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.
From left to right (First left) Zhakyp Bokenbayev - Chairman of the Board, Ministry of Industry and New Technologies, JSC Institute of Energy and Energy Efficiency, Chairman of the Board (third left) Greg Rozenfeld, PED Chief Development & Operations Advisor (fourth left) Yakhiya Chudrov - Chairman of the Board, JSC Western Kazakhstan Electric Grid Company (middle) Sean Fitzerald - VP Business Development (6th) Michael Rozenfeld - VP Geoscience (7th) Nabi Aitzhanov - President, JSC “Utilities of Kazakhstan” First Front Row (First left) Mariyash Zhakupova (first in the small front row) - Advisor to the Chairman of the Board, Ministry of Industry and New Technologies, JSC Institute of Energy and Energy Efficiency. (9) PED accounting/finance team.
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?
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.
$400 billion deals aren't announced every week--even by heads of state--although the new natural gas supply agreement between Russia and China has been in the works for some time. However, the crucial element of price apparently wasn't agreed until a negotiating session that lasted until 4:00 AM, Shanghai time. "Our Chinese friends are difficult, hard negotiators," said President Putin. They certainly waited for the right moment, with Russia pressed by sanctions in the aftermath of its annexation of Crimea.
The numbers cited in the media are all impressive: After investing more than $50 billion in gas field and pipeline development in Eastern Siberia, Russia will sell 38 billion cubic meters (BCM) of gas per year to China for 30 years, and China will reportedly invest $20 billion for gas infrastructure and market development within its borders. Deliveries are set to start in 2018 and could eventually ramp up to 60 BCM/yr.
To put that in perspective, 38 BCM/yr equates to 3.7 billion cubic feet (BCF) per day. That's on par with the entire natural gas production of the Eagle Ford shale formation in south Texas, or the federal waters of the Gulf of Mexico. Of greater relevance is that it's also nearly twice the output of Australia's Gorgon LNG project, which is expected to begin production in 2015. So from the perspective of the regional gas market and alternative supplies, this is a very significant quantity of gas, especially with a number of new Australian LNG projects under development or consideration.
As of 2012 China's gas market was already the largest in Asia, ahead of Japan, based on BP's annual Statistical Review of World Energy. This deal represents 27% of China's current gas demand. It's tempting to conclude that squeezing Russian gas into China must come at the expense of other potential suppliers. If China's gas market were mature, such a zero-sum view could not be ignored, particularly by marginal LNG projects in Australia, Indonesia and the US that have not yet begun construction.
Competition with Russian gas could also impede development funding and access to infrastructure for China's nascent shale gas industry. The US Energy Information Administration's 2013 global survey of technically recoverable shale resources found that China could have over a quadrillion cubic feet--1,115 TCF--of shale gas in the ground, or nearly twice as much as the US. Yet China's progress in tapping this resource has been slow, and hardly a week goes by without another article explaining why it will be difficult if not impossible for others to replicate the US shale gas boom any time soon.
The demand side will shape the competitive environment. In 2012 natural gas accounted for less than 5% of China's total primary energy consumption, compared to 13% for Taiwan, 17% for South Korea and 22% for Japan, none of which are significant gas producers. From 2007-12 China's gas market grew at a compound average rate of 15% per year. In its main "New Policies" scenario, the latest World Energy Outlook from the International Energy Agency (IEA) anticipates the country's gas demand tripling by 2025 and quadrupling by 2035, eventually reaching 11% of energy consumption. Achieving that would require the equivalent of ten gas deals the size of the current one.
That outcome isn't a certainty, for many reasons. Even if all that gas turned up at the right time--a massive logistical and capital investment challenge--the market must be ready, too. The price implied in the media coverage of the Russia/China deal is around $350 per 1000 cubic meters ($10 per million BTUs) or more than double the current US wellhead price. That's a lot cheaper than most of the LNG delivered to Asia, but it won't outcompete Chinese coal on economics alone, and it won't jump-start new, gas-reliant industries the way the US shale gas revolution is beginning to do.
The scale of market development implicit in the IEA's gas forecast for China would require a substantial expansion of gas-fired power generation, which in any case is the logical complement to China's aggressive expansion of wind and solar power installations. It may also entail a significant shift from solid and liquid heating and cooking fuels to gas, where at least in the case of liquids, $10 gas would have the edge over products derived from $100 oil. It might even encompass gas-based distributed power generation using fuel cells, which is still in its infancy in the US. Such developments will benefit all potential suppliers, not just Russia.
It's also worth considering what this deal means for Russia. While a number of reports have suggested it provides a counterweight to Russia's dependence on the European gas market, that's really only true in a financial sense. The deal represents a major growth opportunity for Gazprom, Russia's majority-state-owned natural gas company, but this isn't the same gas that now supplies the EU. It will mainly be production from new gas fields. The potential upside for Russia may depend on its ability to leverage the infrastructure built for this deal into a larger gas network for supplying growth throughout Asia--in competition with others, including US LNG projects eyeing that market.
"Milestone" is an over-used term, but it fits this deal. If the parties can iron out all the remaining details and proceed to construction and ultimately delivery, it could prove to be a key step in giving gas a much bigger role in fueling Asia's growth. That would have important environmental benefits, too, in both mitigating the air pollution in Asia's major cities and bending the curve of the region's greenhouse gas emissions.
On Monday the International Energy Agency released its latest Energy Technology Perspectives (ETP), a technology roadmap extending out to mid-century, with a major focus on the increasing electrification of global energy, against a backdrop of climate change. It sheds further light on the assumptions and outcomes of the scenarios included in the IEA's most recent World Energy Outlook, which I examined in a post here last December.
This is turning out to a big season for climate-change-related reports, with the ETP arriving just a week after the US National Climate Assessment, which followed the latest volume of the IPCC's Fifth Assessment Report on climate change. The ETP has already caught the attention of renewables-oriented news sites for its characterization of natural gas as, "a transitional fuel, not a low-carbon solution unless coupled with carbon capture and storage (CCS)."
That might seem to contradict the general tone of IEA's earlier "Golden Age of Gas" scenario, though when that study was released in 2011 it, too, included caveats about the limitations of gas in reducing greenhouse gas emissions. From that standpoint, the new ETP is no more negative about gas than the relatively rosy (for gas) Golden Age scenario was, and in fact sees gas supporting both "increasing integration of renewables and displacing coal-fired generation."
The IEA's press release for the ETP highlighted the growth of electricity as a major energy carrier, particularly in the developing world, increasing from 17% of final global energy consumption in 2011 to 23-26% by 2050. However, it also noted, "While this offers many opportunities, it does not solve all our problems; indeed it creates many new challenges." Among other things, that alludes to the fact that while renewables such as wind and solar power have been growing rapidly, so has coal use, with the result that, as the ETP launch presentation put it, "the carbon intensity of (energy) supply is stuck."
The emissions benefits of electricity displacing oil from transportation and other fossil fuels from industrial, commercial and residential uses will be largely negated if power generation does not also shift towards lower-emitting sources such as nuclear, hydropower, geothermal, wind and solar power. The "2DS" scenario that received far more attention in the IEA's rollout than the ETP's other two scenarios, provides the prescription and justification for that transition. However, it's important to realize that the 2DS case is not a forecast or prediction; it's what scenario experts might call a "normative scenario"--one that the authors hope to encourage, rather than expect to occur.
2DS reflects the official stance of most member countries of the IEA and links to the low-emission "450" scenario in the agency's current World Energy Outlook. Both are predicated on creating a 50% chance of limiting the average global temperature increase due to climate change to 2°C (3.6°F), compared to pre-industrial conditions. That is generally thought to require keeping the atmospheric CO2 concentration below 450 ppm (0.045%). In Monday's presentation, as in other recent reports, the IEA has sounded the alarm that this goal may be slipping out of our grasp. This April's CO2 reading exceeded 400 ppm for the first time since measurements began, and is growing at around 2 ppm per year.
The IEA makes a good case that the rapid energy transition described in their 2DS scenario is feasible and economically beneficial, despite its $44 trillion price tag, providing substantial future savings in fuel costs, or more modest ones on the discounted cash flow basis on which most investments are premised. However, they are equally candid that reaching this goal will require significantly greater commitments and actions than countries have already made--or than I would assess to be politically feasible in the current global environment.
Renewables may be on-track, but many other aspects of the low-carbon transition aren't. That's especially true for new nuclear power, post-Fukushima, and CCS, on which 2DS counts for 7% and 14%, respectively, of emissions reductions through 2050.
It's worth recalling that the main scenario in the IEA's World Energy Outlook of last November was not "450", but rather the less-restrictive "New Policies" scenario, which appears to correspond to the middle "4DS" technology scenario of the ETP. (The WEO also includes a status quo "Current Policies" scenario.) In that context we must not let the appealing outcomes envisioned in 2DS obscure the emissions-reducing benefits of natural gas in the world we are still likelier to inhabit, based on current trends, than the one we might desire.
Only under the rapid replacement of fossil fuels by renewables and nuclear power and CO2 sequestration assumed in the 2DS/ "450" scenarios would it be true that, "After 2025...emissions from gas-fired plants are higher than the average carbon intensity of the global electricity mix; natural gas loses its status as a low-carbon fuel." Presumably in the ETP's other two scenarios, that crossover would not happen until much later, if at all.
Gas is thus still a crucial bridge to a lower-carbon world, and it will not lose that status until we have made much more progress in reducing energy-related emissions than seems likely in the near future. While I certainly wouldn't bet against the continued growth of renewable energy, the slow progress of the other elements of decarbonization leaves an important and valuable role for gas to help fuel the beneficial electrification of energy that the IEA has highlighted, for multiple decades.
Frank C. Ingriselli, President and CEO of PEDEVCO Corp. (Pacific Energy Development), was recently interviewed by Energy Pipeline magazine, a publication of the Greeley Colorado Tribune. Click here to read the article.
Exporting gasoline from the US to other countries remains controversial, due to suspicions that it results in higher prices at the pump, here. A recent story in the Wall Street Journal seemed to fuel that concern, starting with its title, "Price of Gas in U.S. Rises as Refiners Export More to Other Countries." Their selection of conjunctions matters, however, and it was just as well the Journal chose the circumstantial "as", rather than a causal "because", since the case against exports doesn't hold up very well.
Many factors affect wholesale gasoline prices, starting with the price of crude oil--the main feedstock for producing gasoline--while retail prices reflect these issues along with changes in tax rates. Crude has been relatively static over the last year, at least internationally. Refinery production levels and domestic consumption also play a major role, while the price of ethanol and the regulatory mechanisms of the federal Renewable Fuel Standard are becoming increasingly important, too. Inventories are another key factor, and the story's author cited their current low level as evidence of the influence of exports.
Given all these moving parts, I can see the appeal of assuming that more exports leave less product for sale in the US, and that prices here must rise as a result. The biggest problem with this conclusion is that the only indication of such a trend in a comparison US gasoline export volumes and average retail prices for unleaded regular gasoline (see graph below) is attributable to the drop in global oil prices during and following the financial crisis.
In fact, when we remove oil prices from the picture by graphing the difference between average US unleaded regular and Brent Crude prices against exports, the parallel trends in the middle years of the chart disappear and something very different emerges.
The margin between US gasoline prices and crude oil does not seem to increase with exports. If anything, an inverse relationship is apparent: exports are highest when US gas prices are lowest, relative to crude oil, and vice versa. So instead of reinforcing gasoline price spikes, as someone reading the Journal article might infer, exports may provide a safety valve of sorts, giving refiners an effective floor price when demand is low, while preserving capacity for use domestically when US demand increases.
That makes sense if you consider the mechanism behind exports. US gasoline exports have been a feature of the global market for decades, as I know from my experience trading petroleum products in the 1980s and '90s. Product leaves the US when the price elsewhere is higher than the local price by enough to cover the cost of shipping, plus a profit margin. When domestic prices go up, the output of US refineries is likelier to supply local markets, rather than foreign ones.
We see other evidence of this from the fact that most US gasoline exports originate from the Gulf Coast region, which generally has some of the lowest gasoline prices in the country. Little gas leaves the East Coast, the supply for which includes significant imports, or the West Coast, with its routinely high prices.
So why are US gasoline prices, which until recently were below last year's same-month levels, rising now? The "A" answer from a study of past trends would be seasonal factors, and that's precisely where the latest analysis of the US Energy Information Administration points. It highlights the annual return of "driving season", refinery maintenance schedules, and the requirement for refiners to switch to summer gasoline formulations.
A skeptic might argue that even if exports aren't contributing to peak gasoline pricing, they must be raising average prices over the course of the year by elevating seasonal lows. That might be true in the short run, but in the longer term refining capacity that lacked a profitable outlet would not be utilized, and would eventually be shut down. Instead, with exports ensuring year-round outlets, US refining capacity is growing.
US exports of gasoline and other petroleum products are certainly helping to reduce the US trade deficit and sustain good jobs in a US refining sector that has become much more attuned to global opportunities. And based on the foregoing analysis, they don't seem to be harming US consumers in the process. That may sound counter-intuitive, but it's consistent with the benefits of trade in other parts of economy.
Michael Rozenfeld - V.P. of Geosciences, STXRA
US natural gas prices have recovered recently thanks to a 5 year seasonal low in underground storage brought on by a cold winter and decreased natural gas drilling. With so many companies out of the gas drilling business, there has been hope that prices would exceed $6/MCF bringing back the profitable days of the original shale gas plays such as the Barnett. Unfortunately, that has not been the case to date. The natural gas drilling business has been fundamentally changed (at least in the near term) due to two primary reasons.
The first one is the discovery of liquids rich gas plays such as the Eagle Ford whose economics are driven by natural gas liquids (derived from processing high BTU natural gas) and oil. The gas that comes off of these plays is essentially a residual cash stream which does not drive the economics of the wells. This results in natural gas being produced that is not dependent on current pricing.
Additionally, Marcellus gas is located next to gas using major cities resulting in shorter distances to market. How big is the Marcellus shale? The USGS has estimated over 84 TCF of natural gas resources in the Marcellus making it the largest gas play in the entire country! Currently, the Marcellus is only produced in its southern and central areas with New York banning fracing and thereby shale production. There is a light at the en d of the tunnel for natural gas pricing though as LNG terminals in the United States come online and coal power plants are converted to a cleaner better fuel. Also, thanks to the guidance of energy greats, such as Boone Pickens, many companies are now considering fueling vehicles with natural gas.
So what is the future of natural gas? Countries in Europe & Asia desperately need US gas as they are dependent on hostile nations to fuel their energy needs at high prices (up to 3 times current prices in the US) which will guarantee demand. America hopefully in the future will not become as short sighted as Europe (and learn from their experience) and continue to try to ban fracing as the recent Ukraine and Russia situation shows what happens when you aren’t in control of your own energy supply. Of course, if the US decides to continue on it path of trying to ban fracing, natural gas prices will go up rapidly to the detriment of us all. If it doesn’t, shales such as the Marcellus will keep us comfortably supplied with affordable energy for decades to come.