MIT study cautions smaller nations on rushing to develop their natural gas resources; Cyprus as model
|Cyprus offshore hydrocarbon exploration blocks. Paltsev et al. Click to enlarge.|
Based on the interim results of a new study, MIT researchers are warning smaller nations to proceed with caution in pursuing the development of their natural gas resources. The study is a part of of a larger report that will further take into account the changing dynamics of the regional and global gas markets, giving a comprehensive view of the implications for the long-term development of natural gas in Cyprus and other like nations.
The interim report analyzed the economics of natural gas project development options in Cyprus with a focus on exports. (The authors noted that Cyprus will have sufficient resources for developing export capabilities regardless of the extent of domestic gas substitution in the coming years, given its rather small energy consumption profile.) The report explored three major options for monetizing the resource: an onshore LNG plant; a transnational undersea pipeline; and the deployment of a CNG marine transport system. The researchers expect to finish the larger report in August 2014; the study is sponsored by The Cyprus Research Promotion Foundation.
While natural gas is often cheaper than oil and gives off fewer emissions, developing the resource comes with risks, especially for smaller nations. The cost for these smaller nations makes up a larger portion of their economies, so before spending the money, they need to have the proper expectations.—Sergey Paltsev, an author of the study and a principal research scientist at the MIT Energy Initiative
The MIT researchers found that it will take Cyprus about five years to put their natural gas resource to use; the required investments will make up to a quarter of the country’s Gross Domestic Product (GDP).
That’s a substantial amount of a country’s economy dependent on a resource that has proven to be unpredictable in the past. Natural gas development is so new to such regions, and the global gas market is changing so rapidly, that there’s a large amount of uncertainty.—Sergey Paltsev
|Exploration and production activity in the Eastern Mediterranean. The Levant Basin contains the activity closer to Cyprus, while the gas production offshore Egypt is a part of the Nile Delta Basin. Click to enlarge.|
Background. In 2007, MIT signed an agreement with the Government of Cyprus to aid in the development of The Cyprus Institute (CyI) Center for Energy, Environment, and Water Resources through human resource development and joint research. MIT and CyI researchers have been working together on initiatives of importance to the Mediterranean island nation and the region with the focus on water, energy, and climate change.
Cyprus faces serious shortages of both drinking water and energy; the nation uses fossil fuels to power water desalination, so the two problems are intertwined. A major joint research project has therefore been investigating the use of concentrated solar power to produce both electricity and desalinated seawater. Analysis has shown that this novel cogeneration concept is technologically viable in Cyprus. Among the concepts coming out of this work are an innovative storage system, installation of heliostats on hillsides, and an advanced-design desalination system.
During the past two years, a deep budget problem in Cyprus led to a slowdown of the project with three projects selected for 2012–2014 extension of the original five-year agreement. The projects involve underground exploration which has strong implication for gas and oil exploration offshore of Cyprus; technologies for joint production of solar energy and desalinated water; and a study on natural gas monetization options for recent gas discoveries offshore Cyprus.
In December 2011, Noble Energy announced the discovery of a major natural gas reservoir offshore Cyprus, in Block 12 of its Exclusive Economic Zone (EEZ). The “Aphrodite Field” is located 1,700 meters (5,577 feet) below sea level with initial estimates of recoverable volumes in the 5–8 trillion cubic feet (Tcf) range. As of August 2013, Noble began drilling its second appraisal well.
Earlier this month, Noble announced that the A-2 appraisal well drilled on the Block 12 discovery offshore the Republic of Cyprus successfully encountered approximately 120 feet of net natural gas pay within the targeted Miocene-aged sand intervals. The Cyprus A-2 well, which is more than four miles northeast of the A-1 discovery location, was drilled to a total depth of 18,865 feet (5,750 m) in 5,575 feet (1,699 m) of water.
Evaluation of drilling data, wireline logs and reservoir performance information resulted in an updated estimate of gross resources of the field ranging from 3.6 trillion cubic feet (Tcf) of natural gas to 6 Tcf, with a mean of approximately 5 Tcf. The Cyprus A structure represents the third largest field discovered to date within the Deepwater Levant Basin, Noble said.
In the meantime, the government has licensed four additional blocks for exploration to Total, Eni, and Kogas. As of August 2013, drilling had not commenced in these other blocks. (Earlier post.)
(BP puts the global proved reserves of natural gas—those that can be recovered from known reservoirs under existing economic and operating conditions—at 6,600 Tcf. Estimates of shale gas technically recoverable reserves are about 7,200 Tcf. Global gas use in 2012 was 117 Tcf.)
These numbers tell us that, while this is a significant find for a country the size of Cyprus, it’s only a small fraction of the global resources. Most likely, Cyprus will never be a major player in the global gas markets, but that doesn’t mean natural gas can’t benefit the country’s economy if developed properly.—Francis O’Sullivan, the director of research for the MIT Energy Initiative
The MIT team noted that the offshore Cyprus discovery was part of a larger trend in the Eastern Mediterranean Sea, which has become over the last decade an active region for offshore oil and gas exploration. In 2010, the US Geological Survey (USGS) estimated that the Levant Basin—the basin of which the Aphrodite Field is a part—held 122 Tcf of potentially recoverable natural gas, while the Nile Delta Basin’s potential stood even higher at 223 Tcf.
Noble has also discovered the 9 Tcf Tamar Field offshore Israel (2009), followed by the 17 Tcf Leviathan Field, also offshore Israel. Leviathan is 36 km (22 miles) from Aphrodite, and is the largest discovery in the region. (Earlier post.)
What’s happening in Cyprus is a good model for other countries like it that are exploring natural gas, according to Paltsev. The small nation has been teetering back from a near collapse of its banking industry and searching for revenue. When a major natural gas reserve was discovered off its coast two years ago, Cyprus leaders saw it as a golden opportunity.
Economic analysis. The economic analysis of gas monetization pathways in the report is primarily based on discounted cash flow (DCF) techniques. Inputs to DCF analysis include all of the capital and operating expenses associated with a project along with financial and fiscal parameters, and assumptions regarding plant utilization levels and operating lifetimes. Common generic outputs from DCF analysis include net present value (NPV) and internal rate of return (IRR).
In the Cyprus report, the output of the DCF analysis is presented in terms of breakeven gas price (BEP), which represents the gas price needed to ensure that a project’s NPV is zero, and as such that it is the price needed for the project to be value neutral. If the realizable price is above the BEP, then the project will create value and should be pursued. If not, then the project would destroy value and should not be undertaken.
The MIT team defined a base scenario for each of the three pathways, and subjected those to the DCF analysis.
LNG analysis. The LNG economic analysis focused on the liquefaction stage of the value chain. Given the current level of proved reserves, the analysis assumes the construction of a single 5-Mt LNG liquefaction train, with an expected operational lifetime of 20 years.
Input parameters include the project’s capital costs, its operating costs, the plant’s fuel loss factor, and the plant’s utilization rate. The capital cost of the LNG plant was set at $1,200/tonne of nameplate capacity. Operating maintenance costs were set at $0.20/MMBtu of throughput, the plant’s fuel loss factor was set at 8% of output, and the plant’s utilization level was set at 85% of nameplate.
The authors assumed any initial Cypriot liquefaction project would likely be a stand-alone entity—i.e.,not integrated with upstream development—i.e., the plant will pay a rate for its feed gas to the upstream development operator. This feed gas cost was assumed to be $2.50/MMBtu.
The analysis suggested that in the base cases, BEP prices are $9.75/MMBtu for the Cyprus LNG option to the European markets, and $10.25/MMBtu for the Cyprus LNG option to the Asian markets.
While a clear political maneuver, building an LNG terminal would also create jobs and raise revenue. Depending on the tax scheme, it may raise $1.5 billion in taxes. Still, it would cost about $6 billion to build, for a country that has a GDP of about $25 billion. The cost of building an LNG terminal is far more than the cost of building a pipeline, though LNG offers greater flexibility to adjust production to changing natural gas prices and market supplies—perhaps outweighing the upfront costs, the authors suggested.
Submarine pipeline analysis. On-shore pipelines are well established; offshore pipelines pose some technical challenges in deployment and maintenance, the authors observed. However, given that the gas resource is offshore, the construction of one or more offshore pipelines is already anticipated—a 200 km (124-mile) line from the Aphrodite Field to Vasilikos—as part of the plan to build an LNG plant onshore. Such an upstream pipeline will likely be a necessary precursor to every monetization option for Cyprus, unless the country turns to floating technology options.
The current resource estimate of 5-7 Tcf gas would be insufficient to support both an LNG and an export pipeline option, the authors noted. However, if additional gas is found or brought in from other countries, that might change.
Two submarine pipelines are under consideration: one to Greece and one to Turkey (although the latter might prove more of an issue geopolitically than technically, according to the report).
The analysis concluded that the BEP if $10.32/MMBtu for the Cyprus offshore pipeline option to the European markets.
CNG marine transport. Compressed natural gas marine transport is the continuous compression, transport, and delivery of natural gas via ship. Although CNG does not attain the the same energy density of LNG (thus reducing the economies of scale to long-haul shipment), recent advances in compression have seen the achievement of up to half the energy density of LNG.
Further, the authors noted, proponents of such a system claim that what is lost in long-haul efficiency is recovered in lighter infrastructure costs (essentially just a compression facility, which can be placed on a floating platform/vessel or onshore); a shorter development period (one to two years rather than four-plus years for LNG); and the potential price premium that such a system could achieve for delivery to smaller, stranded energy markets that do not have large enough demand profiles to justify the investment in regasification infrastructure (or a pipeline).
Because such a system has not yet been deployed commercially, the report authors had to rely on industry data. The authors formulated a preliminary base case based on the technology for Sea NG—a company that has been most active in the Eastern Mediterranean—assuming an onshore facility at Vasilikos, with a shuttle system that can reach as far as the Greek mainland. The capacity of the system is lower than those of the other options, given the limitation in scale.
The results found that the breakeven landed gas price for this pathway $5.86/MMBtu.
If this were to be a realistic result, it would suggest CNG has huge economic appeal. However, this result should not be taken as conclusive, given the potential bias in the source material available.—Paltsev et al.
Observations. Base case assumptions lead to the following IRRs: 14.8% for the Cyprus LNG option to the European markets; 20.5% for the Cyprus LNG option to the Asian markets; and 13.6% for the Cyprus offshore pipeline option to the European markets.
Considering the pipeline option, it should be noted that a natural gas exporter does not have the same flexibility to react to the changing market conditions (for example, to re-orient the flows from European to Asian customers) as an exporter does with the LNG option. There is also an issue of potential disputes with transit countries. An LNG terminal might be more costly to develop than a pipeline up front, but the relative flexibility of supply to different markets based on changing market conditions will likely outweigh such a difference in capital costs.
LNG development is also not without major risks, particularly for small nations like Cyprus in which the necessary investment, even for modest LNG projects (around $6 billion) is on the same order of magnitude as the country’s GDP (around $25 billion). The potential benefits of growing an LNG industry in Cyprus will include employment opportunities and, of course, a potentially large revenue stream for the nation through taxes and royalty payments and dividends from entities the nation holds equity in.—Paltsev et al.
O’Sullivan and Paltsev warn that even projects that start out having clear economic gains can become less profitable because of poor technical planning and execution or bureaucratic and regulatory delays.
The funding for this study is provided solely by The Cyprus Research Promotion Foundation. While Eni S.p.A. and Total are members of MITEI and have exploration interests in Cyprus as described in the report, they have not contributed to any input, output, or funding related to this research.