The true cost of imported LNG – and what it means for electricity prices

For years, public debate in Cyprus has focused almost entirely on the international price of LNG. Every discussion about importing natural gas eventually arrives at the same question: what will LNG cost? It is an understandable question – but increasingly the wrong one. The price Cyprus pays for LNG is only one component of the cost of supplying gas to its power stations. Once the cost of financing the import infrastructure, settling the arbitration, operating the terminal, recovering capital investment, transporting and regasifying LNG is included, the economics change dramatically. In addition to when, the real question is therefore not whether LNG costs $8/MMBtu, but what the gas will cost by the time it reaches EAC and PEC power stations. Following the reassessment of the Vasiliko LNG import project presented in the previous article, this question deserves careful examination. LNG is only the starting point An LNG cargo arriving in Cyprus does not go directly to a power station. It passes through an entire value chain. The LNG must first be purchased on the international market and delivered to Cyprus. It is then unloaded into the floating storage and regasification unit (FSRU) Prometheas, stored, regasified, transferred ashore through high-pressure pipelines, metered, compressed where necessary and finally delivered to power stations. Each step adds cost. The commodity price of LNG is therefore only the beginning. The full cost chain Assuming an international LNG price of $8/MMBtu, recovery of project capital would be between $5.5–6.5/MMBtu, operations and maintenance between $1.0–1.2/MMBtu, financing and insurance between $0.5–0.8/MMBtu and cargo logistics and operational inefficiencies, $0.5–1.0/MMBtu. This brings the cost of delivering gas to power stations to between $15.5–17.0/MMBtu. This means that the infrastructure costs are almost as large as the cost of the LNG itself. This is highly unusual by international standards. The reason lies in the economics of the project rather than the technology. The utilisation problem The Vasiliko terminal was designed around an FSRU capable of regasifying approximately 5 billion cubic metres of gas (bcm) annually. Cyprus, however, is expected to consume only about 0.7bcm/yr for electricity generation in the foreseeable future. That means the terminal would operate at roughly 15 per cent of its technical capacity. From an engineering perspective this presents no serious difficulty. From an economic perspective it is a major problem. Whether the terminal processes 0.7bcm or 5bcm each year, it still requires: operators, maintenance, inspections, safety systems, insurance, management and financing. These costs are largely fixed. They do not reduce simply because less gas passes through the terminal. Consequently, every MMBtu delivered to consumers carries a disproportionately high share of the project’s capital and operating costs. This is the single biggest factor affecting the economics of imported LNG. Why throughput matters Annual throughput terminal add-on is estimated at $7-8/MMBtu for 0.7 bcm/year and $5-6/MMBtu for 1.0 bcm/year. The infrastructure itself changes very little. Only the volume of gas increases. As throughput rises, the fixed costs are spread over more gas and the cost per unit falls rapidly. Unfortunately, Cyprus is simply too small a market to utilise the terminal efficiently. The Prometheas issue The FSRU Prometheas is another factor affecting operating costs. Although technically suitable for Cyprus, it has an LNG storage capacity of about 137,000 cubic metres, smaller than many of today’s LNG carriers, which increasingly carry 170,000–174,000 cubic metres or more. This does not prevent operation. However, it reduces commercial flexibility. Cyprus may need to purchase smaller cargoes or arrange partial deliveries. Such cargoes generally attract higher shipping costs per unit of gas than those delivered to large import terminals handling continuous volumes. Because Cyprus would import only eight to ten cargoes annually under a 0.7 bcm market, it would also have less purchasing power than larger LNG importers. These operational penalties are relatively modest – perhaps $0.5-1/MMBtu – but they reinforce the effect of low utilisation. The hidden cost of capital Perhaps the biggest change since the project was approved is the level of capital that now needs to be recovered. The original business case was based on an investment of around €300 million. As discussed in the previous article, a realistic risk-adjusted assessment now suggests that total project costs could approach €1.0-1.2 billion once completion costs, arbitration, financing, commissioning and contingency are taken into account. That increase fundamentally changes the economics. Instead of recovering €300 million over the life of the project, consumers may ultimately need to recover three or four times that amount through the gas tariff. The consequences become particularly severe when annual throughput remains below one billion cubic metres. Clearly what matters as far as the electricity price is concerned, is not the price of imported LNG, but the price of gas as delivered to the EAC and PEC. I am not sure this has ever been calculated using realistic risk-adjusted project costs. Part Three in this series of articles will convert these gas costs into electricity generation costs, compare them with oil-fired generation at Brent $70/barrell, assess the implications for consumers, and explain why the original expectation of significantly lower electricity prices may no longer hold. This is Part Two in a series of three articles on LNG imports.