<![CDATA[PEDEVCO Corp. (Pacific Energy Development) Corporate Website - BLOG]]>Tue, 24 Nov 2015 17:43:03 -0800Weebly<![CDATA[ Shrinking the Strategic Petroleum Reserve ]]>Thu, 05 Nov 2015 18:55:36 GMThttp://www.pacificenergydevelopment.com/blog/-shrinking-the-strategic-petroleum-reserveGeoff Styles - Managing Director of GSW Strategy

The recently agreed Congressional budget compromise includes plans to sell 58 million barrels of oil from the US Strategic Petroleum Reserve, beginning in 2018. This 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, on a last-in, first-out (LIFO) basis the 2011 SPR release (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 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.
The good news is that the combination of revived US oil production and lower domestic petroleum demand effectively doubled the notional import protection that the SPR provides. 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-tem 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 of the SPR's inventory wouldn't create much cause for concern. Yet 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 the SPR.

We don't have to look far to find reasons to suspect that oil prices might someday be higher and more volatile than today--perhaps as soon as the 2018-25 legislated SPR 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 gradually dissipate, bringing the market back into balance. However, that balance is likely to be more precarious than before, since OPEC's strategic shift to protect market share instead of managing prices entails the shrinkage of its "spare capacity." That means that in a future crisis, Saudi Arabia and other OPEC producers would have less flexibility to increase production to make up for lost output elsewhere.

Barring an unforeseen reduction in global  oil demand, the scenario that is starting to take shape, including the prospect of rising US oil imports, increasing reliance on OPEC, and the growth of ISIS in the world's oil "breadbasket", fits the  pattern of risks the SPR was originally intended to address. 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. 

Together, these strategic and geopolitical concerns should provide ample motivation for the next Congress and administration to revisit the SPR sales provisions of the 2016 budget deal, before they go into effect.

<![CDATA[Diesel's Future on the Line]]>Fri, 02 Oct 2015 23:07:20 GMThttp://www.pacificenergydevelopment.com/blog/diesels-future-on-the-lineGeoff Styles - Managing Director of GSW Strategy

​Whether or not Volkswagen's diesel deception proves to be "worse than Enron" as a Yale business school dean commented, it is more than just the business scandal du jour. Its repercussions could affect many other carmakers, especially those headquartered in Europe. And if it triggered a large-scale shift by consumers away from diesel passenger cars, that would have major consequences for the global oil refining industry, oil and gas producers, and sales of electric and other low-emission cars.

The scale of the problem ensures that it will not blow over quickly. Nearly 500,000 VW diesel cars in the US were equipped with software to circumvent federal and state emissions testing, and the company has indicated that 11 million vehicles are affected, worldwide. Even if Volkswagen's retrofit plan passes muster with regulators in the US, Europe and Asia, the resulting recall could take years to complete.

It's also still unclear whether VW's diesel models are unique in polluting significantly more under real-world conditions than in laboratory testing. Regulators in Europe appear to suspect the problem is more widespread. Other companies use essentially the same emission-control technologies--from the same vendors--to control the NOx and particulates from smaller cars equipped with diesel engines. The French government announced plans to subject 100 diesel cars chosen at random from consumers and rental fleets to more realistic testing.

So aside from the investigations and lawsuits that VW faces in multiple countries, the claims of every carmaker selling "clean diesels" and the reputation of a technology that European governments have long viewed as a crucial tool for reducing CO2 emissions and oil imports are likely to be under a cloud for at least the next few years. How consumers react to all this will determine the future, not only of diesel cars, but of the future global mix of transportation fuels and vehicle types.
Start with oil refining. As long ago as the early 1990s, when I traded petroleum products in London, the European shift to diesel was creating a regional surplus of motor gasoline and a growing deficit of diesel fuel, or "gasoil" as it is often called there. For a while trade was the solution: The US was importing increasing volumes of gasoline to meet growing demand and had diesel to spare. The fuel imbalances of the US and EU were well-matched, in the short-to-medium term.

As this shift continued, the wholesale prices of diesel and gasoline in the global market adjusted, affecting refinery margins on both sides of the Atlantic. Marginal facilities in Europe shut down, while others invested in the hardware to increase their yield of diesel and reduce gasoline production. US refiners also invested in diesel-making equipment.

The aftermath of the financial crisis and recession increased the pressure on Europe's refiners, as did the rapid growth of "light tight oil" production in the US. Europe's biggest export market for gasoline dried up as fuels demand slowed and US refineries reinvented themselves as major exporters of gasoline.

Diesel cars still make up less than 1% of US new car sales but have accounted for around 50% of European sales for some time. If governments and consumers were now to lose their confidence in diesels and shifted back toward gasoline, it would wrong-foot Europe's refineries and leave them with some big, underperforming investments in diesel hardware.  A persistent slowdown in diesel demand could alter corporate plans and strategies even faster than refinery profits. In the meantime, US refineries would stand to benefit from a bigger outlet for their steadily rising gasoline output.    

If consumers did retreat from diesel passenger cars--trucks are unlikely to be affected--the shift back to gasoline could be less than gallon-for-gallon, because competing technology hasn't stood still since 2007, when the US Congress enacted stricter fuel economy standards and the Environmental Protection Agency's tougher tailpipe NOx standard went into effect.

New gasoline cars are closing the efficiency gap with diesels, thanks to direct injection, hybridization and other strategies. At the same time, the number of new electric vehicle (EV) models is growing rapidly, their cost is coming down, and infrastructure for EV charging is sprouting all over.

EVs still accounted for less than 1% of the US car market last year, but the combined sales of the Chevrolet Volt, Nissan Leaf, Tesla Model S and over a dozen other plug-in hybrid and battery-electric models nearly matched those of the standard Prius hybrid "liftback". EVs are still not cheap, even after government incentives that mainly benefit high-income taxpayers. Most still come with a dose of "range anxiety", but they are greatly improved and getting better with each new model.

Even in Europe, where EVs haven't sold very well outside Norway, a big shift away from diesel would surely help EVs gain market share. If European consumers bought 9 gasoline cars and one EV for every 10 new diesels they avoided, European refiners would soon see not just a shift, but a net drop in fuel sales. Nor would refineries be the only part of the petroleum value chain to be affected. Global oil demand would grow more slowly as well, bringing "peak demand" that much closer.

For now, this scenario is hypothetical. VW may solve its technical problem, bringing the 11 million affected vehicles into compliance with pollution standards and performing more-or-less as advertised. Meanwhile, regulators could find that most other carmakers have been in compliance all along, particularly those selling cars that use the urea-based Selective Catalytic Reduction NOx technology; the rest might only need a few tweaks.

​In that case, the scandal might eventually die down without putting small diesel cars into the grave, as a mock obituary in the Financial Times recently suggested. Carmakers would have a hard time increasing diesel's penetration of markets like the US, but loyal diesel customers around the world might still conclude that these cars provide them the best combination of value, convenience and drivability. Having driven a number of diesels as rentals and at auto shows, I wouldn't dismiss that possibility too easily. The jury is likely to be out for a while.

<![CDATA[ The Shale Revolution Has Reduced US Energy Risk from Hurricanes ]]>Tue, 15 Sep 2015 15:56:18 GMThttp://www.pacificenergydevelopment.com/blog/-the-shale-revolution-has-reduced-us-energy-risk-from-hurricanesGeoff Styles - Managing Director of GSW Strategy

A recent report from the US Energy Information Administration (EIA) highlighted the impact of the energy shifts of the last decade in reducing the vulnerability of US energy supplies to Atlantic hurricanes. The report was issued just in time for the 10-year anniversary of Hurricane Katrina. As the Houston Chronicle noted, It illustrates another benefit of the revolution in shale oil and gas. However, with oil below $50 per barrel, it is also worth considering how durable these particular effects might be if low oil prices were to persist.

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 this 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.

From our current vantage point we can see 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.  It  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 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, at 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 latest outlook from 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.

Nature 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.
<![CDATA[What Do Futures Markets Tell Us About Long-term Oil PricesĀ ]]>Thu, 13 Aug 2015 06:26:21 GMThttp://www.pacificenergydevelopment.com/blog/what-do-futures-market-tell-us-about-long-term-oil-pricesGeoff Styles - Managing Director of GSW Strategy

An article in Monday's Wall Street Journal reminded me of numerous debates about the significance of energy futures prices, when I was a trader and later a trading manager for the former Texaco, Inc.  Do changes in futures contract prices actually predict future oil prices as the Journal's reporter suggests? If so, then it might be reasonable to conclude that today's low oil prices could persist for years. However, from my perspective that over-interprets the market data and ignores some important oil fundamentals.

As tempting as it might be to think so, the futures market for West Texas Intermediate (WTI) crude oil isn't a crystal ball, and neither is the market for UK Brent crude. A futures price is simply the price someone is willing to pay or receive now for oil to be delivered (or settled without delivery) later. It is typically based on business needs, rather than deep analysis.  A concrete example might be helpful.

The parties who on Tuesday bought or sold oil for $56 or $57 in December 2017 likely did so, not because they were certain what the price would be then, but because they couldn't be sure and either needed to hedge another transaction or activity, or thought it constituted a reasonable bet. Aggregating a modest number of such transactions--long-dated futures trade much less frequently than those for the near months--doesn't improve the accuracy of these bets on an inherently unpredictable commodity over long intervals. Anyone who thinks it does should examine the track record of oil futures as predictions; it is a sobering exercise, especially for those who have traded this market.

Consider that while the September 2015 WTI contract closed at a little over $43 per barrel Tuesday afternoon, traders were buying and selling the same contract for more than twice as much during long stretches of 2012--about as far removed from us as the late-2017 contract prices cited in the Journal article as evidence of a persistent oil-price slump. Prices for the September 2015 contract were even higher in the middle of last year, when traders knew nearly as much about the growth of US tight oil production and its rising productivity as we do today, but crucially didn't know that OPEC would choose not to cut output to alleviate an over-supplied market as they had done in the early 1980s and late 1990s. Similar examples abound.

So how else might one explain the fact that long-dated oil contracts are trading for less today than they were this spring, if not as a prediction of a longer period of low prices ahead? Behavior and learning play key roles. With the  first anniversary of this historic price collapse just a few months off, expectations of a quick rebound in prices have faded. The possibility that the US could produce as much tight oil, for now, with fewer than half as many drilling rigs in operation as a year ago has sunk in. So has the reality that as painful as $50 oil is for some of OPEC's members, cartel leaders like Saudi Arabia show little inclination to blink first.

However, others are blinking, and that's why I'm skeptical that oil prices can remain this low indefinitely. The cuts in staff and investment budgets by major oil companies and their national oil company peers have been breathtaking, totaling $180 billion this year according to one analysis. The cuts suggest that the projects in question require significantly higher oil prices to be profitable, even after recent cost reductions, or have become too risky at current prices.

Few of these companies are big players in shale. Their bread and butter is large, conventional onshore oil fields and enormously expensive deepwater oil projects, the collective output of which is inherently subject to annual declines in output. Decline is the "silent killer" of output, to the tune of 5% or so every year. The only way to offset this trend within the portfolios of these producers is to spend large sums every year on new wells and new projects--projects that according to Rystad Energy, as cited by Bloomberg, have been cut more than at any time since 1986.

We must also put the US shale revolution in its proper context. When added to a global market that was balanced between supply and demand at around $100 per barrel, it was a game-changer, not least because no other producer or group of producers was willing to reduce output enough to accommodate this new source. However, even at today's 5.4 million barrels per day US tight oil represents only about 6% of global supply. The combination of shale plus OPEC covers less than half the world's oil demand.

The remainder must come from onshore and offshore oil fields in non-OPEC countries like Brazil, Mexico, Norway and Russia. This non-OPEC supply has grown thanks to  a wave of completions of  large projects begun 5-10 years ago, when prices were rising rapidly. However, reduced investment now surely means lower non-OPEC production within a year or two.

The key question for future oil prices is therefore when demand, which according to the International Energy Agency is growing rapidly under low prices, and supply, for which new investment has suddenly shifted from the accelerator to the brake pedal, will cross over, erasing today's glut. It's hard to infer the answer from the thinly traded market for long-dated oil futures contracts.
<![CDATA[The Return of Iran's Oil]]>Fri, 17 Jul 2015 18:40:22 GMThttp://www.pacificenergydevelopment.com/blog/the-return-of-irans-oil Geoff Styles - Managing Director of GSW Strategy

The signing of a nuclear agreement between Iran and the five permanent members of the UN Security Council plus Germany represents more than a geopolitical milestone. In the context of today's lower oil prices it puts additional pressure on near-term prices, but perhaps more importantly creates the potential for significant shifts within the oil industry. Iran's expanded exports--once the conditions of the deal are met--will arrive in a market quite different from the one that prevailed when they were restricted in early 2012.

These differences include an OPEC that is now engaged in a contest for global market share, rather than one focused on maintaining oil prices at around $100 per barrel. This is the cartel's response to the rapid growth of non-OPEC production, mainly from US shale, or "tight oil" formations. Based on data from the International Energy Agency, non-OPEC production has increased by 5 million barrels per day (bpd) since 2012, while global demand has grown by just 3 million bpd.  The return of anywhere from 600,000 to 1 million bpd of Iranian exports would expand a global oil surplus and intensify competition.

 Iran's oil traders may find that placing additional volumes with refiners will not be as easy as it would have been just a few years ago. As the Wall Street Journal noted, the likeliest home for most of this incremental supply is in Asia, where competition between Saudi, Iraqi and Russian barrels is already keen. China and India have been the largest purchasers of Iranian oil during the sanctions (see chart below) but Iran is not the only producer seeking to expand its output of similar crude oil. 


Oil prices have two main dimensions, only one of which is widely understood outside the industry. Media reports focus on the absolute price level, particularly for benchmark grades such as Brent and West Texas Intermediate (WTI). However, differentials--the gaps in price for oils of different quality, or of similar quality in different regions--are nearly as important for producers and often more so for refiners.

Iranian oil is mainly sour (high in sulfur) and so competes principally with other sour grades, including those from Saudi Arabia, which is already at record output, and Iraq, where production is approaching 4 million bpd, compared with just under 3 million in 2012. OPEC's other big producers seem no more inclined to cut output to make room for extra Iranian oil than they were to accommodate surging US tight oil. Meanwhile, refineries in Europe, where sanctions on Iranian oil had the largest impact, are also "spoiled for choice" with various crude streams displaced from US refineries by the shale revolution.   

If Iran's restored exports keep oil prices lower for longer, they are also likely to widen the "sweet/sour spread", or premium for light sweet crudes like those produced in the Bakken and Eagle Ford shales, over sour crudes like Saudi medium or Iranian heavy. That would lend greater urgency to calls for an end to 1970s-vintage restrictions on exporting US crude oil, because it would expand the potential economic opportunity for US exports.

As a result of opening the taps in Iran, we could also see deeper shifts in the structure of the global oil industry. OPEC's current production policy may be targeted at US shale, but shale producers have proven themselves much more adaptable than expected to prices in the $50-60 range. The same cannot necessarily be said for new conventional oil projects with price tags in the hundreds of millions to billions of dollars. 

Barring another shift as dramatic as the one that rippled through oil markets last fall, we may have witnessed the end of an era in which low-cost producers in OPEC held back production to drive up prices and, in the process, made room for much higher-cost production elsewhere. Iran appears poised to go beyond its pre-sanctions exports by inviting international investment in new developments that would be profitable at current prices.  If Iran's terms are attractive, the losers won't be shale producers that operate at dramatically lower scales of investment and risk per well, but big projects in places like the North Sea, which has already seen a wave of project cancellations. The recent lackluster Mexican bid round might be another signpost.

Could we end up in a few years with a global oil industry in which prices would be determined mainly by a new balance between a resurgent OPEC and US shale producers? That would be a very different world than we have experience recently, and probably one with more price volatility.

Of course before any of this could happen, the nuclear agreement with Iran would have to go into effect and be widely seen to be holding. For anyone who recalls the periodic inspection crises with Iraq in the late 1990s, that can't be a foregone conclusion, even if the agreement survives review by a US Congress that asserted its right to scrutinize the deal's provisions.