In this overview of recent significant regulatory developments in the oil and gas sector, the scope is limited to decisions and policy changes of the Alberta Energy and Utilities Board (the "Board") and judicial appeals and consideration of same. In addition, a significant decision of the Alberta Environmental Appeals Board ("EAB") is discussed. Of primary interest is the discussion and overview of Board and judicial decisions respecting the gas over bitumen conflict where the Board's decision to shut in natural gas wells to preserve the bitumen resource was hotly contested.
JUDICIAL DECISIONS
Solex Gas Processing Corp. v. Alberta (Energy and Utilities Board)
In Decision 2004-006: Solex Gas Processing Corp., Application to Amend a Gas Processing Scheme and for a Natural Gas Pipeline (January 27, 2004), the Board dealt with what has been termed as a "sidestreaming" application by Solex Gas Processing Corp. ("Solex"). Solex Gas Processing Corp. v. Alberta (Energy and Utilities Board), 2004 ABCA 388. Solex sought approval to have their share of the gas flowing through the NGTL System diverted to the Harmattan Plant where it would be re-processed and a certain quantity of natural gas liquids Natural Gas Transmission Line ("NGL") would be removed. The re-processed gas would then be returned to the NGTL System to be transported to the Cochrane Straddle Plant for further NGL extraction prior to being delivered to market. The Solex application contemplated that the Cochrane Straddle Plant would still receive a sufficient quantity of NGL to ensure its economic viability as is mandated by Section 35 of the Oil and Gas Conservation Act("OGCA"). R.S.A. 2000, c. O-6 [OGCA]. The Board declined Solex's application in Decision 2004-006.
Solex sought leave to appeal Decision 2004-006 pursuant to Section 26(1) and (2) of the Alberta Energy and Utilities Board Act, and Section 41(1) and (2) of the Energy Resources Conservation Act. R.S.A. 2000, c. A-17, [EUBA]; R.S.A. 2000, c. E-10 [ERCA].
The concept of the public interest was prevalent throughout the Reasons of O'Leary J.A. He concluded that the Board was entitled to balance the interests of Solex against the impacts of sidestreaming on the straddle plant system. O'Leary J.A. reiterated the provisions of Section 4(c) of the OGCA, which state that the purpose of this legislation is to "provide for the economic, orderly and efficient development in the public interest of the oil and gas resources of Alberta." He further concluded that a finding by the Board that the application was contrary to the public interest was one that was within the Board's jurisdiction.
O'Leary J.A. found that the Board's jurisdiction to consider the public interest was not limited to the strict application of Section 35 of the OGCA. According to O'Leary J.A., the consideration of the public interest goes beyond simply determining whether the sidestreaming application encroaches upon the minimum volume of NGL to which a straddle plant is entitled. In considering the public interest, the Board was authorized to consider government policy respecting NGL extraction and straddle plants.
Lastly, O'Leary J.A., in dismissing the leave application, agreed with Solex that natural gas producers are entitled to extract NGL from the natural gas they own and produce, however, this right is subject to the overall public interest.
Dene Tha' First Nation v. Alberta (Energy and Utilities Board)
This was an appeal by the Dene Tha' First Nation ("DTFN") with respect to certain well licenses issued by the Board to Penn West Petroleum Ltd. ("Penn West"). A single judge of the Court of Appeal granted leave to DTFN on December 11, 2003. Dene Tha' First Nation v. Alberta (Energy and Utilities Board), 2005 ABCA 68.
Penn West had advised DTFN in 2002 that it proposed to drill a number of wells and put in access roads on certain Crown lands. These lands were not within the reserve of DTFN, but were alleged by DTFN to be within their "traditional lands." There were a number of meetings and discussions between Penn West and DTFN, and Penn West provided a helicopter site tour of the proposed project to certain members of DTFN.
As part of the consultation process, Penn West attempted to obtain information from DTFN trappers who were potentially affected. However, DTFN objected to direct communications between Penn West and the trappers, insisting that communication go through a central consultation office. It was in late November 2002 that Penn West advised DTFN of the precise legal descriptions of the proposed development.
In late December 2002, the Board issued licenses for some of the wells' roads. Immediately thereafter, DTFN filed material with the Board seeking to intervene and object to the applications. There was an exchange of correspondence between all parties, following which the Board issued a letter, dated January 16, 2003, stating that DTFN had not met the test for intervention set out in Section 26(2) of the ERCA. In essence, the Board concluded that DTFN was not "directly and adversely affected", as is required by this section, by the development.
DTFN then applied for a reconsideration of the Board's decision. Both DTFN and Penn West submitted information to the Board setting out their respective positions. On April 15, 2003, the Board again concluded that DTFN did not meet the test of adverse impact and DTFN was not given Intervenor status.
The Court concluded that the test has two branches, the first being a legal test, which necessitates an inquiry into whether the claim, right or interest being asserted is one known to law. The second branch is factual, demanding an inquiry into whether the application before the Board may directly and adversely affect such interest.
The Court asserted that in order for the Board to have made a factual finding in favor of DTFN, it required specific evidence and information as to possible adverse effect. The Board was not compelled to find that standing existed as a consequence of a mere assertion of an Aboriginal or a Treaty right. The Court stated that the information which would speak to this issue, such as where its members hunt and trap, was readily available to DTFN. However, no such specific information was provided to the Board in this case.
In the result, the Court of Appeal held that the Board had correctly applied the factual test set out in Section 26(2) of the ERCA. The Court further pointed out that it had no jurisdiction to hear an appeal on the Board's determination with respect to the factual component of the test.
REGULATORY DECISIONS
Decision 2005-009: Provident Energy Ltd. ¾Application for a Change in Pool Designation (February 15, 2005)
Provident Energy Ltd. ("Provident") submitted an application to the Board for a change in pool designation from Gilby Basal Manville A3A to Jurassic pursuant to Section 33 of the OGCA. Progress Energy Ltd. ("Progress") and ARR Resources Ltd. ("ARR") subsequently filed Interventions. Progress asserted that the evidence in support of a pool re-designation was conflicting and inconclusive. ARR objected due to concerns that the pool re-designation would affect its gross overriding royalty interest.
The Board considered all of the evidence provided and concluded that the pool re-designation sought by Provident was supported by the evidence. The Board placed considerable emphasis on the fact that the core log analysis submitted by Provident showed the presence of in situ phosphates, which the Board felt was a significant indicator of the Jurassic, rather than Manville, strata.
This Decision is interesting from the perspective of the Board's discussion of the standard of proof required for a pool re-designation. Progress, in its opposition to the application, argued that in the interests of the certainty as to ownership of mineral rights required by the industry, the Board should not allow pool re-designation applications in the absence of "definitive" or "compelling evidence." The Board specifically addressed this position a number of times in the decision.
It remains to be seen whether this Decision will result in a proliferation of pool re-designation applications, particularly in light of the increasing number of deeper, higher risk plays, resulting from a maturing basin.
Gas over Bitumen Judicial and Regulatory Decisions
Prior to discussing the latest regulatory developments in this ongoing issue, it is useful to briefly review the legal and procedural background. Below is a chronological outline of events respecting the gas over bitumen debate:
- In 1996, the Board perceived a concern with respect to potential adverse effects of gas production on bitumen in associated pools.
- In 1997, the Board conducted a general inquiry with respect to this issue.
- In March 1998, the Board released the results of its inquiry entitled "Gas Bitumen Production in Oil Sands Areas," in which the Board accepted the premise that the production of associated gas could have a negative effect on bitumen production. Supra, note 29.
- In 1999, the Board issued Interim Directive ("ID") 99-1, which set the parameters on applications for gas production in specified areas. Gas/Bitumen Production in Oil Sands Areas Application, Notification, and Drilling Requirements (February 3, 1999). There were 4 subsequent Amendments to ID 99-1. Pursuant to ID 99-1, an applicant had to demonstrate that the gas was non-associated or, if associated, why production should be permitted. Wells drilled prior to July 1, 1998 were exempt from ID 99-1.
- The post ID 99-1 applications to produce gas resulted in extensive hearings. On March 30, 2000, the Board issued Decision 2000-22 in which it declined to allow production from 146 wells in the Surmount Area. Decision 2000-22: Gulf Canada Resources Limited Request for the Shut-In of Associated Gas, Surmount Area.
- On March 18, 2003, Decision 2003-023 was issued by the Board and as a result, 60 wells in the Chard Leismer Area were shut in. Decision 2003-023: Chard Area and Leismer Field, Athabasca Oil Sands Area.
- General Bulletin 2003-012 was issued in April of 2003, pursuant to which, the Board indicated that the decision on exempted wells would be revisited and invited submissions from interested parties. Gas Production in Oil Sands Areas (April 3, 2003).
- On June 3, 2003, the Board issued 2003-016, which amended ID 99-1 in that the affected area was reduced, however, all the wells would be shut in. Proposed Conservation Policy Affecting Gas Production in Athabasca Wabiskaw-McMurray Oil Sands Areas.
- The Board indicated that it felt that the protection of the bitumen resource required the shut in of all Wabiskaw-McMurray gas wells in the area. It invited submissions for this proposal and consultation meetings were held in July of 2003.
- In July of 2003, the Board issued General Bulletin ("GB") 2003-028, which set out a staged approach to dealing with the gas/bitumen issues. Bitumen Conservation Requirements Athabasca Wabiskaw-McMurray (July 22, 2003).
Phase 1: Interim shut in of 938 wells including those exempted under ID 99. Exemptions should be granted if non-association was demonstrated.
Phase 2: Parties could challenge the exemptions granted under Phase 1.
Phase 3: Upon the completion of the Board's Regional Geological Study ("RGS") would determine the final status of gas production.
- The Shut-In Order was challenged by virtue of Judicial Review in Queen's Bench and Statutory Appeal in the Court of Appeal. The Judicial Review application was dismissed by Hillier J. with Reasons dated October 29, 2003. BP Canada Energy Company v. Alberta (Energy and Utilities Board), 35 A.R. 363, 2003 ABQB 875.
- The RGS was released at the end of December 2003 and found 464 gas pools associated with bitumen and 313 gas pools were classified as non-associated. Report 2003-A: EUB Athabasca Wabiskaw-McMurray Regional Geological Study (December 31, 2003).
Decision 2004-045: Phase 3 Proceedings under Bitumen Conservation Requirements and Applications for Approval to Produce Gas in the Athabasca Wabiskaw-McMurray Area (May 31, 2004)
This hearing was conducted in order to consider submissions with respect to the production of gas-bearing intervals in the oil sands that were the subject of GB 2003-028. In accordance with GB 2003-028, a Board staff submission group ("SSG") submitted recommendations to the Board respecting the continuation or variance of a production status of wells contemplated by GB 2003-028. Parties that disputed the findings of the SSG were permitted to make submissions, and the hearing was subsequently conducted.
Although much of the evidence and argument at this hearing centered around technical and geologic issues, the Board did deal with a number of legal issues. By way of example, some parties questioned the authority of the Board to conduct the proceeding was questioned. In reply, the Board stated that it had the mandate to manage all energy resources, and had the exclusive jurisdiction under Alberta 's energy legislative regime to address conservation issues. The Board concluded that its jurisdiction stemmed from its general and specific duty with respect to the conservation of crude bitumen.
A number of parties also questioned the Board's perceived need for an expedited hearing process, which, in their view, jeopardized the fairness of the proceeding. The Board maintained that the danger to potential bitumen recovery was such that the delay, which would necessarily result from a more protracted hearing process, was unacceptable.
The participation of SSG in the process gave rise to concerns with respect to the reasonable apprehension of bias. The Board perceived these concerns as being based on the view that the proceeding before it was an extension of previous proceedings or Board-sponsored initiatives with respect to the issue of bitumen conservation. The Board stated that this was not the case, and the present proceeding was independent of both previous Board proceedings with respect to bitumen conservation and the GB 2003-028 consultation process.
The Board also took note of the fact that the Court of Appeal granted leave for the appeal of Decision 2003-023. BP Canada Co. v. Alberta (Energy and Utilities Board), 30 Alta. L.R. (4th) 248, 2004 ABCA 75. The Board further noted the "stay" with respect to the EnCana Corporation ("EnCana") and Canadian Natural Resources Ltd. ("CNRL") wells, which were considered in Decision 2003-023 and in the associated lease decision, stating that the stay applied only to the perforated intervals referenced in Decision 2003-023, and did not extend to distinct intervals within the same wellbores.
BP Energy Company v. Alberta (Energy and Utilities Board)
This was an application to the Court of Appeal seeking leave to appeal GB 2003-028 and a stay of the resulting Shut-In Order. 346 A.R. 147, 2004 ABCA 32. The grounds of appeal proposed by the applicants raised a number of issues respecting violations by the Board of the principles of natural justice. In addition, the Court dealt with the issue of whether the appeal would unduly hinder the progress of the action. It regarded the "action" as the ongoing process employed by the Board with respect to bitumen conservation. Ibid. at para. 42.
The Court further questioned whether any remedy on appeal would be of any assistance to the applicants, given that the Board intended to commence hearings with respect to this issue in March, 2004. The Court found that any appeal would be unlikely to be heard prior to the commencement of the March, 2004 proceedings, with the result that the appeal may be moot.
In the result, the Court concluded that it did not have sufficient evidence to determine the issue of mootness. The Court concluded that the test for leave had been satisfied.
The Court also dealt with the application to seek a stay of the Shut-In Order resulting from GB 2003-028. In determining this issue, the Court went through the tri-partite sequential test set out in R.J.R MacDonald Inc. v. Canada Attorney General. [1994] 1 S.C.R. 311, 164 N.R. 1. The Court concluded that while the questions before it are not frivolous, but rather seriously arguable, the balance of convenience favored the continuation of the Shut-In Order. In reaching this conclusion, the Court made reference to the Board's assessment that the content of the bitumen reserves exceeded that of the shut in gas production by 600%.
The Court also made reference to the principles of equity. It noted that the applicants offered no explanation for the failure to bring a stay application between the issuance of GB 2003-028 in July of 2003, and the stay application brought on September 1, 2003. The Court further commented that the applicants did not submit an undertaking as to damages in the event that the appeal was unsuccessful.
BP Energy Company v. Alberta (Energy and Utilities Board)
In this decision, the Court of Appeal dealt with two issues:
- the refusal by the Board to grant an adjournment of interim proceedings related to bitumen conservation of the interim hearing scheduled for March 8, 2004; and
- the decision of the Board to include certain wells in the proceedings constituting Phase 3 of the gas/bitumen process that were excluded from Decision 2003-023 (Chard-Leismer). 30 Alta. L.R. (4th) 248, 2004 ABCA 75.
With respect to the first issue, the Court of Appeal had little difficulty concluding that the Board was entitled to be the master of its own process. The Court of Appeal considered that prior to doing so, there must be found to have been "egregious" conduct by the Board.
The Court also considered that the adjournment applications were premature. There was an acknowledgement that the refusal to grant an adjournment could be found to be a breach of procedural fairness, however, this issue could not be determined prior to the hearing and decision. The Court concluded that an appeal based on the failure to grant an adjournment could not be properly adjudicated until the final decision of the Board was issued.
The Court concluded that the applicants had met the test for leave with respect to the appeal of the decisions to include wells not subject to the original shut in order in GB 2003-028 and included in Decision 2003-023.
The Court concluded that pursuant to Section 3(5) of the Oil Sands Conservation Regulation and Section 39 of the ERCA, it had the authority to review any of its own decisions. Alta. Reg. 76/1988. However, the Court found that the applicants did not receive notice of the Board's decision to review the Decision 2003-023 wells, and rejected the respondent's argument that notice to review these wells should have been inferred from GB 2003-028.
The Court granted the applicant's request for a stay of proceedings under GB 2003-028, however only insofar as those was applicable to the applicant's wells which were considered in GB 2003-023.
EnCana Corporation v. Alberta (Energy and Utilities Board)
This was a decision of the Court of Appeal respecting applications for leave to appeal Decision 2004-45, being the Phase 3 proceedings pursuant to GB 2003-028 brought by EnCana, Paramount Energy ("Paramount"), Devon Canada Corporation and Giant Grosmont Petroleums Ltd. In addition, the applicant sought a stay of the order shutting in certain of their gas wells. 354 A.R. 380, 2004 ABCA 259.
Paramount argued that because the Board had no jurisdiction to compensate it in the event the Board's interim decision to shut in its wells was reversed, the Board lacked the authority for the interim order. Paramount relied on the Supreme Court of Canada decision in Bell Canada v. Canada (Canadian Radio - Television and Telecommunications Commission), citing the Supreme Court's position that, "a regulatory body has no jurisdiction to grant an interim order unless it also has the power to review and remedy its effect should the interim order be varied or rescinded upon a full and final hearing". [1989] 1 S.C.R. 1722, 97 N.R. 15 [Bell Canada ]; Ibid, at para. 15.
The Court of Appeal rejected Paramount 's arguments. It stated that the Bell Canada decision was concerned with an exercise of intrinsically financial matters, which differed from the resource conservation issues before the Board. It pointed out that the Board's primary objectives are the conservation of energy resources and the protection of the public interest and that its enabling legislation did not permit the interpretation sought by Paramount.
EnCana's approach was slightly different, arguing that the Board had committed an error in limiting the scope of the hearing leading up to Decision 2004-45. The Court had little difficulty disposing with this argument, stating that unless the Board could conduct expedited hearings, its ability to carry out its statutory mandate in time sensitive situations would be frustrated.
Decision of the Environmental Appeals Board
Mountain View Regional Water Services Commission et al. v. Director, Central Region, Regional Services, Alberta Environmentre: Capstone Energy (April 26, 2004), Appeal Nos. 03-116 and 03-118-121-R (A.E.A.B.)
The EAB was required to consider a decision by the Director, Central Region, Regional Services, Alberta Environment (the "Director") to issue Preliminary Certificate No. 00198509-00-00 (the "Certificate") and Proposed License under the Water Act, to Capstone Energy Ltd. ("Capstone"), providing for the allocation to Capstone of fresh water for a secondary recovery project. R.S.A. 2000, c. W-3. Once the Proposed License was issued and came into effect, it would allow for the diversion of 328,503m3 of water annually, at a maximum daily rate of 900m3, from the Red Deer River.
The EAB received Notices of Appeal from the Mountain View Regional Water Services Commission ("RWSC"), which provides water to a number of municipalities in the Red Deer area. The RWSC was of the view that the EAB should have regard to its three fundamental interests, as follows:
- ensuring a sustainable and dependable water supply for the municipalities;
- ensuring the water supply was sufficient for continued economic growth; and
- preserving the natural environment.
The local agricultural community also presented submissions to the EAB. Their concern was premised on the fact that farmers and ranchers were the project's immediate neighbors, and their livelihood was dependent on a stable supply of water. The EAB noted that over the past number of years, the agricultural industry has had to deal with water shortage issues.
The EAB stated that this case represented one of the most difficult balancing of interests that had come before it in over 10 years of its existence, in that it was being asked to choose between legitimate competing demands for a valuable and finite resource.
The RWSC argued that Capstone's proposal conflicted with Alberta 's Water Strategy, and was not in the public interest, but was rather for the sole benefit of Capstone. It argued that there should have been a more detailed investigation with respect to the alternatives to the water diversion for which Capstone had applied. A further articulated concern was that the Proposed License did not contain adequate protection for other water users, including fisherman and other recreational users.
The RWSC argued that the water injected by Capstone would not be returned to the hydrologic cycle and would be lost forever. It indicated that the volume of water needed by Capstone was the same as that used by the Town of Didsbury, which services 3,000 individuals. However, the RWSC asserted that the Town of Didsbury returns 100% of this water back to the hydrologic cycle to be used an infinite number of times.
The agricultural community submitted that the Director had failed to balance the economic benefits and environmental impacts of the water diversion project, and did not adequately consider the alternatives to the proposed water diversion. The concerns of the RWSC with respect to the removal of water from the hydrologic cycle were echoed by the agricultural community. The effect of the project on both groundwater and surface water on adjacent properties was also raised by the agricultural community. The agricultural community argued that the potential effects of the project on the sloughs and dugouts on landowners' property were not examined, and such formations and structures were important, as they were used to contain surface water used by their cattle. The agricultural community further argued that the Director had failed to consider future water use and allocation, along with long-term impacts on the riparian and aquatic environment.
The City of Red Deer (the "City") also opposed the Proposed License, arguing that the Director had failed to comply with not only the specific requirements of the Water Act, but also the spirit and intent of that legislation. Like the RWSC and the landowners, the City complained that Capstone had failed to provide sufficient information with respect to the economic impact of the water diversion. As a result, the City argued that the Director was not in a position to evaluate whether the proposal represented a proper allocation and use of water as required by the Water Act. It was argued that the needs of municipalities should have a higher standing with respect to water allocation decisions, as municipalities return much of the water used back to the hydrological cycle, and thus better serving the public interest. The City argued that on its face, the oilfield injection of potable surface water was a bad practice.
Capstone and the Director made submissions in support of the Proposed License. The Director took an interesting position, arguing that those who opposed the Certificate and Proposed License were attempting to affect policy change, and that the EAB was not the appropriate forum for such a change. The Director took the view that the Water Act does not assign priority to the purpose for which water is used, but rather sets out various statutory factors to be considered. The Director pointed out that there was no existing policy or legislation precluding the use of surface water for oilfield injection purposes. It was further asserted that if the municipal use of water was to rank ahead of industrial use, the Water Act would need to be amended to accomplish this change.
The EAB concluded that the Proposed License should be varied to reduce Capstone's water allocation. The EAB made a number of comments emphasizing the importance of the oil and gas industry to Alberta, and the fact that industry was undertaking efforts to reduce the use of fresh water. The EAB again characterized its task as balancing the protection of fresh water and ensuring that the oil and gas industry is sustained. The EAB also accepted the view that once fresh water is injected as part of an oilfield recovery injection process, it is lost from the hydrologic cycle for millions of years. As a result of this loss, section 2 of the Water Act mandated that the proposed water diversion receive much greater scrutiny.
The EAB varied the Proposed License to reduce Capstone's allocation to 600m3/day, for a total allocation of 219,000m3 annually. The EAB also recommended that a condition be added requiring Capstone to utilize any alternative water sources, such as produced water where possible, and to provide the Director with a report setting out a more detailed investigation of alternative water sources.
POLICY DEVELOPMENTS
Guidelines for Utility Cost Claims (Guide 31(B) (January 2004))
These Guidelines identify circumstances in which the Board may award participants in a utility proceeding the reasonable costs associated with their involvement. Where the Board finds that an Intervenor's participation is premised solely on the protection of its business interests, it may be required to bear some or all of the costs of its participation in the proceeding. Where a party requests a review of a hearing that is denied on the preliminary question, it will be required to bear its own costs associated with that review.
Licensee Liability Rating (LLR) Program and License Transfer Process (Directive 006) (June 1, 2004) and Updated Industry Parameters and Liability Costs (Directive 011) (June 1, 2004)
Through the rescission of the following Interim Directives and Guides, Directive 006 amends and consolidates the rules applicable to the LLR Program and License Transfer Application.
Suspension Requirements for Wells (Directive 013) (December 1, 2004)
Directive 013 establishes requirements for the suspension of inactive wells. The objectives of this Directive are to ensure continued public safety, environmental protection and resource conservation at inactive wells and to consider appropriate risk factors in formulating well suspension requirements.
Utility Regulatory Audits and Reviews (Directive 016) (January 26, 2005)
Directive 016 outlines the legislative authority for regulatory audits and sets out the work to be carried out by the Audit and Compliance Group of the Utilities Branch when conducting regulatory audits. It also outlines the Board's objectives for conducting regulatory audits and provides information with respect to the treatment of information obtained or generated by the Audit and Compliance Group during the course of an audit. Independent and objective third party review of utility finances and operations are to be made available to the public by the Board.
Drilling Blowout Prevention Requirements and Procedures (Directive 036) (July 5, 2004)
The purpose of this Directive is to update the Board's minimum requirements regarding blowout prevention equipment and procedures for drilling wells. This Directive replaces sections 8.130 to 8.143 and Schedule 8 of the Oil and Gas Conservation Regulation and eliminates or modifies existing interim directives, general bulletins and informational letters that relate to drilling operations. Alta. Reg. 122/2005.
Resources Applications for Conventional Oil and Gas Reservoirs (Directive 065) (November 30, 2004)
Directive 065 simplifies the process for obtaining the necessary approvals from the Board to establish a strategy to deplete a pool by imposing a new set of requirements for all Enhanced Recovery (ER) scheme applications and eliminating Enhanced Recovery Recognition and Project Status applications.
To ensure the optimization of hydrocarbon recovery and that all ER scheme requirements are met, the Board will now review all ER scheme applications. ER scheme applications meeting the Directive 065 criteria will be processed in an expedited manner under a quick ER application process.
The Board will now audit all ER schemes approximately six months after approval or approval amendment.