GAS PIPELINE ADJUSTS OPERATIONS TO MEET ORDER 636

John D. Cummins
Texas Gas Transmission Corp.
Owensboro, Ky.

Responding to U.S. Federal Energy Regulatory Commission's Order 636, Texas Gas Transmission Corp., Owensboro, Ky., has instituted an allocation procedure for unbundled supply, pipeline transportation, and storage while maintaining system security and providing required services to each customer.

FERC Order 636 (Apr. 13, 1992, p. 32) requires federally regulated natural-gas pipelines to separate, or "unbundle," such traditional sales services as supply, transportation, and storage. Formerly, these services could be offered as a package, an arrangement the commission felt discouraged competition.

Because Texas Gas has always relied heavily on bundled operation to' provide efficient service to end users, the order has profoundly affected projected design and operational strategies.

The greatest challenge has been to maintain or exceed current levels of safety, reliability, and efficiency.

TEXAS GAS' SYSTEM

The contiguous Texas Gas system extends generally from offshore Louisiana to Lebanon, Ohio, and physically delivers gas to locations in Louisiana, Arkansas, Mississippi, Illinois, Kentucky, Indiana, and Ohio (Fig. 1).

Facilities include more than 6,000 miles of transmission pipelines, nearly 500,000 hp installed, and ten gas-storage fields in Kentucky and Indiana. Major supply areas include East Texas; northern, southern, and offshore Louisiana; and offshore Texas.

Texas Gas' storage fields are located deep within its market area (Fig. 1) with more than 98% of the total storage capacity interacting with the main line at the Slaughters, Ky., compressor station.

On winter peak days, storage on Texas Gas' system provides needed capacity as the main line upstream of Slaughters reaches full capacity.

In fact, the winter pipeline capacity upstream of storage is roughly 2.0 bcfd, while contractual requirements system-wide exceed 2.7 bcfd.

Without storage, Texas Gas would require more than 250 miles of 36-in. pipeline loop and more than 100,000 hp of new compression to provide contractual deliveries.

Maximum peak-day storage withdrawal capabilities are about 1,1 bcfd in late winter. Because supply interruptions occur during extremely cold weather, this peak capability is needed to provide supply security as well as normal requirements.

During normal winter days, net withdrawals are usually 200-300 MMscfd. Most customers on Texas Gas' system use much less gas during the summer months than winter, with the aggregate summer load factor much less than 100%.

Therefore, winter needs are met by the company's use of storage withdrawals, while enough summer capacity exists to deliver city-gate requirements and refill the storage fields.

Total cycled storage is primarily controlled by physical storage field facilities or by summer main line capacity available upstream of storage.

(Winter seasonal withdrawals must be limited to the extent summer pipeline capacity exists to move the gas to Slaughters and refill the storage fields.)

Storage withdrawals, then, are required to serve winter and peak-day loads, while injection takes advantage of summer capacity that results from low summer load factors.

Bundled service was historically provided to Texas Gas' customers, therefore, by effective coordination of storage to balance seasonal pipeline throughput upstream of Slaughters.

To provide comparable service after Order 636, storage capacity must be tied to individual customer requirements.

ALLOCATION

Even though Texas Gas understands thoroughly how to use main line and storage in aggregate, the company needed to apply this knowledge customer-by-customer. The company serves customers with various hourly, daily, monthly, and seasonal needs.

The goal was to develop a practical, understandable mathematical relationship which would allocate all capacities fairly and realistically for the different load patterns on its system.

To develop this relationship, the company first estimated which customers were actually "using" its seasonal and peak storage capacity and generally to what extent.

By researching historical customer seasonal requirements (city-gate deliveries) and historical system operation, Texas Gas identified the several types of customers being served from its system.

Although no two seasonal patterns were exactly alike, they could be combined into a few general categories. After applying its knowledge of how the system was designed, Texas Gas was able to reach two fairly obvious conclusions concerning the customer types:

Customers with fairly constant annual requirements use very little seasonal storage.
Customers with wide seasonal load swings (high winter, low summer, for instance) use relatively large amounts of seasonal storage.

Examples of some of the types of customers and the relative storage they require appear in Fig. 2. There, seasonal storage is a function primarily of the difference in winter and summer load factors, not annual load factor or contract demand.

Peak-day storage, however, is a direct function of annual load factor and contract demand.

For example, if contract demands of the customers shown in Fig. 2 are equal and their relative winter-summer load factors are equal, their seasonal storage would be roughly equivalent.

Their peak storage needs differ greatly, however, because of their different annual load factors.

PROCEDURE

After analyzing the various customer types, Texas Gas established certain guidelines to protect the real-time operation of its pipeline system. In other words, the company had to make sure what it offered customers would actually work if they all used their allocated rights.

Equations were then developed to work within the following guidelines:

Main line facilities cannot physically deliver contract demand 365 days a year.
Storage is allocated based on load factors.
Real pipeline capacity is less in summer than winter.
Allocated capacities will ultimately rely on customer renominations of contract demand and seasonal quantities.

An accompanying box shows Texas Gas' allocation procedure and an example with a hypothetical company of how the procedure is used.

DEVELOPING PROFILES

As the allocation strategies were developed, Texas Gas met with individual customers, customer groups, and FERC staff.

These meetings provided additional direction that helped Texas Gas refine several tolerances to help meet each customer's needs while retaining nondiscriminatory service.

Early in the process, Texas Gas focused on meeting customer needs seasonally while protecting peak-day demands at the same time.

The company soon recognized the need, however, to carry the process a few steps further and explore monthly and daily city-gate requirements.

Using historic daily city-gate deliveries, the company developed annual profiles and tested them against its proposed allocations.

For example, customers with significant amounts of their own storage facilities had special "shoulder-month" (April and October) needs to refill their reservoirs. Others had low summer load factors but required heavy deliveries periodically for certain industrial end users on their systems.

Because customers in Louisiana have very little in common with other customers on Texas Gas' system, in terms of load patterns, they were analyzed separately.

In a few cases, customers tried to apply Texas Gas' proposed allocations to a "worst-case arctic winter of the century" against which the system was never designed to protect: Neither the company nor its customers could afford the extremely low use factor for facilities designed on this basis.

Weaknesses were identified and resolved to the extent possible within the framework of the four-step allocation procedure discussed in the box.

Texas Gas' settlement of customer concerns over pipeline and storage capacity resulted from open communication. Customer support helped resolve several major issues with the FERC, as requested by Texas Gas, including the following:

Texas Gas will retain ownership of storage gas.
Texas Gas can retain upstream pipeline capacity on other systems.
Allocation of storage capacity is linked to allocation of pipeline capacity.

SUPPLY-AREA OPERATION

Supply enters the Texas Gas system primarily in northern and southern Louisiana, offshore Texas, and offshore Louisiana. Approximately 33% of Texas Gas' supply currently enters its system in northern Louisiana with the remainder in southern Louisiana and offshore.

In the past, Texas Gas was able to coordinate supply-lateral capacities with storage and pipeline capacity to provide reliable, uninterrupted service to all customers.

Supply-area allocation on a nondiscriminatory basis must replicate pre-Order 636 services. Although pipeline and storage capacities are well defined, supply-area capacity is a moving target.

Capacity at a receipt point is controlled by the connecting pipeline segments and ultimately the main line. Supply availability also shifts with time, the shifts being somewhat unpredictable.

Several estimates were therefore required to define an exact capacity for each supply area.

Information from several departments within Texas Gas helped define a "most likely" case describing supply-lateral constraints, operation of pivotal compressor stations, and valve configurations.

Historical receipt information helped the company, when determining capacity, to estimate the best locations to load each lateral.

The information helped Texas Gas to calculate maximum simultaneous capacities of all described laterals without regard to main line capacity (Fig. 2). These values served as the basis for the company's preliminary, supply allocation.

For Texas Gas, supply-lateral capacity is approximately 135% of main line pipeline capacity.

METHOD; EXAMPLE

Because supply flow must essentially use main line capacity, tying supply allocation to allocated main line capacity is logical. For example, if a customer is allocated 10% of the total allocated pipeline capacity, this customer would receive 10% of each supply lateral's capacity,

The following example illustrates this idea, plus the other real-time constraints involved.

First, consider a pipeline system serving five customers. The preliminary allocation fraction for each customer is calculated by dividing a given customer's pipeline rights (capacity) by the total pipeline rights (Table 1).

Suppose this pipeline system consists of five supply laterals with individual leg capacities (Fig. 4).

Initial allocations are calculated by multiplying the preliminary allocation fraction by each leg capacity (Table 2).

The complicating aspect of supply allocation is the potential "grandfathering" of pre-Order 636 firm-transportation receipt points.

To protect customers on the supply side, all existing firm-transportation receipt commitments will be eligible for grandfathering, at the discretion of the customer. For example, assume the highlighted volumes in Table 3 are protected, grandfathered quantities, which exceeded the initial allocations. Other quantities may have been "protected" but were not greater than the initial allocations.

Because Texas Gas cannot violate individual leg capacities, non-grandfathered quantities must be reduced pro-rata to bring each leg back to 100% capacity (Table 4).

Each leg is allocated within its capacity, but the customers are not receiving equal percentages of their pipeline rights. Therefore, each customer must be prorated to set his total allocated supply capacity equal to 135% of his pipeline capacity (Table 5).

This adjustment has skewed the total allocation on each leg, but the iterations are obviously converging. Only 6-8 iterations are required to allocate supply capacity so that the legs are at 100% capacity and each customer receives an equal percentage of his pipeline capacity (Table 6).

This procedure is currently being used with Texas Gas' more than 100 customers and eight defined supply laterals, and works as described. Several supply issues remain, such as allocating capacity at oversubscribed points, shifting supplies and capacity, new supply points, and new customers requesting supply capacity.