Jordan does not hold significant reserves of crude oil and natural gas, and has historically imported the majority of its energy. This has been especially disadvantageous in recent years, as regional volatility has affected gas supplies from Egypt and scuttled a planned pipeline to Iraq, while high oil prices had until recently resulted in the government spending up to 20% of annual GDP on energy imports. However, with global oil prices dropping by over 50% between mid-2014 and early 2015, the country has seen a turnaround that will have a significant impact, lowering the kingdom’s near-term energy bill and its trade deficit.
The development of the renewable energy segment has also seen a sharp uptick in recent years, guided by specific legislation and a spate of new solar and wind projects, with nearly 1000 MW of solar and wind projects currently under implementation. The kingdom made significant progress on new shale and nuclear power development over 2014-15, and could become a net energy exporter by 2030. Although gas import interruptions and rising electricity demand continue to challenge stakeholders, the kingdom’s energy market is now poised to become a leading regional example of non-oil diversification, leading to a positive long-term forecast for the sector.
The Ministry of Energy and Mineral Resources (MEMR), established in 1984, is tasked with administering and organising the energy sector. The MEMR’s responsibilities include comprehensive planning, the development of new energy sources, the formation of energy agreements with neighbouring countries and the securing of international capital for new projects, particularly in electricity generation, production of oil derivatives, and oil and gas transportation. It also oversees development of local energy sources, including shale and renewables.
The ministry works with a raft of government bodies to deliver power across the kingdom, most notably the Energy and Minerals Regulatory Commission (EMRC), which replaced a host of separate entities in 2014. Prior to the promulgation of Law No. 17 of 2014, the Natural Resources Authority (NRA), established in 1965, was responsible for mining, and oil and gas exploration. The EMRC stands as the legal successor to the NRA, as well as to the Electricity Regulatory Commission (ERC) and the Jordan Nuclear Regulatory Commission, although the Jordan Atomic Energy Commission (JAEC), established in 1996, still operates as a separate entity responsible for developing nuclear science and technology in the kingdom.
The JAEC aims to transform Jordan from a net energy importer to a net exporter by 2030, under a strategy emphasising exploitation of national uranium assets, promotion of public-private partnerships (PPPs) and effective technology transfer. For its part, the EMRC’s myriad responsibilities include service provision, guaranteeing the sector’s economic sustainability, encouraging investment and improving operational efficiency, setting electricity tariffs, protecting consumer interests and regulating the electricity sector. In the oil and gas sector, the National Petroleum Company’s remit covers oil and gas exploration, while the Jordan Petroleum Refining Company, a public shareholding company, oversees operations at the nation’s sole refinery, Zarqa. Key utilities entities include the National Electric Power Company (NEPCO), which acts as a single buyer for electricity, and the Water Authority of Jordan, which split from the NRA to become a separate entity in 1985. The National Energy Research Centre (NERC) was established in 1998 to develop new and renewable energy sources, as well as energy efficiency strategies.
Two decades of restructuring have seen Jordan’s power market undergo dramatic changes, with ongoing reforms expected to continue the trend of increasing use of innovative solutions and rising private sector participation in development of new energy projects. Restructuring began in 1994, when Jordan’s power sector comprised of the state-owned Jordanian Electricity Authority (JEA), a vertically integrated power utility with a monopoly in the generation and transmission segments and a minor market share of the distribution market, as well as the privately owned Jordanian Electric Power Company, which held two-thirds of the distribution market, and a third distribution company, the Irbid District Electrical Company (IDECO), which is owned in equal parts by the public and private sector.
The JEA was officially replaced by NEPCO in 1996 with the promulgation of the General Electricity Law No. 10 of 1996, and in 1999 NEPCO was restructured into three separate companies. NEPCO remained a state-owned single buyer, the Central Electricity Generation Company (CEGCO) was established as a major generation company (and today supplies around 60% total electricity in Jordan) and the Electricity Distribution Company (EDCO) became NEPCO’s primary distributor. Following further restructuring, the government instituted the regulatory framework for its power market with the establishment of the ERC in 2001, and the General Electricity Law No. 64 of 2002 was passed the following year, acting as the primary legislation for ERC and, now, EMRC activities. Ongoing reforms emphasised privatisation, and between 2007 and 2009 the state privatised CEGCO, EDCO and IDECO, shifting its strategy towards signing agreements with independent power plants (IPPs). Today the national grid comprises six generators with installed capacity of 4100 MW. There are four IPPs in the kingdom and four generating companies, including CEGCO, state-owned Samra Electric Power Generating Company, the Qatrana Electric Power Company and the Amman East Power Plant, while the nation also draws from the international grid for imports. All companies sell to NEPCO, with prices set based on a competitive tendering process.
National Energy Plan
The energy sector is expected to undergo rapid change in the coming years, as outlined by the updated Master Strategy of the Energy Sector in Jordan, which was approved in 2007 following amendments to an earlier plan from 2004. Running until 2020, the plan envisions $18bn of new public and private investment in power projects, and covers all activities within the energy sector, from exploitation of natural resources to electricity tariffs, as well as stipulating legislative and regulatory reforms. The first phase of the plan will see Jordan secure international investment in new power generation and gas distribution projects, as well as the restructuring and reform of its downstream sector, while latter stages will target construction of a diverse array of energy projects, most notably shale, nuclear and renewables. Under the strategy, Jordan hopes to see 29% of total energy needs met by natural gas by 2020, 14% by oil shale and 6% from nuclear energy. The plan also targets generating more than 15% of total projected energy requirements via renewable resources under the same time frame, with the recently promulgated Renewable Energy and Energy Efficiency Law offering significant incentives to renewables investors (see analysis).
Electricity demand has shown a sharp uptick, with the World Bank reporting that Jordanian annual electricity consumption jumped by 114.4% between 2000 and 2011, rising from 6.6bn KWh to 14.15bn KWh, while average annual consumption per capita expanded by 66%, from 1377 KWh to 2289 KWh. Although per capita consumption has since declined to 2235 KWh annually, according to the MEMR’s 2013 annual report, total consumption expanded by an additional 3% to reach 14.6bn KWh. NEPCO projects peak demand will reach 4198 MW by 2020, up from a projected 2915 MW in 2014.
As a result of its lack of naturally occurring energy resources, Jordan relies heavily on imports of crude oil, petroleum products and natural gas to meet domestic energy demand. According to the US Energy Information Administration, energy imports meet over 90% of Jordan’s energy needs, eating up an estimated 40% of the annual budget. Crude oil and oil products comprised 88% of primary energy demand in 2012, while the country currently provides between 2% and 4% of energy needs using local resources. NEPCO reports that in 2014 the cost of energy imports stood at JD4.5bn ($6.3bn), up from JD2.76bn ($3.9bn) in 2008, the equivalent of 85% of annual exports, or 17.8% of total GDP, making the energy bill the kingdom’s most significant cost burden. However, the relatively cheap renewables provided under power purchase agreements and the introduction of natural gas supplies via the floating storage regasification unit docked in Aqaba will help toward a more balanced energy bill in the long run.
Crude oil imports are sent to the Zarqa refinery, where current production of 100,000 barrels per day (bpd) satisfies an estimated 70% of total demand for petroleum products. The refinery is expected to undergo a $1.64bn upgrade in 2015, boosting production to a potential 120,000 bpd, but in the meantime, the remaining 25% of crude oil is imported at the Port of Aqaba, with Jordan importing 4.9m tonnes of petroleum products annually, according to the MEMR. Although this has led to positive growth forecasts for the downstream petroleum sector, which saw consumption rise by an estimated 19% between 2009 and 2015, import dependency has created a number of challenges for energy stakeholders.
Moreover, plans are under way to increase the purchase of electric cars. In September 2015, the government announced the exemption of electric cars from registration fees, while measures governing the recharging of electric vehicles are being prepared.
Subsides & Supply Disruption
The government sells electricity at a lower price than it costs to produce and it heavily subsidised fuel until 2012, when electricity and fuel subsidies were costing the kingdom an estimated $1.5bn-2bn annually. Regional instability has exacerbated the situation, most recently when a planned crude oil pipeline to supply oil from Iraq to Jordan and Egypt was put on hold in October 2014, although Iraq’s Ministry of Oil announced in March 2015 that it is still hoping to develop the $18bn, 1700-km pipeline, which would connect Basra to Egypt via Aqaba in Jordan.
The authorities have also struggled to manage energy demand in the wake of disruptions to the Arab Gas Pipeline, which had supplied natural gas from Egypt and stands as the country’s sole gas import pipeline. Repeated attacks saw natural gas supply grind to a halt on a number of occasions beginning in 2011, shutdowns that cost the kingdom an estimated $3m per day between 2011 and July 2015. Import volumes dropped from 89bn standard cu feet (scf) in 2010 to 17bn scf in 2012, and they stood at just 867m scf in 2013, after shipments halted mid-year due to Egypt’s own energy shortages. As a result, Jordan has been forced to turn to fuel oil imports to compensate.
Oil prices stood at over $100 per barrel between 2013 and mid-2014, and business intelligence publication Venture reports that the shift to fuel imports drove up the cost of generating and delivering electricity to end users across Jordan. NEPCO has felt the impact and its deficit reached a record JD2.46bn ($3.5bn) in 2012, with the company recording further annual losses of $1.53bn in 2013 and $1.67bn in 2014. The IMF reported that NEPCO’s operating losses equalled over 4% of GDP in 2014. As a result of these challenges, the government is now looking for new external energy partnerships, as well as renewing its focus on developing its own local energy sector. These efforts, combined with a strategy to remove energy subsidies and increase its supply of natural gas imports, should see NEPCO return to profitability. The IMF’s December 2014 Article IV Consultation for Jordan, reported that NEPCO’s losses would begin declining in 2015 as a result of tariff increases and the establishment of a new liquefied natural gas (LNG) terminal in Aqaba.
Jordan began raising utility prices in 2012, moving to increase prices for fuel used in public transport by 14%, while kerosene oil used for household heating rose by 28% and cooking gas by 54%. The move was initially met with protest, although plummeting global oil prices – Brent crude fell from a high of $115 per barrel in June 2014 to around $45 per barrel in January 2015 – has since softened the impact and significantly reduced the inflationary risks of subsidy removal. With oil prices forecast to remain depressed in 2015, and the cost of electricity production expected to drop by 30% as a result, the government is in an ideal position to capitalise on savings opportunities realised through reduction of electricity subsidies. After 2013 rate hikes for high-consumption households, Umayya Toukan, the former finance minister, announced in April 2014 that all energy customers will pay full commercial prices by 2017. The increases will be rolled out gradually, starting with a 7.5% tariff hike in January 2015.
Although falling oil prices will have a positive impact on Jordan’s energy bill in 2015, the kingdom remains vulnerable to price fluctuations and the government has moved to seek new energy partners, most notably in the supply of natural gas and to intensify efforts to source more of its power supply locally. In September 2014, US-based Noble Energy reported it had signed a non-binding letter of intent to supply NEPCO with natural gas from Israel’s Leviathan offshore field, a project entailing construction of a new pipeline between the two countries. Under the terms of the deal, Noble and its Leviathan partners would supply a base gross quantity of 1.6trn scf from the field over 15 years, with sales volumes expected to begin at a rate of 300m scf per day. The $15bn deal sparked controversy in the kingdom and in January 2015 it was announced that negotiations had been suspended. However, in April 2015, the two countries approved a separate $500m, 15-year deal that will see Israel supply 87bn scf of natural gas to Jordanian firms Arab Potash and Jordan Bromine. This followed on a February 2015 $900m deal between the two governments to build a shared desalination plant in the Gulf of Aqaba, lending a brighter outlook to potential future energy deals with Israel.
More significantly, a new LNG terminal in the southern city of Aqaba, home to Jordan’s sole sea port, enables a significant near-term increase in natural gas shipments to the kingdom. The project rolled out relatively quickly; after selecting 13 pre-qualified bidders in 2012, the Aqaba Development Corporation awarded a JD46.5m ($65.4m) engineering, procurement and construction contract to a joint venture of BAM International and MAG Engineering in December 2013. The project included design and construction of an LNG jetty, approach trestle and pipeline from a floating storage and regasification unit to a tie-in point with a transmission pipeline from the Jordanian Egyptian FAJR Company. A new 1-km pipeline ties in with the company’s existing pipeline south of the project, running alongside a coastal road, with construction finishing in May 2015.
The terminal was completed in June 2015 and it supplies gas from Qatari Shell LNG carriers, offering initial send-out capacity of 150m scf per day of gas, with ultimate send-out capacity expected to reach 490m scf per day. The terminal is expected to save the government between $400m and $500m in annual energy spending, according to Mounir Bouaziz, vice-president of Shell Middle East and North Africa, although Bouaziz made these estimates in April 2014, when both oil and gas prices were high.
With new supply from a wider variety of partners expected to stabilise the sector, Jordan has more room to manoeuvre in developing its domestic energy resources, which will ultimately allow it to end its dependence on global energy markets. The National Energy Strategy emphasises private sector participation in the development of new IPPs, and Jordan has seen a number of these spring up in recent years.
IPP development kicked off in 2007, when American energy firm AES expanded into Jordan and constructed the country’s first IPP, the 370-MW combined-cycle gas-fired Amman East Power Project. This was the first time an IPP had been established in the country. Since then the government has signed agreements for three additional IPPs, including an $800m contract with Mitsubishi in 2012 to construct a 600-MW oil- and gas-fired power plant east of Amman and a contract for the 240-MW AES Levant Power Plant, located on the Amman East site. The latter project was financed in 2012 by a $170m loan from the Overseas Private Investment Corporation, as well as a $100m facility from the European Bank for Reconstruction and Development. The government plans to establish a handful of additional IPPs.
Oil production has been limited in the kingdom, with Jordan containing proven crude reserves of 1m barrels, as of 2015, and 200bn scf of gas. Onshore upstream activities are generally spread over eight divided blocks, including Risha, Dead Sea, Azraq, West and East Safawi, North Highlands, Jafer, Central Jordan and Sirhan, with modern production peaking at just over 380 bpd in 1986, before dropping to rest at roughly 25 bpd in 2013. However, the kingdom contains significant reserves of oil shale, an organic-rich rock that can be heated, cooled and distilled to yield oil in a process known as retorting. Jordan holds 70bn tonnes of oil shale, the fourth-largest reserves in the world, across 28 separate locations, most notably in the southern governorate of Karak.
“Proven oil shale reserves in Jordan will be enough for energy consumption for the next 1500 years,” Mohammad Maaitah, project partner at liquid fuels producer Enefit, told OBG. Although shale reserves were discovered over a century ago, oil prices had historically been too low to make developing these reserves viable. Rising prices in recent years enabled Jordan to develop its shale oil reserves and despite the sharp drop in oil prices since mid-2014, extraction efforts have continued.
In February 2014 the Saudi Arabian Corporation for Oil Shale announced Jordan’s lower house had approved a $2bn-3bn extraction project which will see production of 30,000 bpd by 2025. More recently, in November 2014, the government signed a memorandum of understanding for a 40,000-bpd oil shale production project, launched by Al Qamar for Energy & Infrastructure, a consortium of energy companies working in the oil and gas, oil shale, wind and solar segments. The project will cover a 64.3-sq-km block in Attarat Um Ghudran, 100 km south of Amman, with production expected to start around 2019 or 2020 at an initial rate of 10,000 bpd.
Jordan has started to develop a shalefuelled IPP, which could see shale provide up to 20% of total electricity demand. A consortium led by Estonia’s Enefit, the largest shale oil developer in the world, is in the final stages of obtaining financing for a 554-MW shale-fuelled power plant in Attarat Um Ghudran. In 2007 Enefit partnered with NEPCO, YTL Power International and Near East Investments to form a special purpose company, Attarat Power Company (APCO), which will develop the IPP, later conducting feasibility and environmental impact studies that confirmed the region’s sizeable oil shale deposits. In June 2013 Enefit announced it had received approval from the Ministry of Environment to proceed with the IPP project, with the government later reaching a power purchase agreement with Enefit, setting prices at between JD0.08 ($0.11) and JD0.09 ($0.13) per kWh.
In April 2014 APCO signed a contract with China’s Guangdong Power Engineering Corporation, which will act as engineering, procurement and construction contractor. Guangdong emerged after a competitive bidding process that saw major foreign firms submit bids. The project will not use hydraulic fracturing, or fracking, to generate energy; rather, the shale is “cooked” in oxygen-free retorts to separate much of the oil and gas, a process described as clean, cheap and productive. The remaining solid is burned to raise steam, which powers a generator, with the process producing electricity, natural gas and synthetic crude that could be used to make diesel and aviation fuel. Leftover ash can be used to manufacture cement.
Enefit authorities announced in July 2014 that they had received a $1.4bn loan from the Bank of China and Industrial and Commercial Bank in China; however, with a total budget of $2.3bn, the project will require additional financiers before it reaches financial close. Low oil prices are proving a hindrance; in 2012, Enefit told media that the project would be profitable as long as oil prices stayed above $75 per barrel. Nonetheless, Maaitah is confident the investment offers considerable returns to potential investors. “The project meets all major international benchmarks for environmental impact and offers major benefits to the mining industry, as well as employing 3000 workers directly during construction and 1500 people at power stations and in the mining sector. This project will set a precedent in Jordan,” Maaitah told OBG. “This project will set a precedent in Jordan.” Enefit itself could see further expansion in Jordan, with the company also announcing plans to construct a shale oil production plant, although the near-term focus will be to secure project financing for the IPP. Construction is set to take 38 months following financial close.
The JAEC signed a $10bn agreement with Russia in March 2015 establishing the legal basis for construction of the kingdom’s first nuclear power plant, which will offer total capacity of 2000 MW (two plants each with a capacity of 1000 MW). Signed with Russia’s state-owned nuclear firm Rosatom, the deal will see construction of a two-unit power plant in the northern Amra region, with construction expected to finalise in 2024. Under the contract, the authorities will conduct a feasibility study, site evaluation and environmental impact assessment, with Russia meeting 49% of total costs and Jordan the remaining 51%.
Although it has faced significant domestic and external stumbling blocks, Jordan’s energy sector appears poised to enter a new era of stable and more cost-effective growth. Electricity tariff reductions, new natural gas supply and falling global oil prices have bolstered the near-term outlook, while new IPPs, particularly in the renewable and oil shale segments, will go far in meeting mid-term demand.
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