Illinois is home to a portion of the New Albany Shale, a formation that is believed to hold between 1 billion and 8 billion cubic feet of natural gas.  That is not a tremendous amount compared to some other widely known plays like the Marcellus Shale, but there is also some belief that the New Albany formation may contain oil and other liquid hydrocarbons.

Fracking regulation is a hot-button issue in Illinois.  Illinois has yet to pass any comprehensive regulatory package.  Energy companies have leased an estimated 500,000 acres for drilling, but have held off on commencing operations until they know what rules will apply.  Meanwhile, Southern Illinois, where the New Albany Shale is located, is the most economically-challenged area of the state.  Many politicians, local residents and businesses are hopeful that drilling activity will help alleviate economic conditions.  Environmentalists are concerned that the economic boost will not be worth the damage they fear will be done to the environment.

Efforts in recent years to pass fracking regulations failed.  John Bradley, a state representative from Southern Illinois, came up with a plan.  He convened a group of negotiators from both sides of the issue to try to hash out a fracking bill that both sides could live with.  Bradley selected a core group of four negotiators from environmental groups, four from industry, plus representatives from state government, including the attorney general's office, governor's office, regulatory agencies, and the legislature.  Several months of sometimes tense negotiations resulted in a bill that was filed in February and received nationwide attention.

The bill is Illinois House Bill 2615.  Among its features are:

• Mandatory baseline water testing before fracking starts and monitoring during operations, with a presumption of liability for any contamination that appears during operations;
• A requirement that flowback and produced water be stored in closed containers, or, in emergencies, in lined pits for up to seven days;
• A requirement that water ultimately be disposed of in injection wells, which are to meet prescribed standards and be tested every five years;
• Mandatory disclosure to state officials of the agents that will be used for fracking, with the caveat that companies can claim trade-secret protection to prevent disclosure to the public at large;
• A requirement that companies plug nearby abandoned wells to prevent water from flowing back up through those wells;
• Limits on the release and flaring of natural gas during operations;
• A bonding requirement of $50,000 per permit or $500,000 to cover multiple permits;
• Provisions for public notice and comment in connection with permit applications, and mailing of notice to landowners within 1,500 feet of a proposed well site;
• Best practice standards for well design, construction and monitoring.[1]

Environmental interests have not uniformly supported the bill.  Some groups rejected the bill, preferring to fight for a ban or moratorium on fracking.  Even groups that nominally support House Bill 2615 are conflicted.  They are simultaneously supporting rival legislation that would impose a two year moratorium, but explaining that fracking appears inevitable and House Bill 2615 may be the best possible outcome.

When the bill was filed, negotiators on both sides warned of the fragile nature of the compromise.  They issued statements that any attempt to amend the bill could cause them to withdraw support altogether.  Those warnings proved prophetic, as the bill has suffered setbacks.  The Illinois House Speaker, who was once thought to support House Bill 2615, has announced that he supports a bill that would impose a moratorium instead.  In mid-March, the bill stalled due to a dispute over severance taxes.  Less than a week after a deal was reached on that issue, an amendment was added that would require unionized well water contractors to be in place at each well site until drillers themselves were licensed.  That caused some industry-related groups to withdraw support for the bill.  A committee vote had to be postponed because it appeared that the bill would not have enough support to advance to the full House.[2]

And so the Illinois fracking bill once hailed as a potential "national model"[3] faces an uncertain future.  Many will continue to watch Illinois to see whether the hard fought fracking compromise is able to survive the legislative process.

[1]           Kari Lydersen, "In Illinois, Environmentalists and Industry Compromise on Fracking Bill," Midwest Energy News (2/22/2013), available at http://www.midwestenergynews.com/tag/fracking/.

[2]           Julie Wernau, "Push for Fracking Bill Delayed by Surprise Amendment," Chicago Tribune (Mar. 22, 2013), available at http://articles.chicagotribune.com/2013-03-22/business/ct-biz-0322-fracking-20130322_1_oil-and-gas-illinois-oil-surprise-amendment.

[3]           Tammy Webber, "Illinois Fracking Deal Could Be the National Model," Associated Press (Mar. 7, 2013).

Indemnity, of course, is an important issue when an industrial facility is sold or otherwise transferred.  This is true even of a well-run facility.  Often, after the passage of years and advances in scientific knowledge, practices that once were considered industry standard turn out, in retrospect, to have been harmful.  For this and other reasons, companies that transfer facilities often require indemnity from their transferees or demand that the transferee assume the transferor's environmental liability.  The transferor thus obtains some certainty by cutting off potential future civil liability for its past operations at the facility.  Or so it thinks.

In Louisiana, there are two basic types of obligations and corresponding rights:  real and personal.  Joslyn Mfg. Co. v. Koppers Co., 40 F.3d 750, 755-56 (5th Cir. 1994); see La. Civ. Code arts. 1763-1766.  A real right "is a right in a thing that can be held against the world."  La. Civ. Code art. 1763, cmt. b (1984) (emphasis added) (citing 1 Yiannopoulos, Property 380 (2d ed. 1980)).  The corresponding real obligation is said to "attach to the thing," or "run with the land."  See La. Civ. Code art. 1764, cmt. b (1984).  This means that the real obligation is automatically transferred to a person who acquires the property to which the real obligation is attached.  See La. Civ. Code art. 1764; Joslyn Mfg., 40 F.3d at 756.

A personal right, on the other hand, is the legal power that one person has to demand a performance from another person.  See Joslyn Mfg., 40 F.3d at 756 (quoting Yiannopoulos, La. Civ. Law Treatise, Property § 203, at 370 (3d. Ed. 1991)).  Unlike with real obligation, when property is transferred, the transferee does not assume his transferor's personal obligations with respect to the property.  See La. Civ. Code art. 1764; Joslyn Mfg., 40 F.3d at 756.

Because an obligation created by agreement is considered personal in the absence of some affirmative indication that it is intended to create a real obligation upon the land itself, an indemnity or assumption of liability usually only creates a personal obligation on the direct transferee unless the transferor is careful to include specific language evidencing an intent to create a real obligation that runs with the land.  See Joslyn Mfg., 40 F.3d at 757.  This can create unforeseen problems for a company that transfers a production facility and negotiates liability protection from its transferee.

In re El Paso Refinery, LP, 302 F.3d 343 (5th Cir. 2002), a case applying Texas-law principles somewhat similar to those discussed above, illustrates the potential problem.  Texaco operated a refinery in El Paso, Texas from 1929 until 1984, when it transferred the facility to a subsidiary, TRMI Holdings, Inc.  Id. at 346.  As part of the transaction, TRMI assumed all environmental liability with respect to the facility.  Id.  Two years later, TRMI sold the facility to El Paso Refinery, L.P.  Id.  The transaction documents included covenants that purported to prevent any subsequent owner from seeking contribution from TRMI or compelling TRMI to take any remedial action.  Id.

El Paso Refinery later filed for bankruptcy.  Id.  A group of creditors ultimately acquired the refinery, and gave notice of their intent to assert environmental and contribution claims against TRMI and Texaco.  Id. at 347.

As one of its defenses, TRMI asserted the covenants it secured when it transferred the facility to El Paso Refinery.  Id. at 354.  After analyzing those covenants, however, the Fifth Circuit concluded that they did not qualify under Texas law as "real covenants" that run with the land and bind subsequent owners.  Id. at 356-57.  They were only personal covenants that did not bind subsequent acquirers and thus did not preclude the present refinery owner's claims against TRMI or Texaco.

Of course, even where an indemnity provision does not create a real right/obligation, the transferor may still have a personal right to indemnity or other protection from its direct transferee.  That personal right is of no value, however, when the direct transferee is defunct or — as in In re El Paso Refinery — insolvent.

The In re El Paso Refinery case is an example of how a company that transfers a processing facility might not obtain the full measure of protection from future civil liability that it thought it bargained for.  Companies transferring facilities would be wise to carefully negotiate and draft the indemnity and other provisions they create to shield themselves from future liability.

Before expropriating private property, companies seeking to acquire an interest in property for pipeline-related purposes are obligated to attempt negotiations with the property owner.  See, e.g., La. R.S. 19:2.  If expropriation proceedings become necessary, the company seeking expropriation must show that its purpose is "public and necessary."  See La. Const. Art. 1, § 4(B)(4); ExxonMobil Pipeline Co. v. Union Pacific R. Co., 2009-1629 (La. 3/16/10), 35 So. 3d 192, 196-97.  Once the expropriator satisfies that baseline requirement, it enjoys vast, though not total, discretion in determining the extent and location of the property to be expropriated.  ExxonMobil Pipeline, 35 So. 3d at 200.  The Louisiana Supreme Court has identified four factors the expropriator should consider: costs, environmental impact, long range area planning, and safety considerations.  Id. (citing Red River Waterway Commission v. Fredericks, 566 So. 2d 79, 83 (La. 1990)).  As long as the expropriator gives these factors some consideration, its decision should not be second guessed.  The only limits are that the expropriator may not exercise its discretion in bad faith, or act so capriciously and arbitrarily as to make its decision "unreasoned."  Acadian Gas Pipeline Sys. v. Bourgeois, 04-578 (La. App. 5 Cir. 11/30/04), 890 So. 2d 634, 641.  Of course, the Louisiana Constitution also requires that expropriator provide "just compensation" to the property owner.  La. Const. Art. 1, § 4(B)(4).

Thus, companies planning to construct natural gas pipelines in Louisiana encounter relatively friendly expropriation laws and jurisprudence.  Especially in light of the recent drilling boom and the steps taken by industry to make use of abundant natural gas supplies (some of which have been discussed in previous entries), pipeline expropriators should have little difficulty establishing that their purpose is "public and necessary."  Courts have held that the need to maintain steady supply in light of increased demand and the need to take advantage of abundant resources are "public and necessary" purposes.  See, e.g., Acadian Gas Pipeline Sys. v. Nunley, 46,648 (La. App. 2 Cir. 11/2/11), 77 So. 3d 457, 463 (specifically mentioning the "huge resources" available from the Haynesville Shale formation).  In many cases, necessity will effectively have been established before an expropriation proceeding reaches the courts, as the expropriator will have obtained a certificate from either the Louisiana Commissioner of Conservation or the Federal Power Commission.  See La. R.S. 30:554; 15 U.S.C. § 717f. 

While Louisiana's existing pipeline infrastructure is often cited as a key consideration by energy and chemical companies planning new development in this state, additions to that infrastructure may ramp up, particularly if industry is successful in implementing new and emerging uses for natural gas.  If that comes to pass, expropriations may be among the many results of the ongoing natural gas supply boom.

LED estimates that the G2X Energy project would create 243 new direct jobs and 748 new indirect jobs.  Just like with the Sasol facility, state incentives are playing a major role in attracting the potential development.  The package Louisiana has offered the company includes a $5 million performance-based grant for infrastructure improvements at the Port of Lake Charles.  G2X Energy also could potentially enjoy payroll and other tax rebates through the Louisiana Quality Jobs Program, and a property tax abatement through the Louisiana Industrial Tax Exemption Program.

The Louisiana Economic Development announcement is available at:  http://www.louisianaeconomicdevelopment.com/led-news/news-releases/g2x-energy-announces-plans-for-$13-billion-natural-gas-to-gasoline-facility-in-southwest-louisiana.aspx?c=News Releases&id=39.

The planned facility's Southwest Louisiana location made sense to Sasol for several reasons.  First, it is close to the abundant natural gas fields in North Louisiana and Texas.  There is pipeline infrastructure already in place that can be linked to the new facility.  Louisiana also offers a trained labor force and an industry-friendly regulatory environment.

State incentives valued at over $2 billion also helped attract the investment. [2]  Incentives include a $115 million grant for land acquisition and infrastructure costs, payroll rebates, a $20 million investment in training facilities and equipment, and Louisiana's Industrial Tax Exemption Program, which provides a 100% property tax abatement for up to ten years on qualifying capital investments. 

The Sasol facility and other processing facilities like it raise a number of legal issues, some of which will be addressed in future entries.  And, many people in the United States and around the world will be watching closely to see whether Sasol's − and Louisiana's − investment will prove worthwhile.

[1]           La. Economic Development, "Sasol Announces Largest Manufacturing Investment in Louisiana History, Creating More Than 7,000 Direct and Indirect Jobs" (Dec. 3, 2012), available at http://www.louisianaeconomicdevelopment.com/led-news/news-releases/sasol-announces-largest-manufacturing-investment-in-louisiana-history,-creating-more-than-7,000-direct-and-indirect-jobs.aspx?c=News%20Releases&id=39.

[2]           Clifford Krauss, "South African Company to Build U.S. Plant to Convert Gas to Liquid Fuels," New York Times, Dec. 3, 2012, available at http://www.nytimes.com/2012/12/04/business/energy-environment/sasol-plans-first-gas-to-liquids-plant-in-us.html?_r=0.

A BRIEF HISTORY OF GTL

The technique underlying GTL is almost a century old.  GTL is based on a process invented by German scientists Franz Fischer and Hans Tropsch in the 1920s.  The process is less efficient and more expensive than traditional petroleum refining.  As a result, it has historically been used only out of necessity by pariah nations that had difficulty obtaining oil to manufacture needed transportation fuels.[1]  Nazi Germany used the process during World War II to convert coal to synthetic oil.  Apartheid-era South Africa did the same in response to international oil embargoes.

Now, industry is turning back to the process due to opportunity, not necessity.  The natural gas production boom has resulted in a large spread between natural gas and oil prices in countries with extensive gas deposits, like the United States.  That spread makes GTL more economical as an alternative to petroleum refining. 

WHY GTL?

Companies investing in GTL are essentially betting that the spread between natural gas and oil prices will remain large well into the future.  They believe that the abundant supply of natural gas will keep prices low and stable for years to come, ensuring that GTL will remain economically viable.

The fuels produced through GTL are also cleaner burning than conventional fuels.  In addition, GTL-created fuel has an advantage over other natural gas-based products like compressed natural gas in that it could be used without retrofitting vehicles or replacing existing fueling stations.[2]

Proponents in the U.S. also tout GTL's potential for contributing to U.S. energy independence.  Some sources estimate that U.S. shale formations contain enough natural gas to sustain domestic energy needs for a century.[3]  GTL would take advantage of this abundant, domestically-available resource rather than oil, which often must be obtained from countries that are unstable, hostile, or both.

GTL also provides an outlet for domestic natural gas.  The gas drilling boom has generated business activity and created well-paying jobs during difficult economic times.  That activity will almost certainly slow unless additional uses are found for the supply that is being built.[4]

REASONS FOR SKEPTICISM?

Skeptics point to the massive, often unpredictable capital investments required to build and maintain GTL facilities.  For example, Shell's "Pearl" plant in Qatar cost more than three times the amount originally projected and has experienced unexpected maintenance problems.  Existing GTL facilities have also encountered operational difficulties.  The Sasol "Oryx" facility in Qatar reportedly encountered serious operational problems and operated far below capacity, at least early in its service life.[5]  GTL proponents counter, however, that they can apply lessons learned from prior ventures to avoid similar cost overruns and operational difficulties in the future.

Skeptics also note the historic volatility of both oil and natural gas prices and argue that industry cannot count on the imbalance between gas and oil prices to persist.  While there currently appears to be sufficient domestic gas reserves to keep prices low and stable for many years to come, skeptics argue that GTL plants require decades of low natural gas prices or imbalances between gas and oil prices in order to be economical due to the large up-front capital investments that are required.  Moreover, while hydraulic fracturing has rendered huge volumes of natural gas accessible, it has also generated a great deal of controversy.  Legal or regulatory developments might increase barriers to the use of such techniques and thus decrease accessible reserves.  While operators may be able to protect against price risks to some extent through mechanisms like long-term supply contracts, such protections are far from perfect and may themselves result in unexpected complications years hence.

Another risk is that competing uses will drive up demand for natural gas, resulting in higher prices.  The same conditions that have led some companies to consider investments in GTL are spurring other companies to find other uses for natural gas.  Steelmakers, for example, are increasingly using natural gas as feedstock for their processes.  Liquified natural gas export facilities are another potential outlet.  While such uses of natural gas generally are not expected to be sufficiently prevalent to make a major impact on price in the near future, that may change as industry finds new and improved ways to take advantage of gas supplies.

Finally, environmentalists argue that the purported environmental benefits of GTL-produced fuels are largely illusory.  They claim that GTL-fuels actually generate more carbon emissions than conventional fuels because the process used to create them is so inefficient and energy intensive.

Consideration of GTL is just one of many developments arising out of the natural gas boom.  The legal, economic, political, and social implications of this activity are enough to provide fodder for numerous entries on this and similar sites.

[1]           John M. Broder and Clifford Krauss, "A Big, and Risky, Energy Bet," New York Times, Dec. 17, 2012, available at http://www.nytimes.com/2012/12/18/business/energy-environment/sasol-betting-big-on-gas-to-liquid-plant-in-us.html?pagewanted=all&_r=0.

[2]           Ben Lefebvre, "Gas-to-Liquid Site May Hit $10 Billion," Wall Street Journal, Sept. 14, 2011, available at http://online.wsj.com/article/SB10001424053111904353504576568872584676488.html.

[3]           Louisiana Economic Development, "New World for Natural Gas," LED News, Q2 2012, available at http://www.louisianaeconomicdevelopment.com/led-news/articles/new-world-for-natural-gas.aspx.

[4]           Steve Hargreaves, "Turning Natural Gas Into Diesel Fuel," CNNMoney (May 9, 2012), http://money.cnn.com/2012/05/09/news/economy/natural-gas-diesel/index.htm.

[5]           "Gas to Liquids - GTL," available at http://www.natgas.info/html/gastoliquids.html.

According to a Sierra Club press release, the DOGGR—the state agency charged with regulating all oil and gas well activity in California—acknowledges “it has not permitted or monitored the impacts of fracking and has never formally calculated the potential environmental and health effects of the practice, even as it continues to approve new permits for oil and gas wells.” The lawsuit asks the court to issue “[a]n injunction enjoining the DOGGR from the approval of any further permits for oil and gas wells where hydraulic fracturing may occur within the state of California unless and until it complies with the requirements of CEQA by considering, evaluating, and mitigating the environmental and public health impacts associated with hydraulic fracturing.”

Earthjustice attorney, George Torgun, who represents the environmental groups, stated

“Right now, the people of California don’t know where or when the drillers are fracking, what chemicals they are using, what pollutants they are releasing into the air and water, and what other risks they’re taking. That’s because the state hasn’t required them to disclose any information on fracking activities.”

Some other states, including Louisiana, have adopted regulations requiring companies engaged in fracking to report the chemicals used in their fracking fluids.

Encana, a major gas producer, strongly disagrees with the EPA's draft report.  According to Encana:

"Numerous discrepancies exist in the EPA's approach, data and analysis. A few of these discrepancies are:

• The EPA report ignores well-known historical realities with respect to the Pavillion field's unique geology and hydrology.
• The EPA drilled two deep monitoring wells (depth range: 783 — 981 feet) into a natural gas reservoir and found components of natural gas, which is an entirely expected result. The results in the EPA deep wells are radically different than those in the domestic water wells (typically less than 300 feet deep), thereby showing no connection. Natural gas developers didn't put the natural gas at the bottom of the EPA's deep monitoring wells, nature did.
• There is unacceptable inconsistency between EPA labs' analysis for numerous organic compounds reported to have been found in the EPA deep monitoring wells. Data is not repeatable and the sample sets used to develop these preliminary opinions are inadequate.
• Several of the man-made chemicals detected in the EPA deep wells have never been detected in any of the other wells sampled. They were, however, detected in many of the quality control (blank) samples — which are ultra purified water samples commonly used in testing to ensure no contamination from field sampling procedures. These two observations suggest a more likely connection to what it found is due to the problems associated with EPA methodology in the drilling and sampling of these two wells.
• The EPA's reported results of all four phases of its domestic water well tests do not exceed federal or state drinking water quality standards for any constituent related to oil and gas development."

New USGS Data Released

In April and May 2012, the U.S. Geological Survey collected groundwater-quality data and quality-control data from one of the EPA's two monitoring wells.  Two groundwater-quality samples were analyzed for field water-quality properties (water temperature, pH, specific conductance, dissolved oxygen, oxidation potential); inorganic constituents including naturally occurring radioactive compounds; organic constituents; dissolved gasses; stable isotopes of methane, water, and dissolved inorganic carbon; and environmental tracers. Quality-control sample results were evaluated to determine the extent to which environmental sample analytical results were affected by bias and to evaluate the variability inherent to sample collection and laboratory analyses.

The data from USGS has not caused EPA or Encana to change its position.  EPA spokeswoman Alisha Johnson said that the new USGS data "is generally consistent with groundwater monitoring data previously released by the Environmental Protection Agency."  But noting that USGS' data came from just one of the two monitoring wells because the other well had insufficient water flow, Encana remains steadfast that EPA's wells are improperly constructed, and is unsurprised by the USGS data.

In response to the new USGS report, Wyoming Governor Matt Mead said, "I feel that the process used to acquire this data was an improvement on the process used for the draft EPA report last December. ... We are now waiting as analysis of this data is done.  It should help inform the peer review process."

The final EPA report on the water study is expected some time next year, but the debate is sure to continue in Wyoming and elsewhere.

The [Dodd-Frank Act] explains that the exploitation and trade of conflict minerals by armed groups is helping to finance conflict in the region and that the emergency humanitarian crisis there warrants these disclosure requirements.  As reflected in Section 1502 of the Act, Congress intended to further the humanitarian goal of ending the extremely violent conflict in the DRC, which has been partially financed by conflict minerals originating in the DRC.

Under the rules, all reporting companies will be required to determine if conflict minerals are necessary to the functionality or production of a product manufactured by the company or contracted by the company to be manufactured.  Whether a company “contracts to manufacture” a product will depend on the degree of influence the company has in the parts that are used in the manufacturing process.  In the second step of the compliance process, the company must undertake a “reasonable country of origin inquiry” to determine the origin of conflict minerals used in its products.  This will generally involve obtaining reasonably reliable representations from its suppliers regarding the origin of the conflict minerals and a review of the company’s own sourcing policies.  If the company determines its conflict minerals do not originate in the DRC, the company must file a form SD describing the nature and results of the inquiry, and has no further disclosure obligations.

If the company determines that its conflict minerals did originate in the DRC, the company must undertake the third step of the compliance process: due diligence of its supply chain to determine if the conflict minerals were used to fund armed groups.  The results of the due diligence are disclosed in a conflict minerals report, which is attached as an exhibit to the form SD.   The conflict minerals report must also include an independent private audit as to whether the company’s due diligence framework conformed to SEC guidelines.

The rules, though well intended, may have limited effectiveness in stemming the tide of conflict minerals.  As a threshold matter, the rules will only apply to companies that file reports with the SEC.  If the rules force those companies to eliminate the use of conflict minerals, foreign companies could step in to fill the void.  The conflict minerals rules also contain exceptions that could lessen their effectiveness.  For example, under SEC guidance a company that simply affixes its brand on a “generic” product will not be considered to “contract to manufacture” the product.  With the rise of outsourcing, many products purchased in the U.S. are produced and manufactured abroad by foreign companies who are not subject to the conflict minerals rules.  U.S. companies with foreign suppliers may be able to interpret the term “generic product” broadly and avoid being subject to the rules.  In addition, although retailers heavily influence consumer purchases and could raise awareness of the conflict minerals issue at the point of sale, most retailers will be exempt from the rules because retailers generally do not manufacture products.  Finally, the armed groups in the DRC could ship the conflict minerals outside the country so that they originate in a permitted country.  Companies using these minerals would not have to undertake the due diligence phase of the compliance process and would therefore be unlikely to discover the funding of the armed groups.

It turns out that the Arctic is even more unforgiving than the world's best engineers predicted.  Yesterday, the Chicago Tribune reported Shell's announcement that it will not drill into any oil reservoirs in the Chukchi Sea in 2012. (Article: http://trib.in/UhtXGd).  Apparently Shell's containment dome was damaged during tests and the required repairs could not be completed by the September 24^th deadline set by the Department of the Interior and EPA.  Shell still plans to drill top holes in preparation for the 2013 drilling season before the October 31^st deadline to halt all drilling operations for the winter.  Regardless, this is a setback in Shell's Arctic strategy as most engineers agree that actual production could begin in 2017 at the earliest, under ideal conditions.

While the Artic might be physically inhospitable, many energy companies are confident that drilling there can be profitable because of the relatively stable geopolitical climate in the region and enormous potential reserves.  Britain's Independent recently reported that geologists estimate there are 400 billion barrels of oil and gas underneath the frozen tundra of the Arctic Circle.  That is enough petroleum to power civilization as we know it for 125 years. 

With such large estimated reserves it should come as no surprise that the nations with coastlines on the Arctic have made a myriad of competing territorial claims.  For every country besides the United States (as the US has not ratified the treaty), territorial rights in the Arctic Ocean are governed by the United Nations' On the Law of the Sea Convention.  The convention provides that out to 200 nautical miles, within the exclusive economic zone, Arctic nations have absolute control over petroleum resources.  Out past 200 nm, Arctic nations retain their rights over seabed resources if they can demonstrate scientifically that the ocean floor is a 'natural prolongation' of the continental shelf closer to shore.  This is why Russia planted a flag on the sea floor at the North Pole in 2007; it claims the Lomonosov Ridge is an extension of its continental ocean floor territory.  These potential disputes are an issue to keep an eye on in the long term.

But well before those competing international claims can come to a head, energy companies must first drill exploratory wells to determine more exactly the location and size of the petroleum/natural gas deposits.  The large number of setbacks for virtually every company operating in the region combined with the global economic slowdown raises the question of whether crude oil prices will support the increased costs of extracting oil and gas from the artic.  Shell is making a significant bet that Arctic oil is indeed worth the price.  Since 2006 Shell's Arctic strategy has cost the company $4.5 Billion, one-sixth of its annual capital spending budget.  Though Shell will not discuss its production costs in the Arctic, some analysts put the costs at around $70-$80 per barrel while others put it closer to $30.  Going forward, those costs compared to the price of crude will dictate the pace of exploration in the Arctic.