Keeping Illinois warm

THE WINTER of 1976-77, one of the coldest in decades, brought the people of Illinois face to face with the nation's chronic gas shortage problem. As the mercury dropped, gas consumption increased to near record levels, but because of insufficient supplies, several utilities in the state were forced to reduce or to terminate gas deliveries to large industrial users, commercial establishments and some schools in order to maintain service to residential customers. While gas cutbacks to users in Illinois were not as sharp as those in Ohio, Pennsylvania, or New Jersey the situation here could easily have been much worse. The problem in Illinois
Cutbacks in retail gas service by utilities in Illinois and other states are symptoms of a long-term national problem that has become increasingly serious in recent years. Simply stated, the problem is that overall gas demand exceeds supply. Since 1971, production of natural gas for delivery to interstate pipelines has been less than demand even though estimated reserves of natural gas are more than adequate for meeting the nation's needs. An important element of the shortage problem stems from Federal Power Commission (FPC) regulation of the gas industry. The federal Natural Gas Act of 1938 provides FPC with authority to establish rates for transporting and reselling gas in interstate commerce. The government controls transmission rates because pipeline companies are viewed as having monopoly power over the shipment of gas from the point of production to the point of retail distribution. FPC determines transmission rates in the same manner as the Illinois Commerce Commission determines retail gas and electric rates. In 1954, in a controversial decision (Phillips Petroleum Co. v. Wisconsin, et al. 347 U.S. 672) the U.S. Supreme Court ruled that FPC was also required to regulate the price at which producers sold gas to interstate pipelines. Prior to the decision, increases in the wellhead price of gas were automatically passed on to consumers. It was argued that although transmission rates were regulated by the federal government and retail gas rates by state public utility commissions, consumers were not protected from increases in wellhead prices which were controlled by producers. In order to prevent unjustified price increases, the court held that FPC had a mandate to regulate wellhead prices.

During the 1960's, FPC followed a policy of holding wellhead prices down. As a result, the price of gas paid by pipelines did not increase in step with the costs of production or developing new supplies. Producers had little incentive to increase gas production for delivery to interstate pipelines or to explore and drill for new reserves. The latter is reflected by a decline in proved reserves of natural gas beginning in 1967, when, for the first time, annual production exceeded annual discoveries and additions to reserves.

Declining reserves, of course, may indicate more severe gas shortages yet to come. Total marketed natural gas production has also declined, but only since 1973. Furthermore, the latest FPC gas production statistics show that the decline in marketed production is leveling off at 20,000 billion cubic feet(BCF) per year. This indicates that gas production has not yet been noticeably constrained by declining reserves, a trend which obviously cannot continue indefinitely.

To understand why there are gas shortages in some states but not in others, one must distinguish between gas production from "new" wells and production for "old" wells. New wells are those that have begun to produce in the last three to four years. Gas from these wells is increasingly being consumed in the state in which it was produced. Since 1971, total sales of natural gas by producers to interstate pipeline companies have declined steadily, while at the same time intrastate sales of gas have increased rapidly. The price of gas sold in intrastate markets is not regulated by the FPC, and in some producing states, intrastate gas customers are outbidding pipelines for supplies by buying gas at prices considerably higher than FPC currently allows interstate pipelines to pay. The growth of large intrastate markets — especially in Louisiana, Texas and Oklahoma, three states which currently account for over 80 per cent of the nation's natural gas production — is absorbing potential new gas supplies for interstate markets.

The combination of declining production from old wells, declining sales of natural gas to interstate pipelines, and increased intrastate consumption of gas from new wells is preventing interstate pipelines from purchasing adequate supplies of gas. At current regulated wellhead price levels, pipelines cannot obtain enough gas to meet contractual requirements, and they have been forced to curtail gas deliveries to gas distribution companies. Because about 90 per cent of gas sold by interstate pipelines is delivered to distributors, who in turn provide natural gas to ultimate consumers, reported curtailments reflect reductions in supply

12 / June 1977 / Illinois Issues

at the wholesale level. Because many pipeline customers have sources of gas supplies other than interstate transmission, pipeline curtailments do not affect consumers as much as the curtailment figures reported by the Federal Power Commission would indicate.

Fortunately, this has been the case in Illinois where recent curtailments reported by the FPC have been the largest in the country. Curtailments by interstate pipelines to utilities in Illinois suddenly jumped from an average of 12.8 BCF per month in the first quarter of 1976, to over 34.1 BCF per month in the third quarter. Total curtailments for the six-month period from April through September alone amounted to 197.7 BCF or nearly one-fifth of total gas sales in Illinois for all of 1975. Yet there have been no severe shortages in the state to date because several Illinois utilities augmented pipeline supplies with substantial quantities of gas that had been stored underground or produced by two large synthetic gas plants.

The supply from underground storage has been extremely important. At the beginning of 1976, Illinois utilities had stored underground reserves of over 376 BCF, which were equal to about 37 per cent of total 1975 gas sales. But the severe winter of 1976-77 has seriously depleted these underground reserves. If curtailments continue at present rates or increase, gas utilities will have a difficult if not impossible time in restoring underground reserves to pre-winter levels. This leads one to ask: "What is the potential for gas supplies for next winter and for the winter after that? What are the prospects for gas supplies for Illinois consumers for the next 5 to 10 years?" To answer these questions some clear information on all sources of gas supplies is needed.

What are the prospects for the next 5 to 10 years in Illinois?

Potential sources of natural gas within Illinois include conventional reserves of natural gas, gas associated with shales and gas trapped in coal seams. For the most part, these sources are considered either too small or too costly to warrant extensive development at this time.

Some gas field development has taken place in Illinois, and in 1975 intrastate natural gas production amounted to only 1.4 BCF or slightly more than 0.1 of one per cent of total gas sales in the state for that year. But while natural gas sources in Illinois may undergo further development in the next 5 to 10 years, it is unlikely that intrastate gas production will increase much over current levels. Illinois must, therefore, continue to rely on interstate shipments of gas to meet the bulk of its needs.

U.S. reserves Estimated reserves of natural gas in the United States are more than adequate for meeting the nation's needs for several years to come. The difficulty will be in getting that gas out of the ground and to consumers. The American Gas Association's (AGA) most recent estimate of total proved recoverable reserves of natural gas in the United States (including Alaska, and some offshore reserves) is 228,200 BCF. These are quantities of gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under present economic and operating conditions. This estimate represents about a 10-to-12-year supply for the nation at current rates of natural gas production.

The U.S. Geological Survey (USGS) has made estimates of inferred reserves and undiscovered recoverable resources of gas which, when added to the AGA's estimate of demonstrated reserves, may add another 25 to 40 years of supply at current rates of production. USGS estimated that inferred reserves — quantities of gas which with additional exploration will be added to demonstrated reserves through extensions and revisions of the estimated sizes of known gas reservoirs — will increase proved reserves by 200,000 BCF or 10 more years of supply at current rates of production. In addition, the USGS estimated that there is a 95 per cent probability that another 322,000 BCF of currently undiscovered but economically recoverable gas, will be discovered in the United States, and that there is a five per cent probability that as much as 655,000 BCF of recoverable gas will be discovered. In other words, there is a 19 in 20 chance that at least the minimum and a 1 in 20 chance that the maximum amounts, respectively, of undiscovered gas will be produced in the United States. This gas is considered recoverable under present economic conditions, and at the present rate of production, these discoveries would add another 15 to 30 years of gas supply. Exploration and development
In the face of increasing difficulties in purchasing sufficient quantities of gas to meet contractual requirements, many pipelines and their associated distribution company customers have initiated their own exploration and drilling programs. Historically, pipelines dealt solely with gas transmission; gas utilities dealt solely with distribution; and producers, who are primarily the major oil companies, developed new gas supplies. With supplies diminishing, many pipelines and distribution companies are now intending to produce for themselves the gas they can no longer purchase in the market place. With apparent encouragement from the Illinois Commerce Commission (ICC) gas utilities and pipelines that service Illinois have shown considerable foresight in establishing their own drilling and exploration programs. For example, over 20 years ago. Northern Illinois Gas Company, the largest gas utility in Illinois, formed a wholly-owned subsidiary, NI-Gas Supply, Inc., for the purpose of engaging in exploration and development activities. The ICC authorized Northern Illinois to invest a portion of its retained earnings each year in NI-Gas Supply, and that investment program is now paying dividends in the form of gas supplies to Northern Illinois Gas Company customers. As of the end of 1976, NI-Gas Supply had participated in the drilling of 367

June 1977 / Illinois Issues / 13

successful wells, 92 of which were connected to pipelines servicing the parent company.

A recent sample survey of major pipeline companies showed that in 1976 estimated expenditures for lease acquisition, drilling and development increased by more than 75 per cent over 1975, and these companies plan additional increases in 1977. Of the pipelines which service Illinois, Natural Gas Pipeline Company of America, Panhandle Eastern, Northern Natural Gas Company, and Michigan-Wisconsin Pipeline Company have established exploration and drilling programs and are planning to increase investments in those programs in the next few years. Pipelines are concentrating exploration efforts offshore in the Gulf of Mexico and in the Rocky Mountain states where intrastate gas markets are weak. In both areas there are large tracts of undrilled territory which may enhance — but cannot insure — discovery prospects. It must be pointed out, however, that even after discovery, it takes two to five years before gas reaches the consumer. It takes that much time to complete the drilling, to install a gathering system, and to connect the field to an interstate pipeline.

To finance exploration and drilling activities, some pipelines have asked gas distribution companies to enter into advanced payment agreements. Under this kind of agreement, a gas utility makes an advance payment to the pipeline for gas that it expects to receive as a result of the development of a new gas field. If gas is not discovered, the advance is returned making it, in effect, a guaranteed, no-interest loan by the gas utility to the pipeline company. In Illinois, several gas utilities have been making advance payment agreements to supplying pipelines and producers since 1971 when gas shortage problems first became apparent. These agreements must be approved by the Illinois Commerce Commission, which to date has approved all requests. The first agreement of this kind involved Natural Gas Pipeline Company of America and, among others. Northern Illinois Gas Company, People's Gas, Light and Coke Company, and Illinois Power Company and financed a development in the Gulf of Mexico that is now supplying gas to Illinois.

Alaska will also provide a major new source of interstate gas supplies as soon as a gas pipeline to transport gas to the lower 48 states is constructed. Construction has not yet begun which means that deliveries of Alaskan gas will not begin to flow until 1982 or 1983 at the soonest. Yet to be decided is the selection of the pipeline route. One proposed route parallels the Trans Alaskan oil pipeline to the port of Valdez, Alaska, where the gas would be liquified and shipped via tankers to west coast ports. A second proposed route is up the Mackenzie River Valley to Edmonton, Canada, and connection with the Canadian pipeline network which in turn links up with the U.S. pipelines particularly for service to Midwestern markets.

Finally, large quantities of imported natural gas from Canada, Mexico and several other countries will flow through interstate pipelines in the next 5 to 10 years. Canadian gas currently accounts for about 7 per cent of total gas sold by producers to U.S. interstate pipelines. U.S. pipeline companies are also planning to import large quantities of liquified natural gas (LNG). LNG import projects whose applications have been approved by FPC would supply 1,350 BCF of gas to U.S. consumers annually by 1981-82. Algeria is expected to be the source of 85 per cent of this supply and Indonesia, the remaining 15 per cent. Projects involving imports of an additional 2,170 BCF annually by 1985 are still in the discussion stage. This gas would come primarily from Iran and the Soviet Union. Wholesale natural gas prices in the U.S., 1975-1976 (cents per 1,000 cubic feet)

		Average price of gas purchased by interstate pipelines	Average price received by interstate pipelines for gas sales	Average intrastate price
Source	July 1975	July 1976	July 1975	July 1976	April-June 1976
Domestic
Average	36.7	43.6
New contract*	56.2-73.6	79.8-101.5
Canadian	120.8	168.4
Total average	41.7	53.2	84.6	101.8	158.8

Source: Federal Power Commission
*Average quarterly prices for first and second quarters. Sources of synthetic gas
In addition to natural gas, Illinois utilities will use synthetic or substitute natural gas (SNG) in meeting the needs of their customers in the next 5 to 10 years. SNG can be produced from a variety of feed-stocks including light liquid hydrocarbons such as liquid petroleum gas (LPG) and naphtha; heavy liquid hydrocarbons such as residual fuel oil and asphalts; and coal.

Coal gasification has received a great deal of attention in Illinois (see Illinois Issues, November 1976). Abundant coal reserves, adequate water supplies, easy access to pipelines and rail transport, and proximity to large markets make the state appear ideal for the development of a coal gasification industry. But the technology for producing pipeline quality gas from Illinois coal will not, in all probability, be available on a commercial basis until the mid-1980's. There are still many complex technical and financial problems which must be overcome before large scale coal gasification plants can be built. Operation of the first of these plants in New Athens has now been pushed back until 1983, and the demonstration phase of that project will not be complete before the mid-1980's. This means that the Coal- con gasification technology will not be implemented on a commercial basis until the early 1990's.

Unlike coal gasification, the technology for producing synthetic natural gas from light, liquid hydrocarbons such as LPG and naphtha is commercially available at the present time. There are now 13 such plants with an installed daily production capacity of 1.307 BCF in operation throughout the country. Two of these plants are in Illinois (one near Morris that has been operated by Northern Illinois Gas Company since 1974 and one near Elwood that has been operated by People's Gas, Light and Coke Company since early 1976) with a combined daily capacity of about .320 BCF. If operated at full capacity on a 335-day per year operating schedule,

14 / June 1977 / Illinois Issues

these plants can produce over 100 BCF of gas per year or 10 per cent of total gas sales in Illinois for 1975.

The major difficulty with producing SNG from liquids is obtaining sufficient feedstock. As a result of the Arab Oil Embargo, the Federal Energy Administration (FEA) was created and given authority to regulate available supplies of all petroleum products. Under the Emergency Petroleum Allocation Act of 1973, FEA has established mandatory price and allocation regulations for determining the amounts of naphtha and other refined raw materials or feedstock that SNG plants can purchase. These regulations require all plants for which groundbreaking has occurred since May 1,1974, to apply to FEA for assignment of a feedstock supplier and volume. FEA's policy on allocating petroleum feed-stocks for SNG production has been quite restrictive and has effectively limited prospects of increasing gas production from liquids in the near future. In 1974, the agency took the position that SNG manufactured from petroleum products represented an inefficient use of energy resources because of the BTU's lost during the reforming process. Because of this stance, many SNG-from-liquids plants that were in the planning stages, including one large plant which was being planned for construction near Bement, Ill., have now been postponed indefinitely or cancelled. Plans to increase Northern Illinois Gas Company's plant by 50 per cent have also been postponed because of FEA regulations. Because it takes three to four years to construct and test a synthetic plant, it may be several years before even an immediate reversal of policy by FEA results in increased synthetic gas production.

FEA's view of the inefficiency of using petroleum products to produce gas is somewhat ironic for the following reason. Naphtha is primarily an intermediate petroleum product, with 90 per cent of naphtha production being used as blending stock for gasoline. The maximum efficiency with which energy in gasoline is converted to useful work in an automobile is 30 to 35 per cent, but the maximum efficiency with which energy in natural gas is converted into heat is about 80 per cent. Therefore, even allowing for the energy loss of converting naphtha to gas, the net capture of energy in end use with gas for heating is 2 to 2.5 times greater than with gasoline for transportation.

A second difficulty with SNG from liquids is the price. SNG, regardless of the feedstock, is more expensive to produce than natural gas. Gas produced from naphtha, for example, currently costs about 3.5 to 4.0 times the delivered wholesale or city-gate price for natural gas. Furthermore, naphtha costs, which account for over 80 per cent of the cost of producing SNG from naphtha, will remain high because of its competing uses in gasoline and petrochemical production. The role of price
The price of natural gas will play an important role in determining the extent to which supplies of natural gas will become available in the next 5 to 10 years. As indicated above, for several years FPC kept the wellhead price of natural gas from increasing in a manner that would have stimulated production, a trend which that agency has now begun to reverse.

The table indicates the current structure and trend in natural gas prices in the United States. The average purchase price of gas from domestic producers is considerably below the purchase price of gas in new contracts, of gas sold in intrastate markets, or of gas imported from Canada. As interstate pipelines purchase more of the higher-priced, new contract gas to replace dwindling supplies of lower-priced, old contract gas, the wholesale price of gas will increase as it did from 1975 to 1976. In '1976 the Federal Power Commission increased the rate at which it would allow pipelines to purchase gas that has been developed since 1975 to a maximum of $1.42 per 1,000 cubic feet (MCF). This rate will automatically escalate by four cents per MCF annually. In addition, FPC also increased the maximum rates for gas which began to flow in pipelines in 1973-74 to 93 cents per MCF with an annual escalation of one cent per MCF.

Over the last few years. Congress has considered legislation to eliminate FPC's authority to regulate wellhead prices. One measure, which was passed in the Senate in 1975, specified immediate deregulation of new gas sales from onshore production and deregulation of gas produced offshore beginning in 1981. Similar bills have again been introduced in Congress this session. If adopted, this kind of legislation would cause new contract gas prices to approach the even higher intrastate prices. In response to emergency conditions created by last winter's cold weather, Congress did pass the Natural Gas Emergency Act of 1977. This act in effect deregulates wellhead gas prices temporarily. The law permits interstate pipelines to make emergency purchases of gas at prices above the $1.42 per MCF ceiling until July 31,1977. The President has the authority to establish prices made under the act, and presidential discretion is expected to keep prices from rising above $2.25 per MCF.

Higher and escalating wellhead prices for natural gas are bound to result in increasing retail gas prices for several years to come, and in all likelihood, increases in wellhead prices will result in even greater than one-to-one increases in the price of gas to consumers. The compressors that move gas through pipelines are also powered by gas. Therefore, an increase in the wellhead price of gas also means an increase in pipeline operating costs which will be passed on to consumers as shown in the table.

Even with complete and immediate deregulation, however, average wellhead prices will not rise up to intrastate levels overnight. Higher wellhead prices for new contracts will be "rolled in" as old contracts expire causing the average gas price to increase slowly. In any year new contract gas supplies from domestic sources comprise only a small fraction of total gas under contract. The full impact of new contract prices will be realized only after the change has been in effect for 5 to 10 years.

Gas users in Illinois and throughout the nation will pay higher prices for gas in the next 5 to 10 years. Higher prices are needed to stimulate exploration and development for new supplies of natural gas. Higher prices will also encourage conservation and switching to other fuels. Natural gas will continue to provide the bulk of Illinois' gas needs in the next 5 to 10 years. Gas shortages will prevail until production for interstate transmission catches up with demand. Supplies will be augmented by LNG imports, SNG production from liquid hydrocarbons, and perhaps to a small extent, by coal gasification. All of these alternatives are more expensive than natural gas. 

June 1977 / Illinois Issues / 15

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