Point Thomson: Field fight over?

Field fight over?

Alaska, Exxon have ‘resolution in principle’ on Point Thomson, Sullivan says

For Petroleum News


A top Alaska official signaled strongly Aug. 15 that the six-year fight for control of the Point Thomson oil and gas field might soon be over.

Dan Sullivan, commissioner of the Alaska Department of Natural Resources, told a legislative committee the state and ExxonMobil, the Point Thomson unit operator, have reached “resolution in principle” on terms to settle the legal conflict.

“We believe that this is a resolution that advances the state’s interests,” Sullivan told the Senate Resources Committee, meeting in Anchorage. “ExxonMobil now is discussing the provisions of the settlement with other working interest owners of the unit, who are also the other litigants in the current lawsuit.”

Terms of the settlement remain confidential, Sullivan said.

He noted the matter is more involved than simply the state and ExxonMobil reaching a deal, as the Point Thomson WIOs also are working out “internal commercial terms between themselves.”

Sullivan’s remarks are the most significant sign yet that the struggle over the rich but undeveloped field is coming to a close, heading off what easily could be years more litigation between DNR and the major Point Thomson stakeholders. Besides ExxonMobil the major players include BP, Chevron and ConocoPhillips.

Alaska economic development boosters are anxious to see the legal cloud lifted from Point Thomson, as it contains roughly a quarter of the North Slope’s 35 trillion cubic feet of natural gas. Many believe that all the gas, including the Point Thomson reserves, are needed to make a North Slope gas pipeline a viable project.

A settlement also conjures intriguing possibilities for how the field’s considerable endowment of oil and other hydrocarbon liquids might be exploited. Full-blown development of these resources could generate a boomlet of industry activity on the Slope.



Private briefing offered

DNR began taking firm steps to break up the Point Thomson unit and reclaim the state-owned acreage in 2005, during the administration of Gov. Frank Murkowski.
The state’s beef is the lack of any production to date from Point Thomson, despite its discovery decades ago in the late 1970s.

The field is located along the Beaufort Sea coast next to the Arctic National Wildlife Refuge.

The oil companies went to court to block the state’s effort to break up the unit, and today the case rests before the Alaska Supreme Court.

In recent weeks, DNR and the oil companies have filed heavy legal briefs, suggesting that no out-of-court settlement was near.

Yet the two sides have been negotiating for a year or more, with Gov. Sean Parnell and ExxonMobil executives stating publicly they wanted to settle the dispute.

Sullivan offered to brief legislators on the settlement terms “in a confidential setting.”

“Thank you, commissioner, I think that we would probably seek to take advantage of that offer because I think ... it is a material step forward,” replied Sen. Joe Paskvan, a Fairbanks Democrat and committee co-chairman.

Sen. Hollis French, D-Anchorage, asked Sullivan whether it was “fair to say that the state and Exxon are through negotiating and that negotiations that are taking place now are between Exxon and its partners. In other words, we made sort of our last best offer.”

Sullivan: “I think it’s fair to say.”

During the court proceedings, some friction emerged among the Point Thomson working interest owners, with Chevron, BP and ConocoPhillips complaining that they had been shut out of the negotiations between the state and ExxonMobil.



Deal timing unclear

ExxonMobil was measured in its response to Sullivan’s remarks. The company provided this statement via e-mail to Petroleum News and other media outlets:
“We’re aware of the State’s testimony on August 15, 2011 at the legislative committee hearings. We remain committed to working with Governor Parnell’s administration and the other working interest owners to finalize a settlement.

“Settling Point Thomson litigation and securing necessary local, state and federal permits is imperative to maintain the pace of Point Thomson development.”

The question naturally came up at the legislative hearing as to when a settlement could be finalized.

“When would you anticipate that the deal would be official and could be made public?” Paskvan asked Sullivan. “What’s the timeline on that — is that 90 days, 45 days?”

Sullivan replied: “You know, Mr. Chairman, I really don’t know. Our interest would be soon. In some ways those discussions right now are ... the timeline of those, we’re not necessarily driving that anymore.”

The other committee co-chairman, Republican Sen. Tom Wagoner of Kenai, said he’s been involved with the issue of Point Thomson development through three administrations, and he congratulated Sullivan on getting this far.

“I know it’s been a real battle that started with the Murkowski administration and went right on through,” Wagoner said. “Well, it’s very, very essential to the completion of the large pipeline.”

“Sen. Wagoner, we’re not, it’s not over yet,” Sullivan said. “As you know, anytime you work on settling litigation it’s never easy. You never get fully everything you want.”



What sort of development?

Sullivan noted that, while Point Thomson gas is considered important for a North Slope gas pipeline, the field also is rich in petroleum liquids, and production of those liquids could help stem the oil throughput decline on TAPS, the trans-Alaska pipeline system.
While construction of a gas line appears far from imminent, with no project yet confirmed, ExxonMobil itself created an incentive for wrapping up a Point Thomson deal as quickly as possible.

The company has pledged to begin production of 10,000 barrels a day of natural gas condensate, a liquid hydrocarbon, from Point Thomson by year-end 2014.

Already, the company has drilled two wells at Point Thomson, having obtained special permission from DNR in 2009 to sink the holes on two of the unit’s 31 leases. ExxonMobil and its partners proceeded with the drilling as part of a strategy to hang onto the field, which is worth billions of dollars.

But the Nabors 27-E rig used to drill the wells has been demobilized, and ExxonMobil would appear to have a tight window now for installing facilities to produce the condensate by the 2014 deadline.

A 22-mile pipeline also must be built to connect the remote Point Thomson field to the Slope’s existing pipeline network.

Of course, the deal now on the table between DNR and ExxonMobil might feature a whole new development scenario.

“The settlement is focused on the development of the Point Thomson unit which contains both hydrocarbon liquids and gas and we believe that the settlement of this litigation should help advance the strategic goals of filling TAPS and commercializing North Slope gas,” Sullivan told legislators.

Kenai LNG plant set to close this spring

ConocoPhillips, Marathon to mothball facility due to weak market conditions; plant has been shipping to buyers in Japan since 1969

By Eric Lidji
For Petroleum News


With news that ConocoPhillips and Marathon Oil plan to mothball their liquefied natural gas plant on the Kenai Peninsula this spring, Alaska is left standing on a bridge without a keystone. Since making its first shipment in 1969, the Nikiski export facility has held the Cook Inlet natural gas market together, even as that market began to change with age.
In its first few decades in operation, the facility justified the production of large Cook Inlet gas fields for local use by providing a large market outside Alaska. In the 2000s, it provided backup for utilities as local deliverability declined. Now, the plant could theoretically be converted to an import facility to bolster declining local production.
ConocoPhillips and Marathon made their decision based on market conditions, but those conditions aren’t easily delineated. As recently as last summer, the owners felt confident enough about the Asian market to apply for another two-year extension of their export license, but it appears the companies could not secure contracts through April 2013.
The reasons abound. The plant used to be the sole supplier to Japan, but now supplies only one half of one percent of that market. The LNG shipments leaving Alaska were once the largest in the world, but are now among the smallest. Supply contracts between Alaska and Japan used to run for 15 years, but have recently run for two-year terms.
Now, the future of the plant is uncertain.
“Right now, our intent is to get the plant preserved. We’re going to be evaluating options,” Dan Clark, ConocoPhillips’ manager of Cook Inlet assets, told Petroleum News. Those options range from closing the plant, to reconfiguring it, to selling it.
The bad news ripple effect
While Asian markets don’t appear to be mourning the news, the closure’s impact on Alaska markets will be wide ranging because of the unique role the LNG facility plays.
Once the plant is mothballed in April or May, it will jeopardize more than 100 direct and indirect jobs and tens of millions in taxes and royalties for state and local governments.
With the coldest months over by then, Southcentral should be no worse off than expected for this winter, but peak demand will be a critical issue next winter. Although Enstar Natural Gas, through Cook Inlet Natural Gas Storage Alaska, is building a new third-party storage facility, it won’t be ready until 2013. Even once it comes online, it won’t make up for the combined loss of the plant and declining Cook Inlet production.
“This storage facility is not intended to be a be-all end-all solution for Cook Inlet,” said John Sims, a spokesman for Enstar Natural Gas, the largest consumer in Alaska.
While Enstar expects to start getting firm shipments from the North Fork unit starting in March, those deliveries won’t fill the shortfall Enstar is facing in the coming years.
“That insurance policy that we had is lost,” Sims said. “And that’s a big one.”
Some wells to be shut-in
Until storage is available, ConocoPhillips will have to shut-in some wells once local demand drops in the summer. Because of the aging nature of Cook Inlet reservoirs, it’s unknown how those wells will produce once ConocoPhillips brings them back online.
(However, ConocoPhillips will continue to operate the Tyonek platform at the North Cook Inlet unit. While that unit primarily feeds the export facility, it is not isolated from the grid. North Cook Inlet and Beluga River will now be used to fill local contracts.)
The closure could also dampen exploration in Cook Inlet.
Through a deal with the state, ConocoPhillips and Marathon Oil bought third-party natural gas at their export facility, creating a market for explorers. Even though Alaska is craving natural gas, the local market might still not be large enough to support all of the potential production from the Cook Inlet leaseholders currently interesting in drilling.
The loss of an overseas market could also jeopardize plans to bring North Slope natural gas to Southcentral. Various plans for an in-state pipeline require an “anchor tenant,” like the export facility, to keep residential and commercial customers from bearing the full cost of the project. Meanwhile, an “all-Alaska line” from Prudhoe Bay to Valdez is based on exporting LNG, although the larger volumes available from the North Slope could change the market dynamics, allowing Alaska to better compete against other basins.
A plant in gradual decline
The closure of the plant is not entirely unexpected.
The last decade brought fundamental changes to the operation of the plant.
Phillips Petroleum and Marathon Oil built their facility at the dawn of the global LNG trade, only a few years after Great Britain began importing it from Algeria in 1964.
The Kenai plant started its life as a pioneering infrastructure system: a liquefaction plant in Alaska and a re-gasification plant in Japan, the two largest LNG tankers ever built and the new offshore Tyonek platform along with new pipelines and wells to support it.
The facility originally operated on long-term contracts with two Japanese utilities, Tokyo Electric Power Co. Inc., and Tokyo Gas Co. Ltd. The first export license ran from 1969 to 1984 with a five-year extension. The second license ran from 1989 to 2004.
Starting in the mid-1990s, the idea of shipping gas overseas caused heartburn at home.
In 1996, Phillips and Marathon applied for a five-year extension, through 2009, but local utilities and producers argued that continued exports would cause shortages in Alaska.
The U.S. Department of Energy approved the extension, but the issue reared its head again when ConocoPhillips and Marathon asked for a two-year extension through 2011.
The State of Alaska only backed the request after the companies agreed to certain concessions, like meeting local needs, increasing drilling and buying third party gas.
Utilities supported last extension
Last summer, when ConocoPhillips and Marathon requested another two-year extension, though 2013, the changing nature of the Cook Inlet changed the nature of the opposition.
Aside from a group of Democratic lawmakers worried about local supplies meeting local demand, the request got wide support from utilities, producers and the State of Alaska.
That happened for two reasons. First, ConocoPhillips and Marathon asked only for more time to ship volumes already approved for export. Second, storage and deliverability became more immediately pressing issues in Southcentral than production.
In the past decade, though, the plant and Cook Inlet began to show their age.
A 2006 report estimated that the plant would need significant investments to continue operating beyond 2011. ConocoPhillips recently put the cost of that investment in the range of several hundred million dollars. Except for an expansion in the mid-1990s, the plant, including its two turbines, has been in service since operations began in 1969.
(Reconfiguring the plant for imports would create additional costs.)
In 2007, Agrium mothballed its nitrogen fertilizer operations on the Kenai Peninsula after years of declining gas purchases because it could no longer secure a supply contract.
In April 2009, ConocoPhillips and Marathon cut their tanker fleet in half, reducing the volume of shipments. “Looking back on it, that was sort of the first step,” Clark said.

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.

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Horizontal Wells and Gas Shales

This post is one of my series of tech talks, describing some of the ways in which fossil fuels are produced. In the current part of the series we are focusing a little more on the procedures that are being used to recover natural gas from formations such as the Barnett, Fayetteville, Marcellus, Haynesville and Woodford shales. In this particular post I am going to concentrate more on the benefits of horizontal drilling through these shale reservoirs, rather than using the more conventional vertical wells that were used historically. This, and the next three posts in the series are likely to be a bit more technically dense than earlier posts, but I am trying to illustrate some of the problems of production, and some of the gains that technology is bringing to help solve some of them. And while the reason for the horizontal wells can be simplified in this graph from Chris McGill, there are a lot of other things that have to be considered in deciding whether or not the horizontal well is going to be worth developing.

Comparative production from a vertical and horizontal natural gas well (Chris McGill).
Full Article

Peak Oil- How will you ride the slide?

Twelve Principles to Guide U.S. Energy Policy

Americans are growing increasingly concerned about energy. Their demand for energy is increasing faster than secure supplies. Much of the world's sup­ply of oil is delivered in a restrictive market dominated by unstable or hostile nations, some of which are using energy as a tool to frustrate U.S. national secu­rity and foreign policy objectives.
Meanwhile, many Americans harbor misunder­standings and myths about energy and market forces. They want low energy prices and plentiful supply but resist the steps that energy companies must take to achieve these goals. This confusion leads their repre­sentatives in Congress to enact conflicting policies that harm America's ability to meet its energy needs. This has to change.
Sound national energy policies must enable Amer­ica to obtain energy supplies from a wide range of sources in a way that is best for the economy and at the same time addresses homeland and national secu­rity considerations. An abundant, diverse energy sup­ply is central to America's freedom and prosperity.
The guiding principles for an energy strategy that advances freedom and prosperity should emphasize three themes:
Unleashing free enterprise,
Protecting America's energy interests, and
Advancing free global energy markets.
Unleashing Free EnterpriseU.S. energy policy should recognize that the cre­ativity of free enterprise is best suited to building the infrastructure that is needed for exploration and distribution, producing domestic supplies safely, and developing viable new energy sources.
To unleash American entrepreneurship, Congress and the Administration should let the free market do its job. Central planning frustrates the functioning of markets and undermines security by limiting oppor­tunities to adapt and innovate. Washington must clear away the red tape that obstructs energy pro­duction and innovation while also assuring safety and appropriate environmental protection.
Specifically, Congress and the Administration should:
1. Avoid costly environmental regulatory man­dates that will achieve little environmental gain. Numerous costly regulations have been proposed or implemented to address various environmental goals, from water quality to glo­bal warming. However, past experience—such as with the morass of gasoline regulations that push up the price at the pump and the require­ments that have stopped construction of any new coal-fired power plants for the past 15 years—shows that mandates can be expensive and economically harmful while making only marginal progress toward environmental goals. The full cost of current and proposed regula­tions and mandates, including the economic and security impact, should be evaluated and compared with the likely environmental gain.
2. Rely on the private sector's research and development capabilities. The competitive pri­vate sector is best able to improve fuel efficiency and develop the next generation of fuels. There are many guesses as to what the “new oil” might be, but no one knows for certain—least of all the federal government. We do know, however, that finding and commercializing these new fuels is crucially important to our economic future. The best way to secure abundant energy sources in the future is to encourage entrepreneurs to dis­cover them, not for agencies and congressional committees to try to pick winners with directed research, regulations, mandates, and subsidies. Entrepreneurs need a regulatory, trade, and tax system that creates the best climate for private-sector innovation.3. Urge government agencies to learn from the private sector. The U.S. government is one of the world's largest consumers of energy. In par­ticular, the Department of Defense is one of the world's biggest customers for petroleum prod­ucts, but it does a poor job of thinking about long-term energy costs. It relies heavily on leg­acy equipment that is very energy inefficient, assumes that it will always have plentiful sup­plies of petroleum products to support opera­tions at reasonable prices, and does not adequately consider the life-cycle energy costs associated with developing, procuring, and maintaining new military capabilities. The mil­itary and the rest of government should adopt the best practices of the private sector to enable them to make smart buying decisions.
Protecting America's Energy InterestsIn today's dangerous world, policymakers must take steps to secure America's energy sources and protect the nation's energy infrastructure. However, they also need to keep down the economic cost of achieving security by enabling the energy produc­tion and distribution market to operate as efficiently as possible. Markets function most efficiently when they are transparent and predictable and when busi­nesses can respond to market incentives.
Therefore, while pursuing the goal of security, government should:
4. Make all sources of energy within U.S. bor­ders accessible.The federal government has placed too many restrictions on domestic oil and natural gas production. Failure to make full use of these domestic energy resources exacer­bates the security and cost problems caused by geopolitical events and makes America more vulnerable to supply disruptions and price increases. All U.S. lands and waters should be made accessible for appropriate exploration and production, which could be done using technologies that are far safer and more efficient than those that were available in the past.
5. Remove artificial constraints on the domes­tic energy infrastructure, including unneces­sarily severe environmental regulations.Red tape has restrained the expansion of refineries, construction of new pipelines and electricity transmission lines, and construction of new power plants. Several key domestic energy sources, particularly coal and nuclear power, can fulfill their potential and thus help to achieve energy security only if costly regula­tions and procedural requirements are revised or eliminated. Thus, new legislative initiatives such as streamlining requirements under the Clean Air Act and rethinking requirements for reprocessing nuclear fuel and the storage of nuclear waste should be considered.
6. Ensure that any effort to reduce reliance on foreign oil is grounded in policies that are best for the economy. Reducing oil imports from unstable or unfriendly regimes should be done in a way that minimizes the economic cost to Americans. Policies such as raising taxes on gasoline while mandating or subsidizing expensive or unproven alternative fuels and vehicles lead to large costs with marginal—or even negative—results. The first steps in reduc­ing reliance on foreign oil are to make full use of domestic petroleum reserves and to remove disincentives to investment in oil production from friendly nations. These should be coupled with efforts to encourage diversification away from petroleum, which will be best achieved not by government fiat, but by the private sec­tor–led development of alternatives that can compete in their own right. Domestically, the federal role should be limited to conducting basic research and removing regulatory and tax barriers that impede private-sector innovation. In addition, restrictions on international growth in alternatives, such as the tariffs that limit ethanol imports into the United States, should be eliminated.
7. Manage risks to critical energy infrastruc­ture as a responsibility shared jointly by the government and the private sector. Assessing the risks to critical infrastructure is a task that should be shared jointly by government, which best represents the national interest, and the private sector, which best understands how to deliver goods and services efficiently and effec­tively. Government can best understand threats and take steps to reduce them, while businesses can best assess their own vulnerabilities and address them effectively. Government should establish reasonable due-diligence standards for safety, security, and environmental con­cerns. This will require a high degree of trans­parency and effective information-sharing between government and industry, a mecha­nism to assess compliance and performance, and a non-bureaucratic way to enforce regula­tions. Optimal requirements would be perfor­mance-based (i.e., setting clear standards and allowing the private sector to determine how best to achieve them).
8. Establish effective risk communications for energy issues.Educating Americans on the facts is essential. In particular, Americans should be better educated about energy policy and the changes likely in the pattern of energy supply and prices before disruptions or crises occur. In the event of a crisis, information that is credible, understandable, and actionable should be provided to Americans so that they can make the best-informed decisions.
9. Develop foreign policies that thwart the capacity of coercive regimes to employ energy supplies as an economic weapon. America should be concerned not only about the dependability of its own energy, but also about that of its friends and allies. Regimes that withhold or restrict energy supplies as an instrument of national policy threaten not only regional stability and prosperity, but also the economy and national interests of the United States. The United States should develop strong bilateral measures to deal with efforts by coer­cive regimes to wage economic warfare. These might include joint contingency planning, public–private initiatives, and research and development initiatives.
Advancing Free Global Energy MarketsAmerica cannot ensure freedom solely from within its own borders. It must be willing to engage internationally to create the conditions for free enterprise to prosper.
This means that the government must act to:
10. Sustain access to the global marketplace.Remaining an integral part of the global econ­omyis vital to long-term U.S. national security and the country's continuing economic com­petitiveness. Rather than attempting to defend, protect, or secure any means of domestic or global production, the greatest degree of secu­rity comes from having access to the global marketplace and obtaining goods, resources, and services based on market decisions from friendly suppliers. It is in the vital interest of the United States to uphold the principle of free­dom of the seas and to promote and protect the ways and means of free trade among nations acting in accordance with the rule of law.To accomplish this, the United States should retain the capability to use all of the instruments of national power—including military, diplomatic, law enforcement, intelligence, economic, and informational power—in any theater where U.S. interests could be at risk.
11. Discourage restrictive international regimes.OPEC and non-OPEC countries with restrictive foreign investment laws, state monopolies, and excessive government intervention undermine the U.S. effort to promote free markets. U.S. economic and foreign policy should seek to discourage these practices.
12. Recognize that not all trading partners are equal.Free people have the right to decide with whom to conduct business, but trade in critical but vulnerable goods and services is best conducted with other free peoples. Amer­ica's closest friends and allies should be viewed as the most reliable trading partners for supply­ing oil and other energy supplies. Geostrategic military and economic alliances will change, of course, and the U.S. should be prepared to adapt, but Americans should seek to conduct energy business with countries that respect the rule of law, combat corruption and terrorism, and foster economic opportunity, democracy, and justice.
ConclusionAmericans clearly understand that freedom, opportunity, and their very quality of life suffer when abundant, affordable energy supplies are threatened. They expect Washington to enact poli­cies that protect their interests. Congress and the Administration would do this best by following these 12 principles to unleash the power of free enterprise, protect America's energy interests, and advance freedom in energy markets not just at home, but worldwide.
Stuart M. Butler, Ph.D., is Vice President for Domestic and Economic Policy Studies, and Kim R. Holmes, Ph.D., is Vice President for Foreign and Defense Policy Studies and Director of the Kathryn and Shelby Cullom Davis Institute for International Studies, at The Heritage Foundation.

Congressional craziness

Congressional craziness keeps United States in much hot water

WE KEEP LOOKING for an expert to explain why the economy is such a mess, but haven't seen anything thoughtful and comprehensive yet. So we'll offer our own. At least two big problems can be blamed in large part on foolish government decisions.

Why are energy costs so high, triggering inflation throughout the marketplace? Why, indeed, since the United States has huge untapped energy resources in oil, gas, coal and tremendous potential in nuclear energy. Then there are renewable sources like hydroelectric, wind and moving water energy.

Some of the problems are in developing technologies, but the nation's vast oil, gas and coal resources are largely off limits to exploration and production because Congress (with a little help from presidents like Bill Clinton) made them that way.

That makes the nation dependent on foreign sources, especially the Middle East, which is now an economic lifeline and must be defended with the lives of young soldiers and the fortunes of average taxpayers.

Many politicians have sold their souls to environmental activists and fight to block oil and gas drilling and coal mining within and around the country's borders. When the subject comes up of drilling in ANWR, a huge oil and gas reservoir, critics argue that it will take 10 years to tap ANWR. "That won't help today," they say. But legislation opening ANWR was passed by Congress in 1995, more than 13 years ago. The field could easily have been in production by now.

And why does it take 10 years to get a new field into production? Mostly government regulation and red tape. It's impossible to believe that process couldn't be speeded up and due consideration still given to environmental protection and public opinion.

Then there are the stock market gyrations triggered by a collapse in the mortgage lending field. Why did that happen? Because Congress mandated that poor people should be able to buy houses whether they could afford them or not. And the rules were loosened enough that liar's loans allowed even middle class people to buy larger and better houses than they could really afford if they wanted to bet that their income was going to go up later on.

Those who sold mortgages to people who couldn't afford the payments or were at risk of defaulting made their money on the paperwork. Afterward they laid off the loans on larger lenders who tried to make their money by buying mortgage paper in large amounts. It should be no surprise that eventually the system collapsed.

These things are all craziness, folks. They just should not be. The United States could be a wise shepherd for its natural resources and still extract them in a timely fashion without damaging the environment. Doing so would create millions of jobs as well as provide the nation with major sources of energy on its own soil.

America needs reform, all right. Most of these problems stem from congressional idiocy. How you fix that is a difficult question. We don't have the answer, just the question.
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From the ground to the pump… or the playing field… or the medicine cabinet... each and every day Americans rely on the products created by oil and natural gas. And behind this vital product is an important story that needs to be told. Whether it’s:

Learning the value of oil and natural gas in fueling our way of life,
Recognizing that energy efficiency has its benefits,
But a rapidly growing world still needs greater supply; or
Developing a better understanding of how company performance contributes to the average American’s retirement portfolio;
We should all know the intangibles of this irreplaceable product.

In just one 24-hour period, the oil and natural gas industry delivers:

Enough energy to heat 80 million homes
382 million gallons of gasoline to service stations, enabling 200 million drivers to get to work, take their kids to school, and take vacations-- traveling 7.5 billion road miles every day
67 million gallons to airport terminals, enabling 30,000 flights to travel around the world
Every day, the industry employs 1.9 million people directly, and many more indirectly.