policies and prevention programs are working? We believe so. However, we continue to work toward our goal of zero incidents. In addition to the data in this report, we have included stories on some of the work being done across our industry to support people and communities.
RESPONSIBLE CANADIAN ENERGY : Progress Report 5 OFFSHORE SPILL PREVENTION AND RESPONSE
It is not surprising that in the wake of the Gulf of Mexico Deepwater Horizon tragedy, regulators, investors, oil and gas employees and ordinary Canadians are asking pointed questions about how companies explore for and produce Canada’s offshore oil and gas resources. Safety and the environment are key priorities. Stakeholders want assurances operators have the right plan in place to protect our oceans and the thousands of people working on Atlantic Canada’s offshore facilities. The Canadian offshore industry is a world leader in many respects and its governing regulatory regime is as robust as anywhere in the world. Offshore operators regularly assess their health, safety and environmental performance and test new ways to approach oil spill prevention and response. Prevention is the best line of defence against spills. It begins with engineering and process controls and well design, continues through drilling practices and is supported by specific technologies. Comprehensive management systems identify potential risks, which operators work to reduce and mitigate. Automated and manual monitoring mechanisms are located throughout offshore facilities to control shutdown systems. Sites are also required to have a backup for those systems. In addition, offshore operators identify potential issues by using electronic systems and trained personnel to monitor drilling and production operations. Operators conduct detailed preventative and corrective maintenance routines to ensure equipment remains in safe working order. Rigs must meet the safety standards of Transport Canada and the appropriate federal-provincial regulatory body. They must also meet international rules and undergo inspections of their design and capabil- ity by international agencies. Companies also develop their own safe operating practices based on years of experience operating in remote, harsh environments. Operating procedures incorporate the industry’s best practices to ensure the safety of workers, offshore facilities and wells and to minimize potential for spills. Training is a crucial element of any safety program at offshore drilling sites. All workers are trained in general safety and in their specific task areas. They also receive regular refresher courses in safety and competency assessments. Chevron Canada Limited operated a deepwater exploration well in Orphan Basin in the Newfoundland and Labrador offshore for several months in 2010. “The focus of everyone involved in Orphan Basin operations was on safety and incident-free operations,” said Mark MacLeod, Chevron’s Vice-President (Atlantic Canada). “Chevron is very pleased that this 2010 exploration well was completed safely without any lost time incidents,” he added. In Newfoundland and Labrador, operators have access to equipment spanning all tiers of response. They continue to implement new response technology as it becomes available. For example, in 2009 operators in Newfoundland and Labrador purchased a piece of response equipment – called the Norwegian Standard System – that is considered the best available for Atlantic Canada’s offshore environment. This new system improves industry’s ability to respond to spills in higher wind and wave conditions. Canadian offshore operators are confident their stringent health, safety and environmental standards are among the best in the world. They are also committed to further enhancing their performance. To that end, operators are paying close attention to knowledge gained from recent events in the Gulf of Mexico. Canada’s offshore industry produces about 10 per cent of Canada’s crude oil and two per cent of Canada’s natural gas and plays a major role in the economies of Canada’s Atlantic Provinces.
6 RESPONSIBLE CANADIAN ENERGY : Progress Report OVERALL FATALITIES
In 2009, CAPP member companies recorded nine fatalities, two of which occurred during the crash of a helicopter transporting oil and gas workers to offshore platforms off the East Coast of Canada. A total of 17 people died in this accident; 15 of the individuals were associated with non-CAPP members and therefore this number is not reflected in this report’s overall 2009 number for fatalities.
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05 06 07 08 09 10 20 9 12 9
TOTAL RECORDABLE INJURY FREQUENCY
Total Recordable Injury Frequency (TRIF) is a measurement widely used by many industries to evaluate the frequency of injuries that occur in their operations. The total number of fatalities, permanent total disabilities, lost workday cases, and restricted and medical treatment cases are combined for every 200,000 hours worked, providing a ratio that is used to benchmark performance. In 2009, TRIF reported by CAPP members was 0.84 – a 22 per cent improvement over the 2008 TRIF of 1.08 and a 45 per cent improvement from 2005. The downward trend is attributed to a number of factors: companies are emphasizing the safety culture within the operating and contracting community, companies are learning from incidents that do occur, and reduced industry activity has resulted in the most highly skilled and trained individuals comprising a larger proportion of the workforce.
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05 06 07 08 09 ■ Employee 0.95 0.83 0.80 0.64 0.58 ■ Contractor 1.74 1.74 1.31 1.24 0.94 Total 1.52 1.48 1.15 1.08 0.84 Mark MacLeod, Chevron’s Vice-President, Atlantic Canada. RESPONSIBLE CANADIAN ENERGY : Progress Report 7 CAPP: Leading the Way on Safety : Development of a Supervisory Competency Guide – assists site supervisors in developing As a result of the commitment to measure con- competencies critical to implementing better tinuously, manage and act to improve on key safety, from a knowledge perspective, as performance indicators in health and safety, well as creating a culture and expectation CAPP’s members have seen a steady decline in for safe activity at worksites (2008). the Total Recordable Injury Frequency (TRIF) numbers for both employees and contractors. In : Development of a Contractor Management addition to ongoing safety initiatives, highlights Guide to ensure the appropriate procedures, of CAPP’s recent activities to improve worker training and contractor management and contractor health and safety include: programs are in place to improve overall contractor safety performance (2008). : Participation in the development of an industry-wide standardized drug and alcohol : Working with the offshore petroleum boards, program model (2005/6) and supervisor members and training institutions in Atlantic training programs (2007). Canada, undertook training course quality reviews to ensure the recognized certificates : Integration of ENFORM’s Guide to Safe Work listed in the CAPP Atlantic Canada Offshore programs in a traveling workshop program Petroleum Industry Standard Practice for the to increase awareness and provide training Training and Qualifications of Personnel are in addressing fatigue (2007). based on a course of acceptable quality that meets the intent of the Standard Practice.
8 RESPONSIBLE CANADIAN ENERGY : Progress Report « Industry employees work with 101 grade fours from Central Elementary in Lac La Biche, Alberta to plant three community garden plots, as part of CAPP’s 2010 Energy in Action program. The plots were donated by the County of Lac La Biche and the local Kinettes service group worked with the students over the summer to maintain and harvest the vegetables,which they donated to the local food bank. »
ENFORM: Better Understanding CAPP: Taking Conservation to the Classroom Through Communication Every May, students in grades four through six Collaboration and consensus building are recog- enjoy a day of learning and community involve- nized as integral for people and organizations ment led by volunteers from CAPP member to achieve excellence. In spring 2010, CAPP and companies. The Energy in Action program has ENFORM, the safety association for Canada’s been operating since 2004 and has involved upstream oil and gas industry, introduced a new 59 of CAPP’s member companies and dozens Contractor Management System Guideline. The sys- of local volunteers in 75 communities across tem was developed to provide a clearer framework Canada, teaching nearly 6,000 students, teachers for more effective working relationships among and community representatives about the oil and oil and gas industry operators and contractors. gas industry and the importance of environmental stewardship. Together they have planted nearly The system emphasizes the importance of a prop- 6,400 trees and shrubs. erly defined scope of work, the establishment of clear expectations, including roles, responsibilities Students spend the morning in classroom sessions and risk exposures, as well as how to select and learning about the oil and gas industry, then develop an appropriate agreement, effectively team up with CAPP member company volunteers manage the work process and conduct record to practice good stewardship by working on an keeping, while capturing knowledge gained. environmental renewal project at the school or in the community. These projects are tailored ENFORM’s Roy Mcknight, Manager, Industry Initia- to each class and include activities such as tives, explains, “This is a framework developed schoolyard naturalization, community gardens by industry, for industry, to ensure all parties and wildlife habitat rehabilitation. engaged in a working relationship understand the rules of engagement and are clear about who is to do what and when. In short, it’s about setting up everyone involved for success.” ENFORM recently adopted Supervisory Competency and Contractor Management Guidelines, both of which were initiated by CAPP, as industry-wide best practices for superior site management results in health, safety, environment, operations and social performance.
RESPONSIBLE CANADIAN ENERGY : Progress Report 9 In early 2010, three companies – Shell, Suncor and Husky – collaborated on the production of brochures providing safety information on the use of off-highway vehicles in the Ghost-Waiparous area of Alberta.
Suncor, Shell and Husky: Reaching Out to Recreational Users Every spring, thousands of people head outdoors Off-highway vehicle traffic is a growing concern to begin the camping and recreational season. in many natural areas but is of particular concern Suncor Energy Inc.’s John Kerkhoven, Senior in Ghost-Waiparous as it has caused significant Advisor, Natural Gas, is one of several oil and erosion over a number of pipelines in the area. gas company representatives working with While area operators repair and reclaim these Alberta Sustainable Resource Development (ASRD) lands on a regular basis, recreational land users to raise awareness of the hazards associated are often unaware of the potential harm that can with random camping or using all-terrain vehi- be done to underlying pipelines when traveling cles (ATVs) close to pipeline rights-of-way and gas through wet or steep areas. well facilities in the Ghost/Waiparous Forest Land In early 2010, Suncor Energy, Shell Canada and Use Zone, located northwest of Calgary. Husky Energy created a safety brochure that area John explains, “The natural gas in Ghost-Waiparous operating personnel and ASRD forest officers contains hydrogen sulphide (H2S), also known as are now distributing directly to campers and sour gas, which in higher concentrations can be ATV users. It is also posted in information kiosks extremely dangerous. With more people camping located at all entrance points to the area. and using off-highway vehicles in the area, we felt it was important to do our part to elevate awareness of the extensive natural gas infrastruc- ture there and how people need to respect it.”
Safety information on the use of off-highway vehicles is posted at information kiosks located at entrances to the Ghost/Waiparous area.
10 RESPONSIBLE CANADIAN ENERGY : Progress Report Chad Krause, ConocoPhillips Northern Transportation Coordinator (in dark overalls) discusses the safety ConocoPhillips: Advanced Safety Auditing procedures for a rig move with a team from KOS Oilfield, including (left to right) Ken Summers, ConocoPhillips Canada is turning to front-line Joe Mayoski and Nick Chomack. leaders to create a culture where safety truly comes first, and the move is paying dividends in the form of significantly reduced workplace injuries. In 2009, the company launched Advanced Safety As part of the program, front-line leaders Auditing (ASA), a program designed to ensure the communicate standards and safety expectations safety of all stakeholders, including employees, across all levels of the organization, conducting contractors and the local community. According weekly and monthly safety meetings to maintain to the program’s creator, Dr. Bruce Staley, ASA awareness and in-field audits to ensure expec- ensures safety begins and ends with the organi- tations are being met. zation’s leaders. “The new auditing program is The results are impressive – the company’s west- about treating people well, delivering a clear ern Canadian gas drilling operations achieved a vision and visibly reinforcing expected behav- 61 per cent drop year-over-year in Total Recordable iors,” he says. Injuries, from a rate of 2.34 in December 2008 to 0.92 in December 2009. Clear communication “We are targeting zero injuries,” says Darryl Hass, « vice president of Health, Safety and Environment of safety standards Operations. “We think Dr. Staley’s message will and procedures from help us hit the bull’s eye.” ConocoPhilips’ front-line ConocoPhillips has trained 240 managers and front-line supervisors to date. leaders has delivered a 61 per cent decrease in year-over-year Total Recordable Injuries. »
RESPONSIBLE CANADIAN ENERGY : Progress Report 11 Reducing the footprint in areas where we operate and returning the land to equivalent capability are key drivers for the oil and gas industry. This requires continuing to evaluate how we operate, continuing to develop and apply new technologies as well as rigorously measuring our impact and improving our performance.
12 RESPONSIBLE CANADIAN ENERGY : Progress Report Collaboration is common among industry partners in areas such as reclamation technology, where new learnings resulting from research and the successful application of techniques can benefit the industry as a whole. Lakeland College environmental sciences student Tracy Piquard examines peat vegetation at Syncrude’s fen reclamation research plot.
One of the ways we tackle this challenge is to minimize our area of impact. This is achieved by avoiding sensitive habitat, using narrow seismic lines, employing low impact pipelining methods, minimizing the area needed for well sites, utilizing mulch to reduce surface disturbances and working with other users to share roads and pipelines. In areas where we disturb the surface through our activities, we have made significant progress in our reclamation work. Reclamation planning begins at the outset of a project and physical reclamation work begins when the oil and gas reserves have been depleted. As one flies over Western Canada, the evidence of our activity is a measure of the abundance of oil and gas reserves in this country, not a permanent scar on the landscape. As reservoirs are depleted, the area disturbed by the oil and gas industry must be reclaimed to an equivalent land capability. Industry recognizes the land is a critical resource to Canadians and it is important that we measure how well we are reducing our impact on the land. With this Responsible Canadian Energy report, we provide data gathered from our members on one key performance indicator – the number of recla- mation certificates or releases received. These certificates are issued by provincial governments following a detailed site inspection that ensures all reclamation work has been completed to the standards set by the respective jurisdiction. Although the number of certificates is one indicator of how much reclamation work is being done across the industry, it does not recognize the progress made by industry on sites in various stages of remediation and reclamation activity. Additional indi- cators are being considered to better represent industry’s commitment to the reclamation process. During 2009, 1,243 certificates or releases received were recorded by members, representing a substantial decrease from the 1,821 recorded a year earlier. The majority of the decline is attributable to both the decrease in drilling activity in 2008-2009 and associated sites that could be quickly reclaimed and certified, and the proportionate reduction of reclamation budgets within overall corporate budgets, due to the economic downturn. It is important to note that reclamation remains a priority and all lands must be reclaimed to a productive state. In this report we describe how companies are changing how they operate and some of the technology being developed to reduce our footprint. We will continue to pursue ways to minimize impact on the land.
RESPONSIBLE CANADIAN ENERGY : Progress Report 13 DEVON CANADA: REDUCING THE PIPELINE FOOTPRINT
An extensive 390,000-kilometre network of underground pipelines gathers and connects the oil and gas produced in Alberta with end-use markets across the North American continent. Devon Canada Corporation typically adds between 150 to 200 kilometres of pipeline each year to this expanding network. In 2007, the company began pipelining in a different way after working to address a challenge that all producers share – how to reduce the surface impact of pipeline construction on the land, while interacting more effectively with regulators, landowners, contractors and other stakeholders. For the Leader of Facilities Construction Marc LaBerge and others at Devon, the answer came through a cooperative approach to problem solving. “This initiative got started because we needed to address several sunken ditch lines on several pipeline rights-of-way in the Grande Prairie area,” he says. “We chose to contact the regulator, Alberta Environment, and seek their input so we could find the best way to address the problem and prevent it from happening again.” Conventional practices involve spreading leftover subsoil across the pipeline right-of-way which, over time and with precipitation and settling, results in sunken ditch lines. The collaboration led Devon, Stratus Pipelines and Alberta Environment’s Partners in Resource Excellence (PRE) program personnel to develop tools, technologies and best practices that exceed the minimum regulatory requirements for pipelining on both agricultural and forested lands. LaBerge explains, “There is no single specific tool or process that completely solves this issue. What we call Innovative Pipelining Strategies (IPS) involves taking the existing knowledge we have and combining and applying it in new ways, as topography and ground conditions allow, as we go through a pipeline route. The key is a shift in attitude, to “why would we take more land than we absolutely have to?” Greater emphasis on conserving rather than reclaiming, reducing industry impact on land and increasing stakeholder participation in decision-making are significant aspects of the PRE model. The PRE model reinterprets government’s role from a passive approach to one that is more supportive, thereby helping industry to use legislative requirements as a starting point and working together to target environmental excellence rather than minimum standards. It also encourages partnerships and innovation and acknowledges the importance of multiple stakeholder involvement early in the pipeline planning process. IPS significantly reduces the surface land disturbance pipelines create. Topsoil stripping is reduced from a 15-metre wide swath to approximately one metre. Main pipeline trenches are sized according to actual pipe diameters, rather than automatically being sized to allowed regulatory widths. Specialized equipment can reduce a 56- to 122-centimetre-trench width to one only 28- to 56-centimetres wide, greatly reducing the volume of subsoil requiring removal. Once a pipeline is in place, subsoil is replaced and compacted, re-stabilizing the soil and minimizing the risk of sunken ditches. Devon applied these techniques in a series of pilot projects throughout 2007, and in 2008 the company made IPS standard operating procedure on all agricultural lands. In 2009, Devon extended the practice to all of its forested lands in Canadian operating areas. The result? On average, Devon has seen a 90 to 95 per cent reduction in the right-of-way footprint for pipelines on agricultural land. At Devon’s Jackfish 1 and 2 interconnecting pipeline project, located in Alberta’s northern boreal forest, IPS has delivered an 80 to 90 per cent reduction in both soil disturbance and soil and water erosion, while accelerating the forest’s natural recovery process. Similar results have been recorded in the other forested lands where Devon has applied IPS standards to its pipeline activities.
14 RESPONSIBLE CANADIAN ENERGY : Progress Report ANNUAL CERTIFICATION OR RELEASE RECEIVED
Certificates and releases are given for sites that have been reclaimed and approved by provincial authorities, and are a key measure of industry progress. Over the past five years, the number of annual certificates or releases received by CAPP members has fluctuated between 1,243 and 1,940 certificates per year. The variability is believed to be at least partially due to changes in regulatory guidance in that time frame, which created uncertainty regarding certification requirements and resulted in fewer applications. The sharp decline in certificates from 2008 to 2009 reflects reduced activity levels in the prior year and reclamation budgets proportionately reduced within capital budgets constrained by the economic downturn.
[number]
05 06 07 08 09 1940 1717 1478 1821 1243 Marc LaBerge, Leader, Facilities Construction for Devon Canada works with Doug Kulba, Resource Assurance Specialist, Environmental Management Division, Alberta Department of Environment to analyze soil as part of the planning stage for an innovative low impact pipelining project. RESPONSIBLE CANADIAN ENERGY : Progress Report 15 The Faust conservation site – set aside in partnership with the Alberta Conservation Association – is located within the hamlet of Faust, approximately 340 kilometres ARC Resources: Using Natural north of Edmonton on the south shores of Lesser Slave Bacteria to Beat Contamination Lake. The 15 acre site consists of mixed wood boreal forest and supports a great blue heron rookery and When ARC Resources Ltd. purchased the more other wildlife. Pictured at the site are John Hallet, than 50-year-old Redwater oilfield late in 2005, right, intermediate biologist and Dave Jackson, senior technician – each having more than ten years a significant amount of historical hydrocarbon- experience with the Alberta Conservation Association. contaminated soil was identified throughout the field. ARC saw this as an opportunity to evaluate alternatives to typical landfill disposal. After Suncor: extensive testing, ARC built a centrally located Boreal Habitat Conservation Initiative bio-remediation facility in the Redwater area. Suncor Energy Foundation has invested $2.75 mil- The facility presents an environmentally sound lion, and pledged an additional $1.2 million for method to treat contamination locally and 2011 and 2012, to a partnership with the Alberta eliminates the need to find large volumes of Conservation Association (ACA). This partnership replacement soils. has helped conserve 1,349 hectares of boreal Jackson Hegland, Coordinator, Environmental Strat- forest habitat. In addition, the ACA has been egies at ARC explains, “We wanted to do what’s able to leverage the Suncor Energy Foundation right, not just what’s required. Bio-remediation to receive an additional $200,000 in donations is proven, it works using natural bacteria found and in-kind services that support the conserva- in the soil and it greatly reduces the volume of tion of this particular land. material that ends up in a landfill.” The Boreal Habitat Conservation Initiative was In 2008, ARC completed construction of the bio- formed in 2003 out of Suncor’s desire to help remediation facility, which has the capacity to offset the footprint of its Alberta operations while treat 20,000 cubic metres of contaminated soil supporting the conservation of natural spaces. annually. In addition to reducing the cost of The initiative’s pilot project purchased and reclaiming contaminated soil by more than half, conserved 190 hectares at Winagami Lake, where its central location eliminates the need to move much of the shoreline had been heavily grazed the soil to a landfill, thereby reducing vehicle and water levels were critically low. Fish, wildlife traffic and the associated safety and emission and natural vegetation now thrive on this perma- concerns in the area, while supporting a strength- nently protected and maintained land, which will ened relationship with local landowners. be incorporated into the Alberta Parks system. The success of the partnership has allowed the ACA to seek other corporate partners, position- ing it for continued growth.
16 RESPONSIBLE CANADIAN ENERGY : Progress Report « Bio-remediation is proven, it works using natural bacteria found in the soil and it greatly reduces the volume of material that ends up in a landfill. »
ARC Resources has completed construction of a bio-remediation facility that carefully contains the Stages of Well Reclamation contaminated soil for treatment using environmentally sound methodology. To receive a reclamation certificate in Alberta, a well must undergo the following process: Decommissioning: Consists of the removal of 10 or more years. Sign-off by a certified profes- surface equipment and downhole abandonment. sional is required at the end of the remediation The downhole abandonment process consists of stage to ensure all contaminants above regional sealing each produced zone with a bridge plug thresholds have been properly addressed. capped with cement. All porous saline and fresh Reclamation: Consists of surface restoration water zones behind the casing are isolated at (re-contouring, subsoil/topsoil placement and the time of abandonment if not done at the time re-vegetation) so that the land can be returned of drilling. After the wellbore has been made to a productive state, typically agricultural or secure to prevent well fluids from migrating out forested. The movement of earth associated with of zone, the wellhead is removed, the casing is re-contouring the site can be done in a matter of cut off at least one metre below ground surface weeks, but establishing vegetation, controlling and a steel plate is welded on top. weeds and demonstrating equivalent land use rou- Remediation: Involves reducing, removing and/ tinely takes several years and is dependent on or isolating the environmental impact identified the weather (drought conditions can extend that in site assessments. These assessments include period from five to seven years, as is the case in testing soil and potentially groundwater for southeast Alberta) and stakeholder concerns. contaminants of concern for comparison to appli- After the work has been done, a soil and vegeta- cable regulatory standards. Soil remediation tion Detailed Site Assessment (DSA) is completed may include on-site treatment and restoration of to confirm the site meets applicable standards. impacted soils, or excavation and disposal at a Landowners have an opportunity to voice concerns licensed landfill. When required, groundwater prior to submission of a reclamation certificate monitoring wells are installed to monitor ground- application. Professional sign-off is needed prior water quality until satisfied there is no groundwater to applying for the reclamation certificate. contamination beneath the site. The timeline for remediation depends on the presence and extent Similar processes are followed in other jurisdictions. of contamination, the complexity of the site, and the method of remediation used. If the ground- water has been impacted, the process could take
RESPONSIBLE CANADIAN ENERGY : Progress Report 17 Managing the emissions of greenhouse gases (GHG) and air pollutants, including nitrogen oxides (NOX), sulphur dioxide (SO2), benzene and particulate matter is a challenge for everyone, from consumers to governments and businesses, including the oil and gas industry. CAPP member companies strive to minimize their contribution to GHG and air pollutant emissions, while continuing to provide oil and gas production to meet society’s growing needs.
18 RESPONSIBLE CANADIAN ENERGY : Progress Report The Cenovus Energy Weyburn oilfield in southeast Saskatchewan has produced oil for more than 50 years largely due to technology advances, most recently CO2 flood. Since the start of CO2 injection in 2000, about 17 million tonnes of CO2 have been sequestered at Weyburn, making it the world’s largest geological CO2 sequestration project. The CO2 sequestered to date represents an equivalent to taking about 3.8 million cars off the road for a year.
Canada produces two per cent of the world’s greenhouse gases. The oil and gas sector is responsible for 17 per cent of Canada’s GHG emissions or 0.4 per cent of the world’s total. Oil sands represent five per cent of Canada’s GHG emissions, or 0.1 per cent of the world’s total GHG emissions. The intensity (emissions per unit of production) of greenhouse gases emitted varies among different types of oil production. Heavy oil takes more energy to produce and, therefore, emits more greenhouse gases per barrel of production than light oil. CAPP members are focused on reducing greenhouse gas emissions per unit of production.
Life cycle analysis, which considers the emissions profile of a barrel of oil from production, through transportation, processing and eventual use by consumers, can be used to further our understanding of GHG emissions. During 2009, the Alberta Energy Research Institute commissioned two reports on the Life Cycle Analysis of North American and Imported Crude Oils. These reports examined and compared GHG emissions from oil sources worldwide on a wells-to-wheels basis or full life cycle basis. Wells-to-wheels or life cycle analysis assess total GHG emissions from crude oils from their production through the consumption of gasoline, diesel, etc. Jacobs Consultancy Canada Inc. and TIAX LLC. worked with an international panel of experts to develop two life cycle research reports. The independent reports indicated that life cycle GHG emissions from oil sands-derived crude oils are similar to those of many other crude oil supplies used in the United States. For example, life cycle GHGs from the oil sands are lower than GHG emissions from thermal oil production in California. Thermal oil production refers to the injection of steam to aid in the recovery of heavy oil (or bitumen) from a reservoir.
RESPONSIBLE CANADIAN ENERGY : Progress Report 19 FULL CYCLE GHG EMISSIONS* [g CO e/MJ gasoline] FULL² CYCLE GHG EMISSIONS* [g CO e/MJ gasoline] 120 ²
120 100 Range of common U.S. imported crude oils 100 Range of common U.S. 98 102 102 102106 104114 108105 116 113 102 107 080 imported crude oils 98 102 102 102106 104114 108105 116 113 102 107 080 060
060
)
n 040
)
n 040 020 Approximately 43% of 2009 oil sands production Approximately 6% of 2009 oil sands production No current productio (likely future scenario 2009 oil sands production 020 Approximately 51% of 000 Approximately 43% of 2009 oil sands production Approximately 6% of 2009 oil sands production No current productio (likely future scenario 2009 oil sands production Approximately 51% of Saudi Mexico Iraq Venezuela Nigeria US Gulf California Oil sands In situ oil In situ oil In situ oil Imported Oil sands 000 Arabia Coast thermal mining - sands - sands - sands - Wtd. Wtd. upgraded diluted upgraded bitumen average average Saudi Mexico Iraq Venezuela Nigeria US Gulf California Oil sands In situ oil In situ oil In situ oil Imported Oil sands GHG emissions from Arabiaproduction and refinin g Coast thermal mining - sands - sands - sands - Wtd. Wtd. GHG emissions from gasoline consumptio n upgraded diluted upgraded bitumen average average GHG emissions from production and refining * Source: Jacobs Consultancy. Life Cycle Assessment Comparison for North America and Imported Crudes, June 2009 GHG emissions from gasoline consumption * Source: Jacobs Consultancy. Life Cycle Assessment Comparison for North America and Imported Crudes, June 2009
This graph provides a comparison of the emissions from most supplies of crude used in the United States and shows that greenhouse gas (GHG) emissions from crude produced in Canada’s oil sands are similar to those from other energy sources. It also demonstrates that the majority of GHG emissions are generated in the consumption, not production, of gasoline from crude oil.
The life cycle emissions studies also revealed that the majority of emissions are produced during the final consumption of the transportation fuels. Consumption represents 75 per cent of the GHG emissions and is the same regardless of the source of crude oil. Our members are also working hard to reduce air pollutant emissions per unit of production and we are monitoring our performance by gathering data on key performance indicators including: sulphur dioxide (SO2) emissions and nitrogen oxides (NOX) emissions. Management of SO2 and NOX are important because of their influence on regional air quality and acid deposition. NOX emissions are by-products of fuel combustion, and are emitted from the upstream oil and gas industry during combustion activities such as flaring, compression, and power generation. SO2 emissions are emitted from upstream oil and gas operations that produce and process raw natural gas, oil and bitumen containing hydrogen sulphide (H2S). Ongoing monitoring and reporting of SO2 and NOX emissions allow us to better understand our year-over-year performance and footprint. To understand better the performance indicators reported by the CAPP membership, there are two common measurements of air and GHG emissions: absolute measures, which tally the total volume of that substance; and intensity measurements, which are a calculation of the total volume of a pollutant divided by the volume of oil and gas produced. Analysis of absolute emissions from CAPP member operations is complicated by factors which vary from year to year, including the number of CAPP members, the number of facilities they operate, and the type of facilities they operate. As well, absolute emission are a factor of demand – consumer demand for oil and gas will drive up produc- tion numbers, with a corresponding increase in absolute emissions. Our industry believes emissions per barrel of oil equivalent produced is a better indicator of improvements in industry performance, because this type of indicator can demonstrate, despite increasing production and change in membership profile, whether industry is becoming more efficient by applying technology, and best practice measures to member operations.
20 RESPONSIBLE CANADIAN ENERGY : Progress Report The propeller anemometer gathers meteorological data such as wind speed and wind flow to better access air patterns at air monitoring stations.
An overarching factor that affects interpretation of both absolute and intensity-based metrics is the trend towards depletion of the Western Canadian Sedimentary Basin. This depletion results in more energy-intensive types of facilities operated, whether due to the additional compression required in a near-depleted gas field, or to the additional energy input required to produce unconventional resources, heavy oil and oil sands. The additional energy required will, without efficiency improve- ments, increase the GHG and NOX intensity of our operations. As for SO2, natural gas production has tended towards higher sulphur content as fields age, resulting in higher SO2 emissions. Through development and implementation of CAPP’s Air and Energy Management Guideline and through stewardship of the related key performance indicators, CAPP member companies expect improve- ments in emissions performance. We will continue to look for new ways to reduce emissions by investing in and applying new tech- nologies to our operations. The following stories highlight just a few of these efforts and innovations.
RESPONSIBLE CANADIAN ENERGY : Progress Report 21 BONAVISTA/CONOCOPHILLIPS: ELIMINATING BENZENE EMISSIONS
Two Canadian companies are getting creative in tackling the issue of benzene. They have reduced their plants’ emissions of the known carcinogen to well below regulatory requirements. “We were trying to think outside the box,” says Harold Gold, a regulatory and compliance technologist at Bonavista Energy, whose company has found a way to eliminate more than 99 per cent of the benzene emissions created during the glycol dehydration process. In Alberta, the main source of benzene is motor vehicle exhaust, followed by industrial emissions and other combustion sources. Significant reductions in benzene concentrations have come mainly as the result of government regulations lowering its concentration in gasoline and improving vehicle emission performance. But natural gas producers have taken on the challenge of reducing emissions from their processes, over and above regulatory requirements. Glycol dehydration is a common, economical method to remove water from natural gas. As glycol absorbs water in the dehydration process, it also absorbs heavy hydrocarbons, along with some of the benzene occurring in natural gas. The glycol is re-boiled, which allows it to be recycled through the system. As the glycol is heated, water and benzene are vaporized and emitted. Benzene emission reductions can be achieved using various types of condensing tanks, flares or incinerators. Requirements set by the Energy Resources Conservation Board (ERCB), Alberta’s regulatory body for energy, place benzene emission limits on industry, which vary depending on when the dehydrator was built and how close it is to a public facility or permanent resident. Dehydrators installed after January 1, 2007 have a limit of one tonne per year of benzene emissions. With the goal of reducing emissions without affecting operating costs, Bonavista Energy retrofitted one of its dehydrators east of Rocky Mountain House in March 2010. The operation now nearly eliminates benzene emissions, while also reducing fuel consumption. Bonavista Energy already had a condensing unit in place to capture vapors created during the re-boiler stage and condense out the water and hydrocarbon liquids. “We knew we were halfway there,” Gold says. The remaining vapors in the condenser tank are now piped back to the re-boiler system for use as the primary fuel source. Testing has demonstrated more than 99 per cent of the benzene emissions are used and destroyed in this fuel combustion process. Bonavista Energy is looking at applying the same technology in its other locations, Gold says. Bonavista wants to be proactive in its approach to benzene emissions, rather than reacting when emission levels approach or exceed the regulatory limits. ConocoPhillips Canada began applying a similar approach in May 2010 with a JATCO BTEX Eliminator at its site near Three Hills, Alberta. The company also now removes more than 99 per cent of benzene emissions, without using additional fuel. Vapors collected from the re-boiler are routed through a shell and tube heat exchanger, where the glycol flowing toward the re-boiler acts as a coolant. This heat exchanger condenses most of the benzene and hydrocarbons, which are deposited in a storage tank. Remaining vapours are routed back to the re-boiler where they serve as fuel when the burner is firing, reducing fuel costs. When the burner isn’t firing, the vapors are sent to a platinum glow plug, installed in the burner exhaust stack, which stays hot long enough to combust the benzene emissions. In addition, the new process decreases the load on the re-boiler because the glycol, arriving rich with water and hydrocarbons, is 20 to 30 per cent warmer after acting as a coolant within the heat exchanger. “We are currently evaluating some more potential sites to install the JATCO unit on,” says Andrea Zabloski, an operations engineer in ConocoPhillips’ energy efficiencies group. “It’s running well. It’s just a great project.”
22 RESPONSIBLE CANADIAN ENERGY : Progress Report OVERALL GHG EMISSIONS
Greenhouse gases (GHGs) are emitted in the production of oil and natural gas. Total GHGs emitted by CAPP member companies increased by less than one per cent between 2008 and 2009, from 90.6 million tonnes to 91.4 million tonnes largely due to CAPP membership changes and a drop in production. Over the past five years (2005 to 2009) absolute GHG emissions have increased five per cent. The overall increase reflects the fact that Canada’s conventional reserves of oil and gas are being depleted and production is shifting to unconventional, more difficult to access reserves, which require more energy to produce.
[millions of tonnes/yr]
05 06 07 08 09 87.0 91.9 94.9 90.6 91.4
OVERALL GHG EMISSIONS INTENSITY
GHG emissions intensity increased about seven per cent from 2008 to 2009 and by 15 per cent over the past five years, largely due to the shift in production from conventional to unconventional sources, including oil sands, which require more energy to produce. Although oil sands GHG emissions intensity has decreased significantly since 1990 (Environment Canada reports a 39 per cent decrease between 1990 and 2008), oil sands GHG intensity remains greater than GHG intensity from conventional production. As a result, as production shifts to more unconventional production overall GHG intensity is expected to increase. However, industry continues to invest in and apply new technologies to reduce overall emissions.
[tonnes/m³ OE]
05 06 07 08 09 0.26 0.27 0.28 0.28 0.30 OVERALL NOX EMISSIONS
Overall, CAPP member-reported emissions of nitrogen oxide (NOX) have changed by less than 0.4 per cent since first reported in 2007. There has been some fluctuation year-over-year, with emissions some two per cent higher in 2009 from 2008, but no significant trend is yet identifiable in the data.
[thousands of tonnes/yr]
07 08 09 290.9 286.6 292.0
OVERALL NOX EMISSIONS INTENSITY
The intensity of overall NOX emissions similarly shows no significant variation in the three years of reported data.
[tonnes/10³m³ OE]
07 08 09 0.98 0.97 0.98 OVERALL SO2 EMISSIONS
Over the past five years, total sulphur dioxide (SO2) emissions have dropped seven per cent as a result of improving operating efficiencies, installation of emissions control equipment at sour gas processing facilities and an overall decrease in sulphur produced. SO2 emissions increased three per cent in 2009 over 2008 levels for CAPP’s oil and gas producers. Aggregate numbers were impacted by changes in CAPP membership, reporting anomalies and facility outages.
[thousands of tonnes/yr]
05 06 07 08 09 238.3 249.9 240.4 214.0 220.8
OVERALL SO2 EMISSIONS INTENSITY
SO2 emissions intensity remained relatively stable over the five year period, although year-over-year intensity increased nearly nine per cent in 2009 versus 2008. Higher intensity in 2009 was largely as a result of outages at processing facilities. The dip in 2008 caused by reporting anomalies and facility maintenance and outages accentuated the increase. We expect to see improved efficiencies in Alberta as sour gas production declines and new regulations are applied to older facilities. Alberta regulation requires that by the end of 2016 all facilities must meet stringent sulphur recovery standards established in 2001.
[tonnes/10³m³ OE]
05 06 07 08 09 0.73 0.73 0.71 0.68 0.74 « With the goal of reducing emissions without affecting operating costs, Bonavista Energy retrofitted one of its dehydrators east of Rocky Mountain House in March 2010. The operation now nearly eliminates benzene emissions, while also reducing fuel consumption. »
Harold Gold, regulatory and compliance technologist, Bonavista Energy. RESPONSIBLE CANADIAN ENERGY : Progress Report 23 Encana’s rig near Fort Nelson, British Columbia uses natural gas while drilling, eliminating the need to flare the gas into the atmosphere. Encana: Finding Ways to Reduce Flaring Routine flaring at oil and gas wells and production facilities can be costly from both an environmen- Shell Canada: Capturing Steam for Power tal and operational perspective, as the process Shell Canada is using surplus steam to generate generates carbon dioxide (CO2) and other gases, more than half the power for its Caroline, Alberta and burns a valuable resource. Oil and gas plant northwest of Calgary, which not only reduces producers follow stringent guidelines for flaring GHG emissions but reduces the amount of energy and incineration, but continually seek ways to required from Alberta’s electrical grid. reduce the practice. One of the processes at the Caroline plant In 2008, Encana Corporation began pilot testing involves converting hydrogen sulphide into sul- a new underbalanced drilling process designed to phur, a process that generates steam and heat. use natural gas instead of nitrogen in their Greater Some of the steam can be used in other areas of Sierra development program, located in north- the plant, but a significant amount would be eastern British Columbia. The process involves wasted without the technology introduced with producing natural gas while drilling, rather than the Low Pressure Steam Unit. flaring it, which enables the safe recovery of up to 80 per cent of the natural gas produced during This unit uses an advanced steam turbine driven a typical underbalanced drilling operation. by the excess steam to generate electricity. Con- struction of the plant was completed in early 2008, Encouraged by initial results, in 2009 Encana and “the big steam turbine that could” began continued refining the new process and applied generating up to 11 megawatts of power daily. the process on both underbalanced drilling pack- ages. This enabled Encana to reduce its CO At full capacity, the Caroline plant has the poten- 2 equivalent emissions by approximately 39,800 tial to generate up to 20 megawatts of power – tonnes in 2009, while conserving 741 million enough to power the entire plant and make it cubic feet of natural gas that otherwise would self-sufficient from the Alberta electrical grid. have been flared – enough to heat close to 8,000 homes in Canada for a year.
24 RESPONSIBLE CANADIAN ENERGY : Progress Report CCS TECHNOLOGY AT WORK: : Several CAPP member companies are exploring ways to apply carbon capture and storage technology to their operations, including: « CCS can contribute Apache Corporation ARC Energy Trust significantly to the Canadian Natural Resources Limited reduction and stabilization Cenovus Energy Inc. Chevron Canada Limited of CO2 emissions in the Enhance Energy atmosphere, particularly Marathon Oil Sands L.P. Nexen Inc. when combined with OPTI Canada Inc. renewable energy Penn West Energy Trust Shell Canada technologies and greater Suncor Energy Inc. energy efficiency. »
“This is a win-win situation that was created Combined with renewable energy technologies and through a lot of consultation, careful risk assess- greater energy efficiency, CCS can contribute ment and control, and the sharing of technologies significantly to the reduction and stabilization of and expertise,” says Adrian Steiner, Encana’s CO2 emissions in the atmosphere. In fact, with- drilling engineer who directed the program. “We out CCS technology in the mix, the International reduced emissions and produced more sales Energy Agency estimates the cost of climate gas which, in turn, creates more royalties for the stabilization would increase by 70 per cent. In Crown and benefits to the people of B.C.” repeated declarations between 2005 and lead- ing up to the 2010 G8 Summit in Canada, world leaders have endorsed the swift deployment and Carbon Capture and Storage: commercialization of CCS. A Multi-Company Initiative Still in the demonstration stages, the technology It’s not yet a household term, but Carbon Capture remains vulnerable to skeptics who question the and Storage (CCS) is on the minds of many who safety and efficacy of the process. However, count responsible development of Canada’s oil through its Weyburn CO injection full-scale field sands as a priority environmental and economic 2 study in Saskatchewan, Cenovus safely stored concern. While not exclusive to the oil and gas 13 million tonnes of CO over the past nine years sector, CCS is a promising innovation to help 2 with a goal to store an additional 30 million reduce industry’s GHG emissions by capturing tonnes. Other companies are also exploring this and storing carbon dioxide (CO ) in deep geo- 2 technology. Enhance Energy is creating a CCS logical formations. Canada, with the efforts of system in Alberta. Shell Canada, in a joint venture companies like Shell Canada, Cenovus and with Chevron Canada Limited and Marathon Oil Enhance Energy, is making a name for itself as a Sands L.P., is evaluating an opportunity to take CCS leader on the international stage. more than a million tonnes of CO2 per year from its Scotford upgrader and store it permanently two kilometres underground.
RESPONSIBLE CANADIAN ENERGY : Progress Report 25 Water is an integral part of oil and gas production around the world, and as Canada’s oil and gas industry grows, so does the demand on water resources. The major uses of water include:
: Hot water treatment process to separate bitumen from sand and clay (oil sands mining), : Upgrading bitumen to decrease viscosity for refining (oil sands mining), : Steam generation to heat bitumen underground, allowing it to flow to the surface (in situ oil sands), : Injection of water to push out oil and maintain reservoir pressure (conventional oil), : Fracturing deep underground formations to enhance production of oil or gas out of tight areas that would otherwise be unproductive (conventional oil and shale gas), : Gas plant processes, and : Well drilling and completion operations.
Depending on the location and nature of the operation, water is taken from either surface water or groundwater (underground) sources. For groundwater sources, both fresh and non-fresh water is used. Fresh water contains low dissolved salts, as defined by regulations in the jurisdiction of the operation. By extension, non-fresh water refers to water high in dissolved salts, and is not of suit- able quality for domestic or agricultural uses. A license is required to withdraw large volumes of surface water or fresh groundwater. Each provincial government closely regulates the amount of water that is licensed for use, and must be satisfied that the amount being withdrawn each year is sustainable to ensure protection of the water resource.
26 RESPONSIBLE CANADIAN ENERGY : Progress Report Quicksilver Monitoring Program – Staff gauge used to monitor water levels at the Horn River Basin Project.
Under government policy requirements, oil sands in situ operations and conventional enhanced oil recovery projects have been progressively increasing the use of non-fresh water (saline, brack- ish or recycled process water) as an alternative to fresh water. This shift toward low-quality water sources, together with increased recycling rates, has allowed industry to improve its fresh water use productivity. In other words, the ratio of barrels of fresh water used per barrel of production has been declining. Canada’s oil and gas industry is maturing, with more production coming from older fields and unconventional sources such as oil sands and shale gas, which require increasing amounts of fresh water. The challenge facing the oil and gas industry is to reduce fresh water use per barrel of production while continuing to develop oil and gas resources. Research and development of tech- nologies to improve fresh water use productivity remains a priority for industry. To help achieve one of the outcomes of Alberta’s Water for Life strategy, the upstream oil and gas sector is developing a Water Conservation, Efficiency and Productivity plan, for planned release in March 2011. The plan will include both the historical and projected water use by the oil and gas sector in Alberta. Water demand forecasts for oil sands mining, oil sands in situ and conven- tional oil operations have been developed up to the year 2015. Overall, the forecasts predict the following trends:
: The amount of fresh water to be withdrawn by oil sands mines is projected to increase as approved mines are developed, : Most new water for in situ projects is expected to come from non-fresh sources, and : A slight decline in both fresh and non-fresh water use is predicted for conventional oil.
The plan estimates the industry’s overall fresh water use productivity in Alberta will improve by 24 per cent by 2015, relative to the selected baseline year (average of years 2002 to 2004). Many of these improvements are the result of years of technological improvements and efforts. Use of the Responsible Canadian Energy program’s water management metrics will support the calculation of the industry’s fresh water use productivity. Efforts will be made to align Responsible Canadian Energy reporting with the goals of the Water Conservation, Efficiency and Productivity sector plan.
RESPONSIBLE CANADIAN ENERGY : Progress Report 27 HORN RIVER BASIN PRODUCERS GROUP: A COLLECTIVE APPROACH TO CONSERVATION
British Columbia’s remote Horn River Basin, roughly 40 kilometres north of Fort Nelson, has garnered considerable attention for its significant shale gas potential. It’s also gaining a reputation for cross- industry cooperation, as operators work together to understand the area’s surface water and groundwater systems. Recent innovations are allowing producers to access shale gas through horizontal drilling and hydrau- lic fracturing. However, these technologies require significant amounts of water and safe sites to dispose of wastewater – two challenges that could strain water resources if not properly managed. To meet these and other challenges of developing the shale gas reserves, estimated to cover more than 800,000 hectares, producers have reached new levels of collaboration and cooperation. The Horn River Basin Producers Group (HRBPG) was formed in 2007, currently consisting of representa- tives from the 10 CAPP member companies holding majority interests in the area: Apache Canada Ltd., ConocoPhillips Canada, Devon Canada Corporation, Encana Corporation, EOG Resources Canada, Imperial Oil Limited/ExxonMobil Canada Limited, Nexen Inc., Pengrowth Energy Trust, Quicksilver Resources Canada Inc. and Stone Mountain Resources Ltd. “We’re a group of people looking to do the right thing,” says Shad Watts, who chairs the HRBPG Environment Committee and is Nexen Inc.’s Director of Community Consultation and Regulatory Affairs. The HRBPG is pursuing responsible development on all fronts: regulatory, operations, communi- cation, environment and Aboriginal relations. In 2009, the group completed an Area Operations Protocol that outlines best management practices for the area, addressing key issues such as land access, wildlife and water management. In addressing stakeholder concerns about water usage, the group is participating in two water- related studies: one is focused on surface water availability, while the other is examining groundwater sources in partnership with Geoscience BC (an industry-led, not-for-profit organization) and B.C.’s Ministry of Energy. HRBPG members individually provided Geoscience BC with confidential data from their drilling activities to help identify, evaluate and map subsurface aquifers within the basin. The study, which has entered its second phase, is designed to assist producers in minimizing the impact on surface water in the area. In September 2010, the group hosted its first water forum in Fort Nelson, designed as an informa- tion exchange with the community on water issues within the context of shale gas. Watts says the HRBPG is also initiating a process for increased collaborative surface monitoring of the quantity, quality and flows of water. This cooperation is helping the producers build the right baseline information. “A coordinated approach to development is a benefit,” says Doreen Rempel, Community and Regulatory Affairs Manager at Quicksilver Resources Canada Inc. “It is unique.” While they are informed by the broader data, individual member companies still must do their own specific water assessment on the surface water within their areas of operation as a regulatory requirement of withdrawing water. Quicksilver Resources completed the latest step of its water assessment in June 2010. It contracted Matrix Solutions Inc. to collect both water level and water quality data from the Petitot River and eight lakes. Remote data loggers were installed to provide ongoing information between assessments. The company also sought out regional expertise, inviting one representative each from the Fort Nelson First Nation and the Acho Dene Koe First Nation to participate in the data collection and act as environmental monitors. Both First Nations groups are key stakeholders in the basin, which falls within their traditional lands. “The whole community is watching producers closely,” Rempel says of the importance of engaging with stakeholders.
28 RESPONSIBLE CANADIAN ENERGY : Progress Report OVERALL 2009 FRESH AND NON-FRESH WATER WITHDRAWAL
Trends for annual fresh and non-fresh water withdrawal have not been established given that 2009 was the first year these metrics were reported on a member-wide basis under the Responsible Canadian Energy program. In 2009, fresh water represented 75 per cent of the total water used by CAPP members, of which the largest part was withdrawn from the Athabasca River. While the majority of fresh water withdrawn in 2009 was consumed with relatively small volumes returned to rivers or aquifers, both fresh and non-fresh water is recycled and reused wherever possible, thus reducing requirements for additional water withdrawals.
[million m³/yr]
09 ■ Fresh 165.5 ■ Non-fresh 056.5 In the absence of overall industry trends for annual fresh water and non-fresh water withdrawal, the following graphs use data reported to the Government of Alberta by the upstream oil and gas industry, including non-CAPP members, to show industry water use performance for oil sands mining, in situ and conventional operations in Alberta.
OIL SANDS MINING: WATER WITHDRAWN FROM THE ATHABASCA RIVER*
The Athabasca River is the primary source of fresh water for mining projects and the annual withdrawal represents less than one per cent of the river’s average natural flow. Industry withdrawals from 2002 through 2007 reflect increasing efficiencies realized in terms of total and per barrel withdrawals. The increase in 2008 is directly attributable to a new project coming on stream. Withdrawal rates are expected to moderate as that project reaches greater operating efficiencies. Actual Athabasca River withdrawal by oil sands mining was 106.5 millions m³ in 2009.
125 125 ] 100 100 ]
75 75
50 50 ter Use [millions m³
Wa 25 25 Bitumen Production [millions m³
0 0 ■ ■ 00 01 02 03 04 05 06 07 08 09 ■ Athabasca River withdrawal Bitumen production * Source: Alberta Environment OIL SANDS IN SITU: WATER USE*
Oil sands in situ projects use a mix of non-fresh and fresh water sources. Actual fresh water use by in situ projects was 16.7 millions m³ in 2009. Non-fresh water use for in situ projects has been increasing since 2002 and surpassed fresh water (17.4 millions m³) as the dominant water source for in situ operations in 2009. Increased recycling rates and the preferential use of non-fresh water sources contributed to these improvements.
125 125 ] 100 100 ]
75 75
50 50 ter Use [millions m³
Wa 25 25 Bitumen Production [millions m³
0 0
00 01 02 03 04 05 06 07 08 09 ■ Total non-fresh sources ■ Total fresh sources Bitumen production * Source: Alberta Environment
CONVENTIONAL OIL: WATER USE*
Conventional oil projects also use a mix of non-fresh and fresh water sources. In 2009, actual fresh water use by conventional oil projects was 12.3 millions m³ and non-fresh water use was 7.9 millions m³. Fresh water use for conventional projects has been decreasing since 2000 along with production, and non-fresh water use has held relatively steady.
125 125
100 100 ] ]
75 75
50 50 ter Use [millions m³ Wa
25 25 Oil Production [millions m³
0 0
00 01 02 03 04 05 06 07 08 09 ■ Total non-fresh sources ■ Total fresh sources Oil production (natural depletion plus EOR) Oil production (EOR only) * Source: Energy Resources Conservation Board WATER USE FOR OILFIELD INJECTION PURPOSES*
The upstream oil and gas industry has been increasing its use of non-fresh water sources for oilfield injection purposes in Alberta and is committed to meeting government policy requirements to use this alternative water source as much as possible. Oilfield injection includes the injection of steam for oil sands in situ operations and the injection of water for conventional oil operations.
The graph below shows the per cent of fresh water (fresh groundwater and surface water) versus the per cent of non-fresh water (non-fresh groundwater) used for oilfield injection purposes in Alberta from 1972 to 2009. The graph demonstrates the trend of increasing use of non-fresh groundwater and a commitment to meeting government policy requirements to use this alternative water source as much as possible.
100
80
ter Use [%] 60 Wa
40
20 Oilfield Injection
0
1970 1980 1990 2000 2010 ■ Fresh ■ Non-fresh * Source: Alberta Environment
A team from Nexen Inc. measures water flow on the Tsea River in northeastern British Columbia; Nexen is a member of the Horn River Basin Producers Group. RESPONSIBLE CANADIAN ENERGY : Progress Report 29 At their Horizon oil sands project, Canadian Natural Resources has created this fisheries compensation lake – a lake ecosystem that compensates for lost fisheries ConocoPhillips: Returning Water to Alberta habitat. This multi-year project included stakeholder consultations, stakeholder involvement, scientific Four years into the moratorium on new Alberta assessments and detailed habitat construction. water licenses, ConocoPhillips Canada is applying to transfer a portion of an Alberta water license to the Water Conservation Trust of Canada. If accepted after an environmental review, a public notice period and government review, this will be the first license transfer to privately protect Alberta’s water. ConocoPhillips has held a license to draw water from the Medicine River since 1968 and recently applied to donate over 50 per cent – 123,000 cubic metres per year – to the Water Conservation Trust of Canada. “We believe this is an important opportunity to contribute to the sustainability of the Medicine River,” said Lloyd Visser, ConocoPhillips Canada Vice President, Environmental and Sustainable Development. “Our application is intended to support the habitat enhancement and recreation values of this river.”
30 RESPONSIBLE CANADIAN ENERGY : Progress Report 2009 RESPONSIBLE CANADIAN ENERGY AGGREGATE DATA – OVERALL
This is the first Responsible Canadian Energy report using the focused set of key performance indi- cators and the data and reporting will be refined and improved with time. This report will serve as industry’s baseline year as companies begin to use Responsible Canadian Energy metrics and align their internal management systems. Development of the program is ongoing and future reports will reflect enhancements in both the metrics and the supporting analysis and interpretations.
RCE METRICS 2009 2008 2007 2006 2005 Safety and Well-Being Fatalities [number/yr]* 9 12 9 20 10 Employee total recordable injury 0.58 0.64 0.80 0.83 0.95 frequency [injuries/200,000 hr] Contractor total recordable injury 0.94 1.24 1.31 1.74 1.74 frequency [injuries/200,000 hr] Worker total recordable injury frequency 0.84 1.08 1.15 1.48 1.52 [injuries/200,000 hr] Water Management Fresh water withdrawal [m³/yr] 165,539,671 First reported in 2009 Non-fresh water withdrawal [m³/yr] 56,482,520 Air and Energy Management
Direct CO² equivalent emissions 76,810,038 74,771,152 81,475,976 77,710,335 71,775,702 [tonnes/yr]
Indirect CO² equivalent emissions** 14,552,333 15,836,524 13,422,756 14,235,598 15,181,504 [tonnes/yr]
SO² emissions [tonnes/yr] 220,848 214,047 240,388 249,914 238,345 NOx emissions [tonnes/yr]*** 292,033 286,555 290,856 45,953 38,363 Tonnes GHG emitted per m³ OE 0.49 0.52 0.47 0.48 0.48 of oil sands production Tonnes GHG emitted per m³ OE 0.30 0.28 0.28 0.27 0.26 total production
SO² intensity [tonnes per 10³m³ OE 1.60 1.64 1.69 1.73 1.83 of oil sands production]
SO² intensity [tonnes per 10³m³ OE 0.74 0.68 0.71 0.73 0.73 total production]
NOx intensity [tonnes per 10³m³ OE 0.84 0.83 0.74 0.65 0.66 of oil sands production] NO intensity [tonnes per 10³m³ OE 0.98 0.97 0.98 x First reported in 2007 total production] Land Management Annual certification or release 1,243 1,821 1,478 1,717 1,940 received [number] Production Total [m³OE/d] 823,704 882,658 948,766 932,819 916,463 General Comments 1) Factors to convert different facilities’ products to an oil equivalent volume was based on the product’s energy or heating value to be consistent with CAPP’s Guidance Document for Calculating Greenhouse Gas Emissions (Pub No. 2003-003). 2) Yellow shaded areas indicate normalized key performance indicators. 3) Data may be impacted by fluctuations in CAPP membership year-over-year. * CAPP started collecting fatality data directly from members in 2007. Fatality data for 2005 and 2006 was collected through provincial sources.
** Indirect CO2 Equivalent Emissions was a non-mandatory metric used to calculate GHG intensities.
*** In 2007 there was a methodology change to include NOX from non-stationary oil sands sources and NOX from conventional sources. Also, 2009 was the first year the metric was mandatory.
RESPONSIBLE CANADIAN ENERGY : Progress Report 31 GLOSSARY OF TERMS
Annual certification or release received Nitrogen oxide (NOX) emissions – the number of sites that received a type of closure certificate – formed during the combustion of fossil fuels. Nitrogen found in (or an equivalent recognition of release) from the certifying the combustion air or the fuel combines with oxygen under high authority in the jurisdiction during the reporting year. temperatures to form oxides of nitrogen. Reported as annual gross weight of nitrogen oxide (NO ) emitted from combustion Carbon dioxide (CO ) equivalent emissions X 2 equipment or oil sands facilities during the year. – a measure that accounts for the global warming potential (GWP) of each GHG, by relating each in terms of CO2 equivalent Non-fresh water emissions, taking into account the longevity of the gas and its – water high in dissolved salts as defined by the regulation in the radiative forcing effect on the climate. Reported as the annual jurisdiction acquired and unsuitable for either domestic or gross weight of direct and indirect GHG emissions from all agricultural use. Typically from groundwater, formation water operated facilities; in CO2E tonnes/year. or sea water. Contractor Non-fresh water withdrawal – non-employees contracted to perform services for the company – the total volume of non-fresh water acquired. on the company’s worksites during the reporting year. Oil equivalents Contractor recordable injury frequency (# per 200,000 hrs) – oil equivalents (OE) is the most common way of reporting – the number of contractor recordable injuries (fatalities + different hydrocarbon production (both oil and natural gas) in permanent total disabilities + lost work-day cases + restricted common units. work cases + medical treatment cases) per 200,000 hours. Recordable injuries Direct carbon dioxide (CO2) equivalent emissions – the sum of lost-time injuries, restricted-work cases and medical – annual gross weight of direct GHG emissions from all operated treatment cases resulting from an event in the work environment. facilities; in CO E tonnes/year. Sources released on the site 2 Restricted-work cases from combustion, venting, fugitive emissions, formation CO , etc. 2 – cases in which an individual is unable to perform normally- Employees assigned work functions or is assigned to another temporary or – individuals employed by the company and engaged in permanent job after the day of the injury. work-related activities during the reporting year. Self-sustaining landscape Employee recordable injury frequency (# per 200,000 hrs) – refers to the establishment of a landscape and associated – the number of employee recordable injuries (fatalities + vegetation that will naturally evolve over time, adapting to permanent total disabilities + lost work-day cases + restricted change while maintaining the native ecosystem. work cases + medical treatment cases) per 200,000 hours. Sulphur dioxide (SO2) emissions Fresh water – a major component of a group of airborne contaminants termed – water low in dissolved salts as defined by the regulation in the “acidifying emissions.” Reported as annual gross weight of jurisdiction acquired. Withdrawn from surface water or sulphur dioxide (SO2) emitted from combustion equipment from groundwater sources, either permanently or temporarily. all operated facilities that individually emitted 20 tonnes or more of sulphur dioxide emissions during the year. Fresh water withdrawal – the total volume of fresh water that is acquired through removal Tonnes emissions emitted per m³ of oil equivalent of production or purchase from any source, either permanently or temporarily. – the total (gross) weight of emissions emitted from oil and gas production activities or facilities per cubic metre of oil Indirect carbon dioxide (CO ) equivalent emissions 2 equivalent production. – annual gross weight of indirect GHG emissions from all operated facilities; in CO2E tonnes/year. Sources may be Worker associated with another party, such as a utility company; for the – the term used to address contractors and employees collectively. oil and gas industry, it most commonly means purchased steam, Worker recordable injury frequency (# per 200,000 hrs) heat and electricity. – the number of contractor and employee recordable injuries Medical treatment cases (fatalities + permanent total disabilities + lost work-day cases – injuries requiring treatment by a physician or medical professional + restricted work cases + medical treatment cases) per (but are neither lost-time nor restricted-work injuries). 200,000 hours.
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32 RESPONSIBLE CANADIAN ENERGY : 2010 Progress Report WeWE are ARE the THE members MEMBERS of OF C aCAPP*PP* (as(as of Juneof June 30, 30, 2010) 2010)
AdecoAdeco Exploration Exploration Company Company Ltd. Ltd. MarathonMarathon Oil Oil Canada Canada Corporation Corporation AdvantageAdvantage Oil Oil and and Gas Gas Ltd. Ltd. MEGMEG Energy Energy Corp. Corp. ApacheApache Canada Canada Ltd. Ltd. MGMMGM Energy Energy Corp. Corp. ARCARC Resources Resources Ltd. Ltd. MidnightMidnight Oil Oil Exploration Exploration Ltd. Ltd. AthabascaAthabasca Oil Oil Sands Sands Corporation Corporation MurphyMurphy Oil Oil Company Company Ltd. Ltd. BaytexBaytex Energy Energy Ltd. Ltd. NALNAL Oil Oil and and Gas Gas Trust Trust BGBG International International Limited Limited NexenNexen Inc. Inc. BirchcliffBirchcliff Energy Energy Ltd. Ltd. NikoNiko Resources Resources Ltd. Ltd. BonavistaBonavista Energy Energy Trust Trust NorthNorth Peace Peace Energy Energy Corporation Corporation BonterraBonterra Energy Energy Corp. Corp. NuVistaNuVista Energy Energy Ltd. Ltd. BPBP Canada Canada Energy Energy Company Company OpenOpen Range Range Energy Energy Corp. Corp. BumperBumper Development Development Corporation Corporation Ltd. Ltd. OPTIOPTI Canada Canada Inc. Inc. CanadianCanadian Forest Forest Oil Oil Ltd. Ltd. OsumOsum Oil Oil Sands Sands Corp. Corp. CanadianCanadian Natural Natural Resources Resources Limited Limited ParamountParamount Resources Resources Ltd. Ltd. CanadianCanadian Oil Oil Sands Sands Trust Trust PengrowthPengrowth Corporation Corporation CelticCeltic Exploration Exploration Ltd. Ltd. PennPenn West West Energy Energy Trust Trust CenovusCenovus Energy Energy Inc. Inc. PerpetualPerpetual Energy Energy Inc. Inc. ChevronChevron Canada Canada Resources Resources PetrobankPetrobank Energy Energy and and Resources Resources Ltd. Ltd. CinchCinch Energy Energy Corp. Corp. ProgressProgress Energy Energy Resources Resources Corp. Corp. ComptonCompton Petroleum Petroleum Corporation Corporation ProvidentProvident Energy Energy Trust Trust ConnacherConnacher Oil Oil and and Gas Gas Limited Limited QuesterreQuesterre Energy Energy Corporation Corporation ConocoPhillipsConocoPhillips Canada Canada QuicksilverQuicksilver Resources Resources Canada Canada Inc. Inc. CorridorCorridor Resources Resources Inc. Inc. RCERCE test test company company CrescentCrescent Point Point Energy Energy Corp. Corp. RegentRegent Resources Resources Ltd. Ltd. CrocottaCrocotta Energy Energy Inc. Inc. RockRock Energy Energy Inc. Inc. DaylightDaylight Energy Energy Trust Trust RustumRustum Petroleums Petroleums Limited Limited DelphiDelphi Energy Energy Corp. Corp. SabreSabre Energy Energy Ltd. Ltd. DevonDevon Canada Canada Corporation Corporation ShellShell Canada Canada Limited Limited DiazDiaz Resources Resources Ltd. Ltd. SouthernSouthern Pacific Pacific Resources Resources Corp. Corp. EmberEmber Resources Resources Inc. Inc. StatoilStatoil Canada Canada Ltd. Ltd. EncanaEncana Corporation Corporation StoneStone Mountain Mountain Resources Resources Ltd. Ltd. Responsible Canadian eneRgy EnerplusEnerplus Resources Resources Fund Fund StormStorm Exploration Exploration Inc. Inc. pRogRess RepoRt EOGEOG Resources Resources Canada Canada Inc. Inc. SuncorSuncor Energy Energy Inc. Inc. ExxonMobilExxonMobil Canada Canada Ltd. Ltd. SyncrudeSyncrude Canada Canada Ltd. Ltd. foR the yeaR ended deCembeR 31, 2009 FairborneFairborne Energy Energy Ltd. Ltd. TalismanTalisman Energy Energy Inc. Inc. FreeholdFreehold Royalty Royalty Trust Trust TAQATAQA North North GalleonGalleon Energy Energy Inc. Inc. TerraTerra Energy Energy Corp. Corp. GeodataGeodata Ltd. Ltd. TotalTotal E&P E&P Canada Canada Ltd. Ltd. GrizzlyGrizzly Resources Resources Ltd. Ltd. TourmalineTourmaline Oil Oil Corp. Corp. HarvestHarvest Energy Energy Trust Trust UnconventionalUnconventional Gas Gas Resources Resources Canada Canada HuntHunt Oil Oil Company Company of Canada,of Canada, Inc. Inc. UTSUTS Energy Energy Corporation Corporation HuronHuron Energy Energy Corporation Corporation VastVast Exploration Exploration Inc. Inc. ImperialImperial Oil Oil Resources Resources VermilionVermilion Energy Energy Trust Trust JapanJapan Canada Canada Oil Oil Sands Sands Limited Limited VeroVero Energy Energy Inc. Inc. KochKoch Exploration Exploration Canada, Canada, L.P. L.P. WestFireWestFire Energy Energy Ltd. Ltd. LaricinaLaricina Energy Energy Ltd. Ltd. WinstarWinstar Resources Resources Ltd. Ltd. LegacyLegacy Oil Oil & Gas& Gas Inc. Inc. ZargonZargon Energy Energy Trust Trust MancalMancal Energy Energy Inc. Inc.
* Members* Members new new to CAPP to CAPP or members or members that that do notdo nothave have production production or have or have undergone undergone significant significant mergers/acquisitions mergers/acquisitions are are exemptexempt from from Responsible Responsible Canadian Canadian Energy Energy data data reporting. reporting.
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