“As the cleanest-burning fossil fuel, natural gas represents an affordable, readily available source of energy that allows us to hit the ground running as we aim to achieve the emissions reduction targets our society has set.”
Air
Natural gas is the cleanest-burning fossil fuel, producing approximately 25 percent less carbon dioxide emissions than oil and up to 65 percent less carbon dioxide emissions than coal. Encana advocates increased use of natural gas in power generation and transportation.
Even though natural gas is the cleanest-burning fossil fuel, we continue to direct our attention to further reducing air pollutants from our production methods.
Reporting greenhouse gas emissions
In 2009, British Columbia legislated hard limits on greenhouse gas emissions through its Greenhouse Gas Reduction (Cap and Trade) Act. The Act introduced regulation that requires mandatory reporting of greenhouse gas across industrial sectors. Reporting operations that emit more than 25,000 tonnes of carbon dioxide equivalent must have their emissions data verified by an independent and accredited third party.
All of our facilities in British Columbia follow the Ministry of Environment’s definition of a linear facility and thus are subject to reporting under the Act. In addition, emissions from drilling and completions from all well sites have to be included in the final report. Although we have reported our greenhouse gas emissions for several years, British Columbia’s new regulation required a concerted effort from our team to make the necessary adjustments to our systems and processes to meet the requirements outlined in the Act.
We recognized the challenge of building a high-quality emission inventory and created a working committee in the early spring of 2010. Throughout 2010, the working committee met frequently to identify gaps in our British Columbia emissions inventory, review equipment inventories, develop measurement and calculation methodologies, conduct site visits to field operations and liaise with the British Columbia government. We did this to ensure that we could meet our reporting obligation on time and deliver an accurate, third-party-verified greenhouse gas emission inventory.
We also anticipated a surge in demand for third-party accredited verifiers as the reporting deadline approached. Early on, we engaged a qualified verifier through a competitive bidding process and by the fall of 2010 we had one in place. In fact, we exceeded what the reporting regulation required and what many of our industry peers were doing by engaging our selected verifier to conduct a pre-verification assessment of our greenhouse gas emission inventory in the winter of 2010/2011.
This work enhances our confidence in our greenhouse gas inventory in advance of the verification and reporting deadline.
As a result of our efforts, we have reduced our regulatory risk and more importantly, refined our greenhouse gas inventory and the underlying methodologies used to develop that inventory. The increased granularity in compiling our emissions inventory as per British Columbia’s new regulatory requirements resulted in an increase in our Canadian Division’s NOx emissions in 2010 over the previous year. If we used equivalent methodology in 2009 and 2010 we would have seen an approximate five-percent decline in emissions year over year.
Emissions (1)(4)(5)
| Nitrogen Oxides (NOx) (tonnes) | 2008 | 2009 | 2010 |
|---|---|---|---|
| Canadian Division(2) | 13,997 | 13,452 | 18,960 |
| USA Division(3) | 6,292 | 5,472 | 4,451 |
| Sulphur dioxide (SO2) (tonnes) | 2008 | 2009 | 2010 |
|---|---|---|---|
| Canadian Division(2) | 4,146 | 3,008 | 2,949 |
| USA Division(3) | 24 | 17 | 21 |
- (1) Some historic figures have been revised as we continue to improve our systems and incorporate various regulatory changes.
- (2) Canadian Division emissions methodologies follow Canadian Association of Petroleum Producers protocols.
- (3) USA Division methodology follows a combination of American Petroleum Institute and Mandatory Reporting Rule methodologies and emissions factors.
- (4) Canadian and USA Divisions are not directly comparable because data capture processes vary according to business system limitations and regulatory requirements.
- (5) Higher SOx and NOx emissions in our Canadian Division as compared to our USA Division is due to a higher quantity of sour gas facilities and compression, respectively.
2010 Encana Air Emissions
Total direct and indirect emissions (CO2e) (1) (2) (3) (4) (5) (6)
Direct emissions (CO2e) (1) (2) (3) (4) (5) (6)
Production carbon intensity (1) (2) (3) (4) (5)
Total gas flared and vented (1) (2) (3) (4) (5)
- (1) Some historic figures have been revised as we continue to improve our systems and incorporate various regulatory changes.
- (2) Canadian Division emissions methodologies follow Canadian Association of Petroleum Producers protocols.
- (3) USA Division methodology follows a combination of American Petroleum Institute and Mandatory Reporting Rule methodologies and emissions factors.
- (4) Canadian and USA Divisions are not directly comparable because data capture processes vary according to business system limitations and regulatory requirements.
- (5) USA Division calculates combustion type GHG emissions from measured fuel and fuel usage derived from equipment’s power rating and certain operational assumptions. This approach is selected due to existing regulatory requirements for calculation of other air emissions.
- (6) Direct operated GHG emissions includes Cavalier power station in Canadian Division.