After months of very public wrangling culminating on November 8 with a full page ad taken by Quebec’s gas utility in the Globe and Mail opposing the Energy East Pipeline, followed a week later with the embarrassing leakage of TransCanada’s 2014 Quebec communication strategy, Quebec’s government has had enough and has taken control of the process in the province. The purpose is to dial down the rhetoric and provide a calmer and more structured environment within which to evaluate the pipeline.Continue Reading...
On Tuesday (November 18, 2014), the U.S. Senate defeated Bill S. 2280 (the Bill), a bill to approve the Keystone XL pipeline. Approval of the Keystone project was stopped by a single vote, as the Bill received only 59 of the 60 affirmative votes required to continue forward in the legislative process. Shortly after the vote, Senator Mitch McConnell, the Senator of Kentucky and the incoming U.S. Senate majority leader from the Republican Party spoke on the Senate floor and stated that he would reintroduce a bill in support of the Keystone XL pipeline once the new Senate convenes in the new year. In 2015, the Republican Party, which has traditionally been in support of Keystone, will control both the U.S. Senate and the U.S. House of Representatives for the first time in eight years. It is also important to note that even if both the U.S. House of Representatives and the U.S. Senate approve the Keystone XL pipeline, President Obama still has the power to veto approval of the project. However, the U.S. House of Representatives and the U.S. Senate together may override a presidential veto in certain circumstances.
Bill H.R. 5682 (the Bill) to approve the Keystone XL Pipeline was passed in the U.S. House of Representatives today (November 14, 2014). The Bill was approved with 252 representatives voting in favour of approval and 161 representatives voting against it. Approval of the Bill marks the ninth time the U.S. House of Representatives has approved the Keystone XL project.
On Tuesday, November 18, 2014 the Bill will be considered by the U.S. Senate. Although the Republicans, who have traditionally been supporters of the Keystone XL project, regained the majority of the U.S. Senate in the recent midterm elections, the new Senators-elect will not be sworn in until the new year. Moreover, it is important to note that even if the Senate approves the Bill, President Obama has the presidential power to veto passage of the Bill. However, a presidential veto may be overridden by the U.S. Congress in certain circumstances.
To date, the Keystone XL pipeline has been delayed for roughly six years due to environmental reviews, legal challenges to the route of the pipeline and political opposition.
On October 21, 2014, the Liquefied Natural Gas Income Tax Act (the “Bill”) was introduced into British Columbia’s Legislative Assembly. The Bill reflects the culmination of the Province’s goal to introduce an LNG tax framework which was initially unveiled in February 2014. The introduction of the Bill is the most significant step taken to date in the B.C. Government’s effort to create a tax framework for the province’s LNG sector.
The primary purpose of the Bill is to introduce a tax regime (the “LNG Tax”) with two fundamental components:
- A tier 1 tax of 1.5% of “net operating income” (as defined); and
- A tier 2 tax at an initial rate of 3.5% of “net income” (as defined).
As set out in the Bill, the LNG Tax will apply to the income from all liquefaction activities in British Columbia. The 3.5% “net income” tier 2 tax is effective for taxation years beginning on or after January 1, 2017. The 1.5% “net operating income” tier 1 tax (i) applies during the period when net operating income exceeds the sum of net operating losses and the capital investment deduction and (ii) is creditable against the 3.5% tier 2 tax. In 2037, the tier 2 tax will increase to 5% of net income. Note that the tier 2 tax has been significantly reduced from the “up to 7%” rate contemplated in the initial version of the framework that was announced in February 2014.
In this article, we discuss the LNG Tax Framework and identify a number of issues and uncertainties arising from the Bill. As any such discussion is necessarily limited in its scope and detail, it is important that readers seeking to understand the implications of the Bill for themselves or their businesses consult experienced counsel with knowledge of their particular situations.Continue Reading...
The last few months have seen a number of regulatory developments in Canadian capital markets that may specifically affect companies in the oil and gas industry. Below, we’ve compiled a list of key legal developments since July 1, 2014 that may be of particular interest, along with corresponding links to our securities blog.
- TSXV approves the completion of three oil and gas team-led recapitalizations of shells by written consent of a majority of shareholders (five in total since December 2013).
- TSX circuit-breaker rules are expanded to all actively traded stocks (more than 500 trades a day and average $1.2M in value per day).
- Canadian regulators adopt rules for the disclosure of gender diversity and other board composition issues by non-venture issuers. These requirements apply in the 2015 disclosure cycle.
- Canadian regulators announce the outcome of the joint continuous disclosure review of more than two hundred issuers — key issues included revenue recognition in financial statements and non-GAAP measures in MD&A.
- TSX publishes Electronic Communications Disclosure Guidelines and provides guidanceon using social media — confirms the importance of factual statements that avoid selection disclosure.
- Amendments to the rules governing auditor oversight provide for disclosure of CPAB remedial orders, certain changes to rules involving foreign audit firms and other procedural matters.
- The ASC decision in Haggerty confirms that an “impression, speculation or abstract possibility” does not constitute material information.
Federal Government introduces legislation to mandate disclosure of payments by extractive industry participants
The Government of Canada yesterday introduced legislation to implement the Extractive Sector Transparency Measures Act, following through on the announcement by Prime Minister Stephen Harper in June 2013 that Canada would be establishing new mandatory reporting standards for extractive companies directed at payments made to foreign and domestic governments at all levels, including Aboriginal groups. The Government of Canada has stated that the legislation is intended to be similar to that being implemented in the European Union, and is anticipated to be similar to that expected to be proposed by the United States Securities and Exchange Commission by March 2015.
It is also intended that the Canadian legislation be implemented in a manner that allows for reporting requirements that are uniform across these jurisdictions so as to reduce associated administrative costs for affected companies.
Given that the United States has thus far not introduced comparable legislation, it will be interesting to monitor whether the ultimate orientation and implementation of the Canadian legislation is modified to align with the initiative south of the border. While the SEC introduced a rule under Section 1504 of the Dodd-Frank Act in 2012 to require disclosure of payments by resource extraction issuers, the U.S. District Court for the District of Columbia, in American Petroleum Institute v. SEC, concluded, among other things, that the SEC misinterpreted Dodd-Frank by forcing public disclosure of detailed data on payments, and failed to consider associated competitive effects. Following the ruling the SEC has taken no further regulatory action, although the SEC has indicated that it would issue a new proposal under Section 1504 by March 2015.Continue Reading...
Earlier today, the Liquefied Natural Gas Income Tax Act (the “Bill”) was introduced into the British Columbia legislature. The Bill reflects the culmination of the Province’s goal to introduce an LNG tax framework, which was initially unveiled in February 2014. The Bill provides for a tier 1 tax rate of 1.5% and a tier 2 rate of 3.5%. The LNG tax applies to the net income from all liquefaction activities in British Columbia.
Effective for the taxation years beginning on or after Jan 1, 2017, the tax rate on net income will be 3.5%. During the period when net operating losses and the capital investment are being deducted, the tier 1 tax rate of 1.5% will apply and is creditable against the 3.5% tier 2 tax. In 2037, the tier 2 rate will increase to 5% of net income. The tier 2 rate set out in the Bill represents a significant reduction from 7% contemplated in the initial framework announced in February.
Since the valuation of revenues, expenses and the cost of capital investment are central to the calculation of the tax, the Bill provides a special set of rules for non-arm’s length transactions applicable to integrated LNG projects and companies, however, there is still significant uncertainty that exists with respect to the application of these rules.Continue Reading...
On Friday, September 14, Ottawa announced the ratification of the Canada-China Foreign Investment Promotion and Protection Agreement (the Canada- China FIPA). The Canada-China FIPA, which comes into force on October 1, 2014, is the newest addition to Canada’s growing list of foreign investment protection agreements (FIPAs).
A FIPA is not a full-blown free trade agreement, but rather a bilateral agreement between two signatory states intended to protect and promote foreign investment through legally-binding rights and obligations to protect foreign investors. Specifically, a FIPA grants foreign investors from each signatory state the right to claim damages against the host state when the guarantees contained in the FIPA are contravened. These claims are heard by international arbitration tribunals, which have the power to grant legally binding awards against host states, and whose decisions are not reviewable by domestic courts.Continue Reading...
Much media attention (including this blog) has been devoted to following the developments of British Columbia’s nascent LNG Export industry. At the same time potential LNG Export Projects on Canada’s East Coast are slowly gaining momentum. The following chart sets out LNG Export Projects on Canada’s East Coast that have been announced to date.
PARTNERS ON PROJECTS
Pieridae Energy Ltd.
(*Repsol has publicly indicated that it is considering converting this import facility into an LNG Export Terminal)
Repsol YPF SA/Irving Oil
Not yet announced
H-Energy LNG Project
Bear Head LNG Project
Liquefied Natural Gas Ltd.
Recently, our firm’s Calgary office completed a review of M&A themes and deal terms in the oil and gas sector for the first half of 2014. This study contains a list of oil and gas M&A transactions over the six month period, a review of key trends in deal terms, a summary of notable features of each transaction, an analysis of the timelines and a numerical analysis of key deal terms.Continue Reading...
The various LNG Export Terminals proposed to be built in British Columbia may be subject to environmental assessment (or EA) under both the Canadian Environmental Assessment Act, 2012 and the British Columbia Environmental Assessment Act. The EA process, whether under the Federal or Provincial legislation, examines projects to identify adverse environmental, economic, social, heritage and health effects that may occur during development and operation of proposed facilities. The EA process includes involvement/consultation with interested parties such as First Nations and working groups, technical studies and the development of comprehensive reports.
In order to minimize duplication and streamline these generally similar Federal and Provincial processes, the Canadian Environmental Assessment Agency (CEAA) and the British Columbia Environmental Assessment Office (the BC EAO) have entered into a Memorandum of Understanding on the Substitution of Environmental Assessments with the Canadian Environmental Assessment Agency (the MOU). The MOU provides a mechanism for the CEAA to issue a Substitution Order and to effectively substitute the BC EAO’s process for its own and to rely on the record established by the BC EAO in conducting its EA of projects located in BC, such as the LNG Export Terminals. Any such Substitution Order is subject to certain terms and conditions including as to the general nature of the process to be run by the BC EAO and also clearly preserves the right of the Federal government to exercise any judgement or discretion which it may possess under applicable Federal legislation as it sees fit. However the MOU does at least hold out the prospect of reducing unnecessarily duplicative proceedings.Continue Reading...
In the oil and gas regulatory sphere, Q2 marked the implementation of the third and final phase of the Alberta Energy Regulator’s new mandate under the Responsible Energy Development Act (REDA). In addition to the “energy resources enactments” over which it previously had jurisdiction in its former incarnation as the Energy Resources Conservation Board, the Alberta Energy Regulator (AER) has now assumed jurisdiction over various provisions in certain “specified enactments”, including the Public Lands Act, the Environmental Protection and Enhancement Act and the Water Act insofar as those provisions relate to “energy resources activities” (i.e. oil and gas operations and coal mining, but not power generation or electricity transmission and distribution).
Whereas the proponents of energy resources projects previously obtained Crown surface dispositions and environmental approvals from Alberta Environment and Sustainable Resource Development (AESRD), all requisite approvals can now be obtained under the single umbrella of the AER. Whether this will actually result in the intended efficiency gains of one-stop-shopping remains to be seen as the AER is only just beginning to dig itself out from under the thousands of applications transferred over to it from AESRD.Continue Reading...
The short take on energy trends in the last two quarters is “what a difference a Polar Vortex can make”. That weather phenomenon is partly responsible for a change in the current and the predicted future prices of natural gas. The winter heating season ended with significantly lower quantities of gas in storage than usual. As well, the demand for gas continues to escalate with gas continuing to replace coal as a power generation fuel.
That and other factors contributed to a strong revival of M&A and financings in the sector. Much of that activity was focused on natural gas properties. The dollar value of deals done to date has already passed last year’s record low levels of activity.
Q1 saw the CNRL purchase of Devon’s Canadian conventional properties (C$3.13B), Baytex’s purchase of Aurora (C$2.6B), Whitecap’s purchase of properties from Imperial Oil (C$855M), Tourmaline’s purchase of Santonia (formerly Fairbourne) (C$189M), IOC’s purchase of 10% of Petronas’ BC gas reserves, and other transactions.Continue Reading...
As we’ve previously discussed on this blog, the increased interest in exporting liquefied natural gas offers Canadian producers the opportunity to access international markets and higher international prices. Notably for producers, the requirements for approval by the National Energy Board for LNG projects over the last few years have eased significantly.
The earliest decisions were made under the NEB’s surplus determination procedure, called the Market-Based Procedure, that had been established in 1987, during the early days of oil and gas deregulation in Canada. The first LNG export licence was granted to KM LNG and involved the filing of detailed gas supply information, an oral hearing, multiple submissions and the production of long and complex reasons. BC LNG Export Co-operative obtained the second licence following a written hearing process.Continue Reading...
The recent provincial budget in British Columbia included a basic framework for taxes and royalties on the liquefaction of natural gas at LNG facilities in the province. Although the specifics of the LNG tax have not yet been announced, in connection with the budget the province recently released an “Analysis of the competitiveness of BC’s proposed fiscal framework for LNG projects” prepared by Ernst & Young for the Ministry of Natural Gas Development.
It is interesting to compare the hypothetical set of assumptions set out in the E&Y Analysis regarding the intensity of development which the province is assuming compared to the historical growth in other countries such as Qatar and Australia.Continue Reading...
The proposed introduction of an anti-treaty shopping rule in Canada would impact non-residents looking to invest in the Canadian oil and gas industry in order to obtain capital appreciation. For this and other reasons, yield-based products could become more attractive to non-residents and, particularly, U.S. residents. For instance, non-residents dealing at arm’s length with a Canadian corporation can generally capitalize the corporation with high yield debt without being subject to any debt:equity restrictions or Canadian withholding taxes. Consequently, in these circumstances, the Canadian corporation can be leveraged beyond the 1.5:1 debt:equity ratio and non-participating interest payments made to non-resident investors would be deductible by the Canadian corporation and received by such investors without the incidence of Canadian withholding tax.
Recently, our firm’s Calgary office completed a review of M&A themes and deal terms in the oil and gas sector for 2013. This study contains a list of oil and gas M&A transactions over the last year, a review of key trends in deal terms, a summary of notable features of each transaction, an analysis of the timelines and a numerical analysis of key deal terms.
The year started slowly with nine deals announced in H1. The market announced 10 deals in H2, trailing the equity uptick that occurred in the last half of the year by some distance. This made for a long 12 months for public equity holders, management, employees and advisors. The landscape in 2013 was dominated by privatizations, financial buyers, service deals and very small transactions. Domestic and international strategic buyers were absent from the market and were responsible for the dramatic decline in activity. The highlights were colourful, but somewhat downbeat.Continue Reading...
During President Obama’s State of the Union address on January 28th, he made his intentions clear that he would use his authority to continue to push forward new standards and regulations that would curb the amount carbon pollution US power plants are allowed to dump into the air. Further still, Obama stated that the United States must “act with more urgency” citing continuing climate changes which have seen droughts and floods affect North American cities in recent years. Canadians must watch these developments for potential implications for business.
In furtherance of these positions, Obama has directed the EPA to issue a draft of a regulation that would set new national standards for carbon pollution by June 1st of this year. It appears the brunt of these changes will target coal-fired power plants, likely forcing hundreds of plant closures throughout the country, and, as such, coal-heavy states have lobbied the EPA extensively with respect to the stringency of the standards to be set in the impending regulation.Continue Reading...
While expectations remain high as to the magnitude and profitability of anticipated BC LNG projects, the “who”, “how” and “where” of BC’s nascent liquid natural gas industry are being replaced with one question: “when”? A series of announcements over the past year from the BC government appear to constitute delays in the establishment of the taxation framework for the BC LNG industry.
The current tension lies between industry players who won’t commit until they know the LNG tax regime, and BC government’s challenge of establishing a tax regime that meets political expectations and pleases LNG developers who can shop for plants internationally.
In the fourth quarter of 2013, the province of Alberta and China entered into a non-binding cooperation agreement to increase energy trade between the respective jurisdictions. The agreement explicitly acknowledges Alberta’s major role in global resource development and China’s growing need for a reliable, competitive and sustainable supply of energy.
The agreement sets forth five guiding principles intended to facilitate its successful implementation. These include:Continue Reading...
As I discussed in an earlier post, Quebec’s Minister of Natural Resources struck a committee and issued a consultation paper last summer as part of a process expected to result with a new energy policy for Quebec. The public consultation process was completed last October and the commission’s report is expected in early 2014. Barring any early elections, a new policy should be released later in 2014.
As outlined in my previous post, the government’s objectives are ambitious and require significant capital. While it is highly unlikely that any policy objective would be dropped by the current government, it will be interesting to see the priority and the resource allocation assigned to each objective.Continue Reading...
Whether measured by volume or aggregate value, 2013 was a weaker year for energy-related M&A than 2012, continuing a four-year decline in activity in the sector. There was a noteworthy lack of public company M&A in 2013 and nothing to match the marquee deals of 2012: PETRONAS’ $6B acquisition of Progress Energy or CNOOC Limited’s $20B acquisition of Nexen. In spite of that, 2013 still saw a significant number of large and complex transactions, including Suncor’s sale of its conventional natural gas properties for $1B to Centrica and Qatar Petroleum, Progress/PETRONAS’ $1.5B acquisition of Talisman Energy’s Farrell Creek and Cyprus properties and Exxon Mobil/Imperial Oil’s $750M acquisition of part of ConocoPhillips’ non-producing Clyden oil sands acreage.
Reasons for the decline in M&A activity in 2013 included the following:
- Asian investors paused to digest what they bought after five years of significant investment in the Canadian energy sector, particularly in the oil sands.
- Changes to Industry Canada’s State Owned Entity (SOE) guidelines announced in December 2012 under the Investment Canada Act, coupled with the failure of two transactions to pass “national security” reviews, have chilled foreign investment by SOEs.
- Increased uncertainty about whether regulatory approvals would be obtained for pipelines and other projects needed to expand the capacity to transport Canadian crude oil and natural gas to the U.S. and to provide access to offshore markets contributed to investors’ concerns about the future prospects for Canadian production.
In addition to the absence of major acquisitions, 2013 also saw a decline in financing activity by oil and gas issuers. While a select few were able to raise the equity they required, many others could not – at least until Q4 when a spike in oil and gas-related capital markets activity occurred. The numbers of oil and gas issuers on the TSX and TSXV, the number of financings by those issuers and the aggregate equity capital raised to the end of Q3 of this past year were all significantly lower than over the same period in 2012.Continue Reading...
Brandon Mewhort -
On October 17, 2013, Transport Canada issued Protective Direction No. 31 (the “Direction”) pursuant to section 32 of the Transportation of Dangerous Goods Act, 1992. The Direction is in response to the Lac-Mégantic disaster on July 6, 2013, in which a train transporting crude oil derailed, resulting in a fire that caused several of the railcars to explode. The downtown core of Lac-Mégantic, a historic town in Quebec, was largely destroyed and at least 42 lives were tragically lost.
Testing conducted after the disaster revealed that the crude oil in the derailed railcars had been incorrectly classified in shipping documents.
The Direction requires any person engaged in importing or offering crude oil for transport to immediately test the classification of that crude oil, if that testing has not been conducted since July 7, 2013. The test results must be provided to Transport Canada on request.Continue Reading...
Confidentiality agreements are typically employed to protect the disclosures made by target companies to potential buyers and to require buyers to deal with the target before making a bid. As case law has demonstrated, it is essential to both sides that confidentiality agreements are drafted carefully in order to avoid adverse consequences either in the M&A context or in other activity. At the same time, in many cases these agreements need to be completed quickly, sometimes without the involvement of internal or external counsel. It is critical that internal counsel and others have reliable tools to allow them to settle confidentiality agreements efficiently and with confidence.
To that end, we have created a checklist for building an oil and gas confidentiality agreement that includes a list of issues to consider from the perspectives of both the discloser and recipient. We have also included in our toolkit below a review of common terms found in confidentiality agreements, based on a review of 28 recent transactions
Our firm’s Calgary office recently released its review of public M&A transactions in the oil and gas sector for the first half of this year. The study is based on a survey of the nine transactions involving corporate targets listed in Canada that were announced between January 1, 2013, and June 30, 2013.
This study canvasses emerging themes and trends in public oil and gas M&A, including a review of key trends in deal terms and a survey of notable terms and conditions.
Ultimately, the review confirmed a sharp reduction in activity in the sector. The total value of deals in H1 2013 was only 3% of the value of deals in H1 2012. There were no transactions completed in the period worth more than $200 million and the total deal value was just $492 million. Four of the nine deals were completed by strategic acquirors, with the remainder being completed by financials. An unusually large proportion of the deals involved acquisitions by large or controlling shareholders. There was no topping or contested activity during the review period.
On June 8, 2013, British Columbia Premier Christy Clark announced the creation of a new Ministry of Natural Gas Development. Rich Coleman, one of her most experienced Ministers, was named as the first Minister of the new department. The extraordinary step – of creating a new Ministry tasked with delivering on the current preliminary plans for LNG Facilities in British Columbia - is just the latest and perhaps the most concrete example of the Government’s consistent commitment to promoting natural gas development in British Columbia, and to LNG in particular.
Since Premier Clark first took office, the Government has first re-formulated its energy policy through the publication of the Natural Gas Strategy in February 2012, accompanied by a specific LNG Strategy. That LNG Strategy was updated in February 2013, and coincided with a Throne Speech that gave pride of place to a vision of the future of LNG in British Columbia generally. The Throne Speech specifically articulated a target of having three major LNG Facilities operational by 2020, and also proposed to establish a BC Prosperity Fund designed to reduce or even eliminate BC’s public debt, improve its social services and/or make life more affordable for BC’s families.Continue Reading...
"Publish What You Pay" - New Canadian transparency rules expected for mining and oil and gas companies
Prime Minister Stephen Harper announced on Wednesday June 12, that Canada is adopting a G8 initiative requiring disclosure of payments by Canadian mining and oil and gas companies to foreign and domestic governments. As a result of this G8 initiative, citizens in resource-rich countries are expected to gain access to information to combat any corruption in their extractive sectors and to demand additional accountability from their governments.
It is expected that the Canadian federal government will consult with the provinces and territories, First Nations and aboriginal groups, and industry and civil-society organizations in developing a framework and setting up a new reporting regime, which would be enforceable by law. Based on some unofficial preliminary estimates, it could take up to two years to implement the new regime. Details relating to how the new regime will be policed and by whom, disclosure methods and timing, and possible fines and other penalties for non-compliance will need to be determined.Continue Reading...
Canada is a relative newcomer in the global market for liquefied natural gas (LNG). Currently, natural gas prices in North American markets are significantly lower than world markets, reflecting the significant surplus supply that exists in the North American market. The discounted value of North American natural gas compared to its value in the rest of the world is expected to persist for a significant period. For Canadian producers, LNG exports offer the opportunity to access international markets and potential exposure to higher international prices.
The British Columbia provincial government has expressed support for the development of LNG export capacity within the province. In September 2011 the provincial government released Canada Starts Here: The BC Jobs Plan. According to the plan, the provincial government has set a target of 3 LNG facilities to be in operation by 2020. It is estimated that in the past year over $6 billion in investment have been made to acquire upstream natural gas assets and to execute joint ventures in the province. In addition, the provincial government estimates that up to $1 billion has been spent to prepare for the construction of LNG infrastructure in the province.Continue Reading...
On May 16, 2013, the Alberta government and the Métis Settlements General Counsel agreed to amendments to the existing co-management agreement between such parties, which will provide Métis settlements within the province of Alberta with increased benefits from oil and gas development on Métis settlement lands.
The original co-management agreement, which established rules for oil and gas development under Métis settlement lands, is a part of the Métis settlement accord signed in 1990. While the province of Alberta maintains ownership of mines and minerals, the original co-management agreement included provisions which permit the Métis settlements to negotiate an equity participation of up to 25 per cent in any oil and gas development occurring on such settlement lands. With passage of the amendments on May 16, 2013, this 25 per cent cap has now been removed. In addition, the new provisions provide that the Métis settlements now have the authority to require the highest three bidding companies to submit proposals in areas such as local employment, training or infrastructure improvements (the “Benefits Proposals”). The Benefits Proposals will then be submitted to the applicable Métis settlement counsel as part of a final selection process for energy projects occuring on thier settlement lands.
Alberta has eight Métis settlements in northern Alberta representing a land area of just over a half million hectares. According to the new provisions, the first mineral rights under Métis settlement lands will be made available for bidding at the June 3, 2013 bi-weekly provincial land sale.
Quebec has a well-deserved reputation for excellence in hydro-electricity. Less well known is its potential as an oil producer. The province is home to at least three likely production zones: Gaspe Peninsula, Gulf of Saint Lawrence and Anticosti Island. Aside from the basic question of whether there is sufficient recoverable oil, there are five other conditions that must be satisfied before Quebec can become an oil producer.
Below is a look at each condition, and its current status.
1. Oil. It has long been known that there is some oil on the Gaspe Peninsula; but it is in the Gulf of Saint Lawrence and on Anticosti Island that very large quantities are thought to be recoverable thanks to newer techniques. Further exploration work is required in all three zones to confirm reserves. Status: More work required.Continue Reading...
Recently, the firm’s Calgary office completed its 2012 review of M&A themes and deal terms in the oil and gas sector. We prepared this study based on a review of the 34 public M&A transactions involving corporate targets listed in Canada that were completed or announced between January 1, 2012, and December 31, 2012.
This study contains a list of 2012 oil and gas M&A transactions; a review of key 2012 trends in deal terms; a summary of notable features of each transaction; an analysis of the timelines and events of contested bids; a numerical analysis of key deal terms.
A few key themes emerged from our review:Continue Reading...
On March 8, 2013 Alberta’s Finance Minister, Doug Horner, stated that no changes are planned to the current royalty incentives for horizontal drilling in the province of Alberta. In the provincial budget released last week, the province anticipated a reduction in revenue from crude oil royalties. According to the provincial government, part of the drop can be attributed to the fact that an increasing proportion of production in the province is derived from horizontal wells, which are eligible for the horizontal well royalty rate.
Currently under the emerging resources and technologies component of the royalty framework, horizontal wells receive a 5% royalty on production for the first year and can receive the 5% rate for an additional one to three years depending upon the depth of the well drilled. In order to qualify the well must: (i) be an oil or non-project oil sands well; (ii) be horizontal (as defined by the Energy Resource Conservation Board); (iii) have a Crown interest greater than zero; and (iv) have a spud date after May 1, 2010.
On March 5, 2013, the British Columbia provincial budget passed second reading in the provincial legislature. In connection with the budget, Premier Christy Clark has recently announced more than $100 billion worth of new royalties and taxes for British Columbia’s nascent liquefied natural gas industry. In the short term, the provincial budget is relying on new royalties and rising gas prices to increase revenue by $138 million in 2013-14, this at a time when low North American gas prices have producers decreasing production. Longer term, the government plans to implement a new Liquefied Natural Gas (“LNG”) export tax. The government has yet to explain how the LNG export tax will be implemented, but overall, it is anticipated to generate $100 billion over 30 years for a provincial “prosperity fund” similar to Alberta’s Heritage Savings Fund. This estimate is based on five LNG plants being built in the province.
Unfortunately, the announcement of the proposed LNG export tax is adding significant near-term uncertainty to the industry’s plan to develop LNG export capacity on the west coast of British Columbia. For example, Chevron, which recently took a lead role in the Kitimat LNG project, has expressed concerns about the economics of LNG in northern British Columbia and CEO John Watson has warned “some projects will go and some will not”. The announcement also comes at a time when industry is seeking certainty from the federal government in relation to federal taxation of LNG exports. In a submission to the standing committee on finance for the next federal budget, the Canadian Association of Petroleum Producers is asking the federal government to tax LNG as a manufactured good rather than a raw material since it is changed from gas to liquid for transport.
Towards the end of last year, we attended Africa Oil Week in Cape Town, South Africa. With more than 500 delegates in attendance from all of the major players and many of the junior explorers and service providers in the sub-Saharan African exploration and production sector, the conference offered a good overview of the state of the industry.
Although Africa and London-based management teams tend to comprise most of the African junior and independent space, Canadian-listed companies and management teams are playing an increasingly important role in developing African assets.Continue Reading...
It’s generally agreed that 2012 was a difficult year for the oil and gas industry in Canada. No part of the industry was spared from challenging times. Indications of these difficulties included:
- Persistent wide differentials in prices for Canadian oil and gas production compared to North American and international benchmarks;
- Decreases in capital spending by producers; and
- Declines in Alberta land sale bonuses and aggregate drilling days from 2011 levels.
At the same time, the industry’s initiatives to increase oil pipeline and refinery capacity and to develop alternatives to the US market for the oil and natural gas produced in Canada were frustrated by organized and effective opposition from First Nations, environmental and other special interest groups and by the reactions of governments to those political pressures.Continue Reading...
Imperial Oil Ltd. (“Imperial”) and its parent, Exxon Mobil Corp. (“Exxon”), are entering the race to export liquefied natural gas (“LNG”) from Canada’s west coast to markets in Asia. Speaking at the Canadian Association of Petroleum Producers Oil & Gas Investment Symposium in Toronto on Monday, Imperial President and CEO Bruce March announced that Imperial and Exxon have begun planning for a LNG export business located in British Columbia.
The move comes on the heels of the $3.1 billion proposed acquisition by Imperial and Exxon of natural gas producer Celtic Exploration Ltd. (“Celtic”) and is a clear attempt to capitalize on the Celtic reserves as well as gas holdings they already own in Western Canada and in the Horn River shale gas play in British Columbia. Imperial and Exxon will be competing directly with a growing number of global players that have picked British Columbia’s coast to build export LNG businesses. Notably, a consortium led by Royal Dutch Shell PLC and Malaysia’s Petronas which is working on a competing plan involving building an $11 billion LNG plant near Prince Rupert.
Canada's Prime Minister sent a clear message today that the country remains open to foreign investment, including investment on a significant scale by state-owned enterprises (SOEs) in certain circumstances. However, continued acquisitions by SOEs of controlling interests in the oil sands industry has been largely constrained and will be found to be of net benefit to Canada only on an exceptional basis going forward. The acquisition by SOEs of non-controlling interests, including joint ventures, will continue to be welcome.Continue Reading...
Spectra Energy, the parent company of Union Gas Limited, has been hit with a 4th quarter $30 Million charge related to a decision by Ontario’s energy regulator. The Ontario Energy Board (OEB) determined that the revenues realized by Union Gas from the optimization of upstream transportation contracts must be reclassified as gas supply costs. As a result, approximately 90% of the total reclassified revenues, equaling approximately $30 Million will be refunded to customers, while the remaining 10% shall accrue to Union Gas as an incentive to continue to undertake optimization activities.
In reaching its decision, the OEB explained that it did not agree with Union Gas’ arguments that the optimization activities were sustainable efficiency improvements found by Union Gas in 2011 and 2012. Instead, the OEB held that the optimization revenues were clearly related to reductions in upstream transportation costs that resulted in an overall reduction to Union Gas’ supply chain costs. As such, given that these cost reductions are subject to “pass through” treatment, the OEB held that they must accrue to customers.
A link to the full decision can be found here.
On June 29, 2012, the federal government’s Jobs, Growth and Long-Term Prosperity Act received Royal Assent. This newly enacted legislation implements key components of the Economic Action Plan 2012 and also contains important features of the Ministry of Natural Resources Responsible Resource Development plan. The intended goals of Responsible Resource Development are to: 1) ensure timely and predicable project reviews; 2) eliminate duplication of project reviews; 3) strengthen environment protection, and 4) improve dialogue with Aboriginal peoples.
As discussed in our April 19, 2012 post, as part of the goal to ensure timely and predictable project reviews, there are now fixed timelines for the beginning-to-end review process, which range from 12 to 24 months depending on the type of review. The plan also provides for the replacement of federal assessments with provincial environmental assessments that meet the requirements of the Canadian Environmental Assessment Act, in order to avoid duplication of environmental reviews.Continue Reading...
The government of British Columbia along with industry representatives have announced the launching of a joint three year air monitoring program in northeastern British Columbia. The program comes as a response to increased oil and gas activity in the region. The program will fund a coordinator to establish working groups to review air quality data and make results accessible to the public. Monitoring is scheduled to begin immediately at two rural locations in the South Peace region.
Initial monitoring will focus on the detection of hydrogen sulphide, sulphur dioxide and volatile organic compounds. Once the program becomes available to larger communities it is anticipated to include broader monitoring of air contaminants, including particulates.
The federal government announced on April 17, 2012 its plan for “Responsible Resource Development” which contains a number of proposals to reform key aspects of the review process for federal environmental assessments.
Simplified and Set Timelines for Environmental Assessments
The government’s plan proposes to simplify the current structure of environmental assessments and replace it with two kinds of reviews: 1) a standard environmental assessment, or 2) a review panel. Though details on this proposal are currently lacking, it appears this reform is meant to allow appropriate projects to proceed in a more streamlined fashion through a standard environmental assessment.Continue Reading...
Last Thursday, the federal government released Budget 2012. It contained a number of proposals to improve efficiency and predictability in the review and approval process for major resource development projects while shifting tax incentives and strengthening environmental protection and free trade.
One project, one review
The government plans to create a “one project, one review” policy in coordination with the provinces and territories for environmental assessments (EAs) and associated regulatory processes. Provincial EAs would substitute for federal EAs, and responsibility for review would be consolidated significantly from at present over 40 departments and agencies. Federal and provincial governments would also coordinate Aboriginal consultations and fully integrate them into project reviews.Continue Reading...
The Conservative government has rejected the proposal for a carbon tax in favour of the United States’ model of regulating emissions through environmental regulations.
Energy industry critics and environmental groups have endorsed the carbon tax model citing the high bureaucratic involvement and low flexibility of regulations, and arguing that a market-based approach minimizes administrative costs and maximizes mechanisms to price the cost of greenhouse gases. Supporting these arguments, a paper prepared by Nancy Olewiler, released by the University of Calgary, recommends the federal government institute a carbon tax as part of a full-cost pricing system.
The author will be presenting her views to the Natural Resources Minister on March 9, 2012, suggesting further pressure on Ottawa to choose taxation over regulation.
TransCanada Corporation (TransCanada) announced on February 27, 2012 that it has sent a letter to the U.S. Department of State (DOS) informing DOS of its intention to reapply for a Presidential Permit in the near future for the Keystone XL Project. TransCanada will supplement this application with an alternative route in Nebraska that avoids the ecologically sensitive Sandhills area once this alternative route is determined.
TransCanada also informed DOS that the southern leg of the Keystone XL Project which runs from Cushing to the U.S. Gulf Coast will proceed independently of the Presidential Permit process because the Gulf Coast Project has its own independent value to the marketplace and no international border is involved. The approximate cost of the Gulf Coast Project is US$2.3 billion and subject to regulatory approvals, would likely be in service in mid to late 2013. Jay Carney, a White House spokesman, announced that the administration welcomed the decision on the southern leg, and would help speed up the permit process.
In a highly anticipated vote, a European Union committee of technical experts failed to reach a decision on whether to approve a European Commission proposal to classify oilsands crude oil as more harmful to the environment than other forms of fuel. The proposal will now go to a council of EU ministers, with a final decision expected by June.
The proposal by the European Commission, the EU’s executive arm, would constitute a revision of the EU’s Fuel Quality Directive, which aims to reduce carbon emissions by 6% from 2010 levels by 2020. The proposal would not ban oilsands crude oil, but it would assign it a greater carbon footprint than conventional crude oil. Under the proposal, oilsands crude oil would be deemed to emit 22% more greenhouse gas by weight than average crude oil.Continue Reading...
The Canadian Association of Petroleum Producers (“CAPP”) unveiled six “operating principles” it expects natural gas companies to follow. These new environmental reporting guidelines for natural gas companies are an attempt to alleviate concerns regarding hydraulic fracking. There are concerns that fracking may result in natural gas and other toxins leaking into water sources.
CAPP specifically wants its members to reveal the following information: the chemicals they use when extracting natural gas by fracking; how they construct wellbores; test results of water wells near drilling sites; how they transport, handle and store fracking fluids; and their processes for creating well-specific risk management plans for fracturing fluid.
However, these new guidelines are voluntary and do not establish any firm rules about hydraulic fracturing. Thus, it is not clear whether any companies will abide by CAPP’s new guidelines.
Shell Canada Limited has been awarded exploration rights by the Canada-Nova Scotia Offshore Petroleum Board on four parcels of offshore lands located approximately 200 kilometers off the southwest shore of Nova Scotia. The area is largely unexplored, but recent geological work funded by the Province of Nova Scotia indicates it has significant oil and gas potential. Government officials have credited this work, the results of which were publicly released, with creating renewed interest in offshore exploration in the region. The Shell Canada initiative will be the first major exploration project in the province in ten years.
Shell Canada’s bid commits it to spend a total of $970 million on exploration activities during the first six years of its nine year licence. These expenditure bids are the highest ever received by CNSOPB. A deposit of 25 percent of the bid amount will be required to secure Shell’s commitment.
The awards were based solely on the amount of money committed to exploration of each parcel. Bidders were required to demonstrate experience drilling deep-water exploration wells in the last ten years. Four other parcels included in the process received no bids.
CNSOPB’s next call for bids will be issued in May 2012. Industry members may nominate parcels to be included in this round until March 16, 2012.
The U.S. Environmental Protection Agency (“EPA”) will delay proposing the country’s first-ever greenhouse gas limits on oil refineries. The EPA agreed to implement these regulations under a settlement agreement (“Settlement“) that stemmed from two multi-state lawsuits where environmental groups sought court orders to require the EPA’s action on greenhouse gas regulation.
Pursuant to the Settlement, the EPA agreed to propose standards for oil refineries by December 10, 2011, and to enact the new regulations by November 10, 2012. According to a spokeswoman for the EPA, “the EPA expects to need more time to complete work on greenhouse gas pollution standards for oil refineries.” The EPA did not meet the December 10 deadline for the standards but is currently working with the litigants from the Settlement to set a new date for submitting the proposed standards. It is unclear whether the EPA will also miss the deadline to enact the regulations.
On October 31, 2011, the Alberta Provincial Court ordered an oilsands operator to fund an online training course in water diversion best practices that will be administered by the Canadian Association of Petroleum Producers (CAPP). Statoil Canada Ltd. plead guilty to the charge of breaching the terms of its temporary water licence by using water from unapproved sources, using unauthorized intake screens and under-reporting the volume of water diverted from a lake source.
The offences, which occurred from December 15, 2008 to May 29, 2009 near Conklin, Alberta, resulted in 19 charges that were reduced to one charge under a plea deal. The Provincial Court ordered a fine of $190,000, of which $5,000 will be paid outright and the remaining amount will be held in trust by CAPP to establish the industry training course.
This latest example in creative sentencing falls on the heels of the Alberta Provincial Court’s 2010 decision (discussed here) to issue a $3 million penalty against Syncrude Canada Ltd. to fund studies on bird deterrence and to restore migratory bird habitats.
On October 13, 2011, the National Energy Board (NEB) granted Kitimat LNG a 20-year license to export liquefied natural gas (LNG) from British Columbia. Apache Canada Ltd., EOG Resources Canada Inc., and EnCana Corp. are the proponents of the $5 billion project that would provide Canadian producers access to markets where LNG prices trade at between 3 and 4 times North American natural gas prices.
The license will allow Kitimat LNG to export 10 million tonnes of LNG a year. Apache and EOG’s shares of this volume represent more gas than Apache currently has in established reserves, and over the 20-year term, will use up almost all of EOG’s current reserves. Concerns over gas shortages, and the effect on gas prices in North America were addressed by the NEB, stating that “the export of the proposed term volume is unlikely to cause Canadians difficulty in meeting their energy requirements at fair market prices.” In support of their statement, the NEB cited EnCana’s reserves, which are substantially greater than its export commitment, and the development of shale gas resources as sufficient gas sources to satisfy the increase in demand from the Asian market.
Royal Dutch Shell PLC (“Shell”) has made a move to enter the competition of exporting Canadian natural gas to Asia by purchasing a marine terminal near Kitimat, British Columbia. Shell currently has partners in South Korea and Japan that are the world’s top liquefied natural gas buyers. This move is part of Shell’s “early stage” work to determine whether to construct a LNG export facility to export Canadian resources to Asia. Shell’s newly purchased site is near land where Apache Corp. and partners are poised to construct a $5 billion-plus export terminal, a project that received a regulatory license last week.
Canadian natural gas companies are suffering from low prices as a result of strong supply from all the recent shale gas discoveries in the United States. Canada’s only export customer for natural gas is the U.S. and these shipments to the U.S. have been halved in recent years. However, prices in Asia are far higher than they are in North America.
Shale gas discoveries in British Columbia’s northeast are massive and the industry is of the view that these discoveries would easily supply exports and domestic consumption. Companies such as Shell believe that this shale gas might be left in the ground if exports to Asia are not opened.
On October 20, 2011, Dalton McGuinty revealed his new, and slimmed down, cabinet. Chris Bentley, former Attorney General of Ontario, was named Minister of Energy, while Brad Duguid, former Minister of Energy, became Minister of Economic Development and Innovation. The energy portfolio came under much scrutiny during the provincial election and Bentley will now be responsible for running Ontario’s FIT program, as well as the negotiations regarding the natural gas plants originally planned for Mississauga and Oakville. In addition, Bentley will oversee the phase-out of coal power generation in the province, expected by 2014, and will be a key decision-maker with respect to the future of nuclear energy in the province.
On September 7, 2011, the Alberta Court of Appeal released its judgment, Omers Energy Inc. v. Alberta (Energy Resources Conservation Board) 2011 ABCA 251, with respect to an appeal by Omers Energy Inc. ("Omers") of an Alberta Energy Resources Conservation Board ("ERCB") decision to suspend two well licenses on an oil and gas lease due to a lapse of the lease. The lease contained a suspended wells clause that provided an indefinite extension of the primary term of the lease when a “well that is capable of producing the leased substances is shut-in or suspended".
The Court of Appeal Decision
Omers argued that a suspended well is “capable of producing” for the purposes of the lease whenever the well has the ability to achieve any production flow whatsoever; particularly where there is pressure from the leased substances at the outlet valve of that well or whenever steps can be taken to address the well’s conditions to achieve production flow.Continue Reading...
The Tax Consequences of Estimating Assumed Obligations in a Purchase and Sale Agreement: The Daishowa-Marubeni Case
On September 23, 2011, the Federal Court of Appeal (the "FCA") released the highly anticipated decision in Daishowa-Marubeni International Ltd. v. The Queen (2011 FCA 267). The decision of the FCA is of key importance in the mining, forestry, and oil and gas context, where the assumption of reforestation and reclamation liabilities is part and parcel of the sale of properties.
In this case, the corporate taxpayer (“Daishowa”) sold two of its forestry divisions. As part of each of the divisions, Daishowa held timber rights, which gave rise to certain reforestation liabilities. The Purchase and Sale Agreement provided the following: a purchase price of $169,000,000 for the assets; the net working capital (as adjusted); and the assumption by the purchaser of $11,000,000 in reforestation obligations, plus or minus "any difference between a preliminary and a final estimate" of the reforestation obligations. The FCA noted that Daishowa admitted that the purchase price would have been greater if the purchaser had not assumed the reforestation liabilities.
U.S. and Canada-based environmental groups have filed a petition with the U.S. Secretary of the Interior under the Pelly Amendment, a statute that allows the U.S. President to impose trade restrictions against countries that engage in trade which diminishes the effectiveness of an international program to protect threatened or endangered species.
The petition claims that Canada has not put in place mechanisms in its oilsands regulatory regime that would prevent or mitigate harm to woodland caribou, whooping cranes and other species of migratory birds. The petition further claims that such omissions have diminished the effectiveness of international efforts to protect those species such as the Migratory Bird Convention of 1916 and the Western Hemisphere Convention of 1942.
Under the Pelly Amendment, the Secretary of Interior must now determine whether Canada’s actions have diminished the effectiveness of these international conservation efforts. If the Pelly Amendment application is certified by the Secretary of Interior, the President may direct the Secretary of the Treasury to prohibit any imports to the extent such prohibition is sanctioned by NAFTA or the World Trade Organization, and shall notify the U.S. Congress of any such actions.
The Canadian Association of Petroleum Producers (CAPP) recently issued Guiding Principles for Hydraulic Fracturing (hydrofracking) operations that emphasize public disclosure and the protection of water resources. CAPP President, Dave Collyer, stated that the guidelines are intended to address concerns regarding water use. The guidelines set a priority on recycling water for reuse and for public disclosures regarding the quantity of water used in hydrofracking operations.
In addition, the recommended practice of disclosing fracturing fluid additives is under development and will be released on CAPP’s website when finalized. Fluid additives range from various oil- and water-based alternatives to complex polymeric substances with a multitude of additives.
The guidelines are meant to apply in all jurisdictions and will complement existing and future regulatory requirements.
On June 24, 2011, Niko Resources Ltd., a Calgary-based oil and gas exploration and production company, entered a guilty plea under Canada’s Corruption of Foreign Public Officials Act (CFPOA) with respect to charges of bribing a public official in Bangladesh. Niko, which operates in a number of countries around the world, had been notified by Canadian authorities in January 2009 that it was being investigated over allegations that it had provided the Energy Minister of Bangladesh with a $190,000 vehicle for personal use as well as with trips to Calgary and New York. These gifts had been made at the time when the Minister was assessing how much compensation was owed to Bangladeshi villagers for water contamination and other environmental concerns caused by explosions at a Niko operation.
Niko’s sentence included a $9.5 million fine and a three-year probation order that requires the company to implement a detailed compliance program subject to review by an independent auditor. Prior to Niko’s conviction, only one Canadian company had been convicted of foreign bribery under the CFPOA in the past decade. The $25,000 fine issued by the court in that case, known as R. v. Hydro Kleen Services Inc., was less than the bribe involved.Continue Reading...
The Republican-led U.S. House of Representatives has passed H.R. 1938, a bill which would direct President Obama to expedite the consideration of the construction of the Keystone XL pipeline.
The bill requires that the President issue a final order granting or denying the Presidential Permit for the Keystone XL pipeline no later than 30 days after the issuance of the final environmental impact statement, but in no event may the decision for the final order be made later than November 1, 2011.
The U.S. State Department has previously stated that the permitting process for Keystone XL would be completed by the end of 2011. H.R.1938’s prospects of being approved by the U.S. Senate and being signed into law by President Obama are very slim, but nonetheless, its passage received support from various industry groups and trade unions.
On June 17, 2011, Texas Governor Rick Perry signed Bill HB 3328 into law, making Texas the first state to require public disclosures of the chemicals used in hydraulic fracturing, or "hydrofracking," operations. Hydrofracking is the process of using pressurized fluids to create fractures in rock to assist in the recovery of hydrocarbons. The new disclosure requirements are a result of heightened public concern about potential contamination of water resources from hydrofracking fluids.
The legislation creates two avenues of disclosure. First, for chemicals subject to Material Safety Data Sheets ("MSDS"), the legislation requires the well operator to post the list of chemical ingredients on a publicly-accessible website. Second, for non-MSDS chemical ingredients intentionally included in the fluid, the legislation requires the information to be provided to the Texas Railroad Commission in a publicly-accessible form. In order to balance the disclosure requirements, the legislation creates a process to protect trade secrets that may be at risk due to the disclosure obligations. As well, the total volume of water used for hydrofracking operations must be posted and filed with the Texas Railroad Commission.
Holders of natural gas rights in PNG leases in Alberta are applauding the July 7, 2011 decision of Madam Justice Kent of the Alberta Court of Queen's Bench in the well-known series of cases involving coal rights owners and natural gas rights holders (the "CBM Actions").
In late May and early June, 2011, Justice Kent heard applications brought by natural gas rights holders seeking summary judgment for a declaration that, for leases which specifically grant natural gas to the lessee, the lessees of natural gas are entitled to produce coalbed methane ("CBM") from the subject lands. At issue was the meaning of the newly amended Alberta Mines and Minerals Act ("MMA"), and specifically, Section 10.1 which provides, among other things, that CBM is and has always been "natural gas."
The Federal Court heard an application from First Nation and environmental groups (“Applicants”) on June 22 and 23, 2011 seeking to compel the federal Minister of Environment (“Minister”) to recommend the Governor in Council to issue an emergency order protecting herds of Woodland caribou in northeastern Alberta under Subsection 80(2) of the Species at Risk Act ("SARA").
Boreal Woodland caribou were listed on SARA’s Threatened Species list in 2003, and under Section 42 of SARA, the Minister had until 2007 to include a proposed recovery strategy for the species in the public registry. As the Minister has yet to perform that duty, the Applicants argued that the Minister must now recommend an emergency order that will commence measures to protect the Woodland caribou’s habitat. However, the Minister is taking the position that the species do not face an imminent threat to their recovery and that an emergency order is not warranted.
This application is of particular interest to oil and gas operators, as an emergency order under SARA may include provisions prohibiting activities that may adversely affect a species and their habitat on both federal and non-federal lands.
Amendments to the Renewable Fuels Regulations under the Canadian Environmental Protection Act will set a coming-into force date of July 1, 2011 for the requirement that diesel fuel and heating distillate oil contain on average 2% renewable fuel by volume.
As we reported earlier here, this requirement will only apply to primary suppliers who produce or import more than 400 cubic meters of diesel fuel and/or heating distillate oil per year.
The amendments will provide a permanent exemption for diesel fuel and heating distillate oil sold in or delivered to Newfoundland and Labrador to account for logistical challenges in blending biodiesel in that region. As well, temporary exemptions will be provided until December 31, 2012 for diesel fuel and heating distillate oil sold in or delivered to Quebec south of 60 degrees North, New Brunswick, Nova Scotia and Prince Edward Island, giving time to refiners to install biodiesel blending infrastructure.
Canada's Minister of the Environment, Peter Kent, stated that the renewable fuel content requirements will help reduce greenhouse gas emissions by approximately four megatonnes per year.
Calgary partner Stuart Olley will be speaking at the Andean Energy Summit in Bogota on July 13 and 14. In its 5th year, the Andean Energy Summit will address the financial, regulatory, technological and operational challenges facing oil & gas, electric power and renewable energy operators in the Andes and Central America. For access to a 25% discount (tickets only) on attending the summit, please send an email to email@example.com.
In a letter released June 13, the Canadian - Newfoundland and Labrador Offshore Petroleum Board urged federal Environment Minister, Peter Kent, to appoint a federal panel to decide whether to approve an exploration well proposed by Halifax-based Corridor Resources Ltd.
Corridor Resources Ltd. holds the rights to develop in the Old Harry field, a thirty kilometre-long and twelve kilometre-wide area in the Gulf of St. Lawrence which straddles disputed territory between Quebec and Newfoundland, and may produce up to 2 billion barrels of oil and 5 trillion cubic feet of natural gas.
Quebec now has a moratorium on oil and gas exploration and development on its portion of Old Harry until the end of 2012. Quebec has expressed concerns that Newfoundland and Labrador may allow drilling in the Gulf and may undertake their own environmental assessment of offshore development in the area.
New York Attorney General, Eric T. Schneiderman, filed a complaint with the United States District Court against various federal agencies including the U.S. Army Corps of Engineers, Fish and Wildlife Service, National Park Service, Department of the Interior and Environmental Protection Agency.
The complaint seeks to compel the federal agencies to prepare a draft environmental impact statement in accordance with the National Environmental Policy Act of 1969, before adopting proposed Delaware River Basin Commission regulations that would authorize gas drilling in the Delaware Basin.
New York state's complaint argues that the potential risk of hydrofracking additives to the Delaware Basin must be fully evaluated before natural gas development is authorized.
Meanwhile, New York state's moratorium on horizontal hydrofracking is scheduled to expire on July 1, 2010. Draft regulations from the state's Department of Environmental Conservation are expected to be released later this month.
Newly re-appointed federal Minister of Environment Peter Kent signalled that the Canadian government will begin regulating greenhouse gas emissions from coal-fired electricity and oilsands projects. Minister Kent stated that regulations for coal-fired plants will arrive first, with rules for oilsands to follow later this year. For now, a carbon tax or cap-and-trade plan will not form part of the regulations. Instead, the federal government will issue “flexible guidelines” that allow individual sectors to meet their targets through measures such as technological improvements.
Minister Kent indicated that there will be an accommodation period for oilsands operations, and that regulations will not be a “hardline of sudden conversion.” As well, Minister Kent noted that the rules may not necessarily adopt all the provisions of last year’s proposed coal regulations, which starting in 2015, would have forced the shut-down of coal plants over 45 years old if upgrades could not bring down plant emissions.
Minister Kent indicated that federal regulations are needed to meet Canada’s commitment to reduce greenhouse gas emissions by 17 percent below 2005 levels by 2020, the same target provided in the United States by the Obama administration.
Further to our update on January 28, 2011, Alberta Energy Minister Ron Liepert continues to develop plans for a single energy regulator in the Province. A discussion paper recently tabled in the Alberta Legislature outlines the Energy Department’s proposal to create an “energy superboard” that would oversee the development of all oil, natural gas, oil sands and coal within Alberta, and take on all of the regulatory functions for air, water, land, mine and facility authorizations. These responsibilities are currently distributed amongst several government entities, including the Energy Resources Conservation Board (ERCB), Sustainable Resource Development and Alberta Environment.
Coal is currently regulated by the ERCB, however, the paper indicates that because coal extraction methods are similar to those used for oil, gas and oil sands, it fits efficiently within the scope of the single regulator. The paper also states that mineral regulation would be governed by the single regulator sometime “down the road”.
The paper is a starting point for new energy regulation the Minister expects to table during the legislature’s next sitting. Interested parties can provide feedback through the Energy Department’s website and the Minister has indicated that officials would be willing to sit down with organizations interested in contributing to the formation of the new law.
A complete copy of the paper, entitled “Enhancing Assurance” is available here.
On Wednesday May 11, 2011, Charlie Parker, Minister of Energy for Nova Scotia announced the results of the Play Fairway Analysis, a study into the offshore resources of Nova Scotia. The government invested in the study in order to develop an industry standard picture of Nova Scotia’s offshore geology.
According to the study, there are more than 3.3 trillion cubic meters of natural gas and 8 billion barrels of oil sitting offshore Nova Scotia. According to the minister, over the next several months the department will be marketing the study to oil and gas companies in the hope of gaining interest in a call for bids that will occur in the near future.
On Wednesday May 11, 2011, the United States House of Representatives advanced two bills that would accelerate offshore oil and gas drilling. The first of two bills would give the Federal Bureau of Ocean Energy Management, Regulation and Enforcement a maximum of sixty days to approve or reject applications for offshore drilling permits. If the board fails to make a decision within the time frame, the legislation automatically deems the permit application to be approved.
The second bill relates to forcing the federal government to sell drilling leases in waters off the coast of California and much of the Atlantic coast. Neither measure is expected to advance in the Senate as the Obama administration, as well as congressional democrats have voiced there opposition to the passing of such legislation.
The bills attempt to address the continued debate surrounding the cause of and solution to high gasoline prices in the United States. Supporters of the house bill argue the legislation would have the effect of eventually lowering oil prices by ensuring more crude oil supplies are tapped domestically.
The Alberta Energy Resources Conservation Board (“ERCB”) issued Decision 2011-012, which concluded that the production of natural gas from 455 intervals in 321 wells located in northeast Alberta may present a significant risk to the ultimate recovery of Wabiskaw bitumen due to a potential decline in reservoir pressure.
The ERCB ordered an interim shut-in of gas production of these wells, plus an additional 152 intervals, effective May 31, 2011. Production from these intervals must remain shut-in pending the ERCB’s final hearing and decisions.
In discussing the test for an interim shut-in of gas production, the ERCB stated that the Board only considers whether the bitumen is potentially recoverable, and not whether it is commercially recoverable. An interim shut-in order will be issued if bitumen is potentially recoverable and gas production has the potential for significant wasting of bitumen during the time required to decide on an application for permanent shut-in.
As part of an effort to reduce the U.S. federal deficit, the Democratic Party-controlled Senate is calling for the repeal of $2 billion in tax breaks for the five largest oil companies. The proposed Senate bill would modify foreign tax credit rules, limit deductions of income attributable to oil and gas production and eliminate domestic manufacturing tax deductions.
U.S. Senate Finance Committee hearings were held on May 14 to discuss the issue with industry leaders, who stated that the bill would limit investments in exploration and production.
The government of Saskatchewan has approved SaskPower’s construction of the $1.24 billion Boundary Dam Integrated Carbon Capture Storage Demonstration Project. The project will involve the refurbishment of a coal power generating unit at the six unit Boundary Dam Power Station near Estevan in southeastern Saskatchewan.
Carbon dioxide emitted from the 110 megawatt unit will be captured and sold to oil and gas producers seeking to use the product for enhanced oil recovery in mature reservoirs. As well, sulphur dioxide will be scrubbed from the flue gas to produce sulphuric acid.
SNC Lavalin and Cansolv, a Shell Global Solutions subsidiary, have been contracted to build the project with an expected completion date in 2014. When fully operational, the unit will yield approximately one million tonnes of carbon dioxide per year.
Following the Deepwater Horizon Macondo incident, the British Petroleum blowout in the Gulf of Mexico, the government of Newfoundland and Labrador commissioned an independent study into the preparedness and ability of provincial agencies to respond to an off-shore crisis. Captain Mark Turner, an expert in marine safety and environmental management, was retained to assess the current regulatory framework and the ability of the province to respond to an incident.
Among the recommendations of the study, the report suggests the need to increase the liability cap on compensation in the event of a spill or blowout from the current Canadian law limits on liability for damages from a spill of $40 million for Arctic water and $30 million for spills on the eastern coast. The report also advocates for the inclusion of regular audits performed by independent third parties in order to add transparency to internal findings of the regulators. Furthermore, the report recommended the need for the Canada-Newfoundland and Labrador Offshore Petroleum Board to design more detailed strategies aimed specifically at blow-outs, and advocated for a “Total System” approach to blowout control, management response and recovery.
Newfoundland & Labrador Natural Resource Minister Shawn Skinner said the government supports all of the recommendations and is prepared to work with the other provincial and federal agencies that share responsibility for the oversight of off-shore drilling and production activities.
Quebec and the Federal Government have entered an agreement to give the province 100 per cent of the oil and gas royalties from the portion of the Old Harry formation that lies within the province’s undersea boundary in the Gulf of St. Lawrence.
The Old Harry formation, which may contain up to 2 billion barrels of oil, straddles between the undersea boundaries of Quebec and Newfoundland & Labrador. The agreement relies on the 1964 undersea boundary between the two provinces. Quebec Premier Jean Charest indicated the agreement contains an arbitration clause to deal with potential boundary disputes.
Quebec is under a self-imposed moratorium on offshore drilling until 2012, and will continue its course despite the signing of the agreement.
The Government of Alberta has announced the release of the draft Lower Athabasca Regional Plan. According to the draft plan, approximately 16% of the Lower Athabasca region will be designated as a conservation area. This is in addition to the existing six per cent of the region already protected as wildland provincial parks. As a result of the plan, the Lower Athabasca region will contain more than two million hectares of legislatively protected lands – a 20,000 square kilometre area, three times the size of Banff National Park.
The plan states that the development of oil sands, minerals and commercial forestry will not be compatible with the management intent of these conservation areas. Therefore, certain existing leases, including leases where projects are already in development, will be revoked if the plan is implemented. Leases subject to cancellation will be compensated, including refunds for payments made to the Crown for the leases, development and reclamation costs and interest.
This plan is part of the Government of Alberta’s Land-use Framework, which consists of seven strategies to improve land-use decision making in Alberta. Thus far, only the Lower Athabasca and South Saskatchewan regions have released regional plans. The Lower Athabasca Regional Plan will now be subject to a public consultation process. For a schedule of the public consultation process, please see the Government of Alberta’s website.
In response to the Federal Oil Sands Advisory Panel’s report released in December, the federal Minister of the Environment, Peter Kent, announced a $20-million per year comprehensive water quality monitoring system for the Athabasca River.
In its research findings, the Oil Sands Advisory Panel concluded that the environmental monitoring programs already in place are unable to definitively distinguish, with reasonable statistical confidence or power, oil sands industrial impacts from natural sources.
The new proposed monitoring system will include more frequent and widespread sampling of the Athabasca River, and will eventually encompass the monitoring of air quality and biodiversity. The program will be administered by Environment Canada and is expected to be funded by oil sands producers.
The British government announced that it would levy a new tax on oil companies’ profits (expected to result in £2 billion ($3.2 billion) in additional taxes) in order to shift the pain felt by many consumers as a result of triple-digit crude prices. In exchange for this new tax on oil companies, the British government will lower the country’s gas tax to consumers by a penny a litre.
The new tax will hit the bottom line of oil companies operating in the North Sea as these companies can expect their tax on production to grow from 50% to 62%. The effects of this announcement were felt by Canadian companies with North Sea interests as shares fell in Nexen Inc., Suncor Energy Inc., Talisman Energy Inc. and Canadian Natural Resources Ltd.
This move by the British government has stirred speculation about copycat measures around the world as political leaders seek to dip into high crude prices.
The Alberta government announced that it will be directing a portion of the province's oil sands production to a proposed $5 billion upgrader that is scheduled to be completed by 2014. The upgrader is a joint venture between North West Upgrading Inc. and Canadian Natural Resources Ltd. The government will supply 37,500 barrels of bitumen per day to the proposed upgrader, which bitumen will be obtained by the government from production royalties it will collect from oil sands companies. In addition, Canadian Natural Resources Ltd. will supply 12,500 barrels of bitumen per day to the facility.
Alberta presently has a handful of upgraders that refine bitumen into crude, but the proposed upgrader will be the first to refine bitumen into a producing diesel fuel. The upgrader will also capture about 3,000 tonnes of carbon dioxide per day, which will be used for enhanced oil recovery in conventional oil fields.
In Bearspaw Petroleum Ltd. v. EnCana Corporation, the Alberta Court of Appeal upheld a trial court's interpretation of "producible" to mean, in the context of an oil and gas lease's habendum clause, hydrocarbons which are capable of being produced "with no more to be done than turning on a valve."
For a lease where the term endures "so long thereafter as the leased substances or any of them are producible from the leased area," it is sufficient if the lessee has drilled a well that is capable of producing hydrocarbons. The ordinary and natural meaning of the word "producible" does not require immediate commercial production or a pipeline tie-in to market as a condition for the lease's continuation.
The Court of Appeal distinguished this case from Freyburg v. Fletcher Challenge Oil and Gas Inc., where the term of the lease depended upon the leased substances being "produced" rather than "producible." The Freyburg case outlined policy considerations in favour of the strict construction of habendum clauses, including the desire of lessors to have wells produce as soon as possible to generate royalty income.
Nevertheless, the Court of Appeal held that the policy concerns in Freyburg do not preclude parties to a lease from choosing its duration on a basis other than that of immediate production, which is what occurred through the use of the word "producible" rather than "produced."
The Alberta Court of Appeal recently denied an application by Celtic Exploration Ltd. ("Celtic") for leave to appeal a decision from a Companies’ Creditors Arrangements Act (Canada) ("CCAA") proceeding involving Celtic and SemCAMS ULC ("SemCAMS"). The CCAA court found that the parties’ gas purchase agreement had been suspended as of July 2008, and as a result, Celtic could not set off amounts it owed to SemCAMS after that date against indebtedness arising under the agreement.
SemCAMS is the operator and joint owner of natural gas processing plants and related gas gathering lines in Alberta.Continue Reading...
The Alberta government has announced that it will launch a single regulator for oil and gas development within the Province in an effort to improve its competitiveness.
In a statement released today, Energy Minister Ron Liepert said the provincial government has accepted a report created by the Regulatory Enhancement Task Force (Task Force). The recommendations outlined in the report include:
• Establishing a new Policy Management Office and ensuring integration of natural resource polices;
• Creating a single oil and gas regulatory body;
• Providing clear public engagement processes;
• Using a common approach to risk assessment and management;
• Adopting performance measures to enable continuous system improvement; and
• Creating a mechanism to help resolve disputes between landowners and companies, and enforce agreements where required.
Liepert stated that the recommendations will be immediately taken through the appropriate government review process for implementation and that legislation will be introduced this spring to being implementation of the report. Practically, functions that were previously the responsibility of separate ministries, such as Alberta Environment and Alberta Sustainable Resource Development, will now be co-ordinated by the Energy Resource Conservation Board.
The Task Force was created in March 2010 after a review found that the oil and gas regulatory system in Alberta had become increasingly complex and characterized by a lack of integrated policies. The goal of the task force was to perform an upstream oil and gas regulatory review and recommend system level reforms to ensure the Province has an efficient and competitive regulatory system which also maintains Alberta’s commitment to environmental management, public safety and resource conservation.
A complete copy of the report is available here.
The Alberta Energy Resources Conservation Board (“ERCB”) has closed the comment period regarding proposed reforms to the province’s well spacing framework for conventional and unconventional oil and gas reservoirs.
At present, Part 4 of the Oil and Gas Conservation Regulations (“OGCR“) specifies that the normal drilling spacing unit (“DSU”) for an oil well is one quarter section, and the DSU for a gas well is one section. An operator may apply to the ERCB to order a special DSU which amends the normal DSU’s size, shape or target area on a case-by-case basis.
ERCB’s Bulletin 2010-39 outlines the following four proposed reforms to Part 4 of the OGCR:
1. Remove Well Density Controls for Unconventional Gas Reservoirs
Well density controls will be removed for coal bed methane (“CBM”) and shale gas reservoirs, and for all gas zones to the base of the Colorado Group outlined in Schedule 13A of the OGCR. Existing holdings will require a spacing application to replace the current approved spacing.
2. Increase Baseline Well Densities for Conventional Gas Reservoirs
The baseline DSU for a gas well will be increased from one gas well to two gas wells per section. The increased baseline well density would only apply to lands that are not subject to previous spacing approvals.
3. Standardize Target Areas for Standard DSUs
Target areas for the placement of wells would increase in size so that the target area for the production of gas would be 150 metres from all boundaries of a section and the target area for oil would be 100 metres from the boundaries of a quarter section. Furthermore, references in the OGCR to corner target areas would be eliminated in favour of central target areas across the province.
4. Streamline Regulations regarding Well Spacing Applications
The special DSU application process will be eliminated in favour of operators establishing holdings under Part 5 of the OGCR to allow the operator flexibility to locate wells, increase well density, avoid surface obstructions and access seismic features outside of standard target areas.
Additionally, operators drilling on fractional tracts of land will not be required to apply for a special DSU if the fractional tract of land meets the OGCR’s criteria for a DSU.
In addition to the proposed reforms, the ERCB stated that it would explore increasing the baseline well density for oil pools from one well per pool per standard DSU to two wells per pool per standard DSU.
On December 16, 2010, the National Energy Board (NEB) approved the application for the construction and operation of the Mackenzie Gas Project. The Project includes the 1,196 kilometer Mackenzie Valley Pipeline, three onshore natural gas fields and a 457 kilometer pipeline to carry natural gas liquids from near the coast of the Beaufort Sea to northwestern Alberta and onwards to southern markets. The NEB attached 264 conditions to the Project’s approval in areas such as engineering, safety and environmental protection. The NEB will monitor the Project throughout its lifespan to ensure these conditions are being met.
The NEB began hearing evidence in January 2006 on five applications filed by a number of parties, including lead partner Imperial Oil. The Board held over 58 days of hearing sessions in 15 communities throughout the Northwest Territories and northern Alberta.
To move forward, the NEB’s decision must now be approved by the Federal Cabinet. If the Project is approved, construction is expected to begin in 2014 and the pipeline is scheduled to be in operation by the end of 2018. If the Project proceeds, it will be the largest pipeline system to be constructed and operated in Canada’s north.
A news release was provided by the NEB concurrently with the reasons for their decision.
The proclamation of the Oil and Gas Activities Act, S.B.C. 2008, c. 36, (OGAA), on October 4, 2010, represents a significant change to the legal regime for oil and gas activities in British Columbia. The OGAA sets out the regulatory framework that will now govern oil and gas activity within the Province. It attempts to simplify the previous oil and gas framework by consolidating and modernizing the requirements that previously existed under several acts and regulations. This was accomplished by repealing the Oil and Gas Commission Act, the Pipeline Act as well as the regulatory provisions in the Petroleum and Natural Gas Act.Continue Reading...
Following our report in November, on December 2, 2010, Bill 26 received Royal Assent and came into force as the Mines and Minerals (Coalbed Methane) Amendment Act, 2010, S.A. 2010 c.20. The Act declares coalbed methane “to be and at all times to have been natural gas” for both Crown and freehold minerals. Despite this declaration, the Act expressly honours existing agreements that specifically grant coalbed methane to the coal owner and protects coal owners or their lessees, surface owners and the provincial government from being sued for damages or compensation from the extraction, production or removal of coalbed methane prior to the Act coming into force.
The Act amends the Mines and Minerals Act, R.S.A. 2000, c. M-17, which previously only declared coalbed methane to be natural gas on Crown land, by clarifying the nature of ownership of coalbed methane on freehold lands. The enactment is intended to provide clarity regarding coalbed methane ownership, the lack of which the Alberta government saw as a potential barrier to development of the resource in the province.
Following our report in November, as of December 2, 2010, Alberta's Bill 24, the Carbon Capture and Storage Statutes Amendment Act, 2010 has entered into force. Bill 24 requires the Alberta government to accept long-term liability for carbon dioxide (CO2) that is sequestered underground by way of carbon capture and storage (CCS) projects. The bill proposes that the government assume liability from project operators by becoming the owner of the captured CO2 once it is provided with data proving the stored CO2 is contained. The bill also clarifies the definition of pore space and creates a post-closure stewardship fund for the costs of ongoing monitoring and remedial work. Alberta is the first province in Canada to pass comprehensive legislation for CCS.
On October 27, 2010, the government of Alberta introduced Bill 26, Mines and Minerals (Coalbed Methane) Amendment Act, 2010. Bill 26 declares coalbed methane “to be and at all times to have been natural gas” for both Crown and freehold minerals. Despite this declaration, Bill 26 expressly honours existing agreements that specifically grant coalbed methane to the coal owner and protects coal owners or their lessees, surface owners and the provincial government from being sued for damages or compensation from the extraction, production or removal of coalbed methane prior to the Bill coming into force. Under the proposed legislation read as a whole, coalbed methane is owned by the natural gas rights holder rather than the owner of coal rights.
The Alberta government views the lack of clarity regarding coalbed methane ownership as a potential barrier to resource development in the Province. Under the Mines and Minerals Act as it currently stands, coalbed methane is only declared to be natural gas on Crown land. The Act is silent as to the nature or ownership of coalbed methane on freehold lands.
The Alberta government has recently drafted legislation, Bill 24, Carbon Capture and Storage Statutes Amendment Act, 2010, 3rd Sess., 27th Leg., Alberta, 2010 which clarifies ownership of pore space and that would, if passed, make Alberta the first province in Canada to enact comprehensive legislation to regulate large-scale carbon capture and storage (CCS) projects. Under Bill 24, the Alberta government would own subsurface pore spaces where carbon dioxide is stored and would assume long-term liability for injected carbon dioxide once project operators provide data that the gas is contained. Bill 24 would also create a special fund financed by CCS operators that would pay for future monitoring of underground carbon dioxide storage sites and any necessary remediation.
The Alberta Energy Minister, Ron Liepert, emphasizes that Bill 24 would ensure Alberta is on track to reducing greenhouse gas emissions and would also help to double Alberta’s conventional oil recovery which will generate billions of dollars for the province. In particular, the Alberta Carbon Capture and Storage Development Council estimates that carbon captured and used in enhanced oil recovery could produce an additional 1.4 billion barrels of oil from conventional reservoirs generating up to $25 billion in provincial royalties and taxes.
In an effort to remove barriers to resource development in Alberta, the Government of Alberta is seeking to clarify the ownership of coalbed methane within the province.
On October 27, 2010, the provincial legislature introduced Bill 26, the Mines and Minerals (Coalbed Methane) Amendment Act, 2010, 3rd Sess., 27th Leg., Alberta, 2010. This Bill declares that coalbed methane is, and always has been, natural gas for both Crown and freehold minerals. Therefore, if the Bill is passed, coalbed methane in Alberta will be owned by natural gas rights holders rather than coal owners.Continue Reading...
On October 15, 2010, the Canadian Securities Administrators (CSA) issued a Notice of Amendments to National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (NI 51-101) and related and consequential amendments. NI 51-101 sets out annual filing requirements for reporting issuers who are involved in oil and gas activities and the disclosure standards applicable both to those annual filings and any other disclosures relating to their oil and gas activities. The stated purposes of the amendments are to clarify the standards of disclosure, codify existing staff guidance and practice, and add requirements to enhance reliability of certain disclosure of reserves and resources other than reserves. Each member of the CSA has made, or are expected to make, the amendments, which will come into force on December 30, 2010 provided that all requisite ministerial approvals are obtained.Continue Reading...
The Ontario Government recently released O. Reg. 389/10, made under the Energy Consumer Protection Act, 2010 (the Act). This regulation will govern the conduct of energy retailers and gas marketers and provides for increased consumer protection. The regulation also contains rules regarding the implementation and use of smart meters by individual units in multi-residential buildings. Both the Act and the regulation come into force on January 1, 2011. For more information on the Act and regulations please see our post of June 17, 2010.
On a related note, the Ontario Energy Board issued a Revised Notice of Proposal (the Proposal) on October 15, 2010 to revoke and re-issue the Electricity Retailer Code of Conduct and the Code of Conduct for Gas Marketers, and to amend the Gas Distribution Access Rule. The Proposal will implement the consumer protection provisions of the Energy Consumer Protection Act, 2010. Comments on the Proposal are due on October 29, 2010.
Federal Environment Minister, Jim Prentice, has announced the formation of an independent Oilsands Advisory Panel, whose mandate is to provide recommendations on the scientific research and monitoring of environmental effects associated with oilsands development.
Specifically, the Advisory Panel will:
- Document, review and assess the current body of scientific research and monitoring; and
- Identify the strengths and weaknesses in the scientific monitoring, and the reasons for them.
The Advisory Panel will report to Minister Prentice with their findings at the end of November. It is expected the focus of the Advisory Panel will be on theRegional Aquatics Monitoring Program (“RAMP”), a monitoring organization led by industry and Alberta regulatory bodies, as well as the research methodologies of RAMP’s Technical Program Committee.
Québec’s Cabinet has requested that the Bureau d’Audiences Publiques sur l’Environnement (“BAPE”) hold public hearings beginning September 14 regarding the creation of a new oil and gas regulatory regime for Québec.
Québec currently does not produce oil and gas in significant commercial quantities, yet prospective areas for production, especially the shale gas in the Utica formation of the St. Lawrence Valley, are now fully leased.
Québec’s oil and gas resources are currently legislated under the province’s mining rules and regulations, where depending on the size of production, gas producers pay royalties of 10 to 12.5 percent. Producers must also conform to a patchwork of municipal, regional and provincial permitting laws.
The creation of a single regulatory regime would “create a fiscal and legal framework that can make a company decide to invest in Québec rather than Pennsylvania” says Québec’s Natural Resources Minister, Nathalie Normandeau.
As part of the public hearings, BAPE will conduct a review of the environmental, health and safety issues surrounding the practice of hydraulic fracturing, or “fracking,” a procedure where high pressure fluids are injected into rock formations to release hydrocarbons.
BAPE’s review of fracking practices falls on the heels of the U.S. Environmental Protection Agency launching a similar study, as well as a temporary moratorium on fracking that was approved by the New York State Senate in August and will be reviewed by the New York State Assembly in September.
In Bearspaw Petroleum Ltd v. Encana Corp., the Alberta Court of Queen’s Bench considered an action by a lessee seeking a declaration that it had subsisting rights under a petroleum and natural gas lease, in response to a termination of lease notice delivered by the lessor. The lease, executed in 1960 by the predecessors of both the lessor and lessee, granted the lessee an interest in the petroleum, natural gas, and other related hydrocarbons, in the mineral lands of the lessor. The term of the lease was 10 years “and so long thereafter as the leased substances or any of them are producible from the leased area.”
At the time the termination of lease notice was delivered in 2005, no leased substances had been produced or taken to market since September 2003. However, the lessor had two wells drilled which were considered viable but had not yet been tied into a pipeline. The lessor claimed the lease had terminated for lack of “producible” leased substances because the contents of the wells could not be immediately taken to market and sold. The lessee argued that “producible” meant capable of being produced in economic quantities and did not require actual production.
In finding in favour of the lessee, the Court considered the proper interpretation of “producible” within the meaning of the lease:
Producible does not mean that the product must be able to go to market without anything more to be done. A successful well remains producible in plain language even though the actual flow of gas to market awaits regulatory approval, well-head completion or contractual arrangements with carriers. When, after a well is drilled, leased substances are found in economic quantities, those substances are capable of being produced when other things are done - that is, they are “producible”.
The lease also contained a provision for the payment of yearly rent, in lieu of royalties, during periods in which no leased substances were being produced. This provision served as persuasive evidence for the Court that the continuation of the lease was contemplated in the absence of actual production. The lease continued by reason of leased substances being producible from the well in question and the annual rents being paid to the lessor.
An alternate argument of the lessor, that the lessee had breached an implied covenant to diligently produce and market any leased substances capable of production, was also dismissed. The Court found that there is no implied covenant where, as in the lease in question, production and marketing are expressly considered. The express covenant to develop the property so as to produce leased substances in paying quantities did not impose a timeline for such production. The lessee was entitled to postpone tying the wells to a pipeline until production was more economically viable. The Court also found it reasonable for the lessee to delay production while the legal status of the lease was in question.
The White House Council on Environmental Quality (“CEQ”) released a report which reviewed the permitting policies of the federal agency responsible for oil and gas offshore leases.
Under the National Environmental Policy Act (“NEPA”), all federal agencies must consider the environmental impacts of their proposed actions, and follow NEPA implementation Regulations created by the CEQ.
NEPA procedures may include:
- An Environmental Assessment (“EA”) to determine whether an Environmental Impact Statement is necessary;
- An Environmental Impact Statement (“EIS”) for proposed actions that may create significant environmental impacts; or
- A Categorical Exclusion (“CE“) for activities that are determined through a public process not to raise environmental issues or concerns which would require analysis in an EA or an EIS.
The CEQ’s NEPA Regulations allows agencies to “tier” their analyses by “incorporating by reference” information, findings, and recommendations from existing studies into subsequent NEPA analyses and documents.
The Minerals Management Service, recently renamed the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEM”), relies on “tiering” in the approval of offshore drilling Exploration Plans.
The Minerals Management Service uses the analysis performed at the leasing program level to carry the information forward to the individual lease-level. Since the Deepwater Horizon incident, the CEQ report now recommends that the BOEM refrain from tiering in a way that limits site-specific analysis, “despite the availability of major, prior environmental reviews and studies.”
The CEQ report also recommends the BOEM review the use of CEs for offshore Exploration Plans. Establishing a CE requires that a categorized action has neither individual nor cumulative significant effects on the environment, and that there are no extraordinary circumstances which would preclude the use of a CE.
Going forward, the BOEM will review its interpretation of the threshold requirement for “extraordinary circumstances,” which will likely lead to an increase in the number of leases that are subject to additional environmental reviews prior to approval.
To accommodate the increase in EAs and EISs, the CEQ also seeks to amend the Outer Continental Shield Lands Act to provide more time for the BOEM to conduct environmental reviews. Currently, the BOEM must make its decision whether to approve a submitted Exploration Plan within 30 days.
On Monday, Foreign Affairs Minister Lawrence Cannon announced that the federal government was toughening sanctions against Iran. The announcement, which was co-ordinated with other countries, came as a response to Iran’s continuing refusal to stop uranium enrichment activities.
The Special Economic Measures (Iran) Regulations are effective immediately and are designed to curb the progress of Iran’s nuclear programs.
In addition to prohibitions against dealing in nuclear, chemical, biological and missile technology, new investments in Iran’s oil and gas sector and the export of items and technology for refining oil and gas have also been banned.
In Canpar Holdings Ltd v. Petrobank Energy and Resources Ltd. and Gentry Resources Ltd., the Alberta Court of Queen's Bench considered a claim by a corporate petroleum and natural gas lessor against a lessee for failure to comply with a prescribed royalty schedule. The lease expressly provided that royalties were to be calculated at a given percentage of either the sale price or market value, whichever was greater, and "all without deductions", except transportation expenses. The lessee took the position that the use of fuel gas was a permitted deduction pursuant to the definition of "operations" in the lease. The lessor argued that this deduction was beyond that authorized by the royalty clause and issued a notice of default. The lessee continued production after the notice of default was given.
The Alberta Court of Queen's Bench, in an oral decision issued by Justice Miller, considered (1) the correct interpretation of the lease with respect to the price of gas, and (2) whether fuel gas was a permitted deduction.
The Court relied on a strict interpretation of the terminated petroleum and gas lease to determine damages with respect to royalty pricing and payments. The Court found that in calculating royalties, only two options were available as provided in the royalty clause: the greater of sale price or market value. Contrary to prior decisions, which considered the conduct of the parties and common industry practice when interpreting such clauses, the Court applied a strict, rather than purposive interpretation to the phrase "all without deductions" in the royalty clause. Using this approach, the Court found that fuel gas was not included in the definition of "operations" and was, therefore, not an allowable deduction under the exemption provision.
570495 Alberta Ltd. v. Hamilton Brothers, a 2008 Alberta Court of Queen's Bench decision, provides similar guidance in that a royalty owner is only required to pay a share of processing expenses where it is expressly accounted for in the lease. On the other hand, although addressing a shut-in well provision, the 2008 Alberta Court of Appeal case of Kensington Energy Ltd. v. B&G Energy Ltd. gave direction on the interpretation of oil and gas lease agreements, suggesting that courts should examine the subtle meaning of language and give effect to the parties' intentions.
In determining the damages payable in the Canpar case, the Court concluded that a lessee's continuation of production after termination of a lease amounts to the tort of trespass or conversion, but does not warrant punitive or exemplary damages unless the lessee's conduct is high-handed, abusive or egregious. In this case, the Court held that the lessee's conduct after termination of the lease did not meet these criteria. The lessee was therefore only required to provide an accounting of profits, less any associated costs actually incurred. The primary focus was to restore the lessor to its original position had the tort not occurred.
This case is significant in that the Court gives full effect to the express language of the royalty clause prohibiting deductions. That said, the fact that royalties in this case were to be calculated based on the greater of sale price or market value may distinguish it from other cases where the royalty is calculated at the wellhead, where a more convincing argument may be made that deductions ought to be made for expenses that were incurred up to the time of sale.
This decision demonstrates that petroleum and natural gas leases, and specifically royalty clauses, must be drafted with care. Given the Court's reliance on the plain language of the agreement, future leases should expressly outline the percentage of production on which the royalty is payable, specific allowable deductions (i.e. operating expenses of the property, other overriding royalties, transportation and gathering, cleaning, processing, enhanced recovery, etc.) and any right of the lessee to use substances consistent with the royalty (for example, fuel gas for enhanced recovery to extend production), and whether the lessor is to bear a portion of that expense.
Delegates attending the Pacific Northwest Economic Region Summit in Calgary were invited to tour Fort McMurray and the Alberta oilsands this week in an effort to “showcase the technology and innovation surrounding [the] oilsands developments first-hand” says Gary Mar, Alberta’s Envoy in Washington, D.C. who led the tour.
Twelve U.S. legislators were part of the delegation, including Representative Mike Schaufler, D-Oregon, who told reporters that he was “impressed by the technological advancements and the sophisticated pipeline transportation system used to transport oil to the U.S.” He also stated that he was "more comfortable buying oil from Alberta, which shares similar environmental goals with the U.S., than from foreign sources."
U.S. offshore operators may soon face expanded liabilities, more stringent rig and well design requirements, vigorous and frequent inspections, and greater civil and criminal penalties in the event of an oil spill.
On June 30, two Senate Committees separately approved, and advanced to the full Senate, bills that would tighten offshore drilling regulations.
The Senate Energy and Natural Resources Committee’s Bill, S.3516 would separate the Bureau of Ocean Energy Management, Regulation, and Enforcement into two agencies: one responsible for offshore revenue and royalty collection, and the other for licensing, safety and environmental regulation.
Bill, S.3516 would also include tougher civil and criminal penalties that increase over time with inflation, and would place a levy on operators to fund the hiring and improved training of federal inspectors.
The same day, the Senate Environment and Public Works Committee approved Bill S.3305 to eliminate the $75 million cap on liability found in the Oil Pollution Act of 1990. As well, operators would need to submit extensive spill response plans before new drilling applications are approved.
Meanwhile, three Committees in the House of Representatives are working on similar legislation. The U.S. House Transportation and Infrastructure Committee approved Bill H.R. 5629 that would, with retroactive effect, remove the above mentioned $75 million liability cap, and raise to $1.5 billion the minimum amount of insurance that offshore facilities must hold. Further, under federal law, operators would be liable for health-related claims associated with oil spills, claims that are currently pursued in State courts.
The U.S. House Energy and Commerce Committee’s proposed Blowout Prevention Act of 2010 would require operators who drill “high-risk wells” (wells located within 200 nautical miles of the U.S., or those onshore where a blowout “could lead to substantial harm to public health and safety or the environment”) to install blowout preventers and obtain independent technical inspection of new rigs before they begin operating. Rigs would have to be reviewed every six months by third party inspectors, with the possibility of surprise inspections by federal authorities.
The U.S. House Natural Resources Committee will consider its own bill on July 14, written with the intent to improve the transparency and accountability in federal energy regulation.
Congress’s focus on offshore reform may result in a broad, merged legislation by the end of the Second Session. Despite support for increased regulation by both parties, Republican critics argue that with open-ended liability and tougher drilling requirements, only the largest offshore operators will be able to shoulder these new costs.
Syncrude was convicted in Alberta Provincial Court on June 25 on charges of failing to prevent a toxic substance from harming wildlife (a provincial charge under the Environmental Protection and Enhancement Act) and depositing a substance harmful to migratory birds (a federal charge under the Migratory Birds Convention Act).
Syncrude’s defence had been primarily based on due diligence - arguing that it had taken reasonable care to prevent the unlawful act.
The court found that, while a defence of due diligence was available on these charges, the court found that Syncrude had not acted with due diligence:
Syncrude could not "ensure" that waterfowl did not land on the Aurora Settling Basin on April 28, 2008 but it had a reasonable legal alternative. I am convinced beyond reasonable doubt that Syncrude could have acted lawfully by using due diligence to deter birds from the Basin, whether or not it was successful in its attempts at deterrence, and it did not do so.
With respect to the deployment of deterrence systems available to prevent ducks from landing on Syncrude’s pond, the Court found that:
The evidence convinces me beyond reasonable doubt that Syncrude placed itself in a position where it was unable to take reasonable steps to deter birds from the Aurora Settling Basin on April 28, 2008. It could have set up its system to place deterrents sooner and more quickly, regardless of the weather that arrived in April of 2008. It was reasonable to take those precautions and Syncrude did not. It could have set up its system to place deterrents sooner and more quickly, regardless of the weather that arrived in April of 2008. It was reasonable to take those precautions and Syncrude did not.
Other defences raised by Syncrude (including that it would have been impossible for it to ensure that ducks would not land in the ponds, act of God, abuse of process and officially induced error were all rejected by the Court. .
The matter will resume on August 20th with arguments as to whether convictions should be entered on one or both charges, and for sentencing arguments.
On June 21, 2010, Bill C-2, An Act to Implement the Free Trade Agreement between Canada and the Republic of Columbia, passed its third reading in the Senate. Upon royal assent the act will implement the Free Trade Agreement and the related agreements on the environment and labour cooperation entered into between Canada and the Republic of Colombia and signed at Lima, Peru on November 21, 2008.
The Canada-Columbia FTA will strengthen the investment ties between the two countries and advance the rights and protections for Canadian businesses that currently have, or that plan to make, investments in Columbia. The FTA provides for the free flow of capital to investments, protection against expropriation without compensation and requires Canadian investments and investors to receive fair and equitable treatment.
Because of its significant natural resources Columbia is an important investment destination for Canadian companies involved in mining and oil exploration. Speaking at an auction of oil exploration and production blocks the Energy and Mining Minister of Columbia, Hernan Martinez, stated that the Canada-Colombia FTA “opens the way for a lot of opportunities” for Canadian oil companies.
Columbia is South America’s forth largest oil producer and is in the process of auctioning off more than 200 exploration and production blocks in a process that could bring in between $250 and $500 million dollars.
As reported in prior posts (most recently in April 2010), in 2009 the Alberta Government launched a competitiveness review of the 'New Royalty Framework' implemented by the Stelmach government only two years earlier. The results of that review, along with the Government of Alberta's policy response, were released in March, 2010 and the corresponding new royalty curves were to be provided prior to June, 2010.
As promised, on May 27, 2010, the Government of Alberta revealed its proposed changes to the base royalty curves for both conventional oil and gas, which are to take effect on January 1, 2011. The government also unveiled further initiatives, as a result of the competiveness review, intended to energize investment and encourage development of Alberta's unconventional and deep resource pools. The most significant of these initiatives are modifications to the Natural Gas Deep Drilling Program and the implementation of the Emerging Resources and Technologies Initiative.Continue Reading...
Benjamin S. P. Hudy and Lisa A. McDowell
In 2009, in the wake of a changing economy, a slowdown in oil and gas well drilling and a new but much criticized royalty regime, the Government of Alberta launched a competitiveness review (the Review) with a focus on upstream natural gas and conventional oil development. The results of this Review and the Government of Alberta's policy response were released on March 11, 2010 in its publication Energizing Investment - A Framework to Improve Alberta's Natural Gas and Conventional Oil Competitiveness (the Competitiveness Framework).
By comparing Alberta's investment competitiveness with other key jurisdictions, namely British Columbia and Saskatchewan in Canada and Arkansas, Colorado, Kansas, Louisiana, New Mexico, Oklahoma, Pennsylvania, Texas, Utah and Wyoming in the United States, the Review revealed that, though still a dominant player in the energy business, Alberta has lost competitive ground in relation to its peers in the conventional oil and gas industry. To attempt to secure Alberta's competitive future in conventional oil and gas, the Competitive Framework identifies proposed actions by the Government of Alberta in a few key areas, the most significant of which appear to be royalty adjustments and regulatory process improvements.
A recent application within the SemCAMS ULC (SemCAMS) Companies' Creditors Arrangements Act (Canada) (CCAA) proceeding considered a claim for set-off by Trilogy Energy LP (Trilogy) against SemCAMS.1
SemCAMS was the operator of four natural gas processing plants and gathering lines in Alberta (each, a "Facility" and collectively, the "Facilities"). Most of the Facilities were jointly-owned, with SemCAMS being an owner and the operator of each of the Facilities pursuant to a number of Construction, Ownership and Operation Agreements (CO&Os). As operator, SemCAMS maintained the facilities, gathered and processed natural gas on behalf of its co-owners and collected funds in respect of capital fees and operating expenses on behalf of the joint account for each Facility. For each Facility, the respective joint owners were each entitled to a share of the Facility's throughput capacity, with excess capacity being allocated first to the Facility's respective joint owners and second to third parties on a fee for processing basis.Continue Reading...
On October 25, 2007, Alberta Premier Ed Stelmach announced the New Royalty Framework (New Framework) to be implemented on January 1, 2009. The government stated that the purpose of the New Framework was to give future generations of Albertans a share in the development of resources, to provide stability and predictability to the oil industry, and to assure investors that Alberta would remain an internationally competitive and stable place to do business. Government analysts projected that royalties would increase by approximately $1.4 billion in 2010, a 20% increase from revenues under the prior regime.Continue Reading...
On April 29, 2008, the Ontario Energy Board (OEB) released its decisions on Natural Gas Storage Allocation Policies for Enbridge Gas Distribution Inc. and Union Gas Limited (EB-2007-0724 and 0725). An oral hearing had taken place December 17-20, 2007.
The hearing addressed certain issues arising from the OEB's 2006 Natural Gas Electricity Interface Review (NGEIR) decision, in which the OEB had ordered Union and Enbridge to submit new storage allocation policies on the basis that existing rules, in particular Union's policy of applying the aggregate excess method for semi-unbundled customers, were not consistently applied. The aggregate excess method permits customers with seasonal loads to balance constant supply, allowing them to inject storage all summer and then withdraw all winter.Continue Reading...
As part of the Government of Alberta's commitment to address "unintended consequences" of the New Royalty Framework announced in October 2007 (the Framework), the Alberta Department of Energy (Alberta Energy) recently introduced two new royalty programs and certain other amendments affecting royalty calculations.
The two new royalty programs are designed to encourage the continued development of deep, high-cost oil and gas reserves, in light of identified concerns that some deep oil and gas reserves had the potential of becoming uneconomic under the Framework. These programs are expected to be implemented on January 1, 2009 with the other Framework programs.Continue Reading...
In its October 27, 2005 speech from the throne, the Manitoba Government announced a plan to subsidize residential natural gas consumers, a move that may have a significant impact on the province's retail market. Since the late 1980s, Manitoba, like most other provinces, has permitted active retail competition in the sale of natural gas, and marketers have captured about 20 per cent of the residential market. To ensure that the utility's default supply rate tracked market prices for gas, over the last five years the Manitoba Public Utilities Board (the PUB) has administered a quarterly natural gas rate adjustment mechanism similar to that used by the Ontario Energy Board. Under the RSM, or Rate Setting Methodology, default supply gas commodity rates charged by Manitoba Hydro/Centra Gas were adjusted quarterly to reflect one-year gas forecasts, with variances between forecast and actual costs tracked and flushed out every quarter for recovery over a twelve-month period.Continue Reading...
Erin Michael O'Toole
When it is cooled to -130°C, natural gas becomes a liquid and occupies six hundred times less space than it does in its gaseous form. Liquefied Natural Gas (LNG) is rapidly becoming an important part of the North American energy supply mix, particularly as domestic supplies of natural gas near exhaustion and demand continues to increase. Currently, LNG is the source for only about 6% of the global consumption of natural gas, but this percentage is expected to rise to 11% by 2010 and to more than 20% by 2020.
LNG will be imported into North America from the Persian Gulf region, Russia, Indonesia and parts of Africa. Source countries generally have large gas reserves and relatively slight domestic demand. The gas is liquefied and transferred to ships large enough to carry LNG to supply fourteen million homes with a day's supply of natural gas. Countries receiving LNG will require large port facilities, as well as branch pipeline and re-gasification plant infrastructure to transform the LNG back into natural gas and to transmit the gas to market.Continue Reading...