What lies beneath: New exploration and production to bring the sector back to the fore

After a period of decline, Papua New Guinea’s hydrocarbons industry is preparing for a dramatic comeback, with billions of dollars of investment flowing into exploration and production. The first of several planned large-scale liquefied natural gas (LNG) production and export projects is set to come on-line in 2014.

The electricity sector has been largely static since the Electricity Commission Privatisation Act of 2002, which transformed the incumbent PNG Electricity Commission into its successor, PNG Power. However, with demand expected to continue to climb and new revenue streams anticipated from a multitude of major resource extraction projects, both the government and private investors are showing renewed interest in rehabilitating PNG’s underdeveloped power sector.

SNAPSHOT: The accuracy of production statistics in PNG is questionable, but according to the central bank, crude oil exports totalled 10.4m barrels in 2010 and 4.4m barrels in the first half of 2011. The value of crude exports in the first half of 2011 was $614m. Natural gas production in the first quarter of 2011 from the Hides field was 15.5m cu feet per day (cfd).

Oil production has declined each year since 1993 from a high of 149,300 barrels per day (bpd) to 30,360 bpd in 2010, according to the US Energy Information Administration (EIA). Proven remaining recoverable oil reserves have declined from 400m barrels in 1996 to 88m barrels in 2011. Estimates of PNG’s natural gas reserves vary widely, with BP’s “Statistical Review of World Energy” pegging reserves at 15.6trn cu feet at the end of 2010, while the EIA puts them at 8trn cu feet, UK-based consultancy Wood Mackenzie estimates 22.6trn cu feet and the government puts the total at 14trn cu feet. The wide spread is partly down to the categorisation of reserves, which can be broadly split into proven, probable and possible, and depend on the degree of confidence of recovery.

State-owned integrated power provider PNG Power forecasts an increase in energy sales from 801.4 GWh in 2009 to 1140 GWh by 2018, for an average annual growth rate of 4%. Port Moresby and the surrounding area lead consumption growth at a yearly average rate of 10%, with the northern grid at 5-7% and the rest of the country growing at 2-3%.

GEOLOGY: PNG’s geology has resulted in three primary petroleum areas. The most explored of these is the Papuan Basin Fold Belt, which runs from southeast to north-west through the centre of the mainland, and contains multiple proven oil and gas fields. Running parallel to the north is the Tertiary Basin Trend, which is relatively unexplored and presents high-risk, high-reward opportunities. The Papuan Basin Fly Platform covers the southern region of mainland PNG and has many smaller gas and condensate discoveries, providing a lower risk and cost scenario.

Since the first oil seeps were discovered by gold prospectors in PNG in 1911, the country has been slow to reveal its hydrocarbons potential, and only to those willing to brave its dense jungles. The Australasian Petroleum Company (APC), consisting of the AngloPersian Oil Company (later BP), Standard-Vacuum ( later Mobil) and Australia’s Oil Search, was one of the first to conduct major exploration in PNG. APC was gradually subsumed under Oil Search, which had incorporated in PNG and would later become its largest oil producer. Within a few decades numerous Western firms were exploring PNG’s forests in search of new energy supplies. Heading into the 1950s and 1960s, these efforts yielded a number of small oil wells, but the difficult terrain made exploratory efforts an arduous and time-consuming affair until the introduction of larger, more powerful helicopters in the late 1960s.

The first major oil strike came in 1986, when Chevron subsidiary New Guinea Gulf Oil discovered the Lagifu oilfield. The resulting appraisal efforts gave rise to the Kutubu field with large reservoirs containing upwards of 170m barrels of oil. The field’s production peaked at levels of close to 150,000 bpd in 1993.

LEGISLATION: The central legislation governing PNG’s petroleum industry is the Oil and Gas Act of 1998, which is under the administration and management of the Department of Petroleum and Energy (DPE). The DPE’s mandate is to promote and regulate the development of petroleum and other energy sources. The DPE issues five different licences for oil and gas activities, though only two are used widely in the extraction and production phases. The first is the Petroleum Prospecting Licence (PPL), issued for exploration activity and valid for an initial period of six years, after which a five-year extension may be applied for. Renewals, however, are contingent on 50% of the original tenement area being relinquished.

If the prospecting company discovers hydrocarbons in viable commercial quantities, it then has two years to conduct an appraisal programme necessary for a Petroleum Development Licence (PDL). PDLs are issued to firms wishing to engage in the development and production of petroleum or natural gas and are granted for an initial period of 25 years, with rights to extend for a period or consecutive periods of up to 20 years. The other licences relevant to the sector are the Petroleum Retention Licence, the Petroleum Processing Facility Licence and the Pipeline Licence.

ENVIRONMENT ACT: In addition to the Oil and Gas Act, companies operating in PNG must comply with the Environment Act 2000. Most hydrocarbons exploration, extraction, storage, transportation and processing operations are classified in the act as level-2 and -3 activities, meaning they are among the most potentially damaging and thus most tightly regulated. Firms undertaking these actions must comply with various procedures, including submission and approval of environmental impact statements and assessments, and social impact assessments.

Large-scale works deemed to be in the national interest (the PNG LNG project being one example) are also subject to the Physical Planning Act of 1989, which entails a full physical plan at the national and provincial level covering everything from leasing of land and construction approval to urban planning.

PNG’s petroleum regime is a classical tax/royalty system governed by licences issued under the Oil and Gas Act. The oil and gas framework also allows for substantial incentives for prospectors. These include an income tax rate of 45% for oil production and 30% for gas production, payment of royalty at 2% and a development levy at 2%. Dividends paid out from petroleum income are also exempt from income and dividend withholding tax. Oil and gas projects may also take advantage of PNG’s Infrastructure Tax Credit Scheme, in which eligible expenditures on approved infrastructure projects may be applied towards tax paid.

Other fiscal incentives include free remittance of after-tax profits abroad within limits, and an incentive for oil projects that arise from exploration licences that were granted between 2003 and 2006 for which the tax rate is reduced to 30%. The government typically takes 22.5% equity participation in the development, for which it pays just sunk costs.

DIMINISHING RETURNS: Petroleum production is primarily based in the central highlands, particularly the Southern Highlands province. Nine active petroleum development licences have been issued in PNG, for the Hides, Kutubu, SE Gobe, Gobe Main, Moran, NW Moran, South Hides, Angore and Juha tenements. One of the most consistent and productive fields has been Kutubu, which has so far yielded more than 300m barrels, demonstrating an abnormally high recovery rate in excess of 55% over its lifetime, Michael McWalter, petroleum adviser to the DPE, told OBG. However, production from the maturing field is in decline. Output is dropping by an average of 8-10% per year, according to Oil Search, despite the use of enhanced recovery techniques such as reinjection of separator gas. In the fourth quarter of 2011 gross production rates averaged 14,324 bpd and estimated ultimate recovery from the field was 357m barrels.

Also in the fourth quarter of 2011, the Moran field yielded a gross average rate of 12,023 bpd, compared to 10,823 in the third quarter, while estimated remaining reserves stood at 43.4m barrels, according to Oil Search. Gross average production at Gobe Main and SE Gobe was 1004 bpd and 1731 bpd, respectively, with remaining recoverable reserves of 3m and 3.13m barrels. Figures from Oil Search put proven and probable reserves combined for the Mananda field at 830,000 barrels at the end of 2011, with average production at 193 bpd. PNG’s only natural gas well, Hides, produced 1.27bn cu feet of gas in the fourth quarter of 2011 at an average rate of 13.8m cfd.

Falling production in the maturing oilfields has been somewhat offset by other fields coming on-line, such as the SE Gobe, Gobe Main and Moran fields, which began production in 1997. However, the results of the newer sites have been mixed, with some prospects, such as the Mananda field, in the south-east next to the Kutubu field, thus far proving much less productive than the older sites, McWalter told OBG.

DIFFICULTIES: Some of the difficulties of discovering and developing large, commercially viable reservoirs are due to PNG’s geology. In addition to the dense jungles, logistics and security issues, the dynamic geology has made it difficult to conduct accurate and detailed exploration, particularly seismic reflection surveys. Much of the exploration is conducted by analysing well-bore samples and geologic structural modelling. According to McWalter, “Drilling onshore in PNG is as expensive as in some globally remote offshore areas, due to the costs associated with exploration here, such as remote supply chains, logistics and aircraft, which are very expensive.”

Despite these difficulties, petroleum exploration activity has picked up dramatically in recent years. As of early 2011, the DPE had issued 78 PPLs, compared to 52 in 2008 and 12 in 2002. These cover almost the entire area of the Papuan Basin, as well as the majority of the North New Guinea Basin. Some of the most promising sites include the Stanley and Ubuntu discoveries, as well as the Elevala and Ketu prospects.

GAS: Largely dormant for decades, PNG’s enormous natural gas resources are now revealing their true potential, with three large-scale production and export projects currently under way. The largest of these − the $15.7bn ExxonMobil-led PNG LNG project − is scheduled to begin producing an estimated 6.6m tonnes of LNG per year by 2014 (see analysis). Next in line is the Liquid Niugini LNG project, which will tap into the Elk and Antelope gas fields located in the Gulf province. These fields have an estimated possible recoverable gas reserve of 9trn cu feet, according to hydrocarbons exploration firm Eaglewood Energy.

A joint venture between InterOil and Pacific LNG Operations, the project has already inked deals with international heavyweights Bechtel and ConocoPhillips to provide technical services for construction and LNG production. Korea Gas (Kogas), the world’s top importer of LNG by volume, also expressed interest in February 2012 when it announced it was heading a consortium, which will include Mitsui and Japan Petroleum Exploration, to join the InterOil project. The Elk and Antelope tenements have also shown commercially viable amounts of condensate, the extraction and sale of which is expected to help finance the estimated $6bn investment costs of the project.

GO WEST: A third major project is taking shape in PNG’s Western and Gulf provinces via a partnership between Canada’s Talisman Energy and Japan’s Mitsubishi Corporation. The two signed a $280m deal in early 2012 that gave Mitsubishi access to nine of Talisman’s natural gas tenements. The companies plan to work together to aggregate gas production and export 3m tonnes of LNG per year. The primary source for this natural gas may be the P’nyang, Ketu and Elevala gas fields. Talisman has also secured agreements with other junior petroleum outfits operating in the area, such as New Guinea Energy and Horizon Oil, and has acquired Papua Petroleum and Rift Oil. The firm now holds whole or partial interests in nine petroleum prospecting licences and five petroleum retention licences, encompassing a combined total of 5.54m ha.

A number of other sites are also being explored throughout the country. These include the Kimu gas field, which is operated by Oil Search, and the Pukpuk 1 and Douglas gas fields, operated by Talisman Energy. Oil Search is also conducting exploration projects at two offshore sites − the Pandora and Uramu fields.

While PNG LNG has already locked up its export contracts with its neighbours to the north, future demand for LNG projects with longer development timelines is more of a question – as are future natural gas prices. Although global demand for natural gas is expected to increase over the coming years, large reserves that are currently being explored in Central Asia could play a part in dampening demand for PNG’s output if pipelines were to be extended west to large energy consumer states, such as China and India.

STATE PARTICIPATION: Current mineral rights legislation grants the government the right to take a 30% stake in any domestic mineral extraction and 22.5% in oil and gas operations. To manage these mineral development projects, the government established Petromin PNG Holdings in 2007 with a mandate to hold state equity in oil, gas and mineral projects, and maximise revenue gains from the sector. As of 2011 Petromin held a direct equity stake in the Moran project (20.5%) and a 0.2% share in the PNG LNG project.

Despite the company’s mandate to hold state interests in petroleum and mineral projects, Kroton No 2 holds the state interest in the PNG LNG project under the supervision of the Independent Public Business Corporation (IPBC). The IPBC borrowed $1.74bn from the Abu Dhabi government’s International Petroleum Investment Company to cover the government’s 16.6% equity share in the project. The government then borrowed a further $428m after it lost millions of dollars through interest payments and conversions from Australian to US dollars. The government has exceeded its 22.5% threshold of ownership for the PNG LNG project, with a 24.5% share through the holdings by IPBC, Petromin and its residual ownership in Oil Search.

GIVING SOMETHING BACK: In addition to taxes paid on oil and gas extraction projects, companies must comply with PNG’s legislation mandating that developers must compensate landowners for damage, severance from and usage of their land.

The government has also devised a series of benefits for the landowners of petroleum development sites. These are intended to be used at local level for quality-of-life and infrastructure improvements, such as potable water supply, roads, community centres, communication, sanitation and other services. Landowner and host community benefits for development projects – particularly for oil and gas – have steadily increased in value. Currently there is a 2% royalty, 2% free equity and 2% development levy.

While these payments to the government are transparent and straightforward, the disbursement of funds to the regional and local levels is more convoluted, due to the large number of distribution programmes, government bodies and agencies. Various tools are used to carry this out, including the statutorily defined Expenditure Implementation Committee, infrastructure development grants and, for the PNG LNG project, the Umbrella Benefit Sharing Agreement and the Licence-Based Benefit Sharing Agreement.

Landowners are entitled to 2% equity in a project, offered via the transfer of a portion of the government’s stake in a given project to a purpose-specific incorporated landowner association. For example, landowners at the Kutubu field are represented by Petroleum Resources Kutubu, which holds a 6.75% stake in the field, alongside Oil Search (60.05%), Ampolex PNG Petroleum (an ExxonMobil affiliate), Merlin Pacific Oil Company (14.52%, also an ExxonMobil subsidiary) and Merlin Petroleum Company (18.69%, an affiliate of JX Nippon Oil and Gas Exploration). Separate landowner companies hold a 2% equity interest in each of the PDLs granted by the state and those interests are managed by the Mineral Resource Development Company.

DOWNSTREAM: PNG petroleum is a light, sweet crude, the vast majority of which is shipped to New Zealand and Australia for refinement. The country’s sole oil refinery is operated by InterOil and has a maximum capacity of 35,000 bpd. Established in the late 1990s, the second-hand refinery was originally set up by Chevron in Alaska before being shipped to PNG and retooled for its new job. The acquisition was facilitated by OPIC, the overseas investment arm of the US State Department, which guaranteed the loans to InterOil for the purchase. Recommissioned in 2005 as the Napa Napa refinery outside Port Moresby, the facility also maintains a 1.5m-barrel oil reserve.

Some of the demand for imported fuel could be met by large-scale employment of biofuels, a practice already used in more remote areas of the country. As of 2012, at least three separate private biofuel production projects were in early developmental stages.

OUTLOOK: Despite steadily increasing consumption levels, PNG will remain a net energy exporter in the coming years as production ramps up. With global demand for natural gas widely expected to rise dramatically, PNG is well positioned to take advantage, with three large-scale LNG export programmes in the pipeline. Petroleum reserves are expected to continue to decline as the older fields mature, although the increase in exploratory licences bodes well for future discoveries. Additional new reserves could also be discovered, depending on the findings of a joint study launched by Shell and Petromin in August 2011, which will determine the potential of the large-scale oil and gas deposits found in the country’s major basins.