Our Houston team had the pleasure of meeting with a delegation from Kazakhstan on June 24 during their one week managerial exchange visit in the United States. The meeting was organized by the USEA (United States Energy Association) for representatives of the Kazakhstan Ministry of Industry and New Technologies, with a goal of providing an overview of strategies and best practices used in U.S energy sector. The discussion, led by Greg Rozenfeld, PED's Chief Technology Advisor, and Michael Rozenfeld, VP Geoscience, covered the industrial development and fracking technologies in the U.S.
Several speakers at this week's annual EIA Energy Conference in Washington, DC reminded the audience that energy security extends beyond oil, starting with Maria van der Hoeven, Executive Director of the International Energy Agency (IEA). In her keynote remarks Monday morning she was quick to point out that it also encompasses electricity, sustainability, and energy's effects on the climate and vice versa. Still, the comment that got my wheels turning came from Dan Yergin, author and Vice Chairman of IHS. During his lunch keynote he suggested that without US tight oil production, this year's conference would have been dominated by another oil crisis.
Although shale energy development certainly deserves to be called revolutionary, crediting it with averting an oil crisis calls for a bit of "show me." Yet with problems in Libya, Nigeria and Iraq, while Iranian oil remains under sanctions and oil demand picks up again, even at first glance Mr. Yergin's assertion looks like more than a casual, lunch-speech sound-bite.
Start with current US tight oil (LTO) production of over 3 million barrels per day (MBD) and estimates of future LTO production rising to as much as 8 MBD--also the subject of much discussion at the conference. As recently as 2008 total US crude oil output had fallen to just 5 MBD and was only expected to recover to around 6 MBD by 2014, with minimal contribution from unconventional oil. Instead, the US is on track to beat 2013's 22-year record of 7.4 MBD, perhaps by as much as another million bbl/day.
With conventional production in Alaska and California declining or at best flat, and with Gulf of Mexico output just starting to recover from the post-Deepwater Horizon drilling moratorium and subsequent "permitorium", the net increase in US crude production attributable to LTO today is in the range of 2.5-3.5 MBD and growing, thanks to soaring output in North Dakota, Texas and other states.
That might not sound like much in a global oil market of over 90 MBD, but it brackets the IEA's latest estimate of OPEC's effective unused production capacity of 3.3 MBD. Spare capacity and changes in inventory are key measures of how much slack the oil market has at any time. When OPEC spare capacity fell below 2 MBD in 2007-8, oil prices rose sharply from around $70 per barrel to their all-time nominal high of $145 per barrel. It took a global recession and financial crisis to extinguish that price spike, and high oil prices were likely a major contributor to the recession.
Global oil inventories are now a little below their seasonal average for this time of the year. Compensating for the absence of over 3 MBD of US tight oil would require higher production elsewhere, lower demand, or a drain on those inventories that would by itself push prices steadily higher.
Concerning production, if the US tight oil boom hadn't happened, more investment might have flowed to other exploration and production opportunities. However, for non-LTO production to have grown by an extra 3 MBD, companies would have had to invest--starting in the middle of the last decade--in the projects necessary to deliver that oil now. Were that many deepwater and conventional onshore projects deferred or canceled because companies anticipated today's level of LTO production more than 5 years ago? And would Iraq, Libya and Nigeria be more reliable suppliers today if US companies hadn't been drilling thousands of wells in shale formations for the last several years? Both propositions seem doubtful.
As for adjustments in demand, US petroleum consumption is already over 8% less than in 2007. And as we learned in the run-up to 2008, much of the oil demand in the developing world, where it has grown fastest, is less sensitive to changes in oil prices than demand in developed countries, due to high levels of consumer petroleum subsidies in the former. Petroleum product prices in the latter must increase significantly in order to get consumers there to cut their usage by enough to balance tight global supplies. That dynamic played an important role in oil prices coming very close to $150 per barrel six years ago, when average retail unleaded regular in the US peaked at $4.11 per gallon, equivalent to nearly $4.50 per gallon today.
So to summarize, if the US tight oil boom hadn't happened, it's unlikely that other non-OPEC production would have increased by a similar amount in the meantime, or that OPEC would have the capability or inclination to make up the resulting shortfall versus current demand out of its spare capacity. Demand would have had to adjust lower, and that only happens when oil and product prices rise significantly. With oil already at $100 per barrel, it's not hard to imagine this scenario adding at least $40 to oil prices--just over half the 2007-8 spike.
Combined with higher net oil imports, that would have expanded this year's US trade deficit by around $230 billion. US gasoline prices today would average near $4.60 per gallon, instead of $3.64, taking an extra $130 billion a year out of consumers' pockets. For a reminder of how a similar situation was characterized just a few years ago, please Google "2008 oil crisis". If we found ourselves in those circumstances today, then the heated Congressional hearings and angry consumers to which Mr. Yergin alluded in his remarks Monday would indeed have been major topics at EIA's 2014 conference--rather than the prospect of US oil exports.
An article in last Tuesday's Wall St. Journal focused on the high rate at which excess natural gas from wells in North Dakota's Bakken shale formation is burned off, or "flared." The Journal cited a report of 10.3 billion cubic feet (BCF) of gas flared there during April 2014. That represented 30% of total gas production in the state for the month.
North Dakota's governor attributed the high volume of gas flared in his state to the incredible speed at which the Bakken shale has been developed, outpacing gas recovery efforts. Oil output ramped up from 200,000 barrels per day five years ago to just over a million today, in a place without the dense oil and gas infrastructure present in Texas and other states with a legacy of high production.
Nor is this situation unique to the Bakken. The World Bank has estimated that around 14 BCF of gas is flared every day, globally. Such flaring is a problem for more than states and other mineral-rights owners that worry about missing potential royalties. Aside from our natural aversion to waste, flaring natural gas has environmental consequences.
The tight oil produced from the Bakken shale is quite low in sulfur, and so is most of the associated gas, but some of it contains relatively high percentages of hydrogen sulfide (H2S). When that gas is flared, rather than processed, the resulting SOx emissions can affect local or even regional air quality.
Gas flaring also contributes to the greenhouse gas emissions implicated in global warming, although it must be noted that flaring is 28-84 times less climate-altering, pound for pound, than venting the same quantity of methane to the atmosphere. When annualized, and assuming complete combustion of the gas, North Dakota's recent level of flaring equates to around 6.7 million metric tons of CO2 emissions, or nearly a fifth of total US CO2 emissions from natural gas systems in 2012. That means this one source accounts for just over 0.1% of total US greenhouse gas emissions, or somewhat less than US ammonia production.
Why would anyone flare gas in the first place? As the Journal pointed out, the oil produced from Bakken wells is worth significantly more than the gas, although the energy-equivalent price ratio favors oil by more like 4:1 than the 20:1 cited. The economics of Bakken drilling are mainly driven by oil that can be sold at the lease and delivered by pipeline or rail, and not by the associated gas, particularly after tallying the cost of capturing and processing it, and then hoping capacity will be available to deliver it to a market that in the case of the Bakken might be hundreds or thousands of miles away. The characteristics of shale wells, with their steep decline curves, make this hurdle even higher. Shale gas infrastructure at the well must pay for itself quickly, before output tails off.
There is no shortage of technical options for putting this gas to use, instead of flaring it. A recent industry conference in Bismarck, ND featured an excellent presentation on this subject from the Energy & Environmental Research Center (EERC) of the University of North Dakota. Among the options listed by the presenter were onsite removal of gas liquids (NGLs), using gas to displace diesel fuel in drilling operations, and compressing it for use by local trucking or delivery to fleet fueling locations. However, contrary to the intuition of the rancher interviewed by the Journal, none of these options would reduce high-volume flaring by more than a fraction, despite investment costs in the tens or hundreds of thousands of dollars per site.
Even in the case of the most technically interesting option, small-scale gas-to-liquids conversion to produce synthetic diesel or high-quality synthetic crude, EERC estimated this would divert only 8% of the output from a multi-well site flaring 300 million cubic feet per day, while requiring an investment of $250 million. And to make this option yet more challenging to implement, of the 200-plus such locations EERC identified in the state, fewer than two dozen flared consistently at that level over a six-month period. The problem moves around as older wells tail off and new ones are drilled.
Significantly reducing or eliminating natural gas flaring ultimately requires a large-scale market for the hydrocarbons being burned off. That's as true in North Dakota as in Nigeria. While various technical options could incrementally reduce gas flaring from Bakken wells, the highest-impact solutions would be those that promote market creation. That would include fast-tracking long-distance gas pipeline projects or building gas-fired power plants nearby. Absent large new customers for Bakken gas, additional regulations on flaring will either be ineffective or stifle the region's strategically important oil output.
The blitzkrieg advance of Al Qaeda spinoff ISIS in northwestern Iraq has rattled global oil markets and politicians. So far, oil prices have risen by only a few dollars, reflecting the remoteness of the current threat from Iraq's main producing region and validating OPEC's recent characterization of the global oil market as "adequately supplied." Yet even if the rebel offensive stalls, the escalation of risk in Iraq and its neighbors could affect geopolitics, oil supplies and fuel prices for the rest of the decade.
Iraq currently exports around 2.7 million barrels per day (MBD) of oil, or 7% of global oil exports. It is effectively the number two producer in OPEC. Having recovered beyond pre-war levels, Iraq's oil industry is growing, while Iran's exports are constrained by international sanctions and Libya's output has become highly erratic following that country's revolution.
In the International Energy Agency's latest Medium-Term Oil Market Report Iraq accounts for 60% of OPEC's incremental production capacity through 2019 (see chart below) and nearly a fifth of all new barrels expected to come to market in that period. This is a more conservative view of Iraq's growth potential than in previous scenarios, but it still leaves Iraqi oil, together with " tight oil" in the US and elsewhere, as the bright spots of the IEA's supply forecast.
The Heard on the Street column in Wednesday's Wall St. Journal painted a stark picture of how the destabilization of Iraq could limit investment in the country's oil industry, truncating its expansion. That would increase longer-term oil price volatility and make investments elsewhere more attractive, not just in North American tight oil but also in energy efficiency and alternatives to oil.
Warning signs seem ample. The "Islamic State in Iraq and Syria" might never capture Baghdad or directly threaten the giant oil fields of southern Iraq that are reviving with help from international firms like BP, ExxonMobil and Shell. However, ISIS's actions in the territory they now control, and the fears they incite across a much larger swath of Iraq, are sparking renewed sectarian violence and prompting foreign companies to evacuate personnel. This undermines the IEA's medium-term forecast, which despite being "laden with downside risk" will apparently not be revised in light of recent events. It also raises the potential for jumps in nearer-term oil and petroleum product prices.
It is noteworthy that oil prices haven't already risen significantly, as they did when Libya's revolution began. From February 15 to April 15, 2011 the price of UK Brent Crude jumped 22%. So far, Iraq's troubles have added about 5% to the Brent price, while average US gasoline prices are just $0.06 per gallon ahead of their level for the same week last year. None of that justifies complacency, though.
The market's muted response could change abruptly if the Iraqi military suffered further setbacks at the hands of ISIS and its allies, or if ISIS turned its attention to the oil infrastructure of central and southern Iraq. They have already attacked the country's largest refinery at Baiji, north of Baghdad.
As several analysts have noted, anything that threatened the country's oil exports, most of which pass through the Gulf port of Basra, could send oil prices substantially higher. That's because many other supply outages have reduced usable spare production capacity elsewhere--oil that isn't now being produced but could ramp up quickly--to less than 4 MBD, a narrower margin than in several years. Even if lost Iraqi output were made up by Saudi Arabia and the UAE, the further contraction of spare capacity would drastically increase price volatility and boost oil prices from today's level, until Iraq's exports--or Iran's--were restored.
Nor would booming domestic oil and gas-liquids production, which is surely helping to hold down global oil prices, insulate US consumers from increases at the gas pump. The prices of the oil that US refineries process and the products they sell are still based on the global market. If Brent crude spikes, so will US gasoline and diesel. That would have less impact on the US economy than in the past, when imports made up a much higher share of supply, but shifting money from the pockets of consumers to those of oil company shareholders is rarely popular.
An Iraq-driven oil price spike would affect politics and geopolitics, too. An unstable Iraq makes it more difficult to maintain the sanctions pressure on Iran, particularly if the US and Iran ended up coordinating their responses in Iraq. It's even harder to envision a consensus on keeping more than 1 MBD of Iran's oil bottled up if oil prices returned to $150/bbl.
That could also complicate the debate over exporting US crude oil, already a tough sell for politicians who came up during the era of energy scarcity. As a practical matter, if exports began while prices were rising sharply for other reasons, convincing US voters that the two factors were unrelated would be challenging. A full-blown oil crisis in Iraq or the wider Middle East would likely result in the idea being tabled for an extended period.
It's tempting to view the success of ISIS in seizing territory on both sides of the Iraq/Syria border as a temporary outgrowth of Syria's civil war. If that were the case, the situation might revert to the status quo ante, once the Iraqi army--with some outside help--mopped up ISIS.
Even if this genie could be rebottled, however, the aftermath of the Iraq War and the "Arab Spring" revolutions is exerting great stresses on the post-World War I regional order, overlaid on 13 centuries of animosity between Sunnis and Shi'ites. An accident of history and geology has made this area home to much of the world's undeveloped conventional onshore oil reserves. Can its stability be restored with a few deft military and diplomatic moves, or might it require a complete rethinking of boundaries and nations, as suggested by the security columnist of the Washington Post?
Geoff Styles, Managing Director of GSW Strategy Group
On Monday the US Environmental Protection Agency announced its proposal for regulating the greenhouse gas emissions from the country's electric power sector, including all currently operating power plants. Unsurprisingly, initial assessments suggest it favors the renewable energy, energy efficiency and nuclear power industries--and especially natural gas--all at the expense of coal. However, the long-term outcome is subject to significant uncertainties, because of the way this policy is being implemented.
EPA's proposed "Clean Power Plan" regulation would reduce CO2 emissions from the US electric power sector by 25% by 2020 and 30% by 2030, compared to 2005. Although it does not specify that the annual reduction of over 700 million metric tons of CO2--half of which had already been achieved by 2012--must all come from coal-burning power plants, such plants accounted for 75% of 2012 emissions from power generation.
It's worth recalling how we got here. In the last decade the US Congress made several attempts to enact comprehensive climate legislation, based on an economy-wide cap on CO2 and a system of trading emissions allowances: "cap and trade." In 2009 the House of Representatives passed the Waxman-Markey bill, with its rather distorted version of cap and trade. It died in the US Senate, where the President's party briefly held a filibuster-proof supermajority.
The Clean Power Plan is the culmination of the administration's efforts to regulate the major CO2 sources in the US economy, in the absence of comprehensive legislation. Although Administrator McCarthy touted the flexibility of the plan in her enthusiastic rollout speech on Monday, and suggested that its implementation might include state or regional cap and trade markets for emissions, the net result will look very different than an economy-wide approach.
For starters, there won't be a cap on overall emissions, but rather a set of state-level performance targets for emissions per megawatt-hour generated in 2020 and 2030. If electricity demand grew 29% by 2040, as recently forecast by the Energy Information Administration of the US Department of Energy, the CO2 savings in the EPA plan might be largely negated. EPA is banking on the widespread adoption of energy efficiency measures to avoid such an outcome.
Since we have many technologies for generating electricity, with varying emissions all the way down to nearly zero, many different future generating mixes could achieve the plan's goals, though not at equal cost or reliability. Ironically, since coal's share of power generation has declined from 50% in 2005 to 39% as of last year, it could be done by replacing all the older coal-fired power plants in the US with state of the art plants using either ultra-supercritical pulverized coal combustion (USC ) or integrated gasification combined cycle (IGCC).
That won't happen for a variety of reasons, not least of which is EPA's "New Source Performance Standards" published last November. That rule effectively requires new coal-fired power plants to emit around a third less CO2 than today's most efficient USC's. That's only possibly if they capture and sequester (CCS) at least some of their emissions, a feature found in only a couple of power plants now under construction globally.
It's also questionable how the capital required to upgrade the entire US coal generating fleet could be raised. Returns on such facilities have fallen, due to competition from shale gas and from renewables like wind power with very low marginal costs--sometimes negative after factoring in tax credits. Some are interpreting EPA's aggressive CO2 target for 2020 and relatively milder 2030 step as an indication that the latter target could be made much more stringent, later.
So while coal is likely to remain an important part of the US power mix in 2030, as the EPA's administrator noted, meeting these goals in the real world will likely entail a significant shift from coal to gas and renewable energy sources, while preserving roughly the current nuclear generating fleet, including those units now under construction.
If the entire burden of the shift fell to gas, it would entail increasing the utilization of existing natural gas combined cycle power plants (NGCC) and likely building new units in some states. In the documentation of its draft rules, EPA cited average 2012 NGCC utilization of 46%. Increasing utilization up to 75% would deliver over 600 million additional MWh from gas annually--a 56% increase over total 2013 gas-fired generation, exceeding the output of all US renewables last year--at an emissions reduction of around 340 million metric tons vs. coal. That would be just sufficient to meet the 30% emissions reduction target for the electricity demand and generating mix we had in 2013.
The incremental natural gas required to produce this extra power works out to about 4.4 trillion cubic feet (TCF) per year. That would increase gas consumption in the power sector by just over half, compared to 2013, and boost total US gas demand by 17%. To put that in perspective, US dry natural gas production has grown by 4.1 TCF/y since 2008.
EPA apparently anticipates power sector gas consumption increasing by just 1.2 TCF/y by 2020, and falling thereafter as end-use efficiency improves. Fuel-switching is only one of the four Best System of Emission Reduction "building blocks" EPA envisions states using, including efficiency improvements at existing power plants, increased penetration of renewable generation, and demand-side efficiency measures. The ultimate mix will vary by state and be influenced by changes in gas, coal and power prices.
I mentioned uncertainties at the beginning of this post. Aside from the inevitable legal challenges to EPA's regulation of power plant CO2 under the 1990 Clean Air Act, its imposition by executive authority, rather than legislation, leaves future administrations free to strengthen, weaken, or even abandon this approach.
Since EPA's planned emission reductions from the power sector are large on a national scale (10% of total US 2005 emissions) but still small on a global scale (2% of 2013 emissions) their long-term political sustainability may depend on the extent to which they encourage the large developing countries to follow suit in reducing their growing emissions.
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
PEDEVCO Corp., d/b/a Pacific Energy Development (NYSE MKT: PED) is a publicly-traded energy company engaged in the acquisition and development of strategic, high growth energy projects, including shale oil and gas assets, in the United States. The Company's principal asset, the D-J Basin Asset, is located in Weld and Morgan Counties in Colorado.
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