Energy Realpolitik

This is a guest post by Tessa Schreiber, intern for Energy and U.S. Foreign Policy at the Council on Foreign Relations and student at Rice University.  The state of Texas is known for its deference to two seemingly contradictory assets: Its land and its oil. While the tradition of working and preserving the land remains a historic point of state pride, the last decade’s surge in oil and gas development has dominated the landscape and conflicted with environmental considerations such as water quality and scarcity and habitat conservation. The trade-offs between Texas’s rising oil and gas production and conservation and agriculture have grown increasingly pronounced over the past several years, building pressure for policy intervention. Yet regulators’ responses to the environmental effects of fossil fuel production have been perfunctory at best, largely due to oil and gas’s massive role in the state economy. In 2019, oil and gas tax revenues contributed nearly $6 billion to the Texas state budget, while the Texas Oil and Gas Association reported a cumulative $16 billion industry payout in taxes and royalties. Oil and gas production taxes are even more imperative to the state’s economic stabilization “rainy day fund,” supplying 85 percent of its value since its creation in 1988. Many lawmakers agree the fund will be instrumental in smoothing the economic ramifications of COVID-19. Against this backdrop, policymakers are wary of taking regulatory action against oil and gas corporations. But pressure has built from other important voices, including the investors and banks that finance oil and gas activity. The net result of these forces is an emerging trend towards voluntary environmental action by the private sector. If early-stage voluntary projects prove successful, they could lay a constructive groundwork for future market-based policy options and better regulation, creating productive synergies between land, oil, and Texas’s future economy.    For years, environmental groups have criticized the Texas Railroad Commission (RRC)—which regulates oil and gas—for its regulatory inaction. As natural gas flaring in the Permian Basin has risen to unprecedented levels over the past two years, new revelations have increased public pressure to make flaring a consistent item on the RRC agenda, as well as at shareholder meetings for several large Permian producers. The Permian Methane Analysis Project (PermianMAP) found that flaring efficiency rates were 5 percent lower than those assumed by the U.S. Environmental Protection Agency (EPA). In other words, Permian flaring operations have emitted three times more methane than previously assumed. Though methane remains in the atmosphere for a much shorter duration than carbon dioxide, it is eighty-four times more potent, magnifying its importance to time-sensitive climate change mitigation efforts. In addition to its environmental consequences, flaring is wasteful in commercial and economic terms because flared gas loses its potential value as a revenue source and royalty generator. Instead of producing electricity or heating homes, flared gas lacks any redeeming value to justify its pollution, which prolifically contributes to upstream carbon dioxide emission totals.   Leading Permian operators have publicly recognized that high flaring rates are problematic and some have called for preventative action against routine natural gas flaring and methane leakage. In 2019, a group of major oil and gas companies publicly voiced their opposition to the EPA’s proposed rollback of a rule enacted by the Obama administration that required the installation of methane leak detection and mitigation technology at newly built oil and gas facilities across the United States. Both the Collaboration to Advance Methane Science and the Oil and Gas Climate Initiative, two industry climate change-related associations, have advanced voluntary reductions on methane and carbon emissions by their members. The formation of these groups comes amidst recent announcements of new carbon emission reduction goals by individual companies.   The U.S. oil industry’s increased focus on voluntarily controlling emissions from its operations follows a well-established, widespread trend among American corporations to set forth more tangible, aggressive carbon emission reduction targets, even absent state and federal regulations mandating that they do so. This year, several major Fortune 500 companies pledged to be carbon neutral or carbon negative in the next two decades, including tech giants Amazon and Microsoft. In exchange for continued support, investors now seek similar pledges from major oil companies. Already, oil and gas stocks’ share of the S&P 500 has fallen from over 15 percent a decade ago to under 5 percent today. BlackRock, the world’s largest fund manager with significant holdings in oil majors such as BP, Shell, and Exxon Mobil, announced recently that it would begin to exit investments with high-sustainability related risks and screen fossil fuel investments more stringently. Investor efforts like these are contributing to a rising urgency in the C-suites of oil and gas companies to prove their commitments to reducing the carbon intensity of future sales and operations, lest they lose access to capital or their social license to operate.   But voluntary corporate efforts could be hindered by the operational realities of a yet-underdeveloped American carbon reduction environment. Currently, most technological solutions for removing carbon from the atmosphere cost upwards of several hundred dollars per metric ton, making such investments a tough sell. Still, large producers such as Chevron and Occidental Petroleum have invested in Carbon Engineering, a Canadian venture marketing technology that functionally vacuums carbon dioxide out of the atmosphere through a process called direct air capture. In 2019, the U.S. Congress passed a federal tax credit for another carbon technology, underground geologic carbon storage, or CCS (carbon capture and storage). However, CCS is often opposed by environmental groups who argue that captured carbon is too often used in enhanced oil recovery (EOR) before it is sequestered, leading to increased oil production, which they see as counterproductive.   While direct air capture and geologic carbon storage currently face economic barriers, natural, photosynthetic carbon removal and storage strategies such as reforestation and soil sequestration are starting to gain more interest as a cost-effective, quickly-deployable option. Plants naturally absorb carbon dioxide and store it below the ground in their soil and root systems. Scientists generally agree natural carbon sequestration has strong potential to address greenhouse gas emissions. Because this storage process naturally occurs and requires little—if any—technical intervention, it could cost as little as ten dollars per metric ton of carbon. Natural sequestration has great potential in places like Texas with large swaths of open forest and grassland. Landowners could capitalize on responsible land management practices that keep carbon underground by selling their carbon storage capacity to organizations—such as oil and gas companies—interested in reducing their carbon footprint.   The development of a robust soil carbon storage market in the United States has been inhibited by cumbersome requirements in existing protocols for land-based carbon sequestration. Existing standards are derived primarily from the Kyoto Protocol’s Clean Development Mechanism (CDM), which places multi-decade usage restrictions on landowners who choose to store carbon in their soil. Such restrictions are vital to guaranteeing that carbon will remain undisturbed underground, yet disincentivize landowner participation because they lock in the management decisions of one generation for potentially several to come and can make selling difficult for similar reasons.  To address this problem, the Houston-based Baker Institute for Public Policy’s Center for Energy Studies convened a working group in 2019 to design a new, landowner-friendly soil carbon storage protocol to expedite the creation of a functional carbon market in the United States. The group includes representatives from corporations, regulatory agencies, non-profits, and landowner associations, and hopes to develop market principles that provide both stability for buyers and autonomy for sellers. By the end of its deliberations, the group intends to create a voluntary, land-based carbon program with a credible measurement and verification system for soil carbon storage.   Plans like the Baker Institute’s proposed voluntary program could be bolstered by federal action. Until recently, the federal government had yet to take proactive steps to make voluntary, market-oriented carbon policies mainstream. Earlier this month, a bipartisan group of United States senators introduced the Growing Climate Solutions Act, which would direct the U.S. Department of Agriculture (USDA) to aggregate information about existing carbon protocols and assist landowners with navigating the complex soil sequestration verification process. The bill proposes a USDA certification for third-party consultants familiar with the technical and regulatory nuances of carbon offset markets. If the bill were to pass, it would bring much-needed attention to the immense potential for natural carbon storage in the United States. However, emissions credit offset programs are not without critics. Some political leaders and activists argue that carbon removal schemes that revolve around offsets enable polluters to continue operations, which, they note, often disproportionately harm fenceline communities who have suffered for decades due to their proximity to industrial facilities. These concerns appear in the platform recommendations recently released by the progressive Democratic National Committee Council on the Environment and Climate Crisis, which called for a rejection of carbon offsets in its recommendations for the 2020 Democratic Platform.   The need for broadly-acceptable carbon action has only become more pressing in light of the COVID-19 pandemic. As companies, particularly in the severely depressed oil and gas sector, attempt to restore cash flows and maintain access to capital markets, proving their commitment to viability in a low-carbon future and environmental, social, and governance (ESG) factors is vital. The unexpected and severe collapse in oil prices following the COVID-19 lockdowns this spring was a reminder of the unpredictable consequences of natural disasters and other black swan events on the oil and gas industry. Corporations will be increasingly expected to prove that they can withstand high-impact risk events, particularly those related to climate change. Taking proactive steps to account for their emissions is a step in the right direction.   For oil and gas corporations in Texas, the current circumstances create a window of opportunity. This spring, the RRC came the closest it has in decades to prorating Texas oil production. Though the Commission ultimately eschewed production quotas, the very fact they considered them could mark a small but significant shift. Only time will tell if stricter regulation will follow, but in the interim, the industry should become a leading advocate for market-based solutions that attach real economic incentives to climate action. Soil carbon storage could be an opportune first issue to address, given Texas’s history of land stewardship. A successful soil carbon storage program in Texas would provide landowners with new cash flow, conservationists with a victory in leaving large swaths of land largely undisturbed, and corporations with the accomplishment of driving constructive changes of their own volition. Texas could become a national example of how unconventional partnerships can achieve progress on climate action, bypassing partisan gridlock at the federal level. The global energy mix is diversifying, and business-as-usual alone will not sustain oil-reliant Texas as an energy hub. However, taking a proactive step on innovative forms of climate change mitigation could.   As interest grows among oil and gas companies to voluntarily reduce their environmental footprints, stock should be taken of the existing opportunities to do so. Corporations stand to benefit immensely from embracing efforts like soil sequestration—instead of waiting for regulation to force their hands. Such action would help participating companies gain a competitive advantage over their peers and drive more transformative actions over time. With a growing number of Americans favoring climate-change mitigation policies on both sides of the aisle, oil and gas companies should take this opportunity, increase their voluntary action, and make their stances unequivocal.  

Prior to the COVID-19 pandemic, India was moving to the forefront of the global energy transition, with plans to reach 175-gigawatt (GW) of renewable energy by 2022. Prime Minister Modi’s decisive electoral win in May 2019 seemed to have secured continuation of India’s ambitious solar energy goals, but now the COVID-19 outbreak of early 2020 is slowing and delaying new solar energy construction on top of other challenges the sector faced. The fate of India’s push to clean energy has global implications, since India is a major economy and lowering its carbon emissions is important to global efforts to address climate change.

This is a guest post by Hunter Kornfeind, intern for Energy and Climate Policy at the Council on Foreign Relations and current student at Temple University. Russia is coping with a new reality from the lasting effects from the brief crude oil price war with Saudi Arabia this past spring and the ongoing COVID-19 pandemic that has left Russia’s domestic energy industry in its most difficult position since the breakup of the Soviet Union. Delivering an unprecedented production cut – around 2.5 million barrels per day (b/d) in May and June according to the terms of the recent agreement between the Organization of the Petroleum Exporting Countries (OPEC) and other major oil producers – in an accelerated manner left Russian oil companies with the difficult decision to select what wells to keep going and what wells to idle. Depending on how long oil production reductions are needed, cutbacks in specific Russian regions could potentially lead to some permanent shut-ins due to operational challenges across an industry with little storage capacity and natural geological constraints in a large number of maturing fields. Production curtailments could also affect the quality of Russia’s main crude oil Urals export blend, which is a mix of oils coming from different production streams. Variability of quality can alter the desirability of a crude oil in the export market, thereby influencing its value to refiners. These challenges are exacerbated by the fact that Russia’s oil trade faces strong competition from Middle East exporters in its key markets in Asia and Europe amid flagging demand caused by economic slowdowns. A deterioration in domestic consumption also poses headwinds, so much so the Kremlin recently banned certain oil product imports to protect the Russian market from a wave of cheap fuel.  Russia is fully committed to the historic 9.7 million b/d production cut agreed by the OPEC+ producer coalition of which it is a member. The Kremlin reaffirmed that commitment in announcing publicly today that there was “close coordination” between Saudi Arabia and Russia on oil output restrictions. The Kremlin is hoping its constructive role in fostering the final agreement to stabilize global oil markets could create a diplomatic opening to improve relations with the United States, which took an unprecedented public diplomatic role in pressuring the parties for the oil agreement, ultimately fostering cooperation between top Russian and Saudi leaders. Russian Energy Minister Alexander Novak recently met with major Russian oil companies to discuss a possible extension of the current level of production cuts past June. Much will depend on market conditions in Europe, where demand is beginning to recover. A longer period of curtailments could pose operational or geological difficulties for some Russian producers, including Russian flagship oil and gas firm Rosneft PJSC. Russia has been angling to get some U.S. sanctions eased, especially those applied to Rosneft PJSC, which is no longer trading Venezuelan oil. The technical challenges in Russia’s oil sector could give impetus to Moscow to want to gain access to capital markets for its oil sector as well as U.S. technology and industry assistance. It is unclear where diplomatic progress can be made in the complex U.S.-Russia bilateral relationship that ranges from concerns about future nuclear proliferation agreements to the difficulty of reaching a diplomatic solution to the humanitarian crisis in Venezuela as well as Russia’s continued military presence in the Ukraine, among other active hotspots. This week, the United States chided Russia for its alleged role in escalating conflict in Libya, in an indication that tensions remain on a wide range of issues.   Still, other geopolitical conflicts aside, Russia has a point in noting the significance of its contribution to global oil market stability. The 10 percent year-over-year decline in Russia crude oil production, described in April by Russian Energy Minister Novak, would make 2020 the first year of a double-digit decline in crude oil production since the early years of the Boris Yeltsin presidency. Following the collapse of the Soviet Union in 1991, Russian crude oil production reached a low of about 6.0 million b/d in 1996 according to the BP Statistical Review of World Energy, declining from about a record 11.4 million b/d in 1987. The state suffered from sharp declines in oil production from 1991 to 1994 when the Russian oil sector was under reorganization and little to no capital investment was made in new wells. Only after more than two decades of strong oil company investment, equating to hundreds of billions of dollars, has Russia able to restore its crude oil production capacity to return to its Soviet-era highs.  Russia currently has about 200,000 active wells, more than most other crude oil-producing states. Compared to Saudi Arabia’s lower per barrel cost of production, Russia’s hydrodynamic methods – including horizontal drilling, sidetracking, and hydraulic fracturing – are capital and labor intensive, especially with the country’s older wells. Reactivating a well that is throttled back can be challenging. For some wells, the longer a reservoir remains idled, the higher the chance pressure, water content, and clogging could affect future production. Experts say curtailment decisions will ultimately hinge on the characteristics and geological constraints within production regions. Companies have to assess where it makes the most technical and economic sense to make the cuts, either in brownfields – fields that have matured to a production plateau or even progressed to a stage of declining production – or in greenfields – a new oil and gas field development – throughout Russia. Increases in COVID-19 cases at Russian crude oil assets could also lead to production difficulties in select regions due to quarantines.  West Siberia, an oil producing region in central Russia that extends from the northern border of Kazakhstan to the Arctic Ocean, continues to be Russia’s dominant producing region and contributes more than half of Russia’s total crude oil production. Most fields operating in the region are older, conventional reserves. They are facing permafrost melting and rising associated water levels, which reached 86 percent on average in 2018. According to a study from the SKOLKOVO Energy Centre, Russia’s largest active Siberian brownfields reported a 22 percent increase in drilling rate penetration from 2012 to 2016 but recorded a 5 percent decrease in total crude oil production, demonstrating how Russia’s older fields require more intensive methods to keep production growing. Yuganskneftegaz, Rosneft PJSC’s largest unit with operations in West Siberia, cut crude oil production by about 289,000 b/d between May 1 and 11 from February levels, according to Bloomberg News. Lukoil PJSC, the second-biggest Russian operator, decreased output by about 312,000 b/d compared to February with almost half of the production cuts originating from fields in West Siberia.   Before the OPEC+ cuts, Russian companies were actively exploring greenfield development in remote onshore regions like East Siberia and the Russian Far East, attempting to offset declining production elsewhere in Russia. The shift had been successful – greenfields continue to yield higher production growth compared to legacy brownfields. According to analysis from the SKOLKOVO Energy Centre, Russian greenfield crude oil production grew 77 percent from 2012 to 2016, reaching 21 percent (roughly 2.3 million b/d) of total crude oil production.It remains unclear whether the current oil price environment will hamper continued greenfield investment and production in Russia. So far, Russian oil companies have not abandoned their large-scale investments, instead deferring them in hope of a rebound in global oil prices and eventual relief from the OPEC+ production limitations. State-owned giant Rosneft PJSC announced plans to continue the development of new fields but is "postponing short-term less economically viable projects" and “…high risk long-term projects, including joint ventures.” Russia could have difficulties staying the course, however, given the departure of some Western majors, who continue to slash capital expenditures. Royal Dutch Shell recently withdrew from its proposed onshore joint venture with Gazprom Neft in the Arctic, citing a “challenging external environment.” The current low oil price environment may discourage future Western investment in Russia’s upstream, which also continues to face complications from Western sanctions.   In addition to cash flow consequences and possible damage to oil fields or equipment, Russia’s continued oil production cutbacks could create a marketing headache for Russian firms. Russia’s most popular crude oil blend for export, Urals, is a mix of different grades of crude oil from different regions in West Siberia. As production cuts occur, the mix of crude streams going into Russia’s export pipelines can change, shifting the quality of the export blend and thereby its value to refiners.   Already, amid slumping petroleum demand due to COVID-19 pandemic lockdowns, Russia faces lower demand for its crude oil exports. Rystad Energy estimates crude oil demand in Europe declined 38 percent year-over-year in April and expects demand to slump 13 percent year-over-year for 2020. Chinese demand is slowly recovering following the easing of stringent lockdown measures, helping Russian export sales.   Russia sells roughly three-quarters of its total crude oil exports to just two markets Europe and Northeast Asia, much of it by pipeline delivery. In China, Russia has gained market share since the COVID-19 crisis began, replacing curtailed oil from Iran and Venezuela which recently reached all-time lows. China imported about 1.7 million b/d of crude oil from Russia in April, about a 14 percent year-over-year increase. That compares to about 1.2 million b/d in Chinese imports from Saudi Arabia. Shipments along the East Siberia-Pacific Ocean (ESPO) oil pipeline to the Kozmino export hub near the port city of Nakhodka in the Russian Far East point to a 24,000 b/d month-over-month gain to about 757,000 b/d in May to customers including Japan, South Korea, and Singapore, according to Energy Intelligence Group. In addition to linking to the Kozmino export hub, the ESPO pipeline connects directly to China via the Skovorodino-Daqing spur, an about 660 mile long pipeline transporting oil from Russia’s Far East to China’s Northeast province of Shandong, home to half of China’s teapot refineries and nearly 70 percent of teapot refining capacity.   !function(){"use strict";window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"])for(var e in a.data["datawrapper-height"]){var t=document.getElementById("datawrapper-chart-"+e)||document.querySelector("iframe[src*='"+e+"']");t&&(t.style.height=a.data["datawrapper-height"][e]+"px")}})}(); The recent success in oil sales to China contrasts to struggles in Europe and domestically. Seaborne crude oil shipments from the Baltic Sea ports of Primorsk and Ust-Luga are set to see a 620,000 b/d month-over-month decline in May due to reduced refinery runs and lackluster demand across Europe. March crude oil shipments via the Druzhba pipeline, the longest pipeline in the world, fell about 125,000 b/d month-over-month in April and may experience more headwinds in the coming months. Domestic demand for crude oil has also cratered amid the COVID-19 pandemic. Deputy Energy Minister Pavel Sorokin explained in April that domestic gasoline, diesel, and jet fuel consumption has fallen by 40 percent, 30 to 35 percent, and more than 50 percent, respectively, due to the shutdown of the Russian economy in light of the pandemic. Data shows gasoline production for the first six days of May declined to about 572,000 b/d, down about 40 percent from March levels as about a third of Russian products output is consumed domestically.   Although the OPEC+ agreement is finding very successful implementation, Russian and Saudi Arabian exports are still competing for similar customers going forward. Now, the United States could be added to the mix as the Trump administration is calling upon China to honor its bilateral trade pact, which included increased purchases of U.S. crude oil by China’s refiners. The negotiated increase in U.S. energy purchases, however, has been hampered by China’s economic contraction in the first quarter of 2020. Rebounding oil demand may help paper over such differences when the OPEC+ coalition meets again in less than two weeks, but there will be a lot to navigate beyond June as oil producers try to build on momentum created by the historic deal made in April.