The decline that began after oil prices reached their post-2014 apex on 3 October, when Brent touched $85/b, has been the largest relative price rout since the collapse in benchmarks over the second half of 2014.
The reversal in market sentiment regarding global crude markets was stark, as consensus remained bullish in September, with few immediate concerns regarding demand and the outlook for supply tight over the next several quarters. With firm expectations that the Trump administration would keep its hardline with regard to sanctions waivers for Iranian crude, traders were talking about immediate prospects of oil prices to climb back above $100/b.1
Initially, prices began to feel headwinds in late September as stocks at the Cushing storage hub, the delivery point for the WTI contract, began to grow strongly. After stocks fell to nearly 20 Mb from over 60 Mb in 2017, inflows again grew while offtake slowed, pushing sufficient barrels into storage that builds grew precipitously. Traders were prompted to sell off by the start of this seasonal inventory growth and a desire to exit longs for reasons of profit-taking.2
Just as investors were closing out some of their exposure, financial volatility began to set in, as concerns over the global economy grew. Flagging economic data from China and Europe, the inversion of the yield curve for US Treasuries, a growing likelihood that Brexit could end in a worst-case scenario, and a trade war between the two largest economies in the world served as plenty of reason for oil prices to fall through much of October, particularly as US crude stocks continued to grow rapidly.
Finally, the supply side shocks laid the groundwork for the bulk of the price correction, as markets saw a far more modest impact on Iran exports than previously expected. Nevertheless, in anticipation of the hardline policy, Saudi Arabia had taken its own production to historic levels of 11 Mbbl/d3 , leaving a market well supplied after awaiting shortfalls. This weighed heavily on Brent especially, which stayed above $75/b until waivers were announced on 2 November.4
The pledge by the OPEC+ producer group to cut 1.2 Mbbl/d from October levels in early December has not induced a price rebound. Hesitation on the part of the Russians may be eroding the credibility of future commitments, as crude flows had hit 11.4 Mbbl/d after staying below 11 Mbbl/d for over a year. Oil price volatility as measured by OVX, an indexation to WTI, breached 50, its highest since the price downturn. With little indication that any single entity can balance the market, or that the global economy is returning to firmer footing, oil price volatility, fueled by financial flows, is becoming the norm.5
Azerbaijan is pursuing further expansion in the Turkish energy sector over the past month, as the State Oil Company of the Azerbaijan Republic (SOCAR) announced that it was in talks with the German firm EWE for some of its gas distribution assets for as much as $140 million.6 Growing stakes in the Turkish gas network comes at a crucial time for SOCAR and Turkey, with the connector pipeline that will integrate the Turkish and European portions of the Trans-Adriatic Pipeline (TAP) completed at the end of November.
Volumes from the second phase of the Shah Deniz gas field offshore Azerbaijan will be the primary source for gas traveling to the European market via the Trans-Anatolian Pipeline (TANAP), dramatically enhancing the strategic rationale behind deep political and economic relations with Turkey for Baku.7 The TANAP pipeline will boast a capacity of 16 Bcm/y, of which 10 Bcm/y will continue on to Europe via the TAP pipeline.
Natural gas is not the only sector in which SOCAR has been investing heavily in Turkey. Already reliant upon the Baku-Tblisi-Ceyhan (BTC) pipeline to get its petroleum exports to market, it has also built up sizeable operations in Turkey’s oil and petrochemical industries. Recently SOCAR announced its intention to build nine filling stations at the new Istanbul airport.8
Such expansion of its downstream system in Turkey will soon be facilitated with supplies from the 200 Kbbl/d STAR refinery, which has already been inaugurated with a ceremony in November, however its commercial operations have been delayed again, this time until early-2019. With the streaming of STAR, Turkey will grow its refining capacity by a third, altering the regional product market dynamics and becoming much more self-sufficient.9
Amid a surge in domestic natural gas production, Egypt now seeks to become a regional export and storage hub. In November, Egypt signed a Memorandum of Understanding (MoU) with the EU to increase gas exports in order to diversify supply sources to meet rising European demand.10
In 2018, Egypt has produced 68.2 Bcm/y of natural gas, up from 41.3 Bcm/y in 2016, substantial growth largely attributable to increased production from the Eni-operated offshore Zohr field.11 This growth has transformed Egypt from a large natural gas importer, to a self-sufficient producer that easily meets domestic demand. Ambitions to become a regional hub for natural gas have been further solidified by higher pipeline exports to Jordan. After the next jump in gas volumes, roughly 10% of Jordanian power generation would be attributable to Egyptian natural gas.12 Egypt’s ambitions also include growing import partnerships with Israel, with an eye to source Israeli gas output either for direct re-export, or to feed domestic demand that will thereby free up Egyptian production to be exported as LNG. Earlier in 2018, Israeli firm Delek Drilling and Noble Energy signed a deal to begin pumping 7 Bcm/y to Egypt’s Dolphinus by mid-2019. These supplies would come from Israel’s offshore Leviathan and Tamar fields.13
As an indication of the relative certainty this would provide E&Ps seeking to operate in Israel, preparations for further development of the offshore have begun after years of stalled progress. In December, Israel launched its second offshore bid round to grant exploration licenses to develop its Eastern Mediterranean holdings. The round offered 19 total blocks and five zones, with licenses having an initial period of three years. Bid winners will be announced in July 2019.14
The controversial Nord Stream 2 project, a pipeline to supply 55 Bcm/y annually of cheap, Russian natural gas from Gazprom to German import markets, was this week denounced by the US Congress and European Parliament, the latter of which passed a resolution calling the project “a political project that poses a threat to European Energy Security.”15
The EU Parliament’s denunciation lacks the legal authority to stop the project, but demonstrates growing political antipathy toward the $11 billion project, which would double the amount of gas that Russia can sell to Germany underneath the Baltic Sea, and thus bypass existing routes through the Ukraine to avoid paying the estimated $2 billion in annual transit fees paid to Kiev. 16All three political parties in Germany have also signaled opposition to the pipeline, a significant fact considering that Angela Merkel will be leaving office next year.
Nevertheless, the pipe-laying vessel arrived in the Baltic Sea last week to begin work laying pipeline, 300 kilometers of which has already been constructed. The permits granted by Finland remain valid and Berlin is making few concrete moves outside of vocal opposition.17 Russia promptly denounced the measures taken by the EU and the US, calling the project an economic venture and opposition should be viewed as unfair competition.
The Nord Stream 2 project is scheduled for completion in 2019, eight years after the completion of the first phase of the project, which likewise boasts a capacity of 55 Bcm/y of natural gas to Germany.
The US Congress has threatened to sanction Gazprom and its European partners to halt the project. Half of the project’s cost is financed by European partners, including Shell, BASF, Wintershall, Engie, OMV, and Uniper. Germany’s Wintershall claimed that these companies had already invested $6.8 billion. Should the US Congress push to heavily sanction the European partners, a political rift could emerge between the US and the EU just as their political unity would be required to disrupt the completion of the pipeline in any way.18
Even within the EU, alignment on the legal treatment of offshore natural gas pipelines, such as Nord Stream 2, has not been resolved. If a resolution is not achieved before the completion of the pipeline, any new rules mandating greater transparency in tariff regulation will not apply.19 There is little time left to reach an agreement since the EU Parliament breaks for elections in May. Absent any agreement by then, the Nord Stream 2 pipeline may become grandfathered against sanctions from Brussels.
With the imminent completion and execution of several natural gas projects, Australia became the largest exporter of liquefied natural gas (LNG) globally in November, as 6.5 MMt were loaded from Australian projects whereas Qatar shipped 6.2 MMt of LNG for the month.20 The completion and ramp-up of output from newly streamed projects, including Prelude, Wheatstone, and Ichthys projects enabled Australia to overcome Qatar for the lead spot, despite the cost overruns and delays that have plagued these projects.
With these projects now ramping up, Australia is in an excellent position to fill the current expectations for robust LNG demand growth over the medium-term, especially given the nation’s proximity to Asian markets.
First, in June of this year, Chevron brought online the second LNG train for its $34 billion Wheatstone project in Western Australia. In October of 2017, Chevron also brought online the first train that will now get to a total capacity of 8.9 MMtpa over 2019, as both trains ramp in full. The addition of the Wheatstone train pushed Chevron operations in Western Australia to a total of five, including the $54 billion Gorgon project.21
In late November, Japanese oil company Inpex and its partners officially inaugurated the $34 billion Ichthys offshore LNG project. The importance and scale of the project was reinforced by the presence of Australian Prime Minister, Scott Morrison, and Japanese Prime Minister, Shinzo Abe, at the ceremony. LNG Production at Ichthys is slated to gradually ramp-up to reach 8.9 MMtpa, as well as 1.65 MMtpa of LPG annually and close to 100 Kbbl/d of condensate. Over 70% of this new production will be supplied to Japanese buyers.22
Finally, in early December, Royal Dutch Shell announced that its Prelude floating LNG (FLNG) unit will begin producing LNG by end-2018. First approved in 2011, the offshore project in Northern Australia will have a production capacity of 3.6 MMtpa, as well as the capacity to produce 1.3 MMtpa of condensate, and 400,000 Mtpa of liquefied petroleum gas (LPG). The owners of the project reflect its orientation toward the Asian markets. Shell owns 67.5% of Prelude, with Japan’s Inpex, Taiwan’s CPC, and Korea’s Gas Corp splitting the remaining stakes.23
Trade tensions between major importer, China, and the United States could benefit Australian projects at the expense of new US projects scheduled to come online through 2023. Nonetheless, Australia faces competition from other low-cost projects in Qatar, Mozambique, Russia and Canada, as well as the United States.24
As governments in Asia begin to grapple with the challenges of balancing the need for economic growth with that of environmental sustainability, particularly as growing signs that the impacts of climate change are increasing annually, the need to leverage low-carbon technologies is becoming a central focus of energy policy across the region. Various factors, some policy-driven, such as increased government support for Renewables Portfolio Standards (RPS) and state-sponsored electrification programs, and participation in the Paris Accords to more uncontrollable drivers such as high oil prices and local geology, there is high regional growth potential in renewables across China and Southeast Asia, especially in solar and wind.
Particularly in the area of RPS, as well as with the production of solar panels and a growing presence in supply chains for electric vehicles (EV), China is currently ahead of its counterparts further south. In mid-September, the Chinese government mandated that 35% of its total electricity consumption, or RDS, must come from renewables by 2030. The RDS target also hopes to reduce Chinese reliance on coal electricity.25
In 2016, China produced 3.2 billion tons of coal, or 44% of the world's total, and was the world’s top import market for coal.26 The nation also produced an estimated 30% of the world’s carbon emissions in 2016.
Chinese solar generation, backed by generous state subsidies, has flourished. The IEA estimates that 60% of the world’s annual solar (PV) manufacturing capacity also comes from Chinese companies. The nation’s total installed PV capacity has now surpassed 150 GW, well above the government’s previous target of 105 GW set for 2020. Wind generation also continues to surge, since 2015 output has risen 26%.27 While China will continue to emerge as a key market for renewable electricity, investors are now seeing opportunity in the upside for growth in renewables and related technologies across the Southeast Asia.28
The National Renewable Energy Board of the Philippines in 2018 announced an identical RPS’ portfolio mix as China, stating that by 2030 25% of the nation’s electricity generation must come from renewables.29Geothermal sources may figure prominently in the mix. Officials announced volcanic surveys to locate new possibilities for geothermal power sources, which currently supply 12% of the country’s electricity mix. The government hopes to double this by 2040, and recently announced a joint exploration partnership with companies in the Netherlands.
Indonesia, which is currently seeking to electrify 90% of its households by 2040, also hopes to increase its share of geothermal electricity from 5% in 2017 across the country’s 10,000 islands. Finally, Taiwan holds investment promise in offshore wind sources, driven by its geographic features and a more favorable regulatory
In the US state of Massachusetts, the state and federal governments have completed their first offshore wind auction, drawing a record $405 million in bids for three offshore wind leases. The state selected a consortium led by European firms Equinor and Royal Dutch Shell, which pledged $135 million. The region’s favorable geography for offshore generation, along with pledges by the state to buy the electricity ultimately generated from the prospective wind projects, created high investor interest in the auction.29 The winning consortium also announced that it will utilize wind turbines from MHI Vestas Offshore Wind, with an initial order of 84 of V164-9.5 MW turbines.30
Earlier this year, Massachusetts struck a deal with Danish and Spanish firms to install the first major offshore wind farm in the state. The project will be located 15 miles off the coast of Martha’s Vineyard. Its installed generation capacity will be 800 MW, able to power upwards of 500,000 homes. This was in tandem with a 400 MW offshore wind project in the neighboring state of Rhode Island.32
With its windy coastline and a growing desire for renewable generation sources, northeastern US states like Massachusetts, Connecticut, Rhode Island, and New York are likely to be fertile ground for offshore wind over the next 10-15 years, although European markets are still well larger than US offshore wind capabilities.
In Northwest European countries such as the UK and Germany – two countries that alone now boast 12 GW of offshore electricity generation capacity – progress is years ahead of that achieved in the US. Total installed offshore wind capacity in the US is only 30 MW, with only a single installed wind farm off the coast of Rhode Island. However, with initiatives such as the 2.5 GW of proposals for renewable projects called for by the state government, potentially the US can start to gain some ground on European markets.33
A reason for the relatively belated reaction to new regulations for bunker fuels has been a lack of details surrounding the framework and credible enforcement mechanisms provided by the International Maritime Organization (IMO). This has gradually changed over the past year, as the IMO has held firm on the implementation and phase-in of rules that will see acceptable levels of sulfur in marine fuels drop from 3.5% to 0.5%. In another indication that the IMO wants to project a strict adherence to prospective implementation, the committee administering the transition to IMO 2020 approved an amendment that bans even the possession onboard of fuels with sulfur content greater than 0.5%.34
Currently, the marine sector consumes 3.8 million b/d of bunker fuels, approximately 4-5% of global oil demand. On January 1, 2020, the IMO will implement new emissions standards for the shipping sector, with enormous implications for global oil markets along the supply chain, from refiners and their suppliers, natural gas producers and LNG operators, shipping companies, as well as the insurance and banking sectors related to these various parties and stakeholders.
In order to comply with these new regulations, a vessel has three paths to contain its emissions while under propulsion: use the bunkering fuels with the mandated 0.5% or less, primarily low-sulfur fuel oil (LSFO); begin to order new ships, or retrofit currently operated tankers, that run on liquefied natural gas (LNG); or install scrubbers into smoke stacks that capture sufficient particulates that emissions resemble that from the lower sulfur fuels. Given that market players are initiating concerted strategic responses to rules that are credibly coming into practice in little over a year, despite efforts towards late adoption of LNG and scrubbers, the only viable short-term option for the industry at-large is to purchase LSFO and similar marine fuels.35
Thus, the ability of the global refining system to produce the necessary volumes of low sulfur refined product becomes critical. One of the greatest challenges will be resolving what should be done with the high-sulfur fuel oil (HSFO) that continues to be pumped after 1 January 2020, which potentially most of the world’s refiners will have to face. While the shipping industry is not the sole consumer of HSFO, which is also used for power generation and other industrial uses, demand for higher sulfur fuels should deteriorate significantly come 2020. Greater uptake of scrubbers by shipping companies could see a marginal reversal of that trend, but the impact on price differentials will be potent.36
The change will force refineries to produce more distillate fuels, which require higher utilization rates, higher costs, and will drive some refineries with a less competitive product slate out of business. OPEC forecast that 1.4 Mbbl/d of refinery capacity will close due to the IMO regulation. Nevertheless, at a refiners conference held this month in Cannes, France, the consensus view saw solid medium-term price support for crude markets and significant economic benefits for those refiners that have the capacity to produce these fuels.37
Even oil producers must consider the impact on the demand for specific types of crudes, as those heavier, more sour oil streams are not as competitive for refiners producing cleaner fuels. In September, OPEC affirmed that the IMO's regulations will have a large and negative effect on the bulk of OPEC members, many of whom mainly produce high sulfur crudes.38
Even in the face of Russia belatedly agreeing to a 1.2 Mbbl/d cut to global crude supply (from October levels) by the OPEC+ group of producers earlier in December, it has done little beyond providing a thin floor underneath oil prices. Economic developments such as the inversion of the yield curve for US Treasuries and increasingly weak data out of China and Europe have served to weigh on global markets and oil prices alike. This in spite of the anticipated cuts to output come January.39
The stabilization of prices, with Brent finding support at $60/b, can be attributed partly to the slowing of purchases in short positions that lasted for several weeks (although investors found another short opportunity in middle distillates). 40However, with shorts having grown again in ICE Brent crude futures according to the most recent data release through 11 December, there remains downside price risk
Beyond record levels of open interest and trading volumes in the traditional oil futures markets, new frontiers in oil trading have opened over the course of 2018. In late November, for the first time, an oil trading platform utilizing blockchain technology was launched by the firm Vakt, allowing for greater transparency in the trading of commodities. The platform trades in North Sea crude and its oil company members include BP, Shell and Equinor.41 This is not the first time that such a technology has been used in the trade of crude, however, something which the trading firm Mercuria used in transactions with various banks.42
Even the advanced technologies being applied to oil flows predominantly continue to trade using the traditional currency in which crude is priced, the US dollar. However, last March the first oil futures contract denominated in the Chinese yuan launched. Despite certain flaws that will constrain the potential depth and liquidity of this futures contract, with the support and participation of large Chinese NOCs, trading volumes rose to levels, overtaking Brent during recent weeks.43 However, open interest never reached substantial levels and has come under pressure of late, as volatility and developments in the oil market has exposed the contract’s disconnect from physical markets. As long as open interest is low, the market for Chinese crude futures will remain marginal.44
Flows from the Buzzard field in the North Sea were halted in November after corrosion was discovered in offtake pipelines from the project. With a capacity of 150 Kbbl/d, Buzzard constitutes the largest contributor to the Forties crude stream, one of four that makes up the physical supply of Brent. In addition to the tightening impact of this disruption, the lesser field that forms a portion of Forties, Elgin-Franklin, is also offline for maintenance.45
After staying offline for over a year, the federal government and the Kurdistan Regional Government (KRG) came to an initial understanding surrounding flows from the portion of the Kirkuk field operated by state-run North Oil Co. Incremental flows on the order of 50-100 Kbbl/d enter the KRG export pipeline that terminates at the Turkish port of Ceyhan.46
As Baghdad returns investment to Kirkuk, having signed a deal with BP in late 201747 , the KRG pipeline could see growing volumes of federal oil supplies, especially with the recent expansion of the throughput capacity to 1 Mbbl/d, up 300 Kbbl/d.47 This additional capacity could be valuable to Baghdad particularly as long as the Iraq-Turkey Pipeline (ITP) that channeled Kirkuk output to global markets remains offline, which it has been since March 2014 with significant repair needed for operations to return.49
The deal does not harmonize the oil policies of Baghdad and Erbil, and the validity of upstream contracts granted as production sharing agreements (PSAs) by the KRG have come under renewed scrutiny. 50Export flows from the projects operated by smaller foreign E&Ps in the autonomous region of Kurdish territory did not cease during the impasse involving Kirkuk, which has recently seen growing volumes that has brought KRG exports to Ceyhan to 400 Kbbl/d over recent months.51 These flows have increased thanks to higher production from autonomous projects such as DNO’s Tawke license, which will soon approach 150 Kbbl/d, and continued drilling at fields such as Atrush.
All the barrels that were shut in when federal forces responded to the independence referendum have not remained so the entire time. Of the nearly 300 Kbbl/d that was initially offline has come back in batches, as a new pipeline spur allowed for 40 Kbbl/d of additional output to reach domestic refineries. This was followed by the resumption of operations at Iraq’s formerly largest refinery, Baiji, which suffered significant damage in the wake of the advance by the Islamic State (IS) in mid-2014. The first of two 70 Kbbl/d crude distillation units (CDUs) has begun to ramp up, with the second to return earlier in 2019.52
Despite growing concerns over faltering economic strength in China, refinery runs and crude oil imports remain at robust levels. In November, crude runs by Chinese refineries posted 3% year-on-year growth, hitting 12.3 Mbbl/d on the month. 53Although the annual basis saw an increase, this utilization is lower than the previous month, and the deteriorating crack spreads – for gasoline in particular – are beginning to impact the operations of the state-run refiners.54
The relatively high amounts of crude processing by refiners has necessitated record flows of oil imports, which rose to over 10.4 Mbbl/d in November, as its domestic production continues to decline, boosting its net import requirement. 55With such demand for foreign barrels, the trade war with the US has proven especially ill-timed, given the growth in crude output and exports that is slated to come from its major tight oil plays such as the Permian. Trade tensions escalated to such levels that Beijing halted imports from the US altogether in October, after China had risen to the top crude importer from the US. However, with the announcement of the “truce” in the trade war, an executive at China’s largest oil trader, Unipec, stated that purchases by state refiners of US crude would resume in short order.56
The contraction in refining margins notwithstanding, other developments in the Chinese domestic crude market in 2019 could bolster demand for crude any flagging trends in product consumption. Additions in crude distillation capacity, with new refinery units and petrochemical facilities coming on-line, will require incremental barrels to fill its inventories and operations. This could constitute a strong pillar for oil demand growth in China next year.57 One of the largest complexes in China that will stream in 2019 is ample refining capacity at the Hengli Petrochemical facility, which was set to test its 400 Kbbl/d in processing capacity by 15 December.58
Growing signs of economic slowdown from China has become a frequent headwind for global financial markets in recent months, acting to compound the decline in oil prices by ~30% since early October. Equities fell across the globe again on December 14, as new data emerged that showed further evidence that the Chinese economy is cooling, with worries that the trade war in the US could only drag these already weak figures lower in coming months.59
Retail sales growth from China hit a 15-year low in November, joined by slowing factory output that has dropped to a three-year bottom. Indicators of economic softness from Europe, largely from France and Germany, also tugged on sentiment.
While the US and China averted a worst-case scenario by agreeing to a 90-day truce in escalations of tariffs on the side of the G20 meeting in Argentina60 , it simply delays the most severe repercussions and does not amount to a solution. The good will following this modest breakthrough proved to be brief, with the CFO of Chinese firm Huawei taken into custody in Canada for extradition to the US. This prompted immediate condemnation from Beijing and has resulted in a diplomatic crisis between China and Canada as well.61 The detention and potential prosecution of Meng Wanzhou, the Huawei executive, in the US would pose a direct threat to the potential for any broader resolution of trade issues between Washington and Beijing.
Were the Chinese economy healthier, then perhaps Xi Jinping could maintain a hardline with the Trump administration, however this is looking to be less the case at a time when the US economy still appears to be expanding with relative strength.62Should this divergence continue, and the yuan weaken against the US dollar, this could begin to threaten the financial livelihood of many large Chinese corporations holding substantial amounts of dollar-denominated debt.63
The prospect of lower overall economic growth that may be exacerbated by retaliatory trade measures between China and the US has brought the topic of necessary economic structural reforms back to the fore.64 Given the consolidation of political power that has gone on since 2013 under Xi Jinping, economic liberalization could pose a policy path potentially fraught with risk for the Communist Party to follow. Nevertheless, if the Chinese economy is to become what Beijing aspires to, the largest economy in the world that creates the most innovative firms with deep capital markets that rival New York and London, the next round of reforms (or lack thereof) will provide a good indication of how rapidly this goal can be realized.65
In an extraordinary move announced on 2 December, Qatar plans to exit the Organization of Petroleum Exporting Countries (OPEC) after 57 years of membership, a major move for a nation that had sole observer status at the founding meeting of OPEC. The growing rift between Qatar and two if its counterparts from OPEC and the Gulf Cooperation Council (GCC), Saudi Arabia and the UAE, has given such actions an acute political dimension. However, given the limited amount of oil production relative to other OPEC members, and its abundant natural gas resources that are now under further development, the exit from OPEC allows for a strategic concentration in the commodity that Qatar boasts an advantage.67
Additionally, Qatar will be able to sidestep any potential US legal snags as they expand their investments across North America. The current NOPEC bill making its way through Congress, for instance, would arguably no longer apply, for example.68
However, especially since the imposition of an embargo on Qatar by Saudi Arabia and UAE, in spite of the fact that each is a member of the GCC, such actions inevitably enflame tensions. As such, Doha sees its other close allies in the region, such as Kuwait and Oman, to be able to broker a rapprochement.69
Direct relations, on the other hand, have been fraying lately, as the Qatari Emir did not attend a hastily-organized meeting of GCC representatives in Saudi Arabia, interpreted as a swipe at Riyadh. Qatar went on to criticize the current framework of the GCC, calling for major reforms to the institution. Doha even went so far as to say that dialogue on any business related to the GCC or otherwise is no longer a possibility until the trade embargo is finally lifted.72
After an abnormally long period of stable – and growing – levels of production and exports from Libya, developments in the area surrounding the largest oil field, El Sharara, shut in as the national oil company, National Oil Corporation (NOC), declared force majeure.73This has prompted the rapid loss of the 300+ Kbbl/d that Sharara had been pumping, along with volumes from the adjacent satellite field, El Feel, which also had been producing 80 Kbbl/d.
The political dynamic in the southwest is distinct to that between the west and east of the country, with Berber tribes often feeling disenfranchised, which will often prompt the occupation of oil facilities until a deal with Tripoli is met. Reflecting the instability present in the area, this latest attack on infrastructure had been preceded by an incursion by gunmen in late November, however operations were not seemingly affected.74
Forces related to the Petroleum Facilities Guard (PFG), which had formerly occupied the main export terminals in the Sirte Basin until September 2016, now play a diffuse and complex role with myriad and shifting alliances across the country. 75Further disruptions with the aid of the PFG may become more likely should these groups see political or economic benefit from such acts. Not unaware of this fact, the Libyan Oil Minister, Sanallah, who has presided over an unlikely rise in production to the highest levels since early 2013 at 1.3 Mbbl/d, is holding a hard line against the traditional payments that might placate tribal forces. 76Nevertheless, the longer the disruption persists, the greater the economic cost of the Libyan economy generally, and the ability to finance redevelopment of the upstream sector in particular.