By Mark Lowey

            Alberta’s energy-and-environment story is a lot more than the chapter on “dirty oil.” The province certainly faces some significant environmental challenges, especially in continuing to expand development of its vast oil sands deposits. But Alberta also has pioneered environmental stewardship programs, although sometimes the province’s ‘deliverables’ don’t match its good intentions on the environment.
           “I don’t know how we got to this point that Alberta is labeled by some as being indifferent to the environment and the producer of dirty oil. Certainly it’s a wrong perception,” says Joe Lukacs, General Conference Chair for the Air & Waste Management Association’s 103rd Annual Conference & Exhibition, to be held June 22-25 in Calgary.
          Lukacs, who emphasizes that he’s stating his personal views – not those of the A&WMA – is an engineer who has worked in the pollution-control business for 50 years. “Alberta is actually a leader in many environmental technologies and regulations as they relate to energy production,” he says.
             First, let’s put Canada and Alberta’s energy resources – and the economic benefits from those resources – in a global context. The world now consumes about 85 million barrels of oil per day (bbl/d). By 2015, consumption will be 91 million bbl/d and climbing to 107 million bbl/d by 2030, according to the most recent forecast by the U.S. Energy Information Administration (EIA). Demand for natural gas is expected to grow from 104 trillion cubic feet (tcf) to 153 tcf by 2030, the EIA says.
           Fossil fuels will account for 77% of the increase in world energy demand from 2007 to 2030, with oil demand rising to 105 million bbl/d by 2030, the OECD’s International Energy Agency says in its World Energy Outlook 2009.
          Canada is the world’s seventh-largest crude oil producer and third-largest natural gas producer. And Alberta produces 69% of Canada’s crude oil and 80% of its natural gas. In 2008, the petroleum industry’s net cash expenditures in Canada amounted to more than $69 billion, including $43.2 billion in Alberta, says the Canadian Association of Petroleum Producers (CAPP), which represents member companies that produce about 90% of Canada’s natural gas and crude oil.
           For Albertans, natural gas is the largest single source of non-renewable resource development revenue, accounting for about 63%, or more than $42.6 billion, in provincial royalties from fiscal year 2000/2001 to 2006/2007. Conventional crude oil production was the third-largest source of this revenue type for Albertans during the 2007-2008 fiscal year.
            According to the provincial Alberta Energy department, one out of every six working Albertans – or 170,000 people – is directly or indirectly employed in the energy industry. Oil, gas and their byproducts account for more than 70% of Alberta’s exports. (See below for a compilation of energy-and-environment statistics in Alberta).
            With the EIA, OECD and other organizations forecasting an increase in demand for energy in the U.S. and worldwide, Alberta’s strategic position as a secure and reliable energy supplier will become more important. But how has Canada’s energy province done in balancing development of its abundant fossil fuel resources with environmental stewardship?

Air Pollution and Greenhouse Gas Emissions
            Alberta was the first jurisdiction in Canada to create a government environment department, in 1971. Alberta’s oil and gas regulator, the Energy Resources Conservation Board, is seen as a leader by other jurisdictions and organizations around the world – including the World Bank which adopted the provincial regulator’s petroleum flaring emissions-reduction model.
             Driving much of the effort to clean up air pollution is the Clean Air Strategic Alliance (CASA), a multi-stakeholder partnership of representatives selected by industry, government and non-governmental organizations, which recommends strategies to assess and improve air quality in Alberta. Through CASA’s work, Alberta’s petroleum industry had, as of 2008, reduced flaring emissions (from burning off solution gas that can’t be conserved) by 77% compared with a 1996 baseline. Venting emissions (from unburned gas releases) have been cut by about 41% compared with a 2000 baseline. Sulfur emissions from natural gas processing plants in the province also have been reduced – by 53% from 2000 to 2008.
           “There has been a lot going on to reduce the environmental footprint of the (oil and gas) industry over the past decade or so,” says David Pryce, vice-president of the Canadian Association of Petroleum Producers. “I believe it represents a path of continuous improvement.”
           When it comes to greenhouse gas (GHG) emissions, Canada contributes 2% of the world’s overall GHGs. Alberta is the largest emitter of greenhouse gases in the country. However, the largest source of GHGs in the province is not the oilsands. It is coal-fired power plants – as it is in many U.S. states.
           Alberta’s oil sands industry contributed 38.4 million tonnes (Mt) of GHGs or about 5% of Canada’s greenhouse gas emissions in 2007, and 0.1% of overall GHGs in the world, the Alberta government says. For comparison, coal-fired power plants in the U.S. produce close to 2 billion tonnes of CO2 per year, or 27% of total U.S. emissions, according to the Pew Center on Global Climate Change.
          This is not to infer that GHGs produced by Canada or Alberta or the oil sands sector are minimal or unimportant in the global effort to reduce emissions. However, making such comparisons helps prioritize where money and effort should be spent to reduce GHGs in order to achieve the greatest global benefit. For example, significantly cutting emissions from Alberta’s coal-fired power plants – and from coal plants in the U.S. – would have a greater global benefit than reducing the same percentage of emissions from oil sands operations. But all countries, provinces (and states) and industrial sectors need to do their fair share.
            Alberta was the first jurisdiction in North America to enact legislation requiring large facilities to reduce their GHG emissions intensity (the amount of GHGs per barrel of oil produced or other unit of production). As of July 1, 2007, facilities emitting more than 100,000 tonnes of GHGs annually are required to reduce emissions intensity by 12%. Through this measure, Alberta is targeting a 200-Mt CO2 equivalent (CO2e) reduction annually over business-as-usual projects, by 2050.
           During the first 18 months of this initiative, Alberta’s large emitters achieved 6.5 Mt of GHG reductions through a combination of offsets and process improvements. Companies unable to meet their reduction targets paid about $123 million into the province’s Climate Change and Emissions Management Fund, which will be used to support emissions-reductions technology development.
           In addition, Alberta has committed $2 billion to help implement four commercial-scale carbon capture and storage (CCS) projects in the province. The target of this initiative is to see five Mt of CO2e sequestered annually by 2015. This is the equivalent of taking one million vehicles – or one-third of all registered vehicles in Alberta – off the road. “Long term, the bulk of our emission reductions in our climate strategy will come from CCS,” the province’s Minister of Environment Rob Renner says.
           Oil sands companies have reduced the amount of greenhouse gas emissions per barrel of oil produced by an average 33% since 1990. Suncor Energy Inc., for example, has voluntarily reduced GHG intensity by 51% at its oil sands mining operation near Fort McMurray in northern Alberta. Nevertheless, absolute emissions from Suncor’s plant have increased due to significant production growth.
            When full life cycle GHG emissions are factored in, Canadian oil sands bitumen is comparable with crude oil imported by the U.S. from other countries including Venezuela, Mexico and Nigeria, according to a 2001 study by T. J. McCann & Associates in Calgary and commissioned by the oil sands industry-funded Oil Sands Developers Group.1 Full cycle includes emissions from production, transportation to markets, refining, refining byproducts and end-use consumption.
          However, a 2008 study,2 done by the U.S. National Energy Technology Laboratory and sponsored by NETL’s Office of Coal and Power R&D, found the life cycle GHG emissions from Canadian oil sands to be among the highest among crude oil types imported by the U.S. Canadian oil sands emissions were second-highest after Nigeria’s oil, with Angola’s product having the third-highest life cycle emissions.
          A study published January 20, 2009 by Alex Charpentier at the University of Toronto and other authors, in the journal Environmental Research Letters,3 reviewed 13 studies of GHG emissions associated with oil sands. The authors concluded that there were wide differences among the studies in arriving at GHGs from oil sands (although most studies found life cycle emissions to be higher for oil sands than those for conventional oil), and that “a consensus on the characterization of life cycle emissions of the oil sands industry has yet to be reached in the public literature.”
             The Pembina Institute, a non-governmental environmental policy research group in Alberta, says that producing a barrel of oil from the oil sands produces three times more GHGs than a barrel of conventional oil.
           Joule Bergerson, a researcher at the Institute for Sustainable Energy, Environment and Economy at the University of Calgary, is collaborating with University of Toronto researchers on a life cycle assessment of technologies used in the oil sands industry (see http://www.ucalgary.ca/lcaos/). They are evaluating the industry’s “cradle-to-grave” environmental emissions and other impacts – from the extraction of resources to the disposal of unwanted residuals.
            “We hope to clarify some of the confusion and the ‘spinning’ by all sides that has been going on about oil sands emissions and impacts,” Bergerson says.

Water Management
           In Alberta, about 90% of the water flows through the northern part of the province. Yet about half the province’s population lives in the southern part, where about 88% of the water demand is.
           In 2003, the Alberta government released Water for Life: Alberta’s Strategy for Sustainability. This strategy established 10 watershed planning and advisory councils, with the local knowledge and expertise to assess each of the province’s major watershed basins and develop plans and activities to address issues. An independent review in 2007, by eight environmental and community groups, called the Water for Life strategy “a positive step forward for water management in Alberta . . . If implemented it has the potential to greatly improve the ways Albertans use and think about water and poises Alberta as a leader in protecting watersheds. Water for Life is a well-designed strategy but unbalanced progress in implementing the strategy’s actions has limited its effectiveness to date.”4
           As of 2006, Alberta had allocated more than 9.2 billion cubic metres (325 billion cubic feet) of water for a variety of uses across the province. Ninety-eight percent of this allocation is from surface water sources; the remaining 2% comes from groundwater. Most of the water (45.1%) is allocated to agricultural uses, followed by commercial uses (30.5%) and municipal (11.9%).
           The oil and gas industry is allotted about 7.2% of the water licensed in Alberta, which includes about 1.9% for water- and steam-injection operations to recover oil and gas. Companies are required to investigate alternatives to freshwater for these enhanced recovery operations. Typically, the industry uses about one-third to one-half of its total water allocation, depending on different project stages and life cycles.
            Currently in oil sands pit-mining operations near Fort McMurray, between 2.2 and five barrels of freshwater – depending on the operation – are withdrawn from the Athabasca River to produce each barrel of synthetic oil, the province’s Alberta Energy department says. For in situ operations using steam-assisted gravity drainage technology to extract the bitumen, up to half a barrel of fresh water is required to produce each barrel of bitumen, although this can increase to two barrels or more in some pilot in situ projects. About 90% of the water used by in situ projects is recycled and reused; for mining operations, the figure is 80%.
            Existing oil sands mining operations are currently using 1% of the Athabasca River’s total average flow, and 5% of record low weekly winter flow rates, says Brent Moore, environmental advisor for Devon Canada Corporation. The maximum projected use by existing operations is 2% of annual flow and 10% of record low weekly winter flow rates.
           The Pembina Institute, however, points out that current oil sands mining operations are licensed to divert 349 million cubic meters of water per year from the Athabasca River, or twice the amount of water used by the City of Calgary which has a population of more than one million. At least 90% of this water ends up in oil sands waste tailings ponds, which now cover more than 130 square kilometers, Pembina says.
 
Land Use and Waste Management
          Alberta’s oil sands underlie 140,200 square kilometers (54,114 square miles) or about 37% of Alberta’s boreal forest – an area the size of Florida. The area that can be mined for oil sands is 4,802 km2. The mining area currently under development is 530 km2, or approximately 0.1% of Alberta’s boreal forest.
          More than 65 km2 of disturbed lands are in the process of being reclaimed. In March 2008, the Alberta government issued a reclamation certificate to Syncrude Canada Ltd. for a 104-hectare (257-acre) parcel of land near Fort McMurray – the first piece of oil sands land to be reclaimed in the province.
           The Alberta government and private industry have each invested more than $1 billion in oil sands research, aimed at continuously improving the efficiency and reducing the environmental footprint of oil sands recovery and upgrading.
           Alberta is also implementing a new Land-Use Framework that consists of seven strategies to improve land-use decision making in the province. A key strategy is using cumulative effects management at the regional level to manage the impacts of development on land, water and air. (See sidebar story below).
          “I think Albertans should be proud of their environmental stewardship,” Lukacs says. “We are doing an excellent job in the area of technology and (energy) production practices. We are helping the world to produce more energy more efficiently and, in many cases, in more environmentally friendly ways.”
          In February 2009, the government released a comprehensive oil sands management plan: Responsible Actions: A Plan for Alberta’s Oil Sands. The plan outlined “an integrated approach for all levels of government, for industry, and for communities to address the economic, social and environmental challenges and opportunities in the oil sands regions.” A progress report was issued earlier this year.5
          The Alberta government also has invested at least $7 million on research to speed up reclamation of large oil sands tailings ponds. Oil sands mine tailings consist of bitumen, clay and process water, along with unrecovered hydrocarbons and naphthenic acids; the ponds are a source of methane, volatile organic compounds and hydrogen sulfide emissions.
          Last year, the Energy Resources Conservation Board (ERCB) issued a regulatory order requiring oil sands companies to prepare management plans for their tailings ponds, and reduce fine particles in liquid tailings by 20% by June 30, 2011, and by 50% by 2013. However, in April, a day after Alberta Premier Ed Stelmach said he wanted the oil sands industry to eliminate their liquid tailings ponds within a few years, the ERCB granted Syncrude Canada additional time – ranging from 2016 to 2060 – to clean up its tailings ponds, according to a report in the Calgary Herald newspaper. The ERCB’s decision came as Syncrude was on trial for the deaths of more than 1,600 ducks two years ago on one of its tailings ponds near Fort McMurray.  
Mark Lowey is the managing editor of EnviroLine and the communications director at the Institute for Sustainable Energy, Environment and Economy (ISEEE) at the University of Calgary. This story, sidebar and statistical ‘snapshot’ of energy-and-environment in Alberta first appeared in the June 2010 edition of EM magazine, published by the Air & Waste Management Association.

References:

1. http://www.oilsandsdevelopers.ca/wp-content/uploads/2009/06/GHG-Life-Cycle-in-2007-Aug.-12-08.pdf
2. http://www.netl.doe.gov/energy-analyses/pubs/NETL%20LCA%20Petroleum-Based%20Fuels%20Nov%202008.pdf
3. http://iopscience.iop.org/1748-9326/4/1/014005
4. http://www.toxwatch.ca/files/Recommendations_for_Renewal.pdf
5. http://www.treasuryboard.alberta.ca/docs/Responsible-Actions-Progress-Report-2009.pdf

Alberta’s New Land-use Framework Balances Conservation and Natural Resources Development

By Morris Seiferling
Stewardship Commissioner, Land Use Secretariat
          The Government of Alberta has committed to a new and comprehensive approach to align policy, planning and decision-making to better balance conservation and development of our land and natural resources.
           The Land-use Framework is a significant step forward in the evolution of land-use planning. With the framework, the government is implementing a land-use planning and decision-making system which will help us consider economic, environmental and social opportunities and challenges.
          The establishment of seven planning regions congruent with Alberta’s major watersheds and rural municipal boundaries will enable decision-makers to consider the combined impact of activities on the land, air, water and biodiversity. Regional plans will integrate provincial energy, environment, water, natural resource and other policies at the regional level.
          Under the Land-use Framework, seven strategies to improve land-use decision-making have been identified. The aim of strategy four – conservation and stewardship on private and public lands – is to establish Albertans as environmental leaders through innovative conservation and stewardship practices.
          This strategy will support desired conservation and stewardship improvements in Alberta to achieve regional plan objectives. It will enable individuals, industry, various levels of government and others to make informed land-use choices. And, it will foster individual and collective actions that will ultimately allow for greater growth, but within defined limits that will conserve land and natural resources.
         The Land Use Secretariat is working with the Institute of Agriculture, Forestry and the Environment to develop this strategy, which will include new best practices, market-based approaches and incentives to provide ecological goods and services.
          The next step will be the release of a discussion paper. The Government of Alberta will consult with stakeholders to test the concepts and directions contained in the discussion paper. The paper is supported by four pillars, as established in the framework:
          • identify and develop a toolkit of new best practices, market-based approaches and incentives to provide ecological goods and services;
          • develop education and awareness programs;
          • develop action plans for the conservation and sustainable use of Alberta’s biodiversity that can be used to support and inform development of regional plans; and
          • pursue innovative ways to raise both public and private funds to support conservation and stewardship initiatives.
          The Alberta Land Stewardship Act was proclaimed in fall 2009. It creates the authority to develop and implement regional plans under the Land-use Framework. The legislation enabled four conservation tools currently in the design phase: expanded conservation easements, conservation offsets, transfer of development credits and conservation directives.
           A conservation easement is a voluntary legal agreement to conserve a parcel of land, made between a private landowner and a “qualified organization” that meets certain conservation criteria. Conservation offsets are mechanisms that counterbalance the impacts on ecosystems that result from development activities on public or private lands by offsetting this impact with conservation activities undertaken on other landscapes. These could include conservation and protection, restoration, reclamation, creation or enhancement.
           A transfer of development credits program allows municipalities to direct development away from areas they value for conservation, and towards areas that are better suited to increased urban development. It is a tool that can financially compensate private landowners, such as farmers and ranchers, for retaining the conservation value of their land, while providing developers an opportunity to go beyond existing zoning limits in areas targeted for intensive development by purchasing credits derived from the conserved land.
          A conservation directive is a mandatory conservation tool that applies restrictions on surface use of public or private lands, without the consent of the landowner or disposition holder. Conservation directives can only be used if identified in an approved regional plan. Conservation directives are intended to be applied in situations where a priority conservation action is urgently needed and other tools are unsuitable or unavailable.
          If a conservation directive is expressly established, then the land title holder has the right to compensation equivalent to the decrease of market value in their estate or interest in land resulting from the conservation directive, as of the date the conservation directive becomes effective.
For more information, please visit the Land-use Framework website at www.landuse.alberta.ca 

Energy and Environment in Alberta – By the Numbers
Sources: Government of Alberta (Alberta Energy and Alberta Environment); Canadian Association of Petroleum Producers; Canadian Energy Research Institute; Canadian Centre for Energy Information)

Compiled by Mark Lowey

Economic Impact of Canada’s Petroleum Industry

$40 billion – forecast capital spending by the industry in 2010 across Canada. In 2009, estimated capital spending was $34 billion, while in 2008 it was $54 billion.
$12.2 billion – Alberta oil and gas royalty revenues (fiscal year 2008/2009), which contributed more than 30% of the Government of Alberta’s total revenue. Of this amount, $3 billion in royalties came from oil sands projects.
500,000 – jobs across Canada supported directly or indirectly by the energy industry
170,000 – people directly or indirectly employed in Alberta’s energy industry
44% – percentage of oil sands-related employment outside of Alberta

Future Economic Impact of Canada’s Petroleum Industry (forecast over the next 25 years)
$3.56 trillion – economic impact generated to Canada’s GDP by a $1.09-trillion investment by the petroleum industry
$1.1 trillion – government revenues generated by Canada’s petroleum industry, including:
         • $408 billion in federal tax;
         • $711 billion in provincial tax and royalties
24.5 million person-years (mmp/y) – employment created by Canada’s petroleum industry, including 14.1 mmp/y in Alberta

Alberta’s Oil Sands Resource
1.7 trillion barrels (bbl) – estimated oil contained in the oil sands
175 billion bbl – oil in oil sands reserves (deposits that are recoverable with current technologies), the second-largest oil reserves in the world behind Saudi Arabia
1.31 million bbl – oil sands production in 2008
2.9 million bbl – oil sands production forecast by 2020
73% – percentage of Canada’s oil production forecast to come from oil sands by 2020
80% – percentage of Alberta’s in situ oil sands deposits (too deep to be mined from the surface), recoverable through steam-assisted gravity drainage and other technologies that don’t require mine pits or tailings ponds.
91 – active oil sands projects in Alberta (as of August 2009). Of these, four were producing mining projects; the remaining projects used various in situ recovery methods.

Future Economic Impact of Alberta’s Oil Sands (forecast over the next 25 years)
$1.7 trillion –impact on Canada’s GDP
$170 billion – impact on Canadian economy outside Alberta
$491 billion – amount of government revenues generated by the oil sands, including:
          • federal tax of $188 billion;
          • provincial tax of $118 billion (80% of which is Alberta’s); and
          • Alberta royalties of $185 billion or $7.4 billion per year 
11.4 million person-years (mmp/y) – employment created by the oil sands, which translates into 112,000 jobs and rising to 500,000 jobs over 20 years
2.6 mmp/y – employment generated outside Alberta by the oil sands, mostly jobs in Ontario, B.C. and Quebec

Alberta’s Fossil Energy Resources

Oil
503,000 barrels (bbl) – conventional crude oil production per day in 2008
1.37+ million bbl – amount of crude oil exported daily to U.S. markets in 2008

Natural Gas
87 trillion cubic feet (tcf) – estimated recoverable conventional natural gas remaining in Alberta
500 tcf – estimated coal bed methane (unconventional gas) deposits in Alberta’s coal seams; it is not known yet how much of this is economically recoverable
5 tcf – natural gas produced per year in Alberta (enough to heat every home in the province for about 35 years)
80% – percentage of Canada’s natural gas production that is from Alberta
1.15 billion cubic feet (bcf) – natural gas that Alberta exports daily to the rest of Canada
2.48 bcf – natural gas that Alberta exports daily to the U.S.

Coal
34-37 billion tonnes –coal reserves remaining (70% of Canada’s coal reserves, enough to last for about 400 years at current usage rates)
32.5 million tonnes (Mt) – total marketable coal production in 2008
25 Mt – amount of coal that Alberta uses per year to generate electricity

Alberta’s Electricity Sector
13,000 megawatts (MW) – current generation capacity
5,000 MW+ – new generation facilities built since 1998
521 MW – wind power generation
21,000 kilometers (13,049 miles) – length of transmission lines

Greenhouse Gas Emissions in Alberta
114.4 million tonnes (Mt) – total CO2 equivalent (CO2E) emissions in Alberta in 2007
49.9 Mt – CO2E emissions from Alberta’s utilities sector in 2007 or 44% of the province’s total reported GHG emissions
8.9 Mt – total CO2E emissions from Alberta’s in situ oil sands projects