MATCOR has learned that Anadarko is close to completing its new $100 million natural gas processing plant in Texas.

The Cathodically Protected Brasada plant will process natural gas produced from the company’s Eagle Ford shale wells.  Components like methane, ethane, propane and butane will be separated before they they are transported through the cathodically protected pipeline for further processing.

Anadarko’s plant is designed to process 200 million cubic feet of gas per day but can expand to process up to 400 MMcf/d.  This could lead to capacity expansion if Anadarko undertakes processing of third party gas at some point.

Although the Eagle Ford Shale region has a lot of potential for company’s such as MATCOR it cannot be optmized until the supporting midstream infrastructure comprising of gathering systems, pipeline and processing plants are developed to move oil and gas to to market.

Anadarko’s Eagle Ford Operations

Anadarko explores for shale oil and gas in a gross area of 400,000 acres in the Dimmit, LaSalle, Maverick and Webb Counties in the Eagle Ford region. Its current resources are estimated at over 600 million barrels of oil equivalent (MMBOE), 65% of which is estimated to be liquids. In 2012, the company achieved a gross processed production record of approximately 152,600 BOE per day. With its higher-margin oil and natural gas/condensate, the Eagle Ford shale region is among the most capital-efficient shale plays in Anadarko’s U.S. onshore portfolio.

Anadarko currently operates approximately 380 miles of oil and natural gas pipelines throughout the southwest Texas region, with additional gathering facilities that support more than 50% of its Eagle Ford shale production. In March 2012, Anadarko and Western Gas Partners began construction of the Brasada gas processing plant. The Brasada plant and the construction of an additional 200 miles of gathering lines will enhance the value of Anadarko’s Eagle Ford assets.

The Brasada Plant

All of Anadarko’s Eagle Ford acreage is located to the west of the Brasada plant, and a pipeline network will bring natural gas into the facility as well as move it off site to market. The pipeline will enable the company to eliminate its dependence on trucks. This will speed up transportation of its gas as there are too many trucks on the road in the region which causes a slowdown in the overall movement.

The Brasada plant also will also reduce flaring of methane in the field because Anadarko will be able to move it directly to market through pipelines. Flaring of methane is a common industry practice in cases where transportation is not viable.

From the plant, natural gas liquids will travel further through a pipeline to a plant in Yoakum and to fractionation facilities in Mont Belvieu, east of Houston. Gas also will go south to Corpus Christi, where it can be used in refining or fed into the existing network of interstate pipelines

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Enbridge, Inc. will begin work on Oxford and Addison’s portions of what is known as Line 6B at some point between June 1 and Dec. 31, according to Jack Manshum, a spokesman for the company.

“That’s the plan as of right now,” he said. “We’re in the process of developing the construction timeline.”

Line 6B is a 285-mile crude oil pipeline that begins in Indiana, crosses southeastern Michigan and ends in Sarnia, Ontario, Canada. It serves refineries in Michigan, Ohio and eastern Canada.

This year, Enbridge plans to replace approximately 50 miles of Line 6B with new 30-inch diameter pipeline (the same size as the existing one) from Ortonville to the St. Clair River in Marysville. The portion that runs through Oxford is approximately 6.5 miles in length, while Addison’s portion is approximately 6 miles long, according to Manshum.

This is part of a much larger construction project that spans approximately 210 miles across Michigan and Indiana.

The Michigan Public Service Commission approved Enbridge’s application for this phase of the pipeline project on Jan. 31

“We’ve haven’t formally announced the details yet as to when we’ll be in each county or in each area,” Manshum said. “We’re in the middle of outlining that entire plan. So, I don’t know exactly when we’ll be in Oakland County.”

The old underground pipeline will not be removed to make way for the new one. It will be left in place.

“It will run parallel and adjacent to the existing line that’s in place now using the same right-of-way,” Manshum said. “When the new line is tied in and activated, the old line will be deactivated.”

Deactivation will involve purging all the oil from the old line and cleaning it thoroughly to remove any remaining crude, he explained. The old line will then be “taken apart in small segments” and capped.

“Each chunk of that pipe will have caps on it and then it’s filled with nitrogen,” Manshum said. “We will monitor the pressure inside that line as long as the line exists. The reason you fill it with the nitrogen and you monitor the pressure is to help make sure it doesn’t have any internal corrosion.”

With regard to the line’s exterior, he said Enbridge will maintain the cathodic protection that’s already on it to ensure there’s no external corrosion either.

Enbridge can’t simply walk away from the old pipeline.

“It’s a federal requirement,” Manshum said. “You have to maintain it as if you were using it.”

Manshum explained that leaving the old pipeline in place is “pretty standard in the energy transportation industry.”

“To completely take that line out of service, then replace it with a new one” is not practical for Enbridge’s customers, which are oil refineries.

“(The pipeline) would be out of service for six to 12 months – there would be no product flowing through (it),” Manshum said. “(The refineries) don’t have enough storage capacity to go that long.”

Once the new line is up and running, why can’t Enbridge come back and remove the old one? “That’s more of an inconvenience for landowners,” Manshum said. “We’re already there during one construction season, digging up their property, creating the trench.”

If Enbridge returns for another construction season, the workers will “basically redig everything that we just put back into place the year prior.”

Manshum noted it would involve the “same amount of time and process” to remove the old pipeline as it did to install the new one.

“It’s much less disruptive to landowners for us to only be in there once, instead of having to come back,” he said.

SOURCE: http://www.clarkstonnews.com/Articles-News-i-2013-03-20-250883.113121-sub-Work-on-oil-line-to-begin-later-this-year.html

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LS Power Development LLC received North Beaver supervisors’ approval this week to build a 900-megawatt plant along the Mahoning River at the site of a former American Cyanamid Co. explosives manufacturing plant. Construction could begin early next year.

The New Jersey-based company needs state and federal permits, and the state Department of Environmental Protection is reviewing several requests, project manager Casey Carroll said on Wednesday.

“We’re trying to respond to the large number of proposed retirements — some 3,000 megawatts” of power generation capacity in northwest Pennsylvania and northeast Ohio, he said, addressing how the company chose the location. One megawatt can power about 800 homes.

The proposed Hickory Run Energy Station also needs access to high-voltage lines, interstate natural gas pipelines and a water supply source.

LS Power’s project is moving forward as electric generation companies are closing less efficient coal-fired plants or converting them to run on cheaper natural gas before tougher federal air pollution standards take effect in 2015.

FirstEnergy Corp. of Akron, American Electric Power of Columbus and GenOn Energy Inc., which NRG Energy of Princeton, N.J., acquired for $1.7 billion in December, along with other operators announced closings of dozens of plants last year.

Natural gas plants account for 95 percent of generation planned in grid operator PJM Interconnection LLC’s territory covering 13 states and the District of Columbia, spokeswoman Paula DuPont-Kidd said. Wind used to be the fastest-growing sector, she said.

Pending deactivations of coal-fired plants add up to more than 16,000 megawatts of generating capacity, PJM documents show.

Carroll said LS Power, with offices in East Brunswick, N.J., and St. Louis, has a contract to buy the Hickory Run site off Route 551, about 45 miles northwest of Pittsburgh.

Tennessee Gas Pipeline Co. owns and operates the gas lines that would supply the plant, and has a system that runs from the Gulf Coast to the Northeast.

Carroll said 500 workers would be needed to build the plant, with an estimated payroll of $100 million. The completed power station will employ 25.

LS Power owns or is developing power plants that run on natural gas, coal or renewables such as wind and solar, and is building high-voltage transmission lines, its website said. In Pennsylvania, the company has a natural gas-fired plant under development in Berks County.

SOURCE: http://triblive.com/news/adminpage/3435126-74/power-gas-plant#axzz2KFdbNDtK

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Private equity firm TPG Capital, Copano’s top shareholder with a stake of more than 14 percent, will get a 41 percent premium to its $300 million investment made in 2010, if the deal goes through.

The deal is the latest in a flurry of multi-billion-dollar takeovers in the U.S. pipeline industry over the past two years as companies rush to cash in on a shortage of pipelines to move gas and gas liquids such as ethane and propane.

The oversupply of gas and gas liquids, largely due to the advent of new drilling methods such as hydraulic fracturing, has also hurt prices.

Many companies have announced plans to build new pipelines, but stricter regulations and environmental concerns have delayed the completion of several projects.

“Copano is already executing on a substantial backlog of expansion projects for which it has secured customer commitments and is exploring a significant amount of projects incremental to these,” said Kinder Morgan Chief Executive Richard Kinder.

“As a result of this acquisition, we will be able to pursue incremental development in the Eagle Ford Shale play in south Texas, gain entry into the Barnett Shale Combo in north Texas and the Mississippi Lime and Woodford Shales in Oklahoma,” CEO Kinder said.

Copano owns an interest in or operates about 6,900 miles of pipelines with capacity of 2.7 billion cubic feet per day (bcf/d) of gas and nine processing plants with more than 1 bcf/d capacity.

Kinder Morgan Energy owns an interest in or runs about 46,000 miles of pipelines that transport gas, gasoline, crude oil and other products, while its 180 terminals store petroleum products, chemicals and such other products.

SOURCE: http://www.cnbc.com/id/100419283

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That trend line will only increase in coming months and years with more and more homes and businesses converting to natural gas from heating oil. NStar has estimated that conversions here have tripled over the past three years and National Grid said conversions in Massachusetts and New Hampshire increased 34 percent.

All these are positive trends, particularly considering the abundance of cheap, available natural gas – and the possibility of far more due to the shale gas revolution happening throughout the nation.

However, the region will need to do more to increase our capacity to bring this abundant energy source to our businesses, institutions, and homes. That presents a problem which New England ought to see as an opportunity and move quickly to expand the available pipeline for natural gas into the region.

There is a clear need for additional gas pipeline capacity in New England, not only for electric generation on the relatively infrequent peak-gas-demand days and to fill the gaps from the growing use of intermittent renewable resources but, in general, for the rapidly growing end-use demand for gas.

We need new capacity to take advantage of the nation’s rising supplies of natural gas. Currently, the delivery cost of gas in New England is increasing rapidly and will likely keep rising, unabated, until pipeline capacity increases and more gas starts flowing into the area.

In New York, the key financing for an expansion was secured when marketers and transmission companies signed on to firm contracts after a period of significant increase in primary delivery costs. As a result, marketers are now concentrating in that key, new open market. After this new capacity, New York’s primary delivery cost is now approximately $2/therm lower than what Massachusetts end users are paying, as highlighted in a recent report by the US Energy Information Administration. That report also states that New England has the highest average spot prices for natural gas in the nation.

For New England, it doesn’t make sense to wait until the cost of gas increases to the point where it hurts commercial, industrial, and residential customers. For PowerOptions members, who use roughly 13 million dekatherms annually, matching New York’s primary delivery cost would translate into $26 million of savings.

While it is a bad idea to saddle the electricity market with the full cost, smart expansions of pipeline capacity make sense and regulators and the marketplace should consider a range of expansion solutions and include all potential sources of financing support.

The truth is, we can’t continue to provide the incentives we do to end users for the conversion from oil heating and steam to natural gas and then not expand our ability to bring more gas into the region. That math doesn’t add up.

Bottom-line, this is a very complex problem. There are no simple answers and a wide net of potential solutions must be cast. But simple answers like greater efficiency and leak prevention in our pipeline are simply not enough. Smart but bold action is needed – and soon.

SOURCE: http://www.commonwealthmagazine.org/Voices/Perspective/Online-Perspectives-2013/Winter/002-Arcate-New-England-needs-to-expand-gas-pipelines.aspx

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WASHINGTON and HOUSTON, Jan. 25, 2013 /PRNewswire/ – NiSource’s Columbia Gas Transmission (Columbia) today received approval from the Federal Energy Regulatory Commission (FERC) for a customer settlement that facilitates Columbia’s comprehensive pipeline infrastructure investment plan.

The settlement, filed on September 4, 2012 and widely supported by Columbia’s customers, covers the initial five years of Columbia’s investment plan and contains provisions for potential extension thereafter. Among other components, key elements of the settlement identify individual infrastructure projects and establish a mechanism for recovery of Columbia’s revenue requirement for infrastructure investment under the plan.

“FERC’s approval of our customer settlement is a milestone in our efforts to modernize Columbia’s interstate pipeline system in a balanced, thoughtful and transparent manner,” said Jimmy Staton, Columbia’s chief executive officer. “We acknowledge FERC for their timely review and approval, and appreciate the collaboration from our customers. We look forward to getting the job done. The work we do will help ensure safer, more reliable pipeline infrastructure for our customers and the communities across our footprint.”

Under the settlement, Columbia will invest approximately $300 million per year, in addition to a $100 million investment in ongoing maintenance, over the 2013 through 2017 period on system improvements, which include:

• Replacing Aging Infrastructure – commencing the replacement of approximately 1,000 miles of existing interstate transmission pipelines, primarily bare steel (400 miles in the first five years);
• Upgrading Natural Gas Compression Systems – replacing and modernizing more than 50 critical compressor units along the pipeline system that will enhance system efficiency and improve environmental performance;
• Increasing Pipeline System Reliability – uprating pressures and looping systems where needed to ensure gas is reliably delivered to critical markets; and
• Expanding In-Line Inspection Capabilities – facilitating Columbia’s ability to perform state-of-the-art maintenance and inspections without interrupting services

Infrastructure investment work will take place across Columbia’s footprint, including Kentucky, Maryland, Ohio, Pennsylvania, Virginia and West Virginia. More than 7,000 direct jobs are expected to be created as a result of the infrastructure investment program. That work will cover a broad range of activities, including facility engineering and design, permitting, project management and a variety of construction trades.

Working with FERC and other federal, state and local agencies, Columbia will continue to engage key stakeholders, landowners and customers throughout the planning and construction process. More information about the company’s investment projects can be found on www.ngts.com.

Columbia projects that its entire infrastructure investment plan could involve an investment of approximately $4 billion over an extended (10-15 year) period.

SOURCE: http://www.dailymarkets.com/stock/2013/01/25/columbia-gas-transmission-receives-ferc-approval-of-customer-settlement-facilitating-pipelines-long-term-infrastructure-investment-plan/

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The new route avoids Nebraska’s Sand Hills, an environmentally sensitive region overlaying the Ogallala aquifer, the state’s main source of groundwater. The pipeline will still cross the aquifer, though in a less sensitive area, according to a letter Heineman, a Republican, sent Tuesday to President Barack Obama and Secretary of State Hillary Clinton informing them of his decision.

“Keystone would have minimal environmental impacts in Nebraska,” Heineman said in the letter. “The concerns of Nebraskans have had a major influence on the pipeline route, the mitigation commitments and this evaluation.”

Heineman requested that Nebraska’s environmental review and route approval be added to the study underway by the State Department, which has authority over the project because it crosses an international border. TransCanada executives have said U.S. approval for the pipeline could come by the end of March. Victoria Nuland, a spokesman for the State Department, said the review won’t be ready by then.

“Keystone XL is the most studied cross-border pipeline ever proposed, and it remains in America’s national interests to approve a pipeline that will have a minimal impact on the environment,” Russ Girling, chief executive officer for the Calgary-based pipeline company, said Tuesday in an emailed statement.

Supporters of the 1,661-mile project have said it will provide thousands of jobs and help the United States avoid dependence on energy sources from politically unstable places. Critics have turned the pipeline proposal into an environmental debate over Canada’s oil sands and the heavy crude’s contributions to air and water pollution. Blocking pipeline transport of the oil to markets in the U.S. and overseas might jeopardize development of the resource.

TransCanada’s original permit request to build the $7.6 billion pipeline, planned to stretch from Alberta’s oil sands to Gulf Coast refineries, was delayed and ultimately rejected last year by the State Department after Heineman and other Nebraska officials criticized the route.

The project should now get “the final green light,” Sen. Mike Johanns, a Nebraska Republican who opposed TransCanada’s original route, said in a statement. “I hope President Obama will swiftly approve the project so we can take a significant step forward in meeting our energy needs.”

After the initial proposal was rejected last year, TransCanada broke the project into two pieces, one running from Alberta to Steele City, Neb., and the other from Oklahoma to Texas refineries. Construction has begun on the southern portion of the pipeline, and environmental activists have been arrested in several areas of Texas after staging protests or chaining themselves to construction equipment.

SOURCE: http://www.mysanantonio.com/business/article/Nebraska-governor-approves-Keystone-XL-route-4215201.php#ixzz2Itv8K5O1

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Bill Bennett made that comparison Tuesday while speaking at a press conference to announce the final regulatory pieces have fallen in place for a new liquefied natural gas plant to be built on a native reserve near Kitimat.

The massive LNG plant, a joint venture by Apache Canada Ltd. and Chevron Canada Ltd., in co-operation with the Haisla First Nation, will process nearly 700 million cubic feet of gas per day, becoming a key link in the transportation chain between B.C.’ s northeast gas fields and off-shore markets.

Mr. Bennett said the plant, the first of six that have been proposed for the West Coast, will open up B.C.’s massive gas fields and allow the resource industry to thrive like it never has before in the province.

“The story here is a story about British Columbia exploiting an opportunity … on the scale of what faced Alberta 40 to 50 years ago,” Mr. Bennett said.

“The opportunity for B.C. really is on the same scale as for example, Norway, when they discovered they had off-shore oil [and gas discoveries] and Alberta when they discovered they had oil and could ship it to the U.S.,” Mr. Bennett said.

He said both Alberta and Norway have thrived economically because of the way their governments regulated and encouraged the development of rich oil and gas resources.

“It’s built [Alberta’s] economy and made them, you know, the most [economically] comfortable province in Confederation.

“It’s that scale of an opportunity [for B.C.],” he said.

Last month Apache Canada and Chevron Canada announced they were teaming up to develop gas fields in the Horn River and Liard basins, in northeast B.C.

Apache Corp. chairman Steven Farris has described those fields as “two of the most prolific shale gas plays in North America, with more than 50 trillion feet of resource potential.”

At a press conference in Vancouver, Mr. Bennett and John Duncan, federal Minister of Aboriginal Affairs and Northern Development, jointly announced regulatory changes that they said have now cleared the way for construction of the Kitimat LNG plant.

Haisla Chief Councillor Ellis Ross praised both levels of government and industry for working with the band to bring the project forward.

“Our people have been looking at natural gas projects since the 1980s … this is a small example of what can be done if all … four parties are focused,” he said.

Mr. Bennett said the regulatory changes allow the province to enforce provincial environmental standards on reserve lands, which are technically under the jurisdiction of the federal government.

Tim Wall, president of Apache Canada, said the change provides “regulatory certainty” for the Kitimat LNG plant, allowing construction to proceed.

“It’s unusual to be here celebrating regulations,” said Mr. Bennett, who has a reputation for battling red tape.

Mr. Bennett, whose government is trailing in the polls as it seeks re-election in May, said developing B.C.’s gas fields is of “profound” economic importance to the province.

“It’s huge and it has the potential to change the frame for British Columbia in terms of the jobs [created],” he said.

Mr. Bennett said the chronic unemployment problems that burden many small northern communities, particularly native communities, could be relieved by the development of B.C.’s gas fields.

SOURCE: http://www.theglobeandmail.com/news/british-columbia/bennett-predicts-a-natural-gas-boom-as-way-cleared-for-lng-plant/article7649911/?utm_source=Shared+Article+Sent+to+User&utm_medium=E-mail:+Newsletters+/+E-Blasts+/+etc.&utm_campaign=Shared+Web+Article+Links

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In a joint statement issued Thursday, Dominion and Caiman Energy II, LLC said they would sign a $1.5 billion joint venture by the end of the month.

Blue Racer Midstream LLC will be an equal partnership between Dominion and Caiman, with Dominion contributing existing equipment and facilities valued at about $800 million and Caiman contributing the additional funding over time, the companies said.

The development is expected to help the state’s gas and oil industry grow more smoothly because it will provide the necessary pipeline capacity and processing plants immediately to market the gas as it flows from the new wells.

The absence of gas processing plants and pipelines to newly drilled remote wells has hampered Ohio shale gas development, say analysts, creating a kind of chicken and egg situation because such expensive projects could not be built without the certainty that the wells would be drilled.

Dominion will also contribute a processing plant now under construction in Natrium, W. Va., just across the Ohio River, as well as a large diameter pipeline already connecting the plant to Dominion East Ohio’s gathering pipeline system. The plant is being built next to an older but similar facility.

Earlier this year, East Ohio converted part of its major north-south pipeline system in Ohio to move gas from Ohio Utica shale fields to the Natrium processing plant. The lines were built decades ago to move gas from West Virginia and southern Ohio to the heavy industries in Northeast Ohio, industries that have either shrunk or disappeared.

Blue Racer Midstream’s initial plan is to convert more of East Ohio’s major pipelines to “wet gathering lines” and feed the unprocessed gas from thousands of wells the industry anticipates will be drilled in the Utica shale to the Natrium plant.

The plant will clean up raw or rich gas from the wells, removing oils and then separating the more valuable industrial gases — butane, propane, and ethane — from the methane that will become heating or natural gas.

The various gases and oils can then be shipped from the plant to multiple markets, said the companies, either by truck, railroad, pipeline or barge facilities.

“The Utica shale has enormous potential to provide jobs and revenues for the local Ohio economy,” said Thomas F. Farrell II, Dominion’s chairman, president and chief executive officer, in a prepared statement.

Jack Lafield, Caiman’s chairman and chief executive officer, said Dominion “brings well-positioned assets and experienced operations for gathering, processing, fractionating and delivering natural gas and liquids produced from the Utica shale field.”

Three other similar projects are also under way.

Earlier this month, a partnership of companies led by M3 Midstream, LLC, of Houston, announced its $1 billion gas processing plant under constructionin Columbiana County is on schedule to open in May 2013. Chesapeake Energy had been part of the group but sold its share.

In early November, two Denver companies, MarkWest Energy Partners, a gas transportation and processing company, and Antero Resources, a gas producer, partnered with a Texas investment company, the Energy and Minerals Group, to build processing plants and pipelines in Nobel County. State officials estimated the initial investment at $500 million.

In July, NiSource, Inc., parent company of Columbia Gas of Ohio, announced a joint venture with Texas exploration and production company Hilcorp Energy Co. to build about 50 miles of pipeline and a gas processing plant in the state. NiSource estimated the initial cost at about $300 million. In this latest announced project, Dominion intends to contribute its existing gas gathering pipeline system with an eye toward expanding its capacity to move at least 2 billion cubic feet of natural gas per day.

SOURCE: http://www.cleveland.com/business/index.ssf/2012/12/dominion_resources_plans_15_bi.html

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