Week Ending April 29, 2016

Senate Energy Committee Begins to Examine Oil and Gas Development Issues in the Current Low-Price Environment

This Article Appears as Published in Foster Report No 3097
Senate Energy Committee Begins to Examine Oil and Gas Development Issues in the Current Low-Price Environment

A Senate Energy and Natural Resources Committee’s oversight hearing on April 26 began to examine challenges – and any opportunities to meet them — facing U.S. oil and gas development in the current low-price environment, and corresponding energy policies.  Experts testifying before the Committee conceded the difficult market conditions over the last two years characterized by abundant supplies, record low prices, shut-in production, and for natural gas a changing liquefied natural gas (LNG) market right at the time that new LNG export facilities are coming online.

Jason Bordoff, professor and founding director of the Center for Global Energy Policy at Columbia University; Oren Cass, senior fellow at the Manhattan Institute; Suzanne Minter, manager, oil and gas consulting services at Platts Analytics; and Leslie Palti-Guzman, director at The Rapidan Group, participated in the Committee’s opening discussion (which had been delayed and rescheduled the week before).

Committee Chairman Lisa Murkowski (R-Alaska) suggested that the challenges and opportunities in oil and gas development under different price environments “is of national significance” for U.S. security, the economy, and the environment.  Murkowski believes that oil prices will recover, noting that the Congressional Budget Office assumes price levels will roughly double in the future to around $80/b or more from the today’s approximately $40/b.  Oil prices dipped to $9/b when Murkowski served as a state legislator in Alaska.  “We had to make really tough decisions,” she said.  “And yet, our executive and legislative branches, controlled by a Democrat and Republicans respectively, worked diligently to ensure that our public policy remained attractive to resource investment.”

The same is true now, she stressed.  “When you look at our energy mix, that means we need to provide new access, we need to establish reasonable systems for leasing and development, and we need to reform what is often an overly cumbersome permitting process.  Right now, we do not have that kind of system at the federal level, but with policy improvements we can get there.”

Chairman’s Plan.  To start that kind of process, the Chairman announced the launch of “a new series” of white papers.  “All of my major initiatives have been based on rigorous analysis and brick-by-brick argumentation,” Murkowski said.   Many of the ideas contained in S. 2012, the Energy Policy Modernization Act, which passed the Senate 85-12 last week (FR No. 3096, pp9-11), were actually contained in Energy 20/20, a white paper the Chairman released in 2013.   Before “unveiling Alaska legislation” in the coming weeks, Murkowski is starting with the release of a series of white papers on Alaska: First in Energy, “the building blocks of policy” that will “construct the case that Alaska should be first in energy.”

Oren Cass.  Cass’ testimony focused on federal energy policy, as he urged the Committee to design energy development policy independent of prevailing market prices.  Primary impacts of policy decisions are not felt for years or even decades, when prices could be different.  Furthermore, when anticipating resources that might come online in a decade or more, the market price today is simply not relevant.

Policymakers of the early 2000s had no conception that oil prices might rise more than five-fold in a decade, just as policymakers in the early 2010s had no conception prices would plunge back down.  Basically, “oil prices keep surprising economists, policymakers, consumers and financial market participants.”  Even financial market futures can offer no meaningful guidance.

Therefore, Cass posits that the appropriate federal role is to establish a clear, stable framework within which the private sector can make long-term investments wherever it chooses.  The government must make clear that it is “open for business,” supportive of efforts to expand production and committed to “not whiplashing policy back and forth” in response to changing market conditions.  And the same policies that make sense in a low-price environment make sense in a high-price environment.

The U.S. has the resources under federal lands and waters to repeat the experience of the energy revolution seen from private lands, but achieving this will only occur if the federal government replicates the stable and supportive framework that private industry encountered on private and state-controlled lands.  The states where the federal government controls less than 10% of land saw proved reserves increase 104% between 2008 and 2013, while states where the federal government controls more than 50% of land recorded a reserves decline of 7%.

Notably, the off-limits federal resources “may be far richer” than those driving the shale boom, Cass suggested.  Off-limits areas of the Outer Continental Shelf (OCS) are estimated to contain more than 40 billion barrels of technically recoverable resources.  The Arctic National Wildlife Refuge (ANWR) contains another 10 billion.  By contrast, the entire Bakken Formation in North Dakota is estimated to contain less than 10 billion barrels and that estimate was less than 1 billion until the formation was well into development, Cass shared.

The objective should not be simply to open as much land as quickly as possible either.  The industry lacks capacity to invest everywhere at once and government lacks capacity to provide the requisite oversight.  Rather, reforms should focus on the establishment of a clear and legally-binding (i.e., legislated) roadmap for the opening of new on- and offshore areas over the coming five- and ten-year periods, including ANWR and off-limits OCS areas.

The government should regularly update inventories of federal lands and waters and forecast development timelines and peak output levels that can form a baseline against which to measure achieved production increases.  States should be granted permitting authority over lands within their borders and clear procedures and timelines should be established for permitting processes that remain at the federal level.  In addition, downstream timelines must be shortened.

Not only does it take years or decades for new resources to come online, Cass said, but it can take just as long to construct the infrastructure needed to transport and use the resulting fuel.

Suzanne Minter.  Minter, in the business of providing analytics and forecasting in the energy markets, provided Committee members an overview of the drastic oil price movements over the last two years, beginning with a peak of $107.73/b in June 2014 (the West Texas Intermediate (WTI) price), dropping 76% to reach a low of $26.05/b in February 2016.  The most precipitous drop in oil pricing occurred between June 2014 to March 2015.   “In a mere 250 days,” she said, “prices fell 55% from a multiyear average of $96.93.”

As startling as the collapse of crude prices has been, according to Minter, even more telling of the global oversupply of energy is the accompanying collapse of refined product prices recognized by refiners.  With the swelling refined product inventories and prices for products falling significantly, the global markets did not appear willing or able to absorb what was being created.  Going into 2016, this trend in collapsing refined product margin appears to be accelerating.

Meanwhile, oil producers have had to cut capital expenditure (CAPEX) plans dramatically during this time – by an average of 35% in 2015 — reducing their drilling plans and slashing the rig fleet.  After a 14-month persistently low-priced environment, producers entered 2016 with further estimated CAPEX cuts of 40%.  Yet despite the annihilation of the rig count, U.S. crude production has yet to show dramatic declines.

U.S. production peaked in April of 2015 at 9.7 MMB/d and currently is estimated to be at 9.2 MMb/d – a decline of 500,000 b/d or 5%.  Minter reasons that this phenomenon was made possible by the fact that, as they cut CAPEX, producers were able to capture huge cost savings from the services sector and recognized impressive gains in technology.

Minter referred to Platts Analytics’ estimates that as of Dec. 2015 there were in excess of 6,500 wells drilled but uncompleted (DUC) in inventory.  Since then, the DUC inventory has increased dramatically, she said, and will continue to do so over the next six months.  Approximately 2,500 of the DUC wells are in Texas — presumably oil wells in the Eagle Ford and Permian basins.  With those wells, Texas alone could introduce 1.25 MMb/d of oil into the global market.  This oil, sitting in the ground, with the potential to hit the market in a short period of time (an estimate of current completion time is an average of 30 days), is known as “spare capacity,” Minter remarked, and the U.S has the greatest amount of spare capacity in the world.

U.S. producers are starting to show strain on their balance sheets and, accordingly, production is beginning to decline and will continue to do so in the near term.  But while independent U.S. producers are uniquely driven solely by individual profits, their competitors in the global markets, National Oil Companies (NOC), produce for revenue, not profit, and make economic decisions that drive production in NOC regions different than those of independent U.S. producers.  In addition, U.S. producers still have to purchase or lease drilling land, as compared to NOCs, which not only own the land and the production but also often own the refining complex.

“Given the fact that they are currently receiving 25% of the revenues per barrel of oil produced as they were as recently as June 2014, basic math says these NOC countries need to create and sell more volumes at current low prices in order to keep their economies viable,” Minter said.

Platts Analytics does believe energy markets will rebalance, she added, more than likely “in the near-term as a supply-side response.”  While each producer will behave differently than the next, “it seems realistic to assume” that WTI prices in the mid $40-$50/b will bring back incremental volumes to the market place.

And it will be the U.S. producer that is the marginal supplier and price setter into the global market, Minter believes, since the U.S. holds the largest spare capacity in the form of the growing DUC inventory with reserves that can be brought on line in a short time.  “It is the U.S. producer, and their financial determination of what price point is adequate for their balance sheet, that will dictate the time and price that US production will be reintroduced in to the market,” she said.

But, hold on.  If too much production hits the market all at once, the markets may quickly be in an oversupply situation once again.  “Until we find balance and a way to manage supply growth with global demand growth, the recovery for all will be tenuous,” she cautioned.  Nonetheless, Minter feels that the U.S. is “best positioned” to lead such a recovery, due to the spare capacity and the unique economic environment which drives producer activity.

Leslie Palti-Guzman.  Palti-Guzman’s testimony focused on what the changing price environment means for natural gas and U.S. LNG development on the world market.  Basically, the 2016 global gas market is “a buyer’s market.”  Large oil price declines — reflected in oil-indexed gas prices (notably in Asia)—and the abundance of new LNG supply, and European and Asian rock bottom spot prices at a time when traditional Asian demand is muted, have all ushered “in a new order” for LNG markets.

While the permitting, contracting and building of U.S. LNG export facilities was in retrospect “the easy part,” now the U.S. LNG needs to sell, she cautioned.  Flexible purchasing agreements, eroding international prices and weakened demand in top LNG consumer countries could make the market “less attractive” than it was even a few months ago.

Roughly 58 million tons of U.S. LNG have been sold under long-term contracts out of the five facilities currently under construction (sufficient to supply the combined LNG markets of Europe and South America), but there is “no guarantee” that customers will actually use their export options if the economics do not work.  U.S. LNG is “all about flexibility,” which has made it so appealing to purchasers, but it also means that buyers are free to walk away from previously agreed purchases by simply giving notice.

Furthermore, buyers are free to send their LNG without a fixed destination attached — meaning that there is no predetermined dedicated market for U.S. exports.  The destination of U.S. Gulf Coast LNG will be determined by regional price spreads.  Current narrowing regional spreads make U.S. LNG to Asia “unlikely,” Palti-Guzman said.  About half of all cargoes from new LNG export projects were initially expected to go to Asia, but as it stands today about 1/3 of US LNG will go to Asia, while possibly 1/3 will be sent to Europe and 1/3 to the rest of the world, notably South America.

Given the medium-term glut, Palti-Guzman believes the market may take a wait-and-see approach when it comes to making major final investment decisions (FIDs) for building LNG terminals.  Oil price levels, project cost mitigation, competition between supply sources, and natural gas demand will shape the flow of incremental U.S. supply in the coming years.

FIDs that do go ahead in the next four years will feature either major cost reductions, competitive technologies (such as floating systems, FLNG), capacity downsizing, or access to a large-scale resource and/or strategic markets that make the project a winner in the long run despite the current, unfavorable market conditions.

Palti-Guzman suggested that medium-term and long-term demand will be the most critical elements in determining whether the world market can support additional U.S. LNG.  In many countries, natural gas must compete for market share with cheaper coal and “zero-emission renewables”, which makes future demand uncertain.  In Europe, gas does not have an obvious role and it cannot compete with coal without a carbon price.

Prices will continue to matter, and gas and LNG will have to remain competitive to gain market share.  In Asia, more affordable and accessible LNG makes the environmental argument favoring gas over coal or fuel oil more compelling.  Large Asian importers such as Japan and South Korea will save billions of dollars on their LNG bills, and cheaper gas imports can accelerate switching from coal, now supposedly a top Chinese priority to address urban pollution.

LNG is gaining traction in “new niche markets” that see it as a stop-gap solution or as a security of supply necessity, Palti-Guzman pointed out to the Committee.  New countries have entered the LNG importer club the past 2 years (Jordan, Egypt, Pakistan) due to cheaper and wider availability of “non-long-term” supply as well as expanded use of floating storage and regasification units (FSRU) that cut lead time to get in place a LNG import infrastructure (less than 2 years).  However, demand from these new, opportunistic importers “could be fickle” if prices rebound, and some may increase domestic production, secure alternative import supplies, or displace natural gas with competing fuels.

Finally, the rise of more politically stable suppliers, such as Australia and the U.S., reduces the exposure of global gas markets to geopolitical disruptions, which means enhanced energy security for consumers.  Current structural overcapacity mitigates the risk that any isolated geopolitical event that disrupts LNG flows would significantly impact pricing near term.

Jason Bordoff.  Bordoff observed that the U.S. is in the midst of “one of the steepest oil price collapses in history.”  Many factors contributed to this collapse, with the most significant factor being the unprecedented rise in U.S. oil production from shale due to the technological advances in horizontal drilling and hydraulic fracturing.  From 2010 to 2015, the U.S. had the largest five-year ramp-up in oil production of any country in history, increasing to a peak of 9.7 MMb/d in April 2015.   Gas production between 2005 and 2015 increased more than 50%.

When OPEC took no action at its November 2014 meeting, Bordoff noted, oil prices “fell off a cliff.” Then, OPEC countries sharply increased production in 2015.  At the time, analysts believed the average break-even price for producers was around $60 to $70/b.

In reality, Bordoff emphasized, producers proved to be “far more resilient” by applying drilling efficiencies and productivity, taking advantage of declining service costs and hedging tools, and shifting focus to the most productive shale plays – known as “high-grading.”  As a result, even with the price collapse, U.S. production kept rising in the first half of 2015, and then declined only gradually — even as the total rig count collapsed 78%.

Bordoff ventured that the oil price collapse may come to be seen in retrospect as an opportunity for the oil sector “to make itself stronger and more resilient.”  Prices will recover eventually, and U.S. output will start to rise again.  This will likely happen at lower prices than many previously believed because the intense economic pressure of this current downturn forced oil companies to find new and innovative ways to improve their efficiency, productivity, and cost-effectiveness.  “The U.S. may be a short-cycle supplier, but it is most certainly not the high cost supplier (as some previously described it), and that may allow it to better weather future downturns,” Bordoff commented.

Nonetheless, the oil and gas sector lost nearly 100,000 direct jobs since January 2015, and the impact is more severe in states in which oil and gas is a larger share of the economy, like Wyoming, Oklahoma, North Dakota, and Alaska.  On the flip side, the fall in oil prices has offered somewhat of “a macroeconomic boost” by reducing consumer spending on fuel.

The U.S. is still the world’s largest oil consumer and a very large oil importer (even with the recent decline in imports).  The decline in prices helped Americans spend in total $180 billion less per year on energy goods and services compared to July of 2014, which corresponds to about 1% of gross domestic product (GDP).  A year and a half ago, energy expenses constituted 5.4% of total consumer spending, whereas today that share is down to 3.7%, according to Bordoff.

Even so, he added, analysts had expected more of an economic boost from the dropping prices.  Consumer spending has not increased as much as expected based on the historical relation between spending and energy prices.  And the net benefit to the U.S. is smaller because it is such a large producer now.  The big employment gains from the shale boom are now being thrown into reverse.  Also, the U.S. is a much smaller net oil importer than it was before; when the price falls, more of the consumer benefit comes at the expense of domestic producer revenue.

The drop in price has also changed consumers’ behavior.  SUV sales increased 16% in 2015, while plug-in electric vehicle sales decreased 17%.  U.S. gasoline demand, which many thought had peaked in 2007, is increasing and is projected to equal 2007 levels again in 2016 and 2017.  Total oil demand in the U.S. increased 1.5% in 2015 and is projected to increase further by 0.6% and 1.0% in 2016 and 2017, respectively.  With falling domestic production and rising demand, U.S. net oil imports in January 2016 increased 650,000 b/d from a year earlier.

Importantly, from Bordoff’s perspective, more petroleum dependence reduces energy security in a country that is still a significant consumer and importer of oil.  “Thus we increase our energy security if we reduce oil consumption and concomitantly the exposure of the U.S. economy to inevitable oil price fluctuations in the future—not to mention the climate and environmental imperative to reduce oil consumption,” he concluded.

 

Copyright © 2016 by Concentric Energy Publications, Inc.  All rights reserved.

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