Category: Industry Trends


The LNG Debate on Capitol Hill: When Will LNG Export Facilities Be Approved?

Filed Under: Current Industry Issues, Industry Trends, Regulatory Issues by admin — Leave a comment
April 8, 2013

By Alex Robertson 

The debate in the U.S. surrounding the liquefied natural gas (LNG) export facility approval process has become one of the most controversial issues in the energy sector. Many natural gas companies are eager to ship LNG overseas, where gas is more expensive.1 Others worry that quickly approving LNG terminals will dramatically increase domestic gas prices, thereby hampering domestic economic growth.

So far only one company, Cheniere Energy (Ticker Symbol: LNG), has gained approval from both the Department of Energy (DOE) and the Federal Energy Regulatory Commission (FERC) to build a functioning LNG export facility.2 Cheniere’s first export facility, which will be located at the Sabine Pass between Texas and Louisiana, will likely begin operations in 2015.3 At least sixteen other companies have filed requests for LNG export approval; however, the government is currently grappling with the decision of how and when such approval should be granted.4

The DOE has made one affirmative statement about the approval process: requests will be reviewed in the order in which the companies filed their applications.5 However, the more important issue is timing. How quickly should the DOE grant approval to LNG export facilities? Should it stagger the process, or approve all pending LNG export applications at once?6 The answers to these questions carry deep implications for the U.S. energy industry.

Lawmakers from several states in the oil patch, namely Texas, Oklahoma, Louisiana, and Arkansas, have urged Energy Secretary Steven Chu to speed up the approval process.7 These representatives, comprised of both Democrats and Republicans, argue that approving LNG exports will grow the economy, provide domestic jobs, and stabilize natural gas prices.8 Additionally, Congressman James Lankford pushed for LNG export approval on diplomatic policy grounds at a House committee meeting in March, stating, “For decades energy has been used as a diplomatic tool against the U.S. Now with LNG, the U.S. has the potential to flip that and be in a position to use energy as a tool to the benefit of our nation’s strategic interests.”9

Congressman Lankford makes a strong point; the U.S. has the potential to become a major natural gas exporter, with even President Obama dubbing America the “Saudi Arabia of natural gas.”10 Just a few years ago, energy analysts predicted that the U.S. would become a major natural gas importer. This all changed with new developments in drilling technology, such as hydraulic fracturing and horizontal drilling, which have allowed the U.S. to greatly increase its natural gas reserves.11 Now, the U.S. could potentially become the world’s largest exporter of natural gas if and when LNG export facilities are approved.

However, opponents argue that quickly approving LNG exports without limits will cause domestic gas prices to skyrocket.12 These opponents favor a staggered approval process, where the government would spread out export facility approvals over a number of years in hopes of avoiding a potential natural gas price shock.13 As Dow Chemical CEO, Andrew Liveris, put it in a Senate committee meeting, unrestricted LNG exports “would mean higher gas and electricity prices. It will mean higher transportation and utility costs for consumers as well as industry.”14 Mr. Liveris and others fear that high natural gas prices will force U.S. manufacturers to cut costs and ship more jobs overseas, thereby negatively affecting the U.S. economy.15 There is also opposition from environmentalists, who have long opposed the increase in hydraulic fracturing that could occur if the government grants widespread approval of LNG export facilities.16

The current debate comes at a key time when other countries are being more proactive than the United States in approving LNG exports. Canada, for example, has already issued three LNG export licenses with a total export capacity of 4.66 billion cubic feet of gas, more than twice the 2.2 billion cubic feet that the U.S. has permitted.17 Australia also has become a major player in the LNG export sector, last year becoming the largest supplier to Japan, the world’s largest natural gas buyer.18 In fact, earlier this month Exxon and BHP Billiton announced a joint venture to build the world’s largest offshore LNG processing and exporting facility off Australia’s northwestern coast.19 The plan is currently pending approval with the Australian government, but projects such as this show that major industry players are not shy about establishing a firm presence in other countries as the U.S. takes its time in approving LNG export facilities.20

Debate will continue between now and the time the DOE releases its study on LNG exports late this summer.21 Once the DOE releases its study, the Obama Administration will then move forward in its analysis of the situation.22 The DOE has said that there is no timeline for granting approval to the currently pending LNG export applications, leaving companies unsure when, and perhaps if, they will be allowed to export LNG.23 One thing is certain: the government’s decision will have an enormous impact on the U.S. energy industry. No matter where you stand in the debate, it will be interesting to see how it shapes out in the coming months.

 

A native of the oil patch, Alex grew up in Norman, Oklahoma and went on to attend the University of Missouri where he graduated summa cum laude with degrees in finance and real estate. Prior to law school, Alex interned at the U.S. Capitol in Washington D.C. for Congressman Dan Boren, a member of the House Committee on Natural Resources.

  1.  Timothy Gardner, US DOE delays analysis, decisions on LNG exports, Reuters (Mar. 25, 2012, 3:50 PM), http://www.reuters.com/article/2012/03/23/usa-lng-exports-idAFL1E8EN8WU20120323.
  2. Ayesha Rascoe, New U.S. LNG export approvals face long wait – Cheniere Energy, (Nov. 13, 2012, 6:41 PM), http://www.reuters.com/article/2012/11/13/lng-exports-approvals-idUSL1E8MD7NA20121113.
  3. Lawmakers Request Administration to Speed Up Approval Process for LNG Export Facilities, Energy Solutions Forum (Aug. 8, 2012), http://energysolutionsforum.com/lawmakers-request-administration-to-speed-up-approval-process-for-lng-export-facilities/.
  4. Lawmakers Request Administration to Speed Up Approval Process for LNG Export Facilities, supra note 3; Steven Miles & Thomas Eastment, US debate on LNG exports centered at Energy Department, Oil & Gas Journal (Apr. 1, 2013), http://www.ogj.com/articles/print/volume-111/issue-4/special-report-lng-update/us-debate-on-lng-exports-centered.html.
  5. Brian Scheid, LNG approval process has lots of consequences, more questions, Platts (Apr. 2, 2013, 4:53 PM), http://blogs.platts.com/2013/04/02/lng-approvals/.
  6.  Lawmakers Request Administration to Speed Up Approval Process for LNG Export Facilities, supra note 3.
  7. Id.
  8. Lawmakers Request Administration to Speed Up Approval Process for LNG Export Facilities, supra note 3; Gardner, supra note 1.
  9.  Jared Anderson, Experts Call on DOE to Speed up LNG Export Approvals, AOL Energy (Mar. 21, 2013), http://energy.aol.com/2013/03/21/experts-call-on-doe-to-speed-up-lng-export-approvals/.
  10. Mike Obel, Potential Surge Of US LNG Exports From Shale Natural Gas Boom Splits Corporate America; One Side Gets Allied With Environmentalists, International Business Times (Mar. 1, 2013, 9:31 PM), http://www.ibtimes.com/potential-surge-us-lng-exports-shale-natural-gas-boom-splits-corporate-america-one-side-gets-allied; Jason Koebler, Obama: U.S. ‘Saudi Arabia of Natural Gas’, U.S. News & World Report (Jan. 26, 2012), http://www.usnews.com/news/articles/2012/01/26/obama-us-saudi-arabia-of-natural-gas.
  11. Id.
  12. Scheid, supra note 5.
  13.  Brian Scheid, Manufacturers to push DOE for staggered LNG approvals, decision transparency, Platts (Mar. 19, 2013, 6:31 PM), http://www.platts.com/RSSFeedDetailedNews/RSSFeed/NaturalGas/6271855
  14. Obel, supra note 10.
  15. Id.
  16. Id.
  17. Justin Williams, Canada Taps LNG Export Market. While U.S. Waits, Canada Makes Moves, Energy & Capital (Apr. 4, 2013), http://www.energyandcapital.com/articles/canada-taps-lng-export-market/3251.
  18. Australia Becomes Largest LNG Exporter to Japan, LNG World News (Mar. 8, 2013), http://www.lngworldnews.com/australia-becomes-largest-lng-exporter-to-japan/.
  19. Rebekah Kebede, Exxon, BHP plan world’s largest floating LNG plant off Australia, Reuters (Apr. 2, 2013, 7:07 AM), http://www.reuters.com/article/2013/04/02/us-exxon-bhp-lng-idUSBRE9310C920130402.
  20. Id.
  21. Gardner, supra note 1.
  22. Id.
  23. Id.

 

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Natural Gas Developments in Brazil

Filed Under: Industry Trends, International Energy Law by admin — Leave a comment
March 2, 2013

By Kevin Vermillion

Brazil is the largest economy in South America and the seventh largest in the world.[i] Moreover, Brazil is one of the BRIC (Brazil, Russia, India and China) Nations, which some postulate will overtake the G7 economies by 2032.[ii] Brazil experienced remarkable industrialization over the last six decades, but even so, the nation faces substantial challenges due to energy source volatility.[iii] The following sections analyze Brazil’s energy background and natural gas’s role in realizing true energy stability.

Brazil’s Energy Background

Brazil’s electric grid is disproportionately dependent on hydroelectric power. As of 2012, hydroelectric power accounted for 80 percent of the installed capacity for the national power grid. [iv] While hydroelectric power is a renewable source of energy, years of low precipitation have repeatedly stressed the grid, leading to price instability. Even after ramping up fossil fuel generation, Brazil was forced to implement a strict quota system to avoid load-shedding events — also known as rolling blackouts.[v] The upcoming 2014 World Cup and 2016 Olympics provide additional impetuses for investments in energy production and infrastructure.[vi] To avoid industry-obstructing scenarios, Brazil sought other viable sources of power generation. The primary fuel for this new generation was to be natural gas.

Brazil’s transition to increased natural gas power generation was far from seamless. Initially, Brazil turned to its neighbor, Bolivia, to build a natural gas pipeline (GASBOL) between Bolivia and southern Brazil.[vii] Commenced in 1997 and completed by 1999, GASBOL cost 2.15 billion USD.[viii] The future seemed bright for GASBOL, but internal political turmoil in Bolivia following its 2003-2004 economic crisis began to degrade relations between Brazil and Bolivia. After the previous president fled the country after a change in leadership, Bolivian president Evo Morales nationalized all natural gas reserves as part of a broader political movement.[ix] Although Bolivians viewed the move as patriotic, it was disconcerting for Brazil, which looked to further diversify its energy portfolio via elevated domestic natural gas production.[x]

In 2006, Brazil implemented the Natural Gas Production Anticipation Plan.[xi] The goal of the plan was to increase production of natural gas in southeast Brazil — home to much of Brazil’s industry — from 15 MMcf/day in 2008 to 55 MMcf/day in 2010. [xii] Unfortunately, an illiquid credit market and strong rains undermined that plan.

The 2008 financial crisis dampened international interest in all types of investment, including Brazilian natural gas development. Simultaneously, a robust rainy period allowed the nation to fall back on hydroelectric power, further decreasing private sector interest in natural gas production.[xiii] By 2009, instead of trebled domestic production in southeast Brazil, natural gas production in the area was about one-third of production in 2006.[xiv]

LNG’s Role in Brazil

Despite many setbacks, natural gas is now on the upswing. Owing to an initiative by the National Energy Policy Council, Petrobras — Brazil’s state-controlled oil and gas corporation — laid the groundwork for building LNG import terminals.[xv] Brazil currently has two LNG import terminals: one in Pecém, in northeast Brazil, and the other in Guanabara Bay, near Rio De Janeiro in southeast Brazil.[xvi] Petrobras signed agreements for both terminals in 2007. These terminals are floating storage and regasification units (FSRUs) that together process up to 21 MMcf/day.[xvii]

Additionally, another such terminal is currently under construction in Bahia, in eastern Brazil about halfway between the existing terminals. The Bahia terminal will add another 14 MMcf/day of processing infrastructure. Like the constructed facilities, the Bahia facility will connect to existing natural gas pipeline infrastructure in its respective region. As of 2011, the Pecém and Guanabara Bay terminals import LNG primarily from Trinidad and Tobago, Nigeria, and Qatar.[xviii]

While LNG imports have become a crucial fallback option, natural gas self-sufficiency is the ultimate goal.[xix] Brazil has made significant strides in increasing domestic natural gas production. Between 2009 and 2011, Brazil’s annual domestic production rose from 363,034 MMcf in 2009 to 850,024 MMcf in 2011 — an increase of roughly 230 percent.[xx] Nevertheless, Brazil relied on record LNG imports to meet drought-induced energy demands. In January 2013, Brazil imported over 500,000 tons of LNG — a 20 percent increase from December 2012 and an 86 percent increase from January 2012.[xxi] Moreover, Brazil paid an average of $16.50/MMBtu in January, a significant increase from $13.27/MMBtu average it paid in 2012.[xxii]

Brazil may soon become a hearty consumer of American natural gas. Recognizing robust foreign LNG demand, existing U.S. LNG terminals are looking to add export capabilities. This update is currently taking place at the Sabine Pass terminal in Louisiana.[xxiii] With U.S. spot prices hovering around $3.50/MMBtu, it is no wonder that there are over a dozen U.S. LNG export terminals in varying stages of development.[xxiv] Thus, U.S. gas might soon help power Brazil’s electrical grid. Combined with oil exploration off Brazil’s coast, it is easy to imagine a more interdependent energy relationship for the hemisphere’s two largest economies.

Conclusion

Brazil has a long way to go to build a robust, reliable grid that is not as susceptible to price shocks, but it is moving in the right direction. The LNG import terminals enable Brazil to pursue long-term and short-term energy agreements with far-away nations —ensuring that Brazil is not beholden to neighboring nations like Bolivia.[xxv] Thus, LNG imports provide certainty in gas availability, which encourages investment in natural gas-fired electricity generation. These plants, in turn, ensure a market for domestic gas, hopefully providing an incentive for increased domestic production.

Brazil witnessed immense growth in recent years despite a volatile energy supply. Increased domestic production of natural gas and increased LNG importation capacity help provide the reliability that manufacturers and large commercial electric consumers require. If Brazil’s policymakers are able to address these issues, its burgeoning economy may exceed investors’ already lofty expectations.

 

Kevin Vermillion graduated in 2011 from the University of Texas at Austin with degrees in Plan II Honors and History. Kevin interned with ConocoPhillips as a facilities engineer during his undergraduate career. During law school, he interned with the Railroad Commission of Texas and Mayer Brown, LLP; he will spend the upcoming summer with Jackson Walker, LLP and Bracewell & Giuliani, LLP.


[ii] Projection by Goldman Sachs experts. BRIC Countries Likely to Overtake G7 by 2032: Experts. April 2010. Available at http://www.geopoliticalmonitor.com/bric-countries-likely-to-overtake-g7-experts-3719/

[iv] The Dangers of Relying on Hydroelectric Power: Brazil’s Lesson.  International Business Times.  Rasheed Abou-Alsamh. April 30, 2012.  Available at http://www.ibtimes.com/dangers-relying-hydroelectric-power-brazils-lesson-1056722

[v]. Id.

[vi] Brazil government denies World Cup energy fears. Michael Place. January 23, 2013. Available at http://www.bnamericas.com/news/electricpower/government-denies-world-cup-energy-fears

[vii] GASBOL is not Brazil’s only international pipeline; Argentina and Brazil have the Paraná-Urugaiana Pipeline. Natural Gas Pipelines in the Southern Cone. David R. Mares. May 2004.  Available at http://www.google.com/url?sa=f&rct=j&url=http://www.bakerinstitute.org/publications/natural-gas-pipelines-in-the-southern-cone&q=Natural+Gas+Pipelines+in+the+Southern+Cone&ei=WHIZUeOhGIi8qQGB04CIDQ&usg=AFQjCNEjDb8q_LwDL-460Rn0_qH9l7Pc-A

[viii] Id.

[ix] Id.

[x] Liquefied Natural Gas in Brazil:  ANG’s experience in the implantation of LNG import projects. 2010. Available at http://www.eisourcebook.org/cms/Brazil,%20Liquefied%20Natural%20Gas,%20ANP%20import%20experience.pdf

[xi] Id.

[xii] Id.

[xiii] Id.

[xiv] Id.

[xv] Id.

[xvi] World’s LNG Liquefaction Plants and Regasification Terminals: As of January 2013. January 2013. Available at http://www.globallnginfo.com/World%20LNG%20Plants%20&%20Terminals.pdf

[xvii] Petrobras’ LNG Among World’s Main Infrastructure Products. Pipeline & Gas Journal. September 2010. Available at http://www.pipelineandgasjournal.com/petrobras-lng-among-worlds-main-infrastructure-projects

[xviii] World LNG Report 2011. International Gas Union. 2012. Available at http://www.igu.org/igu-publications/LNG%20Report%202011.pdf

[xix] Energy and Mining Minister Edison Lobão stated that onshore reserves will enable Brazil to begin exporting LNG within five years.  Brazil Onshore Gas is New Pre-Salt: Daily.  Stephen Eisenhammer. April 30, 2012.  Available at http://riotimesonline.com/brazil-news/rio-business/brazils-onshore-gas-reserves-a-new-pre-sal/#

[xx] Converted from 10,280,000,000 cubic meters in 2009 and 24,070,000,000 cubic meters in 2011 for unit consistency. Available at http://www.indexmundi.com/g/g.aspx?c=br&v=136

[xxi] Brazil’s January LNG Imports Smash Country Records.  Available at http://www.hellenicshippingnews.com//News.aspx?ElementID=2c1461cb-2709-48fd-8ae1-cfd6d840637c

[xxii] Id.

[xxiii] The import terminal is adding liquefaction capabilities to its existing regasification capabilities. Sabine Pass Liquefaction Project. Available at http://www.cheniere.com/lng_industry/sabine_pass_liquefaction.shtml

[xxiv] North American LNG Import/Export Terminals: Proposed Potential. Federal Energy Regulatory Commission. December 2012. Available at http://ferc.gov/industries/gas/indus-act/lng/LNG-proposed-potential.pdf

[xxv] “Bolivia accounts for 78 percent of Brazilian gas imports [including LNG].” February 28, 2012. Available at http://www.eia.gov/cabs/brazil/Full.html.

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Choice of Law Under OCSLA

Filed Under: Current Industry Issues, Industry Trends, Recent Cases by admin — Leave a comment
January 8, 2013

W&T Offshore v. Apache, 4:11-cv-02931 (S.D. Tex.)—A Case to Watch

By Will Thanheiser

The Outer Continental Shelf Lands Act (“OCSLA”), passed by Congress in 1953 to govern oil and gas exploration and production activity on the Outer Continental Shelf, states that the district courts of the United States have jurisdiction over cases and controversies arising out of, and in connection with “any operation conducted on the outer Continental Shelf which involves exploration, development, or production of the minerals, of the subsoil and seabed of the outer Continental Shelf, or which involves rights to such minerals.”[i]  “Development” is defined in OCSLA as “those activities which take place following discovery of minerals in paying quantities, including geophysical activity, drilling, platform construction, and operations of all onshore support facilities, and which are for the purpose of ultimately producing the minerals discovered.”[ii]  The Fifth Circuit, handling a majority of OCSLA-related cases, has recognized that OCSLA provides a broad jurisdictional grant, and has applied a “but-for” test to determine whether a controversy arises under OCSLA.[iii]

Once a determination has been made that OCSLA governs a dispute, OCSLA’s choice-of-law provision defines the law to be applied to all the claims in that controversy which fall under OCSLA jurisdiction.[iv]  OCSLA’s choice-of-law provision states that (1) federal law preempts any other choice of law, and (2) the law of the “adjacent State” shall apply as surrogate federal law, unless it is inconsistent with federal law.[v]  OCSLA’s choice-of-law provision is so strong and extensive that it trumps any contractual choice of law provision made between parties.[vi]

The Fifth Circuit has developed a three part test for determining whether OCSLA’s choice-of-law provision is to apply: 1) The controversy must arise on a situs covered by OCSLA (i.e., the subsoil, seabed, or artificial structures permanently or temporarily attached thereto); 2) Federal maritime law must not apply on its own force; and 3) the state law must not be inconsistent with the federal law.[vii]  The first prong of the test requires determining whether the cause of action sounds in contract or in tort.   In a contract claim, the controversy arises where a majority of the contract work will be performed; whereas in a tort claim, the controversy arises where the injury took place.[viii]

W&T Offshore v. Apache, filed in the Southern District of Texas in 2011, involves a dispute surrounding the misallocation of oil and gas at an offshore storage and transfer facility owned and managed by Apache.[ix]  The facility is located off the coast of, and is adjacent to, Louisiana.[x]  In addition to a breach of contract claim, W&T has alleged that Apache’s misallocation gives rise to several tort claims, including fraud and negligent misrepresentation.[xi]  W&T argues that these tortuous actions did not, in fact, take place on the Outer Continental Shelf, but rather occurred in Apache’s corporate offices in Houston, Texas.[xii]  Thus, W&T contends that OCSLA’s choice-of-law provision, which would require Louisiana law to apply to these claims as the adjacent state to the facility, is not applicable to these tort claims as they did not take place on an OCSLA situs as required by Grand Isle.[xiii]  Rather, W&T argues that Texas law should apply as it is both the contractual choice of law and would be applied by a federal district court sitting in Texas following normal choice of law rules anyways.[xiv]

Apache has moved to dismiss W&T’s claims, and as part of their motion argue that OCSLA’s choice-of-law provision (thus, Louisiana law) should apply to all of W&T’s claims.[xv]  Apache’s primary argument is one of statutory interpretation.  They claim that the tort allegations stem from actions which fall under the OCSLA definition of “development” and are thus within OCSLA’s broad jurisdictional grant.  They contend that since “Development” includes the “operations of all onshore support facilities, which are for the purpose of ultimately producing the minerals discovered,” (emphasis added) even activities taking place onshore in Houston which pertain to the contract in question would fall under OCSLA’s jurisdiction, and thus require the application of Louisiana law.[xvi]

Apache’s secondary argument is that in applying the first prong of the OCSLA choice-of-law application test, whether the controversy arose on a situs covered by OCSLA, courts should employ the same “but for” test used to determine OCSLA jurisdiction.[xvii]  That is, W&T’s fraud and other tort claims arose out of, and would not exist but for, the alleged breach of contract.  And, as even W&T concedes, the breach of contract claim certainly arose on an OCSLA situs, as a majority of the production handling work to be performed under the contract would occur at the offshore storage and transfer facility.  Thus, Apache contends that Louisiana law should apply in this instance as well.[xviii]

The issue of whether such onshore activities, allegedly occurring in the corporate offices of Apache and W&T, fall within the jurisdiction of OCSLA (and thus require the application of the OCSLA choice-of-law provision) is one of first impression.  As of the submission of this post, the Southern District judge has yet to rule on Apache’s Motion to Dismiss.

How the court comes out on this issue may have some practical consequences.  For one, the ruling should provide further clarification (and perhaps establish a bright line rule) on how federal courts will handle the “situs” test for OCSLA jurisdiction and choice-of-law application.  A ruling for Apache will demonstrate firm support for the use of a “but for” test, while a ruling for W&T would show the court followed closely to the Grand Isle tort/contract distinction.

Further, and perhaps more importantly, if the court finds for Apache, then parties entering into agreements where a majority of work will take place on offshore platforms should realize that their contractual choice of law provisions will essentially have no effect whatsoever.  Even corporate action taking place onshore, as long as it results because of that agreement, will be under the jurisdiction of OCSLA.  Thus, the law of the state adjacent to the platform where the contract’s activity takes place will be applied regardless of the contractual preference of the parties.  Corporate attorneys drafting agreements to be carried out on the outer continental shelf should be aware of this potential ruling and advise their clients accordingly.

 

Will Thanheiser is a third year student at the University of Texas School of Law.

[i] 43 U.S.C.A. § 1349(b)(1)(A).

[ii] 43 U.S.C.A. § 1331(1).

[iii] See Texaco Exploration and Prod., Inc. v. AmClyde Engineered Prods., Inc., 448 F.3d 760, 774 (5th Cir. 2006) (“[T]he complaint arises on an OCSLA situs because the claims are inextricably linked to the construction of a platform permanently fixed to the Shelf for the purposes of development and would not have arisen but for such development.”)

[iv] Rodrigue v. Aetna Cas. & Surety Co., 395 U.S. 352, 356 (1969).

[v] 43 U.S.C.A. § 1333(a)(2)(A).

[vi] Union Tex. Petroleum Corp. v. PLT Eng’g, Inc., 895 F.2d 1043, 1050 (5th Cir. 1990).

[vii] Id.

[viii] Grand Isle Shipyard, Inc. v. Seacor Marine, LLC, 589 F.3d 778, 781-786 (5th Cir. 2009).

[ix] W&T Offshore’s Second Amended Complaint (filed June 28, 2012) (Docket #27).  Both W&T and Apache produce oil and gas from offshore platforms and then transfer their respective production to Apache’s storage and transfer facility.  The companies signed a Production Handling Agreement (the “Contract”), under which Apache is responsible for properly allocating the production to the appropriate party.  Generally, W&T contends Apache comingled the production and misallocated W&T’s share of the production, crediting a disproportionate amount of the production to Apache.

[x] Id.

[xi] Id.

[xii] W&T Reply to Apache Motion to Dismiss Second Amended Complaint (filed August 14, 2012) (Docket #29).

[xiii] Id.

[xiv] Id.

[xv] Apache Motion to Dismiss W&T’s Second Amended Complaint (filed July 17, 2012) (Docket #28).

[xvi] Id.

[xvii] Id. (citing Texaco, 448 F.3d at 774).

[xviii] Id.

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The Progress of Algae-Based Biofuel

Filed Under: Current Industry Issues, Industry Trends by admin — Leave a comment
October 26, 2012

By Brandon Chang

The rise of gas prices has fueled interest in finding alternative sources of energy that are low-cost, safe, clean, abundant, and renewable.  On October 24, 2010, Kate Beasley posted an entry on this blog exploring the benefits and costs associated with using algae-based biofuel over traditional feedstock biofuels.[i]  Since then, algae-based biofuel research has made significant progress.  This year Lufthansa, a German-based airline, agreed to finance a plant solely committed to producing biofuel and biofuel research has started to generate increasing economic activity.[ii]

Some of the benefits of algae-based biofuel explored previously include minimal resource requirements, lack of competition with crops for arable land, quicker growth periods than tradition biofuels, and environmental safety.[iii]  The development of algae-based biofuel research has led to confirmation of some of these theoretical benefits and, accordingly, algae-based biofuels have caught the attention of companies with significant fossil fuel demands.   On September 19, 2012, Lufthansa signed a financing agreement with Algae Tec to jointly build a large-scale algae-to-aviation biofuels production facility in Europe.[iv]  Additionally, Lufthansa agreed to purchase at least fifty percent of the fuel generated by the plant.[v]  This turn of events represents a significant endorsement of algae-based biofuels because Lufthansa announced in January of 2012 that it was ending its biofuel trials, citing unreliable supplies of plant-based biosynthetic kerosene.[vi]  The decision to pursue algae-based rather than plant-based alternatives to fossil fuels is a tacit acknowledgment that (1) algae-based biofuels require less resources to produce than other types of biofuels and (2) that algae-based biofuels enjoy more reliable and quicker production than other types of biofuels.[vii]  The Lufthansa-Algae Tec deal and other forthcoming algae-based biofuel deals could provide a chance to verify the theoretical benefits of algae-based biofuels in real-world situations, which in turn would lead to heavier investment in algae-based biofuel production.

The Lufthansa-Algae Tec deal might only be the beginning of growth in the algae-based biofuel industry.  In the airline industry, exploration into algae-based biofuel alternatives has not been limited to German companies.[viii]  Airlines in Brazil, India, England, France, Spain, and the United States have all been linked with biofuel companies looking to invest in the growth of the algae industry.[ix]  Additionally, major energy players, including BP, Chevron Corp., and ExxonMobil (with ExxonMobil reported to have already pledged $600 million to algae producer Synthetic Genomics), all have investments in algae now.[x]  In 2011, algae-based biofuel research generated $80.9 million in economic activity in California alone.[xi]  According to Pike Research, the algae-based biofuel industry could grow by 72 percent each year, cumulating in 61 million barrels of biofuel a year with a market value of $1.3 billion in 2020.[xii]  And that might even be a conservative estimate because algae-based biofuel does not enjoy the same tax benefits as other types of biofuel.[xiii]  Algae-based biofuel producers have been lobbying U.S. lawmakers to treat algae-based biofuel in a similar manner to the way ethanol is treated for tax purposes.[xiv]  Such tax incentives could advance the development of commercially viable algae-based biofuel by reducing the production costs needed to produce the biofuel and encourage more investment in the technology needed to bring algae-based biofuel to full commercial production.[xv]  Despite growing investment in the algae industry, there are still significant factors to be overcome before algae-based biofuels can enjoy widespread adoption.

Even the most zealous algae-based biofuel supporters (including companies that research and produce the biofuel) acknowledge that development of the biofuel must reach several milestones before it can be put into commercial production.  Chief among these milestones is sustainability and the “positive energy impact,” which means that it cannot take more energy to grow the algae than the amount of carbon dioxide that the algae can absorb, which eventually determines the algae’s energy output.[xvi]  After all, algae-based biofuels could hardly be called a low-cost, clean, abundant, and renewable energy resource if more energy is used to make the biofuel than the energy that biofuel itself provides.[xvii]  Concerns of sustainability have been noted in the algae industry and recently sustainability objectives were the topic of discussion at the 2012 Algae Biomass Summit.[xviii]  Suggested answers to the problem included advanced metrics to inform future assessments of algae-based biofuel and third-party certifications to verify the returns of using algae-based biofuel.[xix]  It is clear that algae-based biofuel research still has hurdles to overcome before it is more widely adopted.

Despite the issues that must be overcome, algae-based biofuels have the potential to significantly impact the energy industry.  From two years ago, when the original TJOGEL blog post on algae-based biofuels was written, until now there have been several major financing deals and investments made in the algae industry.[xx]  The energy industry’s continued work and investment in algae-based biofuel serves as an optimistic indicator that algae may indeed serve as a key low-cost, safe, clean, abundant, and renewable energy source.

Brandon Chang is a second-year JD student at The University of Texas School of Law.

[i] Kate Beasley, Is Algae Our Future?, TJOGEL Blog (Oct. 24, 2010), http://tjogel.org/blog/?p=44.

 [ii] Lufthansa, Algae Tec to Build Algae-based Biofuels Plant, Environmental Leader (Sept. 19, 2012), http://www.environmentalleader.com/2012/09/19/lufthansa-algae-tec-to-build-algae-based-biofuels-plant.

 [iii] Beasley, supra note 1.

 [iv] Lufthansa, Algae Tec to Build Algae-based Biofuels Plant, supra note 2.

 [v] Id.

 [vi] Id.

 [vii] See Beasley, supra note 1 (Listing theoretical benefits from the use of algae-based biofuels).

 [viii] Debra Fiakas, Emission Standards Driving Algae Aviation Fuel Sourcing… or Not, Alt Energy Stocks (Oct. 10, 2012, 8:55 A.M.), http://www.altenergystocks.com/archives/2012/10/emissions_standards_driving_algae_aviation_fuel_sourcingor_not_1.html.

 [ix] Id.

 [x] Ken Silverstein, Will Algae Biofuels Hit the Highway?, Forbes (May 20, 2012, 7:33 A.M.), http://www.forbes.com/sites/kensilverstein/2012/05/20/will-algae-biofuels-hit-the-highway.

 [xi] Karen E. Klein, Algae are a Growing Part of San Diego’s Appeal, Bloomberg Businessweek (October 11, 2012), http://www.businessweek.com/articles/2012-10-11/algae-is-a-growing-part-of-san-diegos-appeal.

 [xii] Silverstein, supra note 10.

 [xiii] See Id. (stating that a barrier to growth in the algae-based biofuel industry is securing tax incentives given to other advanced biofuels).

 [xiv] Id.

 [xv] Id.

 [xvi] Id.

 [xvii] See Silverstein, supra note 10; Klein, supra note 11 (stating that efficiency concerns still exist regarding prospective widespread adoption of algae-based biofuels.

 [xviii] Tom Bryan, Algae Industry Counseled on Sustainability Objectives at Summit, Biodiesel Magazine (September 26, 2012), http://www.biodieselmagazine.com/articles/8715/algae-industry-counseled-on-sustainability-objectives-at-summit.

 [xix] Id.

 [xx] See Lufthansa, Algae Tec to Build Algae-based Biofuels Plant, supra note 2; Fiakas, supra note 8 (listing financing deals to develop algae-based biofuel plants).

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Hydraulic Fracturing May be Safer for the Environment Than You Think

Filed Under: Industry Trends, Regulatory Issues, Uncategorized by admin — Leave a comment
October 26, 2011

by James Faulkner

Mr. Faulkner graduated from Texas A&M in  2007 with a B.A. in Communication. He spent the past two summers as the legal intern with the General Counsel department at CTIA, a trade association for the wireless industry. Prior to law school Mr. Faulkner worked in Office Services for DuBois, Bryant, & Campbell, LLP. Mr. Faulkner expects to receive his JD in May 2012.

Community and Environmental groups often express concern over the environmental impacts of using hydraulic fracturing to extract natural gas from shale formations. A simple Google search of “the dangers of fracking” will turn up thousands of hits. But is fracking really that much more dangerous than conventional types of drilling? A recent report by the Secretary of Energy Advisory Board (SEAB) Shale Gas Subcommittee supports the idea that while hydraulic fracturing has its risks, a few of the most common arguments  regarding the safety of hydraulic fracturing in comparison to conventional drilling are based less in fact, and more upon misconception and a lack of knowledge about the industry.

Background:

In 2001 natural gas produced from shale formations accounted for less than two percent of U.S. natural gas production. Today that figure is approaching 30 percent. This increase in production can be attributed primarily to developments in hydraulic fracturing and horizontal drilling. Hydraulic fracturing to obtain shale gas involves pumping fluid into wellbores at high pressure in order to create fractures in the shale and release natural gas from the shale formation.  Due to the rapid increase in hydraulic fracturing in the United Sates and public concerns over the environmental and safety repercussions of the practice, President Obama instructed the Secretary of Energy to form a subcommittee of the SEAB to make recommendations addressing the safety and environmental performance of shale gas production. The subcommittee was tasked with reporting to the SEAB within 90 days as to the immediate steps that could be taken to improve the safety and environmental performance of fracturing. That report was released on August 18th and members of the committee subsequently testified as to their findings before the Senate Subcommittee on Energy and Natural Resources on October 4th. In the report, the SEAB Subcommittee touched on a number of arguments most commonly raised in opposition to hydraulic fracturing.

Common Arguments Against Hydraulic Fracturing:

Risk of Hydraulic Fluid Leakage into the Water Supply:

Among the most commonly perceived risks from hydraulic fracturing was the possibility of hydraulic fluid traveling through underground fractures into the water supply. However, the report notes there is consensus among regulators and geophysical experts that the risk of this type of hydraulic fluid migration is remote. In the majority of regions where fracturing is utilized, the large depth of separation between drinking water sources and producing zones makes the risk of fluid migration unlikely. Additionally, despite concerns over the fluid migration into water supplies, the committee could find few if any documented examples of this actually happening.

Risk from the Composition of Fracturing Fluids:

Not only are fluids unlikely to travel through fractures into the water supply, the hydraulic fracturing fluids may not be as dangerous as many believe them to be. The report recognizes a “high level” of public concern over the composition of fracturing fluids which are injected at high pressure into the ground. It appears the concern over the composition of fracturing fluids may be due to misinformation more than anything else. In written testimony to the Senate Committee on Energy and Natural Resources, Stephen A. Holditch, a member of the SEAB Shale Gas Subcommittee, stated:

If you read recent news articles on hydraulic fracturing, the process is often described as pumping in a mixture of water and toxic chemicals under high pressure.  This description is far from the truth.   Most fracture treatment fluids consist of 99.5% percent pure water and sand.   About 0.5% of the fluid is made up of gelling agents, surfactants, and biocides.  Virtually all of these chemicals can be found in a typical home.  Gelling agents are typically guar gum, which is used in many food products to viscosify the product.   A surfactant is just soap, like Dawn dishwashing fluid.   Biocides are use to kill bacteria, like the Clorox we use in our homes.  Granted, we do not want to drink these fluids, but they are all found in our homes.  However, the concentration of these ‘chemicals’ is very minute and does not pose a danger to fresh water aquifers, if the field operations are conducted properly.

Risk of Methane Migration into Surrounding Areas:

The risk of methane leaking into surrounding drinking wells is another risk cited in opposition to hydraulic fracturing. The report recognizes the risk that methane leaking from producing wells into other areas as a cause for concern, though they caution that, “the presence of methane in wells surrounding a shale gas production site is not ipso facto evidence of methane leakage from the fractured producing well since methane may be present in surrounding shallow methane deposits or the result of past conventional drilling activity.”  The report also notes that industry experts believe that when methane migration does occur, is the result of, “drilling a well in a geologically unstable location; loss of well integrity as a result of poor well completion (cementing or casing) or poor production pressure management.” These dangers are not specific to hydraulic fracturing. The report explicitly notes that, “a well with poorly cemented casing could potentially leak, regardless of whether the well has been hydraulically fractured.”  Thus the risk of methane leakage cannot be used to single out hydraulic fracturing as any more dangerous than any other form of conventional drilling.

Conclusion:

The SEAB Subcommittee report and the testimony of the subcommittee members provide evidence that at least three of the most common arguments against hydraulic fracturing are based upon misconceptions over the process of hydraulic fracturing rather than actual risks. While a few groups have had some success whipping up public concern over hydraulic fracturing, the evidence suggests that perhaps fracking is not the great danger that its opponents allege it to be.

Sources:

Secretary of Energy Advisory Board, Shale Gas Production Subcommittee: 90-Day Report, August 18, 2011, available at http://www.shalegas.energy.gov/resources/081811_90_day_report_final.pdf

Written Testimony of Stephen A. Holditch  before the Committee on Energy and Natural Resources, United States Senate, October 4, 2011, available at http://energy.senate.gov/public/index.cfm?FuseAction=Hearings.Testimony&Hearing_ID=b6244826-03fe-5e7c-63a7-ce0cdbb9f141&Witness_ID=60dda64c-e494-4958-8dc0-b7d3ad62334a

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EPA’s Cross-State Air Pollution Rule (CSAPR) Carries Heavy Consequences for Texas

Filed Under: Energy in Texas, Industry Trends, Regulatory Issues by admin — Leave a comment
October 18, 2011

by Jaron Hudgins

Mr. Hudgins graduated from the University of Okahoma in 2010 with a degree in History. He worked full-time at Cox Communications from 2004-2010 while attending OU. Mr. Hudgins will be working this summer at Hall Estill and is expected to graduate in May 2013.

Origins of EPA’s CSAPR and Why It Matters to Texas

The U.S. Environmental Protection Agency (EPA) drafted the Cross-State Air Pollution Rule (CSAPR) to limit the interstate transport of emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2) to downwind states in nonattainment areas. The EPA drafted the CSAPR in response to the 2008 decision in North Carolina v. EPA. In that decision, the D.C. Circuit Court of Appeals vacated EPA’s Clean Air Interstate Rule (CAIR), holding that the rule had serious flaws that violated the Clean Air Act (CAA). The Court’s holding required the EPA to develop a replacement rule to address the Court’s concerns.

Early drafts of the CSAPR did not include Texas in the annual SO2 and NOx emissions reduction program. Within the last year, however, the EPA changed its methodology for estimating emissions from Texas in its emissions models. Texas Attorney General Greg Abbott expressed in his challenge to the rule that the EPA’s new methodology is questionable. The EPA based its decision to raise Texas’ SO2 contribution level from .13 to .18 on a single air quality receptor reading in Granite City, Illinois. While numerous states contributed far more SO2 emissions to the Granite City reading, the EPA decided to use this single instance to move Texas above the .15 threshold.

On August 8, 2011, the EPA published its final proposed rule, placing caps on electric generating units (EGUs) in 27 states and requiring 23 states, including Texas, to drastically reduce SO2 and NOx emissions back to 1997 National Ambient Air Quality Standards (NAAQS) levels. Compliance to CSAPR’s annual SO2 and NOx reduction program is required starting on January 1, 2012, and compliance to the seasonal NOx emissions reduction program is required starting on May 1, 2012. By requiring Texas EGUs to execute such an immediate and severe reduction in emissions, the CSAPR carries heavy consequences for Texas.

What EPA’s CSAPR Requires of Texas

One of the alarming aspects of the CSAPR is how quickly states must gain compliance before penalties begin. The CSAPR requires significant reductions in SO2 and NOx emissions, and EGUs within affected areas must take significant measures to meet compliance by the January 1, 2012 deadline. The CSAPR caps 2012 SO2 emissions at 3,385,929 tons compared to recent SO2 emissions of a little over 5 million tons. Recent NOx levels have to be reduced from 1,595,756 tons to the 2012 NOx emissions cap of 1,245,869 tons.

The new rule will require Texas power plants to reduce SO2 emissions by 42% and NOx emissions by 7%. Luminant, the largest power generator in Texas, stated that the new rule requires it to reduce SO2 emissions in its fossil fuel generating units by 64%. The SO2 reduction requirements placed on Texas constitute 25% of the overall reduction requirements in the emissions program. The burden placed on Texas is twice its contribution in emissions.

Likely Consequences of EPA’s CSAPR on Texas

The CSAPR creates considerable increases in the costs of compliance as compared to past rules. As with most cap and trade programs, the EPA expects that the marketability of allowances will help reduce compliance costs. The Integrated Planning Model (IPM) that the EPA utilized to determine the emissions cap depends upon a different formula than previous models that used historical operations to estimate appropriate budgeting. The IPM’s state caps are based on highly cost effective controls that may not be feasible for many EGUs to implement. By not using historical operations, there is the danger of overestimating the ability of EGUs to affordably reduce emissions to EPA’s expectations. Such overestimation would likely result in fewer available permits than the market would need to keep costs down. Roger Caiazza, Director of the Environmental Energy Alliance of New York, described the reduction program as a “direct control approach masquerading as cap-and-trade.” The result, he says, will be a “cap and trade program that could run out of available allowances for compliance.”

The possible scarcity of allowances is coupled with severe penalties for noncompliance. Each ton of excess emissions constitutes a violation of the CAA, and each violation carries a maximum penalty of $25,000. The required reduction levels under the CSAPR and uncertainties regarding future levels create a furthered lower expectation for the marketability and availability of permits. As such, power companies are preparing to make significant changes to remain in compliance.

The changes that Texas power generators will have to make in order to meet CSAPR requirements are likely to carry heavy consequences for Texans. In compliance with the protocol of the Electric Reliability Council of Texas (ERCOT), Luminant submitted its operational response plan to ensure compliance to the CSAPR’s limits. Luminant’s plan indicates what actions power generators across the emissions program area will have to take to ensure compliance.

Luminant announced that it will have to close operations at several sites to remain in compliance because the CSAPR’s January 2012 deadline does not provide Luminant enough time for the permitting, construction and installation of the environmental control equipment necessary to maintain operations. At Luminant’s Monticello Power Plant, Units 1 and 2 will be idled, while Unit 3 will cease using Texas lignite and operate solely on Powder River Basin coal. The Thermo and Winfield mines will cease mining Texas lignite. At Luminant’s Big Brown Power Plant, Units 1 and 2 will cease using Texas lignite and operate solely on Powder River Basin coal. The Big Brown/Turlington mine will also cease mining Texas lignite.

The cessation of operations to meet compliance with CSAPR is projected to result in approximately 500 job losses at Luminant. Additional costs include reduced tax contributions in the communities affected by the cessation of operations, among other costs.

Luminant projects that expenditures on environmental control equipment to upgrade its capabilities to meet CSAPR’s limits will cost approximately $280 million. Luminant expects more than $1.5 billion in costs before the end of the decade to remain in compliance with CSAPR.

Further consequences of CSAPR compliance include increased unreliability. The Monticello units produce 1,2000 megawatts. Statewide, ERCOT estimates that power generation capacity may be reduced by as much as 1,500 megawatts, enough to cause rolling blackouts throughout parts of Texas.

Legal Responses to EPA’s CSAPR

On August 5, 2011, Luminant requested EPA to reconsider and stay the rule due to the probable consequences of the CSAPR on Luminant and Texas. The EPA’s September 11 letter to Luminant did not provide relief. In response, on September 15, 2011, Luminant filed a petition with the D.C. Circuit Court of Appeals requesting that the court invalidate the CSAPR as it relates to Texas. Luminant’s petition argues 1) that the EPA failed to give fair notice and opportunity to provide comment, 2) that Texas bears an unfair burden of reduction in comparison to its emissions contribution, 3) that the EPA improperly elevated its modeled percentage of Texas SO2 emissions over actual conditions, 4) that the NOx emissions were similarly improperly elevated over actual conditions, and 5) that compliance with the CSAPR’s requirements will jeopardize the reliability of Texas’s electric grid and cause hundreds of job losses.

Other states, power generators, and other interests have filed suit since EPA finalized the CSAPR. Kansas Attorney General Derek Schmidt filed suit against the EPA on September 19, 2011, stating the same complaints against the EPA as numerous other affected states.

On September 21, 2011, Texas Attorney General Greg Abbott filed a motion for stay with the D.C. Circuit Court of Appeals against the EPA. The Attorney General’s press release noted that “because the EPA opted not to include the State of Texas in key aspects of the proposed CSAPR regulations…and added Texas without notice to the final regulations…the rule violated federal law and should be stayed by the Court.” The Attorney General’s petition argues that the EPA 1) violated public notice and comment requirements, 2) altered the standards used to consider states in order to include Texas, and 3) relied on just one downwind site that was actually in compliance but had a connection to Texas as a basis to skew the emissions modeling data to bring Texas under the CSAPR.

On September 22, 2011, Attorney General Greg Abbott, along with attorney generals from Alabama, Florida, Oklahoma, South Carolina, and Virginia, joined Nebraska’s suit against the EPA over the CSAPR.

While the outcome of the current litigation against the EPA’s CSAPR is uncertain, what is certain is that if the litigation is unsuccessful in gaining a stay on the rule, there will be heavy consequences for Texas.

Article Update as of 10-23-11:

Reacting to the widespread opposition to the rule, the EPA proposed some revisions on the state budget limits, increasing them by 1-4%. The EPA has also now stated that while the trading programs will begin on January 1, 2012, companies will have until the end of 2012 or early 2013 to be in compliance.

http://www.gpo.gov/fdsys/pkg/FR-2011-10-14/pdf/2011-26521.pdf

http://www.epa.gov/crossstaterule/pdfs/CSAPRStatement.pdf

Major Change: the EPA’s allowance forfeiture and financial penalty process will begin starting January
1, 2014, rather than 2012, allowing companies additional time to come into compliance.
Here is an additional link that discusses the changes:
http://www.energyblogs.com/theoptimizationblog/index.cfm/2011/10/14/CSAPR-Update-The-Kinder-Friendlier-Ghost

Sources

EPA’s final CSAPR:

http://www.gpo.gov/fdsys/pkg/FR-2011-08-08/pdf/2011-17600.pdf

For more specific information on the EPA’s CSAPR:

http://www.epa.gov/airtransport/stateinfo.html#states

http://www.epa.gov/airtransport/

http://www.epa.gov/airtransport/pdfs/DavidCampbell.pdf

http://www.epa.gov/airtransport/basic.html

For Lesley Foxhall Pietras’ views on EPA’s CSAPR:

http://www.theenergylawblog.com/

For Roger Caiazza’s views on EPA’s CSAPR:

http://www.masterresource.org/2011/09/epa-cross-state-rule-cap-trade/

For the statement by Energy Future Holdings (parent company of Luminant):

http://www.hotstocked.com/8-k/–918772.html

For Luminant’s press release:

http://www.luminant.com/news/newsrel/detail.aspx?prid=1218

For Texas Attorney General Greg Abbott’s press release:

https://www.oag.state.tx.us/oagnews/release.php?id=3857

For N.C. v. EPA:

http://www.epa.gov/cair/pdfs/05-1244-1127017.pdf

Other sources:

http://www.ksag.org/page/attorney-general-schmidt-challenges-new-epa-regulations

http://www.oag.state.ok.us/oagweb.nsf/0/b24bfd8eb57a140d8625791400700ade/$FILE/Nebraska%20Petition%20for%20Review.pdf

http://www.powermag.com/POWERnews/Kansas-Sues-EPA-on-CSAPR-Rule_4040.html

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Advancements in Deep-Water Well Containment Technology

Filed Under: Industry Trends, Regulatory Issues by admin — Leave a comment
April 25, 2011

By Chris Blair

Mr. Blair graduated from the University of Minnesota in 2007 with a B.A. in Law and Politics. This summer he will be clerking for Haynes & Boone in Dallas. He expects to receive his J.D. from the Texas School of Law in 2013.

I. Introduction

As we look back at the one-year anniversary of the Deepwater Horizon blowout, allowances for permits for new deep-water drilling projects remains relatively sluggish. However, the noticeably cautious stance of federal regulators with the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) – routinely derided by critics as a product of regulatory excess – seems to have yielded to both necessity and technological advances. Recent developments in deep-water well containment technology have provided solutions to a beleaguered field, creating opportunities for safe and effective access to deep-water oil fields by utilizing risk-management strategies adapted to an open-ocean blowout like that which occurred on April 20, 2010. Within the past month, several new permits for deep-water drilling have been approved after months of postponement, largely due to such innovation. View full article »

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The Keystone Controversy

Filed Under: Industry Trends, International Energy Law, Regulatory Issues by admin — Leave a comment
April 14, 2011

By Jamie Leader

Mr. Leader graduated from Georgetown University in 2009 with a B.A. in History and Political Economy. This summer he is clerking in Houston at Fulbright & Jaworski and Vinson & Elkins. He expects to receive his J.D. from the Texas School of Law in May 2012.

There are over 2 million miles of pipeline running through the United States, but a Canadian company’s plan to add just 1,600 miles to that total has created a controversy than spans from Nebraska to east Texas. The pipeline, called the Keystone XL, is controversial not for where it goes, but what it carries: crude oil extracted from tar sands. View full article »

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Why the Texas Railroad Commission Needs a Name Change

Filed Under: Industry Trends, Regulatory Issues by admin — Leave a comment
April 4, 2011

By Jack Oberstein

Mr. Oberstein graduated from the University of Texas with a B.S. in Communications in 2008 and a minor in Business Administration. This summer he will be clerking for K&L Gates in Dallas. He expects to receive his J.D. from the Texas School of Law in May 2012.

When asked what the Texas Railroad Commission does, most people would say that it’s in charge of Texas railroads. But the Railroad Commission has nothing to do with railroads—it regulates the oil and gas industry. Accordingly, the legislature is considering renaming the Commission. While this seems simple enough, there are those who oppose the change due to the name’s historical significance and the costs involved. Nevertheless, it’s time for change— changing the Railroad Commission’s name will increase its transparency and accountability.

View full article »

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Debating the Texas Solar Energy Bill

Filed Under: Industry Trends, Regulatory Issues by admin — Leave a comment
March 28, 2011

By Jordyn Johnson

Ms. Johnson graduated from the University of Texas at Austin in 2010 with a B.A. in Government. This summer, she is interning at the Texas Advocacy Project and with Judge Lawrence Meyers at the Texas Court of Criminal Appeals. She expects to receive her J.D. from the Texas School of Law in May 2013.

Just over a decade after the Texas legislature jump-started the state’s wind energy industry in 1999, Texas has become the top-producing state for wind-generated electricity. The legislature is now considering a bill that would serve to stimulate other renewable energy sources, including solar energy, with similar subsidization. Although a recent study lists Texas as the 10th-largest solar energy market in the U.S., the study also observed that while interest in solar energy is rising, the incentives for promotion of solar energy are not growing at the same rate. While the drive for solar energy use is fairly high at the individual residential level, the lack of a statewide program has caused Texas to fall behind its renewable energy sister states. A goal of the proposed legislation is to provide incentives for energy companies similar to those offered by states such as California and New Mexico. View full article »

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