By: Christis Enotiades
Undoubtedly, the early monetisation of proven hydrocarbon reserves, be it oil or gas, takes precedence over any other objective of E&P operators who, in the process, have spent millions in exploration. Expediting the monetization of hydrocarbon reserves reflects their business resolve to bring these resources to the market and establish the much needed revenue streams for the upstream partners. Thus, following a successful exploration, E&P operators will appraise the monetisation options/technologies available and take an appropriate FID on how to develop the gas field most efficiently i.e. minimising capex and opex. The company’s profitability and competitiveness depend on this and their sole criterion will be the projected profits to be realised over the life cycle of the gas find in question. Profitability, in turn, depends on various cost and profitability drivers such as transportation costs as well as current and projected market prices.
Current & Projected LNG Prices
LNG prices over the last decade displayed the same symptoms as those of any other commodity going through phases of excess demand and oversupply. More specifically, in the past five years since the Fukushima accident, the LNG market moved from a phase of market tightness, marked by constrained supply due to high demand and subsequent high prices to a phase of global oversupply which inevitably led to a precipitous decline in LNG prices. For the first time in the past three years, LNG price-affluent Asian markets recorded an all time low during recent months. More specifically, in January 2014 LNG spot prices in Asia were about $20mmBtu, which allowed for significant profits to be made for exporters. In the past seven months, however, LNG spot prices in Asia had dropped dramatically to about $10, emphasizing the uncertainty of the global LNG marketplace. This was the
inevitable outcome of market dynamics.
On the demand side, a sluggish demand for LNG in Japan and South Korea, two of the world’s biggest importers, coupled with a slowed-down rate of economic growth in China and India, caused demand to contract.
On the supply side of the market, a steady flow of LNG production from long established suppliers, such as Qatar and Australia, coupled with fresh supplies from new players such as Papua New Guinea’s new LNG export terminal, which started deliveries as of May 2014, increased production resulting to excess supply which weighed down on LNG prices in Asia. As a consequence, there had been reports of LNG shipments being sold at a loss or diverted to other market destinations in Europe.
A gloomy prospect for East Med LNG to Asian markets
The middle to long-term outlook for LNG prices in Asia is quite grim as additional quantities from South East Asia and the U.S1 are expected to increase LNG competition. At the same time Russia’s efforts to diversify its export markets away from Europe to Asia makes to-be exporters of LNG feel uneasy.
1
Already, Japan’s trade ministry and Alaska’s Department of Natural Resources signed a MoU for 20million tons per year of LNG i.e. 25% of its annual imports of 87.5 million tons for the generation of electricity as well as its retail, industrial, commercial and residential urban needs. This MoU, is aimed at helping Japan to procure lower cost LNG. The shipping route from Alaska to Japan is shorter than that from the Middle East, thus helping Japan lower freight and thus LNG import prices. This is in line with Japan’s strategy to focus on making LNG imports secure and at the same time cheaper. Similarly, Russia’s parliament has already agreed to write off almost $10 billion of North Korea’s debt, in a deal expected to facilitate the building of a gas pipeline targeted by Gazprom to carry 10 bcma of natural gas to South Korea.
Clearly, the recent slide in the Asian LNG prices has signalled alarms for lower profitability which subsequently exerted additional pressure on LNG projects currently being developed, especially for those with cost overruns which in turn make them vulnerable to lower margins.
At the same time, the influx of additional quantities of LNG from East Africa, South East Asia and the U.S. into the Japanese and S. Korean markets is expected to exert further pressure on LNG prices.
These two markets constitute the two biggest world markets for imported LNG and, henceforth, are strategically focused on LNG producers closer than the Middle East. Consequently it is not surprising hat E&P operators in the East Med are inclined to postpone their FID on future LNG and/or FLNG
export projects2.
The importance of Regional Markets for East Med natural gas
The uncertainties and complexity of the LNG market described above have encouraged E&P operators Noble Energy and their partners Delek to diversify their planned exports of Leviathan and Tamar to Regional Markets in order to achieve an early monetisation of the natural gas finds in
Israel’s EEZ. Such markets include the Palestinian Authority, Egypt and Jordan. It is interesting to observe the chronological sequence of these events:
i) In January 2014, the Leviathan basin partners signed their first export deal – a $1.2billion sales
agreement with the Palestine Power Generation Company, which would provide a future power
plant in Jenin with 4.75 bcm of gas over 20 years.
ii) In February 2014, the Tamar reservoir partners signed a $500 million deal to provide 1.8 bcm of
gas to the Jordanian firms Arab Potash and Jordan Bromine over 15 years, beginning in 2016, to
power their Dead Sea facilities.
iii) In May 2014, the partners of the Tamar reservoir signed a letter of intent with Spanish firm
Union Fenosa, for the provision of 71 bcm to that company’s Egyptian liquefaction facility in
Damietta.
iv) In June 2014, a MoU has been signed with British Gas (BG) for a $30billion deal for the supply of
7bcm of natural gas annually for 15-years from Leviathan to BG’s Idku LNG Export Plant in
Egypt.
v) An additional MoU has been signed with Jordan for the supply of 3bcm of natural gas annually
for a period of 15 years, i.e. 45bcm worth $15billion5
Thus far, the development of these two reservoirs is planned with the application of pipeline
technology given their proximity to the littoral markets.
However, the market for East Med natural gas should not be limited to the Middle East. It can be widened to include more distant fragmented regional markets in South Europe thus diversifying the market, whilst at the same time spreading and minimising the risk in a geopolitically volatile area.
Such markets, situated within a range of up to 2,500km, include the Greek Islands in the Aegean and Ionian Seas, Crete, South Italy and even Croatia as depicted in the map here below. Some of these markets/clients do not have a large enough demand profile to sustain the commercial viability of onshore LNG regasification terminals or to justify the investment for the construction of subsea pipelines, yet they urgently need to replace the highly priced and highly polluting fuel oil, gas oil and diesel with natural gas in the generation of electricity. These markets can easily be accessed using marine CNG which is a more versatile and flexible technology than Pipelines which are non-scalable and must be built to ultimate capacity.
2 One such case may have been the announcement by Leviathan’s partners to delay their FID decision for a $6billion
investment for the development of Leviathan for 2015 – “Noble Energy delays $6b Leviathan investment”
http://www.globes.co.il/en/article-noble-energy-delays-6b-leviathan-investment-1000959496
3 “Transmission lines for gas export to be financed by companies, not Israeli government” JPS By SHARON UDASIN –
09/08/2014 – http://www.jpost.com/Israel-News/Transmission-lines-for-gas-export-to-be-financed-by-companies-not-
Israeli-government-374772
4 “Leviathan partners negotiating $30b BG deal”- Globes Israel’s Business Arena dated 29/06/2014 –
http://www.globes.co.il/en/article-leviathan-partners-negotiating-30b-agreement-with-bg-1000949654
5 “Jordan signs MOU to buy $15b Leviathan gas” Globes Israel’s Business Arena dated 29/06/2014 –
http://www.globes.co.il/en/article-jordan-signs-mou-to-buy-15b-leviathan-gas-1000969042
Transportation costs for CNG from East Med to South European markets
Source: Sea NG Alliance
The impact of Market Prices and Transportation Costs
To best illustrate the impact of destination market prices and of transportation costs on E&P
Operators’ netbacks, both regionally and globally, we will use the data in the table here below which
compares the Netbacks to East Med E&P Operators generated by different technologies both regionally and
globally:
Exports from Block 12 in Cyprus EEZ to Regional and Global Markets
Notes to the Table:
1. Europe: 2014 average natural gas price US$10.00-US$11.00/ MMBtu. The European LNG price in Sept’ 2014 stood at
$9.24 i.e. a change of -17.87% over Vs 2013. http://ycharts.com/indicators/europe_natural_gas_price
2. Asia, spot LNG prices almost halved in H1 2014, from around 20 $/mmbtu to just above 10 $/mmbtu, are now back
above 13 $/mmbtu for November ’14 delivery. This is still below long term Asian contract levels (15-16 $/mmbtu at
$100/bbl crude) and well short of spot price levels at the start of this year. http://www.timera-energy.com/commodityprices/
the-next-phase-of-global-gas-pricing/
3. Contract term of 20 years following three years build period
4. SAL buoy loading & offloading for CNG (up to 300 meter water depth)
5. Block 12 proven reserves between 3.6-6 tcf. Assuming proven reserves to be 4.8tcf x 28.31bcm/tcf = 135.84bcm/20
years as per contract term/life cycle approx. 7bcm per year
6. Loading and unloading equipment located on-board CNG ships
7. 13% unlevered IRR
8. Pipeline Capex of $6.5 million/km for deep water. No Opex included
9. Gas consumed as fuel valued as shrinkage
10. Gas composition typical of eastern Med.
11. FLNG based on Mozambique FLNG by Eni – Capex $1billion/mpta
From the table above one can safely deduce the following:
i) Given the current natural gas prices in Europe and Asia as well as the corresponding transportation costs,
East Med’s natural gas comparative cost advantage lies in Regional Markets which can yield a higher
netback than Global Markets with LNG. – One needs only to compare the netback that may be generated
by CNG in Column 1 versus the netbacks generated by LNG, and Pipelines regionally and by LNG globally. In
fact, both Pipelines and LNG are non-starters for exports to Regional Markets in Southern Europe.
ii) Even though FLNG seems to be generating a higher netback than a 2-train LNG plant, yet, according to LNG
Industry Magazine (Nov-Dec 2014) experts believe that as pipeline gas from Russia starts to flow to China
this event alone can drive prices down from US$ 13/MMBtu to US$ 10 – 10.5/MMBtu. Moreover, FLNG
requires a hefty upfront investment which may exceed $2.5billion when compared to FCNG where the
capex as well as the implementation risks are undertaken by the provider of the CNG vessels.
iii) Given the sharp decrease in the price of natural gas in Asia and an analogous decrease in Europe,
“transportation” is becoming a critical cost driver
Conclusion
Evidently, in their evaluation of the long term commercial viability of a development project process, E&P Operators take a global view of the markets as there are critical profitability and cost drivers impacting their netbacks, such as current and projected market prices as well as transportationcosts.
Of paramount importance is the potential competition from suppliers to the target markets, which may further suppress prices, as well as the possibility of diversifying exports.
Numerous new LNG export projects and Pipelines have been announced globally from SE Asia, North America, Russia and East Africa towards the back end of this decade. Inevitably, these will boost supply to a point where supply will exceed demand leading to a revaluation of higher cost LNG projects some of which may be altogether abandoned.
Therefore, after taking all these criteria into consideration one can easily conclude that East Med’s natural gas comparative advantage clearly lies in supplying the Regional Markets where E&P Operators may maximise their netbacks with the lowest possible capex and opex by using marine CNG technology.
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