Third in a series
Count Petroleum Co. of Trinidad & Tobago Ltd. (Petrotrin) as the latest to join the ranks of Western Hemisphere state oil companies seeking to emulate their counterparts in the private sector.
As has been the case with many state companies in Latin America and the Caribbean Sea region, Petrotrin is shedding years of bureaucratic inertia and throwing off the shackles of service as a government agency to better compete with private multinational integrated oil companies.
Petrotrin is ramping up its own efforts to bolster Trinidad and Tobago's oil and natural gas operations, as well as enthusiastically encouraging investment in those operations by foreign petroleum companies.
Its efforts to resuscitate an oil sector that had been in decline for decades are deemed just as critical as its efforts to pursue more opportunities along the gas value chain. And the company is counting heavily on partnerships with foreign companies in both areas to make the difference.
In the downstream sector, the company now sees itself competing with integrated multinational oil and gas companies and has a goal to be the "best in class" in the region, says Petrotrin Pres. Rodney Jagai. Its goal is not merely to compete but to increase market share in its target markets: the Caribbean region and the US eastern seaboard.
Petrotrin evolution
Petrotrin today is essentially an amalgamation of the remnants of several major international oil companies' interests in Trinidad. It was incorporated as a wholly state owned integrated oil company in January 1993.
British companies were the dominant operators in Trinidad and Tobago's petroleum industry from the turn of the 20th century to 1960. A series of mergers and acquisitions that followed left much of the country's petroleum assets in the hands of units of Royal Dutch/Shell Group, the former Texaco Inc., and the forerunner of BP PLC. These assets mostly reverted to state ownership, a process largely completed when Petrotrin acquired Texaco Trinidad Inc.'s interests in offshore operator Trinmar Ltd. in August 2000.
The various constituents came together to form what today is Petrotrin primarily to eliminate duplication and thus better manage costs in a low oil price environment, Jagai noted.
Although government owned, it is now being managed principally along the lines of a private company, and the current management has a mandate from an independent board to ensure the firm's viability as if it were a private company.
The upshot is that Petrotrin finds itself embarking on a new mission to act on behalf of the state but to perform up to the standards of a private company while overseeing a largely mature asset base that nevertheless has much untapped potential.
Jagai expresses his confidence that the most recent evolutionary steps at Petrotrin are already yielding success: "We have changed the mindset of the company. Today, we are much, much better at how we interact with the various stakeholders [in Trinidad and Tobago's petroleum industry]. We are successfully moving the company from a bureaucracy to a more externally focused company."
Strategy
At the outset, Petrotrin recognized that it had control over an unwieldy package of assets. It currently has the largest acreage position-more than 500,000 acres-under active exploitation in the country.
Exploration and production properties under its control cover the southern half of the island of Trinidad and include acreage off the southern, southeastern, southwestern, and northern coasts (see map).
Petrotrin operates these properties alone or jointly with 14 lease operators, 8 farmout operators, and 8 joint venture (JV) partners. In addition, Petrotrin owns JV interests off Trinidad's eastern coast in deepwater Block 25 (with Shell and Agip SPA) and Block 27 (with BP and Petroleo Brasileiro SA unit Braspetro SA), plus a unitized gas interest off the northern coast in partnership with BG Group PLC, Agip, and Veba Oil AG.
Petrotrin also operates Trinidad and Tobago's sole remaining refinery, a 160,000 b/d capacity plant at Point-a-Pierre that has been the focus of extensive upgrading efforts in recent years. The company feeds its refinery with 60,000 b/d of equity and purchased domestic crudes, with the remaining volumes imported via outright purchase or via processing arrangements for foreign companies. Imported crudes come from Venezuela, Ecuador, Brazil, and West Africa.
Given the much higher refining margins with domestic crude, Petrotrin also sees the wisdom in stepped-up exploration and development of Trinidadian oil (the republic's other main island, Tobago, has no commercial hydrocarbons).
At the same time, the company recognizes the growing dominance of natural gas in Trinidad and Tobago's petroleum sector. The country's LNG export plant, in operation only 3 years, already is undergoing the first of what is likely to be a string of phased expansions (OGJ, Mar. 11, 2001, p. 22). And massive onshore and offshore gas discoveries have propelled Trinidad and Tobago into the top ranks of world gas reserves holders and have spawned discussion of a burgeoning gas-based industry.
"In terms of production, on a boe [barrel of oil equivalent] basis, gas surpassed oil [in 2000]," Jagai noted, explaining his company's burgeoning investment in the country's gas sector opportunities.
The proliferation of challenges and opportunities demanded a focused strategy for the company.
"Evidently with as diverse a portfolio as it currently manages, incorporating stripper, nearshore, shallow marine, deepwater, gas, and refining operations, etc., the company has recognized the need to mitigate risk, exploit opportunities, and fulfill stakeholder obligations simultaneously and prudently," Jagai said. "Consequently, its near, medium, and long-term strategies have been informed by these circumstances."
Petrotrin's first initiative was to undertake benchmarking studies of the stripper wells and refining assets it inherited.
"Our first priority was to improve the viability of the refining operations," Jagai said. That meant a 2-3 year span in which the company modernized the Point-a-Pierre refinery, increasing throughput capacity, installing advanced instrumentation and control systems, and improving environmental performance with regard to air and water quality.
At the same time, the company has had to grapple with stringent new environmental and safety strictures, a need to improve labor relations, and pressures to do more to bolster the nation's economy.
Upstream concerns
The foremost upstream concern for Petrotrin was how to cope with oil production that had been generally in decline for more than a decade.
Onshore and nearshore output had fallen to 20,000 b/d last year from 35,000 b/d in 1990, while the former Trinmar offshore fields fluctuated in that time at 30,000-40,000 b/d. The land and nearshore operations, Jagai notes, have high operating costs and are especially sensitive to oil price changes.
During the past decade, Petrotrin's upstream operations saw reduced capital outlays, rising costs, and reduced revenues. The results were consolidation, cost cuts, lessened development, and declining crude oil production.
A key consolidation involved eliminating duplication of technical systems and staff after the Trinmar acquisition and deploying the remaining staff more efficiently, including offering those services to JV partners for a fee.
"We also allowed the G&G [geology and geophysics] people to focus on better prospects, resulting in a program that is much more focused on exploration but not as focused on drilling," Jagai said.
In order to offset the decline and to meet the objective of economically increasing its crude supply to the refinery, Petrotrin undertook a structured program of monetizing its underutilized E&P assets through methods detailed in the following sections.
Lease operatorships
Petrotrin introduced its lease operatorship program in 1989, mainly to reactivate idle wells. Under this arrangement, contractors sublease small blocks of idle or marginally economic wells and can earn revenue from sales of crude from workovers or replacement wells.
Petrotrin books the reserves, collects an override and a user fee, and sells the crude to the refinery.
This program, involving an average capital outlay of less than $3 million/ block, has boosted output from the 25 blocks involved to almost 4,000 b/d from only 40 b/d.
Another 700 wells made available under this program is expected to yield a further incremental 1,000 b/d by mid-2002.
This is production that probably would not have occurred otherwise, noted Kain Look-Yee, Petrotrin manager of production operations: "Our lifting costs don't allow us to produce these reserves."
Farmouts
Petrotrin launched its farmout program in 1991 to exploit small, inactive blocks. It involves leasing all the acreage in a block, with the operator getting unlimited rights to the block's reserves.
The operator, which receives a royalty, is required to commit to a work program that includes seismic surveys, exploration and development drilling, workovers, and deployment of appropriate technology.
Capital costs under the farmout program are pegged at $3-20 million, and production currently is 850 b/d of oil.
"The farmouts have not been as successful as we'd like," Kain said. "Some operators think the terms are a bit onerous to fulfill.
If it would yield greater production, he added, "We wouldn't mind sacrificing a few percentage points [on the royalty rate]."
Drilling portfolio
After the oil price collapse of 1998-99, Petrotrin's lack of access to capital and loss of staff crippled its development drilling program.
It used the downtime during 2000 to develop a drilling opportunities portfolio through reservoir characterization and geotechnical studies, an effort led by consultants, in its Parrylands and Forest Reserve fields.
This yielded a portfolio of more than 70 development drilling candidates, a number of recompletion prospects, and the opportunity to train new staff.
Consequently, 28 wells were drilled under the program, yielding incremental production of more than 900 b/d of oil. Petrotrin now plans to apply this exercise to the former Trinmar properties in 2002.
E&D JVs
Since the last commercial onshore-nearshore discovery, Navette oil field, in 1960, the exploration track record of Petrotrin's predecessor companies had been abysmal: zero successes.
An ambitious program in partnership with three major oil companies in southern Trinidad, begun in 1989, also proved unsuccessful for Petrotrin, although the studies yielded a portfolio of exploration prospects.
Since then, the company has opted for hedging its exploration risk by inviting JV partners to participate in exploring its prospects. A competitive bidding round in 1997 covered onshore and nearshore acreage. Requirements call for work program commitments, including 3D seismic and an explor- atory well, a carry-through for Petrotrin through exploration, and 20,000-acre blocks. Typically, Petrotrin funds its equity share of 35-40% through development, with the JV remaining as operator.
Meanwhile, Petrotrin has taken 5% interests in the two eastern deepwater blocks with the four majors mentioned earlier and in the northern offshore Block 9 Unit, which is being developed to feed the Atlantic LNG complex.
In 1998, Petrotrin kicked off a program of reactivation-development JVs. Five JVs have been executed under this program, which calls for current production to be transferred to the JV; a work program entailing exploration, appraisal, and development wells; and a signature bonus.
Another JV focuses on a novel EOR scheme involving steam-assisted gravity drainage with horizontal and vertical wells, operated by New Horizon Exploration Co., Richardson, Tex. (OGJ, Mar. 18, 2001, p. 24). This is part of an effort to tap Petrotrin's heavy oil-tar sands resource of more than 1 billion bbl.
In all during 2000-04, Petrotrin and its JV partners are expected to invest about $2 billion (TT) in onshore, nearshore, and offshore properties; acquire 450 sq km of 3D seismic; drill 20 exploration and 96 development wells; and rehabilitate existing infrastructure and wells on producing blocks.
Petrotrin also is expanding its field reactivation-exploration and development JV program in the Inniss and Trinity-Catshill, Puzzle Island, Guapo nearshore, Guyaguayare subbasin, and East Coast transition-Galeota areas through this year.
And the company will offer exploration acreage in the Eureka, Central Range, and South Marine areas for bidding during 2003-04.
Refining challenges
Even following a round of upgrades in the past decade, still more capital expenditures are needed to bring the Point-a-Pierre refinery up to international standards, and significant upgrades are still required for the plant to become competitive, Jagai said.
Even at that, Petro- trin is holding to its vision of making the refinery the "best in class" in the Carib- bean and Latin America by 2007.
A 70,000 b/d hydroskimming refinery at Port Fortin that dated to World War I was shut down in 1995, with much of its operations then consolidated at Point-a-Pierre.
The Point-a-Pierre refinery also has its origins in the World War I era, and former owner Texaco sought to make it a major refining center in the Caribbean, expanding its capacity and complexity to the point where by 1973 it was one of the world's 20 biggest refineries in capacity terms at 355,000 b/d. Texaco ratcheted back this effort, and capacity dwindled back to 200,000 b/d in 1978 before the company stopped importing crude into Trinidad and Tobago altogether.
Recent upgrades
Petrotrin implemented a $350 million upgrade beginning in 1991 that involved restoring two idle crude distillation units, revamping a fluid catalytic cracker unit (FCCU), installing four new processing units, installing new instrumentation and controls, and improving environmental performance.
The effort has yielded a whiter barrel, higher-quality products, and a jump in nameplate capacity to 160,000 b/d from 90,000 b/d (although crude charges can reach 175,000 b/d). Almost half of its crude charge is a 22° gravity naphthenic crude with 1.4 wt % sulfur. The upgrade enabled Petrotrin to reduce the residual fuel oil cut to 35% from 45%.
Conceptual engineering for the upgrade program started in the late 1980s, and the project was completed in 1997-98. It included converting a gas oil desulfurization unit to mild hydrocracking, revamping the FCCU for riser cracking, and installation of a second catalytic reformer, a methyl tertiary butyl ether (MTBE) plant, a new visbreaker, and new hydrogen and sulfur recovery units.
About 85% of the Point-a-Pierre refinery products are exported, with 19,000 b/d consumed domestically. The refinery also produces 2,000-3,000 b/d of base lubes.
Future upgrades
In the next phase of possible upgrades, feasibility studies are likely to continue for 5-7 years, says Kelvin Harnanan, business and technical manager, refining and marketing strategic business unit.
"We're focused in the medium term on sulfur in gasoline and diesel and the feasibility for tackling the bottom of the barrel," he said.
It's all part of a strategy to be a key niche clean fuels supplier in the Carib- bean, Harnanan noted.
Petrotrin would like to better "leverage" its huge heavy crude-tar sands endowment with a resid upgrading scheme at the refinery.
"We're looking at resid upgrading, but it may not meet our economic threshold," he said. "We need to be able to substantially improve the gross margin."
Petrotrin is evaluating bids and processes for an isomerization unit. It also is looking at various technologies prior to a tender to replace an alkylation unit that dates to 1943.
Other prospects for added-value projects at the refinery include petrochemicals production and the addition of a cogeneration power plant whereby Petrotrin could furnish its own electric power and sell the surplus power into the national grid.
Successes, opportunities
Like some of its state-owned counterparts in the Latin America-Caribbean region, Petrotrin counts some successes among continuing challenges in its ongoing evolution into a competitive player.
Petrotrin's gross revenues in the past couple of years have roughly doubled, to $10 billion (TT), but some of that increase was the impact of higher oil prices.
The company's management has also had to deal with the prospect of reen- gineering a state company in a highly unionized environment. Major concerns include environmental and safety issues, training, and labor costs (salaries are said to account for 50% of operating costs).
Through a program of mostly voluntary attrition, staff reductions last year were expected to total 500.
Petrotrin also inherited significant environmental challenges with both refining and producing assets under the amalgamations of the 1990s. The company soon plans to be in full compliance with new environmental laws on air and water discharges that have been patterned after the California model, Jagai noted.
At the same time, Petrotrin has embarked on a new program to bolster safety over a 2-3 year period. "Safety compliance had not been what it could be," Jagai said.
Another strategic initiative was to develop a better relationship with local oil workers' unions, stepping up the frequency of meetings with unions at all levels.
"We had to realize that the union is not the enemy-so we're building bridges to the future," Jagai said.
Part of that bridge-building includes a program, dubbed National Energy Skills Development, to improve the education and experience of the oil sector workforce.
Gas initiative
The burgeoning success story that is natural gas in Trinidad and Tobago is stirring debate within the country over the best way to monetize those new assets while maximizing the number of jobs.
That means while Petrotrin and foreign oil company investors are focused more on the front end of the gas value chain, much of the government's focus has been on more labor-intensive industries, such as petrochemicals, aluminum smelting, iron ore reduction, and the like.
While LNG operations are expanding, Petrotrin also remains intrigued by the possibility of monetizing the country's gas via gas-to-liquids technology. The company is discussing GTL technologies with the likes of Shell and Sasol Corp.
"Although GTL economics are becoming more favorable vs. LNG, it still doesn't compete," Jagai said.
The surge in demand for natural gas in Trinidad and Tobago has created an unexpected dilemma elsewhere for Petrotrin. Gas traditionally had been used to fire steam generators for steamflood operations in Trinidad's heavy oil fields. But the rising cost of gas, coupled with increased water coning and dwindling heavy oil production, has forced Petrotrin to look for a low-cost EOR alternative. It now is studying the option of using carbon dioxide from the Point Lisas industrial estate as an EOR medium. If proven commercially feasible, CO2 could be used in a tertiary recovery scheme for Petrotrin's Southwest Trinidad properties, for Trinmar acreage, and for JV projects.
Such initiatives are typical of the new management philosophy at Petrotrin that is both focused and realistic.
"There was a time when the company was not focused on how it did business," Jagai said. "Now we are in a position that can get us to where we can consistently meet cost and compliance targets.
"At the end of the day, Petrotrin is a niche player. But there is still much we can do to improve operating efficiencies and to grow the business."
