Geoff Styles, Managing Director of GSW Strategy Group
Despite the renewed commitment of the US and its allies to a long struggle against terrorism, punctuated by this week's air strikes on Syria, the near-term price of Brent crude oil remains stubbornly below $100 per barrel. Global economic growth is hardly robust, yet without soaring shale oil production in the US, oil prices would surely be much higher as I argued this summer. However, I don't think that paints a complete picture of why Brent looks so weak today.
Since the onset of the "Arab Spring" in early 2011, the only other period of sustained sub-$100 Brent pricing coincided with a spell in mid-2012 when it appeared the financial crisis in the European Union might lead to at least a partial break-up of the EU. Weak demand, or the prospect of it, can have as big an impact on oil prices as the curtailment of a significant producer's output. Today's soft oil market surely reflects lower demand in the EU and slower growth in China, as noted in recent estimates from the International Energy Agency. The big story, though, is still US shale oil and OPEC's response to it.
The numbers for shale, or light tight oil (LTO) as it's often called, are impressive, especially to those accustomed to watching the gradual ebb and flow of different oil sources over long periods. In the 12 months ending in June 2014, US oil production grew by 1.3 million barrels per day (MBD), not far short of Libya's pre-revolution exports. Since January 2011, the US added 3 MBD, or about what the UK produced at its peak in 1999.
In fact, since 2010 incremental US LTO production has exceeded the net decline of the entire North Sea (Denmark, Norway and UK) by around 2 MBD, contributing to a significant expansion of Atlantic Basin light sweet crude supply. And just as the current debate about whether to allow US oil to be exported hinges on crude oil quality as much as quantity, the impact of LTO on Brent is likely about more than just volume. It's the same reason the return of a few hundred thousand barrels per day of Libyan (light, sweet) oil is seen as a serious drag on the Brent price.
The New York Mercantile Exchange defines light sweet crude as having sulfur content below 0.42% and an API gravity between 37 and 42 degrees. That's less dense than light olive oil. Brent is similar. Much of the LTO produced from US shale formations fits those specifications, and what doesn't is typically even lighter and lower in sulfur.
The current "contango" in Brent pricing, in which contracts for later delivery sell for more than those for delivery in the next month or two, is a clear sign of a market that is physically over-supplied: more oil than refineries want to process, with some of it going into storage. However we also see indications that the historical premium assigned to lighter, sweeter crude versus heavier, higher-sulfur crude is under pressure.
One example of this is the gap or "differential" between Louisiana Light Sweet, which wasn't caught up in the delivery problems that plagued West Texas Intermediate for the last several years, and Mars blend, a sour crude mix from platforms in the Gulf of Mexico. From 2007-13 LLS averaged around $4.50 per barrel higher than Mars, while for the first half of this year it was only $2.75 higher and today stands at around $3.40 over Mars.
While OPEC's reported Reference Basket price has been falling in tandem with Brent, its discount to Brent has also narrowed by about $1 per barrel recently, compared with the average for 2007-13. Considering that its components include light sweet crudes from Algeria, Libya and Nigeria that sell into some of the same Atlantic Basin markets as Brent, that looks significant.
A narrowing of the sweet/sour "spread" of only a dollar or so per barrel isn't earth-shattering when it only represents around 1% of the value of the oil in question. However, it might just be the camel's nose under the tent. Further expansion of US LTO output, defensive output cuts by OPEC sour crude producers like Saudi Arabia, and the continued displacement of light sweet crudes formerly imported into the US could all increase the pressure on Brent's premium value. The possibility of US crude oil exports beyond the few cargoes of condensate allowed under current rules adds a wild card to an already strong hand.
It's ironic that for decades the global oil industry planned and invested, anticipating the gradual disappearance of light sweet crude. There were enough periods when that seemed to be occurring to justify the construction of billions of dollars of hardware to convert lower-value heavy and/or sour crudes into high-value products. While there's still a lot of such oil in the market, a prolonged period of narrow discounts versus light sweet crude would frustrate most refiners and reward those who bet against conventional wisdom and kept their facilities simpler.
Geoff Styles, Managing Director of GSW Strategy Group
Could "UK Brent crude" soon be a thing of the past? If the polling last weekend proves accurate, the prospect of Scottish independence is no longer a long shot, and the resulting divorce would force the division of the United Kingdom's energy assets, presumably on a basis favoring Scotland. Although the debate encompasses politics, culture, history and many other factors, energy is central to it, because oil and gas tax revenues would be crucial to Scotland's national finances.
The idea of an independent Scotland never entirely died after the Act of Union in 1707. It gained credibility in the 1960s and '70s when North Sea oil--much of it from Scottish waters--made the UK a major player in the world oil market. The referendum on September 18th is the result of a political deal by the current UK Prime Minister, following a process of "devolution" that has gradually ceded greater autonomy to Scotland within the UK. If Scotland votes to leave, the energy world will look different, too.
The resource portion of the "Yes" argument, articulated in a lengthy white paper, hinges on the proposition that Scotland's post-split allocation of the UK's natural resources would greatly exceed its per capita share, or its 8-9% share of GDP, workforce and similar economic measures. A quick look at a map of UK oil and gas fields shows why. Most of the UK's oil fields lie in waters Scotland would claim, while England's offshore holds mainly lower-valued gas.
According to figures published by the Scottish government, 94% of 2013 UK crude oil production and 49% of natural gas production were attributable to Scotland, equating to over 80% of oil and gas sales revenues of £32 billion. Estimates of a Scottish government's future share of oil and gas taxes vary widely, not least because UK North Sea oil production is in serious decline, while newer resources in the "West of Shetlands" and the Atlantic margin are just starting to be developed. UK oil production peaked in 1999 at 2.9 million barrels per day (bpd) and still yielded over 2 million as recently as 2004, but fell below 900,000 bpd last year. That covered less than 60% of total UK oil demand. The UK became a net oil importer in 2006, but Scotland, with its much lower demand, would be a significant net oil exporter from day one.
The bigger concern isn't current production and revenue, no matter how many details would have to be negotiated concerning the split of producing assets and infrastructure between the two countries. Rather, it's the uncertainties surrounding the development of the remaining North Sea oil and gas resources, which despite its being a highly mature province, look substantial.
The UK government's official 2013 estimate indicated total reserves in currently producing oil fields and those under development at 3.0-7.1 billion barrels, with a central estimate of 4.9 billion. That's after cumulative production of 27 billion barrels. Add natural gas, and reserves increase to 4.5-10.4 billion barrels of oil equivalent (BOE), centered on 7.1 billion. Throw in another billion-plus BOE for "significant discoveries where development plans are under discussion", along with "potential additional resources" and total oil and gas might exceed 18 billion BOE.
The "Yes" campaign's estimate is higher, and it has attracted still bolder assessments, though even at the figure from the UK Department of Energy and Climate Change potential future production would be worth around $1.5 trillion at current prices, ignoring the costs of development and production. After apportioning ownership of these assets, the design and stability of the policies imposed by their new owners would be crucial in determining the pace and extent of future development. It's these uncertainties that appear to worry companies like BP and Shell, based on their public comments. Arguably, the increased uncertainties since the independence referendum was set in 2012 have contributed to the reduced pace of UK North Sea exploration.
As focused as the debate has been on the disposition of today's oil and gas, I'm equally intrigued by the energy choices a post-Scotland UK might make. Consider its unconventional resources, such as shale gas and shale oil. The British Geological Survey identified promising basins in England, such as the Bowland Shale in the midlands, with up to 2 quadrillion cubic feet of gas in place, and the Weald Basin, estimated to hold up to 8 billion barrels of oil in place. Shale development to date has been slow, but accelerating its pace might move up the agenda, particularly under different leadership. For example, Boris Johnson, London's mayor and a possible successor to David Cameron, favors shale policies modeled on successful US conditions. Mr. Johnson recently announced his intention to stand for Parliament next year.
Nor are oil and gas the only energy assets that would have to be divided. The UK has over 5,000 MW of offshore wind capacity in operation or under construction, on seabed held by the Crown Estate--literally the lands of the royal family. While Her Majesty would apparently remain as sovereign north of the border, the "devolution" of the Scottish portion of the Crown Estate has already been broached in the UK Parliament. In any case, most existing UK offshore wind installations are in waters that would likely be controlled by the abbreviated UK. Scotland doesn't lack for wind resources, along with sites for wave and tidal energy, but the bulk of marine renewable energy investment so far has flowed towards England and Wales.
A Washington Post headline this week suggested, "Britain could be on the verge of breakup". Since Britain is technically the island shared by England, Scotland and Wales, rather than their political union, that seems unlikely. However, I can see that the idea of a UK without Scotland (and vice versa) feels geologically momentous to some. It would still be the 7th largest economy in the world, instead of the 6th, with the fourth largest population in the EU, behind Italy. But it wouldn't just be losing some oil and gas, including one of the world's most watched oil prices. The ingenuity and endurance of the Scots have been key ingredients in the national success of the UK for centuries, and they would be sorely missed.
Geoff Styles, Managing Director of GSW Strategy Group
An article from Reuters earlier this month connected two of the biggest energy stories of the last twelve months: the reform of Mexico's oil sector after 75 years of state monopoly, and the US oil industry's drive to gain approval to export a growing surplus of domestic light crude oil. Exporting US oil to Mexico should make sense geographically and economically, though regulatory hurdles remain. It could also increase tension between US oil producers and refiners over the merits of exporting crude versus refined products.
At first glance, the idea seems counterintuitive. Our southern neighbor was the third-largest exporter of oil to the US last year, consistently ranking above Venezuela. However, most of that oil is heavy and sour, in contrast to the light, low-sulfur "tight oil" (LTO) produced from US shale formations like the Eagle Ford of Texas.
Mexico has experienced supply and demand trends similar to what the US saw prior to our shale revolution. Total oil and gas liquids production has fallen by 25% since 2004, largely due to declining output of Maya crude from the supergiant Cantarell field, while demand for refined products grew by around 20% in the same period. Lightening the crude oil slate of Pemex's oil refineries with LTO imported from the US could augment efforts to increase throughput and yields of transportation fuels.
The Commerce Department's recent approval for two US companies to export lightly-processed condensate, which despite its similarities is technically not crude oil, was followed by a hold on similar applications. These events have fueled both enthusiasm and confusion concerning US oil exports, which are still politically controversial, after decades of declining US production and periodic price spikes.
An easier sell might involve the exchange or "swap" of surplus LTO for imported heavy oil, and Mexico makes an ideal partner for this kind of transaction. Existing law at least recognizes the potential for such swaps with "adjacent countries", though it remains to be seen whether such a deal could be made to fit language specifying that the oil received be of "equal or better quality".
As a former oil trader, it strikes me that the best ways to close that gap might be to structure an LTO vs. Maya swap as a barrel-for-barrel exchange in which the US party would collect a financial premium in recognition of the quality difference--money being another measure of quality--or a "ratio exchange" in which every barrel of LTO delivered would be matched by a larger quantity of Maya, at a proportion determined by the refining values of the two oils. Either option would still require some regulatory finesse, but of a much different type than approving the outright, net export of US oil production.
The biggest stumbling block to an exchange of LTO for Mexican crude would probably be one of the same ones impeding the general lifting of a US oil export ban that the Washington Post just called "an economically incoherent policy." While US oil producers argue that allowing exports would enable their product to be sold for its global value and incentivize even higher future production, US oil refiners see exports as a threat to their margins and to the growth of their own exports of refined products. These have been crucial in sustaining arguably the world's best refining industry in the face of a weak economy and declining demand at home.
Mexico is at the heart of this trend. Its imports of LPG, gasoline, diesel and other fuels from the US have increased to over 500,000 barrels per day (bpd) in recent years. Mexico accounted for 44% of all US gasoline and gasoline blending components exported last year, along with 10% of diesel fuel exports and 15% of LPG. I don't think it's especially controversial to suggest that exporting light crude oil to Mexico would come at least partly at the expense of our refined product exports to the country.
This boils down to the familiar economic dilemma of exporting raw materials versus capturing the value added from selling manufactured goods. I'm sympathetic to the refining industry's concerns, and not just as a former refinery engineer. However, those concerns would carry more weight if US refineries had the capacity to process all of the LTO the US is likely to produce in the years ahead, and to pay a world-market price for it. Refiners might benefit from access to lower-priced crude, but if driving down the value of LTO in a confined market choked production, net US oil imports would be higher than otherwise and the economy would be worse off.
Stepping back from the details of that debate, exporting US light crude oil in exchange for Mexican heavy crude has appeal within a broader and increasingly credible vision of North American energy self-sufficiency. That wouldn't mean cutting North America off from the global oil market, but it would put us and our neighbors in the enviable position of being able to select imports based on opportunity rather than necessity. A reformed and revitalized Mexican oil industry, importing and exporting oil with its neighbors as it makes sense, could be a cornerstone of that vision.
Geoff Styles, Managing Director of GSW Strategy Group
Two recent news stories highlighted different ways that utilities and large generating companies are beginning to respond to the emergence of distributed generation (DG) as more than back-up power. Arizona Public Service (APS) is launching its version of potentially the most challenging type of DG for utilities, rooftop solar. Meanwhile, Exelon Corp. announced an investment partnership with a provider of gas-powered fuel cells. The success of such ventures and the evolution of DG will have implications for electrical grid stability and our future energy mix, including the role of flexible, large-scale gas-fired generation.
APS is seeking regulatory approval for a program that might be characterized as free rooftop solar. In effect, they would lease approved homeowners' rooftops for $30 per month, in order to host a total of 20 MW of solar panels that would be owned and controlled by APS. The idea has generated some controversy, partly due to the utility's rocky relationship with the solar industry over issues like "net metering".
The plan would enable homeowners who might not otherwise qualify for solar leasing from third parties to have solar installed on their homes, although they would apparently still receive their electricity through the meter from the grid, rather than mainly from the rooftop installation. That's a very different model from most DG approaches, though under current market conditions the net benefit to consumers reportedly would match or exceed that from solar leasing.
Exelon's announcement is aimed at a different segment of the market and is based on a very different technology. The company would finance the installation of 21 MW of Bloom Energy's fuel cell generators at businesses in several states, including California. Bloom made quite a splash when it introduced its "energy servers", including a popular segment on "60 Minutes" in 2010.
Bloom's devices, which come in models producing either 100 kW or 200 kW, are built around solid oxide fuel cells. At that scale they are too large for individual homes but suitable for many businesses. And because they are modular, they can be combined to meet the larger energy needs of offices or commercial facilities such as data centers. Unlike the fuel cells being deployed in limited numbers of automobiles, they do not require a source of hydrogen gas. Instead they run directly on natural gas from which hydrogen is extracted ("auto-reformed") inside the box.
In that respect, despite their novel technology, Bloom's servers are much closer than rooftop solar to traditional distributed energy, in which a customer owns or leases a small generator to which it supplies fuel. The advantage of Bloom's model is that its servers are designed for highly efficient 24x7 operation, without the expensive energy storage necessary to turn solar into 24x7 power, and with much lower greenhouse gas emissions and local pollution than a diesel generator.
In order to qualify as true zero-emission energy, these installations would need to be connected to a source of biogas, e.g., landfill gas, which effectively creates a closed emissions loop or recycles emissions that would have occurred elsewhere. Even running on ordinary natural gas, the stated emissions of Bloom's energy servers are roughly a third less than the average emissions for US grid electricity, or 20% lower than the average for other natural gas generation. Their emissions are over 10% higher than the 2012 average for California's grid.
I find it interesting that Exelon, the largest nuclear power operator in the US and owner of a full array of utility-scale gas, coal, hydro, wind and solar power, would make a high-profile investment in a technology that could ultimately slash the demand for its large power plants. The company has invested in utility-scale solar and wind power, and as the press release indicated, is already involved in "onsite solar, emergency generation and cogeneration" via its Constellation subsidiary. In fact, it has apparently already achieved its goal of eliminating the equivalent of its 2001 carbon footprint. However, the press release hints that something else might have attracted them to this deal.
Consider all the changes in store for the power grid. Baseload coal power is declining due to the combination of economic forces and strong emissions regulations such as the EPA's Clean Power Plan. Even some nuclear power plants, which have been the workhorses of the fleet for the last several decades, are facing premature retirement for non-operational reasons. At the same time, grid operators must integrate steadily growing proportions of intermittent renewable energy (wind and solar), along with increasingly sophisticated tools like demand response and energy storage. If any of this goes wrong, electric reliability will likely suffer.
From that perspective, Exelon's small--for them--step into DG also looks like a bet on the future value of reliability--"non-intermittent...reliable, resilient and distributed power." That's a bet even an old oil trader can understand: Uncertainty creates volatility, and volatility creates opportunities. I will be very interested to see how this turns out.
Our writers' profile
Geoff Styles - Managing Director of GSW Strategy Group, an energy and environmental strategy consulting firm
V.P. of Geoscicences, STXRA, a strategic partner in PED's technical and drilling operations
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