A.D. Koen
Gulf Coast News Editor
Several indicators of U.S. gas industry activity are trending upward.
That raises industry hopes that markets are balancing and a long awaited recovery has begun.
U.S. gas demand continues growing, pulling spot prices in 1992 to the highest fourth quarter average in more than 2 years.
Short term supplies appear more than enough to serve significantly greater consumption. And there is an ample gas resource base to serve larger markets for many years, given adequate financial incentives.
Gas industry leaders say the Federal Energy Regulatory Commission's implementation of Order 636 will increase competition in the industry to the benefit of players in all segments-production, transportation, distribution, and marketing. Companies willing to apply technological advances, adopt new operating techniques and management strategies, and sign long term sales contracts are contending for larger market shares as players in all segments consider significant new opportunities.
But not all indicators promise prosperity.
The brightest gas industry outlook since federal regulatory evolution began more than a decade ago is dimmed by low drilling activity and declining reserves. Many gas producers say not enough gas wells are being drilled to maintain productive capacity to meet long term demand. Others in industry are concerned about how and where they will find the money needed to add infrastructure to promote gas use.
Despite the beginning of the end of federal regulatory turmoil, many in the gas industry are no less uncertain about who will be left standing as the race to sign up and serve new customers continues to heat up.
EFFECT OF PRICING
The link between drilling activity and spot market prices, the latter one of the gas industry's most promising indicators recently, shows why doubt lingers about the role gas will play in the U.S. energy future.
As reported by Natural Gas Clearinghouse (NGC), Houston, spot prices in 1992 averaged $1.68/Mcf, up from $1.40/Mcf in 1991 and $1.60/Mcf in 1990 despite February 1992's average of only $1/Mcf.
Fourth quarter 1992-when spot prices averaged $2.57/Mcf in October, $2.20/Mcf in November, and $2.13/Mcf in December-was the first time since January 1990 that spot prices had averaged more than $2/Mcf.
NGC reported spot prices averaged $1.93/Mcf for the current month, 32cts/Mcf more than the January 1992 price but the lowest monthly average since September 1992.
As spot prices rebounded through 1992, the number of rigs drilling gas prospects increased.
Baker Hughes Inc.'s count shows that in the last week of 1992, 525 of 928 active rotary rigs were drilling gas wells (OGJ, Jan. 4, p. 60). Rigs on gas wells numbered 313 in the first week of 1992 but dropped below 300 by mid-January. Baker Hughes active rig counts of 1992 ranged to as few as 242 units drilling gas wells in April and June before surpassing 300 in mid-July and 400 in late October.
But even with more than 500 rigs dedicated to gas drilling at yearend, activity was short of estimated levels required to maintain reserves.
In addition, many sources expected gas well drilling to drop significantly after yearend because of the end of Section 29 federal tax credits for new wells. Production from nonconventional gas wells spudded before the end of 1992 qualifies for Section 29 credits through 2002 (OGJ, Nov. 2, 1992, p. 21).
DWINDLING RESERVES
With 1992 U.S. drilling activity at the lowest levels since World War II, U.S. gas reserves at yearend were assured of declining for the second straight year.
In 1991, when Baker Hughes' weekly counts of active rigs averaged 860, U.S. producers drilled about 8,980 gas wells and marketed 18.523 tcf of gas. Meantime, the Department of Energy's Energy Information Administration (EIA) reported proved reserves slipped to 167.1 tcf, down 2.284 bcf from yearend 1990.
In 1992, when weekly rig counts averaged about 717 units, operators through September had drilled 4,920 gas wells-about 70% of 1991's pace and production was ahead of 1991's rate.
Except for 1990, when yearend reserves exceeded the year earlier estimate by 2.23 tcf, U.S. gas reserves have declined yearly. At yearend 1981, U.S. gas reserves stood at 201.7 tcf.
U.S. operators are conscious of the reserve decline, but not everyone is alarmed.
First, the U.S. for many years has maintained a sizable estimated gas resource base from which to prove up reserves.
Thomas E. Fisher, vice-president of natural gas marketing for Unocal Corp., points out that the Potential Gas Committee in 1968 estimated the U.S. gas resource base at about 1.6 quadrillion cu ft.
EIA figures show U.S. operators during 1968-91 marketed gas production of 470.2 tcf, while gross production from all wells totaled 545.5 tcf. Yet the estimated U.S. gas resource base remained steady at 1.6 quadrillion cu ft.
Proved reserves are less than 10 years ago. But Fisher says improved inventory management allows producers to supply markets from smaller reserves, thus avoiding some costs associated with maintaining large inventories.
"We have not replaced reserves in the past couple of years because we did not need previous reserve volumes to serve the markets," Fisher said.
He believes if the price of gas increases, more rigs will go to work drilling gas wells.
"Assuming they can find something, we'll have adequate supplies," he said. "Activity in Louisiana, Texas, Oklahoma, and Kansas really adds supplies."
At present rates of production, Unocal estimates about 600 rotary rigs drilling gas wells are needed to maintain U.S. reserves.
PRODUCTIVE CAPACITY
Reserves are not the only indicator affected by reduced drilling.
Because of low drilling activity, fewer gas well completions, and normal production declines, Petroleum Information Corp. (PI), Houston, late in 1992 concluded that U.S. gas productive capacity by yearend 1995 will fall to 15.5 tcf/year, 2.5 tcf less than at yearend 1991.
PI's study shows how production from new completions helps maintain total U.S. gas supplies by offsetting declining flow from older wells.
For example, gas wells completed in 1981 were producing at a rate of about 1 tcf/year at yearend 1981. Their production peaked in 1982 at 1.862 tcf/year, then began a steady decline to 1.454 tcf/year at yearend 1983 and to 486 bcf/year by yearend 1991.
However, PI data also show clearly that-because of the unusually low rates of drilling and completion activity-production from wells completed after 1990 has failed to offset normal production declines.
PI projects production from wells active at yearend 1991 will decrease about 14%/year to 8.6 tcf/year at the end of 1995 from 18.5 tcf. Meanwhile, discoveries from exploratory drilling, revisions, and other sources are expected to add 6.9 tcf to U.S. gas reserves.
In its recently released U.S. gas industry study, the National Petroleum Council estimates U.S. gas demand in 1995 will exceed 20 tcf. PI says the apparent impending shortfall of U.S. gas production by 1995 likely cannot be offset by imports.
PI calculates U.S. operators would have to drill 12,000-13,000 gas wells/year to halt the decline of deliverability. However, producers through July of last year had reported only slightly more than 2,300 new gas wells. Moreover, capital constraints and short supplies of drilling crews and other key field hands limit the U.S. industry's ability to ramp up drilling activity to any great degree.
In lieu of a substantial increase in drilling, PI says drilling patterns will have to skew toward more gas reservoirs.
John Butler, senior chairman of PI, said, "Significant declines in gas well completions and workover activity in 1991 and 1992 appear to have accelerated the reduction of the gas supply surplus that has prevailed in the U.S. since the early 1980s."
In fact, PI estimates if activity trends of 1989 had held steady through 1992, supply and demand would have crossed in the latter year. By compiling gas production histories of about 2.3 million wells included in its data base, PI concluded current shut-in gas productive capacity is negligible.
U.S. operators in 1989 completed 676 exploratory gas wells and reported about 10 tcf of total reserves added. In 1990, 645 exploratory gas wells were completed and 12.368 tcf of reserves added. However, operators in 1991 completed only 474 exploratory gas wells and discovered 7.542 tcf of reserves.
Last year, exploratory gas well completions through third quarter totaled 285. EIA next fall is to release 1992 additions to U.S. gas reserves.
GAS CONSUMPTION
Despite declining gas reserves and indications of dwindling productive capacity, U.S. gas consumption in 1992 continued increasing. NPC and EIA predict the trend likely will endure throughout the decade and into the 21st century.
U.S. end users through the first three quarters of 1992 consumed 14.462 tcf of gas, EIA reported, topping 1991 consumption for the same period by more than 3.8%. Year long U.S. gas consumption in 1992 is expected to total 20.1 tcf, the highest level since 1979. U.S. gas use in 1991 totaled almost 19.1 tcf, 5.91% more than in 1990.
EIA predicts U.S. gas demand in 1993 will increase 5.5% to 21.2 tcf, led by consumption in industrial and electric utility sectors. U.S. economic recovery could combine with a return to normal seasonal weather to boost residential and commercial gas use as well.
EIA's 1993 base case projection assumes U.S. real gross domestic product will grow 2.8% to $5.09 trillion, imported oil prices will increase 6.3% to $20/bbl, and gas wellhead prices will increase about 6% to $1.68/Mcf. With U.S. economic recovery gathering steam, total energy demand could increase by 2.1% this year to 84 quadrillion BTUs, following a 1.5% increase in 1992.
GROWTH MARKETS
Electrical power generation is considered one of the biggest potential U.S. markets for gas, However, the extent to which gas will retain power generation markets or capture new ones will be limited by competing fuels.
EIA says gas consumption by U.S. electric utilities in 1992 will reach 2.93 tcf, up 5% from 2.79 tcf in 1991. Utility gas consumption in 1993 is expected to grow another 5%.
Gas use among nonutility power producers (NPPs), including gas fired cogenerators and independent power generators, also is expected to increase. EIA says gas fired power plants in 1990 accounted for 46% of the 215 billion kw-hr of gross electricity generated by NPPs reporting 43 billion w of rated capacity. NPP expansions in 1991-93 are expected to add another 19 billion w of capacity.
Industrial end users in 1992 were expected to consume about 7.57 tcf of gas, up 4.3% from 7.24 tcf in 1991. EIA predicts industrial demand in 1993 will increase another 4.2% to 7.88 tcf.
EIA says U.S. residential end users in 1993 will consume about 4.93 tcf of gas, up more than 6% from 1992 consumption. Commercial customers in 1993 are expected to use 2.79 tcf of gas, about a 2.95% increase over 1992.
STATUS OF SUPPLIES
According to EIA, U.S. 1992 gas supplies from all sources through the third quarter totaled 16.695 tcf, up 3.34% from 1991. Among supply sources, only withdrawals from storage trailed the pace of the previous year.
EIA says the effect of Hurricane Andrew on most gas wells in the Gulf of Mexico's central planning area was short lived. Most gulf gas production temporarily disrupted by Andrew was replaced by onshore production.
Through September, U.S. dry gas production in 1992 increased by about 1.9% to 13.31 tcf, while imports, mainly from Canada, totaled 1.54 tcf, an increase of more than 21.6%. Supplies increased despite decisions by many U.S. operators in March 1992 to curtail production of gas wells after spot prices slid to an average $1/Mcf.
U.S. gas imports in 1993 are expected to increase 9.8% to about 2.3 tcf, with most coming from Canada. Canadian gas export pipeline capacity during 1992 increased to nearly 2.52 tcf/year.
EIA logged 1.773 tcf of gas withdrawals from underground storage during the first 9 months of 1992, about 56 bcf less than during the same period of 1991. Meanwhile, additions to storage through September totaled 2.067 tcf, 73 bcf less than 1991's 9 month total. Net additions to storage for the first three quarters of 1992 totaled about 294 bcf, off about 5.5% from a year earlier.
The American Gas Association estimates total U.S. underground storage capacity is 7.84 tcf. AGA calculated 2.71 tcf of working gas in storage at yearend 1991 and maximum single day withdrawal capacity of 39.5 bcf.
However, as recently as 1988 operators were able to withdraw more than 55 bcfd from essentially the same number of storage caverns. So if U.S. gas production declines by 1995 as PI expects, withdrawals from storage, which already provide gas during months of peak demand, could be called upon to make up some of the difference, even if more injection/withdrawal wells are needed.
NPC GAS OUTLOOK
NPC in its exhaustive 2 year study of the U.S. gas industry concluded gas supplies are abundant and can make a greater contribution to U.S. energy and environmental needs. But work still is needed to make the industry more competitive and responsive to customer needs (OGJ, Dec. 28, 1992, p. 106).
NPC constructed two hypothetical scenarios to assess gas growth opportunities, economic potential of satisfying gas demand through 2010, capability of transmission and storage infrastructure to serve domestic markets, and how the regulatory environment affects gas industry operations.
Under the moderate energy demand growth scenario, NPC estimates U.S. gas prices by 2010 will increase gradually to $3.50/Mcf in 1990 dollars with supply, transportation, and demand in economic balance. Consumption by 2010 by residential, commercial, industrial, and electric utility customers total 22.7 tcf, nearly one-third more than in 1990.
With low energy demand growth, NPC says gas prices by 2010 could increase to about $2.75/Mcf, also in 1990 dollars, and combined end use consumption could increase only slightly to 18.8 tcf. In the latter case, consumption by industrial customers will slip by 2010 to 6.1 tcf, down from 7 tcf in 1990. The effect of lower demand growth will flow in part from more aggressive conservation measures.
In NPC's reference cases, penetration of compressed natural gas (CNG) vehicles will create consumption of 140 bcf/year by 2010. Even with consumption as high as 640 bcf by 2010 under more optimistic circumstances, the U.S. gas industry appears able to supply CNG vehicles without slighting other markets.
NPC recommends federal, state, and local officials promote competition on U.S. gas markets by supporting policies and regulations that foster consumer choice and reduce regulatory uncertainty and by opposing policies that unduly increase delivered gas costs.
To assure emerging competitive gas markets function appropriately, NPC also said U.S. gas industry participants should:
- Speed development of technologies and procedures that reduce delivered gas costs, including new end use technologies.
- Develop new strategies to deal with environmental issues.
- Improve reliability of supply and delivery systems.
- Increase the customer focus of marketing strategies.
KEY CHALLENGES
NPC says expansion of value added transportation and storage services as the gas industry prepares to operate under FERC Order 636 confirms the new competitiveness of U.S. markets. But as the gas industry moves to increase its role in meeting future U.S. energy and environmental needs, questions remain about gas reliability and the industry's sensitivity to customer needs.
Most doubt about supply reliability arises from customer perceptions of gas curtailments in the 1970s and during an extraordinarily cold period late in 1989. Doubt is compounded by moratoriums barring oil and gas development on much of the most promising offshore federal acreage.
However, Bruce Henning, chief AGA economist, says the association expects gas supplies to be adequate on U.S. markets through 2010.
Speaking at a Smith Barney gas conference in Houston last month, Henning said AGA calculates future peak U.S. gas deliverability of more than 2.4 tcf/month, including withdrawals from storage, stabilization of U.S. production, and increasing Canadian exports into the U.S.
"That exceeds the amount of projected gas demand in any given month and would exceed on a nationwide basis what is likely to be demanded, even in the coldest month in 50 years," he said.
Henning acknowledged AGA's estimate of deliverability does not mean localized, short term transportation problems are impossible. But such problems are less likely than before the U.S. gas markets began evolving toward increased competition.
"When you consider what the industry has done to reduce the problems that were associated with December 1989, you find that there has been significant debottlenecking and significant attention paid in the field to handling well freezeups," he said. "Plus, we have more experience working under an open access transportation system."
GROWTH UNDER 636
Henning and most other gas industry officials say most utilities, pipelines, end users, and producers have embraced FERC Order 636 as a way to gain market share during the next 1020 years because of the choices it allows consumers and the flexibility it affords providers of valued added services.
Henning said allowing customers to choose among transparently priced supplies and services will limit a company's ability to cross-subsidize services. As a result, market responsive pricing will push through the gas industry, while remaining regulations cap undue market power.
"All services-pipeline capacity, storage capacity, charges from new ventures working as aggregators or marketers-will have to stand on their own because of unbundling," he said. "Services will have to be priced reasonably or customers will not want them."
Charles L. Watson, NGC chairman, chief executive officer, and president, does not expect Order 636 this winter to cause significant deliverability problems "under almost any scenario."
He said, "Any reference to deliverability problems this winter because of Order 636 are premature. But to the extent anything happens, I'm confident some people will say it was because of Order 636.
"But it's not in place yet and at the rate we're going it might not be next winter."
INDUSTRY REALIGNMENT
GC expects considerable gas industry realignment to occur as players assess new opportunities created by 636.
Major to intermediate size gas producers choosing to become gas marketers and supply aggregators likely will acquire small niche gas marketing companies that can fulfill an aggregating function to support a full range of marketing services.
Companies not wanting to function as aggregator/merchants likely will sell gas gathering systems and processing plants.
"Not every producer wants to be an aggregator," Watson said.
In addition, each U.S. gas storage site conceivably could be considered a profitable acquisition by companies that think they could add value to the installation or the facility could add value to their operations of whatever type. "I think we're going to truly learn the value of peak day storage," Watson said.
NGC has been investing in nonjurisdictional gathering systems and processing plants as well as gas reserves because gas handling facilities with dedicated producing reserves can be more valuable than the reserves themselves.
"Every dollar I spend in a plant that has a specific volume of gas committed to it that is available for us to market is a whole lot better than buying reserves," he said.
Watson and Jeff Skilling, chairman and chief executive officer of Enron Gas Services, Houston, say Order 636 will lead to creation of more and better transportation and storage services and to emergence in the 1990s of a few very large gas marketing companies.
Both also say development of long term contracts are critical to full development of a competitive U.S. gas industry.
"Long term contracts are going to be a key part of the product and service offerings of our industry in the future," Skilling said. "That's going to be a big piece of the value added with the new merchant functions."
In the past 3-4 years, gas sold through short term contracts has grown to account for about 80% of the volumes on U.S. gas markets. But Watson said a share of U.S. gas markets could be recaptured by merchants in any gas industry segment willing to buy or sell gas under long term contracts.
"Going back to more long term contracts and relationships can only help our ability to outperform alternative fuels in the future," he said.
NEED FOR CAPITAL
An important adjunct to long term contracts will be financial instruments and rebundled merchant services that allow parties to lay off some commodity risk by assuring supply and pricing security. Skilling said reducing risks to investors is the only way to attract the capital needed to bring potential gas supplies to market.
"To make potential gas real supplies, we have to invest literally tens of billions of dollars in exploration and production and tens of billions of dollars in new gas consuming facilities for gas," he said. "We have to let people considering investing in a gas consuming facility know the gas will be there and will be economic."
Enron estimates producers have to invest a little more than $11 for each Mcf of annual production, interstate pipelines spend about $1 for each Mcf of annual transportation capacity, and distribution companies spend about $7 for each Mcf of gas handled annually.
Altogether, Enron estimates participants in the U.S. gas industry will have to invest about $75 billion in the next 7 years "if we expect the industry to grow."
Skilling said, "And that says nothing about capital requirements needed just to maintain existing supplies and demand infrastructure. If we intend to get the money we need, we've got to change the way we do business and take some of this 30 day pricing volatility out of the system.
"The solution in our view is long term, known price gas supply commitments."
COST OF SPECULATING
Enron is beginning to see significant interest among independent producers in long term contracts with indexed price provisions. But so many producers are unwilling to sign long term, fixed price contracts, NGC has coined a term for it: "the Texas hedge."
"A Texas hedge means you're long all the time," Skilling said.
What many producers don't realize is the price they pay for the right to speculate on future spot prices.
"Most independent U.S. producers are capitalized at a 60% equity ratio to get any kind of legitimacy to their balance sheet," Skilling said. "But 60% equity with an asset in the ground that can be hedged is ludicrous."
Instead, he advised independents to enter into a hedging structure that includes a long term, fixed price contract that can be capitalized with an off balance sheet financial vehicle allowing project financing at 80% debt.
"A company can cut capital costs by upwards of 300 basis points just by moving to more predictable cash flows against that asset base," he said. "So essentially, a producer is paying upwards of 300 basis points for the opportunity to take a chance on what future gas prices will be."
As off balance sheet financial instruments become more available and producers calculate what it is costing to speculate on gas prices, banks and other lenders will be less likely to allow the risk.
As a result, "it will become absolutely imperative for the exploration and production business to get out of the speculation business because it is too expensive," Skilling said.
"This is an incredibly volatile price environment, and banks and equity investors aren't going to stand for producers throwing the dice every winter."
Copyright 1993 Oil & Gas Journal. All Rights Reserved.
