Robert T. Booth Donald E. Greenfield* Bennett Jones LLP Introduction This past year has been one of significant change in the oil and gas industry in Canada. It has seen the announcement of new rules regarding the taxation of income trusts; the release of the Report of the Alberta Royalty Review Panel; and the enactment of Alberta s Specified Gas Emitters Regulation. Income Trust Taxation In last year s edition of this article, we reported on the Federal Minister of Finance s October 31, 2006 announcement regarding the taxation of specified investment flow-throughs ( SIFTs ). This announcement caused considerable controversy. Implementing legislation has since been enacted, but ambiguities and issues remain. Among other things, these ambiguities are in regard to: the application of the normal growth guidelines to the issuance of equity by a SIFT to repay debt of a subsidiary; certain exchanges of exchangeable securities; the exercise of employee options, issuer bids and redemptions; dividend reinvestment plans; and to certain aspects of mergers of two or more SIFTs. Furthermore, the Department of Finance has not proposed legislation to allow a SIFT to be converted into a corporation on a tax-deferred basis; nor are there anti-avoidance rules in regard to the normal growth guidelines. At least one of the predicted results of this announcement has materialized: a sharp increase in the number of trusts being taken over. Alberta Royalty Review On September 18, 2007, the Report of the Alberta Royalty Review Panel (the Panel ) titled Our Fair Share was released. It proposed significant changes and revisions to the current royalty structure in Alberta. The Report concluded that Albertans do not receive their fair share from energy development and recommended increases to the total government take (royalties plus tax). The Alberta Government released its detailed royalty framework on October 25. The Government s proposals are a compromise between the Panel recommendations and what industry has suggested. The changes will be implemented effective January 1, 2009. The Government expects an additional $1.4 billion in royalty revenue in 2010. They project this increase to come in equal shares from natural gas, conventional oil and oil sands royalties. The Government acknowledges the possibility of unintended consequences and is explicitly left open therefore the possibility of changes. In regard to natural gas, the Government has accepted the panel's recommendation to go to a single sliding rate formula that is sensitive to price and volume. The rate will range from 5% to 50%, up from a maximum of 35%, and has also accepted the recommendation to eliminate the vintage distinction and certain special royalty programs but will retain the deep gas royalty holiday. In regard to conventional oil, the Government is eliminating specialty programs and the vintage distinction and as with gas, royalties will be calculated using a single sliding-rate formula, which will contain separate elements for price and productivity. In regard to oil sands, the pre-payout gross royalty rate on revenue will be changed from a flat 1% to a sliding scale of a minimum of 1% and rising to 9% over the WTI price range from Cdn. $55 to $120 and the post-payout net royalty rate will change from 25% to a sliding scale of 25% to 40% over the same price range. The Government has rejected the recommendation that both royalties be payable in the post-payout period and has also rejected proposed the oil sands severance tax. The Government will not implement the proposed tradeable royalty credit for upgrading capital costs. It will work on its "Value-Added Strategy" to determine what tools will best encourage resource value additions within Alberta. There will be no grandfathering of existing projects, although it was acknowledged that the Syncrude and Suncor oil sands mining projects are special situations. The Government will attempt until January 2008 to negotiate what we understand to be a consensual implementation of the new framework with Syncrude and Suncor, failing which the Government will consider other options to level the playing field. Investment Canada Act In a speech on October 9, 2007, the Honorable Jim Prentice, the Federal Minister of Industry, stated that the question of foreign investment in Canada by state-owned enterprises and regulation for an investment for NAFTA will be examined by the Federal Government this fall. The government s concern, he said, is not with the ownership of the foreign capital being invested in Canada; but, rather, with how that capital behaves in the marketplace and the issue of reciprocity among nations as to whether state-owned enterprises are allowed to invest. The government views the absence of a national security test in the Investment Canada Act to be an oversight that should be addressed. In considering these issues, the government will look at rules in other G-8 countries as well as Canada s NAFTA obligations. Conventional Oil and Gas While there has been declining production in the natural gas and conventional oil sector, significant acquisitions and dispositions were undertaken in 2007. Effective January 1, 2007, Duke Energy Corporation spun off its wholly owned subsidiary Spectra Energy Crop. The spin-off resulted in the creation of a
new public entity with approximately US$21 billion in assets operating in the US and Canada. On January 22, 2007 Pengrowth Energy Trust acquired certain western Canadian oil and gas properties from ConocoPhillips Canada for C$1.0375 billion, which is the largest property acquisition made by a Canadian energy royalty trust. On April 2, 2007, Progress Energy Trust acquired a natural gas producer operating in northeast British Columbia and northwest Alberta for approximately C$526 million. In April 2007, Royal Dutch Shell plc completed the purchase of the 22% of Shell Canada Limited that it did not already own, for approximately C$8.7 billion. Abu Dhabi National Energy Co. acquired Northrock Resources Ltd. for approximately C$2.0 billion in August 2007 and has announced the purchase of Pioneer Natural Resources Canada Inc. for US$540 million and PrimeWest Energy Trust for C$5.0 billion. Klemke Mining Corp. v. Shell Canada Ltd., 2007 ABQB 176, [2007] A.J. No. 301 At issue in this case was whether an enforceable contract was formed between the parties as a result of negotiations and a signed term sheet. The Court of Queen s Bench held that despite the absence of a formal signed agreement, or an agreement as to the final price or precise scope of work to be completed under the project, there was a binding contract for Klemke to perform mining and consulting work on the Muskeg River project. The Court found that there was a meeting of the minds which was evidenced by letters exchanged between the parties, including a letter to which the term sheet was attached, and that the terms of the agreement were sufficiently clear to support the existence of an enforceable contract. This decision has been appealed. Canadian Natural Resources Ltd. v. EnCana Oil and Gas Partnership, 2007 ABQB 460, [2007] A.J. No. 767 EnCana Oil & Gas Partnership and Canadian Natural Resources Ltd. entered into a pooling agreement. Subsequently, EnCana entered into a wide-area farmout agreement with Marauder Resources West Cost Inc. Pursuant to the farm-out agreement, Marauder provided EnCana with its list of test well locations. EnCana determined that these selections resulted in Marauder s right to earn a working interest in certain parcels of the pooled lands and that they triggered Curl s right of first refusal. EnCana issued a notice of disposition to CNRL. CNRL elected to exercise its right of first refusal. CNRL later objected to the well locations and the timelines. At issue was whether CNRL was bound by the locations and timelines set out in the notice of disposition. The Court held that CNRL was bound by the terms of the notice of disposition pursuant to clause 2401 of the CAPL Operating Procedure. The clause provides that when an offeree exercises its right of first refusal, a binding contractual obligation is created requiring the offeree to acquire the interest in question on the terms and conditions set forth in the disposition notice. Oil Sands Activity in the oil sands industry remained strong in late 2006 and 2007 and foreign investment continues to be significant. Statoil Canada Limited, a wholly owned subsidiary of Statoil ASA acquired all of the shares of North American Oil Sands Corporation for C$2.2 billion on June 25, 2007. In late 2006, Canadian Oil Sands Limited acquired the remaining 25% stake that it did not own in the Canadian Oil Sands Limited Partnership, which holds a 5% interest in the Syncrude Project, from Talisman Energy Inc. for C$475 million. In April 2007, Enerplus Resources Fund acquired a 90% interest in the Kirby Oil Sands Partnership, which owns prospective oil sands leases in the Athabasca area of Alberta for C$182.5 million. In September 2007, Teck Cominco Limited, UTS Energy Corporation and Petro-Canada entered into an agreement pursuant to which Teck and Petro-Canada each subscribed for an additional 5% stake in the Fort Hills Energy Limited Partnership by funding an aggregate additional C$750 million of project expenditures. SGER Alberta s Specified Gas Emitters Regulation ( SGER ) is a regulation created under the Climate Change and Emissions Management Act (Alberta). Alberta is currently the only jurisdiction in North America with legislated limits on industrial greenhouse gas emissions. The SGER imposes emission intensity limits on certain large greenhouse gas emitters with the first set of targets being for the six-month period July 1 to December 31, 2007. The SGER includes the adoption of extensive greenhouse gas emissions reporting, emissions trading between regulated sectors, an offset system and the administrative arrangements needed to support such an enterprise. The SGER is intended to reduce, over a specified period of time, the emissions intensity of each regulated entity by up to 12%. Major Pipeline Projects The proposed Mackenzie Gas Project ( MGP ), which would transport gas from the Mackenzie Delta in the Northwest Territories, continues to be scrutinized in hearings before the National Energy Board ( NEB ) and the Joint Review Panel ( JRP ). As a result of regulatory delays, a regulatory decision on the MGP is not expected until 2008. Imperial Oil, the major project proponent, continues to report increased project construction cost estimates that threaten the viability of the project. In March
2007, Imperial reported in NEB filings that the delay in regulatory approval would cause a delay in production startup to no earlier than 2014. In June 2007, the Alaska Governor signed the Alaska Gasline Inducement Act ( AGIA ) into law. The AGIA is intended to encourage expedited construction of a natural gas pipeline to transport natural gas from the Alaska North Slope to Alaskan and other markets. A request for competitive applications from potential participants was issued with a deadline of November 30, 2007. While TransCanada Corporation holds certificates under the Northern Pipeline Act, which it alleges permit it to construct the Canadian portion more quickly and cheaply than other alternatives, no application to the NEB has been submitted with respect to the construction and operation of the Canadian segment of a potential Alaska pipeline project. Consideration of two gas pipeline projects on the East Coast of Canada have concluded before the NEB. Following a coordinated public hearing with the Canada-Nova Scotia Offshore Petroleum Board, the NEB approved an application by EnCana Corporation for the construction and operation of a C$234 million 176 km underwater pipeline (the Deep Panuke Pipeline) that will connect offshore production to markets in the Maritimes and North Eastern United States. Once constructed, this pipeline will transport up to 300 million cubic feet per day of natural gas production from Sable Offshore, which is expected to commence production in 2010. In the spring of 2007 the NEB approved the Emera Brunswick Pipeline Project, a 145 km natural gas transmission pipeline from the Canaport LNG terminal in Saint John, NB to St. Stephen, NB. Emera anticipates a November 2008 in-service date. A number of crude oil pipeline projects have been or are currently before the NEB for consideration. However, the NEB continues to predict crude oil pipeline bottlenecking as early as the fall of 2008, owing to the significant increases in oil production from the Canadian oil sands, which is anticipated to precede the proposed in-service dates of approved projects. In September 2007, the NEB approved the Canadian portion of the Keystone Pipeline Project, which will transport up to 435,000 bpd of crude from Hardisty to a point near Haskett, Manitoba. The American segment will complete the connection from Hardisty, Alberta to Illinois. The NEB has also approved the Terasen Pipelines (TransMountain) Inc. application for a 158 km pipeline, referred to as the TMX Anchor Loop Project, which will be constructed through Jasper National Park and Mount Robson Provincial Park. Other Canadian crude oil pipeline projects are currently being considered by the NEB, among them the Enbridge Southern Lights Project, to bring diluents from the US to the oil sands area and an expansion of Enbridge s Line 4 upstream from Hardisty to Edmonton, Alberta, to eliminate the potential bottleneck of the Enbridge mainline between Edmonton and Hardisty, Alberta. The proposed Enbridge Alberta Clipper Project would require the construction of a new pipeline from Alberta to Superior, Wisconsin to initially increase capacity on the Enbridge system by 450,000 bpd. The hearing for the Clipper Project was completed in November 2007. South of the border, the Enbridge Southern Access Project is under construction and, once completed, the staged construction project will increase crude oil capacity from the Alberta oil sands to Midwest and other refineries, adding 124,000 bpd to the Enbridge Lakehead system of pipelines. Enbridge has also completed a binding Open Season for Phase I of a two-phased expansion of the Spearhead Pipeline, which would increase deliveries into Cushing, Oklahoma. The Dene Tha have negotiated a C$25 million deal with Ottawa which permits the Dene Tha to participate in the review of the Mackenzie Gas Project and provides for the fast-tracking of the Dene Tha land claim. On November 10, 2006, the Federal Court Trial Division of Canada ruled that the federal government breached its fiduciary duty to consult with the Dene Tha regarding their traditional lands or Aboriginal rights with respect to the Mackenzie Gas Project. The Court ordered that the JRP could not consider any aspect of the Mackenzie Gas Project affecting Dene Tha land, and that the JRP could not report to the NEB until there was a process for taking into consideration the concerns of the Dene Tha. The Dene Tha have agreed to discontinue all legal actions against the federal government and not to interfere with, delay or frustrate the construction, operation or maintenance of the Mackenzie Gas Project. Negotiations with the Deh Cho with respect to the Mackenzie Gas Project continue and discussions have commenced for an agreement in principle to guide negotiations regarding a Deh Cho final agreement. However, no resolution has been reached. Offshore Oil and Gas Development Newfoundland and Labrador Husky Energy currently holds a 72.5% working interest in, and is the operator of, the White Rose oil field, which is located approximately 350 km off the coast of Newfoundland and which came into production in 2005. Petro-Canada holds a 27.5% working interest. In September 2007, the Province of Newfoundland and Labrador reached an agreement in principle with Husky and Petro-Canada
for a 5% ownership share in the White Rose satellite fields, for which the provincial government will pay approximately C$44 million. Newfoundland and Labrador has also signed a Memorandum of Understanding ( MOU ) with ExxonMobil Canada, Chevron, Petro-Canada and Norsk Hydro Canada Oil and Gas Inc., to move ahead with the C$6 billion Hebron offshore oil project, located 340 km southeast of St. John s. The MOU contemplates a C$110 million investment by the province, in exchange for a 4.9% equity stake in the project. Nova Scotia In the spring of 2007, the Canada- Nova Scotia Offshore Petroleum Board ( CNOPB ) announced changes to make the province s offshore more attractive for exploration. The changes involved more flexible terms and conditions for new exploration licenses. In early October 2007, the CNOPB approved EnCana Corporation s Deep Panuke offshore gas project. The CNOPB s Decision Report was accepted by the federal and provincial governments on October 2, 2007. The approval gives EnCana Corporation the necessary approvals to move toward project sanction. Production is expected to begin in 2010. Coal Bed Methane Coal bed methane ( CBM ) is one of the largest untapped natural gas opportunities in North America. CBM development is more advanced in the United States because of generous tax incentives, whereas the industry is in its relative infancy in Canada. The Alberta Geological Survey estimates that there may be 500 Tcf of natural gas in Alberta s coals. Compared with conventional natural gas, CBM development requires greater well density and raises concerns regarding effects on groundwater. Despite these challenges, CBM development has emerged as a major new energy frontier in Canada. As conventional natural gas reserves continue to decline, Alberta s natural gas producers will be forced to rely increasingly on CBM. Uncertainty regarding ownership of CBM on split title lands was lessened by the March 2007 decision of the AEUB regarding whether well licenses to produce CBM had been properly issued to natural gas rights holders. In its decision the AEUB refused to revoke the licenses it had granted to the certain natural gas owners and held that the certain natural gas owners were entitled to develop the CBM under AEUB regulations. The AEUB was careful to limit its ruling by holding that entitlement was strictly for regulatory purposes and that final authority in the ownership matter belongs to the courts. As a result of this decision, AEUB Bulletin 2006-19, which had held in abeyance all CBM facility and well applications in regard to which ownership of CBM was at issue, was revoked. Certain applicants and intervenors are seeking leave to appeal the AEUB s decision. This application is scheduled to be heard on October 31, 2007. Liquified Natural Gas At this time, there are no liquid natural gas ( LNG ) shipments into or out of Canada but there are currently proposals for 10 LNG terminals across Canada. The terminals are intended to be located in British Columbia, Québec and Atlantic Canada. Of the 10 proposals, the Bear Head LNG project was canceled in February 2007 because of an inability to sign a contract for the supply of LNG. As well, WestPac LNG Corporation announced its proposal to develop an LNG terminal on Texada Island but put its proposal to develop an LNG terminal on Ridley Island, near Prince Rupert, British Columbia on hold for economic reasons. The Canaport LNG and LNG receiving and regasification terminal project owned by Repsol YPF, SA and Irving Oil Ltd., is currently under construction in Saint John, New Brunswick, and is expected to begin operations in late 2008. The terminal will be the first LNG regasification plant in Canada, and will produce natural gas for markets in both Canada and the US. Coal In Canada, substantial reserves of coal are found in British Columbia, Alberta, New Brunswick and Nova Scotia. Sherrit International Corp. announced its intention to develop Canada s first commercial coal gasification facility, the Dodds-Roundhill Coal Gasification Project. It is anticipated that the project application, along with the environment impact assessment report, will be submitted for regulatory review in 2008. Uranium Saskatchewan dominates Canadian uranium production. The Athabasca basin in the north of the province is the site of some of the world s richest deposits of uranium. On December 20, 2006, First Uranium Corporation completed its initial public offering for gross proceeds of C$203 million comprised of 29 million common shares at a price of C$7 per share. On April 20, 2007, sxr Uranium One acquired UrAsia Energy Ltd under a plan of arrangement. The combined company has a market capitalization of approximately C$4.5 billion. On August 10, 2007 Uranium One Inc. completed a plan of arrangement with Energy Metals Corp. The acquisition was valued at C$1.6 billion.
Biofuel Two biofuel facilities have been announced in Alberta. The most recent announcement related to a C$90 million biodiesel refinery near Edmonton, Alberta. Construction is anticipated to commence in the spring of 2008. Capacity is expected to be 225 million liters of canola-based biodiesel a year and production is projected to start in June 2009. Riverstone Holdings, Carlyle Group, and Dominion Energy LLC announced plans to construct a C$400 million biofuel-refining complex in Innisfail. The complex would have the capacity to produce 378 million liters (nearly 100 million gallons) each of ethanol, canola oil and biodiesel. It is expected to be in production in the fall of 2008 and is the first facility to combine the production of ethanol, biodiesel and canola oil in Canada. Canadian Green Fuels Inc. has entered into a joint venture with Cansource Biofuels to open a new biodiesel production facility in Mayerthorpe, Alberta. Once constructed, the integrated facility is expected to initially produce 10 million litres of biodiesel, which will be scaled up to 40 million litres by 2010. n * The authors thank Michael Barrett, Marie Buchinski, Jenny Kirkpatrick, Sandra Malcolm, Tom McInerney and Holly Ward of Bennett Jones LLP for their assistance in writing this article. Robert T. Booth, Bennett Jones LLP Tel: (403) 298-3252 Fax: (403) 265-7219 E-mail: boothb@bennettjones.ca Partner in the corporate department with an emphasis on energy and resources. Represents clients in oil and gas exploration, production, midstream and marketing; major energy and infrastructure projects; oil sands, heavy oil, refining; upgrading and EPC and EPCM contracting; mining, electric power generation and transmission, and energy utilities businesses. Recognized by Chambers Global and Lexpert as a leading Canadian energy lawyer. Donald E. Greenfield, Bennett Jones LLP Tel: (403) 298-3248 Fax: (403) 265-7219 E-mail: greenfieldd@bennettjones.ca Partner in the corporate department and co-leader of the energy practice group. Experienced with asset and share sales and acquisitions in Canada and internationally, oil sands development, production and facilities construction and operating matters, production sale contracts, financings, joint ventures, limited partnerships, farm-outs and matters relating to the Investment Canada Act and Competition Act. Acts for exploration, production, upstream and midstream companies and private equity funds. Recognized as a leading Canadian energy lawyer by Chambers Global and Lexpert.