LNG market grows, uncertainties persist

Discussion at London liquefied natural gas conference driven by US shale gas production, Japanese tsunami’s affect on nuclear power

By Bill White

Researcher/writer for the Office of the Federal Coordinator
Driving much of the discussion at a liquefied natural gas conference in London were two relatively recent events that have rattled how the global LNG industry views its short-term future.
The events help explain the unusual LNG pricing trends of late, underscore some of the volatile dynamics of supply and demand, and amplify the uncertainty forecasters have of their own predictions.

The first event was the rise of U.S. shale-gas production over the past five years, sweeping aside the world’s biggest gas market — North America — as an LNG customer. Companies mistakenly targeted billions of dollars for construction of new gas liquefaction capacity and U.S. import terminals. The lack of U.S. customers cast adrift that new LNG production, which needed to find a new destination and did so in Europe, helping soften short-term and spot LNG prices there. The continued rise of Lower 48 shale-gas production also has engrossed the LNG industry in a guessing game: Will the United States export some of its new-found gas bounty as LNG?
Event two: A tsunami stifling nuclear power production at Japan’s Fukushima plant last March. This boosted short-term LNG demand in Japan, raising prices there and diverting to Asia spot shipments that had been aimed at Europe.

Two currents at congress

Shale gas and Japan were two currents flowing through presentations at the LNG Global Congress held in London during the last week of September. I was invited to present on Alaska natural gas and to learn the latest developments in an industry undergoing rapid change.
A key message from the conference is that the spectacular expansion of LNG supply and demand worldwide should continue over the next decade, although LNG traders, analysts and consultants offered no consensus on the exact timing and details of that growth.

The LNG conference covered a breadth of other topics, from the rise of Qatar and Australia as gas liquefiers, to China’s energy appetite, the prospect of U.S. LNG exports, whether North America’s shale-gas revolution will be replicated elsewhere, and how a wider Panama Canal and a new technology called floating LNG might be game changers for the industry.

Optimism about LNG

Conference attendees gushed optimism about the LNG industry, while mumbling uncertainty about how exactly the future will unfold.
Alaska helped pioneer the world of LNG exports when the Nikiski liquefaction plant opened in 1969 to supply Japanese utilities with natural gas from the new Cook Inlet discoveries. Alaska since has been eclipsed as an exporter by Indonesia, Malaysia, Egypt, Trinidad & Tobago and, more recently, by such countries as Qatar, Yemen, Russia and Norway.
People attending the conference were generally aware that Alaska is about to exit the game, with the last LNG shipment expected to leave the Nikiski plant this fall.

Why Alaska would drop out just as Japanese demand is spiking did puzzle them, however. They didn’t understand that the historic Cook Inlet fields are petering out. I explained that some Alaskans hope the state can re-enter the fray within a decade by exporting North Slope gas from a resuscitated Nikiski plant or a new mega-plant at Valdez, if a proposed pipeline from the Slope gets built.
Here’s a snapshot of themes discussed at the conference.
Supply and demand

The LNG market has been defined for decades by long-term contracts between LNG makers and buyers of the gas. LNG makers needed these 20-year-plus deals to underwrite the huge upfront cost of building plants to liquefy gas — superchilling it to minus 260 degrees Fahrenheit transforms methane into a liquid that is more compact and economical to transport via special tankers.

But thanks to their rapid expansion in recent years, the world’s LNG exporters now have far more capacity to liquefy natural gas than is needed to fulfill current demand. This imbalance has given rise to short-term contracts and spot sales, which last year comprised about 20 percent of the LNG volume traded. That’s roughly akin to the percentage of oil under short-term and spot deals, said Kasper Walet, principal with Amsterdam-based energy consultant Maycroft. But he noted that these spot and short-term deals, while 20 percent of the LNG trade, comprised just 2 percent of all natural gas movement. Most speakers said they expect long-term deals to continue to characterize the industry.

Japan needed 110 billion cubic feet of additional LNG this year after Fukushima, and it got about 48 billion of it on the spot market, buying from Algeria, Egypt, Yemen and Nigeria, said Frederic Deybach, an LNG executive with European energy conglomerate GDF Suez.
The imbalance will end soon, as demand catches up with the capacity to supply LNG. When? The presenters’ estimates ranged from 2012 to 2015.
Key unknowns

Here are key unknowns that make this future so hard to predict:
Will low coal prices tilt China and other emerging Asian economies away from natural gas for future fuel supplies?
Will Japan and Germany phase out nuclear power and need more natural gas (as well as coal and oil) to make electricity, and if so, how quickly will the phase-outs occur? Will the world economy double-dip into another recession, or even triple-dip?
Will geopolitical events disrupt LNG supply, as they did this year in Libya, a gas exporter, and could do in unstable Yemen, another LNG exporter?
After 2015, start-up of new liquefaction plants — particularly in Australia but also in Papua New Guinea, possibly Canada and other locations — probably will ease any worries about LNG supply shortages for several years.
But timing is everything. If capacity comes on slow and demand rises fast, expect to see LNG prices rise, several speakers said. Prices could fall if liquefaction capacity gets built faster than demand rises.

Andre Mernier of Belgium sees a bright future in Asia for LNG because of its geology and geography. Geology — not enough of its own gas reserves and generally too distant for gas deliveries through pipelines. Geography — lots of need for electrical generation fuels in coastal population centers, where deliveries can be made easily. Mernier is secretary general of the Energy Charter Secretariat, a group with 53 member countries that upholds international laws to ensure the smooth flow of energy between exporters and importers.
Deybach of GDF Suez, said much of the expected new demand for LNG imports to 2020 will come from nations “where demand uncertainty is greatest.” These importers include developing nations in Asia, the Middle East and Latin America.
Ship charter rates soar

The LNG fleet has expanded rapidly in recent years, from 195 ships at the end of 2005to 360 ships at the end of last year, according to the International Gas Union.
That expansion hasn’t been fast enough, said Walet of consultancy Maycroft. Most tankers are sailing under entrenched contracts. The few available for short-term hire are demanding premium rates.
The rate for chartering an LNG tanker last year averaged $41,000 a day. That price jumped to $80,000 in the first half of this year, particularly after Japan’s Fukushima disaster boosted that nation’s short-term need for gas, Walet said. Claire Wright, principal gas analyst with Lloyd’s List Intelligence, said some spot-shipment rates have reached $100,000 a day.
Chris Meyer, a European LNG consultant with Poten & Partners, said shipyards are busy building tankers, and that day rates will fall within 18 to 24 months, after the new boats get launched. About 60 new ships have been ordered, Wright said.

Hot commodity

Worldwide demand for natural gas last year rebounded from the drop in demand caused by the 2008-2009 global recession. Overall demand leaped 7.4 percent, with LNG demand up 21 percent, said Hideomi Ito, natural gas analyst for the International Energy Agency. (LNG tends to be a niche product desired by places like Japan, South Korea and Taiwan that lack the option of pipeline deliveries. As was mentioned, less than 10 percent of the world’s gas consumption involved LNG last year.)
Growth in gas demand should slow over the next five years to perhaps 2.4 percent a year, Ito said, with LNG demand growing faster than that because it would help fuel hotter economies such as China and India.
Christof Ruehl, chief economist for BP, said European demand for LNG might even fall next year although he expects it to grow over time.

China’s big appetite

Natural gas comprises 4 percent of China’s energy needs now, Ruehl said. Coal provides 70 percent. China consumes less than one-tenth the amount of gas that Europe uses.
But China is just getting going as a natural gas consumer, Ruehl said. By 2030, China will consume far more energy than today, and natural gas will supply 9 percent of it. Within 20 years, China will consume as much natural gas as all of Europe consumes now, he predicted.

China will get about half of its gas in 2030 from domestic production, particularly tapping shale and other unconventional reservoirs, and it will import the other half via pipelines and LNG tankers, Ruehl said.
Ito noted that China has been investing furiously to secure new supplies. These investments include developing conventional, shale and coal-bed methane resources within China; securing long-term LNG-supply contracts with Australia, Qatar and Papua New Guinea; opening of an almost 4 billion cubic feet a day pipeline from Turkmenistan in late 2009 (expected to reach full capacity next year); and building a 1.1 bcf a day pipeline from Myanmar that should start in 2013.
Ito said China’s total gas demand could rise from about 10 bcf a day on average last year to 25 bcf a day in 2015, with LNG sating some of that growth.

Australia — boom towns, boom nation

Australia is the Wild West of LNG — a brawny frontier toward which the industry’s future is migrating.
Alan Copeland of the Australia Bureau of Resources and Energy Economics said his nation exported about 19 million metric tons (2.5 bcf a day on average) of LNG last year from two plants. That’s about the same LNG volume Alaska would export from Valdez if that idea ever catches on.

But that volume is dwarfed by what’s planned for Australia: Seven projects totaling 57.1 million metric tons (7.5 bcf a day) at some stage of development (a combined price tag of $144 billion), plus another six totaling 44.4 million metric tons (5.8 bcf a day) proposed but not under way.
The seven projects are supposed to be done by 2016. Can Australia really pull that off? Copeland called it “a huge challenge, an enormous task,” but noted the companies involved are sticking to their start dates. Others at the conference said start-up delays are all but certain.
Still, nearly everyone expects Australia will become the world’s No. 1 LNG exporter by 2020. Last year it was No. 4, behind Qatar, Indonesia and Malaysia. Qatar exported 56 million metric tons of LNG, the equivalent of 7.4 bcf a day on average.

Australia is developing gas fields relatively close to its East Coast population center. These include coal-bed methane fields that some local farmers oppose, Copeland said. But the giant plays are in remote areas, including in deep water far off the nation’s northwest coast. Australia, through a Shell project called Prelude, is pioneering the emerging technology called “floating LNG,” where liquefaction occurs at sea rather than piping the offshore gas to an onshore LNG plant.
The rapid build-out of Australian LNG is straining the country. An LNG development called Wheatstone plans to bring 3,500 workers to a town of 800 people — raising issues of where to house them, how to feed them and what they will do for fun. Some projects have adopted a work schedule familiar to those who labor at Alaska’s North Slope oil fields: one or two weeks of 12-hour days followed by extended time off.
With coal and iron ore developments occurring as well in Australia, engineers and equipment are in short supply, Copeland said. A big winner is the average laborer, who is pulling in wages of $225,000 to $300,000 a year on remote LNG projects, Copeland said. The audience gasped when Copeland mentioned this.

U.S. LNG exports

Several speakers said U.S. exports of LNG are inevitable. The United States will have the supply, due to fast expanding shale-gas production. And if the big gap between gas prices in North America and those in Asia linger, liquefying U.S. gas production could be very profitable.
Deybach of GDG Suez noted that a race is afoot within the Lower 48 by companies positioning themselves to make and export LNG. One or two of them will win. Possibly three.
Simon Bonini, a consultant and former LNG director for Centrica, a British utility, said that of course the United States will export LNG. “I’m a firm believer that if you can have a stampede into Queensland (one of Australia’s gas hotbeds), you can have anything.”

Leslie Palti-Guzman, a New York-based analyst with political-risk consultant Eurasia Group, said at least six serious LNG export proposals are in play in the United States and Canada. If they all came together they could export 70 million metric tons of LNG, or 9 bcf a day. That’s twice the volume TransCanada and ExxonMobil hope to flow into the Lower 48 from Alaska’s North Slope. Asian utilities or governments are involved directly or indirectly in the push for North American LNG, Palti-Guzman said.
“In practice only half of that amount at best will be expected to be exported but that is still a significant volume,” she said.
U.S. projects that are finished by 2016 could “hit a window of opportunity” if Australian projects fall behind schedule and LNG demand grows as some expect, Palti-Guzman said.
She noted the opposition to exports from the U.S. petrochemical industry, which uses natural gas as a feedstock and wants a supply glut to hold down prices. But, she added, “U.S. LNG export is definitely going to happen.” The exports would reduce the nation’s trade deficit, providing political reason to allow gas to leave the country, she said.

The current price gap between North American gas and Asian LNG is about $12 per million Btu. U.S. gas can be liquefied and shipped from the Gulf Coast to Asia for about half that price, Palti-Guzman said. The economics are even better for LNG from British Columbia — as long as the price gap holds, a risky assumption, she said.
Lower 48 natural gas prices could rise by $2 to $2.50 per mmBtu if the nation starts exporting significant volume, she predicted.
Some analysts believe U.S. LNG exports, and the resulting price rise, would heighten the Lower 48’s need for North Slope gas from Alaska.

Panama Canal

Palti-Guzman said expansion of the Panama Canal will help U.S. LNG exports to Asia.
LNG tankers traversing the Panama Canal can sail from the U.S. Gulf Coast to Asia in 22 days, shorter than a trip around South America or Africa, she said. Proposed LNG projects in British Columbia would hold a travel advantage, however: an eight-and-a-half-day trip to East Asia, she said.
Right now, only 6 percent of the LNG fleet of under 400 ships can squeeze through the canal, and none of them try, said energy consultant Walet.

But when the Panama Canal expansion is done, scheduled for 2014, 80 percent of the fleet will fit through the canal.
“It should be a real game changer,” Walet said.
The canal will transform how LNG flows around the world. In particular, diverting a cargo load in the Atlantic over to Asia will become more cost effective.
Shale gas globally?

Can the U.S. shale-gas revolution be duplicated elsewhere in the world?
Not easily, several speakers noted.
The United States is the perfect setting for shale gas. The country has lots of independent producers and service companies. A skilled labor force exists. Regulators generally understand gas production. Technology such as hydraulic fracturing and horizontal drilling are easily disseminated and improved on. The pipeline network to move production to market is vast.

China is estimated to have even greater shale-gas resources than the United States, but it falls short of the U.S. on know-how, competitiveness and market structures, said Madjid Kubler, owner of energy analyst Team Consult. Germany falls far short of China, he said, particularly on competitiveness and the regulatory/social environment for accepting unconventional gas development.
Will floating LNG sink or swim?
A new idea that many are watching to see how fast and how well it catches on is called floating LNG.

Shell is the first mover with this technology, approving a FLNG vessel to be built in South Korea and deployed to the company’s $10 billion Prelude development far offshore Northwest Australia. Shell estimates the field will start up in 2016, with 3.6 million metric tons of annual output (processing about 500 million cubic feet a day of natural gas).
A company called Flex LNG is involved in a smaller proposal off Papua New Guinea — an onshore field with offshore liquefaction, unlike Prelude where the entire operation will be offshore. Other projects are envisioned, including a couple more off Australia’s coast.
The attractions: FLNG fields could be developed more quickly for less cost, with no long-distance pipelines, fewer environmental challenges and less bureaucratic red tape ... if the concept proves itself.

The actual cost of building and operating FLNG units is unproven. This is causing some in the financial industry to wait and see, some speakers said.
But Wouter Pastoor, business development vice president with Flex LNG, said the technology is custom-made for small and medium-scale LNG production — 2 million metric tons a year (260 million cubic feet a day) in production or less, a bit more than the peak output from the ConocoPhillips/Marathon plant at Nikiski that is closing. This will let smaller countries and smaller fields get into the LNG business, and smaller volumes are easier to market, he said.
However, he noted that FLNG is “a novel idea whose risk profile is being defined.”

Alaska lawmakers propose ditching Palin's pipeline plan

JUNEAU – Leading state lawmakers introduced legislation Friday to abandon a centerpiece of former Gov. Sarah Palin’s administration: a state-sanctioned effort to advance a major natural gas pipeline.

The measure from Alaska House Republicans underscored the impatience and skepticism that many lawmakers have expressed about the current process and a belief the state is no closer than it was several years ago to realizing the long-hoped-for line.

Under the Alaska Gasline Inducement Act championed by fellow Republican Palin, the state promised TransCanada Corp. up to $500 million to advance a line. TransCanada won the exclusive license in 2008.

The state has reported that reimbursements so far have topped $36 million.

The company missed a self-imposed target for reaching agreements with shippers at the end of 2010 but has cautioned against reading much into that, noting that negotiations are complex and continuing.

But a number of lawmakers are losing patience — and faith — that this process will succeed in getting a line built this decade, if ever. The measure Friday was the first such introduced by the Legislature.

The bill, introduced by Republican Reps. Mike Chenault, Mike Hawker, Craig Johnson and Kurt Olson, would presume the project is uneconomic if TransCanada cannot show proof to Gov. Sean Parnell’s administration before July 15 that it has received firm shipping commitments.

Parnell has stood behind the process, saying he supports efforts by private industry to build a line that could carry gas from the North Slope to market.

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Still hope for gas pipeline

Study for DNR suggests future L48 gas prices will support gas from North Slope

Alan Bailey

Petroleum News


Amid current speculation about the future of the Alaska oil and gas industry, as oil production from the North Slope slows down and exploration drilling comes to a near standstill, it has become popular to add what some view as fading hopes for a future North Slope gas line to a general list of woes.

For, as the burgeoning development of plentiful supplies of so-called shale gas in the Lower 48 has caused a paradigm shift in the North American gas market, the price of Lower 48 gas has plummeted to levels below the projected transportation rates on a gas line from the Arctic, perhaps rendering the gas line uneconomic.



Objective analysis

In the interests of taking a rational look at the prospects for future Lower 48 gas prices, to replace worry-driven conjecture by objective analysis, the Alaska Department of Natural Resources commissioned consulting firm Black & Veatch to prepare a report on the future of North American gas prices in the context of the new shale gas revolution.
And the Black & Veatch analysts have found that, although there are major uncertainties around future North American gas markets, it is likely that gas prices in Alberta, Canada, will climb to somewhere between $5 and $7 per thousand cubic feet by 2020, with prices continuing to climb thereafter. And with a possible fee of $3.50 per thousand cubic feet for treating North Slope gas and carrying it by pipeline to Alberta, those gas prices could make a North Slope gas line viable, Antony Scott, a commercial analyst with Alaska’s Division of Oil and Gas, told Petroleum News Nov. 22.

DNR wanted an authoritative set of data, against which to benchmark the gas line project and had obtained funding from the Alaska Legislature for the Black & Veatch study, said Mark Myers, Alaska Gasline Inducement Act coordinator.

“This is a very robust study,” Myers said. “It’s like no other study we’ve seen out there in the literature.”

And Scott emphasized that the study tried to be unbiased in its views of future gas markets and, if anything, had underestimated the future cost and pricing of shale gas.



Technical breakthrough

Shale gas technology involves the extraction of natural gas from the impervious rocks where gas forms, rather than using the conventional approach of drilling into porous and permeable reservoir rocks that have trapped gas as it bubbles through subsurface rock strata. The use of high-tech horizontal drilling techniques that allow a well bore to pass for long distances through a shale gas horizon, coupled with the use of water and chemicals to fracture the rock, thus releasing the gas from the rock lattice, have been key enabling technologies in shale gas development.
The coupling of technical breakthroughs in shale gas production with the realization that vast areas of gas shale underlie various regions of the United States and Canada has triggered the shale gas revolution and caused a massive uptick in estimates of North American natural gas resources.

However, despite much hype about shale gas, with implications of vast gas supplies at rock-bottom prices, shale gas development still only has about a 10-year track record, with most of that record relating to one shale unit, the Barnett shale in Texas, Scott explained.

“It’s really important to recognize that outside of the Barnett we’re in extremely early days of the shale gas story,” Scott said.

But, after assessing various natural gas scenarios, the Black & Veatch analysts have concluded that shale gas production would figure large in any future North American natural gas supply situation.

“No matter what, there’s an awful lot of shale gas that is going to be relatively inexpensive to produce,” Scott said.



Price impact

The arrival of shale gas in the North American gas market, converting tightening production from conventional gas fields to a growing gas glut, caused gas prices that had climbed to levels approaching $8 per thousand cubic feet by 2008 to suddenly collapse, dropping to below $4 currently.
And the import of liquefied natural gas into the Lower 48, thought just a few years ago to be an inevitable growth industry as domestic supplies of natural gas decline, has now been pushed into the background.

“If you look at the price environment … it becomes hard to tell a story in which LNG finds an attractive home in North America,” Scott said.

Key drivers behind Black & Veatch’s view of future Lower 48 natural gas markets are the assumptions that the now-known abundant supplies of North American natural gas, coupled with an environmental preference for the use of gas rather than coal as a fuel, will push up the use of natural gas for electricity generation. On the other hand, while there are major uncertainties regarding future gas demand levels, there are also major uncertainties in estimates of the future costs of developing new shale gas resources.

For example, the supply of water for shale fracturing and the subsequent treatment and disposal of water produced from gas wells has represented a fairly modest cost element in the development of the Barnett shale, but will likely become a major cost factor in the development of shale gas in other basins.



Inconsistent data

But inconsistencies in the way in which finding and development costs for shale gas are reported make it difficult to assess whether those costs are compatible with current gas price levels, and Black & Veatch thinks that current prices may be artificially low.
“Current market prices for natural gas in North America may not provide adequate return for full development of shale resources in North America,” the Black & Veatch report says. “Significant levels of current shale production appear to be driven by requirements to drill to maintain acreage positions.”

Published shale gas finding and development costs in the Lower 48 range from $2.06 to $2.35 per thousand cubic feet, but these numbers do not appear to include factors such as land lease costs and water costs. Estimated costs of $3.25 to $4.25 per thousand cubic feet in western Canadian basins are likely nearer the full cost, although there are differences between cost reporting rules in Canada and the United States, Black & Veatch says.

And an examination of the production history of the Barnett shale provides some revealing insights into possible future shale-gas cost trends.

Essentially, Barnett shale production has seen a series of significant technical breakthroughs, each of which has caused a sudden jump in gas production. But the rate of increase in production has dropped back sharply after each technology-induced spike. And, contrary to popular belief, the cost of finding and developing additional volumes of Barnett shale gas appears to have increased rather than decreased over time.



Rising cost

The explanation for this conundrum seems to lie in the production characteristics of shale gas resources. In essence, a shale gas well achieves high initial production rates as the fractured shale rapidly releases its gas content. But, with the rock being relatively impermeable, that initial production rate drops off quite rapidly, requiring increasing effort to stimulate existing wells and the drilling of new well bores to sustain overall production levels.
The result is a production cost profile that curves upwards as more and more of the gas resource is accessed, until a law of diminishing returns places an upper cap on the total volume of gas that can be viably extracted from a particular shale gas resource, the Black & Veatch analysts concluded.

Recognizing the importance of individually considering the unique characteristics of each shale gas basin, the Black & Veatch analysts applied the upward curving cost model to each of the various U.S. and western Canada basins, to assess future gas production costs in different basin scenarios. Estimated water costs factored high in the distinctions between the scenarios — potential situations ranged from unlimited water access and the disposal of untreated water down wells, as for a Barnett shale development, to limits on water supplies and the need for the treatment of produced water, as would be required for developments in the Marcellus shale in Pennsylvania.

Additional costs, all subject to significant uncertainty and regional variation, include land access and government taxes.



Rising demand

But future demand for natural gas in North America should support the anticipated gradual rise in shale gas costs.
Black & Veatch has its own Lower 48 gas demand forecast that assumes gas demand for electricity generation will rise at an annual rate of 3.2 percent, with greenhouse gas regulation tending to drive the replacement of coal-fired generating capacity by gas-fired power plants. In 2010 the Energy Information Administration, apparently barred from considering potential changes in government energy policies, came up with a lower growth rate of 0.5 percent, on the assumption that there would be no future restrictions on greenhouse gas emissions.

And although the Black & Veatch projection of total demand from all uses of gas through to 2035 also exceeds the equivalent EIA projection, the Black & Veatch projection is “within the fairway” of several independent gas demand forecasts, Scott said.

“Power generation demand is going to be a really big story,” he said. “It’s going to matter a lot.”

Then, when it comes to the interplay between gas costs, gas demand and gas prices, the actual level of gas demand and the actual finding and development costs would appear to be the likely dominant future drivers of gas prices. And Black & Veatch assembled low, medium and high gas price scenarios, using a standard North American gas model to project, for each scenario, likely annual gas prices at different market hubs, together with likely annual production volumes from each shale gas basin, through to 2040.



Price scenarios

The low-price scenario assumes the relatively low EIA projection of future gas demand, together with low water costs; low finding and development cost escalation, along the lines of conventional gas fields; and modest tax rates. The medium-price scenario uses Black & Veatch’s shale-gas cost escalation model, together with Black & Veatch’s projection of future gas demand. The high-price scenario adds in increased environmental restrictions over access to shale gas resources, somewhat higher tax rates and relatively high water costs.
The low-price and high-price scenarios projected into 2020 result in the $5 to $7 per thousand cubic feet price range that may come into play in Canada at around the time when completion of a North Slope pipeline could be in the offing.

“Except in very extreme events we believe the Alaska (gas line) project — given what we know about the tariff structure today, the cost of producing gas at Prudhoe and Point Thomson — it looks like it should work,” Myers said.

http://www.petroleumnews.com

Alaska Candidates: Oil is declining, so what do we do?

Tim Bradner
adn.com Economy


When the debate topic turns to state economic policy in the governor's race, the first thing out of the chute is usually petroleum policy and oil taxes, and what we can do to stimulate this industry, which many fear is declining.
Oil is vital to Alaska. Royalties and oil taxes pay for 90 percent of the state budget, the Department of Revenue says. Overall, the industry supports about a third of Alaska's economy directly and indirectly, according to University of Alaska studies.
However, the trends in this vital industry are headed the wrong way. Production is declining, employment is down and new exploration may hit a record low this year.
Don't think a gas pipeline will bail us out, either. State revenues generated by gas will be very modest compared with oil and a pipeline is 10 years away, if then.
What do our governor candidates say about this? Sean Parnell, the incumbent, talks about expanding targeted tax credits for field work. His major opponent, Ethan Berkowitz, talks about negotiation of special fiscal terms for new fields as a way of inducing development.
Both ideas have merit and both are done in Alaska today on a more modest scale, and with success. But neither packs the punch to really turn this industry around. The big problem, which no major party candidate will talk about, is that Alaska's oil taxes are just too high, period.
Retired state economist Roger Marks has authored a new paper showing that Alaska's marginal oil tax rate, in essence the tax rate on profits from new investment, can exceed 80 percent. Alaska now has the dubious distinction of having one of the heaviest tax rates among major oil producing regions of the world, Marks says.
With production, drilling and jobs declining, is this where we want to be? I want to hear some discussion from candidates that we may have overshot in 2007 when we did major surgery on the state oil tax law and adopted a very aggressive tax formula. Do our politicians have the stomach to admit they possibly made a mistake? The proof of this is in the declining production and drilling. Only Ralph Samuels, a candidate in the Republican governor's primary, had the guts to talk about this.
Some legislators raised this in Juneau earlier this year, State Rep. Craig Johnson among them. Most lawmakers weren't interested in taking the issue on, however.
It's not that political leaders are clueless. In fact, our state has adopted some very innovative incentives with very generous investment tax credits for exploration and special royalty terms for development that have brought new companies here, most recently Apache Oil.
These help, particularly for small independent companies, but the problem is that the high overall tax rate really dampens the economics of major exploration projects, the very high-cost, high-risk ventures aimed at making really big discoveries. These are the kind that can really turn things around.
When exploration managers model their risk/reward balance with a new exploration project, for example in a high-cost, remote area, they seek a balance between the small chance they could make a very profitable find and the high probability of failure. The high state tax on a profitable discovery skews this balance, in that if the company wins its gamble the state takes almost all the gain, as Roger Marks shows. The state's current drilling incentives help ease the risk a bit but not enough to overcome the disadvantage of the high tax rate.
We need more discussion of this. Gov. Parnell says he likes targeted investment tax credits because no credit occurs unless the investment is made. He worries that there is no guarantee investment dollars will follow if a general tax reduction is made. Parnell's challenger, Berkowitz, basically follows a similar safe strategy: Unless a company agrees to invest in a negotiated deal, no fiscal agreement occurs.
Again, nothing is wrong with these tried-and-true strategies but they're too cautious. We need something more daring to turn things around. The Legislature had real guts last session in offering up a radical incentive for new drilling in Cook Inlet, a state offer to pay most of the costs of the first three test wells drilled with a jack-up rig. As a result we now have new companies investing in the Inlet. We need something similar for the North Slope, our largest oil basis, and we should engage the discussion now.

Conoco to reassess Alaska gas pipeline

According to London's Financial Times, ConocoPhillips' chief executive Jim Mulva said recently that the company would reassess the economics of the Denali project, a $30 billion gas pipeline from Alaska to Alberta it is considering building along with partner BP. The reconsideration is coming because a glut of natural gas in North America, being driven by unconventional shale gas plays, is keeping forecast commodity prices low. The current price is so low that Conoco has even shut in some of its North American gas wells (as have other companies). Mulva candidly explained the decision: "We’d rather keep it in the ground for when it will have a greater financial impact.” The report doesn't mention whether or not that statement applies to Alaska's natural gas as well as the shut-in wells, but read much more, here. Alaska Beat thinks it's worth noting that the industry pretty much agrees that gas prices will likely stay low in the short term, but there has been quite a bit of uncertainty over what they would do in the long term. At the very least, Mulva's comments and Conoco's plans to reevaluate Denali's particulars indicate that doubts over the long-term price of gas are coming into greater focus and are significant enough to attend to.

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So far, Parnell looks like Palin Lite

I had high hopes for Sean Parnell when he took office last July. After Sarah Palin, it seemed a bright young governor who had a positive relationship with the oil and gas producers would be an improvement.

But so far, Parnell has looked more like Palin Lite, a charisma-free copy of his predecessor. He still has time and opportunity to redeem himself, notably if he kills that foolish attempt by Tom Irwin and Marty Rutherford to cancel the Point Thomson oil and gas leases held by Exxon and its partners.


It should be an easy decision. After all, if state lawyers get the Superior Court judge’s decision overturned and Natural Resources Commissioner Irwin’s attempt to cancel the leases is upheld, they could kill the gas pipeline. It really is as simple as that.

The state’s tussle with Exxon over development of Point Thomson goes back a long time. The company appeared to be dragging its feet on drilling and development for years, though there was no pipeline to take the gas away and the high-pressure field has tremendous engineering challenges, on which it spent many millions.

In 2006, Gov. Frank Murkowski decided to poke his finger in the corporate giant’s eye and moved to cancel the leases. Asked later why he did it, Murkowski said he wanted the Exxon people to come back with a better development plan and a firm commitment to carry it out. “And they did,” he said.

But Palin, Irwin, Rutherford and now Parnell have continued the fight and carried it to ridiculous extremes, putting Alaska’s economic future at great risk. Last summer, Irwin said he didn’t trust Exxon to fulfill its promises, so the commissioner’s uneasiness keeps the legal battle raging. He should try taking a Valium.

The gas pipeline is no sure thing by any means. And Point Thomson contains more than 8 trillion cubic feet of gas, a volume needed for pipeline viability. If those leases get tied up in a decades-long legal hassle — to ease Irwin’s worries — the gas could be nearly worthless by the time the mess gets untangled.

Irwin and his deputy Rutherford are both good people, but they have a doggedly negative attitude toward the North Slope producers that should disqualify them for their jobs. If they persist in the attempt to get the leases canceled, and Parnell goes along with it, this state may find itself back where it was at statehood in 1959, but without the bright prospects.

Idiotic public policy sometimes seems a way of life in Alaska. And that aimed at Exxon in retribution for the 1989 tanker disaster — plus the Palin-Irwin-Rutherford claim that Alaska didn’t get a big enough share of the North Slope pie — is classic dog-in-the-manger politics.

Oil money has funded this state’s government for two generations, Alaska did away with its state income tax 30 years ago and we have a free-money program that sends just about every living soul here a nice check every October.

State leaders came to terms with the companies exploring and developing the North Slope years ago. As a result, billions in investments were made, billions in taxes and royalties were collected. But now some of our leading lights want more. If this were 1898 and you tried that on a gold mining partner, you would be asking for a necktie party.

Sure, it’s politically incorrect in Alaska to say good things about Exxon. I don’t know any of the current bunch, but some of the finest people I’ve ever met were Exxon employees. That includes Otto Harrison, who headed up the Exxon Valdez cleanup; many of the engineers and managers who worked for him and those that helped build the trans-Alaska oil pipeline; and the late Max Nalley, who was the company’s public affairs manager for several years.

The list also includes my old hunting and fishing buddy, Hank Rosenthal. Hank was delivered to Alaska by the icebreaking tanker Manhattan, which reached Prudhoe Bay via the Northwest Passage. He was the public relations guy on the project. I was in public affairs at ARCO in those days and Rosenthal became my Exxon counterpart (actually the company was named Humble Oil & Refining in those days).

Hank and I both had statewide responsibilities and could always come up with a reason to meet with people in Unalaska when the geese were in at Cold Bay, Southeastern Alaska when the ducks were flooding in there, and in summer anywhere the salmon were running.

Hank left Exxon sometime in the 1970s and took my job at ARCO when I decided to bail out in 1980. (I gave him a heads-up before I told my boss I was quitting.) He came back to Alaska and married one of my favorite liberals, former Assemblywoman Heather Flynn. Hank fought in the Korean War and survived fighting at the Chosin Reservoir, but was killed in 2003 by a curb-jumping taxi while on vacation in Prague.

So don’t bad-mouth Exxon people around me, friend. Say what you want about Joe Hazelwood and the company’s lawyers, but there are a lot of good people at Exxon. I’ve known many of them.

If Sean Parnell and Tom Irwin don’t smarten up about Point Thomson and drop that stupid lawsuit, I just might say bad things about them.

* * *

I’m a humanitarian kind of guy. For instance, I think we should treat attempted undie-bomber Umar Farouk Abdulmutallab humanely. Police should give him a clean pair of exploding shorts, light his fuse and send him on his way, perhaps into an unoccupied field of clover.

Of course, that won’t happen. The United States is teaching the terrorists about democracy a little at a time. Their latest lesson, for instance, is that when things go wrong, lawyer up and demand your rights as a non-resident attempted mass murderer. Don’t forget to ask the policeman to read you your Miranda rights.

Terrorists also learn quickly that — if things go wrong — they are most likely to become guests of the American government, be sentenced to three nutritious meals a day and a comfortable bed, and given access to exercise equipment and lots of television, movies and other forms of scandalous entertainment. Unless sent back home to attack America again, they will suffer such infidel indignities for the rest of their lives.

I like my way better.



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Tom Brennan is author of The Snowflake Rebellion, a tongue-in-cheek novel about Alaska seceding from the union, and three other books. His Website is: http://arcticternbooks.com/

Alaska's Natural Gas Pipeline: A Reality Check

Alaska poorer for outdated oil attitude

COMPASS: Other points of view

By BRAD KEITHLEY Brad Keithley heads the oil and gas law practice at Perkins Coie, LLC, from its Anchorage offices.

(10/07/09 19:31:30)

A recent New York Times article should make Alaskans think. The headline was "The Oil Industry is on a Roll This Year with New Discoveries."

The first sentence captures the thrust: "The oil industry has been on a hot streak this year, thanks to a series of major discoveries that have rekindled a sense of excitement across the petroleum sector, despite falling prices and a tough economy." The article reports 200 significant discoveries so far this year in dozens of countries, including Australia, Brazil, Norway, Ghana and Russia.

Alaska receives mention only as a historical footnote.

Why has Alaska become an historical footnote? Perhaps unintentionally, the article provides the answer. As explained by an oil company CEO, "That's the wonderful thing about price signals in a free market -- it puts people in a better position to take more exploration risk."

To put it bluntly, for the past several years, Alaska's exploration signals to the industry have said "go elsewhere."

Recent legislative enactments, such as the Alaska Gasline Inducement Act and the ACES oil tax, come to mind as examples. The root cause runs deeper, however.

Alaska has become smug and arrogant about the industry legislatively, administratively and even on the editorial pages of some newspapers. A good example is the attitude expressed earlier this year by one of the governor's "energy" advisers, Joe Balash.

In a recent international survey conducted by a Canadian institute, Alaska ranked 78th out of 143 states and governments in an assessment of policies designed to encourage oil and gas production. When asked to comment on the results, Balash said, "Alaska is right where it ought to be. 'We ... have tough terms; we set the bar high. ... We have world-class resources. Arkansas and Mississippi don't.'"

Unfortunately, that worldview is outdated. Alaska has 35 trillion cubic feet of reserves on the North Slope. To pick an example, recent discoveries of shale gas from Arkansas' Fayetteville shale formation alone are estimated at 20 Tcf, and additional amounts exist in the Woodford shale formation in eastern Arkansas and the potentially gigantic Haynesville shale formation located, in part, in southern Arkansas.

That story repeats across several states and the globe generally. Against these alternatives, Alaska's "tough terms" have shot Alaskans in the foot.

This situation poses a serious threat. Ninety percent of Alaska's general state government revenues and one-third of Alaska jobs derive from the oil industry. Undeniably, Alaska's economy runs on oil.

But, this linchpin is on a very steep decline. At its peak, the North Slope produced in excess of 2 million barrels per day; now, it produces roughly 700,000 barrels per day and is declining rapidly at the rate of 10 percent per year. The two new high-profile projects currently under development will not offset even one year's reduction. At its peak, BP's Liberty project is estimated to produce 40,000 barrels a day; Port Thomson is estimated to produce 10,000 barrels a day of liquids.

To overcome these declines -- and preserve its economy -- Alaska must renew its commitment to encouraging oil development; Alaska's "price signals" must indicate Alaska is open for business.

One question often asked is "who's responsible" for maintaining the "revenue side" of Alaska's economy. Sometimes, Alaskans assume it is the oil industry's responsibility. The correct answer, however, is that we -- Alaskans -- are. Alaska's political leaders set the "price signals" for development in Alaska; industry only responds to them.

The upcoming Legislature session and 2010 elections are critical. Without maintaining oil revenues, state services will decline, income and sales taxes will become a reality, and current residents will leave the state in large numbers, resulting in the collapse of housing prices and the economic well-being of scores of Alaska's businesses.

The revenue side of Alaska is on the line. Alaska's founding generation set the right price signals to sustain Alaska's first 50 years. The current generation must step up to put Alaska on track for the next 50.