The Regulation of “Gas Utility” Transmission Pipelines in Alberta

PDF Version: The Regulation of “Gas Utility” Transmission Pipelines in Alberta

Decision Commented On: ATCO Gas and Pipelines Ltd. Pembina-Keephills Transmission Pipeline Project August 6, 2019, AUC Decision 23799-D01-2019.

This decision of the Alberta Utilities Commission (AUC) deals with a large gas transmission pipeline designed to provide additional gas supplies to the Wabamun area (principally to provide fuel for coal to gas conversions of existing coal-fired generating facilities and additional gas generation). The decision reveals the surprising complexity of gas transmission pipeline regulation in Alberta.

The construction and operation of pipelines in Alberta (that are not federally regulated under the National Energy Board Act, RSC 1985 c N-6 (NEBA)) is governed by the Pipeline Act, RSA 2000, c P-15. Section 3.1 of the Pipeline Actmakes a fundamental distinction between pipelines generally and “gas utility pipelines”. Gas utility pipelines are regulated as to both construction and rates by the AUC. Other pipelines are regulated by the Alberta Energy Regulator (AER). For an example of a recent and significant AER pipeline decision, see Grand Rapids Pipeline GP Ltd. Applications for the Grand Rapids Pipeline Project October 9, 2014, 2014 ABAER 012. Such pipelines will generally be contract carriers not subject to any form of economic regulation. In some cases that has proven to be controversial with attempts made to bring those pipelines under regulation. See for example the many (unsuccessful) efforts made by Williams Energy (Canada), Inc. to bring NGTL’s Ventures pipeline under regulation as documented in various ABlawg posts here and here.

Jurisdiction of Regulator

3.1(1) Subject to subsection (2), the Regulator [the AER] has jurisdiction with respect to pipelines.

(2) The Alberta Utilities Commission has jurisdiction with respect to gas utility pipelines and exercises all the powers, functions and duties of the Regulator with respect to gas utility pipelines.

A “gas utility pipeline” means a gas utility pipeline as defined in the Gas Utilities Act. The Gas Utilities Act, RSA 2000, c G-5, in turn defines a “gas utility” and a “gas utility pipeline” as follows:

(g) “gas utility” means

(i) any gas pipeline,

(ii) any system, works, plant, pipes, equipment or service for the production, gathering, conveying, transmission, transporting, delivery, furnishing or supplying of gas by retail or wholesale, either directly or indirectly, to or for the public or any member of the public, whether an individual or a corporation, other than the transportation, delivery, furnishing or supplying by retail or wholesale, either directly or indirectly, of liquefied petroleum gas (except propane and butanes) by means of tank car, tank wagon, cylinder or vessel,

(iii) any absorption plant or scrubbing plant, and

(iv) any system, well, works, plant, equipment or service for the production of gas or capable of producing gas that may be declared by the Commission to be a gas utility;

(g.1) “gas utility pipeline” means a gas pipeline of a gas utility designated by regulation or of its affiliates;

In other words, a pipeline can only become a “gas utility pipeline” if it is a gas pipeline of a designated gas utility. The current version of the Gas Utilities Designation Regulation, Alta Reg 257/2007, designates only two gas utilities for the purposes of this provision: ATCO Gas and Pipelines Ltd. and AltaGas Utilities Inc. See also AUC Rule 020, Rules Respecting Gas Utility Pipelines.

A second distinction is that between a gas utility pipeline that is part of the “Integrated Alberta System” (IAS) and a gas utility pipeline that is not. The description of the IAS below draws heavily on the AUC’s current decision as well as several earlier decisions including AUC Decision 2010-228, ATCO Pipelines 2010-2012 Revenue Requirement Settlement and Alberta System Integration May 27, 2010; AUC Decision 2011-160, ATCO Pipelines Contract Transition April 20, 2011; and AUC Decision 2012-310, ATCO Gas and Pipelines Ltd. Asset Swap Application, November 22, 2012. It also draws upon on the illuminating rebuttal evidence filed by ATCO, March 22, 2019 in this current proceeding # 23799. This evidence is available on the AUC’s website by logging in to the AUC’s e-filing system and entering Proceeding # 23799; follow “documents” and then look for exhibit # 0095.

The Background to the Integrated Alberta System

The origins of the IAS date back to 2007 when the then Energy and Utilities Board (EUB) initiated a proceeding known as the competitive pipeline review proceeding. The proceeding was initiated to address concerns arising from the appreciation that there were in fact two natural gas transmission systems operating in Alberta. One was the original Alberta Gas Trunk Line (AGTL) system (see The Alberta Gas Trunk Line Company Act, SA 1954, c. 37) then operated by NOVA Gas Transmission Ltd (NGTL); the other was operated by ATCO Pipelines (AP). The existence of these two systems gave rise to a number of concerns that the AUC described as follows in its Decision 2010-228:

(i) Stacked Tolls: Parties that required service on both systems due to their geographic location within the province were subject to “stacked” tolls, i.e. the payment of tolls on both systems.

(ii) Duplicative Terms of Service: Parties that required service on both systems were subject to two different tariffs, or terms and conditions of service (e.g. nominations, balancing requirements, payment and credit terms, etc.) in the province. This created added time and cost in the administration of gas transmission service in Alberta.

(iii) Duplicative Regulatory Proceedings: With two major gas transmission systems operating in the same areas within Alberta, shippers using both systems were subject to an increased regulatory burden (dual GRA’s [General Rate Applications], both Phase I and Phase II, and other regulatory proceedings to deal with pipeline competition before two different regulatory tribunals).

(iv) Least Cost Regulatory Proceedings: The presence of two major competing transmission pipelines in the province gave rise to least cost issues, with many proceedings requiring regulatory resolution in order to ensure the orderly, efficient and least cost expansion of gas transmission service in Alberta. (at para 118; reference omitted)

On September 8, 2008 AGTL and AP announced that they had reached an agreement to integrate their systems as a result of which the EUB ultimately cancelled the proposed proceeding. At that time NGTL and AP were both under provincial jurisdiction – but that was about to change when NGTL applied to the NEB to bring itself under federal jurisdiction. On February 26, 2009, the NEB released Decision GH-5- 2008 declaring that the NGTL System fell under federal jurisdiction (for an earlier post on that decision see here) (effective on approval of a certificate of public convenience and necessity) and on April 7, 2009 AP and NGTL entered into the Alberta System Integration Agreement (Integration Agreement). By the time of the Integration Agreement therefore the AUC only had jurisdiction over AP; it had no jurisdiction over NGTL.

The AUC approved the Integration Agreement in principle in decision 2010-228 as part of the AUC’s approval of a negotiated settlement of AP’s revenue requirement for 2010 -2012. In its later decision on “Contract Transition”, AUC Decision 2011-160, the AUC described the elements of the Integration Agreement as follows:

The Integration Agreement requires AP and NGTL … to swap ownership of certain physical assets within distinct operating territories or “footprints” in Alberta (Asset Swap), and to work together in Alberta under a single rates and services structure, while maintaining separate ownership, management and operation of their assets (Integration). NGTL would be the party that interfaces contractually with customers for regulated gas transmission services using the combined regulated AP and NGTL gas transmission systems within Alberta (collectively, the Alberta System). AP proposed that NGTL would include AP?s approved revenue requirement through a monthly charge by AP to NGTL (AP Charge), in NGTL’s revenue requirement which will be collected from customers using the Alberta System. The total Alberta System revenue requirement would therefore be composed of the AP revenue requirement approved by the Commission and charged to NGTL plus the NGTL revenue requirement approved by the National Energy Board (NEB). This would form the basis for the determination of Alberta System rates and tariffs for all customers. As part of the implementation of the Integration, all AP contracts would be transitioned to Alberta System contracts with NGTL (Contract Transition). (at para 2)

There were thus five main elements to this arrangement. First, there would effectively be a single gas transmission system for which NGTL would have all operational planning responsibilities. Second, expansions to this integrated transmission system were to be approved as part of the Alberta System Annual Plan which in turn is guided by the Guidelines for New Facilities (Guidelines) and the Facilities Design Methodology Document (FDMD). The AUC describes the approach as follows in its current decision:

The documents guide the type of facility growth that NGTL will pursue moving forward and can be used to assist regulators [i.e. both the NEB and the AUC] to determine whether an application is consistent with the Alberta System Annual Plan under the approved Integration Agreement. ATCO Pipelines stated that the Guidelines were agreed to by NGTL and its stakeholders: the members of the Tolls, Tariff, Facilities and Procedures (TTFP) Committee. (at para 27)

The two documents have been approved by both the AUC and the NEB. In addition, NGTL is responsible for establishing “the Alberta System Terms and Conditions; the Alberta System Tariff; the Alberta System Rate Schedules and the Alberta System Tolls, all of which will require structuring so that they meet the needs of the Alberta core market served by local distribution companies connected to the Alberta System.” (As quoted from the Integration Agreement in AP’s rebuttal evidence at para 37.)

Third, the agreement documents the footprint of each of AP and NGTL (see map below). As such it contemplates that when the planning process identifies the need for new facilities those facilities will be built and owned by the party in whose footprint area the facilities fall. Existing assets were also to be swapped along the same lines. Fourth (and for the most part – there is an exception for ATCO Gas) the Agreement contemplated that NGTL would act as the sole contracting party to provide transmission service. This entailed that all of AP’s contracts would have to be migrated to NGTL. It also entailed that AP and NGTL would have to develop a mechanism to allow AP to recover its cost of service. The fifth key element addresses this last point. AP’s revenue requirement including its rate base continues to be determined by the AUC under the terms of the GUA. Once approved, this revenue requirement is then charged to NGTL on a monthly basis and recovered by NGTL through its customer tolls. The AUC explains the relationship between its regulatory function and that of the NEB in the current decision as follows:

Once approved, ATCO Pipelines’ revenue requirement is charged to NGTL on a monthly basis. The rates paid to NGTL by all customers connected to the integrated Alberta natural gas transmission system are those approved by the National Energy Board in applications filed by NGTL. These rates collect the combined revenue requirements of ATCO Pipelines (as approved by the AUC) and NGTL (as approved by the National Energy Board). As a result, under the integrated Alberta natural gas transmission system ATCO Pipelines no longer administers a tariff for the use of ATCO Pipelines’ system. (at para 28)

How Does This Apply Here?

The current proceeding was triggered by an application for service filed by Capital Power with NGTL (since all commercial contract arrangements are NGTL’s responsibility under the Coordination Agreement) requesting incremental firm transportation service of 200,000 GJ/day in four annual increments of 50,000 GJ/day commencing in 2021 (at para 30). As AP noted:

… the Wabamun area is home to approximately 4,500 megawatts of generating capacity from coal-fired plants, which represents approximately 28 per cent of the total 16,157 megawatt generating capacity in Alberta or roughly 38 per cent of Alberta’s peak internal load of 11,697 megawatts that was established on January 11, 2018. The substantial concentration of Alberta’s electricity generation in the Wabamun area has led to the development of significant electrical transmission infrastructure to transport generated electricity from this area. ATCO Pipelines stated that over the longer term, it expects that, from the perspective of new electricity generation, brownfield sites such as Wabamun would have significant development advantages over greenfield sites due to lower development costs and existing electrical transmission infrastructure. (at para 33)

CCA mounted an intervention in the proceeding arguing that this application was driven by a single customer (and by implication was therefore not a system demand) and that therefore Capital Power should be expected to make a capital contribution to the cost of the proposed facilities. AP’s response was to the effect that NGTL had run Capital Power’s application through its annual planning procedures and guidelines (adding additional confidential information from other customers and potential customers), had formed the conclusion that there was a need and accordingly (at para 53) NGTL had “directed ATCO Pipelines to build the extension because it falls within ATCO Pipelines’ footprint.” AP further noted (ibid) “that facilities meeting the extension facilities criteria are put into service as part of rate base” and that if CCA wanted to further question this approach it must do so before the NEB and (at para 53) “not indirectly as part of an ATCO Pipelines facilities application.”

The AUC essentially deferred to NGTL’s (federally approved) methodology for distinguishing between system-driven expansions and consumer-driven expansions:

The Commission considers that it is important in this proceeding to make the distinction between a mainline improvement and a customer lateral since, under the Integration Agreement, that determination affects the cost and facility ownership administration. The Commission accepts ATCO Pipelines’ assessment that the proposed project has been designed and sized to serve the long-term area demand forecast for the project area, which was determined on the basis of multiple information sources that include discussions with customers and AESO forecasts. The Commission considers the proposed project to be a mainline improvement rather than a customer lateral, since the project is driven by a forecast of multiple customer projects. In that situation, the NGTL methodology indicates that project costs are to be recovered from all shippers contracted on the integrated Alberta natural gas transmission system rather than by requiring a customer-specific contribution as recommended by the UCA. (at para 79)

The AUC noted that both regulators had approved the use of the Alberta System Annual Plan as a means of implementing the Integration Agreement and as a means of assessing expansion plans and that NGTL in this case had followed those criteria (at para 72). Under the NGTL system, once an expansion is classified as a system cost (at para 78) “The revenue requirement of the project will be divided equally between all receipt customers and delivery customers that pay the rates that will satisfy the combined revenue requirements of ATCO Pipelines and NGTL.”

Another argument of CCA was that the demand for natural gas in the Wabumun area could be adequately met by Tidewater’s Pioneer Pipeline. This pipeline is regulated by the AER rather than by the AUC. The response to this argument is that while this pipeline would certainly provide some additional capacity, given the concentration of generation assets in the Wabamun area, prudence dictates that there be a variety of infrastructure and contractual arrangements for the delivery of natural gas. This is a concern that Alberta’s Electric System Operator has raised in its long-term transmission planning: AESO’s 2017 Long-term Transmission Plan, at 23.

In the end, therefore, the AUC had little difficulty concluding that there was a need for the proposed pipeline project and that it was in the public interest.

Observations

It is interesting to reflect on the similarities and differences between the electricity transmission system and the natural gas transmission system. The electricity transmission system has evolved to the point where the different parts of the transmission system are owned by different transmission facility operators but the terms of access to that system are controlled by a third party system operator (the AESO) operating under a statutory mandate conferred by the Electric Utilities Act, SA 2003, c E-5.1, and subject to regulatory review by both the AUC and the Market Surveillance Administrator. The entire scheme is under provincial regulation. The scheme is governed principally by public law and is generally quite transparent -although as previous posts have pointed out some elements of the scheme (especially issues of cost allocation involving the AESO) lack transparency (see posts here and here).

By contrast, the natural gas transmission system has evolved in a more ad hoc and ‘private’ or commercial manner (reminiscent of the scheme for regulating the integration of the electric transmission system before the adoption of the EUA). There is no independent system operator. That function is served by NGTL (one of the transmission owners) and the principal terms of reference under which it operates are established by contract rather than by statute or regulation – albeit that NGTL is ultimately accountable to the NEB and provides service under NEB approved and regulated tolls and tariffs. The AUC’s only responsibility is for that part of the system owned by AP and facilities to be built by AP, and while the AUC approves AP’s revenue requirement, toll design is a matter for NGTL, its shippers and the NEB.

This arrangement is no doubt convenient and does achieve many of the results that the EUB was originally aiming at, but one consequence of this approach is that the AUC is effectively delegating to the NEB the authority to set an important element of the “just and reasonable rates, tolls or charges, or schedules of them” for service on AP (i.e. toll design). One implication of that in this case was that AP effectively instructed CCA to raise its concerns before the NEB – not before the AUC. This suggests that the coordination agreement may have resolved some of the regulatory complexity identified by the EUB but the subsequent decision to bring NGTL under federal regulation while leaving AP under provincial regulation created other complexities. It also makes me wonder (given the integrated tolling system based on a network of receipts and delivery points) why AP is not also subject to federal regulation. But that is no doubt a topic for another post – although it would seem that these two pieces of transmission infrastructure are far more integrated than is the Coastal GasLink Project with NGTL, as recently examined by the NEB: Jurisdiction over the Coastal GasLink Pipeline Project MH-053-2018, Letter Decision of the National Energy Board, 26 July 2019 (declining to assume jurisdiction over Coastal GasLink).

This post may be cited as: Nigel Bankes, “The Regulation of “Gas Utility” Transmission Pipelines in Alberta” (August 14, 2019), online: ABlawg, http://ablawg.ca/wp-content/uploads/2019/08/Blog_NB_AUCDecision23799.pdf

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Map of the Integrated Alberta System: AP’s ‘footprint’ depicted in blue (AUC Decision 2010-228)