Introduction and Overview Economic sanctions are one foreign policy tool that can be used to potentially influence the behavior and actions of political leadership in other countries. Oil-related sanctions are one option that could be used to apply economic pressure on certain countries in order to achieve broader geopolitical and foreign policy objectives. Currently, the United States has active economic sanctions imposed on three major oil-producing and exporting countries: Iran, Russia, and Venezuela. Combined, these countries produced approximately 17.7 million barrels per day (bpd) of oil in 2018âapproximately 18% of total world oil productionâaccording to one estimate. Only a portion of these supply volumes might be directly affected by U.S. economic sanctions in the near termâpotentially ranging from 3.3 million to 4.0 million bpd from both Iran (estimated to be 2.8 million bpd) and Venezuela (estimated to range from 0.5 million to as much as 1.2 million bpd). Estimated oil production volumes affected to date have been approximately 1.7 million bpd from Iran. Venezuela oil production has likely also been affected, although accurately quantifying volumes is challenging due to monthly oil production declines that had been occurring over a period of years prior to U.S. sanctions affecting oil trade in January 2019. A sustained global petroleum supply imbalance of 1% to 2% could contribute to market conditions that could result in volatile price movements (both upward and downward) for crude oil and related petroleum products (e.g., gasoline and diesel fuel). To date, oil supply impacts related to economic sanctions have not generally resulted in significant upward price pressure for benchmark oil prices. Generally, sanctions-related supply losses have been counterbalanced by increased production and exports from the United States, Russia, and other countries; petroleum trade flow adjustments; indications of slowing global oil demand growth rates; and design elements of oil-related sanctions. Oil sanctions frameworks can include wind-down periods, requirements to consider and certify that global oil supply is adequate to compensate for supply reductions, and engagement with other oil producers before applying certain sanctions. These design elements are intended to mitigate sanctions-related market and price impacts and to build into the sanctions regime multilateral coordination and cooperation. Oil-related economic sanctions for each respective country discussed in this report differ in terms of design and potential market impacts. As a result, each framework is likely to have a different effect on oil production, trade, and potentially price levels. Generally, each sanctions framework is structured to reduceâeither immediately or in the futureâoil sales revenue to the subject country. Since 2011, sanctions targeting Iran's oil sector have aimed to eliminate the country's oil export revenue. Sanctions applied to Russia's oil sector generally target long-term, high-risk oil production projects. Venezuela sanctions imposed to date prohibit petroleum trade with the United Statesâhistorically one of the primary destinations for Venezuela's oil exportsâand have the potential to affect Venezuela's petroleum trade with other countries. Table 1 provides a general overview of current oil-sector sanctions imposed on Iran, Russia, and Venezuela. Scope of Report The scope of this report is to assess the possible impact of current U.S. economic sanctions on oil production in and exports from Iran, Russia, and Venezuela. For each country, this report provides general background and historical information about the oil sector, followed by an overview of each oil-related sanctions framework and a discussion of oil production, supply, and trade impacts resulting from U.S. sanctions. European Union (EU) oil sector sanctions imposed on Iran and Russia are referenced but are not discussed in detail. Selected oil market impact observationsâspecifically price impacts and trade flow adjustmentsâand policy considerations are discussed. A detailed assessment of how oil-related sanctions might have affected each target country's overall economy and how these effects may have contributed to achieving U.S. foreign policy objectives is beyond the scope of this report. Iran7 Iran holds the fourth largest proven oil reserves in the worldâbehind Venezuela, Saudi Arabia, and Canadaâwith an estimated 156 billion barrels as of the end of 2018. A founding member of the Organization of the Petroleum Exporting Countries (OPEC), commercial crude oil production in Iran started in 1913 and Iran has been both an oil producer and exporter for more than a century. Iran's oil industry was nationalized in 1951 by Prime Minister (PM) Mohammed Mossadeq, who expropriated the Anglo-Iranian oil companyâtoday known as BP. Foreign policy concerns about PM Mossadeq's potential pivot toward the Soviet Union resulted in a U.S.- and British-sponsored intelligence operation that removed Mossadeq from power in 1953. Following that operation, a consortium of U.S. and European oil companies effectively took control of Iran's oil production and exports. Crude oil production in Iran was at its highest historical rate in the 1970s when it ranged between 5 million and 6 million bpd for much of the decade. Diplomatic relations between the United States and Iran in the late 1960s and for most of the 1970s were generally positive, with oil production and trade being one element of the relationship. During this period, the Shah of Iran (Iran's political leader at the time)âin an effort to increase oil revenues for military and domestic policy purposesârequested then-President Nixon to eliminate the Mandatory Oil Import Quota (MOIQ) system that limited U.S. crude oil import volumes from foreign countries. In 1969, the Shah also reportedly offered to sell the United States 1 million bpd of crude oil for 10 years at a price of $1/barrel for the United States to create a strategic oil stockpile. President Nixon declined the Shah's request and offer. As domestic U.S. oil production levels were not keeping pace with increasing U.S. oil demand, President Nixon replaced MOIQ with an import licensing fee system in April 1973. Iran was not party to the October 1973 oil embargoâinstituted by members of the Organization of Arab Petroleum Exporting Countries (OAPEC)âan event that contributed to rapidly rising petroleum prices, perceived supply shortages, and the enactment of U.S. laws to ensure domestic availability of oil supply. The oil market situation in late 1973 created an opportunity for Iran to increase oil revenue. U.S. crude oil imports from Iran more than doubled from 1973 to 1978, when imports reached approximately 550,000 bpd. However, U.S.-Iran relations changed in 1979 when the Iranian revolution culminated with the Shah abdicating, Iran becoming an Islamic republic, and Ayatollah Khomeini rising to power as Iran's supreme leader. Oil production in Iran started declining in late 1978, due to a labor strike in opposition to the Shah's policies, and the situation led to one of the largest (5.6 million bpd) and longest (nearly six months) supply disruptions in history. This supply loss contributed to one of the highest inflation-adjusted annual oil price periods on record. Overview of U.S. Sanctions on Iran's Oil Sector Sanctions imposed on Iran have been a foreign policy tool used by the United States for nearly three decades with the goal of deterring state-supported terrorism, Iran's regional influence, and its nuclear program. Iran's oil sector has been the target of multiple U.S. sanctions initiatives. For example, imports of Iranian crude oil to the United States were prohibited in 1987. Prior to the prohibition, U.S. oil buyers imported as much as 550,000 bpd from Iran. Additional elements of Iran's oil sector are also subject to sanctions, including investments in Iran's oil production; insurance for Iranian oil entities and for shipping Iranian crude oil; the sale of goods and services that support Iran's oil production; oil transportation; and oil exports. Sanctions targeting Iran's oil sector are the product of enacted laws and issued executive orders (E.O.s) that span multiple Administrations. For a brief overview of relevant oil sanctions legislation, see the text box below titled Enacted Legislation that Affect s Iran's Oil Sector: Selected Examples . This section focuses on sanctions legislation enacted in December 2011âNational Defense Authorization Act for Fiscal Year 2012 ( P.L. 112-81 )âand subsequent E.O.s designed to reduce Iran's oil export revenue. Sanctions Framework Targeting Iran's Oil Exports Section 1245 of the National Defense Authorization Act for Fiscal Year 2012 (FY2012 NDAA; P.L. 112-81 ) created a sanctions framework designed to motivate Iran's oil buyers to reduce purchases, with the goal of limiting Iran's oil export revenue. The core element of this framework includes financial sanctionsâprohibition on opening and accessing U.S. bank accountsâthat are to be imposed on foreign financial institutions that conduct a "significant financial transaction" with Iran's Central Bank or with any sanctioned Iranian bank. However, these transactions can potentially continue should affected countries comply with other elements of the sanctions framework that incentivize oil buyers to reduce imports from Iran while mitigating potential oil supply and price impacts. Other design elements of this framework include the following: (1) a 180-day wind-down period for implementation; (2) a provision that allows for financial institutions to be excepted from sanctions based on reducing Iran oil purchases; (3) a requirement that the Administration consider impacts to global oil prices and supplies; and (4) outreach to other petroleum producing countries. Significant Reduction Exception (SRE) Sanctions do not apply to financial institutions under the jurisdiction of countries that the President determines to have "significantly reduced" oil purchases volumes from Iranâ significantly is not statutorily defined. SREs are valid for 180 days, and countries must continue reducing Iranian oil purchases during this period to receive a subsequent exception. The SRE design element provides the Administration with some discretion to determine the level of economic pressure to apply while considering possible global oil supply and price effects. Petroleum Market Assessment and Consideration The President is required to determineâ90 days following enactment and every 180 days thereafterâthat the price and availability of petroleum from non-Iranian producers are adequate to enable Iran's crude oil buyers to significantly reduce purchase volumes. This determination must be based on petroleum price and availability reports submitted to Congress by the Energy Information Administration (EIA) every 60 days. Oil market conditions, should an undersupply situation result in escalated prices, could motivate some degree of sanctions relief even if such an action may not be consistent with sanctions-related policy objectives. However, the term adequate is not defined in enacted sanctions legislation. Therefore, the Administration could have flexibility in determining if oil markets are adequately supplied regardless of price levels. Outreach to Petroleum Producing Countries The sanctions framework also requires the President to encourage petroleum-producing countries to increase oil supplies and to minimize sanctions-related oil availability and price impacts. U.S. State Department officials reportedly have had discussions with oil-producing countries and have indicated that other countriesâspecifically Saudi Arabia and the United Arab Emirates (UAE)âwould provide additional oil supply to compensate for reduced volumes from Iran. Executive Orders 13622 and 13846 On July 30, 2012, President Obama issued E.O. 13622 to authorize additional Iran sanctions. The President revoked the E.O. in the course of implementing the U.S. obligations under the Iran nuclear deal, known as the Joint Comprehensive Plan of Action (JCPOA); President Trump reinstated the E.O.'s tenets on August 6, 2018, with the issuance of E.O. 13846. With respect to Iran's oil exports, E.O. 13846 strengthens the NDAA sanctions framework in two primary ways: 1. Prohibits access to the U.S. financial system for any foreign financial institution that conducts or facilitates a significant financial transaction with the National Iranian Oil Company or for the purchase of petroleum, petroleum products, or petrochemical products, and 2. Authorizes the imposition of Iran Sanctions Act ( P.L. 104-172 ) sanctions on any entity that engages in significant transactions for the purchase of petroleum, petroleum products, or petrochemical products from Iran. Financial institutions and entities subject to sanctions contained in E.O. 13846 can continue petroleum and petrochemical transactions if their country of primary jurisdiction receives an SRE (see " Significant Reduction Exception (SRE) " section). Oil Export Sanctions Relief and Reimposition International negotiations with respect to Iran's nuclear development program resulted in two multilateral agreements that first relieved then waived FY2012 NDAA sanctions and revoked E.O. 13622 sanctions that target Iran's oil exports. President Trump ended U.S. participation in the agreements and reimposed Iran oil export sanctions. Following is a brief description of the oil-related aspects of the two multilateral agreements and the termination of U.S. participation. Joint Plan of Action ( JPA ) : an interim agreement in effect between January 20, 2014, and January 16, 2016, that, among other provisions, removed the requirement on Iran's oil buyers to continue reducing oil purchases to receive an SRE. Iran's oil purchasers at that time (China, India, Japan, Republic of Korea, Taiwan, and Turkey) were allowed to continue purchasing oil at the then-current average. Sanctions on insurance, transportation services, and petrochemical exports were suspended. JCPOA : implemented on January 16, 2016, when the Administration waived FY2012 NDAA Section 1245 financial sanctions and revoked E.O. 13622. These actions effectively removed secondary sanctions targeting Iran's oil exports. Buyers could resume importing unrestricted oil volumes from Iran. United States ends JCPOA participation (sanctions re imposed ) : President Trump announced on May 8, 2018, that the United States would terminate its JCPOA participation and sanctions would be re-imposed following a wind-down period (180 days for sanctions targeting Iran's oil exports). On November 5, 2018, FY2012 NDAA Section 1245 financial sanctions and petroleum, petroleum product, and petrochemical purchase sanctions were reinstated. SREs were issued to eight countries in November 2018 (for additional information see Figure 1 notes). However, SREs are no longer allowed as of May 2019. Oil Supply Impacts Secondary sanctions that target Iran's oil exports have resulted in a direct and measurable effect on Iran's crude oil production and on observable export volumes of crude oil and condensate. As indicated in Figure 1 , crude oil and condensate exports declined by approximately 1.2 million bpdânearly 57%âbetween December 2011 (upon enactment of the FY2012 NDAA) and July 2012. Iran's oil production volumes followed a similar trajectory. During the JPA effective period (January 2014 to January 2016), Iran's crude oil production and export volumes stabilized, as countries were no longer required to continue reducing imports to receive SREs. With the implementation of the JCPOA, sanctions affecting oil exports were waived and Iran's production and exports returned to pre-FY2012 NDAA levels. Following the United States exiting the JCPOA in May 2018, production and exports declined and then stabilized once SREs were granted to eight countries in November 2018. As of May 2, 2019, it is the Trump Administration's intent to no longer grant SREs. According to Bloomberg L.P.'s oil tanker tracking service, observable exports from Iran have declined significantly (see Figure 1 notes for background about data challenges) based on October 2019 volumes. Iran's crude oil exports to certain independent refiners in China have carried on, and some analysts expect this trade relationship to continue. Russia Russia is one of the largest oil producers and exporters in the world. In 2018, crude oil and condensate production in Russia was larger than in any other country, at approximately 11.2 million bpd. The United States (11 million bpd) and Saudi Arabia (10.5 million bpd) were ranked second and third respectively. As of the end of 2018, Russia held the sixth largest amount of proven oil reserves with approximately 106 billion barrels. Commercial oil production in Russia and the former Soviet Union dates back to the 1870s when the first wells were drilled in Baku (today the capital of Azerbaijan). Increasing oil production and exportsâalong with oil refining to make kerosene for artificial lightingâin the late 1800s resulted in the emergence of a major competitor to the global monopoly held by U.S.-based Standard Oil at that time. The oil industry continued to grow and expand in the Russian Empire and growth continued to develop in the Soviet Union after the 1917 Bolshevik Revolution. Soviet oil policy decisions in the 1920s and 1950s resulted in depressed global oil prices that are credited with motivating two historical oil industry developments. The first was an export campaign in the 1920s that contributed to low prices and the signing of the historic Achnacarry Agreement in 1928 by multiple oil companies with the intent to restrict oil production in order to support oil prices. The second was an oil market-share campaign in the 1950s that led to lower prices and was one factor credited with motivating creation of OPEC in 1960. By 1987, the Soviet Union was the largest oil producer in the world at nearly 12.5 million bpd, more than twice the production of Saudi Arabia that year. Soviet oil production had declined to 10.3 million bpd in 1991, the year the Soviet Union was formally dissolved and the Russian Federation (Russia) established. Oil production in the Russian Federation represented approximately 90% of Soviet oil production in 1991, at 9.3 million bpd. Russia's oil production declined to just over 6 million bpd in 1996 but recovered to 10.8 million bpd by 2013. Today, oil is a major element of Russia's economy; approximately 46% of federal revenue came from the oil and gas sector in 2018. Oil Sector Sanctions Framework41 Following Russia's invasion and occupation of Ukraine's Crimea region in March 2014, President Obama declared a national emergency (E.O. 13660) with respect to Russia's actions in Ukraine. Subsequent E.O.s, Department of the Treasury directives, and enacted legislation created a sanctions framework, elements of which target Russia's oil sector. Oil sector sanctions imposed on Russia originated in E.O. 13662, which identified Russia's energy sector as an element of Russia's economy that could potentially be sanctioned. Sanctions imposed on Russia's oil sector target two general activities by prohibiting certain transactions with U.S. entities: (1) access to debt finance (Directive 2, described below), and (2) access to technology, goods, and services to support complex oil exploration and production projects (Directive 4, described below). Subsequently, the Department of the Treasury publishedâand has periodically updatedâa list (Sectoral Sanctions Identification, or SSI, list) of Russian entities that are subject to these E.O. 13662 sectoral sanctions. Directives 2 and 4 issued by the Department of the Treasury, which apply to certain Russian oil companies, describe transactions and activities that are prohibited with entities included on the SSI list. Table 2 contains a list of Russian oil companies and indicates those that are subject to Directive 2 and Directive 4 sanctions. The Ukraine Freedom Support Act of 2014 ( P.L. 113-272 ) created a framework that would allow the President to impose secondary sanctions on foreign persons/entities that make significant investmentsâas determined by the Presidentâin special Russian crude oil p rojects (i.e., projects that would extract crude oil from deepwater, Arctic offshore, and shale projects located in Russia). Enactment of the Countering Russian Influence in Europe and Eurasia Act of 2017 (CRIEEA; Title II of P.L. 115-44 , the Countering America's Adversaries Through Sanctions Act) in August 2017 codified and strengthened Directives 2 and 4, as described below. CRIEEA also modified the Ukraine Freedom Support Act to require the President to impose sanctions on persons/entities determined to have made significant investments in special Russian crude o il p rojects . Directive 2: Access to Debt Finance45 Directive 2 limits the ability of Russian oil companies on the SSI list to borrow from U.S. financial institutions and other lenders. The original version of Directive 2 (July 2014) prohibited access to U.S. debt with a maturity longer than 90 days for certain companies operating in Russia's energy sector. CRIEEA modified Directive 2 to prohibit entities on the SSI list from accessing U.S. debt with a maturity longer than 60 days. Some of Russia's largest oil companies, by production volume, are subject to this directive and now have reduced access to debt capital. Limited access to financial markets can potentially result in higher borrowing costs for the affected companies and could make it difficult for these companies to finance company activities. Directive 2 had the potential to affect Russia's near-term oil production. However, according to analyst reports, Russian oil companies on the Directive 2 SSI list were able to secure alternative sources of finance by accessing, through domestic borrowing, Russia's federal financial reserves. Directive 4: Access to Oil Exploration and Production Technology48 Directive 4 prohibits the sale and transfer of goods, services, and technology from U.S. entities to Russian companies on the SSI list that would support three types of Russian oil exploration and production projects: (1) deepwater, (2) Arctic offshore, and (3) shale. The original version of Directive 4 (September 2014) stipulated that these oil sector sanctions were applicable to projects located in Russian territory or claimed maritime waters. However, CRIEEA legislation enacted in 2017 expanded the applicability of Directive 4 to include deepwater, Arctic offshore, or shale projects in any locationâinside or outside Russiaâthat are 33% or more owned or are subject to voting control by a sanctioned Russian entity. Directive 4 sanctions target complex and challenging oil exploration and production projects that are likely part of Russia's long-term oil resource development plans. In conjunction with Directive 4 sanctions, the U.S. Department of Commerce's Bureau of Industry and Security (BIS) announced export restrictions on Russia in July 2014 to prohibit the export of certain items that may be used for deepwater, Arctic offshore, and shale projects. BIS's announcement of the implementation of these export restrictions indicated the long-term nature of the energy technology sanctions: "While these sanctions do not target or interfere with the current supply of energy from Russia or prevent Russian companies from selling oil and gas to any country, they make it difficult for Russia to develop long-term, technically challenging future projects." Secondary Sanctions on Special Russian Crude Oil Projects Section 4(b) of the Ukraine Freedom Support Act of 2014 ( P.L. 113-272 ) created a framework for secondary sanctions that could be imposed on non-U.S. persons/entities that invest in deepwater, Arctic offshore, and shale projects that extract crude oilâspecial Russian crude oil projectsâlocated in Russia. The secondary sanctions framework includes a menu of nine sanctions. As amended by CRIEEA, should the President determine that foreign persons or entities have made a significant investment âa term not defined in enacted legislationâin certain Russian crude oil projects, the President is required to impose at least three of the nine sanctions on those foreign persons/entities. To date, secondary sanctions related to investments in these types of Russian crude oil projects have not been imposed. Oil Supply Impacts Oil production in Russia has increased since U.S. oil sector sanctions were first imposed in July 2014. Further, this increase occurred during a period of rapidly declining oil prices and Russia's participation in an oil production agreement with OPEC and other non-OPEC oil-producing countries (collectively referred to as OPEC+). Under the current sanctions framework, Russia could continue increasing oil production levels in the near term. However, future oil production in Russia is somewhat uncertain due in part to potential impacts that might result from Directive 2 and Directive 4 sanctions, as well as the potential for secondary sanctions that aim to limit foreign investment in certain Russian crude oil production projects. Short-Term Supply: 2014-2019 On a monthly basis, Russian oil production increased by approximately 1 million bpd between July 2014 (10.4 million bpd) and December 2018 (11.45 million bpd), as illustrated in Figure 2 . Annual oil production levels in Russia have been trending up from 2014 to 2018. Monthly oil production levels have declined since December 2018 to 11.1 million bpd as of May 2019. Two factors that likely contributed to this observed decline are (1) implementation of a voluntary OPEC+ oil production agreement and (2) oil contamination in Russia's Druzhba pipeline that temporarily disrupted oil shipments to Europe. Russian oil production increased during periods of low and declining oil prices (see Figure 2 ) following the imposition of oil sector sanctions. This upward oil production trend during challenging market and price conditions is a result of several factors, including Russian companies securing alternative sources of finance, currency devaluation, and Russia's oil tax and export duty policy. Alternative Sources of Finance Directive 2 financial sanctionsâin combination with similar EU financial sanctions âimposed on certain Russian oil companies required those firms to secure alternative sources of capital to manage corporate finance activities. Directive 2 sanctions had the potential to result in financial stress for Russian oil companies on the SSI list and potentially affect short-term oil production levels. However, reports indicate that sanctioned Russian oil companies were able to use Russia's international currency reservesâaccumulated, in part, when oil prices were in the $100 per barrel range (2011-2014)âas an alternative source of finance. Russia's financial reserves enabled companies like Rosneft, a state-controlled Russian oil company, to borrow money from the domestic bond market to manage debt obligations and fund business operations. Additionally, Rosneft has sold minority ownership positions to Chinese and Indian companies as a means of funding oil production activities. Finally, Rosneft has raised cash through equity sales and sold a 19.5% ownership position to the Qatari Investment Authority and Glencore for $11.3 billion in 2016. Currency Devaluation Following the imposition of sanctions in mid-2014, and as oil prices were declining rapidly, the Russian ruble began to lose value relative to the U.S. dollar. In November 2014, Russia's Central Bank announced it would limit its exchange rate interventions and allow the ruble exchange rate to be determined by the market. Weakening of the ruble relative to the dollarâeach dollar being worth more rublesâcontinued. In June 2014, one U.S. dollar could be exchanged for approximately 34 rubles. This exchange rate reached 59 in December 2014 and was as high as 75 in January 2016. This currency devaluation, while arguably negative for the overall Russian economy, actually supported profitability and cash flow for Russian oil companies. Russian oil export sales are primarily denominated in dollars, and most Russian oil company expenses are denominated in rubles. At a given oil price, currency devaluation increases the amount of rubles received for dollar-denominated oil sales. However, the exchange rate does not directly affect ruble-denominated expenses. As a result, ruble-denominated profitability can be supported even when oil prices are relatively low. These factors, along with downward price pressure on oilfield equipment and service contractors following oil price declines in 2014 through early 2016, contributed to the general upward trend of Russia's oil production while oil prices steeply declined. Tax and Export Duty Policy Russia's oil tax policy motivates oil companies operating in the country to maintain and increase oil production, even when benchmark oil prices reach levels as low as $20 per barrel (/b). Russia's oil tax framework currently consists of two primary elements: (1) mineral extraction tax (MET), and (2) export duty (ED). MET and ED payments are linked to benchmark oil prices. Both are calculated using formulasâmodified periodically to incentivize oil production from certain locationsâthat adjust the tax and duty based on the price of Urals crude oil, Russia's oil price benchmark. The effect of this tax and duty structure is that the Russian government assumes most of the financial risk from low oil prices and receives most of the benefits from high oil prices. Based on analysis of MET and ED base formulas, government tax and duty receipts can be zero at a $10/b oil price and more than $45/b when oil prices reach $70/b. Oil company cash flows also fluctuate but to a much lesser extent and are insulated to some degree from oil price fluctuations. As a result, Russian oil companies are motivated to maintain and increase oil production with limited consideration of the market price for crude oil. Russia has also started implementation of its "tax maneuver" that will gradually eliminate the ED and increase the MET by 2024 for crude oil production. Longer Term: Beyond 2019 Russia's ability to maintain and possibly increase oil production beyond 2019, should the sector continue to be subject to U.S. and EU sanctions, is uncertain. The International Energy Agency projects that oil production in Russia is likely to continue increasing through 2021 (11.8 million bpd including crude oil, condensate, and natural gas liquids) and then decline slightly by 2024 (11.6 million bpd). Russian oil production post-2024 is less certain, with some forecasts indicating that Russian oil companies may need to develop new resources in order to maintain oil production levels in the 11 million bpd range. Exploration and production sanctions (Directive 4) imposed in 2014 were intended to affect future Russian oil production. Some specific projects have been affected by U.S. and EU oil sector sanctions. For example, Exxon has withdrawn from joint venture projects with Rosneft that would develop oil resources in deepwater, Arctic offshore, and shale locations. Additionally, certain European oil company joint venture projects have been affected by oil sector sanctions. French oil company Total sold its ownership stake in a shale joint venture project with Lukoil. According to the Energy Information Administration (EIA), large shale oil resources are present in Russia. Several U.S. and European oil companies had been participating in joint venture Russian shale oil projects prior to the 2014 sanctions. However, development of these projects has since slowed. Should Directive 4 and similar EU sanctions continue to be imposed, sustaining oil production growth in Russia will likely be a function, largely, of two factors: (1) the ability of Russian oil companies to develop or acquire oil production technology needed to produce resources in deepwater, Arctic offshore, and shale formations; and (2) the successful execution of exploration and development strategies that target oil production in areas outside the scope of sectoral sanctions (e.g., tight oil). Following the imposition of Directive 4 sanctions in 2014, Russia started developing plans to reduce its reliance on imports of oil production equipment. Furthermore, Russian oil companies reportedly have been increasing acquisition of oilfield equipment from Chinese suppliers. Venezuela Venezuela holds the largest proven oil reserves in the world, estimated at 303 billion barrels as of the end of 2018. A founding member of OPEC, Venezuela has produced oil commercially since 1914. U.S. oil companies began seeking agreementsâalso referred to as concessionsâto explore for and produce oil in Venezuela as early as 1919. Venezuela was not a participant in the 1973 Organization of Arab Petroleum Exporting Countries embargo of oil shipments to the United States and other countries. However in 1976, consistent with developments in other oil-producing countries during the 1970s, Venezuela nationalized its oil industry and created Petroleos de Venezuela S.A. (PdVSA). U.S. oil companies, such as Exxon, reduced investments in the country leading up to nationalization but continued to be active in Venezuela in a limited service-based role following nationalization. Oil production in Venezuela was approximately 3.7 million bpd in 1970. Production declined 2.1 million bpd (54%) from 1971 to 1988 to reach 1.6 million bpd. In the 1990s, PdVSA embarked on a program referred to as the apertura petrolera âor oil opening. As part of this program, international oil companiesâincluding U.S.-firms Chevron, Exxon, and Conocoâwere allowed to either control certain oil field operations or establish majority-owned oil production joint ventures with PdVSA. Oil production in Venezuela increased to approximately 3.4 million bpd by 1998. During his campaign, former Venezuelan President Hugo ChÃ¡vezâelected in 1998âthreatened to reverse the apertura program. Subsequently, President ChÃ¡vez enacted the Hydrocarbons Law of 2001, which restructured Venezuela's petroleum sector by requiring PdVSA to have majority ownership of future oil developments and raising royalty payments on existing projects to the Venezuelan government. Throughout the ChÃ¡vez presidency, oil companies operating in Venezuela were subject to periodic increases in royalty rates and taxes. These additional payment requirements reduced the financial attractiveness of investing in Venezuela's oil sector. In 2007, the ChÃ¡vez government enacted a law that required existing oil joint ventures to convert into new entities that would be majority-owned by PdVSA. Some companies (e.g., Chevron) complied with the new requirement. Other companies (e.g., Exxon and Conoco) ceased operations and sued PdVSA for damages resulting from unilateral changes to contractual agreements. Oil production in Venezuela trended a bit lower but was relatively stable from 2007 through 2013, in the range of 2.5 million bpd. Following the death of ChÃ¡vez in 2013, NicolÃ¡s Maduro was elected president of Venezuela. A series of antidemocratic actions and human rights violations by the Maduro government resulted in sanctions legislation and executive actions by the United States. In 2017, President Trump declared a national emergency in E.O. 13808 and the Administration imposed financial sanctions on PdVSA, including limiting PdVSA's access to U.S. debt finance. PdVSA is also prohibited from receiving dividends and cash distributions from its U.S.-based Citgo refining subsidiary. These limitations made it more difficult for PdVSA to purchase oil-related services and oil production equipment. With the overall U.S. objective to pressure President Maduro to transfer government control, the United States recognized Juan GuaidÃ³ as interim president of Venezuela and imposed sanctions in January 2019 aimed at reducing Venezuela's oil revenues. These sanctions effectively terminate U.S.-Venezuela petroleum trade and potentially make it difficult for PdVSA to sell crude oil to and obtain petroleum products from non-U.S. entities. Oil Trade Sanctions Framework U.S. sanctions targeting Venezuela's oil trade are a function of PdVSA being designated to be subject to U.S. sanctions. This designation prohibits U.S. companies from engaging in transactions with PdVSA, including petroleum trade, oilfield service operations, and oil production operations in Venezuela. To date, Congress has not enacted legislation that specifies and requires oil sanctions be imposed on Venezuela. Rather, the sanctions framework is a result of E.O.s issued under national emergency authorities, and Treasury designations and general licenses (GLs) based on that emergency that allow for the wind down or continuation of certain activitiesâsee list of actions below. E.O. 13850 (November 1, 2018): authorized prohibiting U.S. persons from engaging in certain transactions with any person determined by the Secretary of the Treasury to have supported "deceptive practices or corruption" involving the Government of Venezuela. E.O. 13857 (January 25, 2019): amended the "Government of Venezuela" definition in E.O. 13850 to include PdVSA. Treasury designates PdVSA (January 28, 2019): the Secretary of the Treasury determined that persons operating in Venezuela's oil sector are subject to sanctions. PdVSA added to the Specifically Designated Nationals (SDN) list. GLs issued (January 28, 2019 and subsequent revisions): Office of Foreign Asset Control (OFAC) GLs authorize certain transactions and activities with PdVSA for certain periods, including oil purchases (wind down periods) and oil production operations (continuation). E.O. 13884 (August 5, 2019): blocks property and interests in property located in the United States for persons/entities determined to have assisted PdVSA and the Government of Venezuela. The Secretary of the Treasury's determination and designation affects several areas in which U.S. companies have business interests (e.g., debt and financial transactions, oil field services, and oil production activities) and effectively terminates U.S.-Venezuela petroleum (crude oil and petroleum products) trade. GL 12 allowed U.S. companies to continue purchasing and importing crude oil and petroleum products from PdVSA until April 28, 2019. However, any payment made for petroleum imported from PdVSA during the 90-day wind-down period must have been deposited in a U.S.-based blocked account. This requirement likely resulted in most of these transactions ending immediately, as PdVSA would have been motivated to seek alternative buyers. Some GLs explicitly stated that exporting diluentsâtypically light crude oil, condensate, or naphtha that is blended with Venezuelan heavy crude oil to facilitate transportation and processing âfrom the United States to Venezuela was prohibited immediately. Chevronâcurrently participating in oil production joint ventures with PdVSAâand four oil service companies (Halliburton, Schlumberger, Baker Hughes, and Weatherford International) have been granted a GL to continue operating in Venezuela. This GL has been extended multiple times since January 2019 and is currently set to expire on April 22, 2020. Potential Secondary Sanctions Treasury guidance issued in January 2019 and E.O. 13884 create the potential for imposing sanctions on non-U.S. entities that transact with PdVSA. Following E.O. 13857, OFAC-issued Frequently Asked Questions (FAQs, #657) indicated that petroleum purchases by non-U.S. entities involving "any other U.S. nexus (e.g., transactions involving the U.S. financial system or U.S. commodity brokers)" are prohibited following the 90-day wind-down period. Most oil transactions are denominated in U.S. dollars and this guidance may create some difficulties for PdVSA to secure alternative buyers for crude oil volumes that were previously destined for the United States. E.O. 13884 provides for the blocking of property and interests in property in the United States for persons and entities determined by the Secretary of the Treasury to have materially assisted âterm not defined in the E.O.âPdVSA. This potential for sanctions on entities that transact with PdVSA, and have interests in property within U.S. jurisdiction, may further complicate PdVSA's efforts to sell crude oil to non-U.S. buyers and acquire petroleum products from alternative suppliers. Oil Supply Impacts Following the 2017 imposition of PdVSA financial sanctions, Venezuela's monthly oil production declined by approximately 50%âbetween August 2017 and January 2019. Venezuelan oil production had been trending downward in prior years due to aging oil infrastructure and insufficient investment in, and maintenance of, oil production assets. As indicated in Figure 3 , crude oil production declined from approximately 2.8 million bpd in January of 2011 to approximately 1.9 million bpd in August 2017âwhen sanctions were imposed on PdVSA. U.S. imports of Venezuelan crude oil also declined by nearly 50%, on a monthly basis, during this period. Sanctions imposed on PdVSA in 2017 made it difficult for the company to access financial resources from debt markets and to receive cash distributions from PDV HoldingâPdVSA's U.S.-based subsidiary that owns Citgo, an oil refining and marketing company. This limitation likely created some operational difficulties for PdVSA with respect to short-term credit that might be needed to pay for oil-related services and acquire oil production and maintenance equipment from U.S. suppliers. Oil production data illustrated in Figure 3 indicate that the production decline accelerated following the 2017 financial sanctions. However, it is difficult to attribute specific production volume declines directly to these sanctions since production had been trending lower since 2014. Oil production continued declining and reached approximately 1 million bpd in January 2019, when Treasury's PdVSA determination, designation, and GLs took effect (see Figure 3 ). U.S. imports of Venezuelan crude oil declined 50% over a one-month period between January 2019 and February 2019, and consistent with the pressure applied under sanctions, have since been reduced to zero. Prohibiting petroleum trade between the two countries results in a constraint in the global oil logistics system that can potentially resolve itself as transportation modes, trade routes, and transactions adjust to the sanctions-related constraint. PdVSA has sought alternative buyers such as India and China, countries that historically have been two of the largest destinations for Venezuelan crude oil (see Figure 8 in the " Trade Flow Adjustments "). Ship-tracking information indicates that Venezuela's crude oil exports to India and China increased 49% and 34% respectively between January 2019 and February 2019. However, export volumes to these countries in February 2019 were in the range of export volumes that have been observed since 2017. Although PdVSA sanctions do not explicitly prohibit non-U.S. entities from purchasing crude oil and petroleum products from Venezuela, these sanctions prohibit transactions that occur on or after April 28, 2019, that involve the U.S. financial system. Furthermore, E.O. 13884 provides Treasury with discretion to take action against foreign persons/entities that assist PdVSA. These sanctions framework elements may make it difficult for PdVSA to locate alternative buyers for crude oil barrels previously destined for the United States. Oil Market Impact Observations Sanctions-related oil supply losses and trade constraints have had an impact on oil markets. These impacts have been observed in the form of Iran and Venezuela supply reductions, as discussed above. Impacts have also been reflected in price relationships for specific crude oil types and adaptive changes to trade flow patterns. In terms of benchmark prices (i.e., West Texas Intermediate and Brent futures contracts that are often quoted in the media), potential price escalation that might be expected from Iran and Venezuela supply reductions appear to have been averted to date by an increase in oil production in other countries, trade flow adjustments, and indications of slowing oil demand growth rates. Higher oil production and export volumes from the United States, Russia, and other oil-producing and exporting countries have contributed toward mitigating potential upward price pressure. Oil Prices Potential effects on oil and petroleum product (e.g., gasoline, diesel fuel, and aviation fuel) prices have been an explicit and implied consideration for sanctions that impact global oil supply and trade. Enacted sanctions legislation targeting Iran's oil exports requires the Administration to consider and certify that the world oil market is adequately supplied when imposing sanctions and to coordinate with other oil-producing countries to minimize price impacts (see " Sanctions Framework Targeting Iran's Oil Exports " and subsequent discussion). Additional policy design elements, such as wind-down periods, provide some time for markets to adjust for sanction-related trade constraints. These design elements serve to minimize potential price increases to oil buyers and petroleum product consumers. At the same time, existing oil-related sanctions policy does not include considerations for possible oil market oversupplyâa circumstance that could contribute to market conditions that could result in sharply lower oil pricesâshould certain sanctions be relieved, waived, or terminated. While such an outcome may be a temporary benefit to U.S. petroleum consumers, a severe oil price decline over a sustained period could have a negative impact on U.S. oil exploration, production, and exports. This topic is discussed further in the " Policy Considerations " section. Benchmark Prices Oil prices that receive the most visibility are front month benchmark futures prices that are regularly reported in the news media. Benchmark prices represent the value of crude oil with certain quality characteristics at a specific location. Buyers and sellers use benchmark prices to establish a baseline oil price that is adjusted for various parameters such as quality differences and transportation costs (e.g., maritime, rail, and pipeline). Brent crude oil, a light/sweet crude oil that represents the price of North Sea (located between the United Kingdom, Norway, and Denmark) crude oil cargoes loaded on to shipping vessels, is one common benchmark price that is generally considered a proxy for global prices. As indicated in Figure 4 , Brent prices in August 2019 were more than 40% lower than in December 2011, when legislation targeting Iran oil exports was enacted. However, this macro-level pricing behavior does not suggest that oil sanctions imposed since 2011 have contributed to lower prices. Rather, benchmark prices generally reflect near-term expectations of global oil supplyâpotentially affected by oil-related sanctionsâand demand balances that quickly can change due to unplanned production outages, economic and oil demand growth forecasts, supply growth in certain countries, OPEC oil production decisions, and other physical and financial market variables. Due to the different factors contributing to benchmark price directional movements, it is difficult to attribute any actual price change to a sanctions event that either reduced supply or allowed curtailed oil volumes to return. However, there was at least one period when uncertainty about sanctions targeting Iran's oil exports arguably contributed to temporary market oversupply and an oil price decline. When the Trump Administration announced in May 2018 that the United States would exit the JCPOA, general market expectations were that the Administration would not grant SREs to countries that were importing crude oil from Iran. In response to this expectation, Saudi Arabia increased its oil production by approximately 1 million bpd between May 2018 and November 2018. Other producers, including Russia, also increased production over this period. However, the Administration granted SREs to eight countries in November 2018. A temporary oversupply resulted and arguably contributed to the Brent benchmark price declining by more than $20 per barrel between November 5, 2018, and December 24, 2018. Media reports indicate that the SREs created an oversupplied market condition that required Saudi Arabia, Russia, and other OPEC+ members to manage. Price Differentials for Certain Crude Oil Types Petroleum sanctions imposed on Venezuela prohibit petroleum trade with the United States. The largest element of the U.S.-Venezuela petroleum trade relationship consisted of U.S. imports of Venezuelan crude oil (approximately 500,000 bpd in January 2019). A significant portion of these imports was classified as heavy/sour, indicating the crude oil's gravity and sulfur content. When Venezuela petroleum trade sanctions were announced in January 2019, U.S. refiners began seeking alternative suppliers during the 90-day wind-down period. The resulting price impact was an increase in prices for medium and heavy crude oils relative to light/sweet crude and a narrowing of the price differential between these crude oil types (see Figure 5 ). As indicated in Figure 5 , the Louisiana Light Sweet (LLS) to Mars spot price differential has been negative on certain days in 2019 following the prohibition of U.S.-Venezuela petroleum trade in January. Lower quality Mars crude oil was temporarily more expensive than LLS crude oil. While this is not the first time this differential has been negativeâthe LLS/Mars price differential was also negative on certain days in 2009 and 2011âprice signals in 2019 are indicative of the oil logistics system adjusting to a sanctions-related trade constraint. U.S. refiners that previously purchased heavy crude oil from Venezuela were required to source substitute crude oil from other suppliers (e.g., Colombia, Canada, Iraq, and Saudi Arabia), modify refinery operations to process other crude oil types, or a combination of both. Operating margins for U.S. refiners that are optimally configured to process heavy/sour crude oil could be adversely affected by a persistently narrow or negative light/heavy price differential. Trade Flow Adjustments Sanctions imposed on Iran and Venezuela have resulted in oil export and trade constraints for which the global oil logistics system has had to adjust. For example, Iran's oil buyers have sourced oil from alternative suppliers, and some U.S. refiners have located alternative supplies to replace crude oil previously imported from Venezuela. The United States, Russia, Saudi Arabia, and other countries have provided alternative oil supplies to compensate for sanctions-related oil supply constraints. U.S. Crude Oil Exports Crude oil exports from the United States have contributed to "adequate" global oil supplyâa statutory requirement of the Iran oil export sanctions frameworkâthat has enabled the Administration to pursue an objective of reducing Iran's oil exports to zero. Growth in U.S. crude oil exports has been enabled by increasing U.S. oil production, the 2015 repeal of a 40-year crude oil export prohibition, and global oil benchmark price differentials that financially motivate crude oil exports. Monthly U.S. crude oil export volumes have been as high as 3 million bpd in 2019. South Korea, following a U.S. policy decision to exit the JCPOA, provides an example of how U.S. crude oil exports provided an alternative source of oil supply as the country reduced imports from Iran (see Figure 6 ). As indicated in Figure 6 , South Korea imports of Iranian crude oil declined to zero following the Trump Administration's May 2018 decision to exit the JCPOA in expectation that no SREs would be granted. At the same time, imports of U.S. crude oil to South Korea immediately increased and had more than quadrupled, month-over-month, by December 2018. China Oil Imports China's oil imports provide another example of how oil trade flows have adjusted to sanctions-related constraints. As illustrated in Figure 7 , imports of Iranian crude oil to China began to decline following the U.S. JCPOA exitâat a relatively slower pace than South Korea. As imports from Iran began to decline, imports from Saudi Arabia and Russia increased as refineries in China sought alternative oil supplies. China imports of U.S. crude oil declined to as low as zero (March 2019)âlikely a result of U.S/China trade negotiationsâfollowing the JCPOA exit but have increased since. In September 2019, China imposed a 5% import tariff on U.S. crude oil, which couldâin addition to crude oil quality considerations (see Figure 7 notes)âreduce incentives for refineries in China to increase U.S. crude oil purchases as an alternative to Iranian supplies. Venezuela-Related Trade Sanctions imposed on PdVSA have effectively eliminated petroleum trade between the United States and Venezuela. In response to this trade constraint, PdVSA has sought alternative buyers for crude oil that was previously destined for the United States and has sought alternative suppliers of light crude oil and other diluents previously supplied by U.S. exporters. As indicated in Figure 8 , Venezuela crude oil exports to the United States immediately stopped following the January 2019 designation of PdVSA as a sanctioned entity. To date, crude oil exports to China and India have remained at levels similar to those observed since 2017. However, oil exports to countries categorized as "other" have trended up since January 2019. Potential secondary sanctions on entities that transact with PdVSA using the U.S. financial system, as well as entities determined to have materially supported the government of Venezuela, could motivate non-U.S. entities to reduce or eliminate purchases of Venezuelan crude oil at some point in the future. PdVSA has also been sourcing diluent products from other suppliers. U.S. diluent exports to Venezuela were prohibited immediately in January 2019, with no wind-down period. According to trade reports, PdVSA has sourced diluents from Russia following the imposition of U.S. sanctions. However, total Venezuela diluent imports have reportedly been lower compared with import levels prior to January 2019. Lower diluent imports could be a leading indicator for lower crude oil production due to blending needs for certain Venezuelan crude oil types. Policy Considerations Sanctions imposed on Iran, Russia, and Venezuela have affected global oil markets, prices, and trade flows. As U.S. foreign policy objectives toward these countries evolve, sanctions relief, increased sanctions pressure, or both may have additional impacts on supply, prices, and potentially the U.S. oil production sector. Regarding Iran, options for additional sanctions that might affect Iran's oil sector appear to be limited as the current framework aims to eliminate Iranian oil exports. Should sanctions relief be provided to Iran, such an action could contribute to a market condition that could result in lower oil pricesâactual price levels would depend on market conditions at such a timeâand could adversely affect U.S. oil production and exports. Regarding Russia, some Members of Congress have called for additional sanctions, and several bills have been introduced in the 116 th Congress with certain provisions that could affect Russia's oil sector. Finally, the Administration has continued to strengthen oil-related sanctions on Venezuela through the use of E.O.s and administrative actions. Legislation introduced in the 116 th Congress would codify some of these sanctions. Iran: Oil Market Impacts Should Sanctions Be Relieved or Eliminated Impacts to oil supply and the potential for high oil prices are explicit considerations for economic sanctions that affect Iran's oil trade. Iran oil trade sanctions are the most stringent of the three frameworks discussed in this report. This framework includes design elements that require a periodic assessment of global oil supply adequacy when sanctions are applied and maintained (see " Sanctions Framework Targeting Iran's Oil Exports " and subsequent discussion). However, the framework does not include provisions to assess the potential for global oil market oversupply should these sanctions be relieved, waived, or eliminated. Depending on oil market conditions (i.e., supply and demand balances) at the time of potential sanctions relief, the immediate reentry of 1 million to 2 million bpd of Iranian supply could contribute to a market condition that could result in downward oil price pressure that could range from moderate to severe. Iran's oil minister has indicated that, should U.S. oil export sanctions be removed, oil production and exports could return to pre-sanctions levels in as little as three days. Although gasoline and diesel fuel consumers might welcome this result, oil producers could encounter challenging business and financial conditions should oil prices decline to, and be sustained at, extremely low levels. In 2018, total petroleum production (crude oil, condensate, and natural gas liquids) in the United States was larger than in any other country (Saudi Arabia and Russia ranked second and third, respectively). Low oil prices, depending on the actual price level and its duration, could contribute to reductions in both U.S. oil production growth and actual production levels, and could contribute to challenging business conditions for this sector of the U.S. economy. Historically, oil producers have generally relied on OPEC to attempt to manage oil supply and demand imbalances. However, as recently as 2014, OPECâeffectively led by Saudi Arabiaâsometimes has elected not to adjust production levels when oil markets are oversupplied. Results from such decisions have included rapidly declining oil prices, financial strain on some U.S. oil producers, lower U.S. crude oil production, and proposed legislation to investigate OPEC anticompetitive practices because prices were too low. Subsequently, OPEC, along with Russia and other non-OPEC countries, entered into a voluntary production agreement in December 2016 to address market oversupply and low oil prices. As prices were rising, the No Oil Producing and Exporting Cartels (NOPEC) Act was introduced with the goal of reducing and moderating oil prices that were deemed too high. The United States' ongoing position as the world's largest petroleum consumer is now coupled with being one of the largest and fastest growing oil producers. As a result, economic sensitivity to oil price levels has been rebalanced to reflect the interests of both consumers and producers. Introduced legislation is indicative of this balance. Should oil export sanctions on Iran be relieved or eliminated, the current sanctions framework would require the market to adjust to additional Iranian barrels that quickly could reenter the market. Market adjustments could take the form of lower prices, OPEC+ production restraint, or both. Depending on market conditions at such a time and the volume of Iranian oil that reenters, global benchmark oil prices could experience downward pressure that could range from moderate to severe. Extremely low oil prices could possibly have a negative impact on all oil producers, including U.S. companies. Based on recent history, whether or not OPEC, along with other OPEC+ countries, might adjust production levels to accommodate additional Iranian barrels is uncertain. One possible option to address such an outcome, should this potential situation become a concern, may be to encourage, or perhaps require, consideration of oil market conditions and communication with other oil producers as a means to reduce downside price risk that might result from sanctions relief. Russia: Is the Iran Oil Export Framework Applicable? Much of the congressional interest in additional economic sanctions directed toward Russia includes introduced legislation that would impose sanctions on various elements of Russia's energy sector, including oil production. The current Russia oil-sector sanctions framework has not affected near-term oil production but may affect future oil production. Comparing this near-term outcome with the measurable impacts of sanctions targeting Iran's oil exports, it might be of interest to explore the potential applicability of the Iran oil export sanctions framework to Russia. The size of Russia's and Iran's oil production (approximately 11 million bpd currently and 4 million bpd prior to oil export sanctions, respectively) is one consideration. Two additional considerations (discussed below) are Russia's pipeline integration with Europe and U.S. institutional investor ownership of certain Russian oil companies. Russia's Oil Pipeline Integration with Europe Transneft, Russia's state-controlled oil pipeline company that is on the SSI list, transports approximately 83% of crude oil produced in Russia. One element of the Transneft pipeline system is the Druzhba (Friendship) pipeline network that supplies Russian crude oil to several European refineries, many of which are optimally configured to process Russian crude oil. A sanctions frameworkâsuch as the one currently structured for Iranâthat might require oil buyers to significantly reduce oil purchases from Russia could be difficult for some refiners due to pipeline logistics and access to alternative suppliers. Unlike Iran's crude oil buyers that can access alternative suppliers through easily-adaptable maritime trade, accessing and configuring pipeline infrastructure to source non-Russian supplies is a more complicated and potentially difficult endeavor. Such logistical constraints introduce complexities when considering the possibility of applying the Iran oil trade sanctions framework to Russia's oil sector. U.S. Institutional Investor Ownership of Russian Oil Companies Russia's oil sector is different compared with Iran's in that U.S. institutional investors have ownership positions in some of Russia's major oil companies. Banks, U.S. states, pension funds, and insurance companies have minority investment positions in companies such as Rosneft and Lukoil, which are on the SSI list. Sanctions that affect these companies, and that aim to reduce Russia's oil production and exports, could negatively affect the value of Russian oil companies and investments held by U.S. investors and their clients. Russia: Introduced Legislation A number of congressional concerns about Russia's influence in Europe, interference in U.S. elections, and other activities have resulted in legislation introduced in the 116 th Congress that, among other things, would impose additional sanctions targeting Russia's energy sector. Some of the proposed bills that could affect Russia's oil sector are listed below. S. 1830: Energy Security Cooperation with Allied Partners in Europe Act of 2019 As originally introduced, the bill would have required mandatory sanctions on persons/entities that invest inâbased on certain investment level thresholdsâor support Russian energy export pipelines, including modernization and repair. Mandatory sanctions under this bill could include oil pipelines. Transneft, Russia's oil pipeline monopoly controlled by the Kremlin, transports 83% of oil produced in Russia. Transneft's pipeline system is used to transport crude oil to shipping ports and to export oil to refineries in European countries and in China. To the extent that the possibility of sanctions might reduce pipeline development and maintenance activities for Russia's oil pipeline network, this could affect oil flows and oil prices for certain European refineries that may not have easily accessible alternatives to Russian crude oil. Provisions related to export pipeline sanctions were removed from the bill when it was reported out of the Committee on Foreign Relations in December 2019. S. 1060: Defending Elections from Threats by Establishing Redlines Act of 2019 The bill would prohibit any "new investment"âto be defined by the President after enactmentâin a Russian energy company or in Russia's energy sector, including oil production. Investments made in the United States or by a U.S. person/entity would be prohibited. The bill would require the President to impose financial sanctions on certain property owned by any foreign firm that makes a new investment in Russia's energy sector or in a Russian energy company (i.e., secondary sanctions). S. 482: Defending American Security from Kremlin Aggression Act of 2019 As reported by the Committee on Foreign Relations, the bill would require sanctions to be imposed on individuals/entities that invest in energy projects outside of Russia that are supported by Russian-owned or parastatal entities. The bill would also require the imposition of sanctions on any person/entity that sells, leases, or provides goods, services, technology, financing, or support for any crude oil development in the Russian Federationânot just for deepwater, Arctic offshore, and shale developments currently included in the existing sanctions framework. Venezuela: Sanctions Enforcement and Enacted Legislation Sanctions affecting Venezuela's oil sector prohibit U.S. entities from transacting with PdVSA and provide a potential pathway for the Administration to sanction non-U.S. entities that transact with PdVSA and support the government of Venezuela. Petroleum trade between the United States and Venezuela has been eliminated. To date, however, enforcement actions related to Venezuela oil sector sanctions that could be imposed on non-U.S. entities have largely targeted companies and shipping vessels that have transported oil to Cuba. Venezuela's crude oil exports have continued since U.S. sanctions were imposed in January 2019, with India and China being two of the largest destinations. Trade reports indicate that much of Venezuela's oil exports are being managed by a Rosneft trading office. Rosneft has also provided PdVSA with diluent cargos as an alternative supplier to U.S. exporters and the company participates in multiple joint venture oil production projects in Venezuela. Whether or not these activities violate the U.S. sanctions framework, and are potentially subject to an enforcement action, is subject to a determination made by the Administration. Rosneft has argued that oil-trading with PdVSA is not a sanctions violation. To date, no sanctions enforcement action related to Rosneft transactions with PdVSA has been taken. Legislation enacted in December 2019 ( P.L. 116-94 ) includes provisions that require the Administration to engage with other countries and to coordinate an international effort to impose sanctions on the Maduro government. P.L. 116-94 also includes sections that express concern about PdVSA transactions with Rosneftâprimarily related to a Rosneft loan to PdVSA collateralized by 49% ownership of PdVSA's U.S.-based Citgo refinery and marketing company. Concluding Remarks In some cases, U.S. economic sanctions that target oil sectors in Iran, Russia, and Venezuela have observably affected oil markets in several ways, including reductions in supply, changes in price relationships, and adjustments to trade flows. Oil-related sanctions frameworks include design elements that aim to minimize upward price pressure that might result from the imposition of sanctions. However, design elements that consider possible oil market impacts in the event of oil-related sanctions relief or terminationâthat could contribute to market oversupply and downward price pressureâare not included in current oil-related sanctions frameworks. Arguably, potential sanctions-related price escalation has been counterbalanced by increased global supplies, lower global demand growth rate expectations, and market adjustments in response to oil supply and trade constraints. Should oil market conditions change to a persistent undersupply condition and benchmark prices escalate to levels deemed too high for U.S. consumers, sanctions relief is one available policy option that could possibly be considered to increase oil supply with the goal of rebalancing markets and moderating price levels; however, such an action could potentially conflict with broader foreign policy objectives.


Introduction to the Payments in Lieu of Taxes (PILT) Program The Payments in Lieu of Taxes (PILT) program provides compensation for certain entitlement lands that are exempt from state and local taxes. These lands include selected federal lands administered by the Bureau of Land Management, the National Park Service, and the U.S. Fish and Wildlife Service, all in the Department of the Interior (DOI); lands administered by the U.S. Forest Service in the Department of Agriculture; federal water projects; dredge disposal areas; and some military installations. Enacted in 1976, PILT is the broadestâin terms of federal land types coveredâof several federal programs enacted to provide compensation to state or local governments for the presence of tax-exempt federal lands within their jurisdictions. PILT was enacted in response to a shift in federal policy from one that prioritized disposal of federal landsâone in which federal ownership was considered to be temporaryâto one that prioritized retention of federal lands, in perpetuity, for public benefit. This shift began in the late 19 th century and continued into the 20 th century. Along with this shift came the understanding that, because these lands were exempt from state and local taxation and were no longer likely to return to the tax base in the foreseeable future, some compensation should be provided to the impacted local governments. Following several decades of commissions, studies, and proposed legislation, Congress passed PILT to at least partially ameliorate this hardship. PILT payments generally can be used for "any governmental purpose," which could include assisting local governments with paying for local services, such as "firefighting and police protection, construction of public schools and roads, and search-and-rescue operations." The Office of the Secretary in DOI is responsible for the calculation and disbursement of payments under PILT. Payments under PILT are made annually to units of general local governmentâtypically counties, though other types of governmental units also may be used (hereinafter, counties refers to units of general local government)âcontaining entitlement lands . PILT comprises three separate payment mechanisms: Section 6902, Section 6904, and Section 6905 payments, all named for the sections of law in which they are authorized. Section 6902 payments account for nearly all payments made through PILT. The Section 6902 authorized payment amount for each county is calculated according to a statutory formula that is subject to a maximum payment based on the county's population (see " PILT Payments Under Section 6902 "). The remaining payments are provided through Section 6904 and Section 6905 under selected circumstances and typically are limited in duration. Through FY2019, PILT payments have totaled approximately $9.2 billion (in current dollars). Members of Congress routinely consider amending PILT within both appropriations and authorizing legislation. For example, legislation in the 116 th Congress would amend how PILT appropriations are provided and would change how payments are calculated under Section 6902. In addition, Members of Congress may address issues related to which federal lands should be eligible for payments under PILT. This report provides an overview of the PILT payment program and includes sections on PILT's authorization and appropriations, which discusses the history of how Congress has provided funding for PILT; Section 6902 payments, which includes a breakdown of how Section 6902 payments are calculated; Section 6904 and Section 6905 payments, which outlines what situations result in payments under these mechanisms; and issues for Congress, which discusses several topics that have been or may be of interest to Members of Congress when considering the future of PILT. PILT Authorizations and Appropriations Congress has funded PILT through both discretionary and mandatory appropriations at various times since the program was first authorized. Some stakeholders and policymakers have routinely expressed concern about changes in the appropriations source, both the process of switching between mandatory and discretionary appropriations and the uncertainty that may accompany such changes. From 1982 to 2008, Section 6906 provided an "Authorization of Appropriations" for PILT, which stated, "Necessary amounts may be appropriated to the Secretary of the Interior to carry out [PILT]." Further, it clarified that "amounts are available only as provided in appropriation laws." Congress amended this language in 2008 and changed the section title from "Authorization of Appropriations" to "Funding." Further, Congress changed the text to read For each of fiscal years 2008 through 2012- (1) each county or other eligible unit of local government shall be entitled to payment under this chapter; and (2) sums shall be made available to the Secretary of the Interior for obligation or expenditure in accordance with this chapter. This amendment effectively changed PILT funding from being discretionary to being mandatory for the years specified (see Table 1 for PILT funding since FY2005). Since 2008, Congress has amended Section 6906 several times by changing the fiscal year in the first line through both annual discretionary appropriations laws and other legislative vehicles ( Table 1 ). PILT was funded through discretionary appropriations from its enactment through FY2007. Since FY2008, Congress has provided funding for PILT through both discretionary and mandatory appropriations ( Table 1 ). From FY2008 through FY2014, Congress authorized mandatory funding for PILT through several laws . Since FY2015, funding has been provided, at least partially, through the annual appropriations process. In FY2015, PILT received both discretionary and mandatory appropriations. For FY2016 through FY2020, Congress funded PILT through the annual appropriations process. In FY2016 and FY2017, the appropriations laws provided specific funding levels for PILT, which was treated as discretionary spending. In FY2018, FY2019, and FY2020, the appropriations laws provided funding for PILT by amending the authority provided in 31 U.S.C. Â§6906, which was treated as mandatory spending. In each of these three years, funding was provided for PILT at the full statutory calculation levels. Since FY2008, Congress has provided funding for PILT through both one-year and multiyear appropriations. Congress's actions have resulted in full funding and partial funding in different years ( Table 1 and Figure 1 ). These types of changes from year to year may have implications for counties that rely on PILT funding as part of their annual budgets. In addition to appropriating funding for the program, Congress routinely provides other guidance on PILT within the annual appropriations process, such as minimum payment thresholds, set-asides for program administration, and provisions for prorating payments. When appropriated funding is insufficient to cover the full amount for authorized payments under Sections 6902, 6904, and 6905, counties typically receive a proportional payment known as a prorated payment ( Figure 1 shows the disparity between the authorized amount and the appropriated amount in recent years). Even in years in which appropriations are set equal to 100% of the full statutory calculation, payments to counties may be prorated if funding is set aside for purposes other than payments, such as administration. PILT Payments Under Section 6902 Section 6902 payments are provided to units of local government jurisdictions (referred to as counties in this report) across the United States to compensate for the presence of entitlement lands within their boundaries. Section 6902 payments also are provided to the District of Columbia, Guam, Puerto Rico, and the Virgin Islands. Section 6902 payments account for nearly all of the payments made under PILT. In FY2019, 99.85% of all PILT payments were made through Section 6902. Further, more counties are eligible for Section 6902 payments than either Section 6904 or Section 6905 payments. In FY2019, of the 1,931 counties that received PILT payments, 1,927 received payments under Section 6902, and 134 received payments under Section 6904 and/or Section 6905 (130 counties received payments under both Section 6902 and Section 6904 and/or Section 6905). Entitlement Lands There are nine categories of federal lands identified as entitlement lands in the PILT statute. 1. Lands in the National Park System 2. Lands in the National Forest System 3. Lands administered by the Bureau of Land Management (BLM) 4. Lands in the National Wildlife Refuge System (NWRS) that are withdrawn from the public domain 5. Lands dedicated to the use of federal water resources development projects 6. Dredge disposal areas under the jurisdiction of the U.S. Army Corps of Engineers 7. Lands located in the vicinity of Purgatory River Canyon and PiÃ±on Canyon, CO, that were acquired after December 31, 1981, to expand the Fort Carson military reservation 8. Lands on which are located semi-active or inactive Army installations used for mobilization and for reserve component training 9. Certain lands acquired by DOI or the Department of Agriculture under the Southern Nevada Public Land Management Act ( P.L. 105-263 ) Of these categories, the first three (National Park System, National Forest System, and lands administered by BLM) largely account for all of the lands managed by the relevant agencies. The remaining categories are either lands tied to specific laws or actions (categories 7 and 9, above) or lands that represent a subset of the lands administered by a particular agency. For example, entitlement lands that are included within the NWRS (category 4) only account for lands within the system that have been withdrawn from the public domain, which excludes lands that have been purchased as additions to the NWRS. Further, lands administered by the U.S. Fish and Wildlife Service that are not included in the NWRS are not included within the definition of entitlement lands. Similarly, lands in the other categories (5, 6, and 8, above) may not include all, or even the majority of, lands administered by particular agencies or departments. Calculating Section 6902 Payments Section 6902 payments are determined based on a multipart formula (see Figure 2 ). The DOI Office of the Secretary calculates PILT payments according to several factors, including the number of entitlement acres; a per-acre calculation determined by one of two alternatives (Alternative A, also called the standard rate , or Alternative B, also called the minimum provision ); a population-based maximum payment (ceiling); certain prior-year payments pursuant to other compensation programs; and the amount available to cover PILT payments. To calculate a particular county's PILT payment, the DOI Office of the Secretary first must collect data from several federal agencies and the county's state to answer the following questions: How many acres of eligible lands are in the county? What is the population of the county? What was the increase in the Consumer Price Index for the 12 months ending the preceding June 30? What were the prior year's payments, if any, for the county under the other payment programs of federal agencies? Does the state have any laws requiring the payments from other federal land payment laws to be passed through to other local government entities, such as school districts, rather than stay with the county government? The first step in calculating a county's Section 6902 payment is to determine the number of entitlement acres within the county ( Figure 2 , Box A). The next step is to calculate the population-based ceiling by multiplying the county's population by the population payment rate ( Figure 2 , Box B). County population data are provided by the U.S. Census Bureau. For this calculation, counties with different populations are treated differently ( Figure 3 ): For counties with populations smaller than 5,000, a county's actual population is used in the calculation . For counties with populations larger than 5,000, a county's population is rounded to the nearest 1,000, and this rounded population is used in the calculation. All counties with populations greater than 50,000, regardless of their actual populations, are considered to have a population equal to 50,000 for the purposes of calculating the ceiling. The population payment rate generally declines as population increases in 1,000 person increments (per statute), although the population-based ceiling generally increases ( Figure 4 ). However, this is not always the case. For example, in FY2019, payment rates for several populations are the same despite increasing populations, such as the rates for populations of 26,000; 27,000; and 28,000, which are all $94.98. Further, some payment ceilings do not increase with increasing populations. For example, counties with populations of 50,000 have a lower ceiling than those with populations of 49,000 (49,000 Ã $76.33 = $3,740,170; and 50,000 Ã $74.63 = $3,731,500, or $8,670 less for the more populous county). The population payment rate is adjusted annually for inflation based on the change in the Consumer Price Index for the 12 months ending on the preceding June 30. For FY2019, the population payment rates ranged from $186.56 per person for counties with populations of 5,000 or fewer to $74.63 per person for counties with populations of 50,000 or greater. The next step is to calculate the payment level under alternatives A and B ( Figure 2 , Box C). Alternative A has a higher per-acre payment rate than Alternative B, but Alternative A is subject to a deduction for prior-year payments. Prior-year payments are those payments from the federal payment programs listed in statute: the Act of June 20, 1910 (ch. 310, 36 Stat. 557); Section 33 of the Bankhead-Jones Farm Tenant Act (7 U.S.C. Â§1012); the Act of May 23, 1908 (16 U.S.C. Â§500), or the Secure Rural Schools and Community Self-Determination Act of 2000 (16 U.S.C. Â§Â§7101 et seq.); Section 5 of the Act of June 22, 1948 (16 U.S.C. Â§Â§577g-577gâ1); Section 401(c)(2) of the Act of June 15, 1935 (16 U.S.C. Â§715s(c)(2)); Section 17 of the Federal Power Act (16 U.S.C. Â§810); Section 35 of the Act of February 25, 1920 (30 U.S.C. Â§191); Section 6 of the Mineral Leasing Act for Acquired Lands (30 U.S.C. Â§355); Section 3 of the Act of July 31, 1947 (30 U.S.C. Â§603); and Section 10 of the Act of June 28, 1934 (known as the Taylor Grazing Act) (43 U.S.C. Â§315i). However, if a state has a pass - through law that requires some or all of these prior-year payments to be paid directly to a sub-county recipient (e.g., a school district), these payments are not deducted from subsequent PILT payments in the following year. Alternative B is calculated using a lower per-acre payment rate, but prior-year payments are not deducted. For FY2019, the per-acre payment rates were $2.77 per acre of entitlement land for Alternative A and $0.39 per acre of entitlement land for Alternative B. If the per-acre payment (number of acres multiplied by the per-acre payment rate) calculated under either alternative is greater than the population-based ceiling, then the population-based ceiling replaces the calculated amount. Once each alternative is calculated, the greater of the two is the Section 6902 authorized payment for the county ( Figure 2 , Box D). The Section 6902 authorized payments are calculated for every county, and this amount is added to the Section 6904 and Section 6905 authorized payments (for more information on Sections 6904 and 6905, see " PILT Payments Under Sections 6904 and 6905 "). This summed amount is the full statutory calculation for a given fiscal year ( Figure 2 , Box E). DOI compares the full statutory calculation with the amount appropriated and available for PILT payments to determine whether Congress has provided adequate funding to cover the full statutory calculation ( Figure 2 , Box F). If sufficient funding is available, each county receives its authorized amount; if funding is insufficient, each county receives a prorated payment that is proportional to its authorized payment ( Figure 2 , Box G). The full statutory calculation and the amount available for PILT payments determine proration. Although there are additional adjustments made in the PILT proration calculation resulting from small idiosyncrasies related to the requirements for PILT paymentsânamely, the requirement of a minimum threshold of $100 for PILT payments âthe proration is fundamentally the ratio of the appropriated funding available for PILT payments to the full statutory calculation: As a result, counties may receive less than their authorized PILT payment in years when appropriated funding is insufficient to cover the full statutory calculation. This scenario can occur even when total PILT appropriations match the full statutory calculation; this has been the case in years with mandatory appropriations, when part of the appropriated amount is set aside for a use other than county payments. For example, laws providing appropriations for PILT routinely have allowed DOI to retain a small portion of PILT appropriations for administrative expenses. PILT Payments Under Sections 6904 and 6905 Section 6904 and Section 6905 payments account for a small fraction of total PILT payments. In FY2019, these payments were made to 134 counties and accounted for 0.15% of PILT payments ($750,605 of $514.7 million in total payments made). Once a county receives Section 6904 and Section 6905 payments, it is to disburse payments to governmental units and school districts within the county in proportion to the amount of property taxes lost because of the federal ownership of the entitled lands, as enumerated under these sections. County units and school districts may use these payments for any governmental purpose. Section 6904 Payments Section 6904 authorizes the Secretary of the Interior to make payments to counties that contain certain lands, or interests in lands, that are part of the National Park System and National Forest Wilderness Areas. However, Section 6904 specifies that these lands, or interests, are eligible only if (1) they have been acquired by the U.S. government for addition to these systems and (2) they were subject to local property taxes in the five-year period prior to this acquisition. Payment under Section 6904 is calculated as 1% of the fair market value of the land at the time it was acquired, not to exceed the amount of property taxes levied on the property during the fiscal year prior to its acquisition. Further, Section 6904 payments are made annually only for the five fiscal years after the land, or interest, is acquired by the U.S. government, unless otherwise mandated by law. Section 6905 Payments Section 6905 authorizes the Secretary of the Interior to make payments to counties that contain lands, or interests, that are part of the Redwood National Park and are owned by the U.S. government or that are acquired by the U.S. government in the Lake Tahoe Basin under the Act of December 23, 1980. Section 6905 payments are paid at a rate of (1) 1% of the fair market value of the acquired land or interests or (2) the amount of taxes levied on the land in the year prior to acquisition, whichever is lesser. Payments on these lands continue for five years or until payments have totaled 5% of the fair market value of the land. Issues for Congress PILT is of perennial interest to many in Congress and to stakeholders throughout the country. County governments are particularly interested in the certainty of PILT payments, as well as in how payments are calculated, because many consider PILT payments to be an integral part of their annual budgets. Congressional and stakeholder interests include questions of how PILT should be funded, what lands should be included as entitlement lands, and how authorized payment levels are calculated under PILT, among others. Congress annually addresses questions of how funding should be provided to PILT. Congress has funded PILT through both mandatory and discretionary appropriations (see " PILT Authorizations and Appropriations "). More often than not, PILT funding has been provided through the discretionary appropriations process for one fiscal year at a time. Although PILT has consistently received funding since its enactment, the appropriations process has created uncertainty among some stakeholders about the level of annual funding. Stakeholders also have asserted that greater certainty, in terms of both the guarantee of funding and the amount of funding (i.e., full statutory calculation) would be better. Members of Congress typically contemplate the implications and tradeoffs of discretionary versus mandatory spending and may have different views than the counties that receive PILT payments. Congress, for example, may weigh its discretion to review and fund PILT on an annual basis through the appropriations process against the certainty of funding for specific activities that accompany mandatory appropriations. Several bills have been introduced to amend how PILT is funded. For example, legislation has been introduced in the 116 th Congress that would require mandatory funding for PILT for either a set period of time (e.g., 10 additional years) or indefinitely. The question of which lands should be eligible for PILT payments is also of interest to many Members and stakeholders. In law, entitlement lands are restricted to the listed federal land types (see " Entitlement Lands "). However, this definition does not fully encompass the types of lands that are held by the federal government, nor does it account for the full suite of lands that are exempt from state and local taxes. Although some of these other lands may receive compensation through other federal programs, not all do, which may cause financial hardships for counties that otherwise might receive revenue through taxation. To address this concern, some Members of Congress have contemplated amending the definition of entitlement lands under PILT. For example, past Congresses have introduced legislation that would have amended PILT by expanding the definition of entitlement land to include land "that is held in trust by the United States for the benefit of a federally recognized Indian tribe or an individual Indian"; lands under the jurisdiction of the Department of the Defense, other than those already included in PILT; lands acquired by the federal government for addition to the National Wildlife Refuge System; and lands administered by the Department of Homeland Security, among others. Amending the definition of entitlement lands could have several implications. Adding additional acres of entitlement lands could increase the authorized amount of payments under PILT, which likely would benefit those states with the added lands but not states that lack additional lands. This, in turn, could influence how Congress elects to fund PILT. Additional entitled lands may be eligible for other compensation programs, which could further affect PILT payments. The authorized payment level under Section 6902, which accounts for nearly all payments under PILT, is calculated pursuant to the statutory requirements. This section has remained largely unchanged since it was amended in 1994 to add the requirement to adjust for inflation, among other changes. The inflation adjustment clause has resulted in increasing payment and ceiling rates since that time. Congress routinely considers whether the current formula is the best means of calculating payments under PILT or whether the formula should be amended. For example, in the 116 th Congress, bills have been introduced that would adjust the payment structure for counties with a population of less than 5,000. This adjustment would have implications for how population or area would be incorporated into calculating PILT payments and whether PILT payments were provided in an equitable manner. PILT is of interest to a large number of counties and other state and local entities across the country, and it may remain of interest to many Members of Congress. In addition to the above issues, Congress may consider other issues related to PILT and how the program fits into the landscape of federal programs that compensate for the presence of tax-exempt federal lands.