In its judgment, the court noted that the Colorado Oil and Gas Conservation Commission had conducted an investigation and concluded that the Strudleys' water supply had not been affected by oil and gas operations.  Further, the plaintiffs' own environmental expert could go no further than to state that the results of his analyses of the plaintiffs' water supply "could be consistent with contamination from gas well chemicals or production waters."  He could not state an opinion that the defendants' activities had actually caused any contamination.

The court also noted that the Strudleys' medical expert reached "no opinion as to whether exposure was a contributing factor to Plaintiffs' alleged injury or illness."  The medical expert could only state that the plaintiffs' symptoms coincided in time with the defendants' wells being brought into production. 

The court's judgment dismissing the case was signed last week, on May 9, 2012.

An EPA spokesman confirmed that the test results "did not show levels of contaminants that would give EPA reason to take further action."

The EPA's testing program was initiated in response to complaints from residents of Dimock about their water quality, which some of the residents blamed on local oil and gas activity, including hydraulic fracturing.  The EPA has now completed four rounds of water sampling and testing, with samples being collected from approximately 61 homes in the small northeastern Pennsylvania town.  The EPA has not found any results that fall outside federal drinking water standards.

A spokesman for Cabot Oil & Gas Corporation, which operates in the area, said: "Cabot is pleased that EPA has now reached the same conclusion of Cabot and state and local authorities resulting from the collection of more than 10,000 pages of hard data — that the water in Dimock meets all regulatory standards."

The test results (a large file) can be found here.

Why does the guidance focus on the use of "diesel" in fracturing?  The SDWA generally prohibits any underground injection that is not authorized by permit or some other rule.  But under the SDWA, hydraulic fracturing is not classified as an "underground injection," unless diesel fuel is included in the fracturing fluid.  That is why the guidance specifically relates to hydraulic fracturing operations in which diesel is used in the fracturing fluid.

Why was a guidance document needed in the first place?  In the past, the EPA has not required SDWA permits for fracturing, even when diesel is included in the fracturing fluid, but the EPA announced in 2010 that companies would have to obtain SDWA permits before using fracturing fluid containing diesel.  Because the EPA has not previously required permits, both companies and regulators were uncertain what standards would be used in evaluating permits.  Also, because the SDWA does not define "diesel," there was uncertainty regarding what substances would be considered "diesel" for purposes of SDWA permitting requirements.  The guidance document is the EPA's attempt to provide clarification.

Where does the guidance apply?  The guidance will apply only in states where EPA administers the SDWA program.  Many states have "primacy," meaning that those states have their own SDWA regulatory programs that meet certain federal standards, and those states have been delegated the responsibility to administer SDWA enforcement within the state.  The guidance document will not apply in the states that have primacy, but those states may adopt the  new guidance standards if they choose.

Methane hydrates look like ice, but are a crystalline structure comprised of two compounds ─ water molecules, which are on the outside of a crystal lattice, and methane, which is on the inside.  When methane hydrates are exposed to pressure and temperature conditions for which the hydrates are not stable, the crystal structure breaks down, yielding liquid water and methane gas.  Methane hydrates are found onshore beneath the Arctic permafrost and offshore in ocean sediments along most of the world's continental shelves, including in the Gulf of Mexico.

In the field test, the research team injected a mix of carbon dioxide and nitrogen into a formation containing methane hydrates, then depressurized the formation.  The result was an in situ exchange of carbon dioxide and methane molecules in the hydrate structure, and the release of methane gas.  The field test was conducted from February 15, 2012 to April 10, 2012, with the depressurization phase lasting 30 days.  During the depressurization, the formation produced a steady flow of natural gas.

The Department of Energy's statement called methane hydrates "a vast, entirely untapped resource that holds enormous potential for U.S. economic and energy security."  The Department stated that it plans to conduct a "long‑term production test in the Arctic as well as research and test additional technologies that could be used to locate, characterize and safely extract methane hydrates on a larger scale in the U.S. Gulf Coast."  The work has "the eventual goal of making sustained production economically viable."

The Department said that it still is evaluating data from the recent field test "to determine the efficiency of simultaneous CO₂ storage" in, and methane production from, the same reservoir.

The draft regulations also include provisions that BLM says will improve assurances of well-bore integrity, in order to prevent fluids from escaping the well, and confirm that operators have a plan in place to properly handle and fracturing flowback water.  Once in place, the regulations will apply to a large number of wells.  BLM estimates that about 3400 wells are hydraulically fractured on federal lands or Indian lands each year, about 90% of the total number of wells drilled on those lands. 

The regulations will require companies to obtain BLM's approval of any hydraulic fracturing operation prior to conducting the operation.  The well operator can seek approval for fracturing at the same time that the operator submits an application for a permit to drill, or the operator can seek approval later.  So that BLM will have sufficient information to evaluate  requests for authority to conduct hydraulic fracturing, the draft rules would require the operator to give BLM a report that includes:

• a geological description of the formation that would be hydraulically fractured, as well as the depths of the top and bottom of the formation   
• the source location for the water that would be used in fracturing 
• the type of proppants to be used in the fracturing   
• the anticipated pressures to be used in the fracturing operation     
• an estimate of the total volume of fracturing fluid to be used    
• an estimate or calculation of the anticipated fracture length           
•  the estimated volume and composition of flowback water that would be recovered after fracturing    
• the methods the operator intends to use to manage flowback (including information regarding any pits or ponds to be used), and
• the operator's plans for eventual disposal or reuse of the flowback.   

The operator also will be required to submit a cement bond log to the BLM prior to fracturing in order to ensure mechanical integrity of the wellbore.  The purpose of this log is to verify that there are no voids in the cement that is supposed to fill the annulus between the well's casing and the well's outer wall, thereby providing a seal to prevent vertical migration of fluids through the annulus.  In addition, the operator will be required to perform a pressure test of the wellbore prior to fracturing, to ensure that it can withstand the maximum pressures expected during fracturing.

During fracturing, the operator would be required to continuously monitor the annulus pressure (an unexpected change in the pressure could be an early indicator of a problem with well integrity).  The draft regulations would require operators to store the flowback water recovered from the fracturing operation in tanks or lined pits to minimize the chance for an unintentional release.  After the fracturing operation is complete, the operator must provide BLM with a report that includes such information as the actual amount of water used and recovered, and a discussion of any ways in which the fracturing operation deviated from what was expected.  

The post-fracturing report also must identify each additive used in the fracturing fluid by trade name, additive purpose (such as biocide, corrosion inhibitor, etc.), and the Chemical Abstracts Service Registry Number (which provides a unique identification for each known chemical compound).  The information provided to BLM will be made public unless the operator submits with the report a claim that a particular additive constitutes a trade secret that is protected against disclosure by some existing federal law. 

An operator that makes a trade secret claim must identify the federal law that the operator claims provides the protection against disclosure.  If a operator makes such a claim, the BLM will not publicly disclose the identity of the additive unless the BLM determines that federal law does not provide the protection the operator claims.  If the BLM makes such a determination, it will give the operator at least ten days notice before publicly disclosing the identity of the additive for which the BLM determined the trade secret claim was invalid. 

BLM states that it plans to make the publicly-disclosed information available on the internet.  It is evaluating the possibility of making FracFocus the platform for such disclosures.  FracFocus began as a website for well-by-well disclosures of fracturing water composition by operators who were willing to make voluntary disclosures.  But several states that have adopted requirements that operators disclose the composition of fracturing fluid have directed operators to post the information on FracFocus, which has now become a central source for such disclosures.

The draft regulations will soon be published in the Federal Register, after which there will be a 60-day public comment period on the draft. 

In addition to the draft regulations, the Department of Interior issued a press release regarding the draft and BLM's analysis of the likely economic impact of the proposed regulations.

The move toward nationalization was launched on April 16, when the Argentinian government issued a decree that temporarily placed administration of YPF under a government ministry, effectively transferring the powers of the company's Board of Directors to the government.  President Cristina Fernández also announced that she would ask parliament to enact legislation authorizing the central government to nationalize 51 percent of the shares of stock in YPF, with all of the nationalized shares being seized from Repsol. 

Last week, Argentina's Senate approved a bill to authorize the proposed nationalization of Repsol's shares by a vote of 63 to 3.  Argentina's Lower House of Congress is expected to follow suit this week.  Repsol has issued a statementcondemning the expected nationalization as "manifestly unlawful and gravely discriminatory."  Repsol also stated: 

The measure clearly contravenes the obligations undertaken by the Republic of Argentina during the privatization of YPF, breaching the most basic principles of legal certainty and of reliance by the international investment community.  Repsol will carry out all pertinent legal actions to preserve the value of all their assets and the interests of all their shareholders."

The move is expected to be popular with Argentinian public, which sees YPF as a national symbol.  The move is also expected to provide short term financial benefits to the central government, enabling it to divert YPF profits to itself, at the expense of Repsol, as well as the shareholder's whose stock is not nationalized. 

The longer term effect of nationalization is less certain.  YPF had begun drilling wells into the Vaca Muerta shale formation, from which both oil and gas can be produced.  One recent report estimated that drilling in the Vaca Muerta shale play could help double Argentina's production of oil and gas within ten years if appropriate investment is made in the play.  But the Argentinian government is strapped for cash and it may be difficult to attract foreign investment after the government nationalizes Repsol's shares.  The Argentinean government has stated that it will compensate Repsol, but the government has suggested that it will not pay anywhere near the value that Repsol has placed on the shares.

In reporting on the nationalization, The Economist magazine recently stated, "For Argentina, it is a disaster."  The magazine predicted: 

The effects of nationalization will be felt far beyond energy.  Spain is Argentina's biggest foreign investor.  After seeing YPF's fate, Spanish banks, utilities and telecoms may also look for the exits.  Ms. Fernández has also endangered Argentina's trade relations with Europe, one of its biggest export markets ... ." 

Cheniere's export facility would be only the second LNG export facility in the U.S., though other companies recently have begun the process of applying for permits to build export facilities.  The only existing LNG export facility in the U.S. is in Kenai, Alaska.  It was built in 1969 and primarily exports LNG to Japan, the world's largest importer of LNG. 

Just a few years ago, analysts were projecting that the U.S. would be importing increasing amounts of liquefied natural gas in the future.  But domestic production of natural gas production has soared in the last few years, largely because companies have utilized improved hydraulic fracturing and horizontal drilling technologies to produce natural gas from shale formations.  Indeed, the United States Energy Information Administration predicts that the U.S. will be a net exporter of LNG within a few years. 

Louisiana Department of Natural Resources Secretary Scott Angelle offered his "congratulations and appreciation" to Cheniere and federal regulators "for working together moving this project forward — the first of its kind in a generation and the second in our nation's history — and for establishing a procedural path in providing new markets for domestic natural gas and new economic stability in our natural gas markets that could mean more exploration, more jobs and more countries around the world dependent on us for energy instead of the other way around."

Cheniere released a statement in which its Chairman and CEO, Charif Souki, states: "Obtaining approval from the FERC is one more milestone for our Liquefaction Project.  We will now finalize financing arrangements in order to commence construction of the first two LNG trains of our Liquefaction Project promptly."

The surge in U.S. production of natural gas, and the central role that production from shale formations has played in that surge is illustrated by the two graphs below.  The top graph shows total U.S. production of natural gas, which began trending sharply upward in 2005.  The bottom graph shows U.S. production levels of shale gas (natural gas produced from shale formations).

The province also has an information page on its website regarding hydraulic fracturing.

The requirement for "reduced emissions completions" relates to the flowback portion of hydraulic fracturing operations, when the water that is used to fracture the underground formation is recovered from the well, prior to the well being put into production.  When it flows back to the surface to be recovered, that water is accompanied by natural gas.  Some companies vent that natural gas.  The new rules will require companies to conduct "reduced emissions completions" in which they recover that natural gas whenever recovery is feasible.  The new rules will require that companies send the natural gas to a flare for combustion whenever recovery is not feasible.  Either way — whether the natural gas is recovered or flared — the emissions of VOCs will be lower than if the natural gas were vented.    

A couple of states already require reduced emissions completions, but industry representatives expressed concern about immediate implementation of a nationwide rule.  Specifically, industry has stated that the type of equipment used to conduct reduced emissions completions does not exist in sufficient quantity for all the wells that are being hydraulically fractured nationwide, and that immediate implementation of a nationwide rule would bring drilling operations to a halt in some places.  Industry urged that the effective date of the reduced emissions requirement be delayed so that a sufficient quantity of the necessary equipment can be built. 

In response to that concern, the EPA is delaying until January 1, 2015 the requirement that companies recovery the natural gas whenever feasible.  In the meantime, however, companies will be required to flare the natural gas if they do not recover it.  Thus, the emissions of VOCs still will be reduced.  The requirement that companies flare the natural gas (if they do not recover it), along with portions of the new rules that apply to aspects of oil and gas activity other than hydraulic fracturing, will go into effect 60 days after the rules are published in the Federal Register.  That publication should occur soon.

For additional, information, see:

• Text of new rules (588 pages)
• Summary of new rules
• Summary of changes made in rules since publication of original draft rules 
• Summary of requirements relating to natural gas well sites  
• Summary of requirements relating to natural gas compressor stations  
• Summary of requirement relating to natural gas processing plants  
• Summary of requirements relating to natural gas gathering and boosting stations 
• Summary of requirements for equipment used in oil production
• Oil & Gas Law Brief post dated August 10, 2011, discussing proposed rules.