Eye on the long term: Pushing ahead with exploration and market liberalisation efforts

Long regarded as a challenging environment for investors due to the its often unpredictable political climate and its vast geography, the Philippines is nonetheless making significant strides in laying the foundations for a more stable and productive energy sector. The oil and gas sector has recently offered up more than two dozen new production blocks for tender, many of which show considerable promise, while plenty of hope is currently being placed on the potential offshore deposits located deeper in both the East and West Philippine Seas.

Great headway has also been made in the liberalisation of the power sector, as solid legislation continues to pave the way for the growth of private investment and healthy competition in electricity generation and distribution. The transfer of power assets from the public to the private sector has also shown healthy progress in the past year, as has the advancement of a new incentive scheme for renewable energy.

BY THE NUMBERS: As of late 2011 there were 28 active service contracts (SCs) for oil. Production is served by local players such as the Philippine National Oil Company (PNOC) and several large international operators, including ExxonMobil, Shell Philippines Exploration, Nido Petroleum, BHP Billiton (BHP) and Galoc Production Company (GPC).

Through first-half 2011, total domestic production was around 63.21m barrels of oil, according to the Philippines’ Department of Energy (DoE). This is divided among four fields: Nido, which produced 18.82m barrels; Matinloc, with 12.14m; North Matinloc, with 2.22m; and Galoc, with some 8.93m. All located within the offshore SC14 block north-west of Palawan Island, the first three fields are owned and operated by Philodrill Corporation, while the Galoc field, thought to be the country’s largest oil find to date, is operated by GPC. The DoE estimates the country’s total recoverable discovered and undiscovered petroleum reserves at 1.89bn barrels, natural gas reserves at 10.35trn cu ft (tcf) and 164m barrels of condensates.

EXPEDITING EXPLORATION: With the government showing a renewed commitment to expediting exploration activity by revoking inactive licences, several companies have reported progress in their surveying and exploration. These included UK-based exploration and production company Forum Energy Philippines, which accumulated a total of 564.93 sq km of 3D data over Recto (also known as Reed) Bank in the 880, 000-ha SC72 block located in the West Philippine Sea. Gas was first discovered in the area 100 km west of Palawan Island during exploratory searches for oil in the 1970s, but production was abandoned due to the lack of interest in gas production at the time.

Results from these initial explorations indicate that the wells yielded some 2m cu ft per day (mcfd) and reserves could be as high as 44m barrels of oil equivalent (boe) and 96bn cu metres (bcm) of gas. More recent 2D and 3D seismic surveys now suggest that the size of the potential deposit could be two to three times larger than the country’s most productive existing gas field of Malampaya. Forum Energy’s new exploratory drilling on the project is expected in 2012, although seismic survey teams have been hampered by Chinese vessels in the area, as the region is claimed by both the Philippines and China.

NorAsian Energy of the Philippines also completed 228.8 sq km worth of 3D data within its 528,000-ha SC69 block in the Camotes Sea. The DoE reported that a total of 2202.28 line km of 2D seismic data was recorded in 2011. According to the DoE, geophysical surveys encompassing the country’s 16 sedimentary basins were completed, totalling 519,841.73 line km of 2D results and 16,948.56 sq km of 3D seismic data. NorAsian Energy also drilled two onshore exploratory wells in its contracted areas, located in north-west Leyte and north-west Palawan. Australiabased Nido Petroleum Philippines drilled the Gindara-1 exploratory well in its 314,000-ha SC54B block, located in north-west Palawan. The DoE later noted in November 2011 that seismic surveys for the SC58 and SC63 blocks were also completed and their respective developers, Nido and the joint venture between PNOC Exploration Corporation and Nido, were moving into the exploratory drilling phase.

HIGH HOPES: There are high hopes for the two blocks lying just north-east of the island of Borneo. Designated SC59 and SC62, the Iligan blocks share the same geological composition as the rich offshore hydrocarbons deposits currently being exploited in the Sabah province of neighbouring Malaysia.

Operator Palawan Sulu Sea Gas is conducting exploratory efforts on the 1.3m-ha SC62 block, while BHP is operating the 1.48m-ha SC59 block, located in West Babalac. As of late 2011 newly completed 2D and 3D seismic surveys of both blocks were being analysed to determine if the findings warrant drilling exploratory wells throughout 2012. According to Ismael Ocampo, the director at the Energy Resource Development Bureau of the DoE, if large deposits of natural gas similar to the nearby Malaysian blocks are indeed present, the new gas source could potentially be significant enough to supply the country’s first liquefied natural gas (LNG) plant.

Not all the news was good for the sector though, as ExxonMobil announced in September 2011 that it was pulling out of the SC56 block – also known as the Sulu block – located in the Sandakan Basin just to the north-east of Borneo. The company cited disappointing results from its four exploratory wells as the reason for abandoning the project just two years after beginning operations there.

Although Exxon Mobil concluded that pursuing further production in the marginal block was not in its best interest, the initial findings indicate that extractable amounts of gas do reside within the area and production could still be possible for another enterprise in the future. Since 2009 the company spent roughly $500m drilling four wells in the 862, 000-ha block, in which it owns a 50% operating stake along with partners Mitra Energy (25%) and BHP (35%). The block is expected to be resubmitted for bidding in the next round of tendering.

NEW CONCESSION AREAS: Even as exploratory efforts are stepped up for existing production contracts, the government is offering a new grouping of concession areas for future development. The most recent round of contracting was initiated in June 2011, with bidding on the 15 new blocks expected to begin in early 2012. According to the DoE, interest in the new areas is high, with some 40 local and international companies signing confidentiality agreements regarding the new concession areas by the end of 2011. In total, up to $7.5bn could be invested in the exploration and development of the 15 new areas, according to the government.

This will be the fourth energy contracting round for the country, but only the first since 2006 due to a series of delays largely caused by a lack of continuity in the upper levels of management within the DoE and the government as a whole. The much-anticipated fourth round encompasses a combined total area in excess of 10m ha, spread over 15 blocks ranging in size from 424,000 ha to 983,000 ha. The minimum application fee for the bidding process is P100,000 ($2270), with a 150-day application period, followed by a 45-day evaluation period and the service contract award within 30 days of completing the evaluation.

Similar to existing production-sharing agreements, the working areas are primarily located near the island of Palawan, with six blocks located in the vicinity of east Palawan and another three in north-west Palawan. Two others are located at Mindoro-Cuyo, along with offshore blocks in the Sulu Sea and onshore blocks in Cotabato, Cagayan and Central Luzon. The Cagayan block, designated block 1, is being re-tendered after the contract with Burgundy Global Exploration Corporation for the area was revoked due to inactivity.

EXPECTATIONS: Of the new blocks, there is significant optimism surrounding blocks 10, 11, 13 and 14. These blocks border on Borneo and share similar geological characteristics with existing Malaysian fields. The wildcard could be blocks 3 and 4, which lie just to the north-west of Palawan, as recent exploratory efforts have received considerable attention from Chinese-flagged vessels in the vicinity.

Speaking about the potential of large finds in the area, Antonio Cailao, president of the PNOC, said, “The Philippines sits in the middle of the Asia Pacific region, surrounded by countries with substantial oil and gas assets, yet the Philippines has very low proven reserves. This either means the country is extremely unlucky, or it has not yet begun to scratch the surface in terms of exploring its hydrocarbons potential.”

LEGISLATIVE FRAMEWORK: Legislation governing the oil and gas sector has been largely unchanged since Presidential Decree (PD) 87 – otherwise known as the Oil Exploration and Development Act of 1972 – was enacted, and later amended in 1983, thus lending investors a sense of stability in this area.

The provision allows a number of incentives for oil and gas exploration and production operations, while other regulatory measures such as zero taxation on equipment also encourage the development of the sector. In terms of profit sharing, the Philippines mandates a 60:40 split, with the government entitled to 60% of net profits and the private company taking 40%. This compares favourably to other ratios throughout the region, which can be as high as 90% for the government’s share. In addition, no royalty payments or other taxes are taken by the state, and the 30% corporate income tax on petroleum operations is paid out of the government share. Cost recovery allows for reimbursement of up to 70% of gross production with carry-forward of unrecovered costs for exploratory companies. Additionally, there is 100% cost recovery for non-capital expenditures, as well as capital expenditure depreciation over five to 10 years, depending on the category of expenditure.

Despite these incentive packages, investors are concerned about a proposed change in the way firms are taxed under the production-sharing agreement. Under the current system, oil and gas producers operate essentially tax-free, as income taxes are paid out of the government’s 60% share of profits.

The government is now considering a revision of this agreement to move the onus of tax payment from the government to the private partner company. If the plan moves forward, it could have a significant impact on investment, most immediately by altering feasibility of plans for those companies already awarded exploratory or production contracts.

There are also calls for a clearer process for permit approval. Dennis Uy, the president and CEO of Phoenix Petroleum, said, “Currently, the regulatory environment for expansion is very confusing, as local government policies are not always in line with those of the national government. The industry and the country would certainly benefit from a rationalisation and a streamlining of the permit approval process.”

DOWNSTREAM: Petroleum-refining operations in the country are currently limited to 275,000 barrels per day (bpd). These operations are split between the Limay refinery in Bataan, which has a capacity of 180,000 bpd and is operated by Petron, and Pilipinas Shell refinery, which has a production capacity of 155,000 and is located at Tabangao in Batangas. Total crude oil processed at the refineries through the first six months of 2011 increased 13.7%, from 30.5m boe in 2010 to 34.7m boe. This current capacity is less than the country’s consumption rate, which was 282,000 bpd in 2010, according to BP’s “Statistical Review of World Energy 2011”. Natural gas consumption in the country also decreased from 3.3 bcm in 2009 to 3.1 bcm in 2010, down 5.8% on the year.

IMPORTS: To make up for the shortfall of both domestic production and refining capacity, the country imported 67.25m barrels of crude oil in 2010, according to DoE data. The Middle East remained the primary source of imports, with Saudi Arabia supplying 30.36m barrels (45.1%), followed by the UAE, with 18.19m barrels. Malaysia accounted for another 10.2% of the total, followed by Russia with 7.7% and Qatar with 6.4%. Various other regional countries, including Thailand and Indonesia, make up the difference.

These imports cost the country $9.96bn in 2010, up approximately 40% over the 2009 price tag of $7.17bn due to the increased volume and price of imports. Crude oil accounted for 53.8% of the bill, with finished products rounding out the remaining 46.2%. National export earnings were a fraction of these costs, amounting to $1.17bn in 2010, compared to $791.4m the previous year. While the economy undoubtedly takes a big hit each year on energy imports, these costs are borne by the consumer; the government does not offer fuel subsidies, preferring instead to let market forces dictate the price.

GENERATION: After two decades of transitioning from a government monopoly on the generation, transmission and distribution of electricity, the country has achieved one of the most liberalised power sectors in South-east Asia. Through April 2010 formerly government-owned power plants representing a combined installed capacity of 3318 MW – 88% of the original total – had been turned over to private operators, generating $3.47bn for the cash-strapped National Power Corporation (NPC), which previously dominated the sector.

Despite strong growth in renewables over the past two decades, power is still largely generated by the traditional carbon-based fuel sources of coal, petroleum and natural gas. As of 2010 coal-fired thermal power plants accounted the largest proportion of the country’s power output, with 4867 MW of the national total of 16,359 MW of capacity, or 29.75% of the capacity, according to DoE data. Hydropower stations ranked second, with 3400 MW of installed capacity, good for 20.78%, followed closely by oil-based generation (3193 MW, 19.52%), natural gas (2861 MW, 17.49%), geothermal (1966 MW, 12.02%) and other renewables (73 MW, less than 1%).

Over the past decade, the use of natural gas in power generation has risen from nearly nothing to account for almost one-fifth of the country’s electricity supply. The installed capacity of gas-fired thermal power plants in the Philippines has grown from just 3 MW in 2000 to 2861 MW in 2010, according to the DoE. The majority of this power is generated from a single project – the 2700-MW Malampaya deep-water gasto-power project, operated by a joint venture between Shell Philippines Exploration (45%), Chevron Malampaya (45%) and state oil and gas company PNOC (10%). Entering service in 2001 and supplying 16.5% of the entire country’s installed capacity, the gas fuels the 1000-MW Santa Rita power plant, 500-MW San Lorenzo power plant and 1200-MW Ilijan power plant.

By contrast, petroleum-fuelled power plants are the only primary power source which has decreased in installed capacity over the past 20 years, declining from a peak of 5973 MW, representing just over half of total power production in 1997, to current levels of 3193 MW. This trend is the result of both increasing emphasis on cleaner technology, as well as the escalating price of oil compared to other, more costeffective generation technologies.

GOING GREEN: Renewable energy generation has been growing rapidly as well, bolstered by the government’s recently launched National Renewable Energy Programme, which hopes to nearly triple the nation’s renewable energy capacity from around 5232 MW in 2010 to 15,300 MW by 2030. Currently, the bulk of renewable energy is generated from hydropower sources, which accounted for 3400 MW of capacity in 2010, up from 3291 MW in 2009 and 2304 MW a decade ago. Geothermal generation ranked second, with 1966 MW of installed capacity, up from 1953 MW the previous year. Other renewables including solar, wind and biomass combined for a much smaller share of 73 MW of installed capacity.

Upgrading older power plants with newer, cleaner and more efficient technology is also a priority for the government. The repowering of the 850-MW Sucat plant is one such project under consideration. As of late 2011, the government was mulling a public-private partnership to help with the costs and operation of the project, which would convert Sucat from coal to gas power. Dozens of other plants utilising all types of fuel are scheduled for upgrades as independent power producers take control of them from the NPC.

LIBERALISATION: Although much has been accomplished in terms of liberalising the country’s electricity sector, a lot of work remains to be completed in order to fulfil the promise of the 2001 Electric Power Industry Reform Act (EPIRA). Enacted as a means to finalise the transition from government to private control of domestic electricity assets, EPIRA’s primary responsibilities were to build a sustainable and reliable power supply and to lower electricity rates. Paradoxically, electricity rates must first be raised to attract investments in the sector for newer, more efficient power plants, which will in the long run reduce power prices by remaining profitable with lower prices through increased efficiencies.

Froilan Tampinco, the president of the NPC, told OBG, “Despite the gradual privatisation of the power market in the Philippines since 2001, market conditions undermined capacity enhancements and investments for a number of years over the past decade. While substantial generation projects are now being developed, the gestation period is such that it will be a number of years before the country enjoys the benefits from these investments, and this gap in investment is becoming more serious.”

MORE OPTIONS: On a structural level, the privatisation of the industry had made significant progress through the end of 2010. Generation, transmission and distribution services have all been unbundled. At the same time, the goal of 70% privatisation of government-owned power plants was exceeded with an 88% rate of progress, and the transfer of management and control of at least 70% of the joint contracts between independent power producers (IPPs) and the NPC to IPP administrators was accomplished. As a result of the privatisation of the NPC, the sector boasts a competitive electricity generation market, open access to high-voltage wires for distributors and large consumers, a regulated transmission and distribution sector, and open access of distribution lines for consumers, resulting in retail competition.

End-use consumers also now have green energy options as part of the open-access agreement, as well as a competition agreement to choose different power distributors. While the competition scheme is being phased in over a number of years, starting with larger consumers (over 3 MW) and eventually reaching residential buyers, the green energy option allows end-users to choose only electricity produced from renewable sources. This option will be immediately available with no minimum consumption requirement.

ENTER THE PRIVATE SECTOR: The transfer of NPC assets to private firms has accelerated in recent years, with 2010 witnessing a particularly high degree of activity. According to DoE statistics, non-NPC power generation assets, which generally take the form of IPPs, nearly doubled from a combined power output of 24,315 GWh in 2009 to 48,442 GWh in 2010, which equates to a 99.23% increase. Over the same period, NPC electricity production dropped 58.41% from 9745 GWh to 4053 GWh, while NPC-IPC joint venture generation fell 46.26% from 27,400 GWh to 14,725 GWh.

The most prominent power plants handed over to private operators by the NPC over this period include the 620-MW Limay combined-cycle plant (turned over in January 2010), the 55-MW Naga land-based gas turbine plant (January 2010) and the 100-MW power-barge (PB) 118 oil-fired power plant ( February 2010). The 100-MW PB 117 oil-fired plant has also been in private hands since March 2011.

The wholesale electricity spot market (WESM) has also made significant strides since opening in 2001. The WESM highlights in 2011 included successfully integrating the Visayas grid into the market, achieving a system peak demand high of 8849 MW in June 2011, with demands on the individual Luzon and Visayas grids peaking at 7530 MW on June 7, 2011 and 1383 MW on May 3, 2011, respectively.

The WESM is based on a gross pool, net settlement model in which all energy transactions are scheduled through the market but bilateral contracts transacted in the pool may be settled outside the market. Marginal prices are computed reflecting transmission losses and congestions and functions on hourly and bid-based mechanisms, with generators submitting separate bids for each hour of the day. The EPIRA also mandates that all entities withdrawing or injecting power to the grid are required to participate in the WESM and that at least 10% of all power must be procured from the market.

TRANSMISSION: Due to the dispersed geography of the archipelago, power transmission, balancing and distribution have been a continuous problem. There are currently three separate primary power grids operating in the country – the Mindanao, Visayas and Luzon networks. The largest of the three, the Luzon grid, transmitted 50,265 GWh in 2010, up 11.76% over the 2009 total of 5290 GWh, according to the DoE. The Visayas network handled 9075 GWh in 2010, up 4.02% year-on-year from the 2009 mark of 8724 GWh, while the Mindanao grid handled 8403 GWh in 2010, up 2.03% over 2009’s 8235 MW.

In total electricity consumption spiked 9.4% from 61,934 GWh in 2009 to 67,743 GWh. This was driven in large part by election-related expenditure, increased spending by remittance-supported households, and growing exports and investments.

Grid loss ate away some 7800 GWh of production (11.51%), while own use of power subtracted another 4677 GWh (6.9%) from total production, leaving 55,266 GWh (81.6%) for electricity sales. Of this, the residential and industrial sectors were nearly equal, with consumption of 18,833 GWh and 18,576 GWh, respectively. Commercial operations consumed another 16,261 GWh, or 24% of the total, with other consumption accounting for the remaining 1596 GWh.

OUTLOOK: While many of the new contracts issued show promise for the short and medium term, long-term energy security will likely depend on both the political and geological outcome of exploration of the reserves in the West and East Philippine Seas. Efforts to privatise the power sector have laid strong foundations for continued investment, with services now unbundled and the majority of production in the hands of independent operators. The impending implementation of feed-in tariffs for renewable energy should also open the floodgates for thousands of new megawatts of generation capacity proposed by investors now awaiting approval. Eventually, this access should encourage more competition in the supply and distribution of electricity and lead to lower prices.

According to Oscar Reyes, the chief operating officer of Manila Electric Company, for the short-term the country will be reliant on coal for needed base capacity. “Beyond that, natural gas and LNG will start to play a bigger role, and finally, over the long-term renewables will have a larger and larger market share, especially as technology continues to evolve,” Reyes said. The energy sector is now firmly on the international investment map, especially the power segment.