CAARS Domestic Natural Gas Supply Rules March 11, 1993 1.0 BACKGROUND 1.1 Deregulation in Natural Gas Supply Since 1985 In March of 1985, the Western Accord between the Federal Government and the western provinces established that wellhead deregulation of oil prices would occur and directed that a companion agreement on natural gas prices be negotiated by November of 1985. The Government of British Columbia then moved quickly to enact the British Columbia Natural Gas Price Act in June of 1985. This Act allowed large gas users in the province to contract for separate gas supplies. On October 31, 1985, the Federal Government and the western provinces entered into an Agreement on Natural Gas Markets and Prices, ("the Hallowe'en Agreement").
A "Backgrounder" to the Hallowe'en Agreement stated the objectives of the Agreement as follows: "The agreement among participating governments is intended to create the conditions for a new market-responsive pricing system consistent with the regulated character of the transmission and distribution sectors of the gas industry. It signals an end to government administered prices and a return to market forces characterized by choices for buyers and sellers. While the agreement provides for a transition period of one year, access will be immediately enhanced for Canadian buyers to natural gas supplies and for Canadian Producers to natural gas markets. The new regime will provide the framework for negotiated prices between buyers and sellers. Prices will be affected by conditions in the marketplace; both supply and demand will influence the price. Competition will be fostered which should increase the industry's ability to react quickly to changing conditions." British Columbia was the first province in Canada to allow large industrial customers to purchase their natural gas supplies directly from producers. The British Columbia Utilities Commission ("the BCUC","the Commission") was asked to deal with issues such as the unbundling of rates, by-pass, allocation of the benefits and costs between those leaving the local distribution utility and those remaining as utility customers ("Core Market Customers") for gas supply. In its Decision on Inland Transportation Tariffs dated June!17, 1987, the Commission ordered that while incremental costs to the other utility customers resulting from the departure of industrial customers should be covered by the departing customers, inherent benefits such as load factor should go with the departing customer.
2 2 1.2 Core Market Policy In June of 1988 the Minister of Energy, Mines and Petroleum Resources issued a policy paper, entitled "British Columbia Natural Gas Core Market Policy". At the same time the Commission received new responsibilities under Section 85.3 of the Utilities Commission Act ("the Act") to review energy supply contracts. In that regard, the Commission established "Rules" in August of 1988.
While the Core Market Policy applied to all end users of natural gas in British Columbia, it focussed on the Core Market, namely those end users who were purchasing gas from the local distribution company ("LDC") at the time the policy was announced. To leave the Core Market and purchase directly, an end user had to meet the requirements in the Commission's Rules. Under these Rules, there are no restrictions on industrial purchasers who buy gas for any term up to two years, while restrictions do apply to industrial purchases for contracts beyond two years. Commercial and residential customers require a gas supply portfolio with a diverse supply and an average rolling five!year term for process loads or 15!year term for residential heating loads. The 15!year requirement, together with minimum charges contained in LDC transportation tariffs, have rendered direct purchases uneconomic for residential end users, as none have left the Core Market under these provisions.
Other key requirements of the Rules are that: • All gas supply contracts and amendments are to be filed with the Commission. • The confidentiality of contracts is to be maintained unless disclosure is in the public interest. • A third party review of reserves and deliverability must be undertaken. • The direct purchasers assume risks of availability and price. • The utility is allowed up to 13 months to accommodate returning customers. • Changes to the Rules are to be prospective and all approved contracts are to be honoured.
3 3 1.3 Developments in Other Jurisdictions While the Core Market Policy and Rules in British Columbia have tended to restrict direct purchases to industrial and large institutional end users, there has been more activity in opening up the market in several other jurisdictions in Canada. In the Provinces of Ontario, Quebec and more recently, Manitoba, the introduction of direct purchase in the form of "buy-sell" arrangements has facilitated direct sales to smaller commercial and residential users.
In Ontario and, to a lesser extent in Quebec, the Direct Purchase market has been essentially free to operate without oversight from government regulators. However, this has led to a number of difficulties. Recently in Ontario steps have been taken to introduce minimum conditions of supply which took effect in January!1993. In 1991, the Manitoba Public Utilities Board approved direct purchase and introduced a licensing requirement for agents/brokers/marketers ("A/B/M's").
In reviewing its Rules in this Decision, the Commission has considered the developments in other jurisdictions with the introduction of direct sales on a broader scale. It has not, however, adopted any particular model from these jurisdictions, but rather has focussed on the particular issues in the Province of British Columbia. 1.4 B.C. 1992 Domestic Supply Policy On June 23, 1992, the Ministry of Energy, Mines and Petroleum Resources advised interested parties that it was conducting a Core Market Policy review and invited comments. On November 17, 1992, the Ministry released its new policy statement on domestic natural gas supply. The title "Domestic Supply Policy" ("DSP") was used to replace "Core Market Policy". A copy of the DSP is attached as Appendix B to this Decision.
From the general language of the DSP, the Commission believes that the DSP's principal intention is to distinguish between those for whom security of gas supply is of paramount importance and those for whom security of supply is but one of several business decision factors. Thus, if gas consumers were placed along a continuum, one end would be represented by a single family residence using gas for space heating with no stand-by alternative fuel, while the other end would be represented by a commercial, industrial or institutional consumer with an alternative fuel supply.
4 4 The following are key quotes from the DSP. It applies to; "...all consumers who rely upon natural gas mainly as a space heating fuel, and do not have alternative fuel capability or expertise in arranging a supply of natural gas."
Other gas consumers who: "...use gas mainly for productive purposes or are sufficiently versed in natural gas acquisition may not have as strict a contract security requirement and can be exempted from the policy. To be exempted, consumers must establish that they have arranged, and are able to arrange on an ongoing basis, an adequate supply of gas."
While these two statements appear straightforward, their interpretation can be problematic. Specifically, a literal interpretation suggests that any consumer who has arranged gas supply with the help of an A/B/M is exempt from the DSP; by signing a contract with an A/B/M the consumer has acquired the necessary "expertise in arranging gas supply" in the same way that a very large firm might contract for gas supply expertise.
However, the Commission also has the responsibility to determine the specific conditions necessary for exemption. If the Commission decides that these conditions must be identical to the conditions applying to those who remain under the policy, it is irrelevant whether a consumer is considered to be exempt or not from the DSP.
Therefore, in this Decision the Commission makes the following initial determinations: • The Decision makes no comment on who is, or is not, exempt from the DSP. This is not material to the application of the gas supply contracting rules.
• Every gas consumer is eligible to continue purchasing system gas from their LDC.
5 5 • Every gas consumer is eligible to opt for direct purchase of natural gas, provided that certain contracting and supply conditions are met to ensure comparable conditions with LDC system gas supply.
• The gas supply contract rules described in this Decision, and presented in detail in Appendix!A, apply to all gas consumers. However, these rules distinguish between the requirements for core market consumers and those who have stand-by alternative fuel capability or who use natural gas as a production feedstock. Core market consumers, as defined by the Glossary, may now be either system gas consumers or direct purchase consumers.
1.5 BCUC Generic Hearing to Set Rules For Domestic Natural Gas Supply The DSP is to be implemented by the Commission. In order to review its Rules, the Commission decided to hold a generic hearing to obtain the views of interested parties. The Order and list of issues to be considered in the hearing are attached to this Decision as Appendix C.
The hearing commenced on January 11, 1992 and concluded on January 21, 1992. Written argument was filed by January 28, 1992 and reply argument by February 2, 1992. Thirty-seven parties submitted written comments prior to the hearing. Eight of those took an active role as intervenors in the hearing. The intervenors represented four groups, the LDC's, producers, A/B/M's and consumers.
The sanctity of contracts and market integrity were the primary issues of concern to the producers and the LDCs. A/B/M's focussed on the barriers to the creation of an open market in British Columbia. Consumers wanted to participate in direct purchase arrangements and be permitted to make their own decisions on the trade-offs between risks and costs.
A major focal point for the hearing was the importance of transportation capacity on the Westcoast Energy Inc. ("Westcoast") system. In particular the availability of Transportation South ("T-South") or Zone!4 transportation was viewed by A/B/M's as key to their participation in direct sales. A map showing the Westcoast system was filed in the hearing and is attached to this Decision as Appendix!D.
6 6 2.0 SECURITY OF SUPPLY In the past, government policy and utility commission regulation in many North American jurisdictions has emphasized the importance of long-term supply contracts to enhance security of supply, especially for core market customers of LDCs. In the DSP hearing, the arguments made by producers and LDC's generally reflected the historic position, namely:
• Long-term contracts provide an incentive for exploration and development by those producers who are signatories.
• Customers with long-term contracts are given preferential treatment by producers during times of transient supply shortages, thereby enhancing security of deliverability.
• Because B.C. is a gas producing province, domestic supply policy should emphasize a stable market and investment climate for producers.
• Reliable access to gas transportation and processing between the field and the LDC is essential to supply security, and such access is facilitated by long-term contracts.
However, the Commission heard arguments from other participants suggesting that in a properly functioning deregulated market, long-run security of supply is primarily determined by the natural gas resource potential and the associated profit expectations for exploration and development. Moreover, the time frame required by the natural gas industry to respond to tightening supply markets (and therefore rising prices) is more likely to be in the three to seven year range, not the period implied by the 15 year reserve requirements in previous Commission Rules. The Commission recognizes however, that Westcoast transportation availability may constrain "proper functioning" of the British Columbia market, especially in the short term. 2.1 Long-run Security of Supply The utilities noted that key factors in security of supply include quality of reserves, deliverability, financial health of the supplier, and access to processing and transportation. The producing community, as represented by the comments of CAPP, Czar and Talisman, feel that the resource base in B.C. is not a concern. CAPP currently sees B.C. as one of the most interesting and promising areas for exploration and development in Canada. CAPP and Czar suggested that length
7 7 of contract term increased security of supply, along with legislative and regulatory stability and a healthy natural gas industry. Talisman added that prudent gas supply contract arrangements backed by real assets, as well as transportation contracts with terms consistent with the terms of the supply arrangements, were also factors. In Talisman's view, the alignment of high quality B.C. gas supply sources with long-term core markets "enables reinvestment in exploration, development and production of new gas supplies" (Exhibit!40, p. 4).
However, the need for long-term supply contracts, in the order of 10 to 15 years, was not supported by evidence regarding the time required to bring new supplies on line. Producers indicated that three to seven years is required to find new reserves and develop them into new supply, although this could be as short as 18!months in favourable circumstances. Additionally, expansion of Westcoast facilities takes from less than a year to three!years for processing capacity. Transmission capacity can be increased in 18!months.
In general, the evidence indicated that long-term contracts with annually renegotiated prices provide little in the way of long-run security for the customers tied to these contracts. This security is only maintained if these customers (or their purchasing agent, such as the LDC) bid at least the market clearing price for gas in each year, the same option that is available to those customers who do not have long-term contracts. Most of the LDC long-term supply contracts are subject to yearly renegotiation or arbitration of price (T!208). As argued by ECNG, long term contracts of this type provided no assurance with respect to future prices (Exhibit!26 p. 2).
Long-term contracts with reserve commitments tend to have higher prices even though the prices are renegotiated every year. Since both producers and consumers benefit from the lower transaction costs of longer term contracts, the only rationale given for these higher prices were (1) that producers dedicate their highest quality reserves to such contracts and (2) that long-term contracts require producers to tie up reserves for several years. Participants disagreed as to whether these higher prices were justified. Producers and LDCs argued that risk reduction and higher quality reserves were worth the higher price. Marketers and Dr. Uhler believed that the key reason for the higher price was the requirement to tie up reserves. They argued that it made little sense in a deregulated market, with plentiful natural gas potential, to pay extra to set aside gas reserves for several years, especially when these reserves were only guaranteed if the customers holding such contracts were prepared to match the market clearing price in any given year.
8 8 BC Gas suggested that because B.C. is a gas producing province, domestic gas supply policy should emphasize a stable market and investment climate for producers (Exhibit!13 p.!1 and T!957-959). However, Dr. Uhler argued that the change in market structure due to deregulation, leading to many new buyers in the market, has changed the incentives for gas development, and reduced the need for long-term contracts as a requirement for supply security. Dr. Uhler's thesis was supported, in part, by the CAPP panel who stated that the decision of producer companies to explore for and develop new reserves was based on the cash flow and economics of the industry at the time, rather than on the existence of a long-term contract (T!288). Enron (Arg, p. 20) also suggested that the market would operate to balance supply and demand. Moreover, the fact that B.C. is a producing province should not affect the direct purchase policy. Producers have been arguing for some time that what they want is a move to more deregulated markets.
With respect to short-run security, Talisman submitted that, in times of short-term supply crisis, a typical producer may have a hierarchy of gas supply and deliverability commitments under which longer term markets are given priority over equivalent shorter term contracts. Others argued, however, that market priority was an item that could exist in contracts separately from length of term, and that in any event producers would tend to give priority to those contracts providing the greatest return. LDC witnesses (Consumers Gas and BC!Gas) pointed out that it is virtually impossible for the utility to shut-off small industrial, commercial, and residential customers during a short-run crisis. BC!Gas noted that limited storage reduced their ability to supply compared to that of Consumers Gas, but pointed out that, even as an issue of company image, residential customers whose supply had failed would be the last affected in a short-run crisis. However, notwithstanding the fact that residential customers will be the last group of consumers at risk from short-term supply failure, it is important that security of supply to the LDC system not be significantly compromised. This issue is addressed in Section 2.3. 2.2 Transportation Services and Security of Supply Deliverability and access to Westcoast processing and transportation services are essential components of supply security. Few, if any, parties disputed this proposition. Although most of the firm gas transmission contracts on the Westcoast system are currently short-term, renewal options give the holder of service the ability to retain capacity on a longer term basis. During the hearing, Westcoast testified that it is currently proposing a five year minimum contract term to the National Energy Board ("NEB"), with an 18!month notice period for renewal rights for firm service contracts. Shippers requesting an expansion of the Westcoast system are required to sign a
9 9 ten-year contract for capacity as well as demonstrate either a ten-year market or a ten-year supply. However, most of the transportation capacity for core market consumers is held by the LDC and has been assigned, with recovery rights, to system gas suppliers. Exhibit!51 showed the BC Gas situation related to Westcoast capacity and is attached as Appendix E to this Decision. The need for transportation capacity for core market consumers is not altered whether contracts are long or short term.
Westcoast testified that its pipeline expansion decisions were largely based on its forecast of overall long-term supply and market growth. Capacity requests driven by displacement, rather than market growth, would not lead Westcoast to expand its system (T!124).
2.3 Reducing the Length of Reserve Requirements In implementing the Core Market Policy of 1988, the previous Commission Rules favoured longer term contracts with reserve and deliverability commitments for core market consumers. The logic of this approach was that individual consumers may lack the expertise to make trade-offs between price and security that are in their own long term best interests. The general move to deregulate natural gas markets, as supported by the new Domestic Supply Policy in B.C., suggests that consumers should have this freedom to choose, at least until it can be shown that the deregulated market is not capable of functioning in consumers' long run interests.
The Commission believes that in the current increasingly deregulated market (with a plentiful natural gas resource base, many buyers and sellers, and a predominance of contracts in which the price is annually renegotiated) contract terms and reserve commitments far in excess of the time period necessary to develop and bring to market new reserves may not be worth the higher prices that are generally associated with such contracts. In any event, to as great an extent as possible, consumers should be allowed to make their own decisions about market risks and costs rather than have these determined by the Commission. However, in anticipation of future market conditions, in which the natural gas market may tighten, and recognizing that a four year contract will provide a minimum of three years contracted gas at all times, the Commission believes that a four year rolling average reserve and deliverability commitment is a reasonable minimum for core market consumers.
The Commission finds that gas supply contracts for the core market need no longer be backed by 10!to!15 years of reserves and deliverability. Instead, the
10 10 Commission sets a four year rolling average as the minimum reserve and deliverability requirement of all contracts for core market consumers. The rules will provide for a Corporate Warranty to be substituted for dedicated reserves, if appropriate. (The only gas consumers who are exempt from the four year minimum requirement are those who were considered to be non-core under the previous Core Market Policy and those who can demonstrate that they have a viable stand-by alternative fuel capability or use natural gas as a feedstock.)
Much of the growth in direct sales in other jurisdictions has arisen from the differential between the price of short-term gas and the price of LDC purchased gas, the latter based on long-term contracts and reserve requirements. There is no social benefit to a situation in which dramatic market opportunities are created simply because the LDC is restrained from level competition by a requirement that its contracts remain long-term, while direct purchasers are able to sign shorter-term contracts. If, as occurred in Ontario, a level playing field is eventually created, the LDC only belatedly starts to be able to provide a competitive alternative to direct purchase through lower system gas tariffs. Thus, it is important that the direct purchase industry not over-expand simply because of regulatory asymmetry. If the LDC can be safely permitted to better compete for gas sales, the customer is the ultimate beneficiary.
To maintain a level playing field, LDC's are encouraged to renegotiate any existing supply contracts in which the term of the contract (and the associated price) prevents them from offering a comparable product to that of direct sellers. Above the four year minimum, LDCs and A/B/M's are free to set contract terms and reserve requirements that satisfy their appraisal of their customers' price-risk trade-offs.
The Commission further directs that on or before the commencement date of each contract and on or before each anniversary date, the direct-sale gas supplier be required to confirm to the LDC that it has a minimum supply reserve and deliverability extending over the next four years. This confirmation may be by means of a report from an independent third party expert or by a Corporate Warranty acceptable to the utility.
11 11 2.4 Supplier of Last Resort There was considerable discussion during the hearing about an LDC's role in the event of a direct sale supply failure. In particular, the discussion focussed on the extent to which the LDC is responsible for supplying back-up gas.
In other jurisdictions, it is generally accepted that the LDC is the supplier of last resort, regardless of whether or not there is any legal or regulatory obligation in that regard. Most LDCs appear to have recognized that it is in the best interests of all parties for the LDC to make its best effort to provide backstopping.
In B.C., because of a lack of storage capacity close to the major load centres, the LDCs may have more difficulty in backstopping direct sale supply failures at a reasonable cost. In some circumstances, unauthorized over-run ("UOR") penalties may be incurred.
BC!Gas suggested that each buy-sell broker should provide backup supplies by contracting for gas supply and Westcoast capacity at a level of 110!percent of its customers' daily deliverability. In the hearing, Great West testified that in Ontario a 110!percent minimum condition of supply was negotiated between the A/B/M's and the LDCs to backstop not only the direct purchase customer but the system supply as well (T!1262). For B.C., Great West also suggested a similar condition for its core market customers (T!1365).
The Commission believes that by requiring equivalent security of supply from both LDC's and A/B/M's, there is no need to require additional backstopping for A/B/M contracts. The Requirement for 110!percent deliverability could also be viewed as tilting the playing field against A/B/M's. The Commission concludes that 100!percent deliverability is appropriate for all base load suppliers.
The Commission requires the LDC to act as "supplier of last resort", on a best-efforts basis. Any additional costs incurred by the LDC in providing last-resort back-up service are to be recovered from the failed supplier's customers. In the event of non-payment of utility bills by any of these customers, the LDC shall recover such unpaid amounts in exactly the same manner as it would from a system gas customer.
12 12 3.0 MARKET DEVELOPMENT AND MARKET INTEGRITY Consumers represented at the hearing were in favour of the anticipated benefits of direct purchase options such as buy-sell arrangements. However, organizations such as the Public Interest Advocacy Centre ("PIAC") were anxious to avoid the potential of unethical business practices emerging in a new and unfolding market. All intervenors agreed that customers in a deregulated market would stand to lose in the long term if the market were destabilized by questionable practices by any of the market participants.
Some intervenors were concerned that the development of a truly competitive market could be unduly limited by stringent requirements for new market participants, especially smaller A/B/M's. In the words of Great West, "...[the] BCUC should not be the paternalistic protector of all consumers. Rather there will have to be a large element of caveat emptor governing the market" (Exhibit 29, p.9). During the hearing, the Commission also heard about practices in other jurisdictions regarding requirements for A/B/M's. The question before the Commission is how much and what kind of protection is the appropriate balance between protecting consumers from unethical marketing practices and preventing them from realizing the benefits of deregulation by placing too many constraints on the market.
Suggestions as to how to prevent consumer abuses included: licensing or bonding of A/B/M's or both, providing consumer information on gas markets, standard form contracts and agency agreements, a code of conduct for A/B/M's, and appropriate indemnification against unwarranted transfer of risks or costs to other parties.
The Commission views its responsibilities in a deregulated market as being the maintenance of a secure and orderly market that provides competitive options to consumers while ensuring that the gas supply to single fuel consumers will be available even in adverse circumstances. However, the Commission does not accept a responsibility to ensure that price discounts for end use customers are realized. Direct Purchasers are expected to assume their own risks. 3.1 Licensing Among A/B/M's, ECNG argued that there was no need for licensing, but suggested that if some form of certification was to be required, then the Manitoba situation - where brokers were required to file company information in order to receive an annually renewable licence - was a suitable
13 13 model. Other A/B/M's generally supported licensing, with Great West suggesting that licensing should require adherence to criteria similar to those found in the Ontario Natural Gas Association ("ONGA") Code of Conduct.
Most other intervenors generally agreed that licensing is desirable. For producers, CAPP stated that it is appropriate that terms and conditions under which A/B/M's operate be established, and perhaps enforced through licensing requirements. On behalf of consumers, both PIAC and PWC supported licensing. PWC noted that it is registered as a broker in Manitoba. All three LDCs also suggested that there should be a registration and licensing system for A/B/M's with minimum qualifications or a code of conduct attached. In summary, the licensing of A/B/M's is seen as a useful device for screening inexperienced or insubstantial parties from entering the direct purchase market, and for monitoring the business practices of A/B/M's in the field.
The Commission finds that licensing of A/B/M'S is in the public interest. Any person wishing to engage in direct sales to core market consumers shall first obtain a licence from the BCUC. The BCUC will set the licensing requirements.
3.2 Bonding Bonding was supported by two of the marketing organizations to ensure the performance of direct sales A/B/M's. Great West suggested that brokers and marketers should be bonded in the amount of $250,000. Enron supported a bonding requirement in the order of $500,000. BC Gas suggested that the size of the bond should be related to the volume of gas being shipped. On the other hand, ECNG suggested that there was no need for bonding as evidenced by the experience of Ontario and Quebec where this is not required. It was also pointed out that the need for bonding requirements was reduced by the fact that brokers depended on the LDC for payment; the LDC could withhold payment to recover at least some of its costs from the broker.
For producers, CAPP stated that the terms and conditions under which A/B/M's operate should preferably include bonding. Czar also supported bonding of brokers.
In the opinion of the PIAC, A/B/M's operating in the core market should not necessarily be bonded. In argument, the PIAC stated that, while not strongly opposed to bonding, they were unconvinced of its utility. PIAC indicated that costs to end users could be increased by such requirements.
14 14 The Commission finds that A/B/M licensees must provide a gas delivery performance bond in the amount of $250,000 which the BCUC will hold in trust. The proceeds of the bond shall be used, in the event of a failure of supply arranged by the Licensee, towards the compensation of the LDC for such damages incurred by the LDC as may be agreed upon, or determined by the Courts.
3.3 Code of Conduct Adherence to an approved Code of Conduct was also proposed as a requirement for direct sale A/B/M's. ENGM stated that a Code of Conduct should be developed similar to that of the ONGA. Great West also supported the adoption of a Code of Conduct similar to the ONGA Code, which it filed as evidence (Exhibit 29, schedule B).
BC Gas suggested that in order to ensure jurisdiction over A/B/M's, legislative amendments would be required. As an alternative, it suggested that the Ontario model of a voluntary arrangement should be attempted first (BC Gas Argument, p.23).
The Commission finds that every A/B/M wishing to participate in direct sales in B.C. shall agree to abide by an approved Code of Conduct. Until such time as the B.C. A/B/M's, in consultation with the LDC's are able to produce a code and it has been approved by the BCUC, the current version of the ONGA Code of Conduct will be used. Breach of the Code will be sufficient cause for licence suspension.
3.4 Standard Form Contract and Other Consumer Information Another measure that was suggested to ensure market integrity, was the requirement for pre-approved, standard contract forms for direct purchase contracts. Witnesses for BC Gas supported the use of a standard form of buy-sell contract between the LDC and buy-sell brokers that would contain conditions and a fixed reference price so that all suppliers would be dealt with on the same basis (T.1068, 1173). McDonald's Restaurants also suggested that a standard form of contract for use between the buy-sell broker and the end-user would be useful (T 1332). Great West, in argument, also suggested that a standard form of buy-sell contract should be filed with the
15 15 BCUC, as well as any contracts that significantly deviated from that form (p.19). There were no strong arguments in opposition to these proposals.
The recent Manitoba Decision (Exhibit!72) on buy-sell contracting indicates that the practice adopted by the Manitoba Public Utilities Board is to establish generic terms and conditions to be included in contracts between brokers and the LDC, but not between brokers and end-users or between brokers and suppliers.
The Commission directs natural gas LDCs in B.C. to develop, in consultation with A/B/M's expected to be active, standard forms of gas supply contracts, including pricing mechanisms, for use in the delivery of buy-sell gas to customers in its service area. These contract documents, and any subsequent amendments, must be submitted to the BCUC for approval, prior to implementation. In addition, the rules (Appendix!A) will require minimum standards for agency agreements between A/B/M's and consumers.
On a related contract matter, INGM proposed that system gas consumers should have an opportunity to amend or terminate existing contracts signed with A/B/M'S in expectation of the new DSP and Commission rules. Great West stated that it had acted responsibly and at some expense to develop this market and that it would be inappropriate and beyond the jurisdiction of the Commission to interfere with these contracts. The Commission believes that no action is necessary on this matter, but requires all contracts to comply with the rules.
A number of intervenors suggested the use of Standard Consumer information booklets outlining the risks and benefits of direct purchase as a consumer protection measure.
The Commission also directs the LDC's to consult with A/B/M's to prepare an information booklet that outlines the risks and benefits of direct purchase. This booklet must be distributed to prospective clients when they are first approached by A/B/M's, and must be referred to in the agency agreement.
16 16 3.5 Confidentiality Section!85.3 of the Utilities Commission Act requires that gas supply contracts must be filed with the Commission, and that all information filed including contracts, should generally be made public, except where the Commission considers that disclosure is not in the public interest. The onus of proof in all cases is on those wishing to maintain confidentiality of any specific contracts filed at the Commission.
In principle, competitive markets work in the best interests of consumers when prices and other key contract provisions are public knowledge. This is because competition, with complete information available to all market participants, should drive price down to its lowest possible level, that being the level at which producers are just able to recover their long run costs plus a risk-adjusted normal return to capital.
However, most intervenors argued that the interests of consumers would be better served if gas supply contracts filed at the Commission were kept confidential. According to Talisman (T!468-470): (1) price competition is vigorous because the purchasing agents of consumers (LDCs and A/B/M's) are well informed by various means, such as confidential price survey reports; (2) the interests of consumers are also protected because the contracts are subject to Commission review and approval; (3) there may be price benefits to domestic consumers to the extent that there are confidential price distinctions between close and distant (export) markets; and (4) all generic clauses of contracts have already been disclosed by the Commission ruling in this gas supply hearing. (This ruling required BC!Gas to file typical examples of gas supply contracts and Westcoast operating and cost of service agreements.)
The Commission directs, under Section 85.3 of the Act, that all gas supply contracts, including those for the direct purchase market between A/B/M's and their suppliers, be filed with the BCUC. At the time of filing, the filing party shall provide with each contract brief written argument as to why it is in the public interest that the filed contract remain confidential. If the Commission accepts the argument for confidentiality, price or other significant information may be released in aggregated or summary form. The Commission reserves the right to make additional disclosure in specific circumstances, if this is considered to be in the public interest.
17 17 3.6 Sanctity of Contracts Gas supply contracts, especially those with longer terms, contain provisions designed to enable the agreements to function over their life, in spite of changes in circumstances. However, amendments to agreements may be prompted, especially when the viability of an existing arrangement is threatened by changing circumstances. B.C.'s Domestic Supply Policy does not contemplate the abrogation of existing gas supply contracts. But it also assumes, in good faith, that gas supply contracts have not been entered into which effectively prevent the changes in the gas supply market envisioned by changing government policy.
Marketers, in argument, submitted that gas supply and cost of service contracts, currently existing between producers and LDCs, should not be allowed to prevent the development of direct purchasing. Some parties argued that the Commission has the jurisdiction to require contract amendments, while others argued that the inclusion of regulatory action in force majeure provisions did not require abrogation.
Many parties including CAPP and Unocal recognized practices and regulations regarding supply contracts may change over time. In other jurisdictions, including Ontario, regulators have supported movement to more direct sales and a more open and competitive industry. Rather than abrogate the supply arrangements, the regulator encouraged the parties to renegotiate them in response to the new situation.
A common provision of modern long-term supply contracts enables a buyer to reduce its daily purchase quantity if its market shrinks. This reduces its annual take and other obligations and is known as Market Out. One issue is whether direct sales which move under a buy-sell mechanism would continue to be considered part of the LDCs market. A related matter is the effect on load factor and gas cost under the LDCs' contracts if buy-sells proceed without Market Out.
In its submission and testimony, BC!Gas stated that its contracts give it the ability to reduce the daily contract quantity under a typical supply contract if it suffers a permanent loss of market. However, where the loss was to a direct purchase which moved through its system under a buy-sell arrangement, the gas would continue to be delivered to the customer under a sales tariff. BC!Gas' position is that it would be unable to exercise Market Out provisions as a result of buy-sells and consequently that the amount of buy-sell permitted should be limited to market growth, or about 24!PJ over the next three years.
18 18 If BC!Gas enters into buy-sells for substantial volumes of gas and is unable to Market Out as a result, one alternative would be to attempt to sell the supply it no longer needed off-system on the spot and short-term market. Mobil's evidence indicated significant potential for these sales.
If BC!Gas were to Market Out, it was the position of the utility that typically its Gas Purchase Contracts and related Cost of Service Agreements would provide the supplier with a right of first refusal for the Westcoast service that was no longer needed to deliver the supplier's gas to BC!Gas. That is, the Westcoast service could well be permanently lost to BC!Gas and its customers.
No evidence was presented with regard to the ability of PNG or Centra Gas to Market Out. Great West, Enron and others argued that Market Out provisions agreed to in 1991, which did not anticipate the movement of direct purchase gas by buy-sell and which did not retain access to Westcoast service for buy-sells, are not in the public interest. Moreover, they felt these deficiencies should be corrected by regulatory action or negotiation.
Nothing in the Domestic Natural Gas Supply Policy envisions the abrogation of existing contracts. However, in moving towards implementation of this new policy, the Commission expects that contracts signed under previous government policy and Commission rules should not serve as barriers to the development of the direct purchase market. If existing contracts between suppliers and the LDC prove to be an impediment to the development of this deregulated competitive market, the Commission will take such further action as it deems necessary to ensure that the direct purchase market has access to Westcoast transmission capacity intended to serve the core market. Of particular concern is the assignment by the LDC's of capacity on the Westcoast system, which is addressed in detail in the next section.
19 19 4.0 WESTCOAST TRANSPORTATION The Commission believes, based on the large body of evidence presented at the hearing, that the lack of open access to capacity on the Westcoast system in general, and Zone!4 transportation capacity in particular, is a major impediment to opening up the marketing of natural gas in British Columbia. A truly open market for buying and selling natural gas can only be created if all potential buyers and sellers have open access to the monopoly transportation systems. The Commission believes that ultimately, control of transportation which serves core market consumers should be held by the LDC on behalf of those consumers, and assigned only with recovery rights as required to provide core market consumers with freedom of choice in making their gas purchase arrangements.
4.1 Transportation Availability Westcoast permits the assignment of service to another financially sound shipper, but will only do so with the agreement of the present holder of the service. Much of the Westcoast service used to deliver gas to BC Gas customers is presently in the hands of the suppliers of that gas. BC!Gas' evidence (Exhibit!51) is that it holds 215!MMcf/d of Zone!4 service and has assigned 311!MMcf/d to its suppliers. At issue is the ability of BC!Gas to obtain reassignment of transportation service to facilitate direct purchase by system gas consumers.
The Commission is of the view that firm Westcoast transmission capacity currently allocated to gas supplying the B.C. core market should continue to serve that market regardless of the identity of the supplier. This belief is consistent with many of the views expressed by the National Energy Board ("NEB"), and with the action of the NEB in allocating this portion of firm Westcoast capacity in 1989, as expressed in its Reasons for Decision RH-1-89 (Exhibit!87).
"In reaching its decision, the Board has given considerable weight to the view expressed during the hearing that the security of supply to the core market in B.C. should not be adversely affected. Accordingly, the Board has decided to accept Westcoast's proposal to reserve the sales capacity currently used to serve sales to BC!Gas/Inland for ripe deals serving the core market,..."
The Commission concludes that suppliers of direct sales gas to core market customers should first seek assignment of capacity from the LDC when
20 20 contracting with the LDC for delivery of direct sales gas. When suppliers or A/B/M's present the LDC with direct sales contracts for core market consumers, complete in every other respect, and lacking only Westcoast Zone!4 transportation, the LDC shall do its utmost to provide the necessary transmission capacity. Alternatively, if LDC-held transportation capacity is unavailable, the direct sale gas supplier may provide its own Westcoast capacity. By May of 1994, the Commission will evaluate the actions that each LDC has taken to accommodate the intent of this Decision to facilitate consumer gas supply choices. 4.2 Future Control of Transportation The Commission expects that subsequent to the date of this Decision, one responsibility of an LDC will be to plan and arrange for Westcoast Zone!4 transmission for customers subject to the DSP on its system whether these customers are served by system gas, buy-sell arrangements, or under transportation service agreements. The Commission expects a direct purchase consumer will be able to, and will be expected to, obtain Westcoast Zone!4 transmission service from the LDC and will be obliged to return the service when no longer required.
In particular the Commission directs that future base load gas supply portfolio contracts of the LDC assign transportation capacity to a supplier only so long as that capacity is being used for system gas sales. In the event of loss of system gas sales to direct-sales, future LDC contracts shall be required to provide for the return of required capacity to the LDC and the LDC shall in turn re-assign the necessary portion of relinquished capacity to direct-sales suppliers with ripe contracts which lack only Westcoast transportation capacity.
The LDC shall also incorporate in future contracts an arrangement for reducing its purchase obligations by pro-rationing system gas loss of sales among its suppliers in such a way that the cost impact on system gas consumers will be minimized.
The Commission is well aware of the constraints that the BC!Gas/producer contracts and capacity allocation practices on the Westcoast system pose for the development of competitive gas sales. The Commission has encouraged BC!Gas to renegotiate contracts, and a review of market development will occur early in 1994. In the absence of successful negotiations to free up BC Gas
21 21 capacity for buy-sell arrangements, there remains some capacity from market growth and existing contracts that will be available this year. However, if there are a large number of buy-sells requesting access to BC!Gas capacity, the Commission may have to consider additional actions to ensure that access be provided, recognizing the costs involved.
Alternatively, new suppliers may seek to bring their own Westcoast capacity to serve a group of consumers now served by the LDC. In this instance, the Commission is concerned that the LDC maintain control of capacity to serve the core market without paying the cost of capacity made redundant by the new supplier's capacity.
Therefore, the Commission rules will require direct sales to the core market to use Westcoast Zone!4 transmission capacity controlled by the LDC to the extent it is available. If a supplier to direct purchase core market consumers becomes unable or unwilling to continue supplying its core market consumers, the LDC will be given the first right of refusal for Westcoast Zone!4 transmission capacity that would otherwise be assigned or returned to the Westcoast service queue.
The foregoing problems flow from the existing capacity access procedures for Westcoast service as approved by the NEB. The Commission encourages all parties to seek out new solutions to capacity access that remove market constraints and domestic security of supply concerns related to transportation.
22 22 5.0 UTILITY SERVICES The new DSP, as implemented by this Commission, opens the opportunity for all British Columbia natural gas consumers to directly purchase their gas supplies, by contracting via the market expertise of a licensed and bonded A/B/M for gas with a four year rolling average supply. This deregulation of gas supply contracting requires neutrality by the LDC in its treatment of customers, whether they are purchasing system gas or the gas of some other supplier.
The Commission makes no presumption about how, if at all, a direct purchase market will unfold; the outcome properly depends on market forces of costs and consumer preferences. The Commission's role is to ensure that in a deregulated environment, consumers have the desirable range of market opportunities that best meet their diverse needs, and that the development of the market is not unduly limited by past actions.
The decisions in this chapter therefore apply equally to buy-sell and T-service direct purchase options. Differences in application, caused by the different nature of these services, are noted where applicable.
5.1 Location of Buy-Sell Intervenors at the hearing presented several options for the location of buy-sell transactions. The most frequently suggested options were Station 2 on the Westcoast system and at the connection between the LDC and the Westcoast system.
The Commission makes no specification of the custody transfer point. It believes the parties to the transaction should be free to select the location which is the most convenient in practical terms. 5.2 Administrative Cost Recovery The enhanced competition benefits of deregulating gas supply contracting must be weighed against the additional transaction costs of this activity: legal, administrative, brokering. The Commission believes that all additional costs of gas supply direct purchasing should be borne by those initiating them. However, certain aspects of direct purchase activity do not impose additional costs, and it is important that direct purchase participants not be charged for these. These principles of
23 23 incremental cost allocation were generally agreed to by all hearing participants, although there was disagreement as to the magnitude of certain costs, notably BC Gas' estimates of its administrative costs of handling the extra work from direct purchase contracting.
The Commission directs that, in the case of buy-sell transactions which use bundled LDC load balancing, peaking and storage service, the LDC shall provide these services at no extra cost to the customer, because the cost for these services should be unchanged by the replacement of system gas with direct sales gas.
Based on experience in Ontario and adopting the Union Gas Ltd. model (Exhibit!70), the initial fee to be charged by the LDC for administration of each buy-sell contract shall be $150/month plus $6/customer account represented by that contract per year. After one year, the LDCs' accounts for this activity shall be reviewed by the Commission, and the fee adjusted if appropriate for more accurate cost recovery. 5.3 Return to System Gas Supply As stated in the DSP, should direct purchase customers wish to return to the system gas supply of the LDC, this will be contingent upon the LDC being able to secure adequate gas supply and the returning consumer paying the full incremental costs incurred by the LDC. The Commission especially recognizes that the LDC requires time to reorganize its gas supply arrangements to accommodate returning customers. A large number of customers deciding to return simultaneously to the LDC could present a particular problem.
The Commission therefore orders that, where a direct-purchase customer wishes to return to LDC system gas service, the LDC's acceptance of such a returning customer shall be subject to one year's notice. In addition, such return shall be conditional on the utility being able to secure sufficient additional firm gas supply to accommodate the returning customer. The utility will be expected to secure the required gas supply on a best efforts basis. Higher incremental gas costs shall be borne by the returning customers, with responsibility upon the LDC to demonstrate to the Commission that the costs of gas procurement for returning customers are higher than current tariff rates.
24 24 5.4 Minimum Contract Volume and Term The Commission believes that administrative cost recovery will serve to limit direct purchases to appropriate volumes and therefore concludes that no minimum contract volume is necessary or desirable at this time. The Commission may approve minimum contract volumes if such action becomes necessary in future.
The Commission will require all base load gas supply contracts which serve core market loads to have a minimum term of four years. This applies equally to LDC contracts and those of A/B/M's. This minimum contract term will require an associated reserves and deliverability dedication or corporate warranty of four!years as discussed in Section 2.3. Agency agreements between A/B/M's and end users, as well as LDC T-Service contracts, will be required to have a minimum term of one!year, in order to provide consumers some flexibility. 5.5 LDC Transportation Service The provision of buy-sell service by an LDC was viewed by all participants as the provision of a bundled service which included load balancing, together with peaking and storage service. However, the Commission continues to be interested in a number of related issues. First, the provision of a fully bundled T-service may be attractive to some consumers as an alternative to buy-sells. Such a service is currently available in Ontario. Second, the provision of peaking and storage service as separate unbundled services could be of interest to some direct purchase participants and was supported by Mobil's evidence (Exhibit 35).
The Commission concludes that, in the interest of providing maximum flexibility in the direct purchase market, both bundled and fully unbundled T-Services shall be made available by LDC's as soon as appropriate tariffs can be submitted and approved, and to the extent the LDC has the resources to provide the service.
A supplier to a core market consumer may provide any or all of the above services with the consent of the LDC. Such consent shall not be unreasonably withheld once the LDC has satisfied itself that the A/B/M or supplier has the capability to deliver the contracted service.
25 25 5.6 Market Role of LDC Concerns about LDC marketing affiliates were raised by a number of participants including Great West. INGM is a non-regulated subsidiary of BC!Gas that has been an active marketer of gas in B.C. for some seven years. Another marketer, Canadian Hydrocarbons Marketing Inc. ("CHMI"), acts as gas manager for its affiliated LDC's, Centra Gas and Pacific Northern Gas.
The Commission has been monitoring the activities of LDC marketing subsidiaries such as INGM and CHMI since their inception and has, from time to time, expressed concerns to them about the need to maintain an arm's-length relationship. To date, the Commission is unaware of any substantiated conflict of interest claims concerning these NRB's, but will continue to monitor this situation. The Commission approved a Code of Conduct and organization structure for INGM in its BC!Gas revenue requirements Decision dated August!5, 1992. That code and structure will serve as a guide to other LDC's considering affiliate gas marketing companies.
The Commission believes that, as suppliers of monopoly gas distribution service, LDC's are in a privileged position relative to their clients, with intimate knowledge of the customer's fuel needs and pattern of consumption. When direct sales are initiated, the LDC is likely to be involved at an early stage in the gas purchase plans of customers contemplating leaving system gas. It would therefore be impossible for the LDC to itself participate in direct sales marketing without placing itself in a conflict of interest position.
The Commission therefore directs that no regulated LDC shall participate in gas sales to customers in its service area, other than through the sale of system gas under published tariffs.
Where a subsidiary or affiliate company of a regulated LDC operates a non-regulated gas marketing business ("NRB"), particular care shall be exercised to ensure separation of data bases and information flow in order to preclude any possibility of unfair competition. In particular, the NRB, when canvassing direct-sales to system gas consumers, should refrain from any gratuitous reference to its affiliate so as to not imply any special relationship with potential customers. The competitive playing field should be level in both perception and reality.
26 26 5.7 Time Frame for Implementation of Direct Sales The Commission orders that buy-sell direct sales of natural gas to core market customers be made available from May 1, 1993.
Sales to the core market customers involving unbundled T-service arrangements shall be made available as soon as the necessary tariffs have been submitted and approved by the Commission. Appropriate tariff proposals shall be presented by each LDC at its first available rate design hearing, or if an appropriate hearing is not scheduled prior to November !1, 1993, filed within 30!days of receipt of a customer request. The Commission recognizes that this latter filing requirement will be best met by the development of "shelf-ready" tariffs as soon as possible.
27 27 6.0 FUTURE REVIEW The Commission considers this generic Decision to differ significantly from most of the Decisions which it issues following public hearings. Those Decisions, which typically deal with matters of revenue requirements or rate design for a single utility company, apply to a relatively narrow subject over a short time period. In contrast, this Decision deals with matters of broad scope which are dynamic in nature. The changes which will occur in the natural gas market place over the next few years also depend on many variables beyond the direct influence of the Commission.
This Decision has two main objectives, namely encouraging competition for supply of natural gas to the core market and maintaining some Commission control over the security of that supply. The Commission considers that for these reasons, as a final aspect of this Decision, it is appropriate to consider further actions and review in the future as follows.
By December 31, 1993 the Commission will require each LDC to file a proposed action plan for the provision of Westcoast Zone!4 transmission capacity required to supply direct purchase, as well as system gas core market consumers. This action plan is to address associated net costs and impacts on the WACOG paid under buy-sell arrangements, considering the following alternatives:
• additional transmission service which the LDC has obtained for market growth or other reasons.
• reduction of purchases under short-term, seasonal and peaking contracts. • reduction of purchases under long-term contracts. • reduction in use of Aitken Creek storage. • renegotiation of long-term contracts. • receipt of gas at Westcoast interconnect under LDC T-service or buy-sell arrangements. • other proposed alternatives.
28 28 Prior to May!1, 1994, the Commission intends to review, among other issues:
• the extent to which direct sales to core market gas consumers have occurred. • benefits which accrue from direct sales. • remaining impediments to direct sales such as available locations for buy-sells. • actions to remove impediments. • the relationship between average LDC system gas prices and direct purchase market prices for firm gas.
DATED at the City of Vancouver, in the Province of British Columbia this !!!!!!!!!day of March, 1993. _________________________________________ M.K. Jaccard Chair _________________________________________ L.R. Barr Deputy Chair _________________________________________ F.C. Leighton Commissioner
29 AN ORDER IN THE MATTER OF the Utilities Commission Act, S.B.C. 1980, c. 60, as amended and The Commission's Rules on Natural Gas Supply Contracts
BEFORE: M.K. Jaccard, Chair; ) L.R. Barr, Deputy Chair; and ) March 5, 1993 F.C. Leighton, Commissioner ) WHEREAS: A. The Commission, in its February!21, 1992 Decision on the BC!Gas Phase!A Rate Design Application, advised that the Commission's Rules on Natural Gas Supply Contracts ("the Rules") pursuant to Section!85.3 of the Utilities Commission Act ("the Act") required re-examination in light of developments in the competitive gas markets in the Province and elsewhere in Canada; and B. On November!17, 1992, following receipt and review of documents on the Core Market Policy, the Ministry of Energy, Mines and Petroleum Resources ("MEMPR") released its Policy Statement on Domestic Natural Gas Supply Policy ("DSP") (formerly Core Market Policy); and C. The Commission determined that the DSP required a full review of the Rules and issued Order No.!G-108-92 which set the review of the Rules down for public hearing commencing January!11, 1993 in Vancouver,!B.C.; and D. The Commission has considered the DSP and the evidence received during the public hearing which concluded on January!21, 1993 all as set forth in the Decision issued concurrently with this Order. NOW THEREFORE the Commission orders as follows: 1. The Rules into Natural Gas Supply Contracts are amended effective as set forth in Appendix!A of the Decision effective the date of this Order. 2. The Commission will require each gas utility to comply with the various directives contained in the Decision. DATED at the City of Vancouver, in the Province of British Columbia, this !!!!!!!!!!!! day of March, 1993. BY ORDER Dr.!Mark K. Jaccard Chair
30 /yk
31 Appendix A B.C. UTILITIES COMMISSION ENERGY SUPPLY CONTRACTS - RULES
The following rules have been developed to facilitate the review by the Commission of energy supply contracts pursuant to Section!85.3 of the Utilities Commission Act. The review is to ensure that the terms of the contract are in the public interest having regard to the following:
• the quantity of the energy to be supplied under the contract, • the availability of supplies of the energy referred to in paragraph!(a), • the price and availability of any other form of energy, including but not limited to petroleum products, coal or biomass, that could be used instead of the energy referred to in paragraph!(a),
• in the case only of an energy supply contract that is entered into by a public utility, the price of the energy referred to in paragraph!(a), or
• any other factor that the Commission considers relevant to the public interest. NATURAL GAS SUPPLY CONTRACTS In the case of natural gas supply contracts, the rules have been updated to implement the 1992!"Domestic Natural Gas Supply Policy", which has as its objectives to:
• ensure that domestic consumers have in place a supply of natural gas which reflects their individual security needs;
• provide a stable and competitive environment for new and existing businesses to operate in the province; and,
• maintain the integrity of, and confidence in, the marketplace.
32 2 1.0 GENERAL RULES FOR ALL NATURAL GAS CONTRACT CATEGORIES 1.1 Under Section 85.3(1)(a), all natural gas purchasers in British Columbia, other than those purchasing exclusively from a gas utility, must file their supply contracts and all subsequent amendments with the Commission. Any approvals required by these rules should be obtained before delivery of natural gas occurs. 1.2 In the case of a Buy-sell arrangement involving a gas supply contract between an agent/broker/marketer ("A/B/M"), on behalf of consumers, and a utility, the utility shall file the contract as part of its base load portfolio. The Commission's approval of such a contract is subject to the A/B/M meeting the requirements of Section!3.0 of these rules. 1.3 Parties filing gas supply contracts with the Commission under Section!85.3,either directly or through an LDC, and wishing confidentiality, shall provide written justification as to why, in their view, it is in the public interest that the filed contract be kept confidential. Regardless of the Commission's ruling on confidentiality, price information is only required for utility gas supply contracts. 1.4 The reserves, deliverability and delivery arrangements supporting all gas supply contracts requiring approval shall be confirmed by independent third party expert review, or be backed by corporate warranty. In future, it is expected that such reviews will be conducted by the Petroleum Engineering and Operations Branch of the Ministry of Energy, Mines and Petroleum Resources. The initial pre-approval review will be followed up with reviews every second year for the life of the contract. 1.5 Where approval is required, the Commission will issue Orders approving all gas supply contracts which meet the requirements of these rules. Notwithstanding Commission approval, core market purchasers who contract for direct purchase of their natural gas supplies do so at their own risk of availability and price. 1.6 Purchasers who wish to displace direct purchases with utility purchases will be accommodated providing the utility can contract sufficient gas and transportation to meet the additional load and providing the purchaser assumes responsibility for any resulting incremental LDC costs that are approved by the Commission. The Commission will normally allow utilities to require up to 1!year's notice to accommodate such load increases. 1.7 Notwithstanding 1.1 above, purchasers who have satisfied Commission requirements for long-term supply security as per Section!2.0 below and who wish to operate in the "spot" market will be permitted to make special arrangements with the Commission to facilitate timely approvals. Generally, this will consist of a verbal request for approval in advance of gas flow followed by filing of an executed contract as soon as possible thereafter.
33 3 1.8 It is the intention of the Commission to review and approve contracts expeditiously, normally without the requirement for a hearing. It is also the Commission's intention to avoid retroactive Orders. The hearing process, pursuant to Section!85.3(2) of the Act, will become necessary where the Commission initially determines that the contract may not be in the public interest. A hearing could also be required as a result of a third-party complaint. 1.9 The Commission may reconsider the duration of energy supply commitments required by Section!2.0 as gas supply market conditions change. Any change would be prospective and it is the Commission's intent that parties honour existing contracts.
34 4 2.0 SPECIFIC CONTRACT RULES BY NATURAL GAS CONTRACT CATEGORY 2.1 Purchasers with Alternative Fuel Capability or who use Natural Gas as a feedstock. The Commission will require purchasers in this category to provide the Commission with a statutory declaration which confirms their alternative fuel capability or their use of natural gas for feedstock purposes only. If these purchasers also qualify under category 2.2 below, no statutory declaration will be required. Purchasers in this category need only file a copy of their gas supply contracts and all subsequent amendments with the Commission. No approval will be required or issued. 2.2 Purchasers considered as "non-core" under the former "Core Market Policy" This category consists of those consumers currently purchasing their natural gas directly from a supplier under a gas supply contract approved by the Commission, with the exception of certain commercial and institutional consumers subject, under the previous rules, to five!year contracting requirements. These latter consumers will henceforth be considered to be "Core Market Direct Purchasers" and subject to the requirements in 2.3. Purchasers in this category, as for those in category 2.1, need only file a copy of their gas supply contracts and all subsequent amendments with the Commission. No approval will be required or issued. 2.3 Utility and Core Market Direct Purchasers Utilities, and all core market direct purchasers must submit gas supply contracts to the Commission for approval, together with all other related contracts which support the gas supply and any information required by 1.4 above. Each gas supply contract shall provide for: 2.3.1 a minimum four year term with a four year supply commitment1 sufficient to meet the purchaser's total firm2 requirements at the level of the current year as per 1.4 above;!and 2.3.2 diversity of supply including where possible a range of suppliers positioned behind alternative processing facilities, or backstopping arrangements. 2.3.3 in the case of utilities only, a prudent combination of terms, conditions, and price. 1 Supply commitments may be in the form of dedicated reserves and deliverability or alternatively by means of a Corporate Warranty from an appropriately qualified supplier.
35 2 For utilities, supply commitments apply to base load rather than total firm requirements.
36 5 3.0 RULES PERTAINING TO AGENTS/BROKERS/MARKETERS ("A/B/M'S") 3.1 Licensing Any person intending to act in the capacity of an A/B/M in order to provide advice to, or act on behalf of, core market consumers purchasing gas directly either under T-Service or a buy-sell arrangement will be required to apply to the Commission for a licence. Licences will be issued subject to receipt of a $100 fee and compliance with the following requirements. Persons acting as A/B/M's on their own behalf and purchasing gas solely for their own use and who are not selling to third-party core market consumers, will not be required to comply with Rules 3.3, 3.5, 3.6, and 3.9. 3.2 Bonding In order to receive a licence, the A/B/M will be required to post a gas delivery performance bond of $250,000 which the Commission will hold in trust. 3.3 Code of Conduct Licensees will be required to comply with a Code of Conduct approved by the Commission. Initially this will be based on that of the Ontario Natural Gas Association. Failure to comply with the Code of Conduct will result in the licence being revoked. 3.4 Standard Form of Gas Supply Contract Licensees will be required to incorporate, in their buy-sell gas supply contracts, all clauses from the standard form of gas supply contract approved by the Commission for the use of each gas utility in its market area. 3.5 Standard Form Agency Agreement It is expected that the arrangements between end-use consumers and A/B/M's will require the use of some form of "agency agreement". Licensees will be required to receive Commission approval of their form of agreement. The Commission's review of such agreements will not require all agreements to be identical, but will focus on certain key requirements which shall include a minimum term of one year, and confirmation that the consumer understands the risks associated with direct gas purchases. 3.6 Standard Information Booklet The Commission requires each gas distribution utility, in co-operation with A/B/M's, to develop a standard information booklet for their service area which outlines the risks and procedures of direct purchase, and which discloses potential benefits and costs of direct purchase.
37 6 The Commission will require Licensees to distribute these booklets to all prospective clients and to include reference to the Booklet in their Agency Agreement. 3.7 Administration Fees and Minimum Contract Volumes The commission will require utilities to collect fees to cover the cost of buy-sell administration. Initially the fee shall be $150/gas supply contract per month plus $6/customer account per year. Fees will be subject to periodic review by the Commission. The Commission may require minimum contract volumes if such action becomes necessary in future. 3.8 Requirements for Assignment of Westcoast Transmission Capacity Where Westcoast Zone!4 transportation capacity is available from the LDC by assignment, it shall be used. Where an A/B/M holds Westcoast Zone!4 capacity and has been using it to serve core market customers, but no longer needs it to serve these customers, and it would otherwise be assigned or returned to the Westcoast service queue, the A/B/M/ shall offer such capacity to the LDC on a right of first refusal basis. 3.9 Limitation on Direct Sales. Aside from buy-sell arrangements, no utility shall engage in the direct sale of natural gas other than through a non-regulated subsidiary which will be considered to be an A/B/M subject to these rules. The utility will be required to demonstrate a complete operational separation from any such subsidiary.
38 1.0 BACKGROUND 1 1.1 Deregulation in Natural Gas Supply Since 1985 1 1.2 Core Market Policy 2 1.3 Developments in Other Jurisdictions 3 1.4 B.C. 1992 Domestic Supply Policy 3 1.5 BCUC Generic Hearing to Set Rules For Domestic 5 Natural Gas Supply 5 2.0 SECURITY OF SUPPLY 6 2.1 Long-run Security of Supply 6 2.2 Transportation Services and Security of Supply 8 2.3 Reducing the Length of Reserve Requirements 9 2.4 Supplier of Last Resort 11 3.0 MARKET DEVELOPMENT AND MARKET INTEGRITY 12 3.1 Licensing 12 3.2 Bonding 13 3.3 Code of Conduct 14 3.4 Standard Form Contract and Other Consumer Information 14 3.5 Confidentiality 16 3.6 Sanctity of Contracts 17 4.0 WESTCOAST TRANSPORTATION 19 4.1 Transportation Availability 19 4.2 Future Control of Transportation 20 5.0 UTILITY SERVICES 22 5.1 Location of Buy-Sell 22 5.2 Administrative Cost Recovery 22 5.3 Return to System Gas Supply 23 5.4 Minimum Contract Volume and Term 24 5.5 LDC Transportation Service 24 5.6 Market Role of LDC 25 5.7 Time Frame for Implementation of Direct Sales 26 6.0 FUTURE REVIEW 27
39 ORDER NO. G-13-93 LIST OF APPENDICES Appendix A BCUC Rules March 1993 B Domestic Supply Policy C BCUC Hearing Order and List of Issues D Westcoast System Map E BC Gas Capacity on Westcoast (Exhibit 51)
40 APPEARANCES G.A. FULTON T. KAMPMAN B.BECKER C.B. JOHNSON S. RICHARDS N. MAYNER C. McCOOL M. DOHERTY H.R. WARD C.P. DONOHUE D. BURSEY D. NUYTS C. WEAFER C. PARK K. FONG C. ZIMMERMAN J. FINGARSON G.H. GIESBRECHT R.T. O'CALLAGHAN W.E. DOWNE R. SIRETT P.B. BUDD
Commission Counsel Alberta & Southern Gas Co. Ltd. BC!Gas Inc. B.C. Health Services Ltd. Consumers' Association (B.C. Branch, B.C. Old Age Pensioners' Organization, Council of Senior Citizens' Organizations, Federated Anti-Poverty Groups of B.C., West End Seniors' Network Canadian Association of Petroleum Producers Pacific Northern Gas Ltd. Czar Resources Ltd. ECNG Inc. Great West Energy Ltd. Inland Natural Gas Marketing Ltd. McDonald's Restaurants of Canada Limited Federal Department of Public Works Mobil Natural Gas Canada Ltd. Northwest Pacific Energy Marketing Inc. R.T. O'Callaghan & Associates Inc. Talisman Energy Inc. Westcoast Energy Inc. ENRON Gas Marketing Canada Inc.
41 LIST OF EXHIBITS Commission Order No. G-108-92 Westcoast Energy Intervention and covering letter Present Policy for queuing procedures and access criteria Mr. Collett's evidence before the National Energy Board Copy of queuing and access policy A response to an information request of the National Energy Board in the RH '92 Proceedings by Westcoast Energy Article entitled "Request for firm service and renewal rights" Map of the Westcoast system outlining the four toll zones Westcoast Energy five year plan Intervention for Alberta Health Care Association Intervention from Alberta Petroleum Marketing Commission Intervention of Alberta and Southern Gas Company Limited Intervention of BC!Gas Inc. Further submission of BC!Gas Inc. and attachments Intervention of B.C. Health Services Limited Intervention of British Columbia Public Interest Advocacy Centre Intervention of Canadian Association of Petroleum Producers Intervention of Canadian Hydrocarbons Marketing Inc. Intervention of Canadian Utilities Limited Intervention of Centra Gas British Columbia Inc. Intervention of Coast Pacific Management Inc. Intervention of the Economic Statistics and Energy Department of the Council of Forest Industries of British Columbia Intervention of Czar Resources Intervention of Direct Energy Marketing Limited
Exhibit No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
42 Intervention of Eastern Natural Gas Management B.C. Limited Intervention of ECNG Inc. Intervention of Energy Resources Management Intervention of ENRON Gas Marketing Canada Inc. Further Submission by ENRON Gas Marketing Canada Curriculum vitae of David F. Pope Corporate Profile of ENRON Gas Marketing Canada Inc. Intervention of Great West Energy Limited Intervention of Inland Natural Gas Marketing Ltd. Intervention of Lower Mainland Large Gas Users Association Intervention of McDonald's Restaurants of Canada Limited Intervention of Ministry of Energy, Mines and Petroleum Resources Intervention of Public Works Canada Intervention of Mobil Natural Gas Canada Limited Intervention of North Ridge Gas Marketing Inc. Intervention of Northwest Pacific Marketing Inc. Intervention of R.T. O'Callaghan & Associates Inc. Intervention of Pacific Northern Gas Ltd. Intervention of Talisman Energy Inc. Intervention of Unocal Canada Limited Intervention of Cominco Ltd. Intervention of Amarada Hess Canada Limited Request for Interested Party status of Sask Energy Comments of CanWest Gas Supply Inc. Comments of WestCan Gas Inc.
25 26 27 28 28A 28B 28C 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46
43 Comments of Friends of the Fraser Valley Paper of Russell S. Uhler Curriculum vitae of Dr. R.S. Uhler Qualifications of Mr. Donald K. Clark BCUC Energy Supply Contracts-Rules Westcoast Service Agreement Summary Typical operating agreement Typical cost of service agreement Gas purchase contract Article from Financial Post Testimony of Rudy G. Riedl Reference to Reference Price Utility Gas purchase Agreement Curriculum vitae of Mr. Murray McIntryre Curriculum vitae of Mr. Andrew J. Anderson Ontario Energy Board Decision E.B.R.O. 474-A For identification Canadian Natural Gas Price Reporter Exhibit previously marked 62 for identification Background documents in relation to Canadian Gas Reporter Document entitled "Minimum Conditions of Supply for the Ontario Core Market" Document entitled "Direct Purchase of Natural Gas Disclosure Statement" Proposed timetable Details of BC!Gas' gas supply portfolio Document entitled costs resulting from Buy-Sells Letter to BC!Gas customers, April 30, 1992
47 48 48A 49 50 51 52 53 54 55 56 57 58 59 60 61 62 62A 62B 63 64 65 66 67 68
44 Letter to North American Land Corporation from Inland Natural Gas Marketing, October 8, 1992 Union Gas answer to interrogatory of great West Energy, re: Cost Schedule Centra Gas Manitoba Inc. Information Requests August 19, 1992 Document headed Tab 15.0.0 original July 17, 1992 Centra Gas Manitoba Inc. Undertaking provided by G. Meyer dated November 26, 1992 Manitoba Public Utilities Commission Decision with respect to direct purchase of natural gas by Manitoba consumers Brochure "Direct Purchase of Natural Gas" Covering letter dated January 4, 1993 Document titled "Unbundling of Services" Excerpt Page 6-3 from BC!Gas Inc. least cost integrated resource plan Excerpt Page 27 from BC!Gas Inc. least cost integrated resource plan Schedule 25 - Transportation Service Breakdown of direct purchase volumes by major market sectors in consumers gas franchise area Curriculum vitae of C. Brian Woods Curriculum vitae of Richard F. Guerrant Curriculum vitae of William L. Oostenbrink Great West letter to all customers BC!Gas Agency Agreement Letter from Inland Natural Gas Marketing Ltd. dated March 4, 1992 to Best Western Richmond Inn Letter from Inland Natural Gas Marketing dated September 18, 1992 to Western Greenhouse Growers Cooperative Union Gas outline of Buy-Sell Contract Gaz Metropolitan Security of Supply Policy Centra Gas Ontario Inc. Minimum Conditions of Supply for the Core Ontario Market
69 70 71A 71B 71C 72 73A 73B 74 75A 75B 76 77 78A 78B 78C 79 80 81 82 83 84 85
45 Letter from Saskatchewan Minister of Energy Mines and Resources Extract from National Energy Board Decision RH-1-89 Letter from Mr. Tardiff to Mr. B. Chandler, Great West Energy, January 14, 1992 Great West Energy background document titled "Natural Gas in the Canadian Economy" Gas Tariff Original Page C-2 Two page document titled "Potential Unbundling Costs to Core Market Ratepayers" Guide for Ontario Natural Gas Buyers National Energy Borad Publication, August 1992, "Natural Gas Market Assessment, Long-term Canadian Natural Gas Contracts"
86 87 88 89 90 91 92 93
46 GLOSSARY A. DEFINITIONS Within the context of this Decision document the following definitions apply. Core Market Those consumers who were considered core market consumers under the "Core Market Policy" with the exception of any such consumer who has alternative fuel capability or uses natural gas as a feedstock. Unlike the definition under the "Core Market Policy", core market consumers may now include direct purchase consumers and system gas consumers.
System Gas This is gas purchased by a local distribution company ("LDC"), usually as part of a portfolio of gas supplies, for distribution and sale to a customer in its service area.
System Gas Consumer A consumer who purchases gas supplied by the LDC as an integral component of its supply and distribution service, under a published tariff, and other than under a buy-sell arrangement.
Buy-Sell Arrangement A buy-sell arrangement is a means of procuring gas supply whereby ownership of the gas is transferred from the seller to the LDC for delivery to end-users. The LDC normally bills the buy-sell customer at its tariffed rate for system gas. The seller rebates to the customer the difference in price between the LDC's system gas WACOG and the gas purchased on behalf of the customer, after subtracting an agent's fee.
47 Buy-Sell Consumer A consumer within the distribution area of an LDC, who chooses to make independent buy-sell arrangements with a supplier of gas other than the LDC to supplement or replace the LDC's gas supply.
Direct-Sales Gas / Direct Purchase This is gas purchased from a supplier other than the LDC in whose service area it is delivered. Direct -sales gas may be delivered by means of a buy-sell arrangement in which ownership of the gas is transferred from the seller to the customer through the LDC. Alternatively, Transportation Service (" T-Service") may be used, in which case ownership of the gas passes directly from the supplier to the customer and the LDC delivers the gas under a gas transmission service agreement.
Gas Sales Agent/Broker/Marketer An independent party who acts on behalf of one or more parties to a direct sale transaction. Market-Out Provisions Roughly stated, market-out provisions in gas supply contracts enable buyers to reduce their daily purchase quantity if their market shrinks.
Non-Regulated Business A non -regulated business is an independent business or subsidiary of an LDC that is not regulated by the B.C. Utilities Commission.
Bundled and and Unbundled Transportation Service Where gas is transported under a bundled tariff arrangement, various services such as load balancing, peaking, storage of gas and backstopping of supply are provided along with the basic gas transmission service. In an unbundled service, a separate tariff is applied to each or some of these services, and the customer may chose only those items it wishes to use and pay for.
48 T-Service Transportation Service (T-Service) occurs when the gas sales and transportation functions of a utility have been separated, and when the utility transports gas owned by someone else. Under a T-Service arrangement the consumer purchases gas from a supplier other than the LDC, and arranges for transportation of that gas on the Westcoast Energy Inc. pipeline to the LDC receipt point, and on the LDC system to the customer receipt point. For this service the customer pays the LDC the Commission approved T-Service rate.
WACOG Weighted Average Cost of Gas calculated in terms of $/GJ. UOR Unauthorized Over-Run gas is that gas taken by a consumer over and above the amounts which are either provided for directly in the consumer's gas supply contract or have been authorized otherwise by the supplier.
Zone 1, 2, 3, 4 Zones 1 to 4 refer to the type of service on the Westcoast Energy Inc.(Westcoast) system for gathering, processing and transporting gas. Zone 1 refers to the transmission of raw gas from the producer and delivering it to the Processing plant. Zone 2 refers to processing service for raw gas to make it pipeline quality gas. Zone 3 refers to the Northern legs of the Westcoast transportation system, from the processing plants to Station 2. Zone 4 refers to Transportation South portion of the Westcoast system, between Station 2 and the LDC take-off point.
49 B. ACRONYMS A/B/M: Agent/Broker/Marketer CAPP: Canadian Association of Petroleum Producers CHMI:Canadian Hydrocarbons Marketing Inc. DSP: Domestic Natural Gas Supply Policy ECNG ECNG Inc. ENGM Eastern Natural Gas Management B.C. Limited INGM: Inland Natural Gas Marketing Ltd. LDC: Local Distribution Company MEMPR: The British Columbia Minister of Energy, Mines and Petroleum Resources NRB: Non-Regulated Businesses ONGA: The Ontario Natural Gas Association PIAC: The British Columbia Public Interest Advocacy Centre PNG: Pacific Northern Gas Ltd. PWC: Public Works Canada
50 C. ABBREVIATIONS BC!Gas BC Gas Inc. Centra Centra Gas British Columbia Inc. Czar Czar Resources Ltd. Mobil Mobil Natural Gas Marketing Canada Inc. Talisman Talisman Canada Inc. (formerly BP Canada Inc.) Unocal Unocal Canada Ltd. Westcoast Westcoast Energy Inc.