Competition from Order 636 has gas customers rethinking their firm capacity options.
Just when everyone thought we had put Order 636 behind us, up pops perhaps our greatest challenge yet: the turnback (or "decontracting") of firm capacity on interstate natural gas pipelines. This phenomenon, now emerging on a few major pipelines, such as Transwestern, El Paso, and Natural Gas Pipeline Co. of America, inspires different reactions. Some see the problem as a natural outgrowth of competition. Others believe it foretells a dire future. Either way, the issue will play a central role in ongoing and future debates over rate design, rate incentives, and the management of pipeline capacity.
Decontracting occurs at the point where competitive opportunities (born of Order 636) run headlong into the as-yet, relatively uncompetitive pipeline infrastructure. Strictly defined, "decontracting" describes the behavior of pipeline customers (shippers) that fail to renew their contracts for firm transportation (FT) service. The trend draws concern from pipelines: If they prove unable to resell that released firm capacity, they may find it difficult to recover costs.
No one knows how widespread this phenomenon will become. Last September the Interstate
Natural Gas Association of America (INGAA) released a paper that predicted only a moderate decline in demand for long-term FT. Even though contracts for nearly half of pipeline firm capacity will expire before 2002, INGAA expects three-quarters of that capacity will be resubscribed on a long-term basis, so that over 85 percent of total capacity will continue under long-term contracts. Nevertheless, decontracting will likely develop into a more serious problem in certain supply-to-market corridors.
With pipeline unbundling through Order 636, gas LDCs have effectively assumed control over their FT rights. Thus, decontracting arose in part from the dynamic adjustment process taking place across the natural gas industry, as participants reshaped their business practices to respond to new market realities.
LDCs now take responsibility for managing their contractual rights to interstate transmission and storage capacity; they control how much capacity they place under contract and how that capacity is used. At the same time, state public utility commissions (PUCs) are encouraging LDCs to minimize the upstream costs they pass on to end users. In response, LDCs are relinquishing, upon contract expiration, capacity that exceeds the amount necessary to meet their system reliability requirements. This trend may accelerate as LDC customers shift away from bundled LDC sales service to transportation service.
The drive for efficiency is expanding throughout the entire gas transmission network. Mechanisms mandated by Order 636, such as FT capacity release and flexible use of pipeline receipt and delivery points, in combination with industry initiatives such as the Grid Integration Project, which results in expanded use of pipeline interconnects, are enhancing transactional efficiency on and between pipelines. Complementing these innovations is the evolution of a group of companies providing value-added services. These service providers are developing strategically placed storage fields and pipeline header systems that bind the pipeline grid together, facilitating optimal use of the integrated interstate, intrastate, and LDC infrastructure.
Market centers are boosting market liquidity, giving shippers access to a more diversified portfolio of gas supplies and providing alternatives for meeting peak-day demands. When combined with released firm or interruptible capacity, market center services (especially storage) help reduce the need for long-haul FT capacity. Decontracting occurs when the combined cost of alternative services is less than the cost of holding primary FT capacity, and when shippers with access to multiple pipelines find gas delivered by another pipeline to be less expensive than gas delivered by their current transporter.
Who's at Risk?
California leads the way, as is so often the case. To serve that growing market, pipelines have competed to construct long-haul capacity connecting new and lower-cost gas-supply sources. But when market demand fails to increase as projected, and fails to keep pace with the growth in aggregate pipeline deliverability, the resulting capacity surplus can lead to decontracting.
In California the development of new and lower-cost gas supplies triggered nearly simultaneous expansions from a number of constrained supply basins (San Juan, Central Rockies, Western Canada). Because of economic recession and low oil prices, however, market demand did not develop as expected. A large surplus developed in pipeline capacity. California LDCs, having lost noncore load, announced plans to relinquish capacity. The El Paso and Transwestern pipelines were affected first, but not because of their capacity costs (em simply because their FT contracts were the first to expire.
Elsewhere, Natural Gas Pipeline Co. (NGPL) has become the first Midwestern pipeline to experience post-Order 636 capacity turnbacks. LDCs are turning back FT as they become more proficient at using their contractual and system assets (em in particular, using on-system storage capacity to meet customer peaking needs. NGPL's ability to retain FT has also been affected by competition from pipelines that offer LDCs and other shippers lower-cost alternatives for transportation services and access to lower-cost Canadian supplies.
Pipelines that serve the Northeast markets have so far escaped any significant decontracting, but their relatively high costs and upcoming contract expirations make them likely candidates. On pipelines like Tennessee and Texas Eastern, end users shifting from LDC sales service to transportation may cause LDCs to relinquish capacity. Northeast LDCs and other marketers are developing storage to serve peak demands. And new supplies from the Sable Island area and liquefied natural gas landed in Boston, MA, could cause decontracting if those supplies can be delivered to LDC city gates at costs below the firm tariff rates of current transporters.
The increasingly competitive market gives shippers an economic incentive to minimize their transportation costs. In markets where surplus capacity develops, decontracting will likely affect pipelines as their contracts expire. Relative cost and level of customer service will not necessarily drive capacity turnback.
What's the Solution?
Various proposals for resolving decontracting problems have surfaced in pipeline proceedings at the Federal Energy Regulatory Commission (FERC). One approach suggests that costs attributable to newly stranded firm capacity should be allocated to existing customers through higher rates, either applied now or deferred for future recovery. Existing firm customers would bear all the risks of unused capacity. Needless to say, neither customers nor the FERC have embraced this
"solution." The FERC has emphatically declared that existing customers are not to be penalized by higher rates for continuing to receive their current level and quality of service. (See sidebar on page 24 for citations.)
Allocating stranded costs to remaining FT customers would mark a poor policy choice. Increasing pipeline rates might well drive customers with newly expired FT contracts to find lower-cost alternatives, creating a death spiral of higher rates and ever fewer FT customers.
Another idea, proposed by El Paso, would charge an exit fee to departing FT holders, thus granting prospective reimbursement to the pipeline for its stranded costs. The FERC rejected this solution, however, as contrary to the basic notion that a party's contractual obligations should not survive the contract's expiration.
Yet another alternative would have pipeline stockholders absorb all uncontracted capacity costs. This approach obviously holds no appeal to the pipelines and, in fact, has not been proposed in any proceedings. Besides being inequitable to shareholders where decontracting is driven by purely external forces (as opposed to strategic miscalculation), such action would raise the cost of capital and debt across the pipeline industry as the perceived risk to cost recovery increased.
The FERC's Transwestern order as well as orders issued in the El Paso and NGPL proceedings clearly favor multiparty negotiations to split the costs associated with decontracting. The FERC also appears willing to consider solutions based on rate design, including departure from the straight fixed-variable (SFV) method.
The SFV rate design has been widely branded as the chief villain in this soap opera. First, pipelines allege that SFV has greatly increased the cost of reserving firm capacity, creating economic incentives for LDCs to develop lower-cost alternatives for peaking needs. Nevertheless, a strong case has been made that decontracting is only a temporary phenomenon, and that the choice of future rate design will not necessarily determine how much long-term FT capacity is held under contract.
Over the next few years, the industry will work through the capacity turnback problem. The FERC's evolving solution, negotiated cost-sharing, should facilitate this process by encouraging stakeholders to enter into agreements that address both short- and long-term economic considerations. The following mechanisms could help increase natural gas demand while minimizing both pipeline costs and transportation rates.
Rate design should encourage efficiency and flexibility. Whatever rate design paradigm the FERC adopts for future use must facilitate both the remarketing of FT capacity and the development of new markets. Any departure from existing policy must preserve efficiencies resulting from Order 636. Flexibility must accommodate a potential customer's need to index gas costs to the price fluctuations of another commodity or product. Also, innovative rate designs such as seasonal SFV (em in which the volume of subscribed FT and the monthly demand charges more accurately reflect both the need for and value of capacity (em should be considered if they enable the pipeline to remarket its capacity.
Tariff terms and conditions should encourage customers to contract for firm capacity. The FERC should institute confiscatory unauthorized overrun penalties at least equivalent to the annual cost of reserving FT, and set at a level sufficient to discourage customers from intentionally undersubscribing. It should also eliminate price caps for interruptible transportation and short-term (up to three months) FT marketed by the pipeline. At the same time, institute an auction under which all available capacity must be sold to the highest bidder at any price exceeding the pipeline's variable cost. This mechanism will allow unsubscribed capacity to trade at its market clearing value at all times.
Give pipelines incentives to cut costs and lower rates. The FERC should allow the pipeline to 1) depart from SFV rate design to capture new markets or facilitate remarketing, and 2) market short-term capacity at rates exceeding its maximum tariff rates (em but allow these only if pipelines adopt a performance-based mechanism. Such a mechanism must be designed to give a pipeline incentives to minimize its costs and to share ongoing cost savings with its customers through lower rates.
Broaden FERC oversight of capacity expansion projects. To minimize future decontracting, the pipeline infrastructure must be expanded optimally, balancing aggregate pipeline capacity with market demand at the lowest possible cost. This may require the FERC to revise its policies regarding new pipeline construction.
These mechanisms are necessary to mitigate decontracting in the long term. Our industry must begin to balance aggregate pipeline capacity with market demand so that reserving FT, to ensure reliability and continuity of service, retains value. The pipeline grid must be globally optimized, with capacity expansions synergistically using existing infrastructure as much as possible. As suggested above, this will require the FERC to look beyond the stand-alone effects of new capacity.
Fortunately, addressing the decontracting issue does not require us to reinvent the gas industry. The essential tools are already in place. Achieving optimal results through the regulatory process will not be easy; there are no simple answers. What we must avoid at all cost are superficial jingoistic "solutions" or "proposals" designed for parochial advantage. A better approach is to employ fair judgment, sound economic principles, and a willingness to correct policy miscalculations, if any. Then everyone wins. t
Rebecca McDonald is president of Amoco Corp.'s Natural Gas Group. Previously, Ms. McDonald was president of Tenneco Gas Marketing Co. in Houston, TX. She is a member of the executive and budget committees of the Natural Gas Supply Association, a director of the Natural Gas Council, and a member of the industry communications committee of the American Gas Association.
Recent Orders-Capacity Turnback
Electric policy no answer:
FERC rejects argument that its electric policy (the "Mega-NOPR" favors stranded-cost recovery) opens the door to an exit fee to recover pipeline decontracting costs. Says electric utilities must demonstrate "a reasonable expectation that the contract would be renewed." Finds no expectation in El Paso case.
-El Paso Natural Gas Co., Dkt. No. RP95-363-000, July 26, 1995, 72 FERC (pp 61,083.
Shippers need protecting:
"As the Commission considers the problem of turned-back capacity ... we are mindful of our obligation to protect the pipeline's captive customers, who [in this case] have little or no alternative .... [T]he pipeline must have an incentive to recover the costs of its unsubscribed capacity from new markets."
-Natural Gas Pipeline Co. of America, Dkt. Nos. RP95-326-000 et al., Oct. 11, 1995, 73 FERC (pp 61,050.
But risk-sharing may qualify:
FERC OKs settlement for cost-sharing through 2001 of some $51 million from capacity turnback by Southern California Gas Co. (457 MMBtu/day, relinquished effective Nov. 1, 1996). Says settlement, which also protects certain customers from rate hikes for 10 years, "is crafted so as to fairly share the costs and burdens."
-Transwestern Pipeline Co., Dkt. Nos. RP95-271-000, July 27, 1995, 72 FERC (pp 61,085.
Recent Proposals-Flexible Pricing
The FERC acknowledges that gas pipelines need more pricing flexibility in today's market. In January, it asked for comment on three proposals:
. Eligibility depends on antitrust analysis, showing no market dominance
. Pipeline must not be able to maintain a 10-percent price increase without losing market share
. "Closer scrutiny" applies when HHI exceeds 0.18 (1,800)
. FERC will rule case by case
Incentive (performance-based) rates:
. Pipelines eligible despite market power
. Rates divorced from cost; no cap
. Prospective and voluntary
. Efficiency gains shared between consumers and stockholders
. Benefits need not be quantified
Negotiated rates with recourse to default rate:
. Mutual agreement between pipeline and individual shipper
. Shippers have access to cost-of-service-based recourse rate as alternative to negotiated contracts
. Pipelines must allocate capacity to recourse shippers during constraints
. Recourse shippers not solely responsible for cost of unsubscribed capacity
-Alternatives to Trad. Cost-of-Service Ratemaking for Nat. Gas Pipelines, Dkt. No. RM95-6-000, Jan. 31, 1996; Regulation of Negotiated Transp. Services of Nat. Gas Pipelines, Dkt. No. RM96-7-000, Jan. 31, 1996.
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