prompt_front: You are given two reports by the government agency.



Question: Write a one-page summary of the report 1.



Report 2: The combination of growing supplies of liquefied natural gas (LNG) and new requirements for less polluting fuels in the international maritime shipping industry has heightened interest in LNG as a maritime fuel  For decades, LNG tanker ships have been capable of burning boil-off gas from their LNG cargoes as a secondary fuel  However, using LNG as a primary fuel is a relatively new endeavor; the first LNG-powered vessel—a Norwegian ferry—began service in 2000  Several aspects of LNG use in shipping may be of congressional interest  LNG as an engine, or "bunker," fuel potentially could help the United States reduce harmful air emissions, it could create a new market for domestic natural gas, and it could create economic opportunities in domestic shipbuilding  However, U S  ports would need specialized vessels and land-based infrastructure for LNG "bunkering" (vessel refueling) as well as appropriate regulatory oversight of the associated shipping and fueling operations  The storage, delivery, and use of LNG in shipping also has safety implications  These and other aspects of LNG bunkering may become legislative or oversight issues for Congress  One bill in the 115 th Congress, the Waterway LNG Parity Act of 2017 ( S  505 ), would have imposed excise taxes on LNG used by marine vessels on inland waterways  This report discusses impending International Maritime Organization (IMO) standards limiting the maximum sulfur content in shipping fuels, the market conditions in which LNG may compete to become a common bunker fuel for vessel operators, and the current status of LNG bunkering globally and in the United States  A broader discussion of oil market implications is outside the scope of this report  The IMO is the United Nations organization that negotiates standards for international shipping  Its standards limiting sulfur emissions from ships, adopted in 2008, have led vessel operators to consider alternatives to petroleum-based fuels to power their ships  In 1973, the IMO adopted the International Convention for the Prevention of Pollution from Ships (MARPOL)  Annex VI of the convention, which came into force in 2005, deals with air pollution from ships  The annex established limits on nitrogen oxide (NO x ) emissions and set a 4 5% limit on the allowable sulfur content in vessel fuels  In 2008, the IMO announced a timeline to reduce the maximum sulfur content in vessel fuels from 4 5% to 0 5% by January 1, 2020  Annex VI requires vessel operators to either use fuels containing less than 0 5% sulfur or install exhaust gas-cleaning systems ("scrubbers") to limit a vessel's sulfur oxide (SO x ) emissions to a level equivalent to the required sulfur limit  MARPOL is implemented in the United States through the Act to Prevent Pollution from Ships ()  The United States effectively ratified MARPOL Annex VI in 2008 when President Bush signed the Maritime Pollution Prevention Act ( P L  110-280 )  The act requires that the U S  Coast Guard and the Environmental Protection Agency (EPA) jointly enforce the Annex VI emissions standards  MARPOL's Annex VI requirements are codified at 40 C F R  §1043  They apply to U S -flagged ships wherever located and to foreign-flagged ships operating in U S  waters  In addition to its global sulfur standards, MARPOL Annex VI provides for the establishment of Emissions Control Areas (ECAs), which are waters close to coastlines where more stringent emissions controls may be imposed  The North American ECA limits the sulfur content of bunker fuel to 0 1% of total fuel weight, an even lower bar than that set by the IMO 2020 standards  This standard is enforced by Coast Guard and EPA in waters up to 200 miles from shore  Currently, most ships operating in the North American ECA meet the emissions requirements by switching to low-sulfur fuels once they enter ECA waters  The European Union also has an ECA with a 0 1% limit on sulfur in bunker fuels, and the Chinese government is considering putting the same standard in place  The IMO 2020 emissions requirement applies to vessels of 400 gross tons and over, which is estimated to cover about 110,000 vessels worldwide  However, analysts indicate that many of the smaller vessels in this group already burn low-sulfur fuel  Accounting for these smaller vessels, one estimate is that about 55,000 vessels currently burn high-sulfur fuel  Ship owners have two main options for meeting the emission requirements with existing engines: burn low-sulfur conventional fuel (or biofuels) or install scrubbers to clean their exhaust gases  Alternatively, ship owners may opt to install new LNG-fueled engines to comply with the IMO standard  The simplest option for vessel owners to comply with the IMO sulfur standards, and the one that appears most popular, is switching to low-sulfur fuel oils or distillate fuels  Although switching to low-sulfur fuels would increase fuel costs compared to conventional, high-sulfur fuels, it would require little or no upfront capital cost and would allow ocean carriers to use existing infrastructure to bunker ships at ports  Anticipating widespread adoption of this approach, many analysts predict that the implementation of the IMO 2020 regulations will drive up demand for low-sulfur fuel and, therefore, significantly increase its price above current levels  Such a trend could also reduce demand for high-sulfur fuels, increasing the price spread between low- and high-sulfur bunkers fuels  Switching to lower-sulfur fuel could increase fuel cost across the industry by up to $60 billion in 2020 for full compliance with the IMO standards  Moreover, while it may allow vessels to meet the existing IMO sulfur standards, low-sulfur fuel does not necessarily support compliance with potential future IMO emissions standards, especially with respect to greenhouse gases (GHGs) such as carbon dioxide (CO 2 ) discussed later in this report  Scrubbers are systems which remove sulfur from a vessel's engine exhaust emissions  A ship with a scrubber would be capable of meeting the IMO 2020 standard while using conventional high-sulfur fuel  Retrofitting a scrubber on an existing engine can cost several million dollars, however, before factoring in the lost revenue from taking the ship out of service for a month for the installation  Therefore, while using a scrubber will allow a ship to continue using (currently) cheaper high-sulfur fuel, it may take years to recover the initial investment  For example, one industry study estimates that, in the case of a typical tanker, a scrubber installation could cost $4 2 million with a payback time of approximately 4 8 years  Furthermore, scrubbers installed to capture sulfur emissions might have to be further refitted or replaced to comply with any future IMO standards for GHG emissions  The rate of scrubber adoption could affect the financial impacts of installing them in terms of fuel costs  Scrubbers ultimately offset some or all of their initial costs because they allow vessel operators to continue using relatively inexpensive high-sulfur fuel  However, the return on investment for scrubbers depends on the relative prices of high- and low-sulfur bunker fuels  The demand—and therefore, prices—for low-sulfur and high-sulfur fuels will be affected by how many vessels use the respective fuels under the IMO standards that take effect in 2020  For example, limited scrubber adoption could result in more vessels demanding more low-sulfur fuel oil, creating upward pressure on low-sulfur fuel prices  Under such a scenario, scrubbers would provide greater fuel cost savings for vessels that installed them  Alternatively, high-sulfur fuel could become more costly due to refinery production cutbacks (because shippers will not be allowed to burn it without scrubbers)  In this case, the economic benefits of scrubbers would be diminished  Given the uncertain fuel supply and demand dynamics, it is difficult for vessel operators to know how big the market distortions from scrubber installation could be or how many other operators may choose to install scrubbers  As of September 2018, there were approximately 660 ships retrofitted with scrubbers and over 600 ships under construction with plans to install scrubbers  By 2020, projecting additional construction orders, some analysts predict about 2,000 vessels could have scrubbers installed  However, even with higher demand for the technology, the ability of vessel owners to install scrubbers is constrained; analysts estimate that current maximum capacity for installing scrubbers is be between 300 to 500 ships per year  Another option for ship owners to comply with the IMO 2020 sulfur standards is to switch to engines that burn LNG as a bunker fuel  LNG-fueled vessels emit only trace amounts of sulfur oxides in their exhaust gases—well below even the 0 1% fuel-equivalent threshold in some of the ECA zones—so they would be fully compliant with the IMO standards  As a secondary benefit, using LNG as an engine fuel also would reduce particulate matter (PM) emissions relative to both high- and low-sulfur marine fuel oils  Furthermore, LNG vessels have the potential to emit less CO 2 than vessels running on conventional, petroleum-based fuels  However, LNG vessels would have the potential to result in more fugitive emissions of methane, another GHG, because methane is the primary component of natural gas, further discussed below  Installing an LNG-fueled engine can add around $5 million to the cost of a new ship  Retrofitting existing ships appears to be less desirable because of the extra space required for the larger fuel tanks (new ships can be designed with the larger fuel tanks)  The costs of retraining crews to work with LNG engines could also factor into a vessel operator's decision about switching to LNG  However, apart from their lower emissions, LNG-fueled engines may offset their capital costs with fuel cost advantages over engines burning petroleum-derived fuels  These savings would depend on the price spread between natural gas and fuel oil—which has been volatile in recent years  The likelihood that switching to LNG will produce long-term fuel costs savings relative to conventional fuels is, therefore, a critical consideration for many vessel owners  The 1920 Merchant Marine Act (known colloquially as the Jones Act) requires that vessels engaged in U S  domestic transport be built domestically  Many newly built domestic ships receive a federal loan guarantee under the Maritime Administration's so-called "Title XI" program  In 2014, the program was modified to include the use of "alternative energy technologies" to power ships as part of the relevant criteria in evaluating a loan application  The Maritime Administration counts LNG-fueled engines as an "alternative energy technology" and may be more likely to approve loan applications for ships with LNG-capable engines  Since the North American ECA was established in 2015, Jones Act coastal ship operators have taken steps to transition their fleets to use cleaner burning fuels, including LNG  The three Jones Act operators that ship dry goods to Alaska, Hawaii, and Puerto Rico have taken delivery or have ordered LNG-fueled and LNG-capable vessels from U S  shipyards in Philadelphia, PA, and Brownsville, TX  Harvey Gulf International has put into service five LNG-powered offshore supply vessels that service offshore oil rigs  Some Jones Act tanker operators that have recently built or ordered vessels have chosen to install LNG-ready engines while other operators have chosen to install scrubbers on their existing fleet  Ship engines and scrubbers for the Jones Act fleet do not have to be manufactured in the United States because they are not considered an integral part of the hull or superstructure of a ship  Seagoing barges, known as articulated tug barges, are also a significant portion of the domestic coastal fleet, especially for moving liquid cargoes  However, these vessels traditionally have burned lower-sulfur fuels and thus the ECA has not prompted fleet conversions  IMO fuel requirements do not apply to river barges operating on the nation's inland waterway system, although this fleet potentially could be a market for LNG as fuel  Bunkering vessels (small tankers with hoses for refueling ships) in U S  waters must also be Jones Act compliant  Barges are the predominant method for bunkering ships in U S  ports  An LNG bunkering vessel for the Port of Jacksonville—the first Jones Act-compliant LNG bunkering vessel to enter service in the United States—was built in 2017 by Conrad Shipyards in Orange, TX  Recent energy sector trends suggest that LNG may be cheaper in the long-run than petroleum-based, low-sulfur fuels  However, these price movements are correlated to some extent  Many existing long-term LNG contracts link LNG prices to oil prices (although such contract terms are on the decline), even in the spot market  Starting in 2008, the advent of shale natural gas production dramatically decreased natural gas prices in the United States  Natural gas spot prices in the United States at the Henry Hub—the largest U S  trading hub for natural gas—averaged around $3/MMBtu (million British Thermal Units) in 2018, about a quarter of the peak in average price a decade before, just prior to the shale gas boom ( Figure 1 )  Liquefying natural gas into LNG adds around $2/MMBtu to the production cost  Including additional producer charges and service costs would bring the total cost of LNG available at a U S  port (based on the 2018 average price in Figure 1 ) to approximately $6/MMBtu  Shipping of LNG from the United States to Asia or Europe adds from $1 to $2/MMBtu, so, based on the 2018 average cost in Figure 1 , LNG delivered to a port overseas would cost on the order of $7 to $8/MMbtu under long-term contracts, depending upon timing and location  Higher or lower prices could occur for specific long-term contracts and in the LNG spot market (i e , for individual cargoes), based on the location and the supply and demand balance at the time  In general, the U S  market will have the lowest-priced LNG  Northern Asia will have the highest LNG prices due to the region's comparative lack of pipeline gas supplies and its distance from LNG suppliers  Figure 2 compares LNG spot market prices in the Japan LNG market—the highest-priced LNG market—to spot prices for two common petroleum-based bunker fuels, low-sulfur gas oil and high-sulfur fuel oil  As the figure shows, over the last five years, Japan LNG generally has been cheaper than low-sulfur fuel and more expensive than high-sulfur fuel on an energy-equivalent basis (i e , per MMbtu)  However, Japan LNG and high-sulfur fuel prices converged in 2018  As the figure shows, spot prices for LNG deliveries to the Japan market fell below $6/MMBtu in 2016 from a high above $16/MMBtu in 2013  Likewise, low-sulfur gas oil prices have doubled, and high-sulfur fuel oil prices have tripled, since 2016  The volatility of the bunker fuel markets and the global LNG market lead to considerable unpredictability about the relative prices among fuels going forward  LNG may become increasingly price-competitive versus low-sulfur fuel as the 2020 IMO sulfur standards take effect  As discussed above, many analysts predict prices for low-sulfur gas oil, which are already higher than those for high-sulfur fuel oil, to increase significantly after 2020 due to a standards-driven rise in demand  Although fuel prices as shown in Figure 2 indicate favorable economics for LNG versus low-sulfur fuel, if prices for high-sulfur fuel oils collapse as some expect after the 2020 IMO regulations enter into force, it is possible that LNG could lose its price advantage over residual fuel oils  Likewise, the price spread between low-sulfur gasoil and high-sulfur fuel oil would increase, incentivizing more carriers to install scrubbers to capitalize on the savings in fuel costs by continuing to burn high-sulfur fuel  An additional complication is the variability of LNG prices by region  Many shipping lines are global operators seeking low-priced fuel worldwide, but unlike the global oil market, natural gas markets are regional  Because the price of LNG can vary significantly by region, the relative economics of LNG versus other bunker fuels would also vary by region  Another uncertainty in the market for LNG bunkering is the discrepancy between the spot price for traded LNG and the price for LNG sold as bunker fuel in ports  Added costs associated with marketing, storing and transporting LNG in bunkering operations (discussed below) would likely require ports to charge a rate for LNG bunker fuel above spot market prices  These additional overhead costs are likely to vary among ports  Before factoring in any effect of IMO standards on fuel prices, and assuming a favorable LNG-fuel oil price spread, it still could take years for the savings generated by using LNG to pay back the capital costs of switching fuels  Through May 2018, there were 122 LNG-powered vessels in operation and another 135 ordered or under construction  Many of the first LNG vessels delivered and ordered were Norwegian-flagged vessels, as the Norwegian government has subsidized LNG-fueled vessels with a "NO x Fund " The fund provides LNG-operated ships with an exemption from the country's tax on NO x emissions  As an alternative to committing to LNG as a fuel, some vessel owners may hedge their bets by opting to install "LNG-ready" engines, which can burn low-sulfur fuel oil currently, but are designed to make future LNG conversion easier  The number of LNG ships that may be in operation by 2030 is difficult to predict  First, as noted above, growth in LNG powered vessels is likely to be driven primarily by new builds rather than retrofits  However, the shipping industry has experienced nearly a decade of vessel overcapacity and slow growth  Weak growth in the shipping industry could result in slower growth in vessel orders overall and, therefore, fewer orders for LNG-powered vessels  Of new vessels ordered, or set to be delivered, in 2018 or after, 13 5% (by tonnage) are LNG-fueled—up from 1 4% in 2010  If this trend continues, demand for LNG from the shipping industry could still be relatively high, even if overall growth in the shipping industry remains slow  Because LNG bunkering infrastructure among global ports is currently limited, vessels that use large amounts of fuel and travel predictable routes—along which LNG is available—are the most suitable for LNG fuel  For this reason, cruise ships, vehicle ferries, and container ships initially may be the most likely vessel types to adopt LNG as bunker fuel  Order books have reflected this assessment: one quarter of all cruise ships on order by tonnage at the end of 2017 were LNG-powered  Likewise, a major container ship line, CMA CGM, recently announced that it was ordering nine extra-large container ships powered by LNG  The carrier stated that the fuel tanks will displace space for "just a few containers" and said it intends to refuel these ships just once on their round trip voyages between Asia and Europe  Conversely, LNG fuel adoption may be less likely for oil tankers  Half the global oil tanker fleet operates on the shipping spot market (also known as the "tramp" market), meaning that ship owners enter into contracts with cargo owners only for a single voyage  In this kind of trade, many oil tankers lack a consistent route  Having to limit spot contracts only to ports that may bunker LNG could reduce the arbitrage opportunities of tankers  Dry bulk cargo vessels (carrying grain, coal, and other commodities) also typically operate in the tramp market  LNG-powered vessels have lower direct exhaust emissions than comparable vessels using petroleum-derived fuels  However, the lifecycle—or "well-to-wake"—GHG emissions (especially of methane) and of volatile organic compound emissions from natural gas production, transportation, and liquefaction complicates the comparison  One study in 2015 concluded, "performing a ['well-to-wake'] GHG study on LNG used as a marine fuel is more complex than previously thought  Further studies are needed     to investigate this subject " A 2016 study found that the relative GHG emissions benefits of LNG versus conventional fuel oil on a "well-to-wake" basis was highly dependent upon fugitive methane emissions in the LNG supply chain  A 2017 study funded by NGVA Europe, an association which promotes the use of natural gas in vehicles and ships, concluded that LNG as a bunker fuel provides a 21% well-to-wake reduction in GHG emissions compared to convention fuel oil  Evaluating such studies is beyond the scope of this report, although they indicate uncertainty about environmental benefits of LNG fuel, which may require further examination  Despite concerns over lifecycle emissions from the natural gas supply chain, in the short term, ships that pair LNG engines with newer vessel designs could reduce onboard GHG emissions  However, whether these GHG emission reductions would be sufficient to meet the future standards could become another issue for ship owners  The IMO has set a provisional goal of reducing GHG emissions from ships by 50% by 2050  Depending upon the state of engine technology, LNG-fueled ships might become less viable if GHG limits were to be established well before 2050  Concerns about such GHG limits might lead to a decrease in orders of LNG-powered ships over time  Commercial vessels have a typical lifespan of over 20 years, so firms ordering new ships have to take into account compliance with potential standards issued decades in the future  If renewable fuels, such as biodiesel, become more available and cheaper in the coming decades, renewable fuel-powered ships may take over part of the market that LNG-powered ships could occupy  A key requirement for ocean carriers to adopt LNG as an engine fuel is the availability of LNG bunkering facilities  Because LNG is extremely cold (-260 °F) and volatile, LNG bunkering requires specialized infrastructure for supply, storage, and fuel delivery to vessels  Depending upon the specific circumstances, LNG bunkering could require transporting LNG to a port from an offsite liquefaction facility for temporary storage at the port, or building an LNG liquefaction terminal on site  Alternatively, LNG could be delivered from offsite facilities directly to vessels in port via truck or supply vessel ( Figure 3 )  Truck-to-vessel LNG bunkering, in particular, provides some fueling capabilities without large upfront capital investments  LNG tanker trucks could also bring LNG to a storage tank built on site at the port, which could then bunker the LNG to arriving ships via pipeline  Supplying LNG using tanker trucks in this way may face capacity limitations due to truck size, road limitations, or other logistical constraints, but it has been demonstrated as a viable approach to LNG bunkering at smaller scales  The predominant method of bunkering today with high-sulfur fuel is vessel to vessel, either by a tank barge or smaller tanker  The type of infrastructure needed to temporarily store (if needed) and deliver LNG within a given port would depend on the size and location of the port, as well as the types of vessels expected to bunker LNG  Truck to ship bunkering is best suited for supporting smaller and mid-sized vessels, such as ferries or offshore supply vessels (OSVs) that support offshore oil platforms  Liquefaction facilities built on site can provide the greatest capacity of any LNG bunkering option, for example, to provide fuel for large vessels in transoceanic trade  However, constructing small-scale liquefaction facilities to produce and deliver LNG on site requires considerable planning and significant capital investment, in one case on the order of $70 million for a mid-sized port  Each LNG bunkering option in Figure 3 may be a viable means to begin LNG bunkering service in a given port  However, ports may face practical constraints as bunkering increases in scale  For example, a container port of significant size typically has multiple terminals, so even with an on-site liquefaction facility, it may need additional infrastructure or supply vessels for moving LNG to other port locations where a cargo ship might be berthed  There may also be port capacity and timing constraints upon the movement of LNG bunkering barges trying to refuel multiple large vessels in various locations around a crowded port  To date, the LNG bunkering operations already in place or in development are comparatively small, but scale constraints could become a factor as LNG bunkering grows and might require additional bunkering-related port investments  Early adoption of LNG bunkering occurred in Europe, where the first sulfur ECAs were created in 2006 and 2007  Through Directive 2014/94/EU, the European Union requires that a core network of marine ports be able to provide LNG bunkering by December 2025 and that a core network of inland ports provide LNG bunkering by 2030  This mandate has been promoted, in part, with European Commission funds to support LNG bunkering infrastructure development  In addition, the European Maritime Safety Agency published regulatory guidance for LNG bunkering in 2018  Over 40 European coastal ports have LNG bunkering capability currently in operation—primarily at locations on the North Sea and the Baltic Sea, and in Spain, France, and Turkey  These locations include major port cities such as Rotterdam, Barcelona, Marseilles, and London  Another 50 LNG bunkering facilities at European ports are in development  LNG bunkering is also advancing in Asia, led by Singapore, the world's largest bunkering port  Singapore has agreed to provide $4 5 million to subsidize the construction of two LNG bunkering vessels  The Port of Singapore plans to source imported LNG at the adjacent Jurong Island LNG terminal, loading it into the bunkering vessels for ship-to-ship fueling of vessels in port  Singapore also has signed a memorandum of understanding with 10 other partners—including a Japanese Ministry and the Chinese Port of Ningbo-Zhoushan—to create a focus group aimed at promoting the adoption of LNG bunkering at ports around the world  In Japan, one consortium is implementing plans to begin vessel-to-vessel LNG bunkering at the Port of Keihin in Tokyo Bay by 2020
Report 2:  For rural carriers, the most recently updated scanning procedures we found was dated 2013  As a result, some of these documents are not updated with the latest information on new scanning procedures  In a related example, the USPS OIG recently found that employees at three of the six USPS facilities the USPS OIG visited did not have an adequate understanding of the procedures for processing election and political mail due, in part, to guidance that was not updated, even though the procedures were centrally documented on an internal USPS website  USPS officials recognized this issue and stated that these handbooks are not updated regularly as the content of the handbooks are subject to labor negotiations  Therefore, new procedures are presented to USPS employees outside of the handbooks  However, given that these efforts rely on employees to orally communicate information, having consistent documented procedures is even more important  In addition to stating that the organization should deploy control activities through policies and procedures, the COSO Framework states that senior management should communicate objectives clearly through the organization so that other management and personnel understand their individual roles in the organization  By not having consistent procedures, USPS risks not clearly communicating to its employees how they should carry out scanning procedures and therefore contributing to scanning errors  As discussed below, USPS officials told us that management updates its procedures typically through regular meetings with employees, which are documented in handouts or slides  USPS officials stated that management stresses the importance of scanning and that employees should follow the prompts on their electronic devices when scanning competitive products  However, employees can still scan competitive products as delivered even if they are not, as device prompts can be misread, misinterpreted, or ignored  Furthermore, even with current prompts, scanning errors can and do occur  Consistent procedures, clearly communicated to employees, have become increasingly important as USPS hires new employees to handle, in part, anticipated growth in the volume of competitive packages  For example, GAO analysis of USPS data showed that USPS’s carrier workforce increased by 6 4 percent between fiscal years 2015 and 2017  The USPS OIG has found that these new employees require training and guidance to properly perform their roles and to reduce turnover  In addition to deploying policies and procedures to achieve an organization’s objectives, the COSO Framework states that an organization should internally communicate objectives and responsibilities that are necessary to support the functioning of internal controls  This process can be accomplished through training and meetings  Specifically, the COSO Framework states that training should enable individuals to develop competencies appropriate for assigned roles and responsibilities, among other things, and that active forms of communication such as face-to-face meetings are often more effective than passive forms such as broadcast e-mails and intranet postings  To communicate how its procedures should be correctly implemented, USPS has developed both initial and on-going training for employees  USPS officials stated that new employees are formally trained in scanning procedures when they start their employment  For example, carriers are trained how to use USPS’s electronic scanning devices, when to scan competitive items, the correct codes to use for different delivery situations (i e , signature required, vacation holds, how to code where a package was left at a delivery address)  Any new procedures can be introduced through presentations given by managers during meetings, as described below  Required regular meetings may be tracked by USPS management to ensure they are completed  Some district officials we spoke with stated that they certify that their employees have received required training and send that certification to area and USPS headquarters officials  Additional training also helps USPS reinforce correct scanning procedures  When scanning procedures are not being followed or scanning goals are not met at a post office, USPS officials stated that reminders of the correct procedures designed to reinforce USPS’s scanning procedures are presented to employees through presentations, posters, job aids, and additional documents such as carriers’ handbooks  For example, the representative of the major mailer we spoke with that had 8 to 10 percent of competitive products not scanned to the final delivery address stated that training was needed for both new and experienced carriers to reinforce that they should scan items at the delivery address  To further ensure the accurate scanning of competitive products, USPS reported that it holds internal and external meetings  Specifically, these meetings are designed to: Reinforce procedures: Post office managers can use stand-up talks— weekly meetings between management and employees at the post office—to discuss scanning issues with employees and opportunities to address those issues  For example, the postmaster at one post office we visited stated that this post office reinforces the standard work procedures designed to improve the scanning performance of employees during these meetings  Carriers and clerks can ask questions and learn why they are asked to do something or how to do a specific task, allowing for additional training and reinforcement of procedures  For example, we reviewed a handout developed by USPS headquarters to provide managers with talking points for service talks  This handout provided information on carriers delivering and scanning accurately and instructions on scanning at point of delivery on rural routes  Introduce new procedures: USPS officials told us that post office managers use stand-up talks to introduce new procedures and processes with carriers and clerks  For example, postmasters stated that they used these meetings to introduce and train carriers on new scanning features at the post offices  USPS district and area management develop and disseminate memos and handouts to assist managers conducting these meetings  We reviewed handouts USPS provided to managers for service talks  These handouts provided information on the rollout of some of the most recent scanning procedure changes  Continuously improve operations: District managers we interviewed stated that post offices with low scanning performance scores are placed on a district’s list of underperforming post offices  USPS district managers we interviewed told us that they meet with these post offices to determine how each post office plans to improve its scanning performance  District management also conducts audits of underperforming post offices and post offices that are in need of improvement  Our review of one district office’s service review checklist identified the key areas of audit for underperforming post offices  Reassess procedures: Representatives of mailers we interviewed told us that they meet with USPS representatives to discuss ways USPS can share scanning information for competitive products  Given that inaccurate scans can and do occur, it is important that postal managers explore and investigate any instances of missed or inaccurate scans  To do so, USPS managers—including area vice presidents, district managers, and postmasters—use a variety of reports as tools to ensure that the required scans are made at the appropriate place and time, and take action to monitor the status of competitive products, track lost items, and identify scanning issues  USPS headquarters designs reports used by managers to review performance at the local level across the country  Managers at each level are responsible for overseeing and reporting on the performances of the level below them  For example, the postmaster monitors performance of employees at the post office and is accountable to the district manager  In turn, each district manager is held accountable by the area vice president  To monitor performance of scanning of competitive products, these managers have access to several USPS data systems to generate reports  They can use the reports to monitor scanning performance of carriers and clerks at each post office and to identify the causes of scanning issues, such as missing or incorrect scans  Managers can also use these reports to track the status of competitive products or to investigate customer complaints of lost items  Some examples of reports available to managers include the following: Report 1: USPS officials told us that each post office receives this report from their District Office  The report identifies competitive products that do not have all the required scans, such as scans when the item arrives at the post office or when a delivery attempt was made  For example, one district official sends postmasters weekly reports on competitive products that do not have all the required scans  The officials told us that these reports help managers investigate the cause of incorrect scans identified in the report and how to prevent future occurrences  Report 2: USPS officials told us that this report is generated by district managers to proactively identify scanning irregularities, such as scans that may be out of sequence or multiple competitive products that are scanned at the same time but are for different addresses  District management can query postmasters about these scans and ask them to investigate the reason for the irregularities and determine if the scan was appropriate  Report 3: USPS officials told us that this report is generated by postmasters to monitor scanning status and performances for each competitive product that has received an arrival scan but lacks a delivery scan  While this may indicate a problem, it could also just reflect that the final scan had not been made by the end of the day or the scan that had not been uploaded into the USPS data systems when the report was generated  While having these reports are helpful, their full potential to help USPS managers may be limited because USPS lacks detailed and up-to-date standard operating procedures for how managers should use these reports or conduct other activities to efficiently investigate and resolve scanning issues  USPS’s Scanning Performance: Delivery Standard Operating Procedures for managers are a list of bullet points outlining managers’ responsibilities to meet scanning performance target goals and not a list of detailed procedures for managers to follow, such as how to use Report 1 to identify items that do not have all the required scans  In addition, USPS officials told us that this list has not been updated since approximately October 2005  The COSO Framework states that organizations should internally communicate information, including objectives and responsibilities for internal control, necessary to support the functioning of internal control  Further, it states that a process should be in place to communicate required information to enable all personnel to understand and carry out their internal-control responsibilities  Absent such communication, managers may take different actions to address problems or may have difficulty knowing where to find the appropriate information to locate a missing item to resolve a customer’s complaint quickly  For example, one post office manager told us that he will look at the scanning history in the USPS data systems to determine if the item received an acceptable delivery event scan or what the status of the item is on the route, while another post office manager told us he will use GPS data to see where the scans were made to determine if the item was delivered to the right address  If managers do not know where to find the appropriate information, they may spend more time investigating and be less efficient in resolving issues  Further, not having detailed standard operating procedures means managers may not be aware of all the reports available to them  For example, some post office managers told us that they use Report 3 while other post office managers told us that this report was not available to them  Without using Report 3, some managers told us that they look in several sources to find the same information needed to resolve the issue, such as locating a lost package  Some managers told us that USPS management discontinued the report because it was being misused by some managers  Specifically, managers told us that some managers were manually entering scanning or service-performance information retroactively to improve their performance scores  However, they told us that USPS management recently made Report 3 available to managers again but changed features to reduce any misuse  Additionally, USPS may miss opportunities to prevent scanning issues from happening again by not clearly communicating how managers should use the various reports to address specific scanning issues  For example, the USPS OIG recently determined that instances of missed and inaccurate scans for competitive products were a result of USPS management not adequately monitoring the implementation of those procedures  Without detailed procedures to guide managers in finding and using specific information in available reports and other tools, managers will not have consistent information to use to investigate and resolve customer complaints quickly or accurately  In addition, new managers may not know where to go for the most appropriate information and how to use this information to address some issues  As competitive products have become essential to USPS’s economic viability, it is increasingly important for USPS to accurately track them to remain competitive in this market  While USPS may be scanning most mail accurately, there continue to be instances where mail is not scanned accurately or is missing scans  Given the volume and growth in these competitive products, even a small percentage of inaccurately scanned products could be a large number of such products  Since USPS’s procedures were developed absent standards for internal control, the adoption of a set of internal control standards could enhance USPS’s efforts to continuously improve the design, implementation, and evaluation of its operational internal controls for scanning of competitive products  Further, since USPS’s standard operating procedures for scanning are located in numerous documents and are not always consistent—and given USPS’s reliance on stand-up talks and meetings to keep employees current—USPS employees may not always have accurate scanning procedures easily accessible to them  Having consistent standard operating procedures is increasingly important to ensure that employees are making accurate scans  Additionally, standard procedures that guide managers to investigate and resolve scanning issues would help managers more efficiently address these issues and ideally prevent these issues from happening again  To improve USPS’s competitive products scanning, we recommend that the Postmaster General take the following three actions  The Postmaster General should identify and adopt a set of internal control standards that can be used as the basis for operational internal-control activities, such as those for scanning competitive products  (Recommendation 1) The Postmaster General should improve the communication of standard operating procedures for scanning competitive products by, for example, updating or consolidating USPS documents, job aids, and standard work steps  (Recommendation 2) The Postmaster General should create standard operating procedures for managers on how to address inaccurate scans and use available reports to investigate and resolve scanning issues  (Recommendation 3) We provided a draft of this product to USPS for its review and comment  USPS’s comments are reproduced in appendix I  USPS stated that it cannot agree with our recommendation to identify and adopt a set of internal control standards for USPS’s operational internal control activities at this time  Although USPS has adopted an internal control framework for its financial internal control activities, USPS does not know what the benefits and costs are of adopting internal control standards for its operational internal control activities  As a result, USPS agreed to conduct a cost study to determine whether to commit resources to identifying and adopting a set of internal control standards for its operational internal control activities  We are encouraged that USPS is planning to conduct such a study and anticipate that performing this study will result in the implementation of an appropriate set of internal control standards  USPS agreed with the two recommendations regarding scanning procedures and committed to completing corrective actions by November of 2018  In its general comments, USPS noted that our reference to the USPS OIG’s report, Processing Readiness for Election and Political Mail for the 2018 Midterm Elections did not appear germane to the scanning of competitive mail  We recognize that this report was focused on a different type of mail, but as USPS noted in its letter, we use the OIG report as a related example of how USPS has taken efforts to improve the communication of its scanning procedures to employees  Therefore, we determined that our use of the report is appropriate  We have added information from the OIG report to characterize the OIG’s recommendations and USPS’s actions to address those recommendations  USPS also provided technical comments, which we incorporated as appropriate  We will send copies of this report to the appropriate congressional committees, the Postmaster General, the Chairman of the Postal Regulatory Commission, and other interested parties  In addition, the report will be available at no charge on the GAO website at http://www gao gov  If you or your staff have any questions about this report, please contact me at (202) 512-2834 or rectanusl@gao gov  Contact points for our Offices of Congressional Relations and Public Affairs may be found on the last page of this report  GAO staff making key contributions to this report are listed in appendix II  In addition to the individual named above, Kyle Browning (Assistant Director); Greg Hanna (Analyst-in-Charge); Michael Hansen; Thanh Lu; John Mingus; Faye Morrison; Malika Rice; Amy Rosewarne; Crystal Wesco; Elizabeth Wood; and Matthew Zaun made key contributions to this report 

ground_truth: Coal accounts for 17 percent of domestic energy production. SMCRA requires coal mine operators to reclaim lands that were disturbed during mining and to submit a financial assurance in an amount sufficient to ensure that adequate funds will be available to complete reclamation if the operator does not do so. Recent coal company bankruptcies have drawn attention to whether financial assurances obtained by OSMRE and state agencies will be adequate to reclaim land once coal mining operations have ceased. GAO was asked to review management of financial assurances for coal mine reclamation. This report describes, among other things, the amounts and types of financial assurances held for coal mine reclamation in 2017 and the challenges that OSMRE and state agencies face in managing these financial assurances. GAO collected and analyzed data from OSMRE and 23 state agencies; reviewed federal laws, regulations, and directives; and interviewed OSMRE and state agency officials and representatives from organizations associated with the mining and financial assurance industries and environmental organizations. State agencies and the Department of the Interior's Office of Surface Mining Reclamation and Enforcement (OSMRE) reported holding approximately $10.2 billion in surety bonds (guaranteed by a third party), collateral bonds (guaranteed by a tangible asset, such as a certificate of deposit), and self-bonds (guaranteed on the basis of a coal operator's own finances) as financial assurances for coal mine reclamation. OSMRE and state agencies face several challenges in managing financial assurances, according to the stakeholders GAO interviewed. Specifically, Obtaining additional financial assurances from operators for unanticipated reclamation costs, such as long-term treatment for water pollution, can be difficult. Determining the financial stability of surety companies has been challenging in certain instances. Self-bonding presents a risk to the government because it is difficult to (1) ascertain the financial health of an operator, (2) determine whether the operator qualifies for self-bonding, and (3) obtain a replacement for existing self-bonds when an operator no longer qualifies. In addition, some stakeholders said that the risk from self-bonding is greater now than when the practice was first authorized under the Surface Mining Control and Reclamation Act (SMCRA). GAO's previous work examining environmental cleanup found that the financial risk to government and the amount of oversight needed for self-bonds are relatively high compared to other forms of financial assurances. GAO also previously reviewed federal financial assurance requirements for various energy and mineral extraction sectors and found that coal mining is the only one where self-bonding was allowed. However, because SMCRA explicitly allows states to decide whether to accept self-bonds, eliminating the risk that self-bonds pose to the federal government and states would require SMCRA be amended. GAO recommends that Congress consider amending SMCRA to eliminate self-bonding. Interior neither agreed nor disagreed with GAO's recommendation.

prompt_front: You are given two reports by the government agency.



Question: Write a one-page summary of the report 2.

Report 1: Coal accounted for 17 percent of energy production (30 percent of electricity production) in the United States in 2016  To generate this energy, approximately 730 million tons of coal were mined domestically in 2016, according to the U S  Energy Information Administration, approximately 40 percent of which was produced on federal lands  As of 2016, state regulatory authorities and OSMRE had received financial assurances associated with coal mines that had been permitted to disturb approximately 2 3 million acres, according to OSMRE data  Coal is mined in two different ways: surface mining and underground mining  In surface coal mining, before the underlying coal can be extracted, the land is cleared of forests and other vegetation and topsoil is removed and stored for later use  Explosives or other techniques are then used to break up the overlying solid rock, creating dislodged earth, rock, and other materials known as spoil  Surface coal mines can cover an area of many square miles  In underground coal mining, tunnels are dug to access coal that is too deep for surface mining methods  In some cases, underground coal mines are designed to leave sufficient coal in the mine to support the overlying surface, and in other cases, they are designed to extract higher quantities of coal that results in subsidence of the overlying surface as mining progresses  In addition to disturbing the land surface, coal mining can affect water quality, according to the Environmental Protection Agency, the National Academies, and others  For example, mining can increase sediments in rivers or streams, which may negatively affect aquatic species  Moreover, mining can expose minerals and heavy metals to air and water, leading to a condition known as acid mine drainage, which can lead to long-term water pollution and harm some fish and wildlife species  Mining can also lower the water table or change surface drainage patterns  The surface effects of coal mining in the United States are regulated under SMCRA, which also created OSMRE to administer the act  SMCRA allows an individual state or Indian tribe to develop its own program to implement the act if the Secretary of the Interior finds that the program is in accordance with federal law  A state with an approved program is said to have “primacy” for that program  To obtain primacy, a state or Indian tribe submits to the Secretary of the Interior for approval a program that demonstrates that the state or tribe has the capability of carrying out the requirements of SMCRA  The program must demonstrate that the state or Indian tribe has, among other things, a law that provides for the regulation of the surface effects of coal mining and reclamation in accordance with the requirements of SMCRA, and a regulatory authority with sufficient personnel and funding to do so  Of the 25 states and four Indian tribes that OSMRE identified as having active coal mining in 2017, 23 states had primacy, and OSMRE manages the coal program in 2 states and for the four Indian tribes  SMCRA requires a mine operator to obtain a permit before starting to mine  The permit process requires operators to submit plans describing the extent of proposed mining operations and how and on what timeline the mine sites will be reclaimed  In general, an operator must reclaim the land to a use it was capable of supporting before mining or to an alternative postmining land use that OSMRE or the state regulatory authority deems higher or better than the premining land use  In reclaiming the mine site, operators must comply with regulatory standards that govern, among other things, how the reclaimed area is regraded, replanting of the site, and the quality of water flowing from the site  Specifically: Operators are generally required to return mine sites to their approximate original contour unless the operator receives a variance from the regulatory authority  To return to this contour, the surface configuration achieved by backfilling and grading of the mined area must closely resemble the general surface configuration of the land before mining and blend into and complement the drainage pattern of the surrounding terrain, with all highwalls and spoil piles eliminated  Operators are required to demonstrate successful revegetation of the mine site for 5 years (in locations that receive more than 26 inches of rain annually) or 10 years (in drier areas)  States have requirements for what vegetation may be planted depending on the approved postmining land use  For example, West Virginia’s regulations call for sites with a postmining land use of forest land to be planted with at least 500 woody plants per acre  The state specifies that at least five species of trees be used, including at least three of the species being higher value hardwoods, such as oak, ash, or maple  SMCRA requires that financial assurances be sufficient to ensure reclamation compliant with water quality standards, including those established by the Environmental Protection Agency or the states under the Clean Water Act  SMCRA’s implementing regulations also contain additional water protection requirements  For example, the regulations require that all surface mining and reclamation activities be conducted to minimize disturbance of the hydrologic balance within the permit and adjacent areas and to prevent material damage to the hydrologic balance outside the permit area  The federal government also enacted SMCRA, in part, to implement an abandoned mine land program to promote the reclamation of mined areas left without adequate reclamation prior to 1977, when SMCRA was enacted, and that continue to substantially degrade the quality of the environment, prevent or damage the beneficial use of land or water resources, or endanger the health or safety of the public  Specifically, Congress found that a substantial number of acres of land throughout the United States had been disturbed by surface and underground coal mining on which little or no reclamation was conducted  Further, it found that the impacts from these unreclaimed lands imposed social and economic costs on residents in nearby areas as well as impaired environmental quality  Since the abandoned mine land program was created, approximately $3 9 billion has been spent to reclaim abandoned mine lands, and there is at least $10 2 billion in remaining reclamation costs for coal mines abandoned prior to 1977, as of September 30, 2017, according to OSMRE  SMCRA generally requires operators to submit a financial assurance in an amount sufficient to ensure that adequate funds will be available for OSMRE or the state regulatory authority to complete the reclamation if the operator does not do so  The amount of financial assurance required is determined by the regulatory authority—OSMRE or the state—and is based on its calculation of the estimated cost to complete the reclamation plan it approved as part of the mining permit  Financial assurance amounts can be adjusted as the size of the permit area or the projected cost of reclamation changes  SMCRA also authorizes states to enact an OSMRE-approved alternative bonding system as long as the alternative achieves the same objectives  One kind of alternative bonding system is known as a bond pool  Under this type of system, the operator may post a financial assurance for an amount determined by multiplying the number of acres in the permit area by a per-acre assessment  The per-acre assessment may vary depending on the site-specific characteristics of the planned mining operation and the operator’s history of compliance with state regulations  However, the per-acre bond amount may be less than the estimated cost of reclamation  To supplement the per-acre bond, the operator generally must pay a fee for each ton of mined coal and may also be required to pay other types of fees  These funds are pooled and can be used to reclaim sites that participants in the alternative bonding system do not reclaim  Under OSMRE regulations, all alternative bonding systems must provide a substantial economic incentive for the operator to comply with reclamation requirements and must ensure that the regulatory authority has adequate resources to complete the reclamation plan for any sites that may be in default at any time  OSMRE regulations implementing SMCRA recognize three major types of financial assurances: surety bonds, collateral bonds, and self-bonds  A surety bond is a bond in which the operator pays a surety company to guarantee the operator’s obligation to reclaim the mine site  If the operator does not reclaim the site, the surety company must pay the bond amount to the regulatory authority, or the regulatory authority may allow the surety company to perform the reclamation instead of paying the bond amount  Collateral bonds include cash; certificates of deposit; liens on real estate; letters of credit; federal, state, or municipal bonds; and investment-grade rated securities deposited directly with the regulatory authority  A self-bond is a bond in which the operator promises to pay reclamation costs itself  Self-bonds are available only to operators with a history of financial solvency and continuous operation  To remain qualified for self-bonding, operators must, among other requirements, do one of the following: have an “A” or higher bond rating, maintain a net worth of at least $10 million, or possess fixed assets in the United States of at least $20 million  In addition, the total amount of self-bonds any single operator can provide shall not exceed 25 percent of its tangible net worth in the United States  Primacy states have the discretion on whether to accept self-bonds  State regulatory authorities and OSMRE reported holding a total of approximately $10 2 billion in surety bonds, collateral bonds, and self- bonds as financial assurances for coal mine reclamation in 2017  Of the total amount of financial assurances, approximately 76 percent ($7 8 billion) were in the form of surety bonds, 12 percent ($1 2 billion) in collateral bonds, and 12 percent ($1 2 billion) in self-bonds (see fig  1)  Twenty-four states reported holding surety bonds, 20 states reported holding collateral bonds, and 8 states reported holding self-bonds (see table 1)  In addition, OSMRE officials identified 6 states—Indiana, Kentucky, Maryland, Ohio, Virginia, and West Virginia—that have also established alternative bonding systems, such as bond pools  In a state with a bond pool, the operator may generally post a financial assurance for less than the full estimated cost of reclamation; in addition, the operator must pay into a bond pool  The pooled funds can be used to supplement forfeited financial assurances to reclaim sites that operators participating in the bond pool do not reclaim  States and OSMRE reported that operators forfeited more than 450 financial assurances for reclaiming coal mines between July 2007 and June 2016, with 13 of the 25 states reporting at least one forfeiture  States and OSMRE reported that the amount of financial assurance forfeited was sufficient to cover the cost of required reclamation in about 52 percent of the cases and did not cover the cost of required reclamation in about 22 percent of the cases  In the remainder of the cases (26 percent), the state or OSMRE reported that it had not yet determined if the financial assurance amount covered the reclamation costs that it was intended to cover  State and OSMRE officials said that it can take many years to fully reclaim a site and that it may take time for them to identify the extent of reclamation needed and to determine if the amount of financial assurance forfeited was sufficient to cover reclamation costs  State and OSMRE officials said there were several reasons why the amount of financial assurance obtained might not be sufficient to cover reclamation costs  For example, officials said the amount of financial assurance might not be sufficient if an operator mined in a manner inconsistent with the approved mining plan upon which the amount of financial assurance was calculated or if mining activity resulted in water pollution that was not considered when the amount of financial assurance was calculated  In cases where the amount of financial assurance does not cover the cost of reclamation, the operator remains responsible for reclaiming the mine site  However, OSMRE officials said that in those cases where the operator may be experiencing financial difficulties, it might be difficult for the states or OSMRE to compel the operator to complete the reclamation or provide additional funds to do so without having the operator go out of business or into bankruptcy  If the operator does not reclaim the site, the regulatory authority must use the forfeited financial assurance to do so  If the forfeited funds are not adequate, the site may not be fully reclaimed unless the regulatory authority either successfully sues the operator for more funds or provides any additional funds needed for reclamation  One other source of funds states can use to reclaim forfeited mines is civil penalties that the United States government collects from operators that violate conditions of their mining permits  OSMRE obligated approximately $2 8 million in civil penalties from fiscal years 2012 through 2017 for states to use to perform reclamation in cases where the financial assurance was not sufficient, according to agency officials  OSMRE has taken steps—including periodically reviewing financial assurance amounts, inspecting mine sites, and reviewing state programs that implement SMCRA—to oversee financial assurances and aspects of the mining and reclamation process that can affect whether the amount of financial assurances obtained will cover the cost of required reclamation  SMCRA requires OSMRE or the primacy state regulatory authority to calculate the amount of financial assurance required for each mine and to adjust the amount when the area requiring bond coverage increases or decreases or when the cost of future reclamation changes  OSMRE officials and state regulatory authority officials from four of the six states we interviewed said they generally review the amount of financial assurance at least every 2 1/2 years or when the mining plan has been modified in a way that may affect the amount of financial assurance required  Such periodic reviews are in part to help ensure that OSMRE and state regulatory authorities continue to hold an amount sufficient to complete required reclamation as conditions change  These reviews can lead to OSMRE or the state regulatory authority changing the amount of financial assurance required for a mine  For example: A state regulatory authority official in Utah said that the regulatory authority reviewed an existing mine permit in 2014, which led to it recalculating the estimated cost of reclamation on the basis of current costs  The state regulatory authority requested that the operator provide a financial assurance to cover the difference (approximately $195,000), in addition to the $445,000 financial assurance already in place  However, the official said that the operator—which had stopped mining the site in 2012 and filed for bankruptcy in 2013—did not provide the additional financial assurance amount  As a result, in 2017 the state regulatory authority collected the financial assurance that was in place (i e , the operator forfeited its assurance)  The official said in December 2017 that the state regulatory authority is determining the steps it will take to reclaim the site and expects that the forfeited amount will be sufficient to cover reclamation costs  OSMRE officials said that the agency reviewed a permit for a mine on Navajo tribal lands and determined that it needed to ask the operator to provide an additional financial assurance in the amount of $5 7 million  The increase was due to inflation and to include certain costs, such as the cost of mobilizing equipment needed for reclamation, that had inadvertently been excluded from the earlier calculation of the financial assurance required  The officials said that the operator provided the additional financial assurance amount  State regulatory authority officials in Wyoming said they review financial assurance amounts annually, and in 2017 they reduced the financial assurance for one mine by almost $35 million because of a substantial decline in fuel costs and the mine’s ability to share the cost of needed reclamation equipment with a neighboring mine  SMCRA requires OSMRE to make an average of at least one complete inspection per calendar quarter and one partial inspection per month for each active permit for which it is the regulatory authority to ensure that mines are in compliance with SMCRA and federal regulations  Complete inspections cover all inspection elements in OSMRE’s directive, while partial inspections may instead focus on issues that most frequently result in violations or a specific topic identified for oversight, according to OSMRE officials  In addition, OSMRE’s directive instructs the agency to inspect a sample of mines annually in states that have primacy to monitor and evaluate approved state programs’ compliance with SMCRA  The total number of inspections OSMRE is directed to conduct in primacy states is based on the number of inspectable units in each state  Complete inspections are to be done on 33 percent of those sites selected for inspection  Overall, OSMRE completed more inspections in primacy states than directed each year for evaluation years 2013 through 2016, according to agency data  For example, in evaluation year 2016, OSMRE’s directive called for it to conduct 1,225 inspections and OSMRE completed 1,388  As part of a complete inspection, OSMRE confirms that the operator is following the mining and reclamation plans to assure that the amount of financial assurance in place is adequate, according to OSMRE officials  If a violation is identified during an inspection, SMCRA requires OSMRE to issue a ten-day notice to the state regulatory authority or an immediate cessation order to the operator  If the violation increases the estimated cost of reclamation (e g , if the operator disturbed more land than it was approved for) or an adequate financial assurance had not been collected, OSMRE or the state regulatory authority can request that the operator provide an additional financial assurance  For example: OSMRE issued a ten-day notice to the Pennsylvania regulatory authority in 2015 because a water treatment system for a mine in that state did not have a financial assurance  According to OSMRE officials, the state regulatory authority took appropriate action to resolve the situation by issuing an order for the operator to post a financial assurance within 7 days  During an inspection of a mine in Tennessee, a nonprimacy state, OSMRE determined that the operator had not correctly reclaimed a portion of the mine because the slope of the regraded area was too steep, according to an OSMRE official  For the reclamation work that would be needed to regrade that area, OSMRE determined that the operator needed to provide an additional financial assurance of $272,000  Under SMCRA, OSMRE is required to evaluate each primacy state’s coal program annually to ensure that it complies with SMCRA  SMCRA includes a requirement that the regulatory authority secure necessary financial assurances to assure the reclamation of each permitted mine site  While OSMRE’s directive on oversight of state and tribal regulatory programs does not instruct the agency to review state regulatory authority calculations of financial assurance amounts, it instructs OSMRE to focus on the state programs’ success in achieving the overall purposes of SMCRA  For example, OSMRE, in conducting its oversight, is to evaluate the states’ effectiveness in successfully reclaiming lands affected by mining and in avoiding negative effects outside of areas authorized for mining activities  If OSMRE’s review of a state program identifies an issue that could result in the state not effectively implementing, administering, enforcing, or maintaining all or any portion of its approved coal program, OSMRE can work with the state regulatory authority to develop an action plan to correct the issue  If a state regulatory authority does not take the necessary corrective action, OSMRE may begin the process of withdrawing approval for a part or all of the state’s primacy  In addition to annually evaluating state programs, OSMRE can conduct national or regional reviews on specific topics  For example, OSMRE conducted a national review in 2010 that examined how state regulatory authorities calculated the required amount of financial assurances for coal mine reclamation  The review examined financial assurance practices in 23 states and reported that on the basis of the sample of mining permits reviewed, OSMRE was unable to determine if the amount of financial assurances was adequate for at least one of the permits it reviewed in 10 of the 23 states  Among the potential issues OSMRE identified were errors in the methods state regulatory authorities used to calculate financial assurance amounts and insufficient information in the reclamation plan upon which to calculate reclamation costs  OSMRE has worked with the 10 state regulatory authorities to address the financial assurance issues identified in the 2010 review  For example, OSMRE’s review found that the regulatory authority in Pennsylvania did not secure sufficient financial assurances to complete reclamation plans, in part because amounts were not calculated based on the actual sizes of the areas excavated for mining  In August 2014, OSMRE and Pennsylvania’s regulatory authority agreed to an action plan to ensure that the financial assurances for all active and new permits would be calculated using the actual sizes of the excavated areas  According to an OSMRE official, as of February 2017, the state regulatory authority had recalculated the financial assurance amount for all mines and had secured the additional financial assurances needed from operators of all but two of the mines  State officials said in October 2017 that they were continuing to work to obtain the assurances required for the two mines  OSMRE’s 2010 review also found that financial assurances in Kentucky were not always sufficient to cover required reclamation costs, in part because the method Kentucky’s regulatory authority used to calculate financial assurance amounts did not factor in all costs, such as the cost of moving equipment to and from the reclamation site  In February 2011, OSMRE and Kentucky’s regulatory authority signed an action plan identifying steps needed to address the issues OSMRE had identified  However, in May 2012, OSMRE determined that the state regulatory authority’s proposed changes to its method for calculating financial assurance amounts was an improvement but would not result in the authority obtaining sufficient funds to cover required reclamation  As a result, OSMRE initiated the process of revoking Kentucky’s primacy for this aspect of its program  In response, Kentucky implemented regulations to increase the minimum financial assurance required  The regulations also required the state regulatory authority to evaluate financial assurance amounts every 2 years to determine whether they need to be increased, among other things  The state regulatory authority sent a set of program amendments to OSMRE designed to address the identified deficiencies, some of which OSMRE is currently reviewing  OSMRE and state regulatory authorities face a number of challenges in managing financial assurances for coal mine reclamation—including those related to self-bonding, unanticipated reclamation costs, and the financial stability of surety companies—according to federal and selected state regulatory authority officials, representatives from organizations associated with the mining and financial assurance industries, and representatives from environmental nongovernmental organizations whom we interviewed  Challenges facing OSMRE and state regulatory authorities related to self- bonding include the following: Not knowing the complete financial health of an operator  The information federal regulations require operators to provide to regulatory authorities may provide an incomplete picture of the financial health of an operator, according to some parties we interviewed  For example, the financial information that operators provide reflects their past financial health, which may not reflect the operators’ current financial position, according to OSMRE’s response to the 2016 petition seeking revisions to its self-bonding regulations  In addition, if an operator applying for a self-bond is a subsidiary of another company, the operator is not required by regulation to submit information on the financial health of its parent company  While the operator applying may have sufficient financial assets to qualify for self-bonding, if its parent company experiences financial difficulties, the operator’s assets may be drawn on to meet the parent’s obligations, which could worsen the financial health of the self-bonded operator  In addition, according to OSMRE officials, even if OSMRE or a state regulatory authority were to become aware that an operator’s parent company was at financial risk, it would be difficult for the agency to deny the operator’s request for a self-bond because eligibility is specific to the entity applying for the self-bond, according to regulations  OSMRE could change its self-bonding regulations to require more information, according to OSMRE officials  However, the financial relationships between parent and subsidiary companies have become increasingly complex, making it difficult to ascertain an operator’s financial health on the basis of information reported in company financial and accounting documents, according to officials  When OSMRE first approved its self-bonding regulations in 1983, it noted that it was attempting to provide rules that would allow self-bonding without necessitating regulatory authorities to employ financial experts to determine which companies should be allowed to self-bond  However, according to OSMRE officials, financial expertise is now often needed to evaluate the current complex financial structures of large coal companies, which was not envisioned when the regulations were developed  Difficulty in determining whether an operator qualifies for self- bonding  The regulatory authority in a given state may not be aware that an operator had self-bonded in other states, making it difficult for the agency to determine whether the operator qualifies for self- bonding, according to some parties we interviewed  Operators are only allowed to self-bond for up to 25 percent of their net worth in the United States, according to regulations  Regulatory authority decisions on accepting self-bonds generally focus on assessing activities occurring in a specific state, not nationwide, according to the Interstate Mining Compact Commission  As a result, the state regulatory authority or OSMRE may know whether an operator has applied for self-bonds in other states that if approved would exceed 25 percent of its net worth in total  Difficulty in replacing existing self-bonds with other assurances if needed  OSMRE and state regulatory authorities may find it difficult to get operators to replace existing self-bonds with another type of financial assurance when needed, according to some parties we interviewed  If an operator no longer qualifies for self-bonding (e g , if it has declared bankruptcy), federal regulations require it to either replace self-bonds with other types of financial assurances or stop mining and reclaim the site  In either case, however, some parties noted that such actions could lead to a worsening of the operator’s financial condition, which could make it less likely that the operator will successfully reclaim the site  Some parties we interviewed have noted that regulatory authorities may be reluctant to direct the operator to replace a self-bond with another type of financial assurance and may instead allow the operator to keep mining so that any generated revenue could help the operator reclaim the site  For example, in 2015 the Wyoming regulatory authority determined that an operator no longer qualified for self-bonding and ordered it to replace a $411 million self-bond  However, the operator entered into bankruptcy without having replaced the self-bond  In this case, the state regulatory authority determined that reclamation was more likely to occur if the operator continued mining and allowed the operator to do so without a valid financial assurance  The operator replaced its self-bond as a part of its bankruptcy settlement approximately 17 months after the state regulatory authority’s order to replace the self-bond, according to OSMRE officials  However, if a self-bonded operator were to enter bankruptcy and did not secure a financial assurance to replace the self-bond or complete the required reclamation, the state regulatory authority would have to work through the bankruptcy proceedings to obtain funds for reclamation, according to OSMRE’s preamble to its 1983 self-bonding regulations  As a result, the state may recover only some, or possibly none, of the funds promised through the self- bond, and the cost of reclamation could fall on taxpayers  Difficulty in managing the risk associated with self-bonding  The risk associated with self-bonding is greater now than when the practice was first authorized under SMCRA, according to some parties we interviewed  According to SMCRA, the purpose of financial assurances is to ensure that regulatory authorities have sufficient funds to complete required reclamation if the operator does not do so  While SMCRA allows self-bonding in certain circumstances, when OSMRE first approved its self-bonding regulations, the agency did so noting that at the time there were companies financially sound enough that the probability of bankruptcy was small  Furthermore, the regulations stated that the intent was to avoid, to the extent reasonably possible, the acceptance of a self-bond from a company that would enter bankruptcy  However, as previously mentioned, three of the largest coal companies in the United States declared bankruptcy in 2015 and 2016, and these companies held approximately $2 billion in self-bonds at the time, according to an OSMRE August 2016 policy advisory, making it a very different risk landscape than originally envisioned  Following these bankruptcies—and recognizing that the coal industry was likely to continue to face economic challenges for several more years— OSMRE initiated steps in 2016 to reexamine the role of self-bonding for coal mine reclamation  Specifically, as previously mentioned, OSMRE issued a policy advisory in August 2016 noting that given these circumstances, state regulatory authorities should exercise their discretion under SMCRA and not accept new or additional self-bonds for any permit until coal production and consumption market conditions reach equilibrium  OSMRE has reported that it is not likely for that to occur until at least 2021  OSMRE also announced in September 2016 that the agency planned to examine changes to its bonding regulations that would, among other things, help ensure that reclamation is completed if a self-bonded operator does not do so  However, following a review of department actions that could affect domestic energy production, Interior announced in October 2017 that it was reconsidering the need for and scope of potential changes to its bonding regulations  OSMRE officials said that they did not have a timeline for finalizing a decision on potential changes in its bonding regulations  In addition, OSMRE rescinded its August 2016 policy advisory that states take steps to assess whether operators currently using self-bonds can still quality to do so and that states not accept any new self-bonds  Similar issues involving bankruptcies of hardrock mining operators led the Bureau of Land Management to implement regulations in 2001 eliminating the use of self-bonding for hardrock mining  In doing so, the Bureau of Land Management determined that a self-bond is less secure than other types of financial assurances, especially in cases where commodity prices fluctuate  The agency also noted that operators that would otherwise be eligible to self-bond should not have a significant problem obtaining another type of financial assurance  In our previous work examining other types of environmental cleanup, we found that the financial risk to the government and the amount of oversight needed for self-bonds are relatively high compared to other forms of financial assurances  Furthermore, we also previously reviewed federal financial assurance requirements for coal mining, hardrock mining, onshore oil and gas extraction, and wind and solar energy production and found that of these activities coal mining is the only one where self-bonding was allowed  Because SMCRA explicitly allows states to decide whether to accept self-bonds, eliminating the risk that self-bonding poses to the federal government and states would require that SMCRA be amended  Unanticipated reclamation costs, such as those related to long-term treatment for water pollution, may arise late in a mine’s projected lifespan, and the operator may not have the financial means to cover the additional costs, according to OSMRE officials  Under SMCRA, OSMRE and state regulatory authorities are not to approve a permit for a coal mine if the regulatory authority expects the mine to result in long-term water pollution  As a result, since long-term water pollution is not anticipated to occur, the cost of addressing it would not be included in the initial financial assurance that the operator provides  If the regulatory authority later determines that long-term water treatment is needed, the regulatory authority must adjust the amount of financial assurance that the operator is required to provide  Some parties we interviewed have also noted that the costs and duration of long-term water treatment are not well defined and that surety bonds are not well-suited to provide assurance for such indefinite long-term costs  For example, according to the Interstate Mining Compact Commission, surety bonds are designed for shorter-term, defined obligations that have a high certainty for bond release following the completion of reclamation  To help address this challenge, some states have established, or allowed operators to establish, trust funds to help cover such unanticipated reclamation costs  For example, West Virginia established a fund, primarily supported through a tax on the amount of coal mined, to operate water treatment systems on forfeited sites  West Virginia’s regulatory authority is also working to evaluate permits for sites with water pollution to estimate water treatment costs within the state more precisely  Similarly, Pennsylvania allows operators to establish trust funds that are maintained by foundations and monitored by the state regulatory authority and are intended to ensure that there are sufficient funds to cover the costs of long-term water treatment, according to state regulatory authority officials  In addition, the OSMRE-run coal program in Tennessee allows trust funds for water treatment, in part because an assurance system that provides an income stream may be better suited to ensuring the treatment of long-term water pollution than conventional financial assurances, according to an OSMRE notice in the Federal Register  The utility of surety bonds in providing a financial assurance depends on the surety company’s ability to pay the amount pledged if the operator forfeits  OSMRE regulations require that a surety company be licensed to do business in the state where a mine is located  Some parties we interviewed noted that surety companies have declared bankruptcy or experienced financial difficulties in the past and could experience similar difficulties in the future  In addition, two states reported recent issues related to surety companies  For example, state regulatory authority officials in Alabama said that a surety company that had provided surety bonds totaling $760,000 for four mines in that state had gone bankrupt or was insolvent  As of May 2017, the state had collected only $127,000  Similarly, state regulatory authority officials in Alaska said that as of August 2017, the state had not collected any part of a forfeited $150,000 surety bond because the surety company had gone bankrupt  In our previous work examining other types of environmental cleanup, we have found that the financial risk to the government and the amount of oversight needed for surety bonds are relatively low to moderate compared to other forms of financial assurances  Billions have been spent to reclaim mines abandoned prior to the financial assurance requirements SMCRA put in place, and billions more remain  Under SMCRA, self-bonding is allowed for coal mine operators with a history of financial solvency and continuous operation—the only type of energy production or mineral extraction activity we have reviewed for which this is allowed  Bankruptcies of coal mine operators in 2015 and 2016 have highlighted risks that OSMRE and state regulatory authorities face in managing self-bonding—a risk that may be greater today than when self-bonding was first authorized under SMCRA  If a self-bonded operator were to enter bankruptcy and does not provide a different type of financial assurance or complete the required reclamation, the regulatory authority and the taxpayer potentially assume the risk of paying for the reclamation  Although OSMRE said it would examine changes to its self- bonding regulations following recent bankruptcies, Interior recently said that it is reconsidering the need to do so  Because SMCRA explicitly allows states to decide whether to accept self-bonds, eliminating the risk that self-bonding poses would require amending SMCRA  Until such a change is made, the government will remain potentially at financial risk for future reclamation costs resulting from coal mines with unsecured financial assurances  Congress should consider amending SMCRA to eliminate the use of self- bonding as a type of financial assurance for coal mine reclamation  (Matter for Consideration 1) We provided a draft of this report to the Department of the Interior for review and comment  Interior did not provide written comments on our findings and matter for congressional consideration  OSMRE provided technical comments in an e-mail, which we incorporated as appropriate  As agreed with your offices, unless you publicly announce the contents of this report earlier, we plan no further distribution until 30 days from the report date  At that time, we will send copies to the appropriate congressional committees, the Secretary of the Interior, the Acting Director of OSMRE, and other interested parties  In addition, the report will be available at no charge on the GAO website at http://www gao gov  If you or your staff have any questions, please contact Anne-Marie Fennell at (202) 512-3841 or fennella@gao gov  Contact points for our Offices of Congressional Relations and Public Affairs may be found on the last page of this report  Major contributors to this report are listed in appendix II  We selected a nonprobability sample of states to examine the Office of Surface Mining Reclamation and Enforcement’s (OSMRE) oversight activities in more detail  We generally selected states that produced the most coal in 2015 but also selected states in order to achieve some variation in factors such as geographic location, the dominant type of coal mining conducted (e g , surface or underground mining), whether the state had primacy, and whether the state allowed self-bonding (see table 2)  In addition to the contact named above, Elizabeth Erdmann (Assistant Director), Antoinette Capaccio, Jonathan Dent, Cynthia Grant, Marya Link, Anne Rhodes-Kline, Sheryl Stein, Guiovany Venegas, and Jack Wang made key contributions to this report 


Report 2:  Japan's NYK line, a large ship owner, recently announced that it had reached an agreement with three Japanese utilities to add LNG bunkering to ports in Western Japan  Asian countries, together with Australia and the United Arab Emirates, currently have around 10 coastal ports offering LNG bunkering, with another 15 projects in development  Some LNG bunkering operations in Europe and Asia are associated with existing LNG marine terminals, which already have LNG storage and port infrastructure in place  However, many smaller operations—including most of the projects in development—employ trucking, dedicated bunkering vessels, on-site liquefaction, and other means to extend LNG availability beyond the ports with major LNG terminals  LNG bunkering is not so advanced in South America, although with nine operating LNG marine terminals (one for export), and another six in development, South America also could support significant LNG bunkering operations in the near future  LNG bunkering in the United States currently takes place in two locations—Jacksonville, FL, and Port Fourchon, LA—with a third bunkering facility under development in Tacoma, WA  The LNG facilities in these ports serve the relatively small U S -flag domestic market  Bunkering of LNG-fueled cruise ships also is planned for Port Canaveral, FL  However, ports in North America have significant potential to expand the nation's LNG bunkering capability  Jacksonville is the largest LNG bunkering operation at a U S  port  One bunkering facility at the port, developed by JAX LNG, initially began truck-to-ship refueling operations in 2016 for two LNG-capable container ships  (The LNG is sourced from a liquefaction plant in Macon, GA  ) In August 2018, upon delivery of the Clean Jacksonville bunker barge, the facility began to replace truck-to-ship bunkering with ship-to-ship bunkering  In the future, the barge plans to source LNG from a new, small-scale liquefaction plant which JAX LNG is currently constructing at the port  A second facility at Jacksonville's port, operated by Eagle LNG, provides LNG bunkering sourced from a liquefaction plant in West Jacksonville  Eagle LNG also is constructing an on-site liquefaction and vessel bunkering facility in another part of the port, expected to begin service in 2019  Taken together, the JAX LNG and Eagle LNG facilities is expected to establish Jacksonville as a significant LNG-bunkering location with the capability to serve not only the domestic fleet but larger international vessels as well  In 2015, Harvey Gulf International Marine (Harvey) began LNG bunkering operations in the Gulf of Mexico to fuel its small fleet of LNG-powered offshore supply vessels serving offshore oil rigs  Harvey has since constructed a $25 million facility at its existing terminal in Port Fourchon to store and bunker LNG sourced from liquefaction plants in Alabama and Texas  The facility can provide truck-to-ship bunkering services for LNG-fueled offshore supply vessels, tank barges, and other vessels  A Harvey subsidiary has ordered two LNG bunkering barges to enable ship-to-ship fueling in the future  Puget Sound Energy has proposed an LNG liquefaction and bunkering facility at the Port of Tacoma, WA  Vessels traveling between Washington and Alaska typically spend the entire journey within the 200-mile North America ECA  Consequently, vessel owners operating along these routes have been interested in LNG as bunker fuel  TOTE Maritime, for example, a ship owner involved in trade between Alaska and the lower 48 states, has begun the process of retrofitting the engines of two of its container ships to be LNG-compatible  The proposed Tacoma LNG facility would be capable of producing up to 500,000 gallons of LNG per day and would include an 8 million gallon storage tank  The facility would serve the dual purposes of providing fuel for LNG-powered vessels and providing peak-period natural gas supplies for the local gas utility system  Its total construction cost reportedly is expected to be $310 million  Community and environmental concerns have slowed the progress of the proposal, which is still under regulatory review  Puget Sound Energy originally planned to put the LNG facility into service in late 2019; however, permitting issues appear likely to delay its opening until 2020 or later—if it is eventually approved  Q-LNG Transport, a company 30% owned by Harvey, has placed orders for two LNG bunkering barges to provide ship-to-ship LNG fueling as well as "ship-to-shore transfers to small scale marine distribution infrastructure in the U S  Gulf of Mexico and abroad " Q-LNG's first barge initially is expected to provide fuel to new LNG-fueled cruise ships based in Port Canaveral (and, potentially, Miami), while service from its second barge is still uncommitted  Initial plans are for the LNG to be sourced from the Elba Island LNG import/export terminal near Savannah, GA—approximately 230 nautical miles away—although the company may seek to develop an on-site LNG storage facility in the future  As noted above, U S  LNG bunkering activities thus far have been limited to a handful of vessels in domestic trade and tourism  LNG bunkering for the much larger fleet of foreign-flag ships carrying U S  imports and exports is still to be developed  As in Europe and Asia, domestic ports located near major LNG import or export terminals may serve as anchors for expanded LNG bunkering operations  Figure 4 shows existing LNG import and export terminals in North America  LNG can be liquefied from pipeline natural gas (or imported natural gas) and stored in large quantities at these facilities  The LNG can then be bunkered on site or transported to bunkering facilities elsewhere in the region by truck, rail, or barge  As discussed above, the distance between Port Canaveral and Elba Island in Q-LNG's bunker sourcing plan is 230 nautical miles  Taking this distance as a measure of how far away LNG can be sourced and barged economically, it is possible to extrapolate which U S  ports are within reach of a potential supply of LNG for vessel bunkering  Table 1 lists the top 20 U S  container shipment ports in the United States and their proximity to existing LNG import/export terminals  Of these top 20 ports, 12 are less than 230 nautical miles from an operating LNG terminal  Distances between LNG terminals and the other East Coast ports are not much greater, suggesting that LNG for vessel bunkering could be within reach of every U S  port along the Eastern Seaboard and in the Gulf of Mexico  On the West Coast, the ports of Los Angeles and Long Beach—the two largest U S  ports—are relatively close to the Costa Azul LNG import terminal in Ensenada, MX  Seattle and Tacoma are far from Ensenada, but would be served by the proposed Tacoma LNG bunkering project, if constructed  LNG bunkering for Seattle and Tacoma alternatively could be sourced from an existing LNG port facility around 100 nautical miles north in Vancouver, BC, which is expanding to provide LNG bunkering services to international carriers  Alaska's existing LNG export terminal currently is inactive, but potentially could supply LNG bunker fuel in the Pacific Northwest as well  Although existing LNG import or export terminals in North America could supply LNG for regional bunkering operations, such activities would require additional investment for infrastructure such as LNG transfer facilities and bunker barges  CRS is not aware of any public announcements among the LNG terminals above to develop bunkering operations  However, at least one LNG terminal owner, Cheniere Energy, which operates LNG terminals in Louisiana and Texas, identifies vessel bunkering as one source of future LNG demand growth worldwide  The IMO adopted safety standards for ships using natural gas as a bunker fuel in 2015  The standards, which took effect in 2017, apply to all new ships and conversions of ships (except LNG tankers, which have their own standards)  The IMO standards address engine design, LNG storage tanks, distribution systems, and electrical systems  They also establish new training requirements for crews handling LNG and other low flashpoint fuels  As is the case for the sulfur standards, the IMO LNG safety standards apply to all IMO member nations, including the United States  In addition, a number of U S  federal agencies, especially the Coast Guard and the Federal Energy Regulatory Commission, have jurisdiction over specific aspects of domestic LNG storage infrastructure and bunkering operations  The Coast Guard has the most prominent role in LNG bunkering, given its general authority over port operations and waterborne shipping  In 2015, the Coast Guard issued two guidelines for the handling of LNG fuel and for waterfront facilities conducting bunkering operations  In 2017, the Coast Guard issued additional guidelines to Captains of the Port, the local Coast Guard officials responsible for port areas, for conducting safe LNG bunkering simultaneously with other port operations  The guidelines advise on quantitative risk assessment of facilities bunkering LNG, which allows Captains of the Port to assess the risks posed to crews and facilities  The Federal Energy Regulatory Commission (FERC) plays a role in LNG bunkering due to its jurisdiction over the siting of LNG import and export terminals under the Natural Gas Act of 1938  Specifically, FERC asserts approval authority over the place of entry and exit, siting, construction, and operation of new LNG terminals as well as modifications or extensions of existing LNG terminals  Notwithstanding this siting authority, FERC reportedly does not intend to assert jurisdiction over the permitting of LNG bunkering facilities, but it may require amendment of permits it has issued for LNG import or export terminals to account for bunkering operations added afterwards  In addition to the Coast Guard and FERC, other federal agencies may have jurisdiction over specific aspects of LNG bunkering operations in U S  ports under a range of statutory authorities  For example, the Pipeline and Hazardous Materials Safety Administration within the Department of Transportation regulates the safety of natural gas pipelines and certain associated LNG storage facilities (e g , peak-shaving plants)  LNG facilities also may need to comply with the Occupational Safety and Health Administration's regulations for Process Safety Management of Highly Hazardous Chemicals  Other federal agencies, including the Environmental Protection Agency, the U S  Army Corps of Engineers, and the Transportation Security Administration, may regulate other aspects of LNG bunkering projects  CRS is not aware of new regulations to date among these agencies specifically addressing LNG bunkering  World production of LNG has been rising rapidly over the last few years, driven by growth in the natural gas sector in new regions—especially Australia and the United States  According to one industry analysis ( Figure 5 ), global LNG supply is expected to increase from 300 to 400 million metric tons per annum (MMtpa) from 2017 to 2021 based on new LNG liquefaction projects already operating or under development  An additional 150 MMtpa appears likely to come online after that  Collectively, LNG supply from these new liquefaction projects could exceed projections of demand, which would put downward pressure on LNG prices  While increases in the global supply of LNG do not necessarily translate directly into an increase in LNG available for bunkering, such increases could provide options for LNG bunkering in more ports  Estimating potential demand for LNG in the maritime sector is complicated and uncertain  One study of future LNG demand for bunkering, specifically, projects that LNG-powered vessels in operation and under construction as of June 2018 will require between 1 2 and 3 0 MMt of LNG per year  The study's review of several LNG consumption forecasts in the maritime sector shows a consensus projection between 20 to 30 MMt per year by 2030  This level of demand growth implies an increase in LNG-powered vessel construction from the current rate of around 120 ships per year to between 400 and 600 new builds per year  If these levels were reached, they could create a significant new market for LNG suppliers  Assuming a Henry Hub spot market price of $4/MMBtu in 2030, the annual market for LNG in shipping could be worth $2 9 billion to $5 8 billion, before accounting for liquefaction and transportation charges  Some studies have projected the LNG bunkering market to be even larger and to grow more quickly  However, key variables—such as the prices of Henry Hub natural gas and crude oil, the number of new vessel orders, and the future costs of emissions technology—are notoriously hard to predict with accuracy  Thus, it is not assured that natural gas consumption in the maritime sector will absorb more than a small amount of the global liquefaction capacity in development  The IMO sulfur standards apply to ship owners globally, as does the development of new LNG supply and bunkering infrastructure  In addition to these factors, domestic LNG bunkering also may be influenced by considerations more specific to the United States  These considerations include growth of the U S  natural gas supply, domestic shipbuilding opportunities, and LNG safety and security  Because of its leading role in global natural gas production, the United States has a particular interest in any new source of natural gas demand  According to the Energy Information Administration, the United States has been the world's top producer of natural gas since 2009, when it surpassed Russia  In 2017, increases in production outstripped increases in domestic gas consumption, leading to the United States becoming a net exporter of natural gas for the first time in nearly 60 years  As discussed above, North America (primarily the United States) is expected to add the most new LNG production capacity through 2030 when including projects that are operating, under construction, and likely (according to investment analysts)  Past increases in U S  LNG exports were driven by greater throughput at the Sabine Pass LNG export terminal—the only operating U S  LNG export terminal in 2017  In March 2018, the Cove Point terminal in Maryland became the second operating U S  LNG export terminal  Four additional projects under construction or commissioning are set to nearly triple U S  liquefaction by the end of 2019  This increase in liquefaction capacity likely will motivate LNG producers to secure new buyers  Figure 6 shows estimated LNG prices for various locations around the world as of October 2018  As the figure shows, LNG prices are substantially lower in North America than in Asia, Europe, and South America  Even after adding $1 00 to $2 00/MMBtu to transport the LNG to overseas ports, LNG produced in the United States is globally competitive at these prices  If LNG from the new liquefaction capacity coming online can be produced and delivered with similar economics, the cost advantage may create an opportunity for U S  LNG in bunker supply  There are over 400 petroleum fuel bunkering ports in the world, but 60% of bunkering in recent years has happened in six countries: Singapore, the United States, China, the United Arab Emirates, South Korea, and the Netherlands  Of these countries, only the United States is a significant LNG producer  Therefore, the United States could be a favorable source of LNG for domestic bunkering and for bunkering at the other major ports  While the LNG industry historically has had a good safety record, there are unique safety risks associated with LNG in vessel operations  Leakage of LNG during LNG shipping or bunkering can pose several hazards  LNG is stored at temperatures below -162 °C (-260 °F), far below the -20°C at which the carbon steels typically used in shipbuilding become brittle  Consequently, extreme care must be taken to ensure that LNG does not drip or spill onto ship hulls or decking because it could lead to brittle fracture, seriously damaging a ship or bunkering barge  LNG spilled onto water can pose a more serious hazard as it will rapidly and continuously vaporize into natural gas, which could ignite  The resulting "pool fire" would spread as the LNG spill expands away from its source and continues evaporating  A pool fire is intense, far hotter and burning far more rapidly than oil or gasoline fires, and it cannot be extinguished; all the LNG must be consumed before it goes out  Because an LNG pool fire is so hot, its thermal radiation may injure people and damage vessels or property a considerable distance from the fire itself  Many experts agree that a large pool fire, especially on water, is the most serious LNG hazard  Leaks of boil-off gas (the small amount of LNG that vaporizes in storage) can also release natural gas into a port area and cause fires or explosions  Major releases of LNG from large LNG carriers would be most dangerous within 500 meters of the spill and would pose some risk at distances up to 1,600 meters from the spill  While a bunkering barge or a vessel using LNG for fuel contains far less LNG than large LNG carriers, LNG spills in bunkering operations could still be a significant concern  Risks associated with bunkering LNG are complicated in ports seeking to engage in "simultaneous operations" during the bunkering process  Simultaneous operations entail loading and unloading cargo and personnel from a ship, maintenance, and other logistical operations performed while a ship is bunkering  Accidents that occur during such operations (for example, the operation of heavy machinery near pipes transporting LNG) can result in a spill of LNG which can threaten workers positioned near the site of operations  LNG tankers, bunkering vessels, and land-based facilities could be vulnerable to terrorism  Bunkering tanks or vessels might be physically attacked to destroy the LNG they hold—and vessels might be commandeered for use as weapons against port or coastal targets  Potential terrorist attacks on LNG terminals or tankers in the United States have long been a key concern of the public and policymakers in the context of large scale LNG imports or exports because such attacks could cause catastrophic fires in ports and nearby populated areas  For example, a 2007 report by the Government Accountability Office stated that, "the ship-based supply chain for energy commodities," specifically including LNG, "remains threatened and vulnerable, and appropriate security throughout the chain is essential to ensure safe and efficient delivery " Affected communities and federal officials continue to express concern about the security risks of LNG  The potential risks from terrorism to LNG bunkering infrastructure may be different than those of larger LNG import or export operations due to smaller quantities of LNG involved, but the risks may become more widespread if LNG bunkering operations are established in more locations  The Maritime Transportation Security Act (MTSA, P L  107-295 ) and the International Ship and Port Facility Security Code give the Coast Guard far-ranging authority over the security of hazardous materials in maritime shipping  The Coast Guard has developed port security plans addressing how to deploy federal, state, and local resources to prevent terrorist attacks  Under the MTSA, the Coast Guard has assessed the overall vulnerability of marine vessels, their potential to transport terrorists or terror materials, and their use as potential weapons  The Coast Guard has employed these assessments to augment port security as necessary and to develop maritime security standards for LNG port facilities  The IMO's overall framework for controlling vessels emissions (MARPOL Annex VI) has been in place since 2005  While the United States, as an IMO member, is subject to the IMO's 2020 sulfur standards, the international standards apply equally to all parties and all vessels  The impacts of sulfur standards on bunker fuel have been an important consideration, but IMO member nations have agreed to the standards independent of any particular energy policies  Moreover, MARPOL Annex VI preceded the U S  shale gas boom, so commitment to that initial IMO framework could not have anticipated United States' current role as a dominant energy producer  Any changes within the international shipping fleet to install sulfur scrubbers, fuel engines with LNG, or switch to other low sulfur fuels, are being driven primarily by market forces in fuel supply, shipbuilding, and shipping—not by any particular push to favor one fuel over another  Nonetheless, given its particular status, the question arises whether the standards may create an economic opportunity for the United States, in energy or otherwise  More specifically, could international adoption of LNG as a bunker fuel create an important new market for U S  natural gas producers, shipbuilders, or infrastructure developers? As discussed above, depending upon the adoption of LNG bunkering in the global fleet, the LNG bunker fuel market could grow to several billion dollars by 2030  If U S  LNG producers were to supply a significant share of this market—on the strength of comparatively low LNG production costs—LNG bunkering could increase demand for U S  natural gas production, transportation, and liquefaction  Opportunities in LNG-related shipbuilding might be more limited, as most of this occurs overseas, with the exception of Jones Act vessels  In the latter case, demand for domestically-constructed LNG bunkering barges could be one significant area of economic growth  Engineering and construction firms could benefit from new opportunities to develop new port infrastructure for LNG storage and transfer  While likely limited in number, such port facilities could be complex, high value projects costing tens or hundreds of millions of dollars to complete  Such projects could create jobs in engineering, construction, and operation, which could be important to local communities  Although LNG bunkering could present the United States with new economic opportunities, it may pose challenges as well  Rising demand for LNG in the maritime sector could increase natural gas prices for domestic consumers  In addition to being the world's largest natural gas producer, as of 2018, the United States is also the world's largest producer of crude oil and the second largest bunkering hub  Consequently, while vessel conversion to LNG bunkering may increase demand for U S -produced natural gas, it could be partially offset by reduced demand for U S -produced crude oil or refined products  Exactly how changing demand in one sector could affect the other is unclear  Furthermore, while LNG can reduce pollutant emissions from vessels, emissions and environmental impacts from increased natural gas production and transportation could increase overall emissions  Much of the net environmental impact depends upon practices in the natural gas industry, which are the subject of ongoing study and debate  Although new LNG bunkering infrastructure can create jobs, as the Tacoma LNG projects shows, the construction of such port facilities can be controversial for reasons of safety, security, and environmental impact  Overarching the considerations above is uncertainty about how the global shipping fleet will adapt to the IMO sulfur standards over time  This uncertainty complicates decisions related to both private investment and public policy  LNG-fueled ships still account for only a fraction of the U S  and global fleets, and it may take several decades for significant benefits of LNG-powered vessels to be realized  It is also possible that alternative ship fuels, including biofuels, electric engines, and hybrid engines, will become more economically viable in coming years  Given the uncertainty surrounding the future of LNG as a ship fuel, it is hard to predict the potential benefits or costs that LNG bunkering may provide to the United States  Until now, the private sector has added LNG-fueled vessels to fleets in the United States in a piecemeal manner under existing federal statutes and regulation  Congress could encourage the growth of LNG bunkering by various means, such as providing tax incentives to support the construction of LNG bunkering facilities and vessels, addressing any statutory or regulatory barriers to bunkering facility siting or operations, and providing funding for technical support to domestic carriers seeking to adopt LNG technology  Alternatively, Congress could seek to encourage competing bunker fuel options, such as biofuels, by incentivizing them in similar ways  In addition, Congress could also affect growth in LNG bunkering through policies affecting the LNG industry or domestic shipping industry as a whole  Changes in federal regulation related to natural gas production, or changes to the Jones Act, for example, while not directed at LNG bunkering, could nonetheless affect its economics  Therefore, evaluating the potential implications on LNG bunkering of broader energy, environmental, or economic objectives may become an additional consideration in congressional oversight and legislative initiatives  If LNG bunkering expands significantly in U S  ports, Congress also may examine the adequacy of existing measures to ensure the safety and security of LNG vessels, storage, and related facilities 

ground_truth: The combination of growing liquefied natural gas (LNG) supplies and new requirements for less polluting fuels in the maritime shipping industry has heightened interest in LNG as a maritime fuel. The use of LNG as an engine ("bunker") fuel in shipping is also drawing attention from federal agencies and is beginning to emerge as an issue of interest in Congress. In 2008, the International Maritime Organization (IMO) announced a timeline to reduce the maximum sulfur content in vessel fuels to 0.5% by January 1, 2020. Annex VI of the International Convention for the Prevention of Pollution from Ships requires vessels to either use fuels containing less than 0.5% sulfur or install exhaust-cleaning systems ("scrubbers") to limit a vessel's airborne emissions of sulfur oxides to an equivalent level. An option for vessel operators to meet the IMO 2020 standards is to install LNG-fueled engines, which emit only trace amounts of sulfur. Adopting LNG engines requires more investment than installing scrubbers, but LNG-fueled engines may offset their capital costs with operating cost advantages over conventional fuels. Savings would depend on the price spread between LNG and fuel oil. Recent trends suggest that LNG may be cheaper in the long run than conventional fuels. LNG bunkering requires specialized infrastructure for supply, storage, and delivery to vessels. To date, the number of ports worldwide that have developed such infrastructure is limited, although growth in this area has accelerated. Early adoption of LNG bunkering is occurring in Europe where the European Union requires a core network of ports to provide LNG bunkering by 2030. LNG bunkering is also advancing in Asia, led by Singapore, the world's largest bunkering port. Asian countries, together with Australia and the United Arab Emirates, have about 10 coastal ports offering LNG bunkering, with another 15 projects in development. LNG bunkering in the United States currently takes place in Jacksonville, FL, and Port Fourchon, LA—with a third facility under development in Tacoma, WA. Bunkering of LNG-fueled cruise ships using barges also is planned for Port Canaveral, FL. The relative locations of other U.S. ports and operating LNG terminals suggest that LNG bunkering could be within reach of every port along the Eastern Seaboard and in the Gulf of Mexico. On the West Coast, the ports of Los Angeles and Long Beach, CA, are near the Costa Azul LNG terminal in Ensenada, MX. Seattle and Tacoma are adjacent to the proposed Tacoma LNG project. Since 2015, Jones Act coastal ship operators have taken steps to transition their fleets to use cleaner burning fuels, including LNG. Shippers of dry goods to Alaska, Hawaii, and Puerto Rico have taken delivery or have ordered LNG-fueled and LNG-capable vessels from U.S. shipyards in Philadelphia, PA, and Brownsville, TX. Another company operates five LNG-powered offshore supply vessels built in Gulfport, MS. Depending upon LNG conversions, the global LNG bunker fuel market could grow to several billion dollars by 2030. If U.S. LNG producers were to supply a significant share of this market—on the strength of comparatively low LNG production costs—LNG bunkering could increase demand for U.S. natural gas production, transportation, and liquefaction. Opportunities in LNG-related shipbuilding might be more limited, as most shipbuilding occurs overseas, although domestically-constructed LNG bunkering barges could be one area of economic growth. Finally, engineering and construction firms could benefit from new opportunities to develop port infrastructure for LNG storage and transfer. However, while vessel conversion to LNG fuel may increase demand for U.S.-produced natural gas, it partially could be offset by reduced demand for U.S.-produced crude oil or refined products. Furthermore, while LNG can reduce direct emissions from vessels, fugitive emissions and environmental impacts from natural gas production and transportation could reduce overall emissions benefits. While the LNG industry has experienced few accidents, the Coast Guard has been developing new standards to address unique safety and security risks associated with LNG in vessel operations. The overarching consideration about LNG bunkering in the United States is uncertainty about how the global shipping fleet will adapt to the IMO sulfur standards over time. This uncertainty complicates decisions related to both private investment and public policy. Although Congress has limited ability to influence global shipping, it could influence the growth of LNG bunkering through the tax code and regulation, or through policies affecting the LNG industry or domestic shipping industry as a whole. Evaluating the potential implications of LNG bunkering within the context of broader energy and environmental policies may become an additional consideration for Congress. If LNG bunkering expands significantly, Congress also may examine the adequacy of existing measures to ensure the safety and security of LNG vessels, storage, and related facilities.