1. Skip to navigation
  2. Skip to content
  3. Skip to sidebar

Extractives companies’ human rights records ranked in Benchmark study

Developments continue apace in human rights responsibilities for businesses. We are seeing persistent implementation of new reporting requirements across EU jurisdictions and beyond, judgments of national courts and international tribunals holding corporations to ever stricter account for their responsibilities in this area and UN negotiations continuing for a global treaty imposing binding international law obligations on businesses.  Staying ahead of the field in this area is crucial.

While the responsibilities imposed by the UN Guiding Principles on Business and Human Rights (the UNGPs) are not in themselves legally binding, governments’ expectations that companies will step up in this area have been made clear through National Action Plans, parliamentary enquiries and the introduction of “hard” legal requirements, such as under the Modern Slavery Act in the UK.

Now, the Corporate Human Rights Benchmark (CHRB) has ranked 98 of the largest publicly traded companies globally on 100 human rights indicators, focusing on the Extractives, Agricultural and Apparel industries.  These areas were specifically selected because of the high human rights risks they carry, the extent of previous work on the issue, and global economic significance.  41 Extractives companies featured.

The CHRB is a collaboration between investors and a number of business and human rights NGOs. It has emphasised this is a pilot assessment and welcomes input on the methodology used.  The study was compiled from publicly available information, with the selected companies also having the opportunity to submit information to the CHRB.  Companies were given scores for the measures they are taking across six themes, grounded in the framework of the UNGPs:

  • Governance and policy commitments.
  • Embedding respect and human rights due diligence.
  • Remedies and grievance mechanisms.
  • Performance: Company human rights practices.
  • Performance: Responses to serious allegations.
  • Transparency.

The selected companies were then banded according to their overall percentage score.  The performance-related criteria carried greater weight than the policy-based heads, with “Embedding respect and human rights due diligence” and “Company human rights practices” counting for 25% and 20% respectively.

Results skew significantly to the lower bands

There was a wide spread in the participants’ performance, with a small number of clear leaders emerging. No company scored above the 60-69% band, with only three companies falling within that band.  A further three scored 50-59% and 12 scored 40-49%.  48 companies fell within the 20-29% band.

Of the companies in the top band, two were in the Extractives sector; a further six Extractives companies fell within the 40-49% band; 19 scored 20-29% and five were found to trail at less than 19%.

The generally low scores across the three industries may be explained by the fact that the impact of some businesses’ human rights processes may still be filtering through. We should expect that in future years the authors of the survey will adopt a more stringent approach and subject low-scoring businesses to greater criticism.

Gap between policies and performance

On the whole, companies tended to perform more strongly on policy commitments, high-level governance arrangements and the early stages of due diligence. They performed less well on actions such as tracking responses to risks, assessing the effectiveness of their actions, remedying harms and undertaking specific practices linked to key industry risks.  There is often a mismatch between board level measures and their granular implementation, as well as between public responses to serious allegations and taking appropriate action.

Of the Extractives companies surveyed, only six companies scored were given a zero score for their policy commitments, whereas this was the case for 17 companies for “Embedding respect and human rights due diligence” and nine for “Company human rights practices”.

On the policy side, some Extractives companies scored points for emerging practices such as regular discussion at board level of the company’s human rights commitments, linking at least one board member’s incentives to aspects of the human rights policy, and committing not to interfere with activities of human rights defenders, even where their campaigns target the company.

In terms of implementation, some participants explained how human rights risks are integrated into their broader risk management systems, how they monitored their commitments across their global operations and business relationships, and how they had systems in place for identifying and engaging with those potentially affected by their operations.

Companies were also scored for their practices in relation to selected human rights specific to each industry. Those in which the Extractives participants featured included freedom of association and collective bargaining, health and safety, land acquisition, water and sanitation and the rights of indigenous people.

Conclusion

The significant interest in the CHRB since it began its work is unsurprising given it provides an opportunity to demonstrate commitment and progress in this area vis-à-vis competitors. The pilot methodology will be refined and ultimately the CHRB will be produced on an annual basis for the top 500 companies globally.  We expect it to contribute to the continued drive of companies across all sectors to proactively manage human rights risks in their own operations and through their expectations of their business partners.

Extractives companies’ human rights records ranked in Benchmark study

Alberta unveils Renewable Electricity Program: The beginning of the end for the energy-only market?

On November 3, 2016, the Alberta government released the details of its long-awaited plan to accelerate the development of renewable power generation in the province through an auction-based procurement process—a key plank of the Climate Leadership Plan it announced in 2015.

The Renewable Electricity Program (REP) will be launched in early 2017 with an initial, three-stage procurement process for up to 400 MW in new or expanded renewable generation.  Winning bidders will be awarded payments under a “Renewable Electricity Support Agreement” (RESA) that would grant fixed, market-insulated prices for a 20-year term, similar to Ontario and other jurisdictions.

The REP represents a clear, if incremental, change of course for Alberta’s “energy-only” electricity market model—one that will offer significant opportunity to prospective renewable developers if the 2017 auction succeeds.

Background:  The Climate Plan and the AESO’s role

In late 2015, the Alberta government, acting on the recommendations of a Climate Change Advisory Panel (Climate Panel), released its Climate Leadership Plan, a four-pronged “policy architecture” to address climate change in the province.

Beyond its plans for an economy-wide carbon tax, a 100 Mt oil sands emissions cap and a methane reduction plan, the Climate Plan includes a commitment to “30 by ’30”:  to increase the generation share of renewables in Alberta to 30 percent by 2030. To that end, the Climate Panel recommended setting up an open, competitive request for proposals process and incentive payments bounded by a “price collar” (or limit to government support) of CA$35/MWh.  The Panel otherwise saw no need for a change in Alberta’s “energy-only” electricity market.

The “30 by ’30” goal coincides with the Climate Plan’s announcement of a planned phase-out of all of Alberta’s coal-fired generation by 2030. This will be a significant undertaking: based on Alberta Energy 2015 statistics, coal supplies fully half of Alberta’s power requirements.

In January 2016, the Alberta government assigned the Alberta Electric System Operator (AESO) the task of developing specific recommendations on the REP, noting that the government “has not chosen to fundamentally alter the current wholesale electricity market structure.” In the first half of 2016, the AESO launched a stakeholder engagement process and retained economic and financial consultants to study options.

The AESO’s report and the Renewable Electricity Program

On November 3, 2016, the Alberta government publicly released the AESO’s May 2016 Renewable Electricity Program Recommendations report (AESO Report) and adopted its recommendations as the REP.

Speaking at the Canadian Wind Energy Association’s annual conference, Minister Shannon Phillips claimed that the REP would inject some CA$10.5 billion into the Alberta economy by 2030 and create 7,200 jobs. The policy is to be implemented through enacting a Renewable Electricity Act in late 2016.

(a)  The REP payment mechanism: Loosening the “collar”

The REP aims to incent the addition of 5,000 MW in installed renewable generation by 2030 through a series of AESO-administered auctions. As described by the AESO, the “[w]inning bidder bids a price that is, in essence, its lowest acceptable cost for the renewable project the bidder plans to advance.” Successful bidders are awarded the right to guaranteed per-MWh prices for 20-year terms via “top-up” support payments enshrined in a RESA.

The RESA payment mechanism, financed by carbon revenues from large industrial emitters, operates as a so-called “Contract for Differences.” To compensate for low Alberta power market prices relative to renewable costs, RESA payments add to the generator’s market revenues and recede as the market price rises toward the generator’s bid price. If the market price exceeds the generator’s bid price, the generator pays its above-bid revenues to the government.

Interestingly, this “indexed” approach was criticized in the November 2015 Climate Panel report on the basis that it would remove market price–based incentives for higher-value (rather than simply higher-capacity) power projects and “likely trigger a land rush for the best wind resources in the province.”

The AESO Report, on the other hand, indicates the opposite concern with the Climate Panel’s CA$35/MWh support “collar”—noting that consulted lenders were of the view that it left power projects unfinanceable. The AESO expects the RESA’s “uncollared,” indexed approach to attract more extensive bidder interest by offering greater revenue certainty to developers (and by placing price risk with Alberta). The likely result, in the AESO’s estimation, is a more competitive auction featuring lower bid prices.

(b)  The 2017 REP bid process

Alberta has indicated its intention to stage and complete its first REP procurement in 2017. For the AESO’s first round, qualifying projects must:

  • be based in Alberta;
  • be new or expanded (existing projects are not eligible);
  • be 5 MW or greater in size;
  • meet Natural Resources Canada’s definition of a “renewable” source;
  • connect to existing transmission or distribution infrastructure; and
  • be operational by the end of 2019.

The requirements of an existing grid connection and a 2019 in-service date may constrict the 2017 bidder pool. In particular, the AESO Report itself acknowledges the challenges developers may face in obtaining the requisite regulatory approvals in time to energize in 2019.

The auction process is to follow three stages, each monitored by an appointed “Fairness Advisor”:

  • Request for Expressions of Interest (REOI): in which the AESO has the opportunity to attract and gauge interest in the auction and receive feedback (4-6 weeks);
  • Request for Qualifications (RFQ): in which eligibility requirements are released and bidders submit their qualifications (including in respect of project eligibility, financial strength and capacity, and construction and operations capability), and a non-refundable “Pay-to-Play” fee is paid by participants (4-6 months); and
  • Request for Proposals (RFP): in which qualified bidders provide security for their bids, make final, binding offers and a winning bidder is selected (2-3 months).

The auction process will be “fuel-neutral”; the AESO is not setting quotas for, or otherwise favouring particular sources. Notably, for the first auction, there is also no provision for crediting Aboriginal or community aspects of a project, as in Ontario’s FIT programs, and as was contemplated by the Climate Panel. The AESO Report instead insists that qualified bidders strictly “be selected on based on lowest price (subject to any affordability ceiling).”

The government has indicated that stakeholder engagement on the 2017 auction’s draft commercial terms will begin on November 10, 2016.

Does the energy-only market have a future?

Since Ontario’s foray into procuring contracted, renewable forms of generation began in 2004, the share of the province’s generation under contract—without exposure to the market price—has risen to 65 percent, according to data from a 2015 Independent Electricity System Operator (IESO) report. Many commentators have described Ontario’s market as a “hybrid” system, characterized by high levels of policy intervention, steeper costs and the effective abandonment of market price as a generation investment signal.

The introduction of market price–insulated generation envisioned by the REP promises, at least at this juncture, to be more incremental than Ontario’s sweeping example. The Climate Plan and AESO Report both contemplate the maintenance of Alberta’s wholesale market system and prioritize, in express terms, cost containment. The increasing price-competitiveness of renewable sources, too, may cushion the cost increases seen in early-adopting jurisdictions. Finally, as noted by the Climate Panel, Alberta continues to reap the benefit of an abundant, low-priced gas supply in transitioning away from coal.

Notwithstanding this, the eligibility of generators for RESA payments—especially given the low market prices and rising costs of the current environment—may itself “result in other generators demanding the same treatment (i.e. some kind of guaranteed revenue stream),” as the AESO acknowledges in its report. Elsewhere, the AESO Report presents a grim diagnosis for non-renewable investment, noting that “there has been a significant erosion of the support for investing in the energy-only markets in Alberta (and elsewhere) given [that] market and policy is undermining confidence.” It remains to be seen whether the REP’s policies, as in other places, signal a broader trend away from energy-only markets; are themselves overtaken by political opposition in a contested election; or find their place in a market framework that has, to date, proven adaptable to Alberta’s ever-changing climate.

This post was co-authored by Joseph Palin and Bernard Roth, Partners in Dentons’ Calgary office.

Alberta unveils Renewable Electricity Program: The beginning of the end for the energy-only market?

Aviation emissions – new global deal looks likely

Government officials are negotiating a market-based mechanism to reduce emissions in the international aviation industry. Ministers from over 190 countries have gathered at the International Civil Aviation Organization’s General Assembly in Montreal to discuss and vote on a draft resolution. If passed, it will be the first industry-specific global market-based measure for CO2 emissions.
The prospects of achieving resolution are good. So far, 55 countries, including the US, China and EU member states have indicated their support for the proposal and agreed to sign-up for the initial voluntary stage. However, some states with large aviation emissions have yet to confirm their agreement and the EU has questioned how effective the measure will be in combatting climate change. A deal is expected by the end of the Assembly on 7 October.
The proposal aims to prevent the growth of aviation emissions beyond 2020 levels by requiring airlines to offset emissions with carbon credits. The mechanism would take effect on a voluntary basis from 2021, and become mandatory in 2027 with exceptions for some states which are less developed or have low aviation emissions. The offsetting obligations will be based on the sector average emission growth, and later move to incorporate the actual emission growth of individual airlines.

, , , ,

Aviation emissions – new global deal looks likely

Insolvency and energy insights: The Redwater decision

The Alberta Court of Queen’s Bench decision in Redwater Energy Corporation Re, 2016 ABQB 278, written by Chief Justice Neil Wittmann, clarifies that the provisions of the Bankruptcy and Insolvency Act (BIA) addressing the environmental liability of trustees render certain provisions of provincial regulatory legislation addressing wells and pipelines inoperative to the extent they conflict with the BIA.

This is a significant decision that will directly impact the conduct of oil and gas receiverships and bankruptcies in Alberta, and affect the position of secured creditors in those proceedings.

You can find Dentons’ commentary on this decision in our recent Insights publication found here.

Insolvency and energy insights: The Redwater decision

Alberta’s Metis Consultation Framework

On April 4, 2016, the Government of Alberta (“GoA”) released The Government of Alberta’s Policy on Consultation with Metis Settlements on Land and Natural Resource Management, 2015 (the “Policy”) as well as The Government of Alberta’s Guidelines on Consultation with Metis Settlements on Land and Natural Resource Management, 2016 (the “Guidelines”). Additional information on the Policy and the Guidelines including the text of each can be found here.

The modest aim of this post is to outline some of the key features of the Policy and Guidelines as they relate to energy project proponents.

Alberta Metis Settlements

The term “Metis” refers to people of mixed European and indigenous heritage who developed their own customs, way of life, and recognizable group identity separate from their settler or indigenous ancestors. Metis people are expressly included within the definition of “aboriginal peoples of Canada” in section 35 of the Constitution Act, 1982. Accordingly, Metis practices that were historically important features of these distinctive communities and that persist today as integral elements of Metis culture are constitutionally protected. According to the Alberta Indigenous Relations website, approximately 5,000 people live on the eight Metis Settlements in the province which collectively cover 1.25 million acres in the central and northern part of the province.

Policy and Guideline Highlights

The stated objective of the Policy is to establish a meaningful consultation process to address potential adverse impacts to Metis Settlement members’ harvesting or traditional use activities. The Guidelines are intended to clarify expectations of all parties participating in the consultation process including project proponents, the Aboriginal Consultation Office (the “ACO”), Metis Settlements, and government agencies.

According to the Policy, and consistent with Supreme Court of Canada decisions on Aboriginal consultation, the GoA policy is to consult with Metis Settlements when:

  1. GoA has real or constructive knowledge of Metis Settlement members’ harvesting or traditional use activities;
  2. GoA is contemplating a decision relating to land and natural resource management; and
  3. a GoA decision has the potential to adversely impact the continued exercise of Metis Settlement members’ harvesting or traditional use activities.

The Policy, therefore, will impact not only strategic resource planning decisions made by the GoA, but also project specific decisions including land dispositions, facility and pipeline approvals, and water use authorizations. It will not, however, apply to leasing or licencing Crown mineral rights.

Borrowing from the GoA’s approach to consultation with First Nations, the Guidelines establish a framework for determining the level of consultation required based on the impact of the project and the sensitivity of the affected location. The level of consultation informs how deep the consultation should be, what process steps are required, and the timelines for completing consultation.

The Policy lists a number of “guiding principles” which it considers will lead to meaningful consultation. These guiding principles will generally not surprise energy project proponents who are accustomed to engaging with First Nations. In some cases, the guiding principles provide reassurance regarding the GoA position on consultation. Notably, the guiding principles include the following:

  • Consultation will take place with the Metis Settlements, not their individual members;
  • GoA will consult with honour, respect, and good faith, with a view to reconcile Metis Settlement members’ harvesting and traditional use activities with the GoA’s mandate to manage provincial Crown lands and resources for the benefit of all Albertans;
  • Consultation requires all parties to demonstrate good faith, reasonableness, openness, and responsiveness;
  • Metis Settlements have a reciprocal onus to respond with any concerns specific to the anticipated Crown decision in a timely and reasonable manner and work with Alberta and project proponents to resolve issues as they arise during consultation;
  • Consultation does not give Metis Settlements or project proponents a veto over Crown decisions nor is the consent of Metis Settlements or project proponents required as part of Alberta’s Consultation process.

The Policy and Guidelines contemplate direct consultation by the GoA as well as GoA delegation of procedural aspects of consultation. In either case, the ACO will “direct, monitor and support consultation activities”. ACO support includes providing staff to assist with consultation, advising both Metis Settlements and proponents when disputes arise, and evaluating consultation records. Energy project proponents will recall that the Alberta Energy Regulator (“AER”) has no authority under the Responsible Energy Development Act to assess the adequacy of Crown consultation. In matters before the AER, the ACO will make a consultation adequacy determination and advise the AER of its decision.

For their part, project proponents may need to carry out certain tasks if the GoA decides to delegate procedural aspects of the consultation process. The Guidelines state that “proponents are encouraged to notify and consult with Metis Settlements as early as possible in the pre-application stage”, “document their consultation activities, share their consultation record with Metis Settlements and provincial staff and advise the GoA of any issues that arise”. The Policy and Guidelines identify a number of consultation activities that may be passed to proponents, such as providing Metis Settlements with plain language information on the project, meeting with Metis Settlements to discuss their concerns, developing and implementing mitigation strategies, and preparing consultation records.

Finally, the Guidelines state that “although the optimal outcome of consultation is that all consulting parties reconcile interests, agreement of all parties is not required for consultation to be adequate”.

Comments for Energy Project Proponents

The Policy and Guidelines closely model the GoA’s approach to engaging with First Nations in Alberta and will be familiar to many project proponents. They serve as a useful starting point for setting expectations on how consultation will proceed and the roles of each party. However, they are just that – a starting point.

The Guidelines acknowledge that consultation must remain flexible. They do not state, however, whether Metis Settlements will be consulted on how the Policy will be implemented in any given case. Further, while the Policy and Guidelines clearly contemplate delegating consultation activities to proponents, there is no commitment by the GoA to communicate the fact of delegation to the concerned Metis Settlements.

Clear communication at every stage of the consultation process is important to avoid delays as the process unfolds. Proponents should ensure from the outset when they undertake delegated consultation activities, such as in-person meetings, that the Metis Settlement representatives understand the consultation activities were delegated and are meant to contribute to fulfilling the Crown’s duty to consult.

Alberta’s Metis Consultation Framework

Daniels v. Canada: Métis and non-status Indians fall under Parliament’s legislative authority

On April 14, 2016, the Supreme Court of Canada (SCC) rendered its decision in Daniels v. Canada (Indian Affairs and Northern Development), 2016 SCC 12.

Members of the Dentons Canada LLP Aboriginal Law practice addressed the significance of the decision in their latest Insights post. You can find that post here.

Daniels v. Canada: Métis and non-status Indians fall under Parliament’s legislative authority

Estimating Upstream GHG Emissions

On Saturday, March 19, 2015, the Department of Environment and Climate Change Canada (“ECCC“) published its proposed methodology for estimating the upstream greenhouse gas (“GHG“) emissions associated with “major oil and gas projects” undergoing federal environmental assessments (“proposed methodology“) in the Canada Gazette.

The Government of Canada (“GOC“) announced in late January that it intended to “restore confidence in Canada’s environmental assessment processes”. Dentons’ commentary on that announcement can be found here. As part of that announcement, the GOC articulated five principles for how it would exercise its discretionary decision making authority for projects undergoing federal environmental assessments. Among the five principles was a commitment to assess “upstream greenhouse gas emissions linked to projects under review”. The proposed methodology published in the Canada Gazette has not yet been finalized. Interested parties, including industry stakeholders, have 30 days from the publication date (until April 18) to comment on the proposed methodology.

The proposed methodology begins by providing a definition of what ECCC considers “upstream” for the purposes of its estimating GHGs associated with a project. It then sets out two parts of its proposed approach to assessing upstream GHG emissions.

Defining “upstream”

The proposed methodology defines “upstream” to be all industrial activities from the point of resource extraction to the project under review. Apparently anticipating questions on what this definition means for crude oil pipeline projects, ECCC gives several examples of “upstream” activities for such projects:

  • Extraction – crude oil and gas wells and oil sands mining and in situ facilities;
  • Processing – field processing and upgrading, if occurring;
  • Handling – products transfer at terminals; and
  • Transportation – any pipeline operation in advance of the project.

The activities considered “upstream” would depend on the project under review.

The Proposed Methodology

We are told that the assessment of upstream GHGs will consist of two parts. The first part is a relatively straight forward quantitative estimation of emissions released from upstream production associated with the project. The second part is a more opaque “discussion” of the project’s potential impact on Canadian and global GHG emissions.

The quantitative component of the assessment will focus on emissions from upstream activities “exclusively linked” to the project being assessed. How ECCC will decide whether something is “exclusively linked” to a project is unclear. The quantitative assessment will not include “indirect emissions” which, for the purposes of the proposed methodology, would include matters such as manufacture of equipment and fuels “produced elsewhere”.

The quantitative assessment begins by determining expected throughput of each “component” (e.g. heavy oil and diluent as separate components) in the product stream. ECCC will rely on project proponent data for this information. Though not expressly stated, information contained in a publicly available application, such as one filed with the National Energy Board would likely be considered.

Next, each product component will be assigned an emission factor using ECCC emissions data, among other information sources. Because different product components will involve different extraction, processing, handling and transportation activities, the emissions factors applied in a given assessment would reflect those differences.

Multiplying the emissions factor for a given component by the throughput of that component (taking into account a vaguely defined “adjustment”) provides the upstream emission for a given component. Upstream emissions for each component would then be totaled to provide the upstream emissions for the entire project.

The second stage to the proposed methodology is a “discussion” that is intended to accomplish two objectives. First, the discussion will assess conditions under which the upstream emissions associated with the project could be expected to occur even without the project. Second, the discussion will consider the potential impact of the project’s emissions on overall Canadian GHG emissions and on Global GHG emissions.

To inform the discussion, ECCC will examine current production levels, the trajectory of future production with and without the project, as well as potential markets for future resource production.

The next stage of the “discussion” is to evaluate “technical and economic potential” for alternatives to be used in absence of the proposed project. The proposed methodology then considers the various alternatives and “discusses the potential implications for Canadian and Global upstream GHG emissions”.

The outstanding issues

When the GOC first articulated the five principles, including the commitment to assess direct and upstream greenhouse gas emissions, its stated intention was to provide greater certainty on how it would exercise its discretion on projects undergoing a federal environmental assessment. This proposed methodology, once finalized, will give proponents some understanding of how ECCC will assess upstream emissions. However, proponents are arguably no closer to understanding how the GOC will exercise its discretion on individual projects.

The proposed methodology gives only a high level overview of how upstream GHGs will be assessed and is vague in a number of respects. For instance, it is not clear how “the technical and economic potential for alternative modes of transportation” will be evaluated. If a proposed pipeline has more “economic potential” or is considered safer than the hypothetical rail alternative, will that tilt the scale in favour of the proposed project for the purposes of an upstream GHG assessment? The proposed methodology also includes a fleeting reference to comparing emissions intensity between Canadian and non-Canadian crude oil sources. What crude oil sources will be used as the comparator or how “upstream emissions” from those non-Canadian-sources will be quantified is anyone’s guess.

The most significant issue outstanding from the perspective of a project proponent is the lack of guidance on how the National Energy Board, ECCC, or the Governor in Council, as the case may be, will exercise its discretion to approve or recommend approval of a project based on its GHG emissions. Will projects be given a green light regardless of the upstream GHGs they facilitate? At the other end of the spectrum, will any increase in Canadian or global GHG emissions from a project be enough to delay or halt a proposed project? The true answer presumably lies somewhere in the middle. The problem from the prospective of a proponent contemplating a substantial investment is that there is no way to assess this potential roadblock.

 

Estimating Upstream GHG Emissions