Midstream: Changing Routes, Emphasis for Energy Renaissance

May 2015, Vol 242, No. 5

Richard Nemec, Contributing Editor

As global oil prices were still falling and various parts of the U.S. oil/natural gas space were reassessing plans for 2015, the American Petroleum Institute (API) was reorganizing to better service one of the industry’s growth sectors – midstream.

API said it was going to provide more attention to “pipelines and processing facilities” that connect oil and gas production with markets. The key is infrastructure, according to the globally recognized Washington, DC-based trade and standards-setting group.

API’s new department focusing on the midstream was a natural progression, following the lead of regulators, executives and environmentalists who are more than ever laser-focused on energy infrastructure. API also recognized other industry groups, such as the Association of Oil Pipelines (AOPL), have long been dedicated to midstream issues, so its task will be to complement – not duplicate – efforts.

“Creating a division with our organization focused on midstream issues will enable the industry to address the critical issues around energy infrastructure,” API CEO Jack Gerard said in announcing the new organization in early January. He sees the need for what he labels as “world-class infrastructure” as a key to ensuring that America’s ongoing oil and natural gas renaissance stays on track.

Among the issues looming that will be strongly focused on the midstream is the Obama administration’s push for reduction of methane emissions as part of its climate change strategy. Early in 2015, stakeholders and various third-party experts were weighing how the Obama initiative will take shape. Some are betting on a hybrid of regulatory programs and voluntary, industry-driven efforts.

With less than two years remaining, the president may not have the time to foster a comprehensive new regulatory program. Energy attorneys at the Washington, DC firm of Van Ness Feldman point out that “key industry players have stepped forward with proposals to achieve substantial additional voluntary reductions in lieu of regulation.”

While this sort of industry-driven effort focuses on harnessing new technologies in leak detection/prevention and other safety-maintenance efforts, there is a whole other set of considerations and challenges for midstream players looking to expand their systems to catch up with the production renaissance that API’s Gerard talks about so passionately.

Last year one of the behemoths of the midstream space, Tulsa-based Williams Cos., completed two expansions on its massive Transco interstate gas pipeline system traversing from the Gulf Coast to the Northeast. The additions included modifications to Transco’s mainline as part of what the company calls its Virginia Southside Expansion (250,000 dth/d of more capacity) and a portion of its Northeast Connector, adding 65,000 dth/d capacity. These were growth projects and the 21st and 22nd on the Transco system since 2003.

Within weeks of the start of 2015 the eastern half of the nation was hit with a massive cold front that covered from Mississippi to New York City and everything in between with sub-zero temperatures in many areas. As a result, and with the timely expansions in place, Williams reported an all-time record throughput for one day (Jan. 7) of 12.6 million dth, covering three of its contiguous market zones (4-6). The previous peak-day mark was recorded exactly a year earlier – 11.9 million dth.

Williams’ Frank Ferazzi, vice president and general manager of Transco Pipeline, said the company “fully expected to hit another record this year because natural gas demand for home heating and power generation continues to grow in new markets.” Ferazzi said the midstream powerhouse is staying ahead of this growth with plans to continually expand parts of Transco.

In a little bit over a decade, Williams has added 3.5 Bcf/d of capacity to the Transco system, about a 53% increase, and the company has already announced another $4.4 billion in growth projects on Transco during the next three years through 2017.

Marcellus Shale centered in Pennsylvania and spilling over into parts of Ohio and New York state is an area all the midstream players of various sizes want to get into. Only a few years ago, companies like Williams had no particular footprint there, and now after a couple billion dollars in investment and three or four acquisitions, their footprint is all over the space and growing. It used its master limited partnership (MLP), Williams Partners LP, to acquire existing companies, such as Blue Racer and Ohio Valley Midstream.

An MLP is the financial structure of choice for many of the growing midstream companies, according to Wall Street analysts who watch the sector. The structure is conceived of as a growth vehicle and this fits with the merger and acquisition (M&A) business that has become such an integral part of the midstream landscape. In midstream, companies grow organically with Greenfield and brownfield projects, and they almost always also buy other firms.

A case in point early in 2015 involved one of the biggest midstream stars, Kinder Morgan Inc. (KMI), and a $3 billion buy of privately held Hiland Partners, the Bakken Shale formation oil/gas infrastructure company owned by billionaire Oklahoma oilman Harold Hamm, whose Continental Resources, Inc., is a major Bakken producer. KMI executives describe the purchase as a “premier midstream platform” in the Bakken, including a significant amount of acreage dedicated under long-term gathering agreements. Hiland customers include Continental, Oasis Petroleum Inc., XTO Energy Inc., Whiting Petroleum Corp. and Hess Corp.

The assets have mostly fee-based contracts – acreage dedications with some of the Bakken’s largest and most successful producers, covering some of the “most attractive and economically viable” areas in the basin, KMI executives said.

“It gives us the kind of platform we need in the Bakken where we currently have no assets,” KMI CEO Richard Kinder told financial analysts on a quarterly earnings conference call in late January. “We think we can do in the Bakken the kind of expansion we did on our crude/condensate system in the Eagle Ford Shale in Texas, which has grown from its original 50,000 b/d throughput to have virtually all of its 300,000 b/d capacity contracted for.”

Standard & Poor’s Rating Services (S&P) Michael Grande, director of the utilities and infrastructure group, thinks M&A action has always been part of the midstream space, but now “it is accelerating for a couple reasons. Some of the small MLPs have assets sold to them from parent companies, and some of that slows down when commodity prices fall. The larger companies look for opportunities to scoop up other companies at a good price.”

Others cite the move by KMI late in 2014 to buy up its MLPs, an abandonment of the midstream’s popular MLP structure, by returning to the more typical corporate structure. However, one midstream observer interprets this as unique to Kinder because of its own particular cost of capital situation that has typically been a lot higher than some of its peers. In the MLP structure, KMI decided it was becoming more difficult for it to compete because of its cost of capital, the theory goes.

Also, according to the analysts’ take on the situation, KMI will lower its cost of capital by leaving its MLP, and Kinder is very much on record that it will continue to acquire companies as the Hiland deal clearly demonstrates. How much this influences others in the space will be watched carefully in the months ahead. Rich Kinder called his latest move “building a spider web” that he expects to expand in the coming years.

S&P predicted 2015 will be good for the midstream players, even with the prospect for oil prices far below recent peaks last year and natural gas prices the S&P analysts think will remain low for another 12-24 months. For the present, the midstream is well-positioned to prosper from its increasing export capacity and logistical advantages, concentrated in Mid-Continent and the Gulf Coast regions.

There is a wealth of potential infrastructure projects in the pipeline for the midstream players, particularly in crude oil takeaway projects in regions such as the Bakken and Permian, along with continued growth opportunities in natural gas liquids (NGL) processing facilities. Nationally, the president and the Republican-majority Congress are both looking at infrastructure (energy and other sectors) as a place where they can agree on a bipartisan approach.

Northeast pipeline takeaway additions will amount to 7 Bcf/d through 2015, climbing to a total of 24 Bcf/d by 2016, compared to the installed takeaway capacity of 17 Bcf/d at the end of 2014, S&P said in its projections for midstream energy and refining this year.

S&P and others are predicting capital expenditures to stay “elevated” in 2015, focusing on NGL and crude from the Eagle Ford, West Texas and Bakken plays, along with continuing robust natural gas production in the Marcellus and Utica formation in Pennsylvania, Ohio and West Virginia. “We expect investment-grade companies alone to spend about $20 billion in 2015,” said the S&P 2015 outlook for the midstream.

The ratings agency, however, did warn at the beginning of the year as prices continued to fall that ever-lower commodity prices eventually will cause companies to slow the pace of their cap-ex spending. Two projects that S&P labeled as being held back for a 2017 startup are the Williams Partners’ $2.1 billion Atlantic Sunrise natural gas pipeline project and the Spectra Energy Corp./NextEra Energy Inc. $3 billion Sabal Trail Pipeline.

To the north in Canada, S&P predicted in 2015 there would be another $20 billion spent on midstream infrastructure projects with Enbridge and TransCanada Pipelines Ltd. representing two-thirds of that total.

The robust shale growth in an increasing number of basins has fanned the fires for midstream infrastructure, S&P analysts continued to emphasize in early 2015. “All the infrastructure built in the last seven years is remarkable,” said S&P infrastructure director Grande. “Shale is directly apart of it, but there is also concern by investors that the government will do away with the tax benefits of the MLP structures.”

Grande is somewhat sanguine about this prospect, noting he doesn’t expect that to happen because MLPs make it much more efficient to get large infrastructure projects built.

While some of the economic winds are blowing in several directions, the political gusts in early 2015 tend to be positive toward the midstream space, from the White House and Congress seemingly closer to agreement on infrastructure to state and trade association pronouncements in the first weeks of the new year.

In Massachusetts, outgoing Gov. Deval Patrick called for 600 MMcf/d of added pipeline capacity by 2020 for his state and region, representing a potential 17% expansion of the existing gas infrastructure network. Patrick’s rationale was that growing gas-fired generation in the region demands major gas pipeline investments. Patrick’s office released a study that may force incoming Gov. Charlie Baker to do something about rising electric utility rates in his initial weeks and months in office.

Recently in New England, several governors have gotten behind the notion that an added tariff on utility bills should be used to help pay for new gas pipelines throughout the region to specifically serve power plants. At the same time, critics say gas-fired power has struggled at times in New England to meet peak-day demand in the coldest days of winter.

“It is important the governors look at all the alternatives before they make a significant gamble on gas,” a clean energy nonprofit leader, Peter Shattuck, told local Boston news media.

In the nation’s capital, the pipeline trade group, the Interstate Natural Gas Association of America (INGAA), applauded passage of a bill in the U.S. House of Representatives to streamline the federal permitting process.

“Pipelines are one of the keys to realizing the benefits of America’s natural gas revolution because they are the indispensable link from supply sources to the ultimate gas consumer,” said Don Santa, INGAA CEO, following the congressional action in late January.

INGAA and some of its individual members have been advocating for years that the federal pipeline process be deconstructed, revised and streamlined to lower the cost of new gas infrastructure in a nation and continent in which record production is taking place.

In the first month of 2015, the analysts and energy consultants were predicting a collective cutback in cap-ex – particularly among exploration/production companies of all sizes – approaching $170 billion. How much of that will spill over to the midstream sector seems unclear. Wood Mackenzie predicted that “capital discipline … will be less about choice and more about survival,” and effects could linger into 2016. “A big unknown is how much and for how long costs will fall.”

Within months of the big oil price fall, S&P’s outlook said the impact of lower oil/gas prices would vary among sectors with E&P companies facing the most immediate impacts of lower profitability and cash flows. Nevertheless, S&P predicted E&Ps can reduce their spending without a sharp drop in production. Energy officials in North Dakota and other states were singing the same tune, and at the start of the new year that projection was holding up in the Bakken, at least.

“Though low commodity prices have somewhat hurt midstream companies, they continue to build infrastructure to absorb a backlog of expanded North American production,” the S&P analysis concludes. “Refiners also face different conditions in North America than they do globally. Abundant discounted crude oil in the United States provides a margin advantage to refiners with access, while downstream operators in Europe and Asia face more expensive crude and low capacity utilization.”

In January, S&P Managing Director Tom Watters and an analyst team outlined the E&P sector during a teleconference, noting that in the three preceding months, the rating agency had issued 73 “negative ratings actions” for about 120 covered E&Ps.

Nevertheless, the team concluded that E&Ps this year should be able to maintain operations even under low, sustained oil prices. Liquidity looked good for 2015 in which prices have been hedged, refinancing was put in place before the big price drop, and cap-ex has been slashed.

“Despite the lower prices and the potential for high-yield issuers facing borrowing-base reductions at their revolving credit redeterminations in April, we found liquidity in general, to be adequate for the next 12 months,” Watters said. “If prices don’t rebound in 2016, however, some producers may face material liquidity pressures.”

Even absent the fallout from the price nosedive, the midstream has been set up for some potential game-changers due to increased competitiveness within the sector and challenges to some of the marquee capital projects due to insufficient market interest.

Heightened competition and more unpredictable commodity prices are a formula for some challenging times for a sector that is getting used to a dynamic environment. The midstream has the advantage of being a key to the nation’s recovering economy, increasing end-user demand, and enough liquidity to keep the sector as a source of relative stability in the otherwise choppy waters of the broader oil/gas industry.

As always, the challenge will be to transform these potential advantages into tangible, positive paybacks.

Richard Nemec is a Los Angeles-based West Coast correspondent for P&GJ. He can be reached at: rnemec@ca.rr.com.

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BENTEK Report: Nowhere to Hide Except the Permian
How Basin is Surviving Low-Price Environment in Oil, Natural Gas and NGLs

The Permian Basin in West Texas is the most active hydrocarbon-producing area in North America, and even in a low-price environment it remains among the most favorable areas on the continent to drill of oil, natural gas liquids (NGL) and natural gas, according to the latest report issued by BENTEK Energy, an analytics and forecasting unit of Platts.

In the last three years, oil production in the Permian, which straddles Texas and New Mexico, has jumped 50%, while natural gas production has climbed 30% and NGL output has increased 61%, the 20-page report states. Horizontal drilling, new exploration and production techniques, and a multitude of unconventional producing formations have led to a major Permian renaissance.

The Permian also is showing greater resilience during the recent drop in drilling in response to falling crude oil, NGL and natural gas prices. Permian rig count declines have been mainly vertical rigs, rather than horizontal rigs.

“Unlike other U.S. producing basins, the Permian Basin is less exposed to adverse market conditions because of its more favorable production economics as well as its closeness to major markets,” said Ross Weyno, senior energy analyst at BENTEK Energy.

“Nowhere to Hide Except the Permian” overviews the characteristics that make the Permian Basin such an attractive location for producers even in a low-price environment. The report includes detailed information on the following:

• Permian crude oil market
• NGL infrastructure and natural gas market dynamics in the Permian and surrounding regions
• A forecast of Permian crude oil, NGL and natural gas production over the next five years
• A review of major challenges and risks ahead for Permian producers

“BENTEK currently expects Permian oil production to increase 40% over the next five years,” Weyno said. “However, the Permian is not immune to adverse market conditions. If crude prices fall to less than $40 per barrel for a sustained period, Permian production would be at risk.”

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