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LDC gas management in a deregulated marketplace.

FERC Order 636 makes interstate gas transmission service the same quality as sales service. This equality is long overdue and will in the long run be good for the industry and especially the local distribution companies.

It will enhance LDCs' marketing efforts by allowing the utilities to more closely plan and control 60% of the cost of service--gas costs. LDCs will be better able to more closely link demand and supply.

The transition will not be painless. Companies need a competent, well-staff organization where planning, sophisticated modeling and daily operations are inextricably linked.

Market Forces

From the beginning of the industry until now, gas pipelines had the responsibility for gas supply management.

The pipelines acted as aggregators of gas supply for all end-users. The system worked well while interstate gas prices were regulated. In the end, it was regulation that did not work, not interstate pipeline management of gas supplies under regulation.

Market forces began to take over with the arrival of producer market deregulation in the late 1970s. Pipelines proved particularly inept at matching gas supplies with demand under market forces. LDCs were not very far ahead, but gas utilities had a greater desire and ability to react to such forces. However, LDCs could not control their own gas supply because pipelines had a lock on gas supply management.

After many painful years, and with probably some still to come, gas supply management is where it belongs: with the local gas distribution companies.

The transition from 40 years of regulation and pipeline gas supply management will not be easy. The first step toward managing this new function, which represents 60% of an LDC's annual costs, is to have a proper organization.

Functions included in Mountain Fuel's gas supply management organization include planning, scheduling, nominating, dispatching, purchasing, reservoir engineering, gas accounting, capacity marketing, contract administration and gas cost regulatory interface.

* Planning: Gas planning personnel coordinate with gas operating personnel daily and work with planning periods from 1 day to 20 years. They must have a complete understanding of the gas supply system, contracts, reserves, deliverability, storage, transportation and load profiles. Tools used include models rivaling the complexity of airline scheduling programs.

* Scheduling: This is short-term, monthly and daily planning. It requires matching expected demand with gas supply contract terms and required takes. It is a team effort between the planners and the nominators (gas supply operating personnel).

* Nominating: Operating personnel must daily match actual demand with supplies through contract with producers, gatherers and transporters across the entire path of gas flow from well-head to the end-user's meter.

This task involves forecasting weather and demand; nominating supplies daily, based on operational and economic considerations; monitoring daily and monthly balances; daily nominating storage withdrawals or injections, gathering and transmission on multiple systems; and many other functions.

* Dispatching: The appropriate pressures and flows in the distribution system must be maintained through control of gas supplies, valves and regulators.

* Purchasing: Gas purchasing practices and terms are changing rapidly. This department must maintain a relationship with producers, marketers, transporters and financial people such as hedgers. Personnel must be in daily contact with the gas futures market, planners and nominators. They have to purchase a least-cost reliable supply that matches the supply portfolio with demand. This portfolio must be flexible enough to respond to changing weather and supplies.

* Reservoir Engineering: If the utility owns gas reserves, reservoir engineers manage them. If the LDC purchases gas from dedicated acreage, these engineers determine reserves and deliverability. This department can also study the operating characteristics of owned or leased storage facilities, and propose proper injection and withdrawal schedules.

* Gas Accounting: Unlike other accountants, gas accountants have to correct every number the following month due to the lack of timely data, most of which is generated external to the company. This sets the department apart from the utility's general accounting function.

* Capacity Marketing: With the implementation of Order 636, Mountain Fuel Supply had $17 million of annual revenue requirement shifted to it by its major gas transporter from interruptible shippers. Capacity marketing seeks to generate revenues to cover that cost shift by selling the company's firm transportation capacity at times when Mountain Fuel Supply does not need it. The sale is usually made to the same shippers that once purchased the service from the transporters.

Capacity marketers must not only maximize revenues but also minimize operational issues associated with releasing receipt or delivery points. Released capacity has to be monitored for use by the capacity purchaser and possible recall for use in meeting the LDC's firm demand. This is an important function with millions of dollars at stake. Regulators will scrutinize the LDC's ability to match the cost shift with released capacity revenues.

* Contact Administration: All other departments, even accounting, come here for data, which today must be provided electronically. Contract administration must be matched to production ownership, nominations and daily flows.

* Regulatory Interface: Although an LDC makes no profit from its gas supply operations, regulators are always interested in maximum performance from any sector of utility operations that generates 60% of the cost. Regulators may penalize profits if performance is not maximized. Regulatory interface involves gas cost reimbursements and Integrated Resource Planning.


Prior to Order 636, gas utilities did not have to make electronic nominations of all gas supplies, which now can include numerous pipelines, hundreds of supply sources and scores of supply contacts involving a mind-boggling number of wellhead royalty interest owners.

This task that previously belonged by gas pipeline companies must now be performed independently by shippers. There are substantially more people involved, which multiplies the chances for error. Electronic systems have been developed to help, but more are needed. These systems are new and complicated.

Contractual obligations must be met. If gas must taken every day of the year, it has to be nominated every day of the year. Gas must be dispatched economically, if there are choices of supplies to meet demand, the right economic decisions must be made or marketing will be handicapped and regulators will be asking some difficult questions.

New, sophisticated data systems must be developed to help the operator with these new responsibilities.

There are also supply issues, and daily capacity issues to manage.

If Mountain Fuel Supply wants to recall unused capacity already sold by its capacity marketers, it must do so 50 hours before its actual use. This requires accurately estimating gas demand at least 50 hours in advance. if too much capacity is recalled and not used, revenues are lost. If not enough capacity is recalled, supply could be curtailed.

The Utah Public Service Commission has established a target revenue that must be achieved through capacity marketing, with any shortfall being subtracted from the company's profits. Mountain Fuel Supply's profit could be reduced if too much capacity is recalled, and firm demand is not met if not enough capacity is recalled.

Flexing is another operational issue. Some major pipelines (including Questar Pipeline, Mountain Fuel Supply's major transporter), require firm capacity be delineated from Point A to Point B. The demand can be fairly easy to predict, but what if supply shifts from Point A to Point C because gas is cheaper at C? In that case transportation would no longer be firm but the LDC is paying the demand charges for total needed throughput. Should the LDC take a chance even if there is no guaranteed firm service?

Another thorny issue involves transportation customers on the utility's system. Should an LDC use its firm gas supplies, purchased and paid for by firm customers, to back-up transportation customers' supplies? If these firm supplies are called upon to replace a temporary lack of customer supply, they would not be available to meet a peak in firm demand. If back-up is not provided, transportation revenues could be lost. The customer might also be displeased with the level of service received from the utility and consider a bypass.

LDCs need telemetry and electronic systems that can determine if a transportation customer is using owned or utility gas. These systems are needed regardless of whether the utility does or does not provide back-up supplies. Without such systems the LDC may be providing the service and not know it.

Gas nomination systems just like the pipelines use are needed by LDCs.

Supply Contracts

Futures trading is a fact of life in the gas business. Many pipelines have market indexes associated with them. Relationships should exist between those indexes and the futures market, but they do not seem to exist. Contracts can be a fixed price, or tied to the futures price or index price, although fixed price contracts are becoming rarer.

Gas supply contracts used to be for 20 years but now they cover 1 or 2 years, or even month-by-month. Contracts once were tied to all gas from certain acreage, but now they are for a set volume that might be provided from a variety of areas. Current contracts involve a less-than-full-price payment for gas not taken, with no make-up provisions. There no more market-out or regulatory-out clauses in gas supply contracts.

As a result of all these changes, an accurate contract administration database is mandatory.


As gas prices went up in the late 1970s and early 1980s, regulators developed a keen interest in gas costs and gas supply management. They focused their attention to gas company planning only after years of oversight of the electric industry resulted in what is known as Integrated Resource Planning.

Regulators decided that demand reductions would be better than new generating facilities. State and regional authorities got involved with the electric industry to ensure that expensive rate-base plants were truly needed because:

* Electric companies did a poor job of forecasting demand.

* Power plants have a lead time of up to 15 years.

* Fuel costs rose rapidly in the 1970s.

Regulators must realize the differences between IRP for electric and gas utilities.

The most significant is that gas facilities do not have a 15-year lead time as do electric power plants. This results in shorter planning horizons and less need for extremely accurate long-term demand projections. Because gas projects are less capital intensive, programs to reduce gas demand are not as economically justifiable from a ratepayer's point of view.

Nevertheless, modeling is complex. Large linear programming models are required. Mountain Fuel Supply's model takes 6 to 17 hours of run time on a 486Dx2-66, and requires massive amounts of memory. Data collection is time consuming.

The model performs least-cost programming on a number of variables:

* Month-by-month for 20 years.

* Five storage fields.

* 15 company production groups.

* 15 existing contract groups.

* Six potential gas supply contracts.

Nothing goes as planned, so Mountain Fuel Supply seeks regulatory approval not of specific operating numbers but rather for rules of operation, principles that guide daily operational decision making. The specific planned numbers are not relevant. Rather, relevance lies in the process developed to react properly to change.
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Title Annotation:local distribution company
Author:Balthaser, James L.
Publication:Pipeline & Gas Journal
Date:Apr 1, 1994
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