Responsible Canadian Energy™ Progress Report for the year ended December 31, 2009

RCE RESPONSIBLE CANADIAN ENERGY PROGRESS REPORT FOR THE YEAR ENDED DECEMBER 31, 2009

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 stewardship 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

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 websiteSustainable (www.capp.ca/rce), where there are links of natural resources always has and responsible development to other sources of information. 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 This is the first Responsible Canadian Energy for report.

This report is our progress, be candid about our an opportunity us to demonstrate based on data reported by CAPP members in the reporting year ending approach in pursuit of solutions. challenges and encourage a collaborative December 31, 2009. As an association-wide performance reporting It represents a unified approach by CAPP’s membership, focusing our program, data collected through the Responsible Canadian Energy improvement and achievement of the efforts on continuous performance program does not represent the entire upstream oil and gas high standards of performanceindustry, our stakeholders expect of the Canadian oil and as such, may not align with andother gas reports industry.accounting for the total industry. Work continues on the development of metrics discussed in this CAPP’sand oil we andwill gascontinue producers are involved report. This process is an evolution to improve upon in an industry that ranks as the fifth largest energy producer in the world.

With five billion barrels of convenour performance reporting. 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.

ABOUT CAPP

Additionally, Canada is the third largest producer of natural gas. Natural The Canadian Association of Petroleum Producersand (CAPP) represents companies, large and small, that gas is an abundant a naturally occurring petroleum product in Canada. explore for, develop and produce natural gas and crude oil throughout Canada. CAPP’s member companies The oil and gas industry touches many Canadians. There are over 500,000 produce more than 90 per cent of Canada’s natural gas and crude oil. CAPP’s associate members provide employees, contractors and suppliers employed directly and indirectly to a wide range of services that support the upstream crude oil and natural gas industry. Together CAPP’s provide Canada and its trading partners with the energy we need to heat members and associate members are an important part of a national industry with revenues of about our homes, run our cars and travel. We manufacture more than 3,000 $100 billion-a-year. products made with hydrocarbons as an original source compound. With CAPP’s mission is to enhance this the economic sustainability of responsibilities the Canadian upstream petroleum industry breadth and reach comes and we are challenged every in a safe and environmentallyday andtosocially responsible manner, throughour constructive engagement andis work smarter and better.

Reducing impact on the environment communication with governments, public stakeholders in the communities in which we operate. a keythe driver forand technological innovation.

Responsible Canadian Energy represents a collective commitment by CAPP’s members to measure our performance and to find new and innovative Responsible Canadian Energyapproaches is an association-wide reporting program based on worker data to reduce ourperformance environmental footprint, to ensure every reported by the CAPP membership, this data, well asthe tools andin returnsannual homemeasurement safely every and day,analysis and to of continue to as improve ways resources for CAPP members which to support continual performance improvement. is designed we communicate and engage the publicThe andprogram other stakeholders. to track progress in the areasIn ofa environmental, health,to safety social performance. program world that continues evolve and its understanding of the The environmental builds on nearly a decade of achievements through our Stewardship initiative, addressing key areas for responsibilities of individuals and corporations, we have developed the performance improvement, with a renewedCanadian focus on Energy transparency in how we assess and communicate Responsible Program to address the expectations of our our performance. stakeholders, incorporating learnings from the sustainability programs of other leading industry associations.

Central to the program is the Responsible Canadian Energy progress report.

The oil and gas industry’s commitment to responsible resource developThis is the first Responsible Canadian Energy progress report, based on 2009 performance data. It ment is at the heart of the Responsible Canadian Energy program. 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.

ABOUT THIS REPORT

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  Drilling for petroleum in the is a critical part of the process underway to ensure the program, andCanadian this report by extension, responds Foothills. 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.

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.

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 of objective stakeholders a report range and of fields representing This isbody the first Responsible Canadian from Energy the program’s key Aboriginal peoples, academia/research, contractors, non-government performance indicatorscommunities, are aligned with the aboveinvestors, principles.government/regulators, The reporting organizations, labour business.

One inof this the report, responsibilities of as the group will be to review year ending December 31, and 2009, discussed will serve this report andyear its recommendations willtobeuse considered for next year’s and subsequent reports. industry’s baseline as companies begin Responsible Canadian Energy metrics and align their internal management systems.

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 and energy security and reliability for North America. The development of the Here’s how wegrowth are doing: 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 PEOPLE and reliability, while at the same time continuing to ensure responsible environmental : Oursecurity safety performance improved significantly, with Total Recordable and social outcomes. The oil sands report provides our current perspective in this regard.

Injury Frequency in 2009 dropping to the lowest level since reporting In summary, oil andtrend gas industry is committed to delivering energy to Canada and the began in 1999. Canada’s The downward is attributable to a number of worldcompanies in a responsible way, everya day.

This Responsible Canadian Energy report provides an factors: are emphasizing safety culture within the opportunity to demonstrate our progress, to beare candid aboutfrom our challenges and to encourage operating and contracting community, companies learning a collaborative of solutions. incidents that do approach occur, andinapursuit reduction in industry activity resulted in the most highly skilled and trained individuals comprising a larger We welcome your feedback. proportion of the workforce.

:

On Sincerely, 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 DAVE COLLYER, President :

4

Canadian Association of Petroleum Producers

Over the past five years, the number of annual reclamation certificates January 2011 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.

RESPONSIBLE CANADIAN ENERGY : Progress Report

AIR

«

: Canada’s and gas sector 17 per cent of the country’s Thisoilprogram isproduces a

greenhouse gas (GHG) emissions. In the global context, this represents 0.4 per cent of GHGs.

collective recognition of concerns about theCanadian crude oil production : As shown through life cycle analysis, including oil sands production creates GHG emissions that are similar to impact of our operations all other forms of crude oil imported or sourced by the United States. andGHG reflects the oil and : Absolute emissions increased as a result of production shifting fromgas conventional reserves ongoing to unconventional reserves. Unconventional industry’s reserves require enhanced production techniques. These techniques commitment continuous require more energy andtoconsequently generate more GHGs than would be generated through the production improvement in areas thatof conventional reserves.

Technological development will continue to focus on energy efficiency and matter Canadians. minimizing GHGto intensities, defined as emissions per unit of production. :

»

Nitrogen oxide (NO X) 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 A Message from the Presidentto mining, as mine-fleet vehicle usage increases, NO X emissions also will increase. However, improved vehicle fuel efficiencies combined On behalf of the Canadian Association of Petroleum Producers have (CAPP) of our member with technological improvements keptand NO Xallemission increases to companies, I am pleased to introduce the first Responsible Canadian Energy (RCE) for the a minimum.

Overall emissions increased two per centreport and emission year ending December 31, 2009.intensity increased one per cent between 2008 and 2009.

The Canadian oil and gas industry is focused on the – environmental performance, economic : Sulphur dioxide (SO“3Es” ² ) is primarily emitted in sour gas processing and growth and energy security and bitumen reliability.

We are proud of our achievements and trackhave upgrading.

Over the pastindustry five years, total SO ² emissions record in delivering the 3Es, for the benefitseven of all per Canadians. also of understand our reputation dropped cent as We a result improvingthat operating efficiencies, and social license to develop andinstallation operate is ofdependent on both continuous performance improveemissions control equipment at sour gas processing ment and effective communication regarding facilities, andour anactivities. overall decrease in sulphur processed. SO ² emissions increased three per cent in 2009 over 2008 levels for CAPP’s oil and The Responsible Canadian Energy program represents an evolution of the CAPP Stewardship gas producers. Aggregate numbers were impacted by changes in CAPP program. It is being developed to measure our performance as an industry in the areas of environmembership, reporting anomalies and facility outages. 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 believeWATER that all our stakeholders should have timely access to credible, objective information about our: industry.

In 2009, CAPP introduced mandatory water reporting to provide a more complete picture the of member as it health, pertainssafety to water.

The Responsible Canadian Energy program highlights strategicperformance environmental, For this reason, reliable aggregate historical CAPP data is unavailable. and social performance of the Canadian oil and gas sector in the areas of greatest relevance to our the purpose this report and to establish we currently have therefore industry and to our stakeholders.For Specifically, theofResponsible Canadian Energytrends Program also accessed information from government sources to supplement the focuses on key performance indicators in four areas: people, land, air and water. new CAPP data. The upstream oil and gas industry has been increasing This is the first Responsible Canadian report using focusedbrackish) set of performance its useEnergy of non-fresh water a(saline, sources for indicators oil and gas and, as with any “first,” the data production and reporting be refined and improved with time. This and will meet government policy requirements to usereport non-fresh will serve as industry’s baselinewater year, sources as companies to useAlthough Responsible Energy as muchbegin as possible. fresh Canadian water still represented 75 per cent of the totalDevelopment water used of by the CAPP members in 2009,and Alberta metrics and align their internal management systems. program is ongoing government datatheindicates of non-fresh water to fresh future reports will reflect enhancements in both metrics that and the ratio supporting analysis. 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.

3

RESPONSIBLE CANADIAN ENERGY : Progress Report

« 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 improvement 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 environmental, 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, academia/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 continually 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 yearover-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 capability 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.

[fatalities]

05 10

06 20

07 9

08 12

09 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.

[injuries/200,000 hrs]

■ Employee ■ Contractor Total

05 0.95 1.74 1.52

06 0.83 1.74 1.48

07 0.80 1.31 1.15

08 0.64 1.24 1.08

09 0.58 0.94 0.84

RESPONSIBLE CANADIAN ENERGY : Progress Report

7

CHEVRON CANADA: 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 capability 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.  Mark MacLeod, Chevron’s Vice-President, Atlantic Canada.

6

RESPONSIBLE CANADIAN ENERGY : Progress Report

RESPONSIBLE CANADIAN ENERGY : Progress Report

7

CAPP: Leading the Way on Safety As a result of the commitment to measure continuously, manage and act to improve on key performance indicators in health and safety, CAPP’s members have seen a steady decline in the Total Recordable Injury Frequency (TRIF) numbers for both employees and contractors. In addition to ongoing safety initiatives, highlights of CAPP’s recent activities to improve worker and contractor health and safety include:

:

:

8

Participation in the development of an industry-wide standardized drug and alcohol program model (2005/6) and supervisor training programs (2007).

Integration of ENFORM’s Guide to Safe Work programs in a traveling workshop program to increase awareness and provide training in addressing fatigue (2007).

RESPONSIBLE CANADIAN ENERGY : Progress Report

:

Development of a Supervisory Competency Guide – assists site supervisors in developing competencies critical to implementing better safety, from a knowledge perspective, as well as creating a culture and expectation for safe activity at worksites (2008).

:

Development of a Contractor Management Guide to ensure the appropriate procedures, training and contractor management programs are in place to improve overall contractor safety performance (2008).

:

Working with the offshore petroleum boards, members and training institutions in Atlantic Canada, undertook training course quality reviews to ensure the recognized certificates listed in the CAPP Atlantic Canada Offshore Petroleum Industry Standard Practice for the Training and Qualifications of Personnel are based on a course of acceptable quality that meets the intent of the Standard Practice.

« 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 Through Communication Collaboration and consensus building are recognized as integral for people and organizations to achieve excellence. In spring 2010, CAPP and ENFORM, the safety association for Canada’s upstream oil and gas industry, introduced a new Contractor Management System Guideline. The system was developed to provide a clearer framework for more effective working relationships among oil and gas industry operators and contractors.

The system emphasizes the importance of a properly defined scope of work, the establishment of clear expectations, including roles, responsibilities and risk exposures, as well as how to select and develop an appropriate agreement, effectively manage the work process and conduct record keeping, while capturing knowledge gained.

ENFORM’s Roy Mcknight, Manager, Industry Initiatives, explains, “This is a framework developed by industry, for industry, to ensure all parties 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.”

CAPP: Taking Conservation to the Classroom Every May, students in grades four through six enjoy a day of learning and community involvement led by volunteers from CAPP member companies. The Energy in Action program has been operating since 2004 and has involved 59 of CAPP’s member companies and dozens of local volunteers in 75 communities across Canada, teaching nearly 6,000 students, teachers and community representatives about the oil and gas industry and the importance of environmental stewardship. Together they have planted nearly 6,400 trees and shrubs.

Students spend the morning in classroom sessions learning about the oil and gas industry, then team up with CAPP member company volunteers to practice good stewardship by working on an environmental renewal project at the school or in the community. These projects are tailored to each class and include activities such as schoolyard naturalization, community gardens and wildlife habitat rehabilitation.

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 to begin the camping and recreational season.

Suncor Energy Inc.’s John Kerkhoven, Senior Advisor, Natural Gas, is one of several oil and gas company representatives working with Alberta Sustainable Resource Development (ASRD) to raise awareness of the hazards associated with random camping or using all-terrain vehicles (ATVs) close to pipeline rights-of-way and gas well facilities in the Ghost/Waiparous Forest Land Use Zone, located northwest of Calgary.

John explains, “The natural gas in Ghost-Waiparous contains hydrogen sulphide (H 2 S), also known as sour gas, which in higher concentrations can be extremely dangerous. With more people camping 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 infrastructure 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

Off-highway vehicle traffic is a growing concern in many natural areas but is of particular concern in Ghost-Waiparous as it has caused significant erosion over a number of pipelines in the area.

While area operators repair and reclaim these lands on a regular basis, recreational land users are often unaware of the potential harm that can be done to underlying pipelines when traveling through wet or steep areas.

In early 2010, Suncor Energy, Shell Canada and Husky Energy created a safety brochure that area operating personnel and ASRD forest officers are now distributing directly to campers and ATV users. It is also posted in information kiosks located at all entrance points to the area.

ConocoPhillips: Advanced Safety Auditing ConocoPhillips Canada is turning to front-line 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 Auditing (ASA), a program designed to ensure the safety of all stakeholders, including employees, contractors and the local community. According to the program’s creator, Dr. Bruce Staley, ASA ensures safety begins and ends with the organization’s leaders. “The new auditing program is about treating people well, delivering a clear vision and visibly reinforcing expected behaviors,” he says.

« Clear communication

of safety standards and procedures from ConocoPhilips’ front-line leaders has delivered a 61 per cent decrease in year-over-year Total Recordable Injuries.

 Chad Krause, ConocoPhillips Northern Transportation Coordinator (in dark overalls) discusses the safety procedures for a rig move with a team from KOS Oilfield, including (left to right) Ken Summers, Joe Mayoski and Nick Chomack.

As part of the program, front-line leaders communicate standards and safety expectations across all levels of the organization, conducting weekly and monthly safety meetings to maintain awareness and in-field audits to ensure expectations are being met.

The results are impressive – the company’s western Canadian gas drilling operations achieved a 61 per cent drop year-over-year in Total Recordable Injuries, from a rate of 2.34 in December 2008 to 0.92 in December 2009.

“We are targeting zero injuries,” says Darryl Hass, vice president of Health, Safety and Environment Operations. “We think Dr. Staley’s message will help us hit the bull’s eye.”

ConocoPhillips has trained 240 managers and front-line supervisors to date.

»

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 reclamation 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 indicators 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 1940

06 1717

07 1478

08 1821

09 1243

RESPONSIBLE CANADIAN ENERGY  :  Progress Report 15

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.

 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.

14 RESPONSIBLE CANADIAN ENERGY : Progress Report

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 north of Edmonton on the south shores of Lesser Slave Lake. The 15 acre site consists of mixed wood boreal forest and supports a great blue heron rookery and other wildlife. Pictured at the site are John Hallet, right, intermediate biologist and Dave Jackson, senior technician – each having more than ten years experience with the Alberta Conservation Association.

Suncor: Boreal Habitat Conservation Initiative Suncor Energy Foundation has invested $2.75 million, and pledged an additional $1.2 million for 2011 and 2012, to a partnership with the Alberta Conservation Association (ACA). This partnership has helped conserve 1,349 hectares of boreal forest habitat. In addition, the ACA has been able to leverage the Suncor Energy Foundation to receive an additional $200,000 in donations and in-kind services that support the conservation of this particular land.

The Boreal Habitat Conservation Initiative was formed in 2003 out of Suncor’s desire to help offset the footprint of its Alberta operations while supporting the conservation of natural spaces.

The initiative’s pilot project purchased and conserved 190 hectares at Winagami Lake, where much of the shoreline had been heavily grazed and water levels were critically low. Fish, wildlife and natural vegetation now thrive on this permanently protected and maintained land, which will be incorporated into the Alberta Parks system.

The success of the partnership has allowed the ACA to seek other corporate partners, positioning it for continued growth.

16 RESPONSIBLE CANADIAN ENERGY : Progress Report

ARC Resources: Using Natural Bacteria to Beat Contamination When ARC Resources Ltd. purchased the more than 50-year-old Redwater oilfield late in 2005, a significant amount of historical hydrocarboncontaminated soil was identified throughout the field. ARC saw this as an opportunity to evaluate alternatives to typical landfill disposal. After extensive testing, ARC built a centrally located bio-remediation facility in the Redwater area.

The facility presents an environmentally sound method to treat contamination locally and eliminates the need to find large volumes of replacement soils.

Jackson Hegland, Coordinator, Environmental Strategies at ARC explains, “We wanted to do what’s right, not just what’s required. 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.”

In 2008, ARC completed construction of the bioremediation facility, which has the capacity to treat 20,000 cubic metres of contaminated soil annually. In addition to reducing the cost of reclaiming contaminated soil by more than half, its central location eliminates the need to move the soil to a landfill, thereby reducing vehicle traffic and the associated safety and emission concerns in the area, while supporting a strengthened relationship with local landowners.

« 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.

»

Stages of Well Reclamation To receive a reclamation certificate in Alberta, a well must undergo the following process: Decommissioning: Consists of the removal of surface equipment and downhole abandonment.

The downhole abandonment process consists of sealing each produced zone with a bridge plug capped with cement. All porous saline and fresh water zones behind the casing are isolated at the time of abandonment if not done at the time of drilling. After the wellbore has been made secure to prevent well fluids from migrating out of zone, the wellhead is removed, the casing is cut off at least one metre below ground surface and a steel plate is welded on top.

Remediation: Involves reducing, removing and/ or isolating the environmental impact identified in site assessments. These assessments include testing soil and potentially groundwater for contaminants of concern for comparison to applicable regulatory standards. Soil remediation may include on-site treatment and restoration of impacted soils, or excavation and disposal at a licensed landfill. When required, groundwater monitoring wells are installed to monitor groundwater quality until satisfied there is no groundwater contamination beneath the site. The timeline for remediation depends on the presence and extent of contamination, the complexity of the site, and the method of remediation used. If the groundwater has been impacted, the process could take

 ARC Resources has completed construction of a bio-remediation facility that carefully contains the contaminated soil for treatment using environmentally sound methodology.

10 or more years. Sign-off by a certified professional is required at the end of the remediation stage to ensure all contaminants above regional thresholds have been properly addressed.

Reclamation: Consists of surface restoration (re-contouring, subsoil/topsoil placement and re-vegetation) so that the land can be returned to a productive state, typically agricultural or forested. The movement of earth associated with re-contouring the site can be done in a matter of weeks, but establishing vegetation, controlling weeds and demonstrating equivalent land use routinely takes several years and is dependent on the weather (drought conditions can extend that period from five to seven years, as is the case in southeast Alberta) and stakeholder concerns.

After the work has been done, a soil and vegetation Detailed Site Assessment (DSA) is completed to confirm the site meets applicable standards.

Landowners have an opportunity to voice concerns prior to submission of a reclamation certificate application. Professional sign-off is needed prior to applying for the reclamation certificate.

Similar processes are followed in other jurisdictions.

RESPONSIBLE CANADIAN ENERGY : Progress Report 17

Managing the emissions of greenhouse gases (GHG) and air pollutants, including nitrogen oxides (NO X), sulphur dioxide (SO 2), 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 CO 2 flood. Since the start of CO 2 injection in 2000, about 17 million tonnes of CO 2 have been sequestered at Weyburn, making it the world’s largest geological CO 2 sequestration project. The CO 2 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 ² e/MJ gasoline] FULL CYCLE GHG

EMISSIONS*

[g CO ² e/MJ gasoline]

120 120 100

102

102

106

104

114

108

105

116

113

102

107

98

102

102

102

106

104

114

108

105

116

113

102

107

Saudi Arabia

Mexico

Iraq

Venezuela Nigeria

Saudi

Mexico

Iraq

Venezuela Nigeria

Imported Wtd. average Imported Wtd. average

Oil sands Wtd. average Oil sands Wtd. average

Approximately Approximately 51% of 51% of 2009 oil2009 sands oil production sands production

060 040 040 020 020 000 000

US Gulf California Oil sands Coast thermal mining upgraded US Gulf California Oil sands Coast thermal mining upgraded

No current No current production production (likely future (likely scenario) future scenario)

102

Approximately Approximately 6% of 6% of 2009 oil2009 sands oil production sands production

080 060

98

Approximately Approximately 43% of 43% of 2009 oil2009 sands oil production sands production

100 080

In situ oil sands diluted In situ oil sands diluted

In situ oil sands upgraded In situ oil sands upgraded

In situ oil sands bitumen In situ oil sands bitumen

GHG emissions from Arabia production and refining GHG emissions from gasoline consumption 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

Range of imported Range of imported

common U.S. crude oils common U.S. crude oils

* 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 (SO 2 ) emissions and nitrogen oxides (NO X ) emissions. Management of SO 2 and NO X are important because of their influence on regional air quality and acid deposition. NO X 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. SO 2 emissions are emitted from upstream oil and gas operations that produce and process raw natural gas, oil and bitumen containing hydrogen sulphide (H 2 S). Ongoing monitoring and reporting of SO 2 and NO X 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 production 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 improvements, increase the GHG and NO X intensity of our operations. As for SO 2 , natural gas production has tended towards higher sulphur content as fields age, resulting in higher SO 2 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 improvements in emissions performance.

We will continue to look for new ways to reduce emissions by investing in and applying new technologies 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 87.0

06 91.9

07 94.9

08 90.6

09 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 conven­t ional 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 0.26

06 0.27

07 0.28

08 0.28

09 0.30

RESPONSIBLE CANADIAN ENERGY : Progress Report 23

BONAVISTA/CONOCOPHILLIPS: ELIMINATING BENZENE EMISSIONS Two Canadian companies are getting creative in tackling issue of benzene. They have reduced OVERALL NO XtheEMISSIONS their plants’ emissions of the known carcinogen to well below regulatory requirements. “We were Overall, CAPPGold, member-reported emissions nitrogen oxidetechnologist (NO X ) have trying to think outside the box,” says Harold a regulatory and ofcompliance at changed by less than 0.4 per cent since first reported in 2007. There has Bonavista Energy, whose company been hassome found a way year-over-year, to eliminatewith more than some 99 per cent of the fluctuation emissions two per cent benzene emissions created during the glycol dehydration higher in 2009 from 2008, process. but no significant trend is yet identifiable in the data.

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 [thousands of tonnes/yr] was built and how close it is to a public facility or permanent resident. Dehydrators installed after 08 09 January 1, 2007 have a limit of one tonne per year of benzene emissions. 07 290.9

286.6

292.0

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 OVERALL NOconsumption.

EMISSIONS INTENSITY

X

Bonavista Energy already had a condensing unit in place to capture vapors created during the The intensity of overall NO X emissions similarly shows no significant variation re-boiler stage and condense out the water in the three and yearshydrocarbon of reported data.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 [tonnes/10³m³ OE] glycol flowing toward the re-boiler acts as a coolant. This heat exchanger condenses most of the 07 vapours 08 are 09 benzene and hydrocarbons, which are deposited in a storage tank. Remaining routed 0.98 0.97 0.98 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 SO 2 EMISSIONS Over the past five years, total sulphur dioxide (SO 2 ) 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. SO 2 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]

05 238.3

06 249.9

07 240.4

08 214.0

09 220.8

OVERALL SO 2 EMISSIONS INTENSITY SO 2 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 0.73

06 0.73

07 0.71

08 0.68

09 0.74

RESPONSIBLE CANADIAN ENERGY : Progress Report 23

BONAVISTA/CONOCOPHILLIPS: ELIMINATING BENZENE EMISSIONS

« With the goal of reducing

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.

emissions without affecting operating costs, Bonavista Energy retrofitted one of its In Alberta, the main source of benzene is motor vehicle exhaust, followed by industrial emissions dehydrators east ofhave Rocky and other combustion sources. Significant reductions in benzene concentrations come mainly as the result of government regulations lowering itsMountain concentration inHouse gasoline and improving in March vehicle emission performance. But natural gas producers have taken on the challenge of reducing emissions 2010. The operation now from their processes, over and above regulatory requirements. nearly eliminates benzene 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 emissions, while also with some of the benzene occurring in natural gas. The glycol is re-boiled, which allows it to be recycled through reducing fuel consumption. 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,”  Harold Gold, regulatory compliancegroup. “It’s says Andrea Zabloski, an operations engineer in ConocoPhillips’ energy and efficiencies technologist, Bonavista Energy. running well. It’s just a great project.”

22 RESPONSIBLE CANADIAN ENERGY : Progress Report

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.

Shell Canada: Capturing Steam for Power Shell Canada is using surplus steam to generate more than half the power for its Caroline, Alberta plant northwest of Calgary, which not only reduces GHG emissions but reduces the amount of energy required from Alberta’s electrical grid.

One of the processes at the Caroline plant involves converting hydrogen sulphide into sulphur, a process that generates steam and heat.

Some of the steam can be used in other areas of the plant, but a significant amount would be wasted without the technology introduced with the Low Pressure Steam Unit.

This unit uses an advanced steam turbine driven by the excess steam to generate electricity. Construction of the plant was completed in early 2008, and “the big steam turbine that could” began generating up to 11 megawatts of power daily.

At full capacity, the Caroline plant has the potential to generate up to 20 megawatts of power – enough to power the entire plant and make it self-sufficient from the Alberta electrical grid.

24 RESPONSIBLE CANADIAN ENERGY : Progress Report

Encana: Finding Ways to Reduce Flaring Routine flaring at oil and gas wells and production facilities can be costly from both an environmental and operational perspective, as the process generates carbon dioxide (CO 2 ) and other gases, and burns a valuable resource. Oil and gas producers follow stringent guidelines for flaring and incineration, but continually seek ways to reduce the practice.

In 2008, Encana Corporation began pilot testing a new underbalanced drilling process designed to use natural gas instead of nitrogen in their Greater Sierra development program, located in northeastern British Columbia. The process involves producing natural gas while drilling, rather than flaring it, which enables the safe recovery of up to 80 per cent of the natural gas produced during a typical underbalanced drilling operation.

Encouraged by initial results, in 2009 Encana continued refining the new process and applied the process on both underbalanced drilling packages. This enabled Encana to reduce its CO 2 equivalent emissions by approximately 39,800 tonnes in 2009, while conserving 741 million cubic feet of natural gas that otherwise would have been flared – enough to heat close to 8,000 homes in Canada for a year.

CCS TECHNOLOGY AT WORK: :

Several CAPP member companies are exploring ways to apply carbon capture and storage technology to their operations, including:

Apache Corporation ARC Energy Trust Canadian Natural Resources Limited Cenovus Energy Inc. Chevron Canada Limited Enhance Energy Marathon Oil Sands L.P. Nexen Inc. OPTI Canada Inc. Penn West Energy Trust Shell Canada Suncor Energy Inc.

“This is a win-win situation that was created through a lot of consultation, careful risk assessment and control, and the sharing of technologies and expertise,” says Adrian Steiner, Encana’s drilling engineer who directed the program. “We reduced emissions and produced more sales gas which, in turn, creates more royalties for the Crown and benefits to the people of B.C.” Carbon Capture and Storage: A Multi-Company Initiative It’s not yet a household term, but Carbon Capture and Storage (CCS) is on the minds of many who count responsible development of Canada’s oil sands as a priority environmental and economic concern. While not exclusive to the oil and gas sector, CCS is a promising innovation to help reduce industry’s GHG emissions by capturing and storing carbon dioxide (CO 2 ) in deep geological formations. Canada, with the efforts of companies like Shell Canada, Cenovus and Enhance Energy, is making a name for itself as a CCS leader on the international stage.

« CCS can contribute

significantly to the reduction and stabilization of CO 2 emissions in the atmosphere, particularly when combined with renewable energy technologies and greater energy efficiency.

»

Combined with renewable energy technologies and greater energy efficiency, CCS can contribute significantly to the reduction and stabilization of CO 2 emissions in the atmosphere. In fact, without CCS technology in the mix, the International Energy Agency estimates the cost of climate stabilization would increase by 70 per cent. In repeated declarations between 2005 and leading up to the 2010 G8 Summit in Canada, world leaders have endorsed the swift deployment and commercialization of CCS. Still in the demonstration stages, the technology remains vulnerable to skeptics who question the safety and efficacy of the process. However, through its Weyburn CO 2 injection full-scale field study in Saskatchewan, Cenovus safely stored 13 million tonnes of CO 2 over the past nine years with a goal to store an additional 30 million tonnes. Other companies are also exploring this technology. Enhance Energy is creating a CCS system in Alberta. Shell Canada, in a joint venture with Chevron Canada Limited and Marathon Oil Sands L.P., is evaluating an opportunity to take more than a million tonnes of CO 2 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),

:

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

Steam generation to heat bitumen underground, allowing it to flow to the surface (in situ oil sands),

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 suitable 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, brackish 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 technologies 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 conventional 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 crossindustry 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 hydraulic 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 representatives 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, communication, 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 waterrelated 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 information 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]

■ Fresh ■ Non-fresh

09 165.5 056.5

RESPONSIBLE CANADIAN ENERGY : Progress Report 29

HORN RIVER BASIN PRODUCERS GROUP: A COLLECTIVE APPROACH TO CONSERVATION the absence of overall industry trends for of annual waterhas and garnered non-fresh British Columbia’s remote Horn RiverInBasin, roughly 40 kilometres north Fort fresh Nelson, water withdrawal, the following graphs use data reported to the Government considerable attention for its significant shale gas potential. It’s also gaining a reputation for crossof Alberta by the upstream oil and gas industry, including non-CAPP members, industry cooperation, as operators towork together to use understand surface water show industry water performance the for oilarea’s sands mining, in situ and and conventional operations in Alberta. groundwater systems.

Recent innovations are allowing producers to access shale gas through horizontal drilling and hydraulic fracturing. However, these technologies require significant amounts of water and safe sites to OIL SANDS MINING: WATER WITHDRAWN dispose of wastewater – two challenges that could strain water resources if not properly managed.

FROM THE ATHABASCA RIVER*

125

125

75

75

25

25

Water Use [millions m³]

The HRBPG is pursuing responsible development on all fronts: regulatory, operations, communication, environment and Aboriginal relations. In 2009, the group completed an Area Operations 100 100 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 waterrelated studies: one is focused on surface water availability, while the other is examining groundwater 50 50 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 0 0 has entered its second phase, is designed to assist producers in minimizing the impact on surface ■ ■ 00 01 02 03 04 05 06 07 08 09 water in the area.

■ Athabasca River withdrawal

In September 2010, the group hosted Bitumen its first production water forum in Fort Nelson, designed as an information exchange with the community on water issues within the context of shale gas. Watts says the * Source: Alberta Environment 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

28 RESPONSIBLE CANADIAN ENERGY : Progress Report

Bitumen Production [millions m³]

To meet these and other challenges of developing the shale gas reserves, estimated to cover more The Athabasca River is the primary source of fresh water for mining projects than 800,000 hectares, producers have new levels of collaboration cooperation. and thereached annual withdrawal represents less than one and per cent of the river’s The Horn River Basin Producers Group (HRBPG) was formed in 2007, currently consisting of representaaverage natural flow. Industry withdrawals from 2002 through 2007 reflect increasing efficiencies realized in terms of total and per barrel withdrawals. tives from the 10 CAPP member companies holding majority interests in the area: Apache Canada The increase in 2008 is directly attributable to a new project coming on Ltd., ConocoPhillips Canada, Devon Canada Corporation, Encana Corporation, EOG Resources stream. Withdrawal rates are expected to moderate as that project reaches Canada, Imperial Oil Limited/ExxonMobil Canadaefficiencies.

Limited, Actual NexenAthabasca Inc., Pengrowth Energy greater operating River withdrawal by oil Trust, sands was 106.5 millions Resources m³ in 2009. Ltd. “We’re a group of people Quicksilver Resources Canada Inc. mining and Stone Mountain 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.

OIL SANDS IN SITU: WATER USE*

125

125

100

100

75

75

50

50

25

25

0

0

00

01

02

03

04

05

06

07

08

Bitumen Production [millions m³]

Water Use [millions m³]

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.

09

■ Total non-fresh sources ■ Total fresh sources Bitumen production * Source: Alberta Environment

CONVENTIONAL OIL: WATER USE*

125

125

100

100

75

75

50

50

25

25

0

0

00

01

02

03

04

05

06

07

08

Oil Production [millions m³]

Water Use [millions m³]

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.

09

■ Total non-fresh sources ■ Total fresh sources Oil production (natural depletion plus EOR) Oil production (EOR only) * Source: Energy Resources Conservation Board

RESPONSIBLE CANADIAN ENERGY : Progress Report 29

HORN RIVER BASIN PRODUCERS GROUP: A COLLECTIVE APPROACH TO CONSERVATION British Columbia’s remote Horn River Basin, roughlyUSE 40 kilometres north of Fort Nelson, has garnered WATER FOR OILFIELD considerable attention for its significantINJECTION shale gas potential.

It’s also gaining a reputation for crossPURPOSES* industry cooperation, as operators work together to understand the area’s surface water and The upstream oil and gas industry has been increasing its use of groundwater systems.

non-fresh water sources for oilfield injection purposes in Alberta and is committed to meeting government policy requirements to use this Recent innovations are allowing producers to access shale gas through horizontal drilling and hydraualternative water source as much as possible. Oilfield injection includes lic fracturing. However, these technologies require significant amounts of water and safe sites to the injection of steam for oil sands in situ operations and the injection of dispose of wastewater – two challenges could strain water resources if not properly managed. water that for conventional oil operations.

To meet these and other challenges The of developing the shale estimated to coverand more graph below shows the pergas centreserves, of fresh water (fresh groundwater surfacereached water) versus per cent non-fresh water (non-fresh groundwater) than 800,000 hectares, producers have newthe levels of of collaboration and cooperation.

The used for oilfield injectioninpurposes Alberta from 1972 to 2009.

The graph Horn River Basin Producers Group (HRBPG) was formed 2007, incurrently consisting of representademonstrates the trend of increasing use of non-fresh groundwater and a tives from the 10 CAPP member companies majority interests in the area:to Apache commitmentholding to meeting government policy requirements use this Canada Ltd., ConocoPhillips Canada, Devon alternative Canadawater Corporation, source as much Encana as possible.

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 100 is Nexen Inc.’s Director of Community Consultation and Regulatory Affairs.

Oilfield Injection Water Use [%]

The HRBPG is pursuing responsible 80 development on all fronts: regulatory, operations, communication, 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 60 access, wildlife and water management.

In addressing stakeholder concerns 40about water usage, the group is participating in two waterrelated 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 20 Ministry of Energy.

HRBPG members individually provided 0 Geoscience BC with confidential data from their drilling activities to help identify, evaluate and map subsurface aquifers within the basin.

The study, which 1970 1980 1990 2000 2010 has entered its second phase, is designed to assist producers in minimizing the impact on surface ■ Fresh water in the area.

■ Non-fresh * Source: Alberta Environment

In September 2010, the group hosted its first water forum in Fort Nelson, designed as an information 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.  A team from Nexen Inc. measures water on the Tsea River in northeastern “The whole community is watching producers closely,” Rempel saysflow of the importance of engaging

British Columbia; Nexen is a member of the Horn River Basin Producers Group.

28 RESPONSIBLE CANADIAN ENERGY : Progress Report

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 habitat. This multi-year project included stakeholder consultations, stakeholder involvement, scientific assessments and detailed habitat construction.

ConocoPhillips: Returning Water to Alberta Four years into the moratorium on new Alberta 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 indicators 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

9

12

9

20

10

Employee total recordable injury frequency [injuries/200,000 hr]

0.58

0.64

0.80

0.83

0.95

Contractor total recordable injury frequency [injuries/200,000 hr]

0.94

1.24

1.31

1.74

1.74

Worker total recordable injury frequency [injuries/200,000 hr]

0.84

1.08

1.15

1.48

1.52

Safety and Well-Being Fatalities [number/yr]*

Water Management Fresh water withdrawal [m³/yr] Non-fresh water withdrawal [m³/yr]

165,539,671

First reported in 2009

56,482,520

Air and Energy Management Direct CO ² equivalent emissions [tonnes/yr]

76,810,038

74,771,152

81,475,976

77,710,335

71,775,702

Indirect CO ² equivalent emissions** [tonnes/yr]

14,552,333

15,836,524

13,422,756

14,235,598

15,181,504

SO ² emissions [tonnes/yr]

220,848

214,047

240,388

249,914

238,345

NO x emissions [tonnes/yr]***

292,033

286,555

290,856

45,953

38,363

Tonnes GHG emitted per m³ OE of oil sands production

0.49

0.52

0.47

0.48

0.48

Tonnes GHG emitted per m³ OE total production

0.30

0.28

0.28

0.27

0.26

SO ² intensity [tonnes per 10³m³ OE of oil sands production]

1.60

1.64

1.69

1.73

1.83

SO ² intensity [tonnes per 10³m³ OE total production]

0.74

0.68

0.71

0.73

0.73

NO x intensity [tonnes per 10³m³ OE of oil sands production]

0.84

0.83

0.74

0.65

0.66

NO x intensity [tonnes per 10³m³ OE total production]

0.98

0.97

0.98

1,243

1,821

1,478

1,717

1,940

823,704

882,658

948,766

932,819

916,463

First reported in 2007

Land Management Annual certification or release received [number] Production Total [m³OE/d] 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 CO 2 Equivalent Emissions was a non-mandatory metric used to calculate GHG intensities. *** In 2007 there was a methodology change to include NO X from non-stationary oil sands sources and NO X 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 – the number of sites that received a type of closure certificate (or an equivalent recognition of release) from the certifying authority in the jurisdiction during the reporting year.

Carbon dioxide (CO 2 ) equivalent emissions – a measure that accounts for the global warming potential (GWP) of each GHG, by relating each in terms of CO 2 equivalent emissions, taking into account the longevity of the gas and its radiative forcing effect on the climate. Reported as the annual gross weight of direct and indirect GHG emissions from all operated facilities; in CO 2 E tonnes/year.

Contractor – non-employees contracted to perform services for the company on the company’s worksites during the reporting year.

Contractor recordable injury frequency (# per 200,000 hrs) – the number of contractor recordable injuries (fatalities + permanent total disabilities + lost work-day cases + restricted work cases + medical treatment cases) per 200,000 hours.

Direct carbon dioxide (CO 2 ) equivalent emissions – annual gross weight of direct GHG emissions from all operated facilities; in CO 2 E tonnes/year. Sources released on the site from combustion, venting, fugitive emissions, formation CO 2 , etc.

Employees – individuals employed by the company and engaged in work-related activities during the reporting year.

Employee recordable injury frequency (# per 200,000 hrs) – the number of employee recordable injuries (fatalities + permanent total disabilities + lost work-day cases + restricted work cases + medical treatment cases) per 200,000 hours.

Fresh water – water low in dissolved salts as defined by the regulation in the jurisdiction acquired. Withdrawn from surface water or groundwater sources, either permanently or temporarily.

Fresh water withdrawal – the total volume of fresh water that is acquired through removal or purchase from any source, either permanently or temporarily.

Indirect carbon dioxide (CO 2 ) equivalent emissions – annual gross weight of indirect GHG emissions from all operated facilities; in CO 2 E tonnes/year. Sources may be associated with another party, such as a utility company; for the oil and gas industry, it most commonly means purchased steam, heat and electricity.

Medical treatment cases – injuries requiring treatment by a physician or medical professional (but are neither lost-time nor restricted-work injuries).

For more information please visit our website at

www.capp.ca

32 RESPONSIBLE CANADIAN ENERGY : 2010 Progress Report

Nitrogen oxide (NO X ) emissions – formed during the combustion of fossil fuels. Nitrogen found in the combustion air or the fuel combines with oxygen under high temperatures to form oxides of nitrogen. Reported as annual gross weight of nitrogen oxide (NO X ) emitted from combustion equipment or oil sands facilities during the year.

Non-fresh water – water high in dissolved salts as defined by the regulation in the jurisdiction acquired and unsuitable for either domestic or agricultural use. Typically from groundwater, formation water or sea water.

Non-fresh water withdrawal – the total volume of non-fresh water acquired.

Oil equivalents – oil equivalents (OE) is the most common way of reporting different hydrocarbon production (both oil and natural gas) in common units.

Recordable injuries – the sum of lost-time injuries, restricted-work cases and medical treatment cases resulting from an event in the work environment.

Restricted-work cases – cases in which an individual is unable to perform normallyassigned work functions or is assigned to another temporary or permanent job after the day of the injury.

Self-sustaining landscape – refers to the establishment of a landscape and associated vegetation that will naturally evolve over time, adapting to change while maintaining the native ecosystem.

Sulphur dioxide (SO 2 ) emissions – a major component of a group of airborne contaminants termed “acidifying emissions.” Reported as annual gross weight of sulphur dioxide (SO 2 ) emitted from combustion equipment from all operated facilities that individually emitted 20 tonnes or more of sulphur dioxide emissions during the year.

Tonnes emissions emitted per m³ of oil equivalent of production – the total (gross) weight of emissions emitted from oil and gas production activities or facilities per cubic metre of oil equivalent production.

Worker – the term used to address contractors and employees collectively.

Worker recordable injury frequency (# per 200,000 hrs) – the number of contractor and employee recordable injuries (fatalities + permanent total disabilities + lost work-day cases + restricted work cases + medical treatment cases) per 200,000 hours.

We WEare AREthe THEmembers MEMBERSofOFCaPP* CAPP* (as(as of June 30,30, 2010) of June 2010)

Adeco Exploration Company Ltd.Ltd. Adeco Exploration Company Advantage Oil Oil andand GasGas Ltd.Ltd. Advantage Apache Canada Ltd.Ltd. Apache Canada ARC Resources Ltd.Ltd. ARC Resources Athabasca Oil Oil Sands Corporation Athabasca Sands Corporation Baytex Energy Ltd.Ltd. Baytex Energy BGBG International Limited International Limited Birchcliff Energy Ltd.Ltd. Birchcliff Energy Bonavista Energy Trust Bonavista Energy Trust Bonterra Energy Corp.

Bonterra Energy Corp.

BP BP Canada Energy Company Canada Energy Company Bumper Development Corporation Ltd.Ltd. Bumper Development Corporation Canadian Forest Oil Oil Ltd.Ltd. Canadian Forest Canadian Natural Resources Limited Canadian Natural Resources Limited Canadian Oil Oil Sands Trust Canadian Sands Trust Celtic Exploration Ltd.Ltd. Celtic Exploration Cenovus Energy Inc.Inc. Cenovus Energy Chevron Canada Resources Chevron Canada Resources Cinch Energy Corp.

Cinch Energy Corp.

Compton Petroleum Corporation Compton Petroleum Corporation Connacher Oil Oil andand GasGas Limited Connacher Limited ConocoPhillips Canada ConocoPhillips Canada Corridor Resources Inc.Inc. Corridor Resources Crescent Point Energy Corp.

Crescent Point Energy Corp.

Crocotta Energy Inc.Inc. Crocotta Energy Daylight Energy Trust Daylight Energy Trust Delphi Energy Corp.

Delphi Energy Corp.

Devon Canada Corporation Devon Canada Corporation Diaz Resources Ltd.Ltd. Diaz Resources Ember Resources Inc.Inc. Ember Resources Encana Corporation Encana Corporation Enerplus Resources Fund Enerplus Resources Fund EOG Resources Canada Inc.Inc. EOG Resources Canada ExxonMobil Canada Ltd.Ltd. ExxonMobil Canada Fairborne Energy Ltd.Ltd. Fairborne Energy Freehold Royalty Trust Freehold Royalty Trust Galleon Energy Inc.Inc. Galleon Energy Geodata Ltd.Ltd. Geodata Grizzly Resources Ltd.Ltd. Grizzly Resources Harvest Energy Trust Harvest Energy Trust Hunt Oil Oil Company of Canada, Inc.Inc. Hunt Company of Canada, Huron Energy Corporation Huron Energy Corporation Imperial Oil Oil Resources Imperial Resources Japan Canada Oil Oil Sands Limited Japan Canada Sands Limited Koch Exploration Canada, L.P.L.P. Koch Exploration Canada, Laricina Energy Ltd.Ltd. Laricina Energy Legacy Oil Oil & Gas Inc.Inc. Legacy & Gas Mancal Energy Inc.Inc. Mancal Energy

Marathon Oil Oil Canada Corporation Marathon Canada Corporation MEG Energy Corp.

MEG Energy Corp.

MGM Energy Corp.

MGM Energy Corp.

Midnight Oil Oil Exploration Ltd.Ltd. Midnight Exploration Murphy Oil Oil Company Ltd.Ltd. Murphy Company NAL Oil Oil andand GasGas Trust NAL Trust Nexen Inc.Inc. Nexen Niko Resources Ltd.Ltd. Niko Resources North Peace Energy Corporation North Peace Energy Corporation NuVista Energy Ltd.Ltd. NuVista Energy Open Range Energy Corp.

Open Range Energy Corp.

OPTI Canada Inc.Inc. OPTI Canada Osum Oil Oil Sands Corp.

Osum Sands Corp.

Paramount Resources Ltd.Ltd. Paramount Resources Pengrowth Corporation Pengrowth Corporation Penn West Energy Trust Penn West Energy Trust Perpetual Energy Inc.Inc. Perpetual Energy Petrobank Energy andand Resources Ltd.Ltd. Petrobank Energy Resources Progress Energy Resources Corp.

Progress Energy Resources Corp.

Provident Energy Trust Provident Energy Trust Questerre Energy Corporation Questerre Energy Corporation Quicksilver Resources Canada Inc.Inc. Quicksilver Resources Canada RCE testtest company RCE company Regent Resources Ltd.Ltd. Regent Resources Rock Energy Inc.Inc. Rock Energy Rustum Petroleums Limited Rustum Petroleums Limited Sabre Energy Ltd.Ltd. Sabre Energy Shell Canada Limited Shell Canada Limited Southern Pacific Resources Corp.

Southern Pacific Resources Corp.

Statoil Canada Ltd.Ltd. Statoil Canada Stone Mountain Resources Ltd.Ltd. Stone Mountain Resources Storm Exploration Inc.Inc. Storm Exploration Suncor Energy Inc.Inc. Suncor Energy Syncrude Canada Ltd.Ltd. Syncrude Canada Talisman Energy Inc.Inc. Talisman Energy TAQA North TAQA North Terra Energy Corp.

Terra Energy Corp.

Total E&PE&P Canada Ltd.Ltd. Total Canada Tourmaline Oil Oil Corp.

Tourmaline Corp.

Unconventional GasGas Resources Canada Unconventional Resources Canada UTSUTS Energy Corporation Energy Corporation Vast Exploration Inc.Inc. Vast Exploration Vermilion Energy Trust Vermilion Energy Trust Vero Energy Inc.Inc. Vero Energy WestFire Energy Ltd.Ltd. WestFire Energy Winstar Resources Ltd.Ltd. Winstar Resources Zargon Energy Trust Zargon Energy Trust

* Members newnew to CAPP or members thatthat do not havehave production or have undergone significant mergers/acquisitions are are * Members to CAPP or members do not production or have undergone significant mergers/acquisitions exempt fromfrom Responsible Canadian Energy datadata reporting. exempt Responsible Canadian Energy reporting.

EnvironmEntal BEnEfits statEmEnt This report is printed on PC100 FSC Certified paper – Forest Stewardship Council certified paper containing 100% post-consumer waste fibres that is totally chlorine free. By using this environmentally friendly paper in a print run of 5,000 copies, CAPP saved the following resources: trees 64 fully grown

Water 29,381 gallons

Energy 20 million BTUs

solid Waste 1,784 pounds

Emissions 6,100 pounds

Calculated based on data research by Environmental Defense Fund.

Printed in Canada

2100, 300 – 7th Avenue SW, Calgary, Alberta, Canada T2P 3N9 : www.capp.ca

January 2011 2011-0027