The Songo Songo field offshore Tanzania was discovered in 1974 by AGIP. Thirty years later the field was developed to supply natural gas to the Dar es Salaam power generation and other industrial customers. The limited market for natural gas in East Africa during that time meant that no gas fields would be developed in a timely manner.

With the success of countries like Qatar with LNG sales, however, the focus on exploration for natural gas in regions with limited local markets is intensifying. Australia, East Africa, the Russian Arctic, and even Canada are lining up to feed LNG into expanding Asian markets since there is not enough domestic demand to absorb the huge natural gas resources in the producing regions.

The speed of development for natural gas finds has accelerated as well. The development of the more than 100 Tcf of natural gas in place discovered offshore Tanzania and Mozambique within the past four years will take place much more quickly than development of the Songo Songo field. It is those same reserves that are attracting newer and bigger players. The same could be said for LNG projects in Canada and Russia.

Since Cove Energy began a four-well program in December 2009 in Rovuma Offshore Area 1, the players have changed dramatically. Cove was swallowed up by PTTEP after the Thai company engaged in and won a bidding war with Royal Dutch Shell. Now Anadarko Petroleum, Eni, Statoil, ExxonMobil, Petrobras, Shell, and BG are tapping into new reserves along the East African coast. Many of the smaller companies that started the play do not have the financial strength to develop those reserves. Anadarko’s proposed Afguni LNG plant in Mozambique will cost an estimated US $15 billion for the first two of a proposed 10 LNG trains.

LNG ante keeps escalating

The cost of an LNG development includes the production platforms and wells in the field, the gathering and transportation pipelines, and the gas processing and liquefying facilities. The cost of monetizing these reserves is escalating rapidly.

For the Gorgon LNG facility on Barrow Island on Australia’s Northwest Shelf, the cost has skyrocketed to $52 billion – the highest cost for any LNG plant worldwide. Chevron, Shell, and ExxonMobil are developing the Gorgon, Jansz, and Io gas fields, which have a combined 40 Tcf of total potential gas resources. The LNG plant consists of three trains with a total capacity of 15 million metric tons per year (MMmt/year). Plant startup is planned for late 2014 with the first export cargo scheduled for 1Q 2015. Australian press reports speculate the final cost of the project will be even higher.

Chevron also is involved in the $29 billion Wheat-stone LNG Project, which is on track to begin commercial operations in late 2016. The plant consists of two trains with a capacity of 8.9 MMmt/year. Total potential gas resources are estimated at 10 Tcf. Chevron, Apache, Kuwait Foreign Petroleum Exploration Co., and Shell own the majority of the project. Natural gas will be supplied from the Wheatstone, Julimar, and Brunello fields.

Inpex and Total are the major players in the Ichthys Project in the Browse basin offshore Western Australia. Resources are estimated at 12.8 Tcf of gas and 527 MMbbl of condensate. The field will be developed with subsea completions, a semisubmersible central processing facility, and an FPSO vessel for the condensate. The gas will be transported to a two-train LNG plant with a capacity of 8.4 MMmt/year, which is near Darwin, Northern Territory. The cost is estimated at $32 billion.

The newest technology being touted is the world’s first floating LNG (FLNG) vessel for Shell’s Prelude field off the northwest coast of Australia. The FLNG facility will have a capacity of 3.6 MMmt/year of LNG, 1.3 MMmt/year of condensate, and 400,000 mt/year of LPG. The Prelude field has an estimated 3 Tcf equivalent of resources. Subsea wells will be tied back to the FLNG facility. Shell, Inpex, and Korea Gas Corp. (KOGAS) are the major players. The cost is estimated between $8 billion and $15 billion. The facility is expected to be moored in the field by 2017. Once the field is depleted, the FLNG facility can be moved to a new location.

On the east coast of Australia there are three LNG facilities under construction and two others planned. Australia-Pacific LNG (APLNG), involving partners ConocoPhillips, Sinopec, and Origin, will cost $23 billion, Queensland Curtis LNG (BG) will cost $20.4 billion, and Gladstone LNG (GLNG) involving partners Santos, Petronas, KOGAS, and Total will cost $18.5 billion.

These are just the projects in Australia that have made a final investment decision and started construction. The common themes that run through all of the projects are the participation of supermajors and national oil companies and the multibillion dollar price tags on all of the developments.

Gas supply, prices drive projects

Despite the cost associated with LNG developments, the huge volume of natural gas already discovered in areas far from demand centers is driving the development of fields offshore East Africa and in the Russian Arctic. More than 100 Tcf of gas in place have been discovered offshore Mozambique and Tanzania. The Australian Bureau of Agricultural and Resource Economics estimated potential coalseam gas (CSG) resources in eastern Australia at 250 Tcf.

Low domestic gas prices in Australia, Canada, and the US are providing momentum for LNG projects that would allow those countries to export LNG to tap into the $12/MMBtu and $17/MMBtu prices in Europe and Asia, respectively. That same market dynamic is heating up the competition between projects in those three countries.

The Henry Hub spot price Feb. 25 was $3.42/MMBtu. The Alberta price Feb. 26 at AECO was $3.02/MMBtu. Australia does not have a spot market. Prices are set by contract. Generally, prices are in the $6/MMBtu to $7/MMBtu range, according to domestic operators. The most recent contract signed was for $9/MMBtu.

With prices in Japan at $15/MMBtu to $17/MMBtu and huge potential markets in China and India, the incentive for developing LNG projects is clear. Without those higher prices, though, exploration and development will begin to fall off, leaving a lot of natural gas in the ground.

Shale revolution opens US exports

The renaissance of the US oil and gas industry with the advent of horizontal drilling in shale plays has had major impacts worldwide. The entire North American natural gas market has shifted from expecting a shortage of gas and building LNG import terminals to having an oversupply and promoting construction of liquefaction plants to export LNG. That has been an amazing turnaround in only five years.

Record US natural gas production boosted by shale plays has resulted in declining US natural gas prices and a pushback of natural gas imports from Canada, providing the impetus for constructing LNG plants on the US Gulf Coast and the west coast of Canada.

Cheniere Energy, which led the charge for building import terminals in the US, is now leading the way for LNG export plants. In July 2012 the company secured $5.6 billion in financing for the Sabine Pass Liquefaction Project for developing, constructing, and placing into service the first two trains with a combined capacity of 9 MMmt/year. Construction has started on the first two trains, which are expected to be in service in late 2015 and mid-2016, and is expected to begin on Trains 3 and 4 in 2013.

What helps Cheniere in its cost for the plant is that it is a brownfield project. The liquefaction plant will be able to use the storage tanks and docking facilities that were built for the import terminal. That will be a benefit to the companies using the plant. The facility does face a huge logistical problem: the transportation cost for moving LNG to Asia. Australia and Canada will have a price advantage delivering LNG to Asia over US exporters because of that distance.

Operators in the US, Canada, and Australia are betting on the export markets raising the price of natural gas in all three countries.

In total, 18 US LNG export projects have been proposed or identified by sponsors with a combined export capacity of 25.4 Bcf/d, according to the Federal Energy Regulatory Commission. Of these, eight are brownfield projects based on existing import terminals, and 10 are greenfield facilities.

The majority of the proposed projects (14) are on the Gulf Coast to take advantage of gas supplies from the Haynesville, Fayetteville, and Eagle Ford shales. The Cove Point import terminal in Maryland would have the advantage in tapping Marcellus and Utica supplies.

It is unlikely that more than two or three of these projects will be built. Cheniere funded a report by Deloitte MarketPoint to look at the impact of US LNG exports. The report on “global impacts of LNG exports from the United States” was based on exports of 6 Bcf/d, which was an assumption to enable evaluation of what impacts might arise.

One of the key findings was that “US LNG exports are projected to narrow the price difference between the US and export markets, and hence the market will likely limit the volume of economically viable US LNG exports.”

Also, gas exporting countries like Russia and Australia could suffer a decline in trade revenue due to price erosion and/or supply displacement, Deloitte continued. If the price differential does narrow, it could mean lower netback to US producers.

Canada’s shale plays boost projects

According to Joe Oliver, Canada’s natural resource minister, British Columbia has estimated total gas in place of 1,200 Tcf, which could supply Japan’s LNG needs for 275 years. He cited a Conference Board of Canada report that stated the province’s natural gas industry could generate investments up to $180 billion through 2035.

With vast amounts of gas reserves in the Liard and Horn River formations in British Columbia, which are beyond the resources currently included in the Kitimat LNG project with Apache Corp., Chevron would consider expanding its proposed LNG terminal on Canada’s west coast. Kitimat, with a capacity of 10 MMmt/year, is one of the first proposed LNG projects in the province and one of only two facilities with a National Energy Board export license.

There are nine proposed projects with a list of longtime LNG players, including Shell, KOGAS, PetroChina, Petronas, ExxonMobil, and BG. The most recent project approved is LNG Canada in the Kitimat area. Shell, KOGAS, Mitsubishi Corp., and PetroChina International are the partners in the facility that would have a capacity of 24 MMmt/year.

With its gas sales in the US being displaced by shale gas, Canada is focusing on the Asian markets. “US and Canadian imports will likely compete against each other to some degree, and the impact to US LNG exports would be partially mitigated by offsetting actions from Canadian exporters,” the Deloitte report noted.

However, the Canadian export projects still face challenges from First Nations groups over permission to build pipelines from the gas fields to the export plants. The federal and provincial governments are pushing hard to get approval for these projects. But construction has not started on any new pipeline projects to date. Pacific Trails Pipeline LP, which would supply the Kitimat LNG project, did sign a revised benefits agreement with the First Nations Group LP that represents 15 First Nations along the 463-km (278-mile) pipeline route.

Because Canada is closer to Asian markets than US Gulf Coast producers, the Canadian producers have a transportation cost advantage. The Deloitte report also noted that “US LNG exports could hasten the transition away from oil price indexation of gas supply contracts.”

Asian buyers have begun to push for such a transition. The Kitimat LNG project, for example, has run into Asian customers seeking lower natural gas prices. Chevron and Apache have both balked at these demands, with Chevron warning Asian utilities and other potential buyers that unless LNG purchases are oil-price indexed, the Canadian projects will not be built, according to an article Feb. 1 in the Financial Post.

Australia likely will be the primary competition with Canada for the Asian markets. So far the Australian projects have been able to tie up production with long-term contracts. Any delay in the Canadian projects would give an advantage to projects in Australia that have not made a final investment decision.

Australian exports drive CSG development

With its huge coal reserves in Queensland, Australia has a ready-made source of natural gas for both the domestic market and exports. Companies have been producing CSG for more than two decades for the domestic market. Developers know that the gas is there, but with low domestic gas prices, there has been no incentive to spend the money needed to develop the resource. APLNG with two trains and 9 MMmt/year, Queensland Curtis LNG with two trains and 8.5 MMmt/year, and GLNG with two trains and 7.8 MMmt/year are that incentive.

The owners of the three plants are pushing development of CSG in the Surat and Bowen basins to supply the export market. Queensland Gas Co. (QGC) has drilled about 1,100 wells and expects to drill a total of 6,000 wells over more than 4,500 sq km (2,317 sq miles) by 2030 to supply the Queensland Curtis LNG project. Each well costs a little more than $1 million to drill, according to BG, QGC’s owner. The company has estimated reserves and resources of 25 Tcf with proved and probable reserves of 9 Tcf. It expects to have drilled a total of 2,000 wells by 2014 when the plant begins exporting.

Arrow Energy, a joint venture of Shell Australia and PetroChina, has not made a final investment decision on its LNG plant, which also would be built on Curtis Island. The company has drilled about 1,000 wells so far and expects to drill a total of 15,000 wells to support its two-train plant with a capacity of 8 MMmt/year.

APLNG has more than 17,000 sq km (6,564 sq miles) of CSG acreage in the Surat and Bowen basins and 18,000 sq km (6,950 sq miles) in the Galilee basin, which “will provide the potential CSG production capacity required to feed the LNG facility for decades,” according to the company’s executive summary. “A total of 10,000 wells are anticipated over the life of the project.”

Diana Hoff, vice president of technical and engineering for Santos, said, “Our first environmental impact statement had 2,500 wells” to supply the GLNG plant. “Now we’ve applied for more wells, and we will be drilling 300 wells per year over the next several years to meet demand.”

However, construction of the three projects is ahead of the pace of the drilling. This marks the first time that three LNG projects are being built simultaneously by the same contractor at the same location by different owners. All three projects consist of the same three segments: upstream field development, a pipeline from the fields to the plants, and the LNG plants. Bechtel Australia Pty. Ltd. is the engineering, procurement, and construction contractor.

QGC is the furthest along on construction with 45% of its 42-in. pipeline buried and 97% of the pipe in position for welding. The pipeline crossing from the shore to the island was coming up in March or April. “QGC expects first gas to be delivered in 2014. About 50% of the work on the LNG plant and jetty is complete. We expect to raise the roof on one of the storage tanks on Jan. 31,” Chris Booker, community liaison officer of projects for QGC, told E&P in Gladstone.

GLNG’s Garry Scanlan, regional manager, said the company’s pipeline installation was at an early stage. Less than 100 km (60 miles) of the 440-km (264-mile), 42-in. pipeline had pipe in position. The first tank roof lift was expected in March. The plant modules will be delivered over the next 12 months. A total of 111 modules are being built in the Philippines. First export cargoes are expected in mid-2015.

The engineering for APLNG is mostly complete, and about 20% of the construction is done. First LNG is scheduled for July 2015, according to Kevin Berg, principal vice president and general manager, Gladstone, Bechtel Australia.

Challenges remain for the projects, including escalating costs. Origin, the largest producer of CSG in Australia, reported a 7% increase in the budget for APLNG to $25.7 billion due to increased drilling costs. GLNG and Queensland Curtis LNG also announced budget increases because of the need to drill more wells and the strong Australian dollar.

East Africa, Arctic, eastern Mediterranean gas

The challenges of rising costs are magnified for companies that are faced with developing huge gas reserves with greenfield projects. For example, the discoveries in East Africa just keep coming. Eni announced a discovery Feb. 25 in the Coral 3 delineation well in its Mamba Complex in Area 4 offshore Mozambique, which confirmed the potential of the complex at 75 Tcf of gas in place. Coral 3 was drilled in 2,035 m (6,715 ft) of water and reached a total depth of 5,270 m (17,391 ft). The well is located approximately 5 km (3 miles) south of Coral 1, 15 km (9 miles) from Coral 2, and approximately 65 km (39 miles) off the Cabo Delgado coast. The well encountered 117 m (386 ft) of gas pay in a high-quality Eocene reservoir.

Eni plans to drill another delineation well, Mamba South 3, to assess the full potential of the Mamba Complex discoveries before moving back to exploration drilling in the southern sector of Area 4.

Given the massive reserves in Offshore Areas 1 and 4, the operators have agreed to a joint development. In December 2012 Anadarko (Area 1) and Eni (Area 4) reached a heads of agreement (HOA) with Eni establishing foundational principles for the coordinated development of the common natural gas reservoirs spanning both areas. The HOA is designed to facilitate a work program whereby the two operators will conduct separate yet coordinated offshore development activities while jointly planning and constructing a common LNG park in the Cabo Delgado Province of northern Mozambique.

Working with the Mozambican government, the companies have a target of first LNG cargoes in 2018. Front-end engineering and design contracts have been awarded for both onshore LNG construction and offshore installation.

To date, Anadarko and its partners have discovered two major natural gas complexes in Offshore Area 1: The Prosperidade Complex is estimated to hold between 17 Tcf and 30 Tcf-plus of recoverable natural gas resources. The distinct Golfinho/Atum complex is estimated to hold 15 Tcf to 35 Tcf of recoverable natural gas resources. Evaluation of a third discovery on the block, Tubar?o, is ongoing, with an appraisal well that was expected to be drilled in early 2013.

Tokyo Electric Power Co. and Tokyo Gas may buy LNG from the project. The timing of the startup of the plant and pricing formula are concerns for the two companies. The Japanese firms want to index the gas price to Henry Hub or the UK’s National Balancing Point. Japanese buyers could opt for as much as 5 MMmt/year of LNG, according to press reports.

BG and Ophir Energy have discovered about 10 Tcf of gas resources offshore Tanzania; however, the remote location, lack of infrastructure, and limited government capacity to handle large investments is causing the company to slow down its operations. The government has requested that BG and Statoil study an LNG export project. BG is studying exploration data before deciding on the next course of action. The company expects to release its drilling rig offshore Tanzania by June 2013.

East Africa is not the only country expecting to develop LNG facilities before 2020. Russia has two projects that could be completed by 2018: Yamal LNG with three trains and 15 MMmt/year and Vladivostok LNG with three trains and 15 MMmt/year. Yamal LNG would be built on the Yamal Peninsula in the Russian Arctic and develop the South Tambley field. Novatek (80%) and Total (20%) are the development partners. Novatek is seeking other partners as well.

Gazprom made the final investment decision on the Vladivostok LNG project on the eastern coast of Russia. Gas would be transported from the Sakhalin, Yakutia, and Irkutsk production centers. Field development and pipeline construction is estimated to cost $40 billion. The other major deepwater gas play that will be developed by an LNG project is in the eastern Mediterranean Sea. Noble Energy has been operating offshore Israel since 1998. The company is the operator of the Tamar field with a 36% operated working interest. Tamar has gross mean resources of 9 Tcf of natural gas, and development drilling is under way. Noble is working on providing additional gas deliverability until Tamar comes online in 2013.

In late 2011 the company had a significant discovery offshore. The Leviathan field represents the largest exploration success in Noble’s history with gross mean resources of 17 Tcf of natural gas. The company is actively studying multiple export options, including both LNG and pipeline scenarios. Also in 2011, the company made another discovery offshore Cyprus with estimated gross mean resources of 7 Tcf. In early 2012 a sixth consecutive field discovery was made at Tanin with estimated gross mean resources of 1.2 Tcf. Noble has now discovered approximately 35 Tcf gross of new gas resources in this region.

The key to the development of these huge gas reserves is LNG. The competition for markets will be fierce, and the landscape in worldwide LNG trade will be altered dramatically.