Shrinking the Strategic Petroleum Reserve

• Selling oil from the Strategic Petroleum Reserve as part of the Congressional budget compromise raises serious questions about the SPR's future role.
• Shrinking the SPR without first bringing its coverage into line with 21st century needs risks strengthening OPEC's hand. 

Last month's Congressional budget compromise included plans to sell 58 million barrels of oil from the US Strategic Petroleum Reserve, beginning in 2018. That decision raises serious questions. The world has changed enormously since the SPR was established in the 1970s, but the realignment of such an asset for the 21st century deserves a full strategic review and debate. Leaping ahead to treat the SPR like an ATM  seems unwise on multiple grounds.

My initial reaction was that the sale would result in the US government effectively buying high and selling low. However, using the last-in, first-out (LIFO) accounting common in the oil industry, the SPR release during the 2011 Libyan revolution should have removed any barrels purchased as prices surged past $100 per barrel (bbl) to over $140, prior to the financial crisis. The oil now slated to be sold in 2018-25 was likely injected between December 2003 and June 2005, when West Texas Intermediate crude oil averaged around $44/bbl. The Treasury should at least break even on these sales, allowing us to dispense with judging the trading acumen of the Congress and focus on the strategic aspects of this decision.

It is also true that the combination of revived US oil production and lower domestic petroleum demand effectively doubled the notional import protection that the SPR provides. That has made policy makers comfortable enough with the coverage the reserve provides to consider shrinking it. Yet as Energy Secretary Moniz  and a growing body of experts have concluded, the SPR's present configuration is inadequate to deal with whole categories of plausible oil-supply disruptions.

Today's SPR consists entirely of crude oil stored in caverns near the major refining centers of the Gulf Coast, to which it is connected via pipelines. However, while crude oil imports into the Gulf Coast have fallen dramatically, the long-term decline of oil production in Alaska and California has forced West Coast refiners to import 1-1.5 million bbl/day of oil, including more than half of California's crude supply, much of it from OPEC producers. In the event of an interruption of those deliveries, and under current oil-export restrictions, getting SPR oil from Texas and Louisiana to L.A. and San Francisco would pose enormous logistical challenges.

We have also learned that natural disasters such as hurricanes Katrina and Rita in 2005 and Superstorm Sandy in 2012 affect refinery operations, as well as oil deliveries.  A crude oil SPR is of little value if its contents can't be processed into the fuels that consumers and industry actually use.  The newer Northeast heating oil and gasoline reserves were intended to address that limitation, though on a much smaller scale.

It is thus fair to say that the SPR established in the Ford Administration and filled by the next five US presidents to a level now equivalent to 137 days of US crude oil imports is not diverse enough in its composition or locations, and too big for our current needs. If we could count on a continuation of cheap, abundant oil for the next two decades, selling off some SPR inventory wouldn't create problems. However, the purpose of such a reserve is to mitigate the risks of uncertain and inherently unpredictable future conditions and events. That should be factored into any decision to shrink it.

We don't have to look far to find reasons to suspect that oil prices might someday be higher and more volatile--perhaps as soon as the 2018-25 legislated sales period--or to worry that oil supplies from the Middle East might become less secure. Consider the consequences of the oil price collapse that began over a year ago. Low oil prices have indeed put pressure on the highly flexible US shale sector, where production is now expected to drop by around 500,000 bbl/day by next year. The impact on large-scale, long-lead-time capital investments in places like Canada, the North Sea and Gulf of Mexico has been even more profound. Over $200 billion of new projects and exploration activity have been deferred or canceled. Unlike shale, most of these projects could not be revived quickly if prices rebounded.

As production from existing fields declines without replacement, the current global oil surplus will dissipate, bringing the market back into balance. However, that balance is likely to be more precarious than before, since last fall's strategic shift by OPEC to protect its market share instead of managing prices entails the depletion of OPEC's "spare capacity." That means that in a future crisis, Saudi Arabia and other OPEC producers will have little flexibility to increase production to make up for lost output elsewhere.

Barring an unforeseen reduction in global  oil demand, the scenario that is beginning to take shape fits the  pattern of risks that the SPR was originally intended to address. It includes the prospect of rising US oil imports, increasing reliance on OPEC, and the threat posed by ISIS in the world's oil "breadbasket".  In that light it is hard to justify reducing the size of the SPR without a clear plan for making the remaining volume more effective at shoring up future vulnerabilities in US energy security.

In their haste to reach a deal, Congressional negotiators may also have overlooked some SPR-related alternatives that could generate revenue without draining inventories. These might include allowing other countries to buy into the reserve by means of "special drawing rights," or simply selling long-dated call options backed by the SPR, to be settled in the future by delivery or cash, at the government's discretion.

Taken together, there are ample reasons for the next Congress and administration to revisit the SPR sales provisions of the 2016 budget deal, before they go into effect.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation

How Shale Reduced US Energy Risks from Hurricanes

• The Gulf of Mexico will be a key region for energy supplies for years to come, but shale development has boosted output elsewhere to such an extent that the US is much less vulnerable than a decade ago to shortages resulting from hurricanes.

Just in time for the 10-year anniversary of Hurricane Katrina last month, the US Energy Information Administration (EIA) reported on the reduced vulnerability of US energy supplies to Atlantic hurricanes, as a result of the energy shifts of the last decade. As the Houston Chronicle noted, this illustrates another benefit of the revolution in shale oil and gas. However, with oil still below $50 per barrel, it is also worth considering how durable these particular effects might be if low oil prices were to persist much longer.

Following hurricanes Katrina and Rita, which made landfall on the Gulf Coast within a few weeks of each other in 2005, I recall some lively  discussions concerning the concentration of US energy assets in the region, and what that meant for US energy security. There was talk of new inland refineries, and even proposed legislation to promote them. With the exception of one small refinery in North Dakota, which came online earlier this year, most of that talk led nowhere. The synergies of the Gulf Coast refining and petrochemical complex were and still are overwhelming.

From the perspective of diversifying US crude oil and natural gas supplies, the situation looked equally daunting in 2005, excluding higher imports of both--an outcome that already seemed unavoidable. The country's main onshore oil fields, including the Alaska North Slope, were in decline. In 2004 their combined output averaged less than 4 million barrels per day for the first time since the 1940s. The deep waters of the Gulf of Mexico were where the majority of accessible, unexploited US oil and gas was expected to be found.

With hindsight it now seems clear that in 2005 the first large-scale application of hydraulic fracturing ("fracking") and horizontal drilling to shale in the Barnett gas field near Dallas, TX was pointing to an entirely different set of possibilities.  The Barnett had just passed a major milestone: one billion cubic feet per day of production. However, other than visionary entrepreneurs like George Mitchell, few energy experts then foresaw how rapidly shale could scale up elsewhere.

Fast-forward to 2015, and the country has experienced a profound geographical diversification of its energy sources. As the following key chart from the EIA's analysis shows, since 2003 the offshore Gulf of Mexico's share of US production has fallen by 40% for crude oil and by nearly 80% for natural gas.

The divergence in those figures may seem surprising. "Tight" oil from deposits North Dakota, onshore Texas and the mountain West supplemented deepwater production that post-Deepwater Horizon has recovered to roughly the level of 2004, bringing total US oil output close to an all-time record earlier this year.  Meanwhile, rising shale gas output in Arkansas, Louisiana, Ohio and Pennsylvania  more than compensated for  the steady, long-term decline of Gulf of Mexico gas production. The extent of the shift in US gas sources has even raised questions about the viability of the benchmark Henry Hub (Louisiana) trading point for the main gas-futures contract. 

In fact, when we look beyond oil and gas to factor in the growth of renewable energy and the recent decline in coal consumption in the power sector, since 2004 the equivalent energy dependence of the US on the Gulf of Mexico--including imports--has fallen from 7% to roughly 4%, in terms of total energy consumption.

If oil prices had remained where they were a year ago, above $90 per barrel, there would be little doubt that this trend would continue. However, the latest short-term forecast from the EIA suggests that US onshore oil production will fall by about 6%, due to reduced shale drilling, while Gulf of Mexico production ticks up about the same percentage, as more projects that were begun under higher oil prices come onstream. This is generally consistent with the outlook of the International Energy Agency. By itself that could cause a small increase in Gulf of Mexico dependence.

As for gas, EIA projects that US onshore natural gas production will continue to grow, though at a slower rate than recently, while offshore gas continues its decline, reinforcing the shift away from the Gulf. The technology and techniques for developing onshore shale gas continue to improve, even with low natural gas prices, while the identified gas resources of the eastern Gulf of Mexico remain off-limits.

The relative importance of the large refining centers on the Gulf Coast may be evolving, too, for different reasons. US refined product exports have grown substantially since the financial crisis, with most of them sourced from the Gulf Coast. To the extent such shipments could be delayed in an emergency or swapped for product sourced abroad to be delivered to their original destinations, that effectively creates a buffer against storm-related disruptions in domestic deliveries.

The abundance of natural resources and the legacy of decades of infrastructure investment guarantee that the US Gulf Coast will remain a key region for US energy supplies. However, the technology for tapping resources elsewhere has greatly reduced the chances for a repeat of the events of 2005, when a pair of hurricanes set the stage for the highest natural gas prices in US history. Low oil prices might slow down further reductions in the relative energy contribution of the Gulf, but a significant reversal of this trend looks unlikely under either low or high oil prices.

 

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

The Path of Least Resistance, Revisited

Three years ago, in the aftermath of Hurricane Katrina, I posted some remarks concerning the concentration of our energy infrastructure in the Gulf Coast. As we head into the Labor Day weekend with Tropical Storm Gustav bearing in a similarly threatening direction, and with the nation embroiled in a debate about expanded offshore drilling and refineries, many of these points still seem timely, with a few updated comments in italics below:

There are natural reasons why the Gulf Coast should be home to a large concentration of the country's energy infrastructure. Nature has provided a bounty of hydrocarbon reserves in this area, with sizable fractions of our oil and natural gas production coming from the coastline between Brownsville, TX and Mobile, AL. It was natural that so much of our refining system and crude and product pipelines would be concentrated in the same area, given their access to domestic, and later imported crude oil. But we need to talk about the additional concentration that is due, not to the natural incidence of resources, but to the difficulties entailed in building energy facilities elsewhere in the country.

When a company looks to add refinery capacity to its network, it is logical to add on to an existing facility, rather than build a new one from scratch, incurring extra investment in basic infrastructure, including water and power. But for the last two decades, there has been little choice available to oil companies, even if it made more economic and logistical sense to start a new refinery elsewhere. Environmental regulations and permitting bureaucracy simply foreclosed this option. Refiners were forced to take the path of least resistance.

The result is that 10% of the country's refinery capacity was sitting in the path of Hurricane Katrina, and even this was a stroke of luck. Had the storm tracked further west and barreled down the Houston Ship Channel, instead of the Mississippi basin, the damage to our refined products infrastructure might have been worse. Houston and the nearby Texas coast are home to nearly 4 million barrels per day of refining capacity, in contrast to the 1.8 MBD or so that Katrina shut down in Louisiana. That was still enough to boost the US average regular gasoline price by 45 ¢ per gallon in one week, giving most of us our first taste of $3 gasoline.

Katrina knocked out nearly 20% of the country's natural gas production, due to the high proportion of supply coming from shallow and deep water gas platforms in the Gulf. It also took 900,000 barrels per day of oil production offline. Most of that came back, gradually, but for the year after Katrina, Gulf Coast output averaged 300,000 bbl/day less than the previous year. A number of new projects were also delayed, including BP's giant Thunder Horse platform. This is nature's part of the equation, and we can't change where the oil and gas reserves are found. However, we can rethink the default option for natural gas imports in the form of liquefied natural gas, along with the offshore drilling bans that have contributed to the concentration of our supply.

We've made some progress since 2005. The Gulf's share of US natural gas production has dropped to about 12% today, partly due to the decline of offshore gas fields, but also to the rapidly-increasing output of unconventional gas from sources such as the Barnett Shale. Biofuels and other dispersed forms of alternative energy also contribute to diversification, although it will be some time before they scale up to a magnitude comparable to oil and gas. Unfortunately, our tendency to follow the path of least resistance remains largely intact. Even the Congressional "Gang of 10" energy compromise exhibits this trait: expanded offshore drilling, yes, but mainly in the eastern Gulf of Mexico. And despite years of talk about new refineries outside the hurricane belt, when the expansion of Motiva's Port Arthur, TX refinery and Marathon's Garyville, LA facility are completed, the Gulf Coast will account for a larger share of US refining capacity than when hurricanes Katrina and Rita came though.