Teucrium Soybean Message Board

"•
Paradigm Shift
–
nitrogen reductions 50% to 90% cheaper;
Integrated Projects the logical next step in production efficiencies
•
Technology validated
–
third generation, scalable, proven, accepted
•
Strong IP portfolio
•
Very
large, addressable market with substantial barriers to entry
•
Recognized
industry thought leader
•
Strong
management team
–
Exec Vice
Chrmn
: Ed
Schafer, former
US Sec. of
Agriculture
and
two
-
term
Gov
of North Dakota
•
At the technology and business inflection point
–
heavy lifting done (tech accepted, policies evolving); anticipate revenues in 2013
•
Valuation: $34M @ $2.00 ($55M FD)
–
Kreider projects alone anticipated to produce $7M to $10M operating cash flow (EBITDA)
•
Primary risk: timing

A good portion was spent on China's garbage problem. Big example was Beijing's garbage problem - 19,000 tons a DAY!! 19 Teesides!! 416 illegal dumps and all 10 of their legal dumps will close in 2014. The government is proposing a $1 billion incinerator which won't begin to solve the problem as it will only handle 5,000 tons/day. Alter already has something going with the metals industry. Sure would be nice if they found some substantial firm to promote the waste disposal side of Alter's technology. Too bad Air Products' Teesides unit isn't up and running. Those plans will be worth many times their weight in gold.

Looks like this board is really starting to degenerate.

Unfortunately, I've seen it all too often before with other non-performing stocks - kind of goes with the territory, I guess.

EVTN has a PR out re attending the OTC conference in Houston again this year - 4th in a row, I think. I wonder if they will show anything different from previous years. I would like to see a video of the Voraxial in action separating stuff on the offshore and onshore sites that they have sold units to in the last couple of years - never happen.

Legislation Targets Mandates for Water Recycling in Oil, Gas Industry
by Karen Boman
|
Rigzone Staff
|
Monday, April 15, 2013
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Legislation Targets Mandates for Water Recycling in Oil, Gas Industry

Legislation introduced last week into the Texas Legislature mandating the recycling of produced and flowback water from hydraulic fracturing operations mark the most recent efforts by lawmakers to make water recycling mandatory.

With Texas' population expected to reach 46.3 million people over the next 50 years, drought conditions over the past three years and water shortages over the past five years, oil and gas and other industries that consume a significant amount of water have been scrutinized by the public, environmental groups and government officials. Texas does not have enough existing supplies today to meet demand for water in times of drought, according to Texas' State Water Plan.

Concerns about water usage have grown in recent years not only in Texas, but communities across the United States, said Gabriel E. Eckstein, an attorney with the law firm Sullivan & Worcester and a professor specializing in water, environmental, natural resources and international law at Texas Weslayan University School of Law in Fort Worth, in an interview with Rigzone. In recent years, a host of water-related bills from the construction of new dams to aquifer storage to water recycling have been introduced to the state legislature, Eckstein commented. Major discussions have also taken place to use money from the state's Rainy Day Fund as seed money for infrastructure to meet Texas' future water supply needs.

The surge in exploration and production and unconventional resources in the Eagle Ford and other shale plays in Texas has created concerns in recent years over the amount of water being used in hydraulic fracturing and hydraulic fracturing's impact on local water supplies. The hydraulic fracturing process involves injecting a mixture of water, sand and chemicals into a well at high pressure to create fissures to release oil and gas deposits. Water usage varies on the size and conditions of the shale formation, with Haynesville shale requiring close to 8 million gallons per well, followed by the Eagle Ford play at 5 million and Barnett shale at over 4 million gallons.

From 2008 to 2011, total water used in hydraulic fracturing in Texas grew from 36,000 in 2008 to 81,500 acre-feet in 2011, according to "Oil and Gas Water Use in Texas: Update to the 2011 Mining Water Use Report". In 2011, the oil and gas industry used 102,500 acre-feet of water, including approximately 81,500 acre-feet for hydraulically fracturing wells and approximately 21,000 acre feet for other oil and gas industry purposes.

Water used in oil and gas exploration, development and extraction and for mining represented 1.6 percent of Texas' total water use, while irrigation and municipal water use collectively represented 82.8 percent of water use in the state, according to the Texas Water Development Board's 2012 State Water Plan. However, in the Eagle Ford shale region, mining accounts for 6.5 percent of water demand; that demand is expected to increase by 26 percent from 2010 to 2060 for the region, according to Luke Metzger, head of Environment Texas.

While water demand for municipal use, manufacturing, and steam electric power generation are expected to rise over the next 50 years, water demand for oil and gas and mining is expected to remain relatively constant and then decline over that period. By 2060, mining water use is expected to decline slightly from 1.6 percent to 1.3 percent for Texas' total water use, according to "March 2013 Eagle Ford Shale Task Force Report".

Last month, the Texas Railroad Commission (TRC) adopted rules to encourage Texas oil and gas operators to continue conserving water used in hydraulic fracturing. These new amendments do not make recycling mandatory for operators.

"However, they are expected to encourage recycling by eliminating the need for a permit for on lease fluid recycling, streamlining the recycling permitting process and providing operators with clear path to securing the Commission permits," a TRC spokesperson told Rigzone in an email.

The TRC's new and updated recycling rules authorize an operator or its contractor to store and recycle well fluids on an oil and gas lease, allow the operators to recycle each other's fluids, and establish protective standards for fluid storage and recycling, the spokesperson said.

For recycling activity that requires a permit, the rules clearly identify application requirements and establish categories of commercial recycling permits to reflect industry practices in the field, the spokesperson said. The amended rules are scheduled to take effect April 15.

Despite the new TRC regulations, some state lawmakers have sought to take matters a step further and require oil and gas operators to recycle water. House Bill 2992, introduced by Rep. Tracy O. King (D-Batesville) would prohibit hydraulic fracturing flowback fluid and water produced from a hydraulically fractured well from being injected into a disposal well unless the fluid cannot be treated so it could be recycled in hydraulic fracturing, used for another beneficial purpose or be released into or near the state's water system.

The bill would also require the TRC to adopt rules establishing standards for determining whether flowback and produced water may be disposed of in an oil and gas waste disposal well.

The TRC has said it would need to track flowback fluid from the point of generation to the point of ultimate disposition for beneficial use or disposal, with certification that the fluid cannot be treated for beneficial use to allow disposal into an injection well. This would require additional inspections; the TRC estimates it would need an additional 16,200 inspections to track this data.

These inspections would be conducted on a different schedule from the current inspection workload, and would focus on tracing the origins and use and treatment of flowback fluid. To implement this bill, 21 full-time employees would be needed, including three at the TRC headquarters to manage the tracking system and to enforce the new requirements, as well as two full-time inspectors at each of the agency's nine district offices to enforce the bill's requirements. These costs are estimated at approximately $1.4 million per fiscal year.

The TRC would also need to establish a complex water tracking system to determine water treatment and ultimate disposal. To track flowback and produced fluid and their method of disposal, the TRC would have to develop an application that would allow for operators to file the volumes of flowback and produced water from an oil and gas well on a monthly basis, along with how these volumes are disposed. The estimated cost to develop the necessary technology in 2014 is $486,720.

HB 3537, introduced by Rep. Roland Gutierrez (D-San Antonio) would require the TRC to adopt rules requiring treatment of flowback and produced water from oil and gas wells that have been hydraulically fractured. The bill would only apply to fluid produced from an oil and gas well on or after the bill's effective date.

Both bills would require TRC to adopt the new rules no later than Dec. 1 of this year, and would take effect Sept. 1, 2013. The legislation does not expect HB3537 to have any significant fiscal impact to the agency.

The new bills aren't the first time lawmakers have sought to make recycling of water from hydraulic fracturing operations mandatory. During the 2011-2012 session, Rep. Lon Burnam (D-Forth Worth) proposed HB 378, which would have required oil and gas operators to pay $.01/barrel tax for every barrel of hydraulic fracturing wastewater injected into a disposal well. That measurement did not pass.

Environment Texas voiced support for HB 2992 and HB 3537, noting that the statewide percentage of water demand in oil and gas drilling and mining belies the impact of oil and gas extraction on water supplies in the few areas of the state where oil and gas production is most prevalent, said Metzger in a statement to Rigzone.

However, oil and gas industry executives say incentives, not mandates, are the best way for Texas to encourage oil and gas operators to recycle water from hydraulic fracturing operations.

"The TRC deserves credit for creating rules that are fair and that help remove impediments to increased recycling in Texas," said Brent Halldorson, chief operating officer of water recycling firm Aqua-Pure/Fountain, told Rigzone in an email.

Recycling is being actively included in exploration and production companies' water management strategies, Halldorson added.

The rules already adopted by the TRC which would allow recycling without acquiring a new permit to do so actually go a long way to encourage recycling compared to a mandate, and for exploration and production companies to adopt recycling, mainly because they can store the water onsite so that they can recycle it, said Anthony Migyanka, CEO of Irving, Texas-based water treatment firm CLLEEN, in a statement to Rigzone.

Texas exploration and production companies have built-in incentives to recycle: water scarcity, drought and transportation costs, Migyanka commented.

"I think if they give them time to play out, the drillers and their water treatment vendors will find better recycle economics versus just taxing them into doing it. And long-term, they would benefit everyone using water."

"It would take a $3/bbl brine well injection tax, not a $.01/bbl tax, at least theoretically, to change the workflow from disposal to recycle, but I don't know that it would improve the economics of recycling water, which is really what Texas wants, and it's what the drillers want too," Migyanka commented. "It would just cause price inflation. What if the drillers simply decide to pay the tax? That's not saving any water, which is the point of the proposed legislation."

The amount of water recycled from hydraulic fracturing is difficult to pinpoint, Migyanka noted. Metzger noted that the low level of flowback water recycled in Texas is partly due to the high cost associated with treating this water. An estimated 5 percent of Barnett shale flowback is recycled and reused.

"It all comes down to down to the total economic picture of the water: how much is it to buy fresh? How far is that in miles? How close is the nearest injection well? How far is the next well where we want to use the water?" Migyanka noted. "So, more than just brine injection well prices comes into play. It's quite a complex issue, really."

Migyanka sees increased adoption of water reuse from one fracking stage to the next, over and over, and not having to reformulate the frac fluid formulation. A biocide is used to kill the bugs in the water that cause corrosion, and water is reused four or five times instead of once before being disposed. This trend is catching on in Texas, Oklahoma, Colorado and other places of true water scarcity and drought.

He also sees high total dissolved solids fracking as the biggest factor in water recycling in the coming years.

"Initially, it was thought that the water needed to be at 25,000 to 40,000 parts per million (ppm) TDS, such as iron aluminum, calcium and sodium) but what testing and experience has shown is that they can frack a well with TDS levels as high as 285,000 ppm TDS, so that the water is pumped in the well at 25,000 ppm, flows back at 100,000 ppm, they reuse it with biocide-only treatment, they refrack at 100,000 ppm, it flows back at 150,000 ppm," said Migyanka. "They reuse it again, and so on, until they are done with that well."

The commercial incest between Alter, W2T, AFC and now Foster Wheeler (who, IMO lends huge credibility to what the other 3 are trying to do because of FW's reputation for project management and engineering expertise) is a wonderful "plus" for Alter's and AFC's technologies.

Once again, patience may be amply rewarded.

Fracking 'Not Significant' in Causing Earth Tremors
by Jon Mainwaring
|
Rigzone Staff
|
Wednesday, April 10, 2013
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Fracking 'Not Significant' in Causing Earth Tremors

New research has found that hydraulic fracturing (fracking) is "not significant" in causing earth tremors. Released Wednesday by the UK's Durham University, the results of a study of hundreds of thousands of fracking operations showed that the process only caused earth tremors that could be felt on the surface in three cases.

The research, titled Induced Seismicity and the Hydraulic Fracturing of Low Permeability Sedimentary Rocks, found that almost all of the resultant seismic activity was on such a small scale that only geoscientists would be able to detect it. It also discovered that the size and number of tremors is low compared to other manmade triggers such as mining, geothermal activity or reservoir water storage.

However, Durham University's report does establish beyond doubt that fracking has the potential to reactivate dormant faults and describes the probable ways in which the pumping of fracking fluid underground triggers this.

"We have examined not just fracking-related occurrences but all induced earthquakes - that is, those caused by human activity – since 1929. It is worth bearing in mind that other industrial-scale processes can trigger earthquakes including mining, filling reservoirs with

Study: Fracking May Boost California's Economy, Adding 2.8M Jobs
by Robin Dupre
|

Monday, April 01, 2013

Study: Fracking May Boost California's Economy, Adding 2.8M Jobs

Development of California's Monterey shale formation can play the major role in the state's future economic well-being, noted a recent study, "Powering California: The Monterey Shale and California's Economic Future", released by the University of Southern California (USC) and Los Angeles-based think tank Communications Institute.

California's Monterey shale is estimated to hold 15 billion barrels of oil and development of the 1,750-square mile formation in central California could generate half a million new jobs by 2015 and 2.5 million jobs by 2020.

"This report provides an indication that there is one potential bright spot in California's economic future: the increased production of energy," the report stated. "California has long served as the incubator for emerging energy sources and technologies, as the state has taken advantage of both technology and its natural resources to become a leader in the generation of renewable energy. Now, these same technological and resource advantages can allow the state to return to leadership in the production of oil."

The Monterey/Santos play, a prolific source rock for many of California's large oil fields, is considered by far the largest shale oil formation in the United States, roughly two-thirds of total oil shale potential. By those numbers, the Monterey reserves trump the Bakken and Eagle Ford fields.

This new onshore oil play can easily pump up the nation's oil output by 25 percent in just a few years and help the state's local energy picture. California has more recoverable reserves in shale than nearby big oil-producing countries, according to a July 2012 report issued by the U.S. Energy Informatio