Headline: Supply crisis looms
Source: Petroleum Economist
Date: July 2003
Author: WJ Simpson
US demand for natural gas is rising fast, driven by the power generation sector. But with storage levels at their lowest since records began and a declining reserves to production ratio in Canada, the US’ main supplier, short- and long-term solutions are needed. WJ Simpson reports
NATURAL GAS is receiving unprecedented attention in North America, as governments and industry scramble for short-term solutions to a potent combination of tightening supplies and relentless demand for power generation.
The US Federal Reserve’s chairman, Alan Greenspan, stirred the debate when he told a committee of Congress in May that he was “quite surprised at how little attention the natural gas problem has been getting, because it is a very serious problem”. He warned that intensifying competition between utilities and storage operators means “something has to give and what is giving is price”, as futures prices climbed above $6/m Btu (see Figure 3).
The US energy secretary, Spencer Abraham, faced with the lowest US storage levels since record-keeping started in 1976, reinforced the grim outlook in May when he asked the National Petroleum Council, his privately funded advisory committee, to develop some quick answers.
Prospects for LNG
Abraham wants a detailed analysis of factors bearing on supply and demand, with a heavy emphasis on: North American output; prospects for liquefied natural gas (LNG) imports for arctic developments; changes to regulatory and environmental rules; demand outlook in the power-generation sector; the potential for fuel switching; and a review of storage and distribution infrastructure.
He has emphasised that the Department of Energy and other federal agencies must move quickly to ease “short-term supply constraints”. If storage is to rise from 1 trillion cubic feet (cf) to between 3 trillion and 3.5 trillion cf by the start of the new contract year, in November, injections must rise above the usual weekly average of 60bn cf, he said.
Added impetus has come from the chairmen of North America’s three leading energy regulators. At a Calgary meeting in May, Pat Wood, of the US Federal Energy Regulatory Commission, Ken Vollman, of Canada’s National Energy Board (NEB), and Dionisio Perez-Jacome, of Mexico’s Comisión Reguladora de Energía, agreed to collaborate on a joint approach to accelerate development of major supply projects, notably LNG and the Arctic.
Abraham said he is confident the US can meet gas-supply challenges, just as it emerged relatively unscathed from international events that created “extremely stressed” oil markets earlier this year.
The nub of the problem, identified by the Canadian Gas Potential Committee (CGPC), is that North America has just 5% of the world’s supply and 31% of world output, which means it is rapidly depleting its easily accessible, conventional reserves. (Canada’s reserves-to-production ratio has tumbled from 27.4 in 1986 to under 9.0.)
Figure 1: US – gas reserves and output
A new study by the American Gas Association forecasts US demand could rise from 24 trillion cf in 2002 to as high as 32 trillion cf in 2020. Gas-fired power generation is forecast to account for 33% of gas demand by 2010, up from 13% in 2001.
But neither LNG nor the Arctic can speedily head off lagging deliverability, which Oklahoma-based Samson Investment predicts will decline in real terms this year by 3-5% in the US and 2-3% in Canada.
Samson’s chief executive officer, Jack Schanck, says the number of rigs hunting for gas would need to increase from 750 to 900 just to maintain production. His best hope for a solution to the supply problem is a shift to tight gas, which usually requires some form of artificial stimulation to produce, but could contribute 400-500 trillion cf of reserves in North America.
Thomas Driscoll, of Lehman Brothers, says LNG – despite 18 new proposals for US import terminals and another four for Mexico’s Baja California – will make only steady gains from 1% of US domestic supply to 5% in 2006 and possibly 10% in 2010, over a period when US consumption is forecast to grow from 22 trillion cf/y to 30 trillion cf/y.
However, a levelling of gas
prices above $5/m Btu is removing a deterrent to the billions of dollars
of capital investment needed to make LNG a vital part of the supply mix,
says analyst Kevin Petak, a director at the Washington, consulting firm,
Energy and Environmental Analysis.
The long-held dream of opening the Arctic to commercial output is an
uncertain proposition. Both US and Canadian gas producers concede that
Canada’s Mackenzie Delta will be first, coming on stream no earlier than
2008 at a cost of about C$4bn ($2.9bn) and delivering 1.0bn-1.5bn cf/d.
Progress on exploiting Alaska’s North Slope, with proved reserves of 35 trillion cf in a state said to hold 237 trillion cf, is bogged down in a contentious political debate. There have been US Senate attempts to win over President George Bush and introduce a guaranteed price floor of $3.25/m Btu to encourage building a $20bn pipeline and start delivering 4bn cf/d between 2010 and 2020.
The extent to which the US can count on Canada to help bridge the supply/demand gap is a growing concern on both sides of the border, especially as Canada has advanced from being a marginal source in the mid-1980s to a critical component at 15% of the US market.
Both the NEB and the Canadian Energy Research Institute have warned the US against taking for granted further growth in Canadian supplies, especially if the US Energy Information Administration is accurate in its forecast that the US is counting on gas imports from Canada to rise to 5.5 trillion cf/y in 2020 from 3.7 trillion cf/y.
A huge undertaking
Investment firm FirstEnergy Capital says a 50% jump in Canadian exports to 15bn cf/d by 2020 – almost matching today’s output for domestic and export markets combined – is a huge undertaking.
New discoveries in the maturing Western Canada Sedimentary Basin (WCSB) are getting smaller and initial decline rates are three times what they were in 1990 – even though drilling has soared over the last decade to an expected 11,500 gas wells this year from 4,000 in 1990. For this year alone, FirstEnergy projects a decline of 5-6%, or 1bn cf/d, in WCSB production, about 60% of which is exported.
The CGPC, although certain the WCSB will continue to be the mainstay of Canada’s gas supply at about 95%, says 200,000 exploration wells (double the number drilled to date) will be needed to tap an undiscovered potential of 142 trillion cf including established reserves of about 55 trillion cf. But even then, 43 trillion cf is locked in reservoirs that are particularly sensitive to economics because of the small size of the pools, while 25 trillion cf is in high-cost, high-risk deep plays, the CGPC says.
Driscoll echoes that view, arguing that rising costs will probably continue to plague the industry as it struggles to offset production declines in the WCSB, where average reserves per well are less than 25% of the 1995 average. He says a 45% decline in initial well productivity since 1995 “is typical of a maturing basin and is a troubling signal”.
Compounding the anxieties are
soaring upstream costs. John S Herold, the energy research firm, says
finding and development costs in Canada jumped by 56% in 2001 from a
three-year average to $12.12 per barrel of oil equivalent, a “sub-par
investment return” that could undermine Canada’s ability to attract
significant exploration capital.
Matthew Simmons, chairman and chief executive officer of the energy
banking firm, Simmons & Company International, notes that Canadian
exports dropped in 2002 for the first time in 14 years, part of what he
describes as a “scary” trend. He claims that unless the US can raise
its supply to 80bn cf/d by 2010, from 60bn cf/d, it will be unable to
increase electricity generation, with dire consequences for the industrial
sector.
Need for drilling Vollman says the implication of these trends is a “heightened need for drilling”. While the remaining potential of the WCSB is significant, all signs indicate the industry will “need to work harder to maintain production in the future and even harder to increase it”. He says a new supply/demand report being prepared by the NEB will project that the WCSB will roughly hold its own at about 16 bn cf/d until 2010, then fade to 7.5bn cf/d by 2025.
As the WCSB ages, exploration and production firms are setting their sights on more distant horizons and unconventional sources, such as the Arctic and coal-bed methane (CBM), which Vollman estimates will meet more than half of Canada’s needs by 2025.
The Mackenzie Delta has only 6 trillion cf of established reserves from its three anchor fields and 9.2 trillion cf in NEB export licences from the 1980s. But the combined northern storehouse is estimated at 17 trillion cf in the mainland Northwest Territories and Yukon, 64 trillion cf in the Mackenzie Delta-Beaufort Sea and 94 trillion cf in the Arctic Islands, most of it far removed from any exploration, let alone pipeline planning.
Although Delta exploration is at its highest level in more than 20 years, with two discoveries in the last year, most leaseholders are awaiting a regulatory filing by the Delta gas owners – Imperial Oil, Shell Canada, ConocoPhillips Canada and ExxonMobil Canada – for a Mackenzie Valley pipeline. The decision hinges on the ability of Northwest Territories aboriginals to raise financing and secure one-third ownership of the line.
Driscoll predicts LNG imports will rise from 1% of US domestic supply to 5% in 2006 and possibly 10% in 2010. If all 18 LNG projects go ahead, it has been suggested LNG could contribute 9bn cf/d in three years’ time.
In Canada, the NEB has forecast that CBM development, which lags far behind the US while local governments develop regulatory regimes, could grow 10-fold to 3,000 wells a year by 2025 and produce 4bn cf/d. Provided Canadian CBM producers can learn from the experience of their US counterparts, Lemmens says Canada has access to at least 146 trillion cf of CBM and possibly 600 trillion cf, compared with 60 trillion cf in the US.
But so far, despite spending of C$100m on CBM development last year by EnCana, Nexen, Talisman Energy, Devon Energy and Penn West Petroleum, commercial CBM production in Canada remains in its infancy.
Figure 2: Canada – gas reserves and output
EnCana and Texas’ Quicksilver Resources ended a two-year joint venture this year after drilling 175 wells. Quicksilver is still targeting modest production of 15m cf/d by 2004, but EnCana, surprised at the high cost of the project, has walked away.
Instead, EnCana is turning its attention to northeastern British Columbia’s Greater Sierra field, Canada’s hottest gas play, with potential reserves of 5 trillion cf. Having quietly assembled 2.24m acres, the Calgary-based independent, backed by new government royalty credits, plans year-round drilling to achieve 300m cf/d by 2005.
With control of the region, EnCana aims to avoid mistakes made at the Ladyfern field, where a race for quick profits by the owners – EnCana, Canadian Natural Resources, Murphy Oil and Apache – is expected to wipe out a reservoir, which produced 0.7bn cf/d last year, by the end of 2004.
Dismal drilling results
Off Canada’s east coast, years of bullish optimism have given way to dismal drilling results, with dry holes costing about C$0.6bn, high-profile failures by ChevronTexaco and Shell Canada, and hefty reserves write-downs for the discovered Sable and Deep Panuke fields.
Offshore Nova Scotia, part of a region estimated to hold 78 trillion cf, has long been viewed as a key source of supply for US northeast markets – Ziff Energy Group predicts output of 2bn cf/d by 2010.
Instead, the single producing field at Sable has seen its 31.3% owner Shell Canada cut its estimate of its share of reserves to 0.7bn from 1.1 trillion cf. Also first-quarter volumes dropped to 458m cf/d from 0.53bn cf/d a year earlier, prompting Ian Doig, an independent analyst, to suggest Sable could be drained in less than half its projected 25-year lifespan.
Now hopes are pinned on an exploration breakthrough by EnCana, which is drilling two wells this summer at Deep Panuke in a make-or-break attempt to bolster its known reserves of 0.94 trillion cf. EnCana’s chief executive officer, Gwyn Morgan, says the project, originally due to come on stream at 400m cf/d in 2006, is “not going to make the grade” unless there is a substantial find.
With the uncertainty around Deep Panuke, two pipeline projects have been shelved – a C$1bn doubling of capacity on the Maritimes & Northeast Pipeline, which ships Sable gas to New England, and El Paso’s planned C$2.3bn, 1bn cf/d Blue Atlantic system, to serve the US northeast and Nova Scotia.
Reviewing the economics
Compounding the doubts, Marathon Oil, after its Annapolis G-24 deep-water wildcat discovery last year and estimates of reserves of up to 15 trillion cf, has postponed a further exploration well until at least 2004. Nova Scotia’s energy minister, Ernie Fage, says Marathon and its partner, EnCana, need time to arrange finance and contract a rig. Brian Prokop, an analyst with Peters & Co, claims the problems are more complex and suggests Marathon is reviewing the economics.
The Canada-Nova Scotia Offshore Petroleum Board, in the face of scepticism among analysts, is still counting on seven exploration wells this winter as part of C$1.56bn in work commitments on 59 licence blocks. So far, the only confirmed plans are for EnCana’s two wells and a C$60m, 19,700-foot well by Canadian Superior Energy and El Paso.
What keeps optimism alive is the knowledge that Nova Scotia has logged only 200 wells against 50,000 in the Gulf of Mexico – the regions are of similar size and geology. Attracted by that potential, the Energy Council of America, comprising legislators from 10 energy-producing states, visited eastern Canada in May to develop closer ties with governments and companies.
The council’s chairman, Jim Ellington, said it will “take time” for Nova Scotia to become a full-fledged producing basin. “It will be a continuing process to fully develop those fields. The Gulf coast is in my backyard and we’ve been exploring there for 50 years.”
But the growing unease is being openly expressed. David Collyer, Shell Canada’s vice-president of frontiers, says: “We need to reverse the recent trend of exploration drilling and get some encouraging results.” Paul Barnes, with the Canadian Association of Petroleum Producers, says both Nova Scotia and Newfoundland need “some success in the next year or two ... or we may lose momentum”.