A common thread to Papua New Guinea’s two largest energy projects to date – the PNG liquified natural gas (LNG) mega-project and the upcoming Elk-Antelope play – is that while both are now controlled by energy supermajors Exxon and Total, neither was originally discovered by their current operators. Like the development of new “elephant” projects across the globe, exploration for new major oil and gas plays is often left to smaller oil and gas firms, which operate on much smaller capital resources than their larger brethren. These “wildcat” outfits, as they are often called, serve as the lifeblood of the energy sector, often risking their reputations and sometimes their financial lives on finding and developing tenements deemed either too risky or too inconsequential to the larger, vertically-integrated oil companies that dominate the global industry.
Squeeze Below
Unfortunately for these wildcats, the recent slump in crude oil prices has had a chilling effect on the industry, as the price of West Texas Intermediate (WTI) crude nearly halved from more than $90 a barrel in October 2014 to about $50 a barrel by January 2015. This decline has further exacerbated an already challenging situation for companies of small and medium-sized capital, for which acquiring capital to maintain operations has been a severe challenge since the global economic downturn hit in 2008. This scarcity of financing has hit these “smaller cap” firms – which historically have relied heavily on bank loans in the form of a corporate revolving credit facility to raise funds – particularly hard, especially those lacking in scale or whose risk is concentrated in a single project or country.
With competition for loans stiffened as many banks have been forced to tighten lending controls, companies are also turning to more alternative sources of finance, such as the bond market, project partners, private equity and export credit agencies. Even large international oil companies (IOCs) with healthy balance sheets and huge operating cashflows have not been immune to this new environment, as they come under increasing pressure from shareholders to curb capital spending and increase cash returns. The net result of these conditions has been a dramatic shrinking of budgets for exploration and development across the board.
Viability
Prices, however, remain the key factor affecting the viability of offshore projects. “If crude oil prices persist below $50 a barrel, there will be a dampening effect on oil-directed exploration and production (E&P) activity in regions of the world that are burdened with high breakeven costs,” said the publisher of World Oil magazine, Ron Higgins, in a January 2015 statement. “We expect that offshore projects that have a long producing horizon will continue, as will activity in fields where capital costs already have been sunk, and operating costs are manageable.” The barrel price of WTI crude hovered around the $50 mark twice in early 2015 before rallying to around $60 in May and June, then dipping again in early July to around $52 amid mounting concerns about economic stability in Europe and Asia.
While the larger IOCs have the resources to weather this storm, lower-rated companies face more obstacles. Ratings agency Standard & Poor’s took 23 rating actions across US oil and gas E&P firms in early 2015, nearly all them downgrades and negative outlook or CreditWatch revisions due to potential liquidity pressures in 2015. Further actions in this vein are possible if prices do not rebound in 2016.
Shutting Rigs
This sustained trend of slack commodity prices has led to a precipitous drop-off in the number of rigs in use internationally. This figure has declined from a high of 3900 in February 2011 to 2127 by May 2015, according to Houston-based oilfield services’ firm Baker Hughes, which has tracked rig usage since the 1940s. The good news for PNG is that the decline has been much less pronounced in the Asia-Pacific region, where the number of active rigs averaged 230 in the first five months of 2015, compared with 254, 246 and 241 in the previous three years. More expensive shale gas projects in North America have, conversely, been hit the hardest, with US and Canadian rig activity falling from an average of 1919 and 365, respectively, in 2012 to 1201 and 219 rigs in the first five months of 2015.
While the decline in rig activity will reduce E&P in the short term, longer-term projections paint a slightly rosier picture. In January 2015, Moody’s Investors Service revised its assumptions for average spot prices for a barrel of Brent crude to $55 through 2015, $65 in 2016 and $80 in the medium term, and for a barrel of WTI crude to $52 in 2015, $62 in 2016 and $75 in the medium term. The prospect of an impending price rebound gives companies a further incentive to carry out new exploration, particularly the more complex projects in frontier and deep-water fields, which have longer lead times. Investing now also capitalises on the current lower costs of development, pulled down by the oversupply of drilling rigs and other finite infrastructure.
New Hope
In spite of the difficult economic climate, a number of smaller, more agile companies have been able to maintain exploratory work across PNG. Small and mid-cap oil and gas exploration outfits that are currently operating in the country include Otto Energy, Nido Petroleum, Santos, Kina Petroleum, Cott Oil and Gas, Cue Energy Resources, Twinza Oil, Drillsearch Energy, Horizon Oil and Tailsman Energy.
Taking a Punt
One of the few outfits forging ahead in the offshore sector in PNG is Kina Petroleum, which managed to buck international trends by receiving a $15.2m injection in November 2014, when PIE Holdings LP purchased 61.4m shares in Kina, a 19.9% stake. PIE Holdings is an investment vehicle held by Phil Mulacek, founder and former chairman and CEO of InterOil. The company under Mulacek explored the Eastern Papuan Basin, which eventually led to the impressive Elk-Antelope and Triceratops finds. Kina is using part of the funding to further explore and develop its nine tenements encompassing 40,660 sq km across PNG in hopes of replicating earlier successes in the basin.
The most developed of these is petroleum retention licence (PRL) 21 in Western Province, which contains the Ketu, Tingu and Elevala gas fields projected to drive a mid-scale LNG project in the future. Kina owns a 15% stake in the project, as well as a 57.5% share in the adjoining petroleum prospecting licence (PPL) 437, which abuts PRL 21 to the north and east. Twice as large as PRL 21, the second development area contains the Malisa, Candlenut, Mango and Kandis plays, which could potentially be added to the existing fields already under development. The Gosur seismic programme was carried out using nodal seismic acquisition systems on the Malisa formation in 2014, with early results indicating that the prospect is similar to the Tingu 1 discovery. A wider-ranging seismic reprocessing programme was also carried out across PPL 437 in 2014.
Exploration work in the Malisa play is also being coordinated with Eaglewood Energy, which holds PPL 259 to the west of PPL 437, to better synchronise the development of the field that straddles the two tenements. Eaglewood and PPL 437 partner Heritage Oil executed a cost-sharing agreement that allows Heritage to carry out a combined survey consisting of two contiguous exploratory programmes across both licences. Similar mutually beneficial arrangements have been made with Horizon Oil, operator of PRL 21, to share fixed costs such as seismic crews, camp infrastructure, unused consumables and other logistical costs.
Offshore
While virtually all of the existing exploration and development projects in PNG have so far centred on onshore reserves, which are more cost-effective and easier to access, offshore projects are now being eyed as the next wave of production. Four junior companies – Cott Oil and Gas (with a 40% stake), Kina Petroleum (25%), Talisman Energy (25% and acting operator) and Santos (10%) – have teamed up to develop PRL 38, located about 200 km offshore in the Bay of Papua, west of Port Moresby. The main area of interest is the Pandora field, discovered in 1988 and thought to contain two principal structures (Pandora A and Pandora B) with contingent resources of 792bn cu feet (bcf) at a depth of 120 metres. Several options are now being explored to monetise the find, the two most viable being aggregation with Western Province fields and infrastructure, or developing PNG’s first floating LNG (FLNG) project.
Joint Option
The first option would entail teaming up with Horizon Oil and Talisman Energy to link into their development of significant gas discoveries in the foreland of the West Papuan Basin, which are expected to underpin a mid-scale LNG facility at the port of Daru. This alternative also has the added advantage of the participation of two large Japanese energy importers, Mitsubishi Corporation and Osaka Gas, which have farmed into the project to accelerate its development.
Floating Option
At nearly 800 bcf, the Pandora gas field is also of sufficient size to justify development as a standalone field using FLNG technology. To this end, Cott Energy commissioned a feasibility study for the project, which could produce upwards of 200m standard cu feet per day (scfd) from a three-well development. Carried out by Wison Offshore and Marine, the study presented two options: a fixed, near-shore LNG facility, and an offshore FLNG project. The first entails field production by a buoyant tower where natural gas will be collected and pretreated before being transported along 160 km of subsea pipeline to a 170,000-cu-metre storage barge jetty moored in at least 14 metres of water. The vessel would take about three years to build, and the project would house two liquefaction trains, each with a liquefaction capacity of 500,000 tonnes per annum (tpa). Capital expenditure for this option is estimated at $600-700 per tonne of LNG throughput.
The second option, FLNG, involves building a similar capacity facility housing two water-cooled liquefaction trains of 500,000-tpa capacity, along with a 170,000-cu-metre storage tank vessel and supporting infrastructure, including on-board gas treatment infrastructure, gas turbines, external turret mooring, accommodation and utilities. Construction would take slightly longer, at 38 months, with a final cost of $900-1100 per tonne of LNG throughput.
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