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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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Brackish Water: Fracking’s Future?

Filed Under: Energy in Texas, Regulatory Issues, Uncategorized by admin — Leave a comment
February 21, 2013

By Koby Kirkland

Last year, TJOGEL editor Mike Marek published an entry on this blog addressing concerns about the effects of hydraulic fracturing on Texas’s water supply.[1]  Looking to the future, Marek points out that legislative action may be needed to protect the state’s water supply for future generations.  One course of action available to the legislature is to provide incentives to oil and gas producers to use the state’s substantial reserves of brackish water, instead of continuing to deplete Texas’s fresh water supply.

Hydraulic fracturing requires a tremendous amount of fresh water.  Depending on well type, between 1.2 to 3.5 million gallons (4 to 11 acre-feet) of water may be consumed in hydraulically fracturing a gas well.[2]  In the last several years, various “hot spots” of increased oil and gas production have appeared in Texas.  Activity in north Texas, centered around the Barnett Shale, is one such hot spot.  In a trend mirrored by other hot spots, as gas development in the Barnett Shale increased, water use also increased.  Water used for Barnett Shale gas development rose from approximately 700 acre-feet (“AF”) in 2000 to more than 7,000 AF in 2005.[3]

Approximately 60% of the water used in the Barnett Shale development was obtained from the Trinity and Woodbine aquifers in north central Texas.[4]  Many rural areas in north Texas rely exclusively on groundwater from the Trinity aquifer.  In fact, many rural areas across Texas obtain their water from the same sources as oil and gas producers.[5]  The conflict set up by this situation will not go away anytime soon.

Projections show water use for fracking is expected to increase exponentially over the next decade.  The Texas Water Development Board estimates the total amount of water used for fracking statewide in 2010 was 13.5 billion gallons . . . .  That’s likely to more than double by 2020 and decline gradually each decade after that until dropping back down to current levels between 2050 and 2060.[6]

At the same time as water use for fracking is increasing, the water supply itself is shrinking due to dry conditions in many parts of the state.  The drought, besides fuelling wildfires, ruining crops, and putting a strain on Texas’s electric grid, has taken an alarming toll on the state’s water supplies.[7]  The urgency of this situation was highlighted in January of this year when wells in Spicewood Beach, Texas ran completely out of water.[8]  In response, the Lower Colorado River Authority (“LCRA”) began trucking in water from other parts of Texas until it could find a long-term solution to the problem.  At first, the LCRA agreed to pay the increased costs of trucking in the water, but eventually told residents they could have to start paying extra for the trucked-in water.[9]

Pushing the increased costs of fresh water on to the community is not unique to Spicewood Beach.  In Odessa, Texas, a city at the center of the west Texas oil and gas hot spot, city residents were recently hit with a 40% increase to their water rates.[10]  This rate hike comes on top of the city’s already-high cost of living.[11]

One possible solution to the problems associated with low water supply and high water costs may lie with brackish water.  Texas has a large reserve of brackish water in its aquifers—almost 2.7 billion acre-feet of groundwater.[12]  There are 325,851 gallons in one acre-foot of groundwater.[13]  Thus, the 2.7 billion acre-feet of brackish water in Texas aquifers comes out to approximately 879 trillion gallons of brackish water.  Even if projections of industry water use more than doubling are realized, at least in theory, brackish water could satisfy hydraulic fracturing water needs well into the future.[14] [15]

Not only is brackish water available, it is located in regions of the state that also happen to be major hot spots of oil and gas production.[16]  “While nearly every geographical region of the state has some brackish water, west Texas, north-central Texas . . . South Texas, and the Gulf Coast regions have the most significant amounts of brackish water.”[17]  This alignment presents an opportunity.

Most operators use fresh water for hydraulic fracturing because it is more effective than using impure, but abundant, brackish water.  However, in some instances brackish water serves as a viable substitute.[18]  If oil and gas producers were given an incentive, perhaps in the form of a tax credit, then they might often choose to use brackish water in their fracking activities.

At present, oil and gas producers have no real financial incentive to not use fresh water.  Recently, however, the Texas legislature passed a disclosure bill requiring operators to report “the total volume of water used in the hydraulic fracturing treatment.”[19]  A tax credit could be based directly on the disclosed amount of brackish water used.  If operators are given an incentive to use brackish water, then they may choose to do so more often.  This would free up fresh water for the use of Texas residents, farmers and ranchers, and Texas businesses.

A similar but more politically-difficult solution would be a tax penalty on producers using fresh water in fracking.  The tax could be based on the disclosed number of gallons of fresh water used.  Like the proposed tax credit, such a tax would be used to discourage operators from using fresh water in fracking and encourage use of Texas’s abundant reserves of brackish water.  This measure is certain to meet with resistance from oil and gas producers, but given the depth of Texas’s water problem and the undeniable importance of fresh water, it may be a fight worth having.  As a representative of Apache Corp. stated, “[w]e’re using scarce resources to get scarce resources.”[20]

No one wants to undermine an industry that props up the state’s economy or add costs to the already-substantial expenses involved in hydraulic fracturing.  But the fact remains that water is special; it is a resource that humanity requires for survival.  Something must be done about the fresh-water situation in Texas.  Either fresh water must be conserved or new techniques must be developed to allow producers to reuse water. The general trends affecting fresh water use are indisputable: Texas’s population is growing and oil and gas production is rising.  Thankfully, there are actions the state can take to avert a serious water crisis, which could come to an ugly head in the future.

 

Koby Kirkland is a second-year student at the University of Texas School of Law.  He is from West Texas and worked in the oilfield before attending law school.

 

[1] Mike Marek, Edwards Aquifer Authority v. Day and the Future of Groundwater Regulation for Hydrofracturing in Texas, TJOGEL Blog (Oct. 7, 2012) http://tjogel.org/blog/?p=206.

[2] Congressional Research Service, Unconventional Gas Shales: Development, Technology, and Policy Issues (Oct. 30, 2009) http://www.fas.org/sgp/crs/misc/R40894.pdf.

[3] See id.

[4] Congressional Research Service, Unconventional Gas Shales: Development, Technology, and Policy Issues (Oct. 30, 2009) http://www.fas.org/sgp/crs/misc/R40894.pdf.

[5] See id.

[6] Kiah Collier, Texas’ second oil boom costs precious water, San Angelo Standard Times (June 25, 2011) http://www.gosanangelo.com/news/2011/jun/25/one-scarce-resource-for-another-water-151-and-of/.

[7] State Impact, Everything You Need to Know About the Texas Drought, http://stateimpact.npr.org/texas/tag/drought/.

[8] Id.

[9] Terrence Henry, When Wells Run Dry: Spicewood Beach, Texas is Out of Water, State Impact (Jan. 31, 2012) http://stateimpact.npr.org/texas/2012/01/31/when-wells-run-dry-spicewood-beach-is-out-of-water/.

[11] Lyxan Toledanes, Cost of living high in a boom town, Odessa American (Aug. 31, 2012) http://www.oaoa.com/people/lifestyle/article_01b9799e-5a70-53fc-985b-90e9cfa83f1f.html?mode=story.

[12] See Sanjeev Kalaswad, Brackish Groundwater in Texas, Texas Water Development Board, http://www.twdb.state.tx.us/publications/reports/numbered_reports/doc/R363/B2.pdf (citing to a study conducted for the Texas Water Development Board suggesting that there are approximately 2.7 billion acre-feet of brackish water in the state’s aquifers).

[13] Bill Peacock, Understanding Water Units, University of California–Davis, http://cetulare.ucdavis.edu/files/82041.pdf.

[14] See Kiah Collier, Texas’ second oil boom costs precious water, San Angelo Standard Times (June 25, 2011) http://www.gosanangelo.com/news/2011/jun/25/one-scarce-resource-for-another-water-151-and-of/.

[15] To be sure, there are likely technical issues that preclude brackish water being exclusively employed in fracking.

[16] Eugene M. Kim, Oil and Gas Production in Texas, Bureau of Economic Geology, http://www.beg.utexas.edu/UTopia/images/pagesizemaps/oilgas.pdf.

[17] Sanjeev Kalaswad, Brackish Groundwater in Texas, Texas Water Development Board, http://www.twdb.state.tx.us/publications/reports/numbered_reports/doc/R363/B2.pdf.

[18] Kiah Collier, Texas’ second oil boom costs precious water, San Angelo Standard Times (June 25, 2011) http://www.gosanangelo.com/news/2011/jun/25/one-scarce-resource-for-another-water-151-and-of/.

[19] Id.

[20] Kiah Collier, Texas’ second oil boom costs precious water, San Angelo Standard Times (June 25, 2011) http://www.gosanangelo.com/news/2011/jun/25/one-scarce-resource-for-another-water-151-and-of/.

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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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Innovative Technology’s Potential Influence on Hydraulic Fracturing Regulation

Filed Under: Current Industry Issues, Regulatory Issues by admin — Leave a comment
November 11, 2012

By Michael Cramer

On October 7, 2012, TJOGEL editor Mike Marek published an entry on this blog on the way Texas regulates groundwater used during hydrofracturing.[i] He focused on regulations over the issue of groundwater scarcity. Groundwater scarcity is a growing problem in West Texas, since Texas has a finite water supply, and hydrofracturing requires the use of thousands of gallons of water for every hydrofracturing well.[ii] As Marek suggested, this issue can be addressed by legislation—but it can also be addressed by technology.

Technology and legislation are not mutually exclusive; for example, the Environmental Protection Agency (EPA) identified that “scrubbers”—which remove toxins from smoke stacks—are a feasible technology that effectively reduces air pollution. The EPA requires that coal power plants use scrubbers or comparable technology in order to comply with the Clean Air Interstate Rule.[iii] Just as new technology related to coal power plants influenced regulations, new technology related to hydrofracturing may also influence regulations.

The energy company GasFrac Services has developed a hydrofracturing technology that no longer requires the use of on-site water. Presently, hydrofracturing involves pumping fluids consisting of around 99% water—called a proprietary solution —into the ground. Energy companies currently use water because it is cheap, abundant and safe.  However, in places like West Texas, where water may become less abundant, it makes sense to switch to a different technology that does not use ground water. GasFrac Services has developed a hydrofracturing technique that uses gelled propane instead of water. This technique uses high pressure to create gelled propane, which is then brought on-site. When compared to hydrofracturing with water, hydrofracturing with gelled propane reduces formation damage, which results in better overall recovery and may therefore even increase profits.[iv]

Like every technology, hydrofracturing with gelled propane has its drawbacks. Even though gelled propane solves hydrofracturing’s need for on-site water, water is required to create gelled propane. [v] Therefore, gelled propane partially redistributes water use, rather than replacing the need for it altogether.

Additionally, safety is an issue.  Because the gelled propane is constantly under high pressure, it has the potential to leak. [vi] If a leak ignited, it could lead to an explosion. However, this risk is also present when hydrofracturing uses water instead of gelled propane, since hydrofracturing with water extracts combustible natural gas from the ground.

In addition to water scarcity, another concern over hydrofracturing is the fear of water contamination. This is because hydrofracturing involves pumping proprietary solutions into the ground, which consist of chemicals that, if leaked into a water supply, may be harmful to the drinker’s health or safety.[vii] Despite studies showing that hydrofracturing has a remote chance of groundwater contamination,[viii] public outcry has caused legislatures to reevaluate the risk-to-benefit calculus of hydrofracturing.[ix]

Just as technology can help address regional water scarcity, technology may also aid in addressing groundwater contamination. Halliburton has developed a proprietary solution called CleanStim Formulation.[x] This solution addresses environmental concerns because it is made from ingredients sourced solely from the food industry. This means that hypothetically, if contamination occurs, “an extra margin of safety” is added since the chemicals injected into the ground are limited to those used by the food industry.[xi] This does not mean that the CleanStim formulation is intended for consumption, even though an employee of Halliburton demonstrated the safety of this solution by drinking it.[xii]

Technologies like CleanStim are helpful, but not perfect in solving water contamination. If a leak occurs, both natural gas and the proprietary solution may be released into the groundwater. Even if the proprietary solution is harmless, natural gas is still not desirable in a water supply (i.e. in a groundwater well or pipes). However, technology like CleanStim is a step in the correct direction, and lessens concerns over groundwater contamination overall. Thus, it is conceivable that agencies may one day require energy companies to use a safe proprietary solution, like one sourced from the food industry.

The use of hydrofracturing is growing and therefore, so is the need to address concerns associated with it. Between 2005 and 2010, the popularity of hydrofracturing in the U.S. grew by 45% a year.[xiii]  Hydrofracturing is popular among U.S. landowners because it provides the potential to make millions of dollars simply by consenting to hydrofracturing operations on their property.[xiv] On top of this, political and economic factors have turned hydraulic fracturing from an unknown concept into an extraction method that is now common. Hydrofracturing reduces the U.S.’s dependence on foreign sources of energy and generates domestic jobs. In fact, the U.S. may begin exporting natural gas, in contrast to our history of importation.[xv] Because of hydrofracturing’s prevalence, there is an apparent need for innovative technologies such as gelled propane and CleanStim.

Michael Cramer is a second year student at the University of Texas School of Law. He previously lived in Upstate New York, where he witnessed the expansion of natural gas production transform the economic landscape. This perspective attuned him to the necessity of technology in keeping up with popular methods of natural gas production.


[i] Mike Marek, Edwards Aquifier Authority v. Day and the Future of Groundwater Regulation for Hydrofracturing in Texas, TJOGEL Blog (Oct. 7, 2012), http://tjogel.org/blog/?p=206.

[ii]  Hydraulic Fracturing Research Study, Envtl. Prot. Agency (June 2010), http://www.epa.gov/safewater/uic/pdfs/hfresearchstudyfs.pdf.

[iii] Controlling Power Plant Emissions: Overview, Envtl. Prot. Agency, http://www.epa.gov/hg/control_emissions/index.htm (last updated Feb. 7, 2012); see also Basic Information, Envtl. Prot. Agency, http://www.epa.gov/ttn/catc/rblc/htm/welcome_eg.html (last updated Jan. 24, 2012).

[iv] Scott McNally, Guest Post: Waterless Fracking? Scientific American (Oct. 10, 2012), http://blogs.scientificamerican.com/plugged-in/2012/10/10/guest-post-waterless-fracking/.

[v] Id.

[vi] Id.

[vii] Chemicals Used In Hydraulic Fracturing, U.S. H.R. Comm. On Energy and Commerce, (April 2011), http://democrats.energycommerce.house.gov/sites/default/files/documents/Hydraulic%20Fracturing%20Report%204.18.11.pdf; see also Fluids Disclosure, Halliburton, http://www.halliburton.com/public/projects/pubsdata/Hydraulic_Fracturing/fluids_disclosure.html (last visited Nov. 9, 2012).

[viii] James Faulkner, Hydraulic Fracturing May be Safer for the Environment Than You Think, TJOGEL Blog (Oct. 26, 2011), http://tjogel.org/blog/?tag=natural-resources.

[ix] See Mary Esch, New York Fracking Moratorium Unlikely To Be Lifted As Regulators Reopen Rulemaking Process, The Huffington Post (Oct. 1, 2012), http://www.huffingtonpost.com/2012/10/01/new-york-fracking-moratorium_n_1928884.html; see also Supplemental Generic Environmental Impact Statement, N.Y. State Dep’t of Envtl. Conservation (Sept. 30, 2009), http://www.dec.ny.gov/data/dmn/ogprdsgeisfull.pdf.

[x]  CleanStim Hydraulic Fracturing Fluid System, Halliburton http://www.halliburton.com/ps/Default.aspx?navid=93&pageid=4184&prodid=PRN%3a%3aKWTBF215&TOPIC=HydraulicFracturing (last visited Oct. 28, 2012).

[xi] Id.

[xii] Evan Bush, Haliburton Introduces “CleanStim” Fracking Solution & Gas Worker Takes a Drink: Environmental Groups Weigh In, The Erie Wire (Aug. 18, 2011), http://www.eriewire.org/archives/12727/section/wire/.

[xiii] Shale of the Century, Economist (June 2, 2012), http://www.economist.com/node/21556242.

[xiv] Mireya Navarro, Over Land, Money and Gas, The N.Y. Times (Nov. 27, 2009), http://www.nytimes.com/2009/11/28/science/earth/28drill.html?_r=2&pagewanted=all.

[xv] Benjamin Lefebvre, Should the U.S. Export Natural Gas?, The Wall Street Journal (Sept. 13, 2012), http://online.wsj.com/article/SB10000872396390444226904577561300198957854.html; see also Mark Scott, The Big New Push to Export America’s Gas Bounty, The N.Y. Times (Oct. 23, 2012),

http://www.nytimes.com/2012/10/24/business/energy-environment/excelerate-energy-aims-to-be-a-leader-in-natural-gas.html?_r=0.

 

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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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Edwards Aquifer Authority v. Day and the Future of Groundwater Regulation for Hydrofracturing in Texas

Filed Under: Current Industry Issues, Energy in Texas, Recent Cases, Regulatory Issues, Uncategorized by admin — Leave a comment
October 7, 2012

By Mike Marek

On October 26, 2011, TJOGEL editor James Faulkner published an entry on this blog debunking several common misconceptions related to hydraulic fracturing’s environmental impact. As Faulkner correctly points out, allegations that the hydrofracturing process contaminates the water supply lack firm scientific support and were not substantiated by government inquiries such as the Secretary of Energy Advisory Board report cited to in his entry.[i] [ii] [iii]

One aspect of hydrofracturing that has received less attention outside of Texas is the sheer amount of groundwater consumed by the process. Historically, groundwater usage in Texas has been governed by the Rule of Capture, which gives landowners ownership of any water they can pump to the surface. Some refer to this as “the law of the biggest pump” because it shields the landowner with the deeper well and bigger pump from liability if he makes his neighbor’s well go dry.[iv] The Rule of Capture protects oil and gas operators who own only the mineral estate as well.  Because Texas common law stipulates that the mineral estate is the dominant estate, the owner of mineral rights may use groundwater in any amount reasonably necessary to carry out operations under a lease.[v] Thus, oil and gas operators may drill water wells on leased land and draw from these wells to the extent reasonably necessary to produce minerals without the risk of liability to the owner of the surface estate or his neighbors. Still, until recently, water was legally owned only at the surface, and not “in place.”[vi] Ownership of ground water was effectively undetermined.

On February 24th, the Texas Supreme Court answered this century-old question by applying oil and gas laws to water. Finding that land ownership includes an interest in groundwater “in place,” in addition to whatever can be pumped to the surface, the court ruled that two farmers had a  “constitutionally compensable interest in groundwater” and affirmed the court of appeals’ reversal of summary judgment against their takings claim.[vii] The court stated, “Whether groundwater can be owned in place is an issue we have never decided. But we held long ago that oil and gas are owned in place, and we find no reason to treat groundwater differently.”[viii]

The Rule of Capture has historically been softened by the regulations of groundwater conservation districts, or GCDs. Section 36.0015 of the Water Code creates GCDs to “provide for the conservation, preservation, protection, recharging, and prevention of waste of groundwater.” There are currently 96 GCDs in Texas, each with independent regulatory authority over groundwater and wells within their districts. With some exceptions, these districts are structured around county lines as opposed to in conformance with aquifer boundaries. The problem here is obvious: two GCDs sitting on top of the same aquifer may adopt different rules for groundwater usage. In addition to resulting in inconsistent approaches to groundwater management, the GCD structure presents due process and equal protection issues.

In comparison to farmers, ranchers, and other landowners who must abide by GCD regulations, oil and gas operators have it easy. Water Code section 36.117 (b)(2) provides an exemption for temporary rig supply wells authorized by the Railroad Commission, forbidding GCDs from requiring drilling permits. An oil and gas operator may sink a water well to pump up water for hydrofracturing fluid without any oversight from a GCD. This exemption is silent as to whether GCDs may regulate the operation of wells in other ways, leaving open in the statutory language the question of whether GCDs might seek to limit groundwater use. Until Edwards v. Day, this gap in the statutory language presented a potential loophole for GCDs to limit or charge for groundwater pumped to the surface for hydrofracturing fluid. The court’s ruling that property owners own groundwater in place, however, is likely to deter GCDs from seeking to exploit this loophole in order to regulate groundwater use.

Hydrofracturing a well may require 5 million gallons of water in a period of a few days. In 2010, Texas temporary rig supply wells for hydrofracturing consumed 13.5 billion gallons of water, nearly 1% of the state’s total water usage for that year.[ix] Though trivial at the state level, temporary rig supply wells in some arid counties accounted for a quarter of total water consumption, almost all of which comes out of aquifers. Factor in record-breaking drought and it becomes apparent, in the words one oil and gas executive, that “we’re using scarce resources to get scarce resources.” [x] Some of the West Texas counties most severely impacted by the drought, and which have since voiced opposition to the hydrofracturing exemption, draw their groundwater from the Edwards Trinity aquifer, an enormous reservoir that spans twenty counties. But the shale boom may be just beginning, and drought conditions are unlikely to abate in the long term.

In the words of Texas Water Law attorney Mark McPherson, the situation prior to Edwards v. Day had the potential to become a “perfect storm.” The collision of common law rules intended to maximize recovery of oil and gas, the regulatory groundwater authority of the GCDs, and the rapid depletion of aquifers due to drilling and drought had created an untenable situation. With Edwards v. Day, the pendulum has swung towards the common law rights of mineral interest holders. Any GCD that seeks to regulate hydrofracturing outside the temporary rig supply well exemption may find itself defending against a takings claim, a grim prospect for the small GCDs. Rains returned just in time last winter and prevented groundwater use from becoming a major political issue in drought-stricken areas. When dry conditions do return, as climatologists expect them to, GCDs will have to grapple with their mandate in the Water Code “to provide for the preservation of groundwater,” without antagonizing landowners and provoking a potential lawsuit.

If the legislature decides to address the issue in 2013, its best option might be to scrap the impractical patchwork of GCDs and structure conservation units around aquifer boundaries as opposed to county lines. The shale boom has provided Texans with enormous job growth and economic opportunity, but we must bear in mind that our aquifer reserves are finite and should be conserved for the use of future generations.  Let’s ride the boom for all its worth, but with an eye to preserving the one resource we can’t live without.

 

In addition to being a joint JD/MBA student at the University of Texas at Austin, Mike Marek is a lessee/operator of a ranch in Kimble County, Texas, where he draws water from the Edwards-Trinity aquifer on a permit granted by the Kimble County GCD. Though Kimble County has not seen significant drilling activity, wells have been hydrofractured in adjacent Sutton and Edwards counties, where they draw water from the same aquifer. During the worst of the drought last summer, several of Marek’s neighbor’s wells went dry.

 

[i] James Faulkner, Hydraulic Fracturing May be Safer for the Environment Than You Think, TJGOEL Blog (Oct. 26, 2011) http://tjogel.org/blog/?tag=natural-resources.

[ii] 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.

[iii] Senate Committee on Energy and Natural Resources, (2011) (written testimony of Stephen A. Holditch), available at http://www.energy.senate.gov/public/index.cfm?FuseAction=Hearings.Testimony&Hearing_ID=b6244826-03fe-5e7c-63a7-ce0cdbb9f141&Witness_ID=60dda64c-e494-4958-8dc0-b7d3ad62334a.

[iv] William F. Mullican, III, and Suzanne Schwartz, 100 Years of Rule of Capture: From East to Groundwater Management, Texas Water Development Board, June 2004, available at http://www.twdb.texas.gov/publications/reports/numbered_reports/doc/R361/R361.pdf; see generally Houston & T.C. Ry. Co. v. East, 98 Tex. 146 (Tex. 1904).

[v] Oil and Gas Exploration and Surface Ownership.  The Railroad Commission of Texas, available at http://www.rrc.state.tx.us/about/faqs/SurfaceOwnerInfo.pdf (last visited Oct. 2, 2012).

[vii] Edwards Aquifer Authority v. Day, 369 S.W.3d 814, 838 (Tex. 2012).

[viii] Id. at 823.

[ix] 2010 Texas Water Use Summary Estimates, Texas Water Development Board, available at https://www.twdb.state.tx.us/waterplanning/waterusesurvey/estimates/2010/; Kiah Collier, Texas’ second oil boom costs precious water, San Angelo Standard Times, June 25, 2011, http://www.gosanangelo.com/news/2011/jun/25/one-scarce-resource-for-another-water-151-and-of/.

[x] Kiah Collier, Texas’ second oil boom costs precious water, San Angelo Standard Times, June 25, 2011, http://www.gosanangelo.com/news/2011/jun/25/one-scarce-resource-for-another-water-151-and-of/.

 

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Murky Future for Chevron in Brazil

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April 17, 2012

By Thomas Verity

Mr. Verity graduated from The University of Texas at Austin in 2009. There he received a BA in History and a Minor in Mandarin Chinese. After graduation Mr. Verity worked in Shanghai, China at Joint U.S. China Collaboration for Clean Energy (5 months) and Lehman, Lee, & Xu (5 months). This summer Mr. Verity will work as a Summer Associate at Fulbright & Jaworski and Vinson & Elkins. Mr. Verity expects to receive his JD in May May 2013.

Introduction

In November of 2011, Chevron drilled into a deep-sea reservoir in the Frade field off the coast of Brazil. The extreme pressure in the reservoir led the oil to rocket upwards into the well, though a blow-out preventer (“BOP”) stopped the oil from shooting up to the Transocean rig above. The success of the BOP largely prevented damages to the scale of the Macondo blowout BP experienced in 2010. While the well pressure was trapped by the BOP, however, cracks began to form at the base of the well bore resulting in oil seeping out into the surrounding sea. Even though the actual amount of oil being leaked appears negligible, Chevron is facing massive economic sanctions, criminal prosecutions, and the possibility that their license to operate in Brazil will be revoked.

The Suits against Chevron and Transocean

After the spill, Brazilian federal prosecutor Eduardo Santos de Oliveira filed an $11 billion civil law suit against Chevron based on alleged negligence by their employees as well as those of Transocean, who was contracted to drill the well.  Chevron has already been forced to pay fines equaling $110 million by Brazilian environment and oil regulators. To put things into perspective, approximately 2400 barrels have been spilled from the November incident. The BP Macondo blowout spilled approximately 5 million barrels of oil resulting in fines equaling $20 billion, which is around $1,200 a barrel. If the judgment against Chevron is awarded, they will be paying $3.6 million per barrel.

In March of this year, the same prosecutor also filed criminal charges against 17 executives and employees of Chevron and Transocean. Citizens of the U.S., U.K.  France, Canada, Australia and Brazil make up the group who has been targeted by the prosecution. Those charged are required to surrender their passports to Brazilian authorities, and must post individual bail of $550,000, as well as $10 million from each company. If the charges result in sentencing, the bail will go towards indemnities, fines, and legal fees. The charges pressed could result in prison sentences of up to 31 years, and the prosecutor has publicly stated his intention to ensure the executives will “serve the full time.”

Formal indictments have yet to be delivered, as Brazilian law requires a judge to review the merits of the charges before proceeding. But, the weight of the charges means Chevron and Transocean will likely face a protracted, expensive litigation. Chevron released a statement that once the facts are fully released, the record will show “Chevron and its employees responded appropriately and responsibly to the incident . . . [and] has collaborated transparently and completely with all the appropriate Brazilian governmental authorities.” The Brazilian prosecutor, however, believes Chevron negligently utilized pressure far beyond what was acceptable to drill, resulting in a “long-term contamination time bomb.”

On March 28th, Chevron and Transocean were slapped with another lawsuit regarding the incident. The Brazil oil workers’ federation, the FUP, filed a suit at a federal court in Rio de Janeiro calling for the cancellation of Chevron’s mineral rights in the Frade field. The federation alleges that the foreign companies have demonstrated incompetence and waste in their operations thus far, and that omissions in reporting the accident and attempts to play down its severity represent disrespect to the Brazilian people.

Not all members of Brazil’s judiciary share the same fervor in attacking Chevron and Transocean as Oliveira, the federal prosecutor who has led the charge so far. Some Brazilian officials believe the prosecution has been too aggressive, and on March 23, the federal judge reviewing the case indicated he might change the venue from Campos to Rio de Janeiro. The jurisdictional grounds for the change in venue would be based on the location of the spill, which took place outside the territorial waters of Brazil but within its nautical economic exclusive zone. A change in venue would not alter the charges, but would serve the interest of Brazil by bringing in a less zealous prosecutor, reflecting political concerns of officials such as Senator Jorge Viana. Viana, who belongs to Brazil’s ruling party, expressed his concerns to a Reuter’s reporter about the damaging effects this litigation may have on foreign investment in Brazil’s oil industry.

Status of Chevron’s Mineral Rights in Brazil

The lucrative Frade field is the largest foreign-operated field in Brazil, and Chevron has spent an estimated $3.6 billion in developing it so far. The company is the largest operator in the field with a 52% stake in the mineral interests. Brazilian oil company Petrobras holds 30%, and a Japanese group owns the remaining 18% interest in the field. Before the November spill, Chevron was producing around 80,000 barrels a day. This number was reduced to 61,500 barrels per day following the spill, and Chevron received permission to temporarily suspend operations in the field in March after discovering new seeps in the ocean bed.

Chevron’s license to operate in Brasil has been temporarily suspended by the ANP, Brazil’s oil regulatory agency, and an increasing amount of local politicians and interest groups are calling for the revocation of Chevron’s mineral rights and assets in the field. Christopher Garmin, a Latin American analyst at Eurasia Group, explained in a Bloomberg interview that “media firestorms” like the one Chevron is experiencing now are a fact of life for oil companies in the “post-Macondo world”. At a hearing in Brasilia, the nation’s capital, an advisor to Brazil’s board of oil regulation informed lawmakers that in instances of non-compliance with safety laws, as has been alleged against Chevron, it is “possible to demand the operator be changed or the contract revoked.” Even the nation’s president, Dilma Rouseff, has stepped up to warn foreign companies that they must strictly adhere to Brazilian safety standards in their operations. A former energy minster herself, Rouseff stated, “there can be no exceptions to being within safety limits and knowing them, to never test them and never go beyond them.”

Even if Chevron’s license is restored, the company has indicated that it may be rethinking its South American presence in the future. Chevron is already fighting an $18 billion dollar judgment from an Ecuadorian court over allegations of environmental damage, and has expressed concern with the treatment of foreign companies in the region. CEO John Watson stated “[Chevron’s] participation in Brazil will be a function of the degree to which they welcome Chevron and other companies and the degree to which we are treated fairly.” Many have noted that Brazilian companies such as Petrobras have not been punished nearly as severely for spills on much larger scales, and that no criminal charges were pursued in those instances. The response to these concerns from Magda Chambriad, chief of the ANP, demonstrates overlying tensions typical of energy investments between foreign companies and the domestic nation’s regulators and companies.  Chambriad openly questioned the dedication foreign companies have to operating in Brazil, noting that key decision makers for energy products in the country are almost always located abroad. The ANP is currently finishing a report based on their investigation of the incident, and Chambriad has indicated they do not believe Chevron has adequately “identified the causes of the accident and [that] the risks have been mitigated to the satisfaction of Brazilian society.” The final decision of the ANP will undoubtedly have a significant impact on future development plans for Chevron and other major companies.

Conclusion

Ultimately, the outcome of this litigation could not only have drastic consequences for Chevron, but also for foreign investment in South American countries at large. The Brazilian government has the unenviable task of balancing two polarizing factions.  Environmental and political groups are concerned with damaging effects of oil spills and accountability for foreign corporations profiting from Brazil’s resources. Aggressive prosecutors and politicians have jumped on these concerns and created a media firestorm over a spill that has thus far has had minimal environmental impact. On the other hand, many Brazilian politicians and members of the energy industry are seeking to encourage continued foreign investments in its developing oil industry, which is a vital part of the Brazilian economy. The outcome of this case will almost certainly be “mandatory reading” for oil companies researching foreign oil plays, as well as the governments of nations seeking outside help to develop their mineral resources.

Sources:

https://ycharts.com/analysis/story/beyond_the_ecuadorian_and_now_brazilian_fiascos_is_chevron_undervalued

http://www.forbes.com/sites/kenrapoza/2012/03/21/chevron-calls-brazil-oilspill-lawsuit-outrageous/

http://www.ft.com/intl/cms/s/0/e9e736fe-78f2-11e1-88c5-00144feab49a.html#axzz1qQtXJAH9

http://www.bloomberg.com/news/2012-03-23/chevron-s-brazil-license-risks-being-revoked-on-oil-spill.html

http://www.reuters.com/article/2012/03/21/us-chevron-spill-idUSBRE82K0PL20120321

http://www.reuters.com/article/2012/03/24/us-chevron-brazil-legal-idUSBRE82N01G20120324

http://www.reuters.com/article/2012/03/23/us-chevron-brazil-idUSBRE82L14320120323

http://www.reuters.com/article/2012/03/14/us-brazil-c

http://www.huffingtonpost.com/2012/03/19/brazil-oil-spill-chevron-leak_n_1363987.htmlhevron-anp-idUSBRE82D00520120314


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Lesley v. Veterans Land Board and the Duties of the Executive Right Holder

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November 20, 2011

By Matt Norwood

Mr. Norwood graduated from The University of Texas at Austin in 2009 with a B.A. in the Plan II Honors Program. Mr. Norwood expects to receive his JD in 2012 and plans to work as an associate for Lynch, Chappell & Alsup in Midland, Texas after graduation.

In 2010, the Texas Journal of Oil, Gas & Energy Law (at p. 138 et seq.) discussed the executive right to lease minerals in connection with a then-pending Texas Supreme Court case, Lesley v. Veterans Land Board of the State of Texas. http://tjogel.org/wp-content/uploads/2010/02/E_Recent-Developments_Final.pdf

This blog entry will update that discussion of Lesley in light of the Texas Supreme Court’s recent opinion deciding the case, which was issued on August 26, 2011 and is available at http://www.supreme.courts.state.tx.us/historical/2011/aug/090306.pdf.

In Lesley, a land developer, who also owned part of the mineral estate and all of the executive mineral right, imposed restrictive covenants on a subdivision to limit oil & gas development in order to protect lot owners from intrusive exploratory, drilling, and production activities. The non-executive mineral interest owners complained that the developer, as the executive, breached its fiduciary duty to them by imposing these restrictive covenants that would prevent the mineral estate from being leased.

The Lesley case has been highlighted by practitioners as an important decision for several reasons.  First, its fact pattern addresses the issue of oil & gas development in residential areas, which is becoming an increasingly contentious issue in today’s energy climate.  As Law360 states in its discussion of the case, “The discovery and exploration of the Barnett Shale and other shale plays in Texas have created new concerns for residential property developers. Often, the surface of a particularly valuable portion of a shale play is covered in residential subdivisions. This inevitably creates a conflict between the competing interests of developing the minerals within the shale and the desire of homeowners to enjoy the peace and quiet of their neighborhoods.”

Second, the Texas Supreme Court’s opinion in Lesley was also eagerly anticipated because of the uncertainty in Texas law concerning the nature of the duty the executive right holder owes to non-executive owners of the mineral estate.

As the court explains in Lesley, the executive right to lease minerals is only one stick in the bundle of real property rights that comprise a mineral estate.   Executive rights are frequently severed from other incidents of mineral ownership, which means that mineral estates often have both executive and non-executive owners as in Lesley.  Non-executive owners own an interest in the minerals in place, but they do not have the right to lease the minerals.  Thus, to some extent the non-executive owners are at the mercy of the executive when it comes to realizing the value of their interest in the mineral estate

For this reason, Texas law has held since 1937 that the holder of the executive interest owes the non-executive owners a duty of “utmost good faith and fair dealing” in exercising the executive right to lease the mineral estate.  But despite the long history of the doctrine, the scope of the executive’s rights and fiduciary duties to non-executives has remained somewhat unclear.

For example, Manges v. Guerra, 673 S.W.2d 180 (Tex. 1984) – once thought to be the definitive case on the issue – established that the executive right owner has a duty to “acquire for the non-executive every benefit that he exacts for himself.”  But more recently in In re Bass, 113 S.W.3d 735 (Tex. 2003), the Texas Supreme Court seemed to limit the broad duty from Manges, and suggested that the executive cannot breach his duty to non-executive owners until the executive power is actually exercised.

This interpretation of Bass arguably could mean that the executive has no affirmative duty to develop or lease minerals – under any circumstances – since the duty of utmost good faith is only triggered once the executive exercises his leasing power.  The Eastland Court of Appeals adopted this interpretation when it decided Lesley by holding that the developer, having never undertaken to lease the mineral estate, did not exercise the executive right and therefore owed no duty to the non-executive mineral interest owners.

With this background, the Texas Supreme Court had several questions to answer in its Lesley opinion.  Does the executive right holder’s duty of utmost good faith and fair dealing apply only to instances in which the executive actually executes an oil and gas lease?  Or does the executive right holder’s duty apply more broadly, imposing an affirmative obligation to lease the non-executive’s minerals when a prudent mineral owner, acting in his own self-interest, would do so?

Unfortunately, the Texas Supreme Court mostly avoided answering these questions in its opinion.  The court reversed the Eastland Court of Appeals’ decision and found that the restrictive covenants were a breach of the executive’s fiduciary duty.  However, the Supreme Court’s reversal was based on the idea that imposing restrictive covenants on the land actually was an exercise of the executive right, since this had an effect on future leasing.   Exercising the executive right triggered the executive’s fiduciary duty, and according to the court, the use of restrictive covenants was a breach of this fiduciary duty because the surface owner was already adequately protected without restrictive covenants through the accommodation doctrine.

However, the Lesley decision largely sidestepped the issue many had hoped it would decide: whether the executive owner has an affirmative obligation to lease the mineral estate.  The court did comment in dicta that Bass should not be read to shield the executive from liability for all inaction. But the Supreme Court was quick to point out that this was not meant to be a definitive statement establishing an affirmative duty to lease, noting that, “We need not decide here whether as a general rule an executive is liable to a non-executive for refusing to lease minerals, if indeed a general rule can be stated, given the widely differing circumstances in which the issue arises.”

The closest the court comes to identifying circumstances where an executive’s inaction might be a breach of duty is its noncommittal comment, “If the executive’s refusal [to lease] is arbitrary or motivated by self-interest to the non-executive’s detriment, the executive may have breached his duty.”   In some ways, this comment that a refusal motivated by self-interest may breach the executive’s fiduciary duty describes a more limited fiduciary duty than the one contemplated in Manges, where the court held that the executive’s self-dealing and refusal to lease to a 3rd party was a breach of the executive’s fiduciary duty.

So, the duties of the executive right owner in Texas remain uncertain after Lesley.  Reading between the lines of the Supreme Court’s opinion, Lesley may hint that the duty falls somewhere between what was described in Manges and Bass. If an affirmative duty to lease does exist, it only exists in limited circumstances that the court is not willing to describe at this time.

On the other hand, the court was willing to rule definitively on the other area of interest in Lesley – the conflict between mineral owners and surface owners in the context of residential property.  Lesley reinforces the traditional dominance of the mineral estate over the surface estate, even in the case of residential property, by cancelling the land’s restrictive covenants based on the theory that they were improper exercises of the executive right.  Although this might not have been as controversial a legal issue as the executive’s duty to lease, it could end up having a substantial practical significance as more and more discoveries and potential shale plays arise near population centers in Texas.

Sources:

Lesley v. Veterans Land Board of the State of Texas, No. 09–0306, 2011 WL 3796568 (Tex. Aug. 26, 2011), 54 Tex. Sup. Ct. J. 1705

Veterans Land Bd. v. Lesley, 281 S.W.3d 602 (Tex.App.—Eastland 2009)

Manges v. Guerra, 673 S.W.2d 180 (Tex. 1984)

In re Bass, 113 S.W.3d 735 (Tex. 2003)

D. Davin McGinnis and Olga Kobzar, Lesley V. Veterans Land Board: Revisiting the Scope of the Duty Owed by Executive Mineral Interest Owners to Non-Executive Mineral Interest Owners, 5 Tex. J. Oil Gas & Energy L. 138 (2010), available at http://tjogel.org/wp-content/uploads/2010/02/e_recent-developments_final.pdf

Case Study: Lesley V. Veterans Land Board of Texas. Law360 (Oct. 14, 2011), http://www.law360.com/articles/278124/case-study-lesley-v-veterans-land-board-of-texas

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Did the Department of Energy break the law with Solyndra?

Filed Under: Current Industry Issues by admin — Leave a comment
November 9, 2011

by Lindsay Hagans

Ms. Hagans graduated from the University of Southern California in 2006 with a B.A. in English and Public Relations. After graduation, Ms. Hagans worked in Los Angeles, making low-budget zombie movies, for 2 years before moving back to Texas in 2008 where she then worked as a field organizer on a campaign and at the Texas Capitol as a policy aide for two state senators. Ms. Hagans will spend this summer working for Baker Botts in Houston and Quinn Emanuel in San Francisco before receiving her J.D. in May 2013.

Did the Department of Energy break the law with Solyndra?

On September 6, 2011, Solyndra, a solar energy company and recipient of a $535 million government loan, filed for bankruptcy, which immediately unleashed a political firestorm.  Solyndra had been the poster child of President Barack Obama’s green energy initiative, which many critics have said pushed loans through too quickly.  Republican lawmakers say that, despite serious warning signs, the Obama administration fast-tracked the loan in an effort to tout the President’s federal stimulus efforts.  In response, the Obama administration and the Department of Energy (DOE) say the Solyndra loan was properly vetted and an unfortunate failure in an otherwise successful program.

Background

In 2005, President George W. Bush signed the Energy Policy Act of 2005, which created a loan guarantee program for innovative technologies that avoid greenhouse gases, including renewable energy.  In 2007, Solyndra was selected as one of sixteen clean-tech companies considered ready to move forward in the due diligence process, and the DOE began to develop a conditional commitment with these companies for funding from the loan guarantee program.  In 2009, the DOE offered a $535 million loan to Solyndra, the first loan guarantee issued under the 2005 energy law and the largest award given to a solar manufacturer.

In late 2010, Solyndra was facing a liquidity problem and approached the DOE for an increase in its loan guarantee.  The DOE refused, but after private investors pumped an additional $75 million dollars into the company, the DOE agreed to restructure the loan in February 2011.  Under the modified loan agreement, the private investors could recoup their $75 million before the taxpayers got any money back if Solyndra went bankrupt.  In other words, the investors’ claims to Solyndra’s assets, in the event of bankruptcy, ranked ahead of the government’s claims.

Did the DOE break the law?

The issue is the February restructuring.  Critics argue that the DOE violated the Energy Policy Act when the department “subordinated” the taxpayers’ interest to those of private investors.  The DOE insists that it did not violate the 2005 energy law in restructuring the loan.  Instead, the department says the move was aimed at protecting the federal investment by giving the struggling company the best chance to stay afloat and giving taxpayers the best chance of being repaid.

In response, Republicans argue that a series of emails shows that there were concerns about the restructuring before it was authorized.  The emails, between the administration and officials at the Treasury Department and the Office of Management and Budget, allegedly show that the administration pressed officials to make a swift decision on whether to restructure the loan, and that there was disagreement within the government about whether the initial loan guarantee was sound.

What are the legal ramifications?

While critics may be insistent that the government violated the 2005 energy law, any repercussions will likely be political, not legal.  Unlike laws such as the Clean Air Act, which allows citizens to sue the Environmental Protection Agency for possible violations, the Energy Policy Act of 2005 does not provide a similar remedy.  A taxpayer wishing to sue the DOE under the Act would not have standing to bring a lawsuit.

Representative Cliff Stearns (R-Fla.) is the chairman of the House Energy and Commerce Committee’s Oversight and Investigations Subcommittee.  When asked in an interview about what actions the House could take to address any allegations of illegalities, Rep. Stearns could not provide a specific answer.

Another member of the subcommittee, Representative Michael Burgess (R-Tex.), has publicly expressed his frustration at the lack of available recourse and suggested that such a dearth of options may need to be fixed through a new energy law.  Rep. Burgess also indicated that even though there’s language in the 2005 energy law to prevent subordination of a loan guarantee, there’s really no penalty to be imposed on the DOE for doing so.

Indeed, in Section 1702 regarding terms and conditions of repayment, the law states, “the [guaranteed] obligation shall be subject to the condition that the obligation is not subordinate to other financing.”  However, in her memo, Richardson justified the decision by arguing that the rule is “applicable only as a condition precedent to the issuance of a loan guarantee.  It is not a continuing restriction on the authority of the secretary.”  In other words, the proscription against subordination only applies at the time of initial loan, not any subsequent modifications.

Perhaps a reason for the lack of repercussions is because the government has typically had wide discretion in making these executive-level decisions, even if the decision is subsequently viewed as ill advised by critics.  Also, any waiver of federal sovereign immunity must be explicitly waived, as in the Clean Air Act.  Here, it was not.

The House Committee investigation

After the bankruptcy became public, the House Energy and Commerce Committee initiated an investigation into Solyndra and whether the administration failed to follow proper protocol before issuing the loan guarantee.  The committee has requested DOE officials to submit to depositions, but on October 18, the DOE informed the House committee that it would not allow the committee to perform depositions of DOE officials, including Susan Richardson.  Richardson is the chief counsel of the DOE Loan Programs Office; in that capacity, she authored the memo justifying the DOE’s decision to restructure the $535 million loan to Solyndra.

While the Republican-controlled committee has cried foul, the DOE says it has offered to make Energy Secretary Steven Chu available for a hearing on November 1st or 2nd, voluntarily provided more than 65,000 pages of documents to the committee, and provided the head of the loan program for a committee hearing.  However, the DOE says the committee does not have the authority to compel a witness to perform a deposition.

Despite these concessions, news sources indicate that Chu, Richardson and other DOE officials are all likely to be called to testify on why they decided to change the terms of the loan.  While before the committee, the DOE officials can also expect questions about why they apparently did not follow a DOE regulation requiring them to first consult with the Justice Department before modifying the terms of Solyndra’s loan guarantee.

The DOE is not the only governmental department to be haled into a hearing before the committee.  Two officials from the Treasury Department testified at a recent hearing that the DOE’s decision to restructure the $535 million loan guarantee was unusual, and they had not seen anything else like it before.  However, the officials refused to comment on the legality of the restructuring, saying their role was to raise questions but not provide legal guidance.

Additional Solyndra hearings are likely to be scheduled in the coming weeks.  Meanwhile, the White House has said that it will not give Congress internal communications relating to Solyndra’s loan guarantee, citing confidentiality interests of the executive branch.  In response, news sources indicate that House Republicans are preparing for a possible vote in early November to subpoena White House documents related to Solyndra.

The FBI investigation

Solyndra may be facing bigger problems than just the House committee inquiry.  On September 8, the Federal Bureau of Investigation raided the company’s Fremont, California, offices.  There are differing stories given as to why the FBI has initiated a criminal investigation.  Ben Schwartz, a vice president and lawyer at Solyndra, official testified in U.S. Bankruptcy Court in Delaware that the FBI’s search warrant affidavit specifically sought information about company contracts.  But some news sources, citing an anonymous FBI official, suggest that the FBI is examining possible misrepresentations in financial statements that Solyndra submitted to the DOE.

Schwartz was in court because the U.S. Office of the Trustee said he had refused to answer questions about the company’s contracts.  His refusal, government lawyers argued, proved that a trustee should be appointed to take over the company.  However, after hearing oral testimony, U.S. Bankruptcy Court Judge Mary F. Walrath rejected the government’s argument, saying there was no indication of any fraud or mismanagement at the company.

Update:  The latest update, as of October 28, 2011, is that the White House has ordered an independent review of similar loans made by the DOE.  The review would not look at the Solyndra case but would evaluate other loans worth tens of billions of dollars and recommend steps to stabilize them if they appear to have problems like the loan to Solyndra.

Sources:

http://dailycaller.com/2011/10/20/doe-refuses-to-let-author-of-solyndra-legal-memo-be-interviewed/

http://www.politico.com/news/stories/1011/66592.html

http://thehill.com/blogs/e2-wire/e2-wire/188861-house-gop-energy-department-isnt-fully-cooperating-with-solyndra-probe

http://www.washingtontimes.com/news/2011/oct/17/judge-denies-bid-by-government-for-solyndra-truste/

http://www.mercurynews.com/breaking-news/ci_19112887

http://www.businessweek.com/news/2011-09-30/solyndra-said-to-be-investigated-by-fbi-for-accounting-fraud.html

http://www.grist.org/solar-power/2011-09-13-bush-admin-pushed-solyndra-loan-guarantee-for-two-years

http://www.usatoday.com/news/washington/story/2011-10-28/solar-investigation/50978966/1

Text of the 2005 Energy Policy Act: http://www.gpo.gov:80/fdsys/pkg/PLAW-109publ58/pdf/PLAW-109publ58.pdf

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