A warm winter in most of North America and capacity limitations on export pipelines to U.S. markets have added to industry problems.
The retrenchment from strong prices in 1993 and 1994 has spawned some shut-ins, project delays, a decline in lease sales and a second look at capital budgets by a number of firms.
Industry analysts generally concur that the soft price scenario afflicting North American-and particularly Canadian-gas producers is part of a normal cycle in a highly competitive commodity market.
RECENT DRILLING SURGE
A steady increase in prices for Canadian gas beginning in mid-1992 spurred exploration and development. Much of the drilling was for shallow, sweet gas within easy reach of pipelines.
Since then, investors have pumped about $8-9 billion (Canadian) into the coffers of gas producers. During 1994, Canadian producers drilled the largest number of gas directed wells in industry history Gas completions last year totaled 5,369, up 66% from 3,239 in 1993 and far more than the previous record of 4,472 completions in 1980.
In its 1994 reserves report, Alberta Energy and Utilities Board says 1994 was one of the most active years in a decade for gas producers.
The number of exploratory wells drilled in Canada last year hit the highest level since 1980 and was 83%, more than 1993. Development drilling was at record levels in 1994, exceeding 3,000 wells for the first time and topping 1993 by 74%.
The board said much of the development work was for increasing gas deliverability in producing reservoirs, which would not typically add to gas reserves.
A total 2.6 tcf was added to Alberta reserves in 1994, replacing 62% of production of 4.2 tcf for a net reserves decline of 1.6 tcf. Remaining gas reserves at yearend 1994 were estimated at 52.9 tcf.
SUPPLY GLUT OUTLOOK
There are differing views on how long the supply glut will last, with estimates of 6-18 months. A cold winter could bring a turnaround.
Dennis Prince, a gas manager for the Canadian Association of Petroleum Producers (CAPP), says some industry analysts believe the current surplus will decline soon and supply/demand will be back in balance within a year.
Prince says individual companies are responding differently to the current situation with some continuing to pursue strong drilling plans this year.
As to the effect on the market of campaigns by environmentalists in U.S. gas markets, Prince says environmental groups such as Greenpeace have been aggressive with rhetoric but have had no effect on flowing gas or deals being made. He says the burden is on industry to explain that there are effective environmental controls in place in western Canada and that the industry operates within them.
Don Herring, managing director of the Canadian Association of Oilwell Drilling Contractors (Caodc) says the association expects overall drilling will fall about 14% overall from record 1994 levels, but gas drilling may be down as much as 30%. He says Caodc projects 10,165 wells will be drilled in Canada this year, broken out as 4,200 oil, 3,800 gas, and 2,165 dry holes.
Herring says the current gas surplus is not huge-he estimates 3%-and active operators such as Calgary's Renaissance Energy are going ahead with strong drilling programs. But he contends the gas market is still pretty thin, with Caodc predicting an average price of $1.45/Mcf this year.
Calgary analyst Ziff Energy Group says the outlook for Canadian gas in the short term is less optimistic than when Ziff forecast in early 1992 in a similar low price market that prices would rise later that year, which they did.
PIPELINE CAPACITY CONCERNS
Pipeline capacity limitations are another concern for gas industry executives at the moment.
Ken Vollman, vice-chairman of the National Energy Board, told a recent gas transportation seminar that producers will not get early relief from any major new pipeline construction to U.S. markets. Vollman said existing lines will increase capacity gradually.
He contends there is a good case for moderate expansion, but companies will have to find new ways of paying for the high long term costs of adding lines. The problem of financing large pipeline projects has been made more difficult by deregulation and the decline of long term sales contracts in favor of spot sales.
Myron Kanik, president of the Canadian Energy Pipeline Association, says Canadian producers need more pipeline capacity to export markets.
The question now being considered in boardrooms and on the street , he says, is whether that capacity should be added in small tranches of 150 to 200 MMcfd in several projects or in one large pipeline such as the Altamont line, which would add 700 MMcfd to markets in the U.S. Southwest.
Kanik cites industry arguments for both options and thinks shippers and pipeline companies likely will come to a consensus by fall.
NOVA, which operates the main line gas systems for connection to export points, is making some adjustments on its expansion program to meet producer requests. The company will make modest cuts in capital spending in 1995-96 and increase outlays for 1997.
NOVA says drilling and rig bookings remain fairly strong and thinks the long term outlook for gas demand remains good.
PIPELINE CONSTRAINTS
Ziff says increased export pipeline capacity will not occur for several years and may be more modest in scope than earlier expansions to the U.S. Northeast and the California/Pacific Northwest markets. Some producers may delay start-up of new facilities tied to the NOVA Corp. gas pipeline network in Alberta to export points.
NOVA began recommending price hedging to clients in second quarter 1994 based on the high gas price relative to full cycle economics for gas in Canada.
"The price was exceeded, and drilling in the third quarter was going for the stratosphere. It was clear that the high prices wouldn't hold," Ziff Energy Pres. Paul Ziff said.
Ziff notes that contracts between producers and Canadian distributors will be renegotiated this fall, and prices will be determined largely by what producers do. He says the most significant question is how much drilling will be done this year. No one expects the record drilling totals of 1994, Ziff notes, but there was no steep decline in drilling in the first 4 months, although that period includes the active winter drilling season.
Ziff says it is difficult to get a handle on how much shut-in gas there is in the market because there is a blurred area between shut-ins and deferred development projects, and companies aren't always forthcoming with information in this area.
The analyst says a big problem for producers is the recline in long term gas sales contracts in favor of short term spot market sales. A major challenge now is determining who will commit to pay for pipeline tolls for 30 years to build new pipelines.
Brent Friedenberg, president of Brent Friedenberg Associates Ltd., Calgary, contends that in the long term industry should not expect gas prices to rise at a rate above the rate of inflation and probably less than that. He says commodities are now subject to an underlying abundance due in large part to technological advances on the supply side.
"Canadian gas prices have fallen proportionately more than gas prices in the U.S. This is due to the tendency for Canadian supply growth to exceed pipeline takeaway capability," he said.
"Even though the relatively large Pacific Gas Transmission Ltd. expansion (from Alberta to California) was just completed in November 1993, Alberta producers are again finding themselves in a situation where the limited ex-Alberta pipeline capacity is causing a buildup of supply in the province. The result has been a partial delinking of Alberta gas prices from other gas prices in North America."
PIPELINE EXPANSION RISKS
Friedenberg says prospects for Canadian producers of any expansion to the U.S. market is good, but there is a problem for the industry generally and particularly in Canada on how to proceed with pipeline expansions.
"Shippers signing on for new capacity face considerable risk that their fixed monthly demand charges will be greater than the value of the capacity over the long-term life of the contract (at least 15 years). But, once built, new capacity will be used as long as shippers are at least recovering their relatively minor variable costs," he said.
"From the producers' perspective they can only benefit from an expansion, since it means more demand for their gas. But to ask them to sign on for at least 15 years carries considerable risk. The market needs to be improved for those willing to take that risk."
Friedenberg notes there is now no price cap on the value of transportation in the secondary capacity market. He says shippers taking the risk of signing on for new pipeline space should be able to market this space in the secondary market at prices above regulated tolls.
He says analysts are correct in forecasting steady demand growth for gas and contends that growth will increase at a rate close to the growth rate of the economy as a whole. But producers must recognize that the long-term price trend is for little or no real growth in gas prices, at best keeping pace with general inflation rates.
EXPANSION PROJECTS
There are a number of pipeline expansion projects planned or on the drawing board that would increase total pipeline capacity by about 1.6 bcfd to 12.08 bcfd by November 1998 if they all materialize. Among them:
- TransCanada PipeLines Ltd., Calgary, plans to increase its 5.9 bcfd mainline capacity by 100 MMcfd by November 1996. The company will also participate in expansion of the Iroquois line to the U.S. Northeast from 750 MMcfd to 1.05 bcfd by November 1997 or 1998.
- Foothills Pipelines Ltd., Calgary, plans to add 200 MMcfd by 1997/98 to its 1,500 MMcfd Northern Border pipeline system.
- Alberta Natural Gas Ltd. and Pacific Gas Transmission Ltd. are considering adding 300 MMcfd to the 2.3 bcfd capacity of the pipeline system to the Pacific Northwest and California. PGT recently polled Canadian producers on their need for additional capacity on the Alberta-California system. PGT Vice Pres. Paula Rosput said the company has no preconceived ideas about the size, scope, or rates for an expansion. She said the company could add as much as 400 MMcfd additional capacity by November 1997 to its current 2.4 bcfd capacity at the Idaho-British Columbia border. PGT says its line often experienced a load factor of more than 100% last winter, and it foresees growing demand for Canadian gas in the Pacific Northwest, Nevada, and California.
- The Altamont Gas Transmission Co. project to deliver Canadian gas via Wyoming to California and elsewhere in the U.S. West is another potential expansion project. The $637 million U.S. leg would run about 621 miles from Wild Horse, Alta., to Opal, Wyo. Foothills would build a 133 mile Canadian leg connecting with the NOVA system in Alberta. The Altamont line would add 730 MMcfd export capacity in 1997. Altamont says Canadian producers need the added capacity to increase their share of the U.S. market. Planned capacity was originally fully booked for November 1996, but producers have dropped bookings for about 200 MMcfd, which Altamont is now remarketing. Several industry observers expressed doubts on the feasibility of Altamont, based on questions about end markets for the gas and the favorable economics of adding compression to existing lines versus the cost of installing new pipeline.
Canadian Natural Gas Exports chart (53257 bytes)
1995 OUTLOOK
The Petroleum Services Association of Canada (PSAC) said in May that industry drilling expenditures will fall by about $600 million this year from 1994, and drilling activity will drop by 19% from last year.
PSAC estimates 9,500 wells will be drilled this year, down by 2,250 from the 1994 record level of 11,750. That still is considerably more than the 10 year industry average of 7,700 wells/year.
The biggest decline will be in natural gas drilling activity, a 30% drop to 3,637 wells from last year's record level. PSAC said, however, that drilling activity will remain strong in Northeast British Columbia and in the Alberta foothills, where targets are deep gas.
Petroleum land sales, another indicator of industry activity, began declining earlier this year after more than 18 months of strong buying activity.
David Coombs, director of minerals disposition for Alberta Energy, said land sales in that province have fallen off drastically British Columbia and Saskatchewan also reported a decline in demand for exploration lands.
Average prices at sales in Alberta fell by 50% from $494/acre to about $247/acre earlier this year. The province is forecasting a decline in revenues from $935 million in fiscal 199495 to about $400 million in fiscal 1995-96. Weak gas prices are seen as a major factor in the decline.
Most industry analysts expect the current price situation will extend for 18 months to 2 years, with wellhead prices well below top values recorded in 1994.
Natural Resources Canada (NRC), in an update on North American gas supply trends, expects continued volatility and uncertainty in gas prices through 1995 and 1996.
NRC said the current gas bubble will gradually dissipate the next 2 years with a better balance between reserves and production. The federal department said the market situation has changed drastically since 1993, with increased drilling activity and storage capacity bringing more supply onto the market from western Canada, the U.S. Rockies, and New Mexico.
The department said reserves in these areas are still underutilized despite having captured 95% of market growth in the 1990s. It said the industry is still in a position to meet higher gas demand, "even at prices that don't encourage replacement of reserves."
NRC said continuing production increases with declining reserves is obviously unsustainable in the long run, and Canada and the U.S. must increase gas drilling to reverse the decline. That, the report said, will require higher prices or major advances in technology to reduce costs.
PRICE FORECASTS
Current forecasts call for prices for Alberta gas to all markets this year to average about $1.20-1.50/Mcf.
Peter Linder, an analyst with BZW Canada Inc., Calgary, sees prices at $1.20-1.50/Mcf, depending on the market sold into, and an average $1.351.45/Mcf. He predicts spot market prices will be about $1/Mcf level this summer. Linder expects continued price weakness in 1996 for Canadian gas, with average prices no higher than $1.50/Mcf.
Paul Mortensen, senior gas analyst with Canadian Energy Research Institute, Calgary, forecasts an average price of $1.45/Mcf in 1995 and $1.55/Mcf in 1996. The CERI forecast is based on a 20 year model that examines relative supply costs in various basins in North America, transportation costs, and competition from alternative fuels.
A survey released in May by Arthur Andersen, Calgary, found uncertainty over gas prices to be the major issue for the heads of 77 oil and gas companies surveyed.
"Gas prices are expected to remain at approximately $1.25/Mcf at the wellhead, share prices are expected to trade below 1993 and 1994 levels, increases in exploration and development spending will be less pervasive, and employment levels are expected to decline," Arthur Andersen said.
However, the Arthur Andersen survey found industry optimistic in the medium term with executives expecting gas demand to increase 2-4%/year to 1999.
SHUT-INS, 1995 E&P PLANS
There are no precise figures available on the levels of shut-in gas in Western Canada. But a number of companies have held gas off the spot market and put it in storage or deferred development this year.
Anderson Exploration Ltd., one of the most active gas explorers in 1994, is cutting back on capital spending by about $30 million to $165 million and will take a more cautious approach to gas development.
Chairman J.C. Anderson said two or three projects will be deferred, not because they are uneconomic, but because the company wants to conserve some of its credit capacity. It is considering a potential purchase or a takeover. Anderson expects gas prices to stay low until next winter. He says the surplus is not that big, and low prices should reduce drilling in Canada and the U.S.
Home Oil Ltd. pulled 15% of its 260 MMcfd production off the market this year in response to weak prices. The company said netbacks from some fields had fallen below acceptable levels. Home said some gas would be shut in at the wellhead and some held in storage. It blamed a 32% decline in gas prices for a first quarter loss and a staff cut.
Alberta Energy Co. Ltd., another large producer, will sell gas only where it has transportation and contractual arrangements to get it outside of Alberta into higher value markets. The company said if weak prices continue in 1995, it would shut in as much as 13% of production, or 50 MMcfd. It also plans to cut 1995 capital spending by $30 million to $300 million as a response to weak prices.
Norcen Energy Resources Ltd., Renaissance Energy Ltd., and Discovery West Corp. also shut in some production.
However, PanCanadian Petroleum Ltd., one of the largest independents, says it plans to drill about 1,200 wells this year, split about evenly between oil and gas targets. The company will spend about $870 million on exploration this year. Despite low prices, the company bought additional export capacity in 1994 and increased its space to 200 MMcfd from 50 MMcfd.
Renaissance shut in 60-70 MMcfd of gas in the first quarter, and its average production fell to 360 MMcfd from 365 MMcfd compared with same period in 1994. The most active driller, it plans to increase drilling activity in western Canada to 1,400 wells from 1,200 in 1994.
The company plans to cut capital spending by about $260 million to $500 million, partly because it invested heavily in 1994 to double its undeveloped leasehold. Renaissance expects some price recovery for gas this fall and plans to split its drilling program between oil and gas. Renaissance Chairman Clayton Woitas forecasts an average gas price of $1.50/Mcf and a turnaround from weak gas prices within 6-18 months, with recovery coming first in the U.S.
Canadian Hunter Exploration Ltd., another big independent, said low gas prices forced staff cuts and a reduction in capital spending. The company shut in 60 MMcfd, or about 20% of production. Pres. Jim Gray said the company would not sell gas at what it considers distressed prices and forecast that weak prices will continue well into 1996. Gray said there is a possibility of a decline in gas production from the Gulf of Mexico, and Canadian producers could fill the gap. But he said that forecast is simply a best estimate.
The current market situation has caused investors to shy away from energy issues and caused financing problems for some juniors, particularly companies that borrowed to finance big gas development programs.
Arthur Korpach, vice-president of Wood Goody Inc., told a CERI gas conference some companies are at their bank borrowing limits. He said individual investors have deserted the industry.
Korpach estimated $5.7 billion was raised in equity in 1993 and $2.7 billion in 1994. He said investors now will be attracted only to companies with strong assets and management.
Richard Thomson, chairman of the Toronto-Dominion Bank, one of Canada's largest, expects to see heavy takeover activity in the oil and gas industry in the next few months. He said there will be consolidation because it will be cheaper to buy a company than develop a field.
WHAT PRODUCERS CAN DO
Friedenberg says there are a number of steps producers can take to deal with the situation:
- Recognize that there is a multiyear price cycle and plan exploration and development for long-term price trend and less to the shorter term price cycle.
- Keep up with technological changes in the industry and keep costs to a minimum.
- Use the futures market to lock in prices on at least part of a company's production.
Companies have been reacting to the changing market since last summer, when early
warnings were sounded of a possible gas glut and weakening prices.
CERI warned in May 1994 that the rapid increase in drilling could boost gas production by 50% the next 3 years and create a supply glut.
CERI's Mortensen noted then that Canadian producers supply 11% of U.S. gas needs. CERI predicted deliverability of 4.9 tcf in 1992 could grow to 7.3 tcf by 1997 and outstrip demand at the pace new gas was being added.
The CERI report warned Canadian domestic demand would not grow fast enough to absorb the extra production. It said Canadian producers need to increase export pipeline capacity of about 2.8 tcf/year and must compete aggressively with U.S. producers for a larger share of the U.S. market.
The study was based on a survey of 55 companies that accounted for more than two-thirds of Canadian gas output in 1992. When the report was released in 1994, companies expected to increase investment in gas production to $4 billion/year by 1997.
Copyright 1995 Oil & Gas Journal. All Rights Reserved.
