News Flow

INGAA: no middle for midstream development

The topsy-turvy nature of oil and gas prices since 2014 caused the INGAA Foundation to update its midstream infrastructure devel- opment forecast through 2035 to reflect new market dynamics and austerity from both producers and midstream operators. The most telling aspect of this new report, pre- pared by ICF International, is that it doesn’t include a base case, only an optimistic high case and a less-optimistic low case.

“The scale of uncertainty that currently exists in energy markets is more pronounced than it has been in quite some time, making it difficult if not impossible to develop a sin- gle ‘base case’ scenario to represent oil and gas supply development and market growth and the associated infrastructure needs,” the report said.

While prices are forecast by INGAA to improve in both scenarios, excessive sup- ply will limit improvement. Consequently, the updated report anticipates much lower prices than previously forecast by the asso- ciation in 2014.

INGAA now anticipates crude prices to improve to $75 per barrel (bbl) on a long- term basis, down from $100 per bbl on a long-term basis in the previous report.

The difference between both pricing sce- narios is the amount of time it would take to achieve this average price level. The high case anticipates it would begin by 2025 while the low case anticipates it would occur by 2030. In addition, the low case anticipates prices would remain below $40 per bbl until 2018.

Reduced crude prices are also expected to have a major impact on NGL prices and pro- duction. The forecast was revised to reflect a market awash in production. More produc- tion is expected to be driven by gas output growth in both cases. The report forecasts an average of between 12.9 million barrels per day (MMbbl/d) and 13.5 MMbbl/d in the high case and 10.7 MMbbl/d by 2035 in the low case.

There is also a marked difference between the high and low cases for gas prices, with the key difference being when export demand will increase from LNG exports and Mexico pipelines. Long-term prices are lower than previously forecast because of the reduction in well completion costs that will increase production from previously forecast levels.

It is projected that Henry Hub gas prices will trade between $4 and $5.50 per million Btu (MMBtu) after 2020 in the high-case scenario with this demand increasing fairly quickly. However, gas-fired power gener- ation would grow at a slower pace due to reduced economic activity in the low-case scenario. In this case, INGAA’s forecast is 15% lower at $3.50 per MMBtu and $4.50 per MMBtu than the high-case scenario.

The expected production decline for crude, gas liquids and gas will result in less midstream infrastructure development in the coming years than had been forecast two years ago. However, significant gas pipe- line construction is still taking place and is scheduled to continue for the next few years because many projects have obtained regu- latory approvals.

INGAA anticipates the need for between 45 billion cubic feet per day (Bcf/d) and 58 Bcf/d of incremental gas takeaway capacity in the U.S. and Canada between 2015 and 2035; the bulk of this capacity is needed in the Northeast, Southwest and Canada. This translates to between 7,100 miles and 8,500 miles of new gathering pipeline construction.

Additional NGL takeaway capacity will need to increase between 1.1 MMbbl/d and 2.3 MMbbl/d between 2015 and 2035; the majority of this capacity will be added in the Midwest, Northeast and Southwest before 2020.

The dominance of the Marcellus and Utica is expected to negatively impact gas production out of the Southwest because gas-on-gas competition favors Appalachian production. The high-case forecast antici- pates these flows to decrease from 10 Bcf/d to nearly 6 Bcf/d. --Frank Nieto

What's that light in the ethane tunnel?

There’s light at the end of the long, dark ethane tunnel, according to a leading mid- stream consultant.

“But that can mean different things. It could mean better times ahead or it could mean an oncoming train,” Peter Fasullo, principal at Houston-based EnVantage Inc., told a standing-room-only crowd in a session at the 95th annual GPA Midstream Association convention in New Orleans.

Ethane is unique among gas liquids because of its limited uses, Fasullo noted. “It really has only one end use, and that is for ethylene production. The suppliers greatly outnumber the users.”

He reviewed ethane’s supply-demand balance, which has been in great oversupply since 2012 due to NGL-heavy production from the unconventional shale plays. That has led to giveaway prices and large eth- ane-rejection volumes, in which much of the ethane extracted from raw field gas goes back into the gas transmission system.

In response to the upturn in shale gas production, the midstream has added 26.5 Bcf/d in gas processing capacity in the last four years, “and virtually all of that has been deep-cut cryogenic capacity—increasing the supply of ethane.”

Meanwhile, end users must take several years to build new cracking capacity that makes use of that surging supply. That, in time, will be a sizeable market. In addition to new domestic cracking capacity, Fasullo pointed out there are growing export mar- kets for ethane as cracking plants switch from more expensive naphtha feedstocks.

So what lies ahead? It’s hard to say, Fasullo noted, repeating his light at the end of the tunnel example. Significant new cracking capacity will come onstream in late 2017 and 2018—right about the time that ethane production, unfortunately, drops off—thanks to the current decline in drilling. Because of that slowdown, the midstream buildout also is slowing and much of the potential new ethane produc- tion lies far from the cracking plants along the Gulf Coast.

“A shortfall in U.S. ethane supplies is probable in the 2018 to 2020 period,” he added. “U.S. and foreign petchems have taken it for granted that ethane will remain oversupplied and cheap,” but that may not be the case.

“The supply-push needs to fully trans- form to a demand-pull” to balance the market, Fasullo emphasized. “The inte- grated midstream players who can take ethane from the field to the end market will benefit the most.” --Paul Hart

Former Shell exec to industry: ‘get self-help,’ change

A former president of Shell Oil Co. delivered a strong message to the U.S. oil and gas industry: Get some self-help, the industry is partly to blame for its dire straits.

The dose of tough love served as a real- ity check for an industry that has accepted the sector’s up-and-down cycles, instead of doing what it can to change the game.

The latest downturn, the result of a sup- ply-demand imbalance, has cut into profits and prompted many oil and gas producers to produce less until market conditions improve. Hundreds of thousands of oil and gas workers have lost their jobs.

“This cyclical nature of our business is somewhat self-imposed. Shame on us,” John Hofmeister, founder and CEO of Cit- izens for Affordable Energy, told a roomful of oil and gas executives. “Shame on us for two reasons: We haven’t figured out yet how to give ourselves some self-help. We are very fragmented.”

Speaking during the recent Decision Strategies oilfield breakfast, Hofmeister said the industry—particularly oil and gas compa- nies in the U.S.—is somewhat responsible for its predicament. Geopolitical wrangling forced leading OPEC producer Saudi Arabia to “defend itself against the hegemony of the Iranians and the Russians” by not lowering oil production—its and others’ economic lifeblood. That, he said, disturbed the market-balance supply-demand relationship, sending oil prices down and leaving U.S. shale producers among others as collateral damage.

But despite its intellect, the industry does not know how to help itself, Hofmeister said.
Competition, the “I’ll take care of mine; you’ll take care of yours and we’ll meet in the marketplace” mentality, is part of the problem.

“We have been manipulated and victim- ized too many times through too many cycles over the last 60 years by OPEC and by our own political leaders to our regret,” Hofmeister said. “But at the same time we see things that we leave alone that could be addressed.” —Velda Addison

Who will export hydrocarbons after 2025?

A satellite view of the refining and petro- chemical industry from 2005 would clearly show a major shift in processing capacity from North America and Europe toward Asia and the Middle East. Although several major heavy crude upgrading projects were underway at that time in the U.S. Gulf Coast (Motiva in Port Arthur, Texas) and Mid- west (BP in Whiting, Ind.), there was no indication that the North American down- stream industry would become a significant exporter by 2015.

Fast forward to 2025: the Middle East and Asia are still projected to be major exporters of refined products and petrochemicals, but perhaps not to the extent that was to be expected.

A Chatham House study observed that Saudi Arabia could become a net oil importer by 2038. According to Enerda- ta’s “Yearbook 2015: Key World Energy Market Data,” Saudi Arabia, with a pop- ulation of about 30 million people, is already the world’s sixth-largest consumer of oil alongside other countries with much larger populations.

In comparison, India with a population soon expected to exceed China’s 1.3 billion, only surpasses Saudi Arabia’s oil consump- tion by 700,000 bbl/d.

Saudi Arabia is currently consuming about 25% of the oil it produces and at a rate that is three times faster than the pop- ulation growth rate, according to the Par- is-based International Energy Agency (IEA). These statistics seem to further support the view that U.S. exporters are better posi- tioned to compete against foreign exporters, including Saudi Arabia and others. Con- sidering additional factors, such as Mid- dle Eastern geopolitical instability; slower growth in China (single digit today rather than double digits pre-2014); and disap- pointing downstream expansion in South America and Africa gives further credence to North America emerging as a source of major refinery and petrochemical exports.

In the latest Petroleum Monthly Mar- keting report released by the U.S. Energy Information Administration (EIA), it was noted that total U.S. petroleum product exports continued to increase in 2015, up 467,000 bbl/d from 2014 to 4.3 MMbbl/d, driven by increased exports of distillate fuel, motor gasoline and propane. The EIA report also noted that Mexico and countries in Central and South America continue to be major recipients of U.S. petroleum prod- uct exports. Ironically, the industry narrative going back to the late 1990s was that the U.S., to reduce its dependence on imports of Mid- dle Eastern hydrocarbons, would become the primary importer of refined products from Brazil, Venezuela and Mexico.

This never happened.

But like other refiners throughout the world, U.S. refiners compete in an increas- ingly oversupplied international market. The IEA noted that excess refining capacity could approach 5.3 MMbbl/d by 2020, with about 75% of that new capacity due to start up in the Middle East and Asia. Since 2015, Middle East countries have accelerated clean energy programs. For example, to avoid lost oppor- tunity costs (the real cost of hydrocarbon output forgone for export) in the burning of hydrocarbons for generating electricity, Abu Dhabi is already operating one 100-mega- watt (MW) solar plant, and in 2015, Dubai awarded a contract for a 200-MW solar plant for generating electricity.

These hydrocarbon exporting countries have been announcing plans to deal with excess domestic oil consumption, includ- ing reduced fuel subsidies, energy efficiency improvements primarily based on solar energy, natural gas and even coal and nuclear to produce electricity instead of burning oil. The burning of oil to produce electricity is a practice that most Western countries abandoned long ago. —Rene Gonzalez

Study measures corrosion’s cost

NACE International released a new study that measured the significant—and detri- mental—impact that corrosion will have on the world’s economy; the study also exam- ined the need for effective corrosion man- agement programs (CMP) by industry.

The research, published in a 216-page report entitled “International Measures of Prevention, Application and Econom- ics of Corrosion Technology” (IMPACT), estimated that the eventual global cost of corrosion to assets will equal $2.5 trillion— equivalent to roughly 3.4% of the global gross domestic product. The two-year study was released at the society’s March 2016 con- ference in Vancouver, British Columbia.

It examined the economics of corro- sion and the role CMP play in establishing industry best practices. The study found that implementing corrosion prevention best practices could result in global savings of between 15% and 35% of the potential cost of damage, or between $375 million and
$875 billion.

“The IMPACT study reinforces what recent news headlines have made all too clear: there needs to be a change in how corrosion decisions are made,” said Bob Chalker, CEO of NACE International. “Whether it is a pipe- line, an airplane, a water treatment plant or highway bridge, corrosion prevention and control is essential to avoiding catastrophic events before it’s too late.”

Expanding on a discussion of corro- sion’s cost to businesses and industries worldwide, IMPACT assessed corrosion management across various industries and regions. Specifically, the study examined the oil and gas, pipeline and drinking and wastewater industries, as well as the U.S. Department of Defense.

The report highlighted a case study of corrosion management within the automo- bile industry, which it considered a success story. Over time, the study said, corrosion management saved $9.6 billion, or 52% annually, in 1999 compared with 1975.

“Looking at the success within the auto industry, corrosion prevention decisions were made at the highest levels,” added Chalker. “The result has been lower corro- sion costs for automakers and longer lasting autos for consumers.”

The IMPACT study covered energy busi- ness issues in depth, noting “corrosion has been a major cost in the operation of oil and gas facilities.

“The oil and gas industry is a capital-in- tensive industry with assets ranging from wells, risers, drilling rigs and offshore plat- forms in the upstream segment, to pipelines, LNG terminals and refineries in the mid- stream and downstream segments,” it noted.

The effectiveness of CMP within oil and gas can vary by “size, geographic location and culture of the companies,” it added. The breadth and effectiveness of corrosion control efforts “differed significantly,” it cautioned.

“When there are significant policy differ- ences within the same company, this would indicate that the corrosion management policy is not truly integrated into the orga- nization’s policy at the highest level, either deliberately or by omission,” it said. —Paul Hart

TransCanada transparent to win pipeline opponents

Canadian First Nation opposition to TransCanada Corp.’s Energy East Pipeline project may appear to be ramping up, but the company firmly believes it can change at least some of its opponents’ minds.

A recent letter from Mohawk Kahnesatá:ke Grand Chief Serge Simon to Québec Premier Philippe Couillard threatened legal action to halt the proposed 2,850-mile pipe- line that is designed to carry 1.1 MMbbl/d from Alberta and Saskatchewan in western Canada to refineries in eastern Canada. Simon, who represents the Iroquois Caucus, specifically expressed concerns about the potential for spilled toxins to contaminate waterways, including the Ottawa River.

TransCanada is not brushing the concerns aside.

“It’s very, very clear to us that this project does, for some people, raise issues regarding the protection of the environment, especially where it concerns waterways,” Tim Duboyce, spokesman for the company, told Midstream Business. “This particular grand chief has raised this in the past and we are working to address those concerns as best as we can.”

TransCanada’s approach is to mix trans- parency along with plenty of engagement, both in terms of discussions and eventual participation in construction and operation of the pipe, which has a projected in-ser- vice date of 2020. The company has signed 51 agreements so far with First Nations and Métis (people of mixed European and indig- enous ancestry) communities, funding inde- pendent studies to assess potential impacts on traditional land use, particularly during the construction phase. The line will cross traditional lands of 166 indigenous commu- nities across Canada.

“We have also signed up 61 differ- ent traditional knowledge studies that are either completed by now or are underway,” Duboyce said. “These are ways in which First Nations and Métis communities look in more detail at the traditional use of the land in the context of the eventual construction of the pipeline. Eventually, there will also be significant opportunities in terms of work— in terms of suppliers of goods and services during the construction of the project from different entrepreneurs based in indigenous communities across Canada as well.”

Energy East will deliver crude oil to three facilities in Eastern Canada:
• Suncor Energy Inc.’s refinery in Montréal;
• Valero Energy Corp.’s Jean-Gaulin refinery in Lévis, Québec; and
• Irving Oil’s refinery in Saint John, New Brunswick.

At the moment, the refineries, with a combined capacity of 600,000 bbl/d of feed- stock, are supplied by train from the U.S. and other parts of Canada, or by ship from foreign suppliers that include Venezuela and Nigeria. Completion of the pipeline, Duboyce said, would eliminate the need for the equivalent of 1,500 rail tankers per day, as well as all imported crude from outside North America.

Duboyce cited a study last summer by Calgary-based Fraser Institute, “Safety in the Transportation of Oil and Gas: Pipelines or Rail?,” that concluded that while both rail and pipelines are fundamentally safe, moving crude oil by rail introduces more risk than pipelines, and trucking poses more risk than rail. The researchers determined that transporting crude by rail in Canada is
4.5 times more likely to result in a spill than moving it by pipeline.

Among its efforts to alleviate safety concerns along the route of the pipeline, TransCanada agreed to significant move up discussions on emergency response plans, though federal regulations do not mandate those discussions until after the pipeline is in the ground. Taking the extra steps signals movement toward gaining the confidence of municipalities that may be difficult to quan- tify, Duboyce said, but nevertheless can be considered progress.

“I don’t believe it’s a foregone conclusion that those who do have concerns about the project at one point in time will continue to have those concerns in the future,” he said. “That’s one of the reasons that we are work- ing so hard to engage different communities. The benefits of this project outweigh any potential impact.” —Joseph Markman

CapLink MLP Forum: ‘lower for longer’

The atmosphere at the third annual Capital Link Master Limited Partnership Investing Forum was one of uncertainty mixed with optimism. The feeling from the major- ity of the speakers was there are still con- cerns over when the industry will begin to recover, but the MLP sector still represents plenty of solid investments.

Though the industry is in perhaps its worst downturn since 1986, there are tre- mendous opportunities at hand, according to Brian Kessens, managing director and portfolio manager at Tortoise Capital Advi- sors, who delivered the keynote address at the New York event.

Fears over the impact of producer bank- ruptcies on the midstream were well founded given the decision by the federal bankruptcy courts that allowed one company to reject midstream agreements. However, the feel- ing was that even if more bankruptcies take place, many midstream contracts would be honored since production remains eco- nomic. Additionally, the bulk of midstream operations serve high-quality customers who aren’t in financial trouble.

“The vast amount of production comes from investment-grade companies,” Kes- sens said, while noting that non-invest- ment-grade producers make up about 1% of all domestic production. “If the recent $8 billion of successful producer equity offerings indicates anything, it’s that balance sheets are only getting healthier and bank- ruptcies are largely the exception.”

Kessens’ colleague Brian Sulley, who is vice president of business development at Tortoise, added that there is still room for growth opportunities in the midstream. “There is a lot of short-term volatility, but long term there’s lot of need for infrastruc- ture, especially with pipelines,” he said.

John Lewis, chairman and CEO of CONE Midstream Partners LP, agreed that there is a large backlog of projects that will be needed.

Speakers were concerned about when a recovery would begin; many analysts advised that it would be prudent for some MLPs to maintain or even slightly drop distributions until the market improves.

The phrase “lower for longer” was consistent throughout the event. “Fundamentals suggest ‘lower for longer’ and no matter what you hear, fundamentals still matter,” said Peter Boylan III, chairman, president and CEO of Cypress Energy Partners LP.

These fundamentals do point to a down- turn, but there is also the suspicion that investors were over-reacting to the down- turn at least when it came to the MLP mar- ket, specifically the midstream sector.

“Ninety percent of the risk is from weaker producers … Investors are overanalyzing and over-penalizing companies,” Jay Hat- field, co-founder and president of Infra- structure Capital, said. He did note that investors seemed to be coming around to MLP investments as more data on the sec- tor’s overall strength are released.

A growing sub-sector of the midstream is LNG, which is seeing multiple domes- tic export terminals come online this year. Though LNG MLPs have to better manage their capital in a down market, the benefit is that the cost of shipping is marginal once the facilities are built, according to Graham Robjohns, CEO of Golar LNG Partners LP.

While emerging markets have gotten the most focus of the LNG picture, arguably just as important are areas that want gas but don’t have access to it. These markets require floating storage and regasification units, which represent a bigger total market than China for LNG, according to Robjohns.

There are worries about producers can- celing their LNG shipment contracts, but panelists agreed this was unlikely because producers wouldn’t want to give up the contracted capacity that is tied to long-term contracts. It also would be difficult for com- panies that canceled LNG contracts to secure new ones in the future. —Frank Nieto

Saudi Aramco, Shell to split Motiva JV

Saudi Arabian Oil Co.’s (Saudi Aramco) wholly owned subsidiary Saudi Refining Inc. (SRI) and Royal Dutch Shell Plc, through its U.S. downstream affiliate, signed a non-binding letter of intent (LOI) to divide the assets of Motiva Enterprises LLC.

Motiva is a joint venture (JV) formed in 1998 that has operated as a 50:50 refining and marketing JV between the parties since 2002.

In the proposed division of assets, SRI will retain the Motiva name, assume sole owner- ship of the Port Arthur, Texas, refinery—at 600,000 bbl/d the biggest in the U.S.—and retain 26 distribution terminals.

SRI will also have an exclusive license to use the Shell brand for gasoline and diesel sales in Texas, the majority of the Mississippi Valley, the Southeast and mid-Atlantic markets.

Shell will assume sole ownership of the Norco, La., refinery where it operates a chemicals plant, the Convent, La., refin- ery, nine distribution terminals and Shell- branded markets in Florida, Louisiana and the Northeast region.

“Motiva’s performance has transformed in the last two years,” John Abbott, Shell’s downstream director, was quoted as saying. “We propose to combine the assets we will retain from the joint venture with Shell’s other downstream assets in North Amer- ica. This is consistent with both the group and downstream strategies to provide sim- pler and more highly integrated businesses which deliver increased cash and returns,” Abbott said.

“Saudi Aramco subsidiaries and affili- ates have had a presence in the U.S. for over 60 years, and the Motiva joint venture with Shell has served our downstream business objectives very well for many years,” Abdul- rahman F. al-Wuhaib, senior vice president of downstream at Saudi Aramco, said in a prepared statement.

“However, it is now time for the partners to pursue their independent downstream goals. The Port Arthur refinery will advance Saudi Aramco’s global downstream integra- tion strategy through supply and trading, refining and fuels marketing, chemicals and base oils,” al-Wuhaib continued.—Jay Bolan

PHMSA proposes new gas line rules

The Pipeline and Hazardous Materials Safety Administration (PHMSA) pro- posed regulations that would update safety requirements for the nation’s natural gas transmission pipelines. The scope of safety coverage would be broadened through the addition of new assessment and repair criteria for gas transmission pipelines and expanded protocols to include pipelines located in medium-density population areas, known as “moderate consequence areas,” where an incident might pose risks to human life.

The proposed regulations provide pipe- line operators with regulatory certainty, and respond to both Congressional mandates and outside safety recommendations, the Department of Transportation said.

Don Santa, president and CEO of the Interstate Natural Gas Association of America (INGAA), said the trade group is “encouraged that the long-awaited proposal has been released” and will respond with for- mal comments based “on whether PHMSA’s proposal is consistent with the voluntary pipeline safety program INGAA’s members undertook in 2012.”

Transportation Secretary Anthony Foxx said the rule proposal follows “significant growth in the nation’s production, usage and commercialization of natural gas.” The proposal “includes a number of common- sense measures that will better ensure the safety of communities living alongside pipe- line infrastructure and protect our environ- ment,” he added.

PHMSA is part of the U.S. Department of Transportation.

The proposed regulations address four congressional mandates in the Pipe- line Safety, Regulatory Certainty, and Job Creation Act of 2011, one Government Accountability Office recommendation, and six National Transportation Safety Board (NTSB) recommendations.

Proposed regulations include an NTSB recommendation made in the wake of the San Bruno, Calif., pipeline rupture in Sep- tember 2010 that pipelines built before 1970 be tested. Pipelines built before 1970 cur- rently are exempt from certain pipeline reg- ulations because they were constructed and placed in operation before current pipeline safety regulations were developed.

In its investigation of the Pacific Gas & Electric gas pipeline failure and explosion, the NTSB concluded that hydrostatic testing of grandfathered pipelines would have likely exposed the defective pipe that led to the pipeline failure.

There was a “pressing need to enhance public safety and the integrity of the nation’s pipeline system,” said PHMSA Administra- tor Marie Therese Dominguez. “The pro- posal’s components address the emerging needs of America’s natural gas pipeline sys-tem and adapt and expand risk-based safety practices to pipelines located in areas where incidents could have serious consequences.”

The proposed changes provide pipeline operators with regulatory certainty that they need when making decisions and invest- ments to improve gas transmission infra- structure, and address priorities outlined as part of the Obama administration’s Climate Action Plan to reduce methane emissions.

The proposed changes to gas trans- mission safety regulations are expected to result in fewer incidents, which could lead to a reduction in gas released into the atmo- sphere as greenhouse gases (GHG).

The proposed rules are expected to result in net annual average reductions of 900 tonnes to 1,500 tonnes of CO2 and 4,600 tonnes to 8,100 tonnes of methane. The regulations also propose changes to the way pipeline opera- tors secure and inspect gas transmission pipe- line infrastructure following extreme weather such as hurricanes and flooding. —Paul Hart

Tallgrass expanding pipeline, water services

Crude oil delivery and exploration logistics for the Rockies is the name of the game for Tallgrass Energy Partners LP, according to Jeff Nelson, vice president and general man- ager of water, who spoke recently at Hart Energy’s DUG Rockies conference at Den- ver’s Colorado Convention Center.

The Lakewood, Colo.-based company, which operates in 10 states, holds 50% own- ership in the REX Pipeline and 98% owner- ship in the Pony Express Pipeline. Tallgrass Energy Partners also own BNN Water Solu- tions with 92%.

“We have a Federal Energy Regulatory Commission [FERC]-regulated crude pipe- line that runs from Guernsey, Wyo., to a plant in Cushing, Okla. Our supply connec- tions are to the Bakken and we have local receipt points to the DJ Basin and Powder River Basin,” Nelson said.

The 764-mile Pony Express Pipeline car- ries crude from Guernsey, Wyo., to Cush- ing, Okla., with connections throughout the Rockies. The pipeline is designed to han- dle about 320,000 bbl/d. Over the last few months, according to Nelson, the company has been averaging about 288,000 bbl/d.

Tallgrass also has processing and treat- ment plants near Douglas and Casper, Wyo., with a 3,500-bbl/d fractionator at the Casper plant. To the south in Weld County, Colo., there is a NGL takeaway plant run- ning from the Redtail processing plant to the Overland Pass Pipeline.

“Our wall-to-wall gas pipeline, REX, recently started flowing gas in our Zone 3 in June of 2014. We increased our flow from 1.8 billion cubic feet per day [Bcf/d] to about 2.6 Bcf/d of the Zone 3 east-to-west capacity,” Nelson said. “We also could have it flowing both directions, east-to-west and west-to-east, running flat out at 1.8 Bcf.”

Tallgrass’ BNN Water Solutions division provides Rockies water sourcing and gath- ering, pipeline transport, storage and dis- posal with more than 90 miles of permanent pipelines that can handle up to 35,000 bbl/d, Nelson said.

In the current market, Nelson said Tall- grass wants to acquire noncore assets from E&Ps and expand its BNN water service to build infrastructure and commercially ship water gathering and disposal.

Meanwhile, the company’s terminal group has a terminal at the intersection of the Guernsey-Sterling, Colo., Pony Express Pipeline.

In third-quarter 2016, Tallgrass is expected to finish the Buckingham terminal, which is off Colorado’s Highway 14 in Weld County. Recently, the company acquired a 20% interest in the Deeprock Development Cushing terminal in Oklahoma, which has 2.25 MMbbl of capacity. —Larry Prado

Feds nix Atlantic from offshore lease plan

The U.S. will continue to be the only major producing country with an Atlantic coastline that does not allow offshore explo- ration for oil and gas. The industry’s quest to open the Atlantic Basin to seismic gath- ering and offshore drilling was squashed by the Obama administration, despite support from four coastal state governors and a peti- tion with 180,000 signatures that was delivered to the U.S. Interior Department.

Concerns raised by coastal communities, the Defense Department and NASA, among others, were enough to outweigh the poten- tial for exploration that has led to discoveries in other parts of the Atlantic.
The proposed program for the Outer Continental Shelf (OCS) Oil and Gas Leas- ing Program for 2017-2022 would have included at least one sale in the Mid-Atlantic and South Atlantic planning areas in 2021. —Velda Addison and Leslie Haines