How big is it, this midstream build-out?

The U.S. Energy Information Administration (EIA) covers midstream action in its 2013 Annual Energy Outlook, which projects energy trends through 2040.

“The midstream sector’s rapid buildup and expansion of natural gas processing, pipeline, and storage capacity have accommodated increasing volumes of NGL (natural gas liquids) resulting from the sharp growth in shale gas production,” the outlook says. Ditto for gas.

For crude, the report determines “The large increase in domestic production of light crude oil and the increase in imports of heavier crude oils have prompted significant investments in crude midstream infrastructure, including pipelines that will bring higher quantities of light sweet crudes to petroleum refineries along the U.S. Gulf Coast. In addition, significant investments are being made to move crude oil to refineries by rail.”

But obtaining an accurate, big-picture number for the value of those trends since the “shale gale” began around five years ago can be hard. There are frequent, sometimes daily, announcements issued by multiple midstream players in the U.S and Canada unveiling all sorts of new projects: a new gathering system here, a repurposed pipeline there, a new rail terminal sprouting from a wheat field, or new storage tanks beside a Gulf Coast dock. The price tag for each project at a minimum always includes the word “million,” or frequently “billion” instead.

That’s a lot of money, even in shrunken 2013 dollars.

It calls to mind the famous quote by the late U.S. Senator Everett Dirksen, after observing the federal government’s large-but-scattershot budgetary process: “A billion here, a billion there, and pretty soon you're talking about real money.”

Those projects include not just an expansion of North America’s midstream but a significant restructuring of it. Product flows based on conventional production and consumption trends since World War II have changed. Regions that were net energy consumers have emerged as net producers, and the industry may be seeing a peak in activity currently.

Mixed results

The impact on the existing midstream has been mixed. Some well-established midstream infrastructure has been glutted. The best example might be the crude trading hub at Cushing, Oklahoma, settlement point for New York Mercantile Exchange futures contracts for West Texas Intermediate (WTI), which for years has been a world standard by which prices for other crude grades have been set. But the Cushing bottleneck has upset traditional crude pricing structures.

On the flip side, some operators have seen traditional business wither. The eastbound Rockies Express Pipeline, built to move abundant conventional natural gas from Rocky Mountain producers to major Midwest markets, has seen demand drop. At the east end of its system, newly developed Marcellus and Utica shale gas has replaced that Rockies production. A Deutsche Bank report cites Rockies Express as one of several pipelines “likely to require restructuring or repurposing in order to have a future.”

These flips and flops in supply and demand have skewed product prices, due in great part to a midstream infrastructure imbalance.

$200 billion

Claire Farley, managing director at Kohlberg Kravis Roberts & Co., told the Deloitte oil and gas conference in Houston late last year the “mezzanine space” of the industry will require more than $200 billion in investment capital in the next 20 years with “innovations” to come in how to raise that much money.

The INGAA Foundation, the research and marketing arm of the Interstate Natural Gas Association of America, published a report, North American Natural Gas Midstream Infrastructure through 2035: A Secure Energy Future, which puts some numbers, at least for gas-related assets, in perspective.

“The cost of new natural gas transmission infrastructure (including gas storage and lateral connections) needed over the next 25 years is projected to average approximately $5.7 billion per year, or more than $141 billion (real 2010 dollars) total. Gathering and processing adds an additional $2.6 billion per year on average or about $64 billion total. The gas transmission mainline category is projected to account for approximately half of the total capital required for midstream natural gas infrastructure in this study,” the report says.

It goes on to point out that “natural gas pipeline companies do not build interstate pipeline projects unless shippers are willing to sign long?term contracts for natural gas transportation” and the Federal Energy Regulatory Commission (FERC) must confirm there’s a need for a project before authorizing it. So all of that work will hardly be on a whim; there’s a need for it.

The foundation adds that projects will be required to move gas from recently emerging plays, such as the Eagle Ford and Marcellus, and connect to the continent’s existing infrastructure. It also lists “big market movers,” such as gaspowered vehicles, liquefied natural gas (LNG) exports and increasing use of gas for power generation. An update on the report, published in 2011, is scheduled for release shortly.

On the liquids side of the business, the Association of Oil Pipelines estimates there are $23 billion worth of liquids pipeline projects under way in 2013 alone.

Brad Olsen, midstream analyst and director with Tudor, Pickering, Holt & Co., has projected an equally impressive estimate of $150 billion in shale-related midstream projects for the 2005-2015 decade.

“There is some variance, those are tough numbers to get,” Olsen tells Midstream Business. “Companies don’t provide exact cost estimates, and I’d venture to say we’re conservative.”

Tudor Pickering’s ballpark estimate breaks down to somewhere around $40 billion in dry-gas projects and $50 billion in gas gathering and processing. “On the crude side, we’re probably looking at $60 billion of infrastructure for major pipeline projects.” The Marcellus play alone has probably drawn in the neighborhood of $10 billion in midstream projects since 2011, Olsen estimates.

Closing the gap

Several planned, large-scale midstream projects have been completed recently and results since they went into service indicate supply and demand may be headed back toward a balance. Two in particular that have had an impact on Cushing’s problems are completion of the first phase of the Seaway Pipeline, which included the reversal of a Midcontinent-to- Gulf line that has been used to move crude oil and natural gas in the past.

The 500-mile, 30-inch pipeline entered service a year ago at 150,000 barrels (bbl.) per day with expanded, 400,000 bbl. per-day capacity going onstream early this year. Work is under way to loop the line, increasing capacity to 850,000 bbl. per day by first-quarter 2014. Enterprise Products Partners and Enbridge Inc. are 50/50 partners in Seaway.

New infrastructure shouldn’t get all of the credit for that balance. Global Hunter Securities observed in a late June report that “uncertainties regarding supply from the Middle East continue to support WTI prices, providing a continued source of pressure on the Brent-WTI price differential.”

Bank of America Merrill Lynch pointed to midstream’s need to expand product infrastructure. “Due to the U.S. becoming a net exporter of refined petroleum products, there could be additional need for refined product infrastructure,” it says.

EIA data show product exports exceeded imports in the second quarter of 2011 and have consistently surpassed imports since. Product exports exceeded imports by an average of nearly 900,000 bbl. per day during the first half of 2013, according to EIA numbers.

The pending emergence of the U.S. and Canada as major LNG exporters will require further midstream modifications to move gas to coastal liquefaction plants. Two Gulf Coast LNG plants, Cheniere Energy’s plant in Cameron Parish, Louisiana, and the ConocoPhillips-led plant at Freeport, Texas, have been fully licensed for export. The federal government is mulling additional applications.

Canada’s needs

Canada’s midstream infrastructure needs appear proportionately greater than those of the U.S. It has similar shale oil and gas potential, plus growing production—and demand for—its heavy oil produced from the oil sands. Bitumen produced from the oil sands also requires inbound shipping of light-oil diluent, another midstream demand.

The newly released crude oil forecast of the Canadian Association of Petroleum Producers (CAPP) sets out what’s happening to meet the needs of producers.

“Given the growing production outlook, the need to reach new markets is a top priority for Canadian oil producers,” CAPP said. “A fundamental shift is occurring in the market due to strong growth in light crude oil production, which is replacing offshore imports to the light-oil refineries in eastern Canada and the U.S. Markets for growing heavy-oil supplies are primarily found in the U.S. Midwest and Gulf Coast. New market opportunities are also emerging as a result of growing demand in Asia.”

The report rates transportation services for western Canada producers as “currently tight” and adds the region’s producers “are essentially landlocked and will need additional transportation infrastructure to bring the growing oil production to market. Protracted approval processes for new pipeline projects are resulting in a variety of creative transportation proposals to access markets. Those creative proposals—south of the border—include rail transport, “a growing transportation option for moving crude oil to markets.”

Finding capital

So who’s going to pay for all of this?

Above and beyond loans and private financing, the high yields offered by master limited partnerships (MLPs)—a corporate structure that has come to dominate the midstream—continue to draw investors. The Alerian MLP Infrastructure Index has consistently outperformed other investment indexes as investors move into partnership units as well as corporate stocks and bonds.

All of those midstream growth opportunities stand out in comparison to the sluggish economic prospects for the U.S., overall. Simmons & Co. initiated coverage on 13 midstream master limited partnerships (MLP) last year and noted in its initial MLP investment outlook that “partnerships and companies that are engaged in crude and NGL infrastructure—including gathering, processing, fractionation and transportation—should continue to benefit from a robust fundamental environment and ample opportunities for organic growth investment” in the next few years.

Simmons projects $251 billion in U.S. infrastructure investments between 2011 and 2035 with gas transmission lines making up the largest share of that amount—$3.9 billion per year for two-and-a-half decades.

That investment trend dovetails with results of a recent KPMG Global Energy Institute study that asked energy industry executives what they see up ahead for the industry. The report found “natural gas is growing in overall importance to the U.S. energy industry,” adding, “Executives expect the growth in shale natural gas and oil production to have profound changes on the prospect of U.S. energy independence, economic growth and consumer technologies.”

But there have been concerns. Pipeline operators view their ability to solicit committed rate contracts from potential customers for new capacity, which can be used to secure project financing, as vital. That principle had been questioned by FERC staff in a rate case involving Seaway. FERC ruled in the pipelines’ favor.

“Billions of dollars are on the table ready to fund new pipeline projects across America and FERC’s actions … will help get those projects financed,” said Andrew Black, AOPL president and chief executive following the ruling.

Getting stronger

There are expectations for midstream mergers and acquisitions to occur as players jockey to get into stronger financial positions.

Deloitte’s Center for Energy Solutions issued a report early this year that projects the build-out “will continue to drive capital spending and funding needs in the midstream sector for years to come.” The report quotes John England, leader of U.S. oil and gas and Deloitte vice chairman, on just how big the capital needs for the sector will be.

“Deloitte believes that, over the next few years, the size of capital expenditures in the midstream area could easily exceed the current market cap of those companies,” says England. “It is therefore reasonable to think that we could see some bigger players enter the market, some consolidation take place, or a combination of both, if the midstream segment is going to continue to support the shale and tight oil activity that is taking place in the U.S.”

Kinder Morgan’s $5 billion acquisition of Copano Energy, which closed in May, is an example of what could be a developing trend.

The Deloitte report also quotes Trevear Thomas, principal: “Looking ahead, we expect continued growth in this area, and related acquisition activity, as MLPs search for quality assets to grow their distributions.”

Tudor Pickering’s Olsen raises an important question for potential midstream/MLP investors: How long will the growth last?

“Beyond the gyrations in the financial markets, over the next year or two investors have to come to terms with the fact that there is not an infinite array of projects out there,” he says. MLP payouts may continue to be comparatively attractive but the current expansive growth will have to slow at some point.

“The chances of finding another Marcellus, Eagle Ford or Bakken where you can sink $20 billion in capital building incremental projects in a hurry may be out there, but we haven’t found it. Investors may buy a stock now with a 4% yield and a 10% growth rate, but that growth rate might be around for the next two or three years. It’s above certainly what we expect the growth rate to be in the long term. Investors need to be cognizant there will be a return to more normal growth rates as we run out of shale-related opportunities, or at least not as plentiful as they were in 2011 through 2013,” he adds.

What can go wrong?

Midstream operators know all about supply and demand and high demand for low supply of parts and supplies has had the predictable impacts: higher prices and shortages that slow projects or throw them over budget.

Gerry Hoover, director of technical services for Valerus in Tulsa, Oklahoma, tells Midstream Business acquiring valves and other necessary parts for the compression, processing and treating systems Valerus fabricates requires planning ahead and creates budgeting problems.

“You have to think about lead times and what goes into strategic inventory,” Hoover says. “This ties up capital. You order something now, but there may not be a payback for two years.”

A major cause of that trend is suppliers are wary from past experience about expanding. “They recognize this is a cyclical business, and business may ramp up today and slow down tomorrow,” Hoover says.

As an industry veteran who has shepherded midstream projects around the world, Hoover feels projected, long-term period midstream expansion may happen—or it may not. Some unforeseen problem, perhaps an economic meltdown similar to what happened in 2008, could derail the trend. Also, there are also consolidations among suppliers, which has further complicated acquiring certain items, he adds.

But some supplier expansion has to occur. Luxembourgbased Tenaris announced early this year it will build its first U.S. seamless pipe mill in Bay City, Texas, south of Houston. The $1.5 billion plant will have an annual production capacity of 600,000 tons of high-quality seamless pipe and is scheduled to go into production in 2016.

Trinity Industries Inc., a Dallas-based firm that specializes in fabricating tanks, pressure vessels, barges and railroad tank cars, is a case in point of how the midstream build-out has stretched suppliers. Trinity said in a recent investor presentation it has a $5.1 billion backlog of rail car orders, $483 million in orders for barges and strong orders for tanks and pressure vessels. In late 2012, it acquired DMI Industries, which manufactures tanks and containers for the oil and gas and chemical industries.

Another complication has emerged in recent weeks— rising interest rates that make MLP units less attractive to investors. That trend could slow the investment inflow.

Tudor Pickering’s Olsen agrees.

“There could still be a lot of actual growth left in the industry in construction activity and new projects,” he says. “And there will be some growth in dividends, 4% to 6% distribution growth in the MLP space at the same time as the risk of interest rates rising 100 to 200 basis points. I don’t think anyone is holding off MLPs; 4% still sounds great when you only get 1% in your money market account. But if (U.S. Treasury) 10-year bond rates jump back up 4% to 5% in the next couple of years, then that growth story becomes more important to people who are more income-dependent investors.” Joe Herman, Tudor Pickering midstream research associate, concurs with Olsen.

“I think June was a pretty good case study in what rising interest rates can do to the MLP asset class. Interest rates were up 25 to 50 basis points, and we saw MLPs get whacked at the end of May. But I don’t know if it will necessary impact their ability to raise capital,” he says.

“Looking at fundamentals as much as we do, projects that have an economic purpose—and most of these infrastructure projects do—will be built and the higher capital costs will be passed along to customers,” Olsen adds. “If you are a Marcellus producer and someone charges you 80¢ to gather and process your gas, and that becomes 85¢ because the cost of capital to that midstream company has gone from 6% to 7% or 8%, that doesn't change the fact that you need those midstream services provided to you as a gas producer.

“I don’t want to sound bearish, but there is more midstream capital than projects to bid on right now. You are seeing investment companies go into deals knowing they are only going to get 7% to 8% returns. But they are still attractive at these current low interest rates,” Olsen adds.

Get out the yardstick

The build-out may be taking hold. One important yardstick to measure the midstream work’s status, the price spread between North American and imported crudes, has narrowed considerably. WTI and North Sea Brent, another important “marker crude” that sets worldwide prices, had a differential in the neighborhood of $20 per bbl. a year ago, favoring Brent. By early this summer, the WTI-Brent gap had dropped to around $1 bbl. as new infrastructure eased bottlenecks—particularly the glut at Cushing. Goldman Sachs has estimated the differential will hold at around $5 bbl. in this quarter. Traditionally, WTI trades at a slight premium to Brent.

Some estimates place this year and 2014 as a crucial topping out of the expansion. A lot of new pipe has gone in the ground, a lot of pipe has been repurposed and motorists at countless grade crossings watch long strings of black tank cars roar by.

So if this is the peak of the build-out, now might be the time for owners to look into their sale, merger and acquisition options, according to Eric Kern, vice president at Allegiance Capital Corp., a private merger and acquisition bank. Kern points to an IBISWorld report that estimates the oil and gas pipeline construction industry’s revenues will increase 4.7% this year as global energy demand boosts domestic investment in infrastructure.

“Elevated energy prices and technological advances are increasing the cost effectiveness of extracting and producing energy from shale and oil sands. The development of these sources is creating unprecedented demand for the construction of pipelines to connect these new production sites with major markets and existing infrastructure,” Kern told Midstream Business recently.

He points to four trends that make 2013-2014 the ideal time for midstream companies to sell: the economy is growing again, major political questions have been answered, corporations are sitting on a $1.8 trillion cash pile and foreign investors want to invest in the U.S., adding “all the factors are in your favor.

“It is clear that the midstream industry is in a growth period with strong demand for products and services in the coming months,” he added.

So is right now a peak-price time for operators looking to sell? Maybe, says Ben Davis, partner with Energy Spectrum Partners and a member of the Midstream Business advisory board. “Things can get better, they can get worse, but the MLP market has been aggressive with valuations recently,” he says, pointing out merger and acquisition activity has been brisk.

“I look at the offerings, and I see a steady flow relative to yield, the trading multiples continue to be strong.” But he cautions “as rates go up, prices are going to come down if trading is based on yield.”

Looking ahead

Olsen’s comment on an unknown and undiscovered shale play out there ties into something other industry observers are starting to mention: Even if this is the peak, the infrastructure build-out will take perhaps 10-plus years to finish and create a midstream system very different than the one that served North America less than a decade ago. The multi-billion dollar investment in the midstream will continue as a strong-but-diminished rate for some years to come and involve new plays, new regions and new methods.

Producers and customers will become better matched as the midstream adjusts. After all, the midstream sector as it was when the shale boom started was the product of a 60-year span that began in the 1940s during World War II. Despite dips, work was generally steady for most of those six decades.

Global Hunter Securities’ big-picture research report on the U.S. oil and gas industry released earlier this year, The Emergence of Saudi America, considers where midstream should be right now in what it calls a “tectonic shift in global oil geopolitics.” The two big North American producing nations are emerging as major oil and gas exporters in addition to re-arranging their own domestic supply and demand flows.

“We view 2013-2014 as a transitional period for U.S. midstream infrastructure as much-needed pipeline capacity comes online and relieves several key bottlenecks that have developed as a result of a recent upstream focus on liquids production,” the study says.

It goes on to cite an important example in West Texas. “In 2013, we forecast that additional crude oil/condensate takeaway from the Permian [basin] will come online and provide more than enough new capacity to cover expected production growth, the majority of which is targeting the Gulf Coast instead of Cushing. This, combined with additional capacity running between Cushing and the Gulf Coast, should result in more unfettered flow and reduced price differentials. Takeaway from the Bakken is already ample but only because of the rapid growth in rail capacity.

“We forecast another year of reliance on rail to transport the marginal barrel from that formation, before new pipeline capacity comes online in 2014. However, rail will continue to play an integral role in Bakken transport post- 2014 due to its flexibility to deliver barrels to non-Cushing markets. The Marcellus region will develop differently and has the potential to turn the Northeast into another NGL hub. The bulk of expected midstream development, including processing, fractionation and takeaway capacity, is expected to come online in 2013 and 2014, with an emphasis on 2014. Lastly, the Eagle Ford is an area of ample midstream infrastructure and, we are looking at takeaway overcapacity in that region.”

Risk Management: Getting The Work Done

By Mary Campos, vice president of exp Energy Services Inc.

In order for North America to achieve energy independence, new pipeline systems to carry oil and natural gas to market must be designed, permitted and ultimately constructed so that operations can begin. The importance of stakeholder engagement and communication throughout the lifecycle of our pipelines is critical to safe and effective operations.

Our local communities and the environments that we live, work and play in are our partners in building a strong energy infrastructure. At the forefront of each and every project is developing a project strategy that brings our energy needs and growth in balance with our communities.

Simply engineering a safe pipeline or providing an environmentally sound route as independent goals often does not lead to project success. It is the integration and connection of the key elements that will lead to success: community, engineering, environment and operations/management.

Understanding and working with the local community to build strong relationships is the first task. Without an awareness of key local drivers, such as sensitive habitats or concerns, does not provide a strong foundation to build the project and support long-term operations and management. The assets will be operating well beyond the date construction is finished so starting off on the right foot is important.

In addition, working with community stakeholders early on allows projects to be developed in a manner that maximizes community benefit by identifying and utilizing local resources.

While every project is unique in its drivers, the basics to effective lifecycle management remain: risk management in all aspects of lifecycle development and operation. Risk management means understanding the risks at each phase of development: preliminary routing/evaluation, route refinement, permitting, engineering design, construction, commissioning and operations.

Key risks

Some of the key risks in the development stage include: community evaluation/ understanding, communications engagement, species evaluation, resource impact analysis, permitting evaluation, constructability evaluation, survey, commercial terms and schedule needs. Without an understanding of the local drivers and resource limitations, potential projects could be stopped before they begin.

Consider a couple of examples: In the Eagle Ford play, the U.S. Army Corps of Engineers shares jurisdiction for water impacts and crossings. While impact avoidance is always the preferred route, sometimes mitigation is required.

Mitigation banks for forested wetlands have very limited availability in South Texas and could lead to permitting delays when impacts occur. This lack of understanding has the potential to significantly impact project schedules and cause delays, leading to overruns on schedule and budget sometimes in excess of 30% to 40%.

In the Utica/Marcellus, species endemic to the shale regions present challenges to projects if not understood and the associated risk managed upfront. Seasonal restrictions on surveys of Indiana bats allow for longer construction windows, combined with challenging slope conditions that can make routing and safe construction of needed infrastructure a challenging task.

There are two options for receiving approval to perform any tree-clearing in areas that are habitat for Indiana bats. One is to conduct a winter habitat analysis that projects the potential habitat impacts to Indiana bat habitat. Rather than surveys for Indiana bats, the assumption may be made that Indiana bats are present within the proposed route area. Assuming presence of Indiana bats, the owner must demonstrate, to the maximum extent practicable, that adverse effects have been avoided by developing avoidance and minimization measures that will protect the bat and its habitat.

The two primary types of impact avoidance measures are: Clearing suitable habitat between September 30 and April 1 and preserving suitable habitat. The second option for receiving approval is to conduct Indiana bat summer presence/ absence surveys. The U.S. Fish and Wildlife Service provided new draft guidance in January. This guidance was designed to provide standardized, rangewide guidelines and protocols that allow for the determination of whether Indiana bats are present or likely absent at a given site during the summer (May 15 to August 15). The guidance provides a phased approach, which includes habitat assessments, as well as acoustic, mist-net, radio tracking and emergence surveys. Once finalized, these guidelines will supersede 2007 guidelines.

Yet Ohio’s Department of Natural Resources will not comment on the draft guidelines until finalized. This illustrates the importance of partnering with local communities and regulators early in the planning phase to understand all the drivers. Without an understanding of these regional drivers, effective planning, at the developmental as well as operational stages, would not be fully addressed and schedules impacted. Projects already in the construction phase can be stopped if seasonal windows are not met, leading to significant cost overruns and stakeholder challenges.

Project success

Engineering and environment being integrated at the onset is critical to project success. Early routing that addresses preliminary routes from an environmental resource impact-avoidance, engineering sustainability and constructability aspect provide the strongest foundation for project success. Having an environmentally sound route that is later found to be not constructable because routing evaluations were done independently will result in delays and often, costs that prevent the potential project from moving forward. Early routing that provides the local community with the confidence that safety is first in the design, construction and long-term operations, impacts to environmental resources have been minimized or managed and the local concerns have been addressed will be the projects with the highest probability of success.

Having the environmental and engineering staffs working together as one team at the onset also provides for more successful regulatory agency-partnering meetings. Early project strategy meetings to engage key regulatory agencies with a sound project strategy that brings together community, engineering and environmental will also help in moving the regulatory process along in a positive manner.

Integration upfront also establishes a strong foundation for the safe operation of our pipelines. Understanding our local communities, the resources that form them and the engineering design for safe operations provide for the effective management of key risk drivers upfront in the planning process.

Local communities being part of that process at the onset help to provide effective outreach strategies in their understanding of how the pipeline is operated safely and the steps taken by operators to ensure this on a daily basis. The environmental constraints are also part of the planning process so operational contingency planning includes all the key important risk drivers from project inception. In the event of any unforeseen incident, contingency planning includes all the key elements necessary to mitigate impacts to our local neighbors.

Whether small gathering-line projects in the shale plays or cross-country transmission projects, successful projects are built on a foundation of communities and industry working together as partners in making North American energy independence a reality.

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