Chinese LNG demand: is it too big to fail?
China’s recent economic woes have rightly caused agitation and concern around the world, as Asia’s great growth engine may be beginning to exhibit some signs of sputtering.
Nowhere has this concern been more acute than in the commodities sphere, where slowing growth over the last several years has already posed problems for major exporters of iron ore, copper and other commodities. Indeed, as the world’s largest importer of oil (some 6.1 million barrels per day [bbl/d] in 2014, as reported by the U.S. Energy Information Administration [EIA]), a perceived potential slowdown in demand precipitated the very beginnings on the current oil price crash in mid- to late-2014.
According to the Stratas Global LNG Service, China’s 5.95 billion cubic feet per day of regasification capacity is the fourth largest in the world, and greater than that of all of Latin America—and third, if one excludes the largely inactive import capacity of the U.S.

Source: Stratas Advisors
Until recently, natural gas has been perceived as safe from some of these concerns. While China’s economy has stepped back from its roaring 10% annual growth to a more moderate-yet-robust 7%, the growth rate of total energy demand appears likely to decline. Given the government’s avowed efforts to reduce the role of coal in the domestic energy mix, it seems that natural gas demand would continue its growth trajectory as it displaced coal volumes.
However, recent fears regarding the true state of Chinese growth and the future of the economy have raised the specter of a lag in demand for natural gas and LNG. Coming at a moment where gas and LNG prices have largely collapsed internationally, concurrent with the fall in the price of oil, this could pose a major threat for developers eagerly chasing the theoretically “limitless” Chinese demand for natural gas.
Of greater concern for LNG proponents eager to engage with this market is the country’s actual level of imports. In 2014, China imported some 2.5 billion cubic feet per day (Bcf/d) of LNG throughout its numerous regasification facilities. While this is impressive in and of its own right, what truly strands out is the scale of these imports juxtaposed with the country’s time line. China’s first imports began in 2006, and since then the volume of these imports has exhibited a 44% combined annual growth rate (CAGR).
The closest competitor over this timeline is India, which has only grown total volumes to some 1.9 bcf/d and shown a CAGR in that time of 11%. No other current importer has demonstrated such a growth trajectory in terms of LNG, and it was this surging demand that many prospective LNG exporters have eyed hungrily for their projects.
So what does this mean for current and hopeful LNG exporters around the world?
Some of the effect of slowing Chinese demand (should it occur) will be moderated for exporters by long-term contracts. However, should Chinese buyers like China National Offshore Oil Corp. and China National Petroleum Corp. begin examining diversions, reroutings or even reloading/reexports, this would push even more liquid supply onto an already glutted market. The result could risk a continuation of the current low-price environment, thereby threatening a number of traditional, integrated (and often costly) export schemes.
Projects’ progress could mean world awash in LNG
An aggressive march toward a final investment decision (FID) for several LNG projects worldwide could result in an additional 100 million tons per annum (mtpa) that would be approved in the next six to 18 months, leading to an oversupply in Asian markets to 2025.
“With the LNG market facing a wall of new supply just as China’s gas demand growth has faltered, it is surprising how few new projects chasing an FID have been postponed,” Noel Tomnay, Wood Mackenzie’s vice president, global gas & LNG research, said following the release of a new global gas analysis.
Global LNG supply is around 250 mtpa, with projects under construction ultimately contributing another 140 mtpa of capacity. Wood Mac has projected difficulties in absorption of this extra supply for some time, but said that the recent demand downturn aggravates its bearish prognosis.
China’s 4% year-over-year decline in LNG imports, as well as cutbacks in other parts of Asia, underpins the gloomy revision to Wood Mac’s outlook. Longer term incremental growth has been negatively affected, Tomnay said, and opportunities to push more LNG onto the Asian market don’t really appear until after 2022.
BG Group’s postponement of its Lake Charles LNG project in Louisiana is unique in its reaction to the anticipated oversupply, Tomnay said. But BG is the exception.
“Major project operators including Shell, Petronas, ENI, Anadarko, BP, ExxonMobil and Woodside maintain that their projects will take FID before the end of 2016,” he said.
Reasons for not delaying projects include the possibility of invalidating contracts, jeopardizing stakeholder support or losing momentum on a project that could lead to its cancellation.
Still, the inevitability of an impending surplus has its consequences.
“The global LNG market does not need all this LNG at the pace proposed,” Tomnay said. “As companies confront this reality, a raft of project postponements will follow.”
Execs focus on cost cuts, conserving precious capital
Oil and gas producers have shifted their focus, not surprisingly, from growth to efficiency and cost reductions, according to a recent survey of executives conducted by Ernst & Young (EY).
“We’ve seen the market break up a bit at the two ends, from those who can handle this downturn and those who cannot, but about 15% of respondents are still focused on growth,” said Russell Curtin, partner and head of energy for EY, speaking at the recent Good Oil Conference in Freemantle, Australia.
EY surveyed 1,000 company executives around the world, including about 100 in oil and gas, to gauge their concerns and find out more about their corporate strategies.
When given a range of answers, most respondents cited current geopolitical concerns as their greatest risk. The survey was conducted in June.
Given that these geopolitical risks affect oil prices, the executives were less enthusiastic about the outlook for corporate earnings. To cope, they cited a sharp drop in planned hiring and a renewed focus on operating efficiencies and service cost reductions.
“They are focused on conserving capital, reducing dividends and postponing FIDs,” said EY partner Darryn Hall.
What is the No. 1 topic of conversation in oil and gas board rooms today? Some 44% of respondents said reducing costs and improving margins; 32% cited commodity prices.
When EY asked them to look longer term, however, 21% of the oil and gas respondents said they think the digital future will have the biggest effect on their companies.
“The anytime, anywhere access to such disruptive technology across the entire value chain is huge. The adoption of digital technology will affect health and safety efforts, reservoir understanding, collaboration between oil companies and their service companies and logistics,” Curtin said.
Canadian study reaffirms safety of pipeline systems
Transporting crude oil by rail in Canada is 4.5 times more likely to result in a spill than moving it by pipeline, a non-partisan public policy think tank concluded in a new study.
Calgary-based Fraser Institute reported in its study, “Safety in the Transportation of Oil and Gas: Pipelines or Rail?” that both methods are fundamentally safe; however, rail introduces more risk than pipelines and trucking poses more risk than rail.
If rail appears denigrated in the comparison, it may be a result of the pipeline industry’s remarkable safety record.
“A telling statistic comes from Natural Resources Canada,” said lead author Kenneth P. Green in a statement, “which notes that between 2011 and 2014, 99.999% of crude oil and petroleum products sent by federally regulated pipelines arrived at their destination safely.”
The study echoes the results of pipeline safety research in the U.S., including conclusions by the U.S. State Department in its evaluation of the Keystone XL Pipeline.
Citing the State Department report, Fraser Institute noted that it “concluded that moving the oil by non-pipeline means would result in more total releases and barrels released per year, while also emitting more CO2 emissions during transport.”
The State Department report acknowledged that pipeline incidents lead to a higher volume of spills than rail, but said that the difference was at least partly offset by the greater ability to recover oil following a pipeline occurrence.
Fraser’s data establishes that less than a cubic meter of oil is spilled in 73% of pipeline incidents, with 16% of incidents resulting in no spill at all.
A study performed for the Manhattan Institute showed that transport of oil by roadway resulted in 19.95 incidents per billion ton miles per year. Rail’s incident rate was 2.08 per billion ton miles, while pipelines averaged only 0.58 incidents per billion ton miles.
“In both Canada and the United States, rising oil and natural gas production necessitates the expansion of our transportation capacity,” Green said. “The decision of which mode of transport should be used is a simple one. It should be the safer one; it should be pipelines.”
Decline in crude-by-rail shipments continues
The volume of North American crude oil shipped by train continues to fall due to the narrowing spread between West Texas Intermediate (WTI), Bakken and North Sea Brent.
The Association of American Railroads (AAR) reported U.S. petroleum and petroleum product shipments were down 4.7%for the year through the end of August, compared to the first eight months of 2014. For the last week of August, shipments were down 15.3%, year over year. However, Canadian crude by rail shipments rose for both periods compared to 2014, according to AAR. This was because of demand created for bargain-priced Canadian oil.
“We note from weekly crude oil import data that heavy crude from Canada has seen decent demand in the U.S. in recent weeks,” Global Hunter Securities said in an analysis of crude-related rail traffic. “Much of the lift has been catalyzed by exceptionally low prices for Canada crude. Indeed, some quotes were putting Western Canadian Select (WCS) at about $20 per bbl just two weeks ago.”
The WTI-Brent price spread has been in the range of $5 per bbl recently, compared to as much as $20 per bbl two years ago. The spread in 2015 peaked at $8 per bbl in April. That narrowed differential makes more expensive rail transport uncompetitive with pipelines—if pipeline service is available. Pipeline service is not always in place, particularly in the isolated Williston Basin, and rail transport remains an option for producers in such areas.
That narrowed price spread has led some Atlantic Coast refiners running primarily lighter crudes to move back to imported oils in place of Bakken oil. Irving Oil Ltd. recently confirmed that its 320,000 bbl/d refinery at St. John, New Brunswick—one of the largest refineries on North America’s East Coast—is no longer processing Bakken crude, all of which was shipped by rail.

Moody’s lowers outlook for global midstream
Slower projected growth in global midstream’s EBITDA has prompted Moody’s Investors Service to downgrade its outlook for the sector to “stable” from “positive,” where it had been since September 2010.
The New York City-based bond rating service attributes midstream’s less-than-sunny outlook for the next 12 to 18 months to deep cuts in capital spending and slowing production in the E&P sector. These reductions have flowed down to midstream, forcing the sector to trim its own spending on growth projects, which had been driving its strong EBITDA results.
Moody’s bleak forecast for oil and gas prices adds to its concerns over already squeezed processing margins.
“While G&P [gathering and processing] volumes have remained intact across many producing basins, weak commodity prices pose a substantial risk to G&P profitability through at least late 2016, straining distribution coverage and raising leverage,” Moody’s analysts wrote in the report. “Throughput volume declines in NGLs and crude oil, and in mature natural gas basins, cannot be ruled out, and would lead to further pressure on G&P-originated EBITDA.”
The report acknowledges the groundswell of M&A activity in the sector in the face of diminished organic growth opportunities, but the analysts are skeptical that this trend will move the midstream needle. “These synergies and savings would not come close to the scale of EBITDA growth that the construction and service of new assets have provided,” Moody’s said.
The issue of financing comes into play as well, with falling equity prices raising the cost of capital. Midstream’s dominant MLP model comes under scrutiny because of the need to continually provide higher distributions. Moving away from MLPs, Moody’s argues, would reduce pressure to increase distributions through continuing EBITDA growth.
A further change—to a “negative” outlook—is possible but unlikely, the analysts said, although the sector could be saddled with a prolonged “stable” label. Infrastructure and logistics are not entirely immune from commodity price risk and the prognosis for a rapid recovery in crude oil and natural gas prices is poor. A rebound in midstream, the analysts said, would require a recovery in upstream capital spending, and a positive impact from that would take several quarters before it had an effect.
Credit offers alternative to the equity markets
As the energy industry faces continuing low commodity prices combined with tightening banking and equity markets, management is looking to other strategies to sustain continued growth. Jay Rose, managing director of newly launched Euler Hermes Energy, told Midstream Business that credit insurance can protect that growth.
Credit “frees up liquidity for shippers, marketing companies, commodity traders, companies servicing producers, in a credit-constrained business,” he said. “The more credit that you can deal openly increases opportunity to reach a broader open market, reducing barriers and creating opportunity to get more financing liquidity to facilitate growth.”
Though companies are getting creative, particularly while prices remain low, Rose said the need for more credit protection results not only from the stressed prices, but from the shift toward increasing globalization.
“The energy industry is becoming a lot more global than it ever has been,” he said.
“The forward-looking future of this industry is becoming global. LNG’s hitting the water, more foreign investment is coming into the U.S., you have deregulation of Mexico and the increased possibility of crude being exported legally. New counterparties and destinations for products are emerging, which is changing the dynamic of the industry as a whole.”
In the meantime, concerns about low prices are at the forefront of the list of business concerns. Those concerns are bringing the industry’s attention to credit insurance and risk management offerings like those from Euler Hermes Energy, Rose said.
“It’s an insurance policy on the credit risk protecting against counterparty defaults; we step in and pay the client in similar fashion to a letter of credit without tying up capital assets.”
Open credit is a valuable financial option for midstream operators, Rose said, because “midstream companies are very credit-constrained, and our programs open up the credit universe to more opportunity with private and non-investment grade shippers on pipeline.”
Usual credit requirements in the midstream “create barriers of trade and financing that prohibit growth,” he said. “By being able to facilitate liquidity in the form of open credit, it lifts barriers. The more shippers pipelines have the higher their subscription, which will lead to more demand, safer investment and, ultimately, more assets and equity growth.”
Companies not utilizing these options to mitigate risk could be missing key opportunities to grow their business, Rose said.
“Credit provides opportunity to businesses, and more tools and more solutions that businesses can use to help grow their business,” he said.
“In today’s environment, you have volatile prices, collapsing balance sheets, nervous shareholders, higher regulation with banks, yet executives are still tasked to grow their business.”
Taking steps to protect yourself from default on the part of your customers “is a way to help businesses grow while also mitigating significant amounts of risk currently on the balance sheets,” he added.
Cyber security threat grows, hackers become more innovative
At 1:48 p.m. Aug. 1, 2012, Walter Energy Inc. submitted a press release to a newswire service announcing its quarterly results—just more than two hours before the news was made public.
At 2:14 p.m., less than 30 minutes after the wire service uploaded the press release into its system, someone bought Walter Energy contract for differences (CFDs) futures referencing 36,000 shares of stock, valued at about $1.2 million, and then made another trade for a larger amount through a different account. That afternoon someone else carried out a similar transaction, the U.S. Securities and Exchange Commission said in recently unsealed court documents. It all happened before the press release became public.
The next day the two are accused of closing their positions in the Walter Energy CFDs and pocketing a combined $137,000 in profit as part of what Andrew Ceresney, director of the SEC’s Enforcement Division, called “one of the most intricate and sophisticated trading rings that we have ever seen, spanning the globe and involving dozens of individuals and entities.”
Walter Energy was only one of the targeted companies—others included Caterpillar Inc. and Panera Bread Co.—listed in a federal court document detailing the SEC’s fraud charges against 32 people. They are accused of using advanced techniques to hack into two or more newswire services between 2010 and 2014 to steal hundreds of corporate earnings announcements before the newswires released the information publicly. The information was then sent to traders in Russia, Ukraine, Malta, Cyprus, France and the U.S.
The scheme, allegedly led by two Ukrainians, generated more than $100 million in illegal profits, the SEC said. The hack shows that the cyber security threats are becoming more elaborate and should remain on the radar for oil and gas companies, which have been frequent targets of cyber attacks in the past.
While the latest high-profile scheme was elaborate, the oil and gas industry is typically still seeing the same previously deployed attacks, experts said.
“In many cases, attackers are using the same methods to hack into companies’ systems given that attackers frequently will look for the path of least resistance such as phishing emails,” said Edwin Cisneros, director of PwC’s cyber security practice.
But use of malware via phishing email; compromised credentials; and water holes, essentially “web browsing drive-by attacks,” are among the fastest-growing sources of cyber attacks against the oil and gas sector, he added.
“If common methods don’t prove to be successful, the game is then changed to increase the sophistication of the attack vectors,” he said.
The oil and gas industry is also still seeing attacks through email, infected USB sticks being plugged in machines and employees being talked out of information over the phone, Red Tiger Security Founder Jonathan Pollet told Hart Energy.
“We are also seeing that sometimes the attackers will target the equipment manufacturers,” Pollet said. He explained this involved the attacker getting equipment that a company would buy, finding the equipment’s vulnerability and putting in code that has been infected with malware. “So it’s like a supply chain issue.”
The motives vary. It could be an attempt to swipe new technology or other intellectual property, damage infrastructure, defame or wreak havoc elsewhere because they simply don’t like the company and its actions, or in the latest high-profile case—money.
“Former employees are becoming more of a threat especially with the ease of personal devices coupled with the lack of monitoring controls, processes and other technologies that can be used to detect exfiltration of data or system configuration changes,” Cisneros added.
Prolonged low prices could halt ethane investments
If crude oil prices don’t recover within five years, the second wave of new ethane crackers in North America will likely be postponed to 2025, tightening ethylene supply and boosting the profitability of naphtha-based producers in Europe and Asia, a recent IHS Chemical report concluded.
An extended recovery period for crude oil prices, exceeding five years, would have dramatic implications for the global petrochemical industry and could mean a “Back to the Future” experience for some companies and regions, creating a more competitive environment for naphtha producers, according to the 2,000-word report, titled “Crude Oil Turmoil and the Global Impact on Petrochemicals—Special Report.”
Specifically, the report assesses the potential market and economic implications of three possible, short-, medium- and long-term recovery trajectories for crude oil prices to help petrochemical producers address their investment planning in the midst of significant market volatility, and a higher degree of uncertainty regarding the role of OPEC in managing the global supply of crude oil.
“We’re not restating IHS Energy’s view of the world. What we’re saying is be prepared if the recovery does occur in a different path,” Don Bari, vice president, technology and analytics for IHS Chemical and author of the report, told Hart Energy.
Oil-price volatility is creating a nightmare for petrochemical companies planning investments, according to Bari.
In the case of a long-term oil-price recovery (exceeding five years), Bari said he and his team expect moderate economic growth to continue for several years, along with slower oil demand growth. At the same time, technology would continue to reduce oil production costs and increasing supply, even at lower oil prices.
Long-term, continued global oversupply of crude oil could keep prices from recovering to trend for more than 10 years, according to IHS.
For petrochemicals, the first major impact of a long-term oil price recovery, Bari explained, would be on NGL production and ethylene production in the U.S., where prolonged lower oil prices would slow NGL production and ethane-cracker capacity expansions, potentially creating a tight market.
“It’s that second wave—the 2018 to 2022 time frame—we see that if oil stays low that’s where you’d start to see those plants [U.S. ethane crackers] put on hold and we could see more investment of naphtha crackers in China and expansions in Europe and Asia,” Bari said.
“It would essentially put a pause in supply—so supply and demand would be very tight,” he said.
Ethylene is the basic building block for many downstream chemicals, plastics and synthetic fibers, and as such, is the largest volume, and perhaps most market-indicative petrochemical. A tighter ethylene market would not only push operating rates higher, but would also cause prices to increase and introduce more market volatility.
According to IHS’ analysis, in the long-term recovery case, ethylene demand is forecast to grow at an annual rate of 4.5%and nearly 4% during 2015 to 2020 and 2020 to 2025, respectively, while the name-plate capacity is forecast to grow at an annual rate of more than 3% and less than 1% respectively, during the corresponding time periods.
Texas oil output surges, but change could be near
Texas appears to be on track to break the state’s annual production record set in 1972 as recently release July production numbers show the state surpassed 111 million bbl.
The Texas Alliance of Energy Producers said July’s oil output was 15% more than what was produced a year earlier. That would be great news for oil companies if the price per barrel had not plummeted. The alliance said that the value of crude produced in Texas fell by 44.3% to about $5.3 billion, with crude oil prices averaging $47.93/bbl for the month.
The price for a barrel of WTI crude has dropped from highs of more than $107/bbl in mid-June 2014 to about $40/bbl, the result of too much oil and not enough demand.
Efficiency gains are evident, especially considering production growth occurred as the number of active drilling rigs was more than chopped in half. Data from Baker Hughes Inc. showed the number of active drilling rigs in the state averaged 369 in July. The active rig count was 892 in July 2014.
But Texas’ producers defying low wellhead prices could be coming to a temporary halt.
Karr Ingham, the economist who created the Texas Petro Index, said that although oil production is growing, the margin of growth is getting smaller—a trend he thinks will continue.
“I still expect crude oil production statewide to peak sometime in the second half of 2015, perhaps even in the third quarter,” said Ingram, “but the question is will monthly crude oil production go negative compared to year-ago levels by year-end? Not by my calculations it won’t, and it looks like we are still on track in 2015 to eclipse the all-time Texas production level achieved in 1972.”
That could mean more troubling news when it comes to oil prices, given the market is still saturated worldwide.
“People are looking for reasons to change their thinking on oil prices, but market fundamentals simply do not point to higher crude prices,” Ingham said. “There might be some short-term ups and downs, but the substantial pressure on price simply has to be regarded as downward, not upward.”
Data science moves to midstream
Data collection and analytics, which have typically been utilized by upstream operators, are beginning to enter the midstream. Louis Fabbi, senior data scientist with SAS, emphasized the importance of incorporating analytics into midstream operations at the recent SAS Energy Analytics Forum in Houston.
According to Fabbi, the energy industry is in a period of extreme uncertainty related to upstream supply, the economics or break-even prices of different shales, and the cost of midstream development.
Analytics can help solve planning problems created by the uncertainty, Fabbi said.
“That’s what we’re addressing in particular through the oilfield production forecasting, simulation, data mining and creating the supply envelope with statistical certainty associated with it,” he told Midstream Business. “Once you’ve done that, you can say you have statistical confidence.”
“So that’s what we’re bringing to the table now and we’re actually implementing right now with a midstream operator.”
Traditionally there has been a gap between the strategic planning of upper management and the actual engineering or building work, Fabbi said. Data science fills that gap by modeling assets and business statistically, using mathematical representations to give insight into strategic and capital planning.
The prospect of launching a data collection or analytics program can be daunting to company leadership, but doesn’t need to be. According to Fabbi, smaller companies can benefit from easily applied, strategic data analysis, and relatively simple implementation can return big results.
Analytics for small companies are “just as important [as for large companies], just on a smaller scale,” he said. “It doesn’t have to be a $10 million implementation; it can be something more affordable for a smaller operator.”
Those smaller operators can benefit from doing their own analyses of third-party data, he said. The International Energy Agency and EIA can be useful sources for data companies, as well as vendors like IHS, for detailed well data, he said.
“Leverage that data,” Fabbi said. “It’s there. Use it, and you could build a whole lot more confidence into what you’re trying to understand as far as risk of your capital.”
Company leadership worried about a potential investment while prices remain low should understand “that doing analytics is achievable for them,” he said. “They don't need a team of PhDs.”
A small, high-functioning analytics team can provide some quick wins with some fairly simple analysis, Fabbi said. One such quick win relates to actually knowing how much pipeline capacity isn’t being utilized.
“Understand that, and understand why you’re not using that capacity,” he said.
‘We have been here before,’ CEO reminds forum
Looking at the energy industry’s current challenges, it’s important to remember that “we have been here before,” Greg Armstrong, chairman and CEO of Plains All American, emphasized in his address to the Houston Producers’ Forum. And as in past cycles, supply, demand and prices could change quickly, he told the audience.
“When I first agreed to speak here in October 2014, little did we know what was going to happen,” Armstrong said, pointing out what has happened to crude oil prices in 11 months.
To illustrate his point, Armstrong presented slides from presentations he gave at past forum luncheons in 1999, 2002, 2007 and 2009. “There’s a lot of relevance to the thoughts I articulated years ago,” he said, emphasizing the industry went through difficult times in the past before booms. In a humorous side note, Armstrong noted technology proved one problem in assembling his new presentation, pointing out software used 16 years ago is not fully compatible with today’s software—a reminder of how long ago his first presentations were.
“We’ve been through a lot of cycles. Crude oil prices have been as low as $12 per bbl and as high as $140 per bbl” since Plains and its predecessor companies started in 1981, he said. Market trends have varied widely, “but throughout that time period we have been able to generate a very successful growth profile.”
Reflecting on charts showing 16 years of oil price trends, Armstrong said there has been a progression up and to the right, adding that “there has been a tremendous amount of volatility” as prices swung up and down, reflecting supply and demand trends in past times.
Today’s crude oversupply situation could change quickly, Armstrong stated. He said in 1986, the world demand for oil was 59 million bbl/d (MMbbl/d) and OPEC had about 15 MMbbl/d of unused capacity, or about 25% of demand at the time. Now, world demand is around 94 MMbbl/d but OPEC has only about 4 MMbbl/d or excess capacity, or scarcely more than 4% of demand.
“So it really doesn’t take much in a 94 MMbbl/d world to come out of balance with a combination of decreasing production or increasing demand,” he said, adding that Plains monitors crude prices and supply closely due to the nature of its business.
“Our revenue base is extensive and crude-centric,” Armstrong said, pointing out Plains moves some 4.3 MMbbl/d of crude, including purchases of more than 1 MMbbl/d from more than 2,200 different producers. As one of the midstream’s biggest players, Plains’ assets include more than 50 different crude-oil grades. It has 125 MMbbl of liquids storage and some 18,900 miles of pipelines and “a large rolling stock of trucks, trailers, rail cars—about anything it takes to get crude oil from the wellhead to the refinery.” The firm also can process 8.5 Bcf/d of natural gas and has 97 Bcf of gas storage capacity.
That big asset profile allows Plains to enjoy a close-up view of trends in the industry, he said. “We’ve never lost our roots that allow us to understand what’s going on in the field, that allow us to understand where to build a pipeline, or to purchase a pipeline. We have to have an appreciation for the reserves.
“We have a staff of engineers and analysts who do a tremendous amount of work on the supply and demand sides,” Armstrong added. “We get a lot of information that gives us real-time data on the market” that can be used to build an accurate business model. “On balance, that gives us the power to control our own destiny, especially in an environment where there is less than full utilization of our assets.”
Armstrong reminded the audience that some recent economic projections by Plains were criticized at the time by the investment community as overly negative, compared to what its peers were projecting. “But they are working from a much smaller footprint. They may be giving the best call they can from the information they see,” he said, pointing out data that Plains used, and its projections, have since proved to be correct.
Based on that large volume of data, Armstrong said Plains is “very bullish in the long term and intermediate term about the crude oil business.” But the short term “could be very challenging,” he cautioned.
“From a midstream standpoint, we think that there will be continued expansion in some areas and [asset] rationalization in others. In some areas today we actually have excess capacity but within the regions there is still a lot of internal development,” said. He cited as an example the Permian Basin may be, overall, well served now while the developing Delaware Basin in the southwest corner of the Permian “is very, very active right now. There’s not enough takeaway capacity, but there’s plenty of capacity once you get it to Midland or one of the other centers.”