Two years ago the Australia liquefied natural gas (LNG) story was about a “golden age,” during which the Land Down Under would super-cool vast volumes recovered from coal seams onshore and from immense offshore fields and meet demand from fast-growing emerging and reaccelerating developed Asian economies.

Today, although the country is poised to shoot up the rankings of LNG exporters to heights now occupied by world No. 1 Qatar, the tale is far more prosaic.

A recent report from the International Energy Agency (IEA) underscored the reality that Australian gas producers will face increasing pressure from the US and Canada as it lifts exports to Asia.

Nearly all US and Canadian LNG project developers are targeting Asian markets, which offer a more attractive price differential than European markets. The conflict on the Black Sea over Russia’s claim to Ukraine’s Crimea region may generate additional political will to accelerate US LNG exports, but the lead time from final project approval to first gas is a long one.
Although that price differential narrowed after US gas prices surged above USD6 per thousand British thermal units (MMBtu) this winter, Asian buyers still pay an average roughly USD18 per MMBtu and spot prices climbed above USD20 per MMBtu.

The front-month natural gas futures contract traded on the New York Mercantile Exchange recently closed at USD4.27 per MMBtu. A widely quoted natural gas benchmark for Japan and Korea recently closed at USD15.90 per MMBtu versus USD13.22 for Southwest Europe and USD12.72 for Northwest Europe.

In late March Canada’s federal minister of natural resources issued final approval for four LNG export licenses, all for projects proposed along the British Columbia coast.
The four facilities–Pacific Northwest LNG, Prince Rupert LNG, WCC LNG and Woodfibre LNG–were previously approved by Canada’s National Energy Board in December 2013. The licenses cover the export of up to 73.38 million metric tons, or about 3.43 trillion cubic feet (Tcf), per year.

A representative of the US Energy Information Administration (EIA) recently told a US Senate committee that the construction of Cheniere Energy Inc’s (NYSE: LNG) Sabine Pass facility in Louisiana, the only US LNG export project with approvals from both the Dept of Energy and the Federal Energy Regulatory Commission (FERC), may already be altering the dynamics of gas contracts, with gas purchasers noting that they felt that they’ve had more successful opportunities to negotiate with large gas suppliers for better contract terms since the facility entered the construction phase.

The EIA forecasts US net exports of LNG of 3.5 Tcf by 2040, though that figure could be nearly twice as much if oil prices remain high. By 2040 roughly 800 billion cubic feet (Bcf) of LNG will be exported from Alaska and 2.7 Tcf of LNG will be shipped from terminals being developed along the US Atlantic and Gulf coasts.

In addition to Sabine Pass, which will produce 2.2 Bcf per day, Freeport LNG, Lake Charles LNG, Dominion Cove Point LNG, Jordan Cove LNG and Cameron LNG have received DoE approval. The latter five await FERC approval.

By law, the DoE must quickly approve applications to export LNG to countries with free-trade agreements with the US, such as Korea, but can modify or block applications to ship to non-FTA countries, such as Japan and much of Europe. There are 24 applications in the DoE approval queue.
But all is not lost for Australia’s LNG industry.

New plants for exporting LNG from the US have been held up by regulatory delays as government agencies have failed to assess issues such as environmental impact as quickly as the projects’ backers had hoped. The conflict on the Black Sea over Russia’s claim to Ukraine’s Crimea region may generate additional political will to accelerate US LNG exports, but the lead time from final project approval to first gas is a long one.

And the Canadian projects are of the “greenfield” variety–as opposed to largely “brownfield” conversions of LNG import terminals in the US–and will therefore entail a much longer time horizon until they reach the production phase.

There is a substantial window of opportunity for companies with projects already producing LNG cargoes and for those who will get on the market in 2014 and 2015.

Australia currently has seven LNG plants under construction. When all are completed by 2018 the nation will be the largest exporter of the super-cooled fuel, overtaking Qatar.

Australia’s three operating LNG projects produce about 24.2 million metric tons of LNG per year, with the seven developments being built slated to boost that by another 61.8 million metric tons.

The problem for the oil and gas companies spending some USD192 billion on the seven plants is that costs have increased well beyond the initial budgets, while the certainty over LNG demand and pricing has eroded somewhat.

That’s not to say that current LNG projects won’t have buyers for their fuel, as the bulk of the planned output is already contracted.

But there are still projects with a total capacity of 31.5 million metric tons awaiting final investment decisions and another potential 65.8 million metric tons of expansions under consideration.

It is this second wave of investment that the industry is warning is at risk.

But all is not lost for Australia’s and the greater Australasian region’s LNG industry. There is a substantial window of opportunity for companies with projects already producing LNG cargoes and for those who will get on the market in 2014 and 2015.

According to the International Gas Union World LNG Report for 2013, LNG trade fell in 2012 after 30 years of consecutive growth. Global flows fell by 1.6 percent from 241.5 million metric tons in 2011 to 237.7 million metric tons in 2012. The contraction was largely driven by supply-side issues in Southeast Asia and domestic and political challenges in the Middle East and North Africa (MENA) region.

Japan and Korea, the world’s dominant LNG importers, accounted for 52 percent of the market, up 4 percent from 2011.

But global LNG demand should continue to grow in the short term and the market will continue to be supply constrained at least until 2015, as few projects are expected to come online in the next few years.

Qatar already produced at nameplate capacity in 2012, and few other projects have room to boost utilization if Southeast Asian and North African projects continue to decline.

Power sector gas demand will continue to drive the regional redistributions of LNG flows in future quarters, the supply constraint during 2013 and 2014 may force a number of markets to take a more critical look at the issue of import cost, subsidies and pricing.

Coupled with a with a tight supply picture, each market’s ability and willingness to pay for LNG and their relative shares of long-term versus spot supply, may require additional attention. Given the economics of small-scale LNG, this emerging tranche of demand may also demonstrate willingness to pay high prices for new supply.

As of 2014 four more markets will be importing LNG–Israel, Malaysia, Singapore, and Lithuania. With the addition of these markets, there will be 15 new markets that did not import before 2005.

Japan’s nuclear situation will be the major determinant of spot and short-term volumes over the next couple of years. Thus far only two nuclear reactors are back online, resulting in a major power generation gap that has been mostly been made up for by LNG. If European LNG demand continues to be weak, Asian and South American markets have proved a willingness to pay for more expensive cargoes above their long-term contracts.

The PNG Play

AE Portfolio Aggressive Holding Oil Search Ltd (ASX: OSH, OTC: OISHF, ADR: OISHY) is an increasingly valuable oil and gas property, with significant, identifiable and realistic production and revenue upside.

As of Dec. 31, 2013, the USD19 billion Papua New Guinea Liquefied Natural Gas ( PNG LNG) project was more than 90 percent complete and remained on budget, with first LNG sales on track for the second half of 2014.

Commissioning activities continued during the fourth quarter, with the introduction of gas from the Kutubu field into the Hides Gas Conditioning Plant in December, which management described as “a major milestone.”

And work by the PRL 3 joint venture continued on the potential development of the P’nyang field as a resource for PNG LNG expansion.

Management previously reported that scoping studies are expected to continue through 2014 in preparation for the submission of a development license application for the field in early 2015. Seismic programs over P’nyang as well as the adjacent Juha field, which had been suspended due to the wet weather season, started up again during the fourth quarter.

Oil Search also reported that updated guidance from PNG LNG operator Exxon Mobil Corp (NYSE: XOM) suggests first production from the project will occur during the first half of 2014.

And output is likely to fall between 5.7 and 8.2 MMboe net to Oil Search for calendar 2014.

Oil Search issued initial 2014 PNG LNG production guidance of 3.8 to 6.3 MMboe in late 2013.

Annual PNG LNG output net to Oil Search is likely to approximate 21 MMboe.

Based on this updated information from Exxon Oil Search upped its production guidance for 2014 to 12 MMboe to 15 MMboe from 10 MMboe to 13 MMboe.

It is in fact a rarity for an operator to offer a positive update for an LNG project.

One March 2011 study found that for LNG projects completed between 2000 and 2010 only 29 percent were completed ahead of schedule, by an average of four months, while 34 percent were completed late, by an average of nine months. Another 24 percent of projects experienced material post-commissioning issues, with an average of four months lost production within the first year of operation.

The safe assumption is that Exxon’s startup date will be refined over the course of the first half of 2014. But for now PNG LNG is moving in the right direction.

Oil Search reported full-year 2013 production was 6.74 million barrels of oil equivalent (MMboe), slightly above the 6.2 to 6.7 MMboe guidance range and 6 percent higher than full-year 2012 output of 6.38 MMboe.

Total revenue for 2013 was USD766.3 million, up 6 percent from USD724.6 million in 2012, as Oil Search benefited from strong global oil prices during the quarter, realizing an average price of USD113.33 per barrel.

Production for the fourth quarter of 2013 was 1.77 MMboe, down from the 1.79 MMboe for the prior corresponding period. Revenue for the three months ended Dec. 31, 2013, was down 3.8 percent to USD210 million from USD218.2 million a year ago.

Oil Search spent USD392.6 million on exploration, development and production activities during 2013, of which USD307.4 million was related to PNG LNG. Spending was funded by cash, operating cash flows and drawdowns from the PNG LNG project finance facility and the company’s corporate debt facility.

As of Dec. 31, 2013, Oil Search held USD210 million in cash and had USD300 million in undrawn credit, for total liquidity of USD510 million.

Total debt was USD4.02 billion as of Dec. 31, 2013, including USD3.82 billion drawn on the PNG LNG project finance facility and USD200 million from the company’s USD500 million corporate facility.

The consensus among analysts is that Oil Search’s earnings will more than quadruple to AUD791 million over the next two years alone. And management has indicated that PNG LNG will drive a stepped-up dividend policy.

Oil Search is a buy under USD8 on the Australian Securities Exchange (ASX) using the symbol OSH and on the US over-the-counter (OTC) market using the symbol OISHF.

Oil Search also trades as an American Depositary Receipt (ADR) on the US OTC market under the symbol OISHY. Oil Search’s ADR represents 10 underlying shares traded on the ASX and is a buy under USD80.

Diversification Strategy

Origin Energy Ltd (ASX: ORG, OTC: OGFGF, ADR: OGFGY) is Australia’s largest vertically integrated energy retailer. Its diverse operations span the energy supply chain, from oil and gas exploration and production to power generation and energy retailing.

Its 37.5 percent stake in the Australia Pacific Liquefied Natural Gas (AP LNG) project, which is expected to make first delivery of cargoes in mid-2015, is expected to drive growth for its Exploration and Production unit.

ConocoPhillips (NYSE: COP) owns 37.5 percent of AP LNG, while China Petroleum & Chemical Corp, better known as Sinopec (Hong Kong: 386, NYSE: SNP), owns the remaining 2 percent.

AP LNG consists of two processing trains, each with nameplate production capacity of 4.5 million metric tons per annum (mtpa). The project is supported by a 7.6 million mtpa, 20-year offtake agreement with Sinopec and a 1 million mtpa, 20-year supply deal with Japan’s Kansai Electric Power Co (Japan: 9503, OTC: KAEPF, ADR: KAEPY).

AP LNG is gathering momentum after struggling with cost overruns in 2012. The second train is on track for early commissioning, and drilling rates are well ahead of target, which should open up additional opportunities for third-party sales.

In its recent quarterly production update management noted that the upstream component of the AP LNG was approximately 58 percent complete as of Dec. 31, 2013, while the downstream component was 62 percent complete.

Regarding the upstream components of the project, drilling and completions and gathering are ahead of schedule. The main pipeline is nearing completion, and commissioning continues on the Condabri Central gas plant and the water treatment facility.

As for downstream work, all LNG refrigeration compressors for Train 1 have been set. A 2,600-bed accommodation camp is complete. The compressor table tops for Train 2 are complete. The methane and ethylene cold boxes were delivered and set in January 2014. And the last Train 1 module is expected to be set in May 2014.

The project is on time and on budget.

AP LNG will deliver what management describes as “a step change” in Origin’s earnings and cash flow beginning in fiscal 2016, when the project begins to deliver LNG under its existing long-term contracts.

Speaking after the company’s first-half results, Managing Director Grant King said Origin was looking at opportunities to expand its LNG exposure once the USD24.7 billion AP LNG starts generating cash flow in fiscal 2016.

The significant Caravel prospect off the coast of Dunedin is of potential magnitude to support LNG exports if the AUD50 million-plus well being drilled there came off.

Mr. King is looking to leverage the education gleaned from Origin’s AP LNG experience, though nothing is imminent.

Origin is benefitting in other ways from the LNG buildout in Australia.

Origin recently reached an agreement with Gladstone LNG partner Santos Ltd (ASX: STO, OTC: STOSF, ADR: SSLTY) to supply the project with “at least” 100 petajoules (PJ) of gas over five-year period beginning Jan. 1, 2016.

Origin has an option to supply up to another 94 PJ.

This is another positive step as Origin attempts to monetize its east coast gas portfolio. The deal could add between AUD100 million and CAD270 million per year in cash flow.

Origin’s retail transformation and cost-reduction program should drive better operating performance in the Energy Markets business. Although fiscal 2014 will likely be another tough year for energy retailers, fiscal 2015 and fiscal 2016 should be much better.

Origin also finalized a number of funding initiatives to extend its debt maturity profile and improve its liquidity position. Origin has AUD6.5 billion in existing liquidity, comprising committed undrawn debt facilities and cash. This strong liquidity position is substantially more than that required to satisfy Origin’s remaining funding requirements for its 37.5 percent shareholding in AP LNG.

And Origin doesn’t have any material refinancing requirements until fiscal 2018.

A return to normalcy for Energy Markets will provide a strong, reliable foundation as AP LNG ramps up.

Origin Energy is a buy on the ASX using the symbol ORG and on the US OTC market using the symbol OGFGF under USD15.

Origin also trades on the US OTC market as an ADR under the symbol OGFGY. Origin Energy’s ADR, which represents one ordinary, ASX-listed share, is also a buy under USD15.

The Big E&P, LNG & Dividends

Woodside Petroleum Ltd (ASX: WPL, OTC: WOPEF, ADR: WOPEY), Australia’s biggest oil and gas exploration and production company by market capitalization, posted company-record annual production for 2013 of 87 million barrels of oil equivalent (MMboe), up 2.5 percent versus 2012, driven by the Pluto LNG project, which went into production in March 2012.

Pluto LNG is underpinned by 15-year sales agreements with Kansai Electric and Tokyo Gas Co Ltd (Japan: 9531, OTC: TKGSF, ADR: TKGSY). Both companies became project participants in January 2008, each acquiring a 5 percent interest in the project. Woodside owns 90 percent of Pluto.

Onshore infrastructure comprises a single LNG processing train with a forecast production capacity of 4.3 million mtpa.

Fourth-quarter production of 23.2 MMboe was up 5.9 percent and sales volumes were 10 percent higher on a sequential basis largely due to increased production at Pluto LNG following the re-start of the liquefied natural gas train and the change-out of dehydrator beds during the third quarter.

Sales revenue for the fourth quarter was up 23.2 percent to USD1.648 billion, largely due to sales contracts adjustments for volumes already delivered by Pluto.

Year-over-year output was down 4.5 percent predominantly due to lower oil production as a result of the Vincent floating production, storage and offloading (FPSO) unit being shut in for a time and natural field decline at other oil assets.

The North Rankin Redevelopment Project achieved start-up during the quarter, while management also noted that Pluto plant reliability and production exceeded all previous quarters. And the Vincent FPSO vessel re-started production on Nov. 29, 2013.

Revenue for the quarter was 6.7 percent versus the fourth quarter of 2012. The impact of reduced sales volumes was partially offset by a one-off price adjustment for Pluto. The average Brent price for the quarter was USD109.35 per barrel, slightly below the USD110.13 in the prior corresponding period.

Year-over-year revenue was impacted by the higher proportion of gas volumes sold in 2013, resulting in lower average realized prices. Additional oil is expected in 2014 with the restart of the Vincent FPSO.

Management had reduced its 2013 production target in July after an unplanned shutdown at its AUD15 billion Pluto LNG plant in Western Australia and delays to the refurbishment of the Vincent floating production storage and offloading vessel. The vessel re-started production on Nov. 29, 2013.

Woodside recently reached an agreement to supply natural gas from Pluto to Japan-based Chubu Electric Power Co Inc (Japan: 9502, OTC: CHUEF).

Woodside will sell as much as 1.5 million metric tons of LNG over three years to Chubu, Japan’s third-biggest power utility. Financial terms weren’t disclosed.

The deal adds to purchases of Australian fuel by Japan, the world’s biggest importer of LNG.

Woodside will send gas to Chubu mainly from previously uncommitted Pluto supplies.

Mitsubishi Corp (Japan: 8058, OTC: MSBHF, ADR: MSBHY) and Mitsui & Co Ltd (Japan: 8031, OTC: MITSF, ADR: MITSY) earlier this month withdrew from an agreement to buy LNG from Woodside’s proposed Browse LNG venture in Australia after delays to the project. The Japanese companies, which reached a deal in 2012 to buy a 14.7 percent stake in Browse for USD2 billion, will continue to work with Woodside to jointly sell LNG from the development to the Asian market.

In April 2013 Woodside scrapped plans for the proposed onshore development of the 12 million mtpa, USD46 billion Browse LNG project. Management is now pursuing a floating-platform option based on technology developed by venture partner Royal Dutch Shell Plc (London: RDSA, NYSE: RDS/A).

CEO and Managing Director Peter Coleman described the decision to halt the Browse development as one of economics. Mr. Coleman noted, “The cost escalation on Browse has been consistent with other projects in Australia. Unfortunately, the cost escalation has been such that the total costs…have resulted in the current development concept not being commercial.”

Considering a cheaper capital option is prudent under current circumstances, partly given the uncertain outlook for LNG demand over the next four or five years.

Woodside, sustaining management’s pledge to ramp up the oil and gas producer’s payout following the start-up of Pluto LNG, declared a final dividend in respect of 2013 of AUD1.03 per share.

That’s up 58.5 percent from a final dividend of AUD0.65 for 2012. It follows a special cash dividend of AUD0.63 declared on April 23, 2013, and paid on May 29, 2013, as well as a 2013 interim dividend of AUD0.83, which was up 27.7 percent from AUD0.065 for the prior corresponding period.

All told Woodside declared dividends of AUD2.49 per share for 2013. That works out to a yield of 6.5 percent based on Woodside’s March 13, 2014, closing price on the ASX.

Woodside Petroleum is a buy under USD42 on the ASX using the symbol WPL and on the US OTC market using the symbol WOPEF.