THERE IS MUCH TALK ABOUT CONVERGENCE.
The Federal Energy Regulatory Commission asks, "What needs to be done to enable the gas and electric markets to work together to become more integrated?" The real question is more direct: "How can the gas industry transform what is presently, at best, a daily market, with daily procedures, to an hourly or quarter-hourly electric generation business and gain benefits at the same time?"
Will the answer come from hourly gas trading and pricing? Yes, but the system won't work smoothly unless something is done about the information and business practice infrastructure underlying gas transportation. Remember that there are two commodities to take into account: the methane and capacity to transport it through time and space. Creating an hourly market for gas title transfers from today's daily market is relatively simple. The real challenge rests with communications (em the acquisition, transfer and coordination of capacity information.
Gas transportation, especially across multiple systems, is plagued with complicated and often conflicting plans for nominations (requests), confirmations (clearing) and scheduling (recording the deal). Moving gas requires the coordination of contracts among buyers and sellers. It involves communication of information to transporters and interconnected parties up and down the line. The simplest transaction involves five parties (em producer, operator, pipeline, local distribution company and end user. The average transaction, which crosses two pipelines, can involve eight or more parties. The parties involved in these transactions are disparately organized with widely varying technological savvy.
Without market improvements in the gas industry, it is likely that the electric industry will consolidate and make permanent its present advantage in time-differentiated products. Why is it important that the gas industry match this capability? Simple. It's all about margins, value and competition. If gas can match the time-differentiation of electricity, then producers and owners of both methane and pipeline capacity will capture margins that otherwise would be available only to electricity generators and transmitters. Such a competitive allocation of revenue will prove essential to a long-term balance of investment and innovation in the energy business.
The task, nevertheless, is not easy. Making use of capacity also requires coordination of one's intentions (em not only with trading partners, but with intermediate transporters, operators and usually an LDC. It is here that the intellectual and technological challenges, although manageable, appear daunting.
To reach this next plateau will require more market information and a better process of supporting the exchange of facilitation information. Only then can the gas and electric markets work to become more integrated. Only then can the growth potential of natural gas in electricity production be realized.
Capacity: Flows and Impediments
At present, gas flows vary hour to hour to meet an electric generation load that varies hour to hour. However, no standard conventions and operating practices exist; this puts buyers and sellers at a disadvantage. Buyers and sellers of gas cannot subdivide their instructions (em ownership orders and changes (em and communicate those plans in a way that will allow transporters to receive, clear and record any changes to initial intentions. What is needed are practices that will support more than just daily transactions: new practices for contracting, releasing, nominating, confirming, scheduling, allocating and balancing.
One big impediment to gas and electric convergence is capacity contracting. Not everybody needs the same amount of gas and associated capacity for all 24 hours in every day. In particular, gas for electric generation typically is consumed during the peak electric consumption hours. Likewise, the gas-for-space-heating peaks occur generally in the morning, before the gas-for-electric peaks, and, in the evening, after the electric peaks. As retail unbundling progresses, these differences will become more defined. Why not have transportation contracts that reflect these time-of-day differences and have the price responsibility also reflected accordingly?
Today, pipeline systems are "packed up" with gas withdrawn or diverted from storage overnight so that the peak hours can be met in the morning. When the industrial and manufacturing load goes off (or down by 80 percent) between 4 p.m. and 6 p.m., compressors often back off and redivert gas into storage. These are realities. It is also reality that today, the typical industrial customer (or its agent) buys 12,000 dekatherms a day of firm but uses that gas from 7 a.m. to 4 p.m. or 5 p.m. (in 9 to 10 hours). If the pipelines held industrials to the hourly rate (which very few do) then they would have to buy close to 30,000 Dth per day of capacity and waste the other 24,000 Dth (15 off-peak hours).
Dividing the capacity rights into quarter-day parts may be the best way to manage and tailor the contours of differing demand profiles. Many pipelines already vary contract quantity by month throughout the year. What may prove necessary is varying the contract quantity within the day and by month. Then, partial day capacity for those who want it only at those times could be market priced.
In the telecommunications markets, wholesale capacity at both local and long-distance levels is sold to competitors at regulated rates so that these competitors may compete in the unregulated segmented retail and day-part markets. Sales by regulated pipelines should work the same way, selling day-round (same hourly quantity for full day), for the year-round capacity for periods of greater than a year at the regulated rates. If allowed, the FERC could free shorter-term capacity from price regulation. That would enable day-part capacity pricing to find its market clearing level. This will go a long way to getting capacity into the hands of those who want it on demand, which is a necessary precondition of an hourly gas trading market.
Allocations: Cutting Up the Day
It is foreseeable that an overnight capacity market in some areas could prove so inexpensive that storage refills, line-packing and pressure services before morning peaks will become ideal uses of daily off-peak capacity. Once the contracting of capacity into these day-parts is established, holders of excess overnight capacity could release it for extended periods to those who can use it.
Devising a way to sell capacity in daily quartiles, thirds, or even halves, would allow the daytime and nighttime capacity markets (and associated methane) to find their own price level. Would that mean four gas "days" per calendar day? At some locations, yes, but not all. Separate day-part allocations to recognize ownership might not be required, for instance, at production locations that show no significant variation in flow.
At a minimum, however, a day-part market should reflect the allocated flows during the ownership period. In other words, absent parking and loaning arrangements, a 50,000 Dth/day well or supply source could not sell all 50,000 Dth to parties nominating flows only from 6 a.m. to 6 p.m. In fact, aggregators would fill the gaps by purchasing gas all day and then subdividing up the markets, and margins. Aggregators or producers who acquire capacity assets that enable time differentiation of gas will capture the margins it generates.
Imagine a stock market without financial reporting data to gauge the value of stocks. Or one in which traders could not discover what are the class, voting rights or sales options for all outstanding shares. The corollary in the capacity market is the real-time capacity availability listings that provide a liquid information underpinning to a daily and hourly trading system. The postings of short-term firm transportation, plus discounts and delivery and receipt points, should provide price and quantity transparency. Adding the points lists to the FERC-mandated index of customer postings creates a primary point exchange inventory and increases fungibility of capacity.
Solutions: Convincing the Naysayers
Here is an interim solution that might support the acquisition and transfer of market facilitating information:
1. Start with three or four intra-day nominations and grid-wide synchronization times.
2. Set procedures to bring allocations to the same level of granularity.
3. Establish standardized, nationwide rules allowing capacity to be released and used in either two, three or four parts per day.
Some pipelines say they cannot deal with hourly changes. That is nonsense. They already do that today, but with two qualifications. First, pipelines adjust the flow rates but do not tie it to whom the flow is for, other than on a daily basis. Second, pipelines are not paid to track whose gas is moving during that quarter day, or eventually, quarter hour.
Hourly adjustments are the name of the game and have always been. The dirty little secret is that quite often there is no match-up between flows on anything other than a daily or sometimes weekly (and often monthly) basis. Pipelines have always provided just-in-time gas. Now we are seeing marketers and traders spying the arbitrage opportunities to layer just-in-time pricing of gas (and capacity) on top of just-in-time physical gas. Increasing intra-day nominations and allocations capabilities provides precisely this opportunity.
Others think scheduling and rescheduling several times per day would be burdensome. Yes (em if it's done by phone. And that would prove nearly impossible without nationally recognized and supported confirmations procedures. Routinizing nomination and confirmation rules means the process can be automated. The increasing velocity of transactions attendant to hourly transacting means that there would have to be a contemporaneous increase in the velocity and certainty of the confirmations (clearing) and scheduling (back-office recording) processes.
The communications standards now exist in the data-sets for electronic data interchange already endorsed by the Gas Industry Standards Board. The business rules and flexibility to adapt over time are a necessity. To perform the faster confirmations and scheduling processes will require the adoption, by all interconnected parties, of computer-to-computer EDI-based processes. Doing so will not eliminate the people factor, it will move the people factor to coping with only the exceptions (em the 10 percent to 20 percent that doesn't fit (em rather than having to deal with the whole 100 percent all the time.
The point also is made that requests for hourly fluctuations should be verifiable. Absolutely. Hourly changes should only be made if the transporter can measure flow rate hourly and the upstream or downstream (as applicable) operator agrees that the hourly change is needed to meet demand.
Other necessary conditions to an hourly trading market:
1. Allow no reductions below prorated, scheduled quantities. Once the scheduled gas period has begun, don't permit any reduction that would "unflow" quantities to below what was already scheduled.
2. Bumping should be implemented only once at a cycle between one-third and one-half through the calendar day, giving bumped parties an opportunity to make alternative market or supply arrangements.
3. Daily allocations and imbalance settlement procedures should include trading of similarly situated quantities with a transaction charge levied by the transporters facilitating the trading.
In the end, the ability of the gas producers and capacity providers to garner time-differentiated margins rests on an information infrastructure and exchange system, and associated business rules. This is as important a challenge as the initial restructuring of the gas business that occurred under Order 636. Failing to recognize the challenge and rise to meet it will relegate producers of the gas commodity and transportation providers to a purely wholesale low-value-added role in the energy market. This role is similar to a third world country that exports its raw materials, then repurchases the finished products at a much later stage in the value chain. Harsh words, but likely to be true if the information and communications infrastructure is not upgraded to match the challenges ahead. F
Greg Lander is chair and president of The National Registry of Capacity Rights Inc. and president of TransCapacity Ltd. Partnership, the data-service agent of the registry.
A Day-Part Market: Minimum Requirements
1. Posting of short-term firm transportation service on electronic bulletin boards and in downloadable datasets consistent with existing standards used for posting of capacity release awards.
2. Posting of transportation discounts in downloadable datasets.
3. Postings of real-time operationally available capacity (updated after each scheduling cycle) to show the daily capacity available for the remainder of the gas day at all scheduled locations.
4. Adding the primary points information to the index of customers.
5. Creating, within each pipeline's database, an inventory accessible through electronic data interchange (a capacity exchange) consisting of unsubscribed-available firm rights at points and points that can be added to a capacity release (or short-term FT contract) by any acquiring shipper during release. This exchange of point rights requires the shipper simultaneously to place into the exchange (the pot of unsubscribed point capacity) an equal quantity of rights from a primary point obtained in the release, for the duration of the release.
6. Removing price caps for sales of capacity (including day-part) of periods less than a year's duration by allowing all sellers to sell for periods less than one year without price restrictions.
7. Keeping for an interim period (another five to 10 years) the requirement that regulated pipelines must sell capacity at regulated rates for periods of greater than a year (and longer terms at lengths of the customer's choosing) subject to such capacity going to the longest-term bidder as between competing bidding shippers.
8. Adding the element of effective time per day to the definitions of capacity rights in the index of customers and awards postings.
Conforming to Electricity: A Mismatch?
IN California, beginning in 1998, electricity will be purchased and sold through a power exchange. The PX will establish a competitive spot market for electric power through a day-ahead and hour-ahead auction of generation and demand bids. The PX will establish a market-clearing price in each hour based on the energy price bid by the marginal resource.
During much of the year, gas is expected to be the fuel used by the marginal plants in the PX. And as a result, the delivered price of gas to electric generators will form the basis for electricity prices in California during that time. Because the electricity market will be based on the market-clearing price each hour, gas-fired electric generators' gas demand will also fluctuate hourly1/4 The GISB [Gas Industry Standards Board] timeline (em which is based on the concept of daily gas commodity and capacity trading (em does not go far enough1/4 [T]his mismatch between daily gas scheduling and hourly electricity prices could create costly gas imbalances and may distort signals to both the gas and electricity markets.
(em Southern California Edison Co., excerpt from comments on hourly gas trading, FERC Docket No. PL97-1-000, Apr. 29, 1997, pp. 11-12.
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