Mexico is one of the premier oil-producing countries in the world. Since the beginning of its oil industry in 1904, it has produced some 30 billion barrels of oil and 50 trillion cubic feet (Tcf) of gas. Today, the country is pumping 3.3 million barrels of crude oil per day. Of that volume, it exports 1.8 million barrels per day, 80% of which it sends to the U.S. However, Mexico is suffering a worrisome decline rate on its workhorse oil fields, at the same time that its reserve replacement rate is alarmingly low. Natural gas offers other challenges. At press time, the government stated that it plans to restrict the use of natural gas because of a daily deficit of 100 million cubic feet. "The future arrived too quickly," one official said of the country's growing gas supply-demand gap. Currently, the country produces 4.6 billion cubic feet (Bcf) of gas per day, and that is not sufficient to meet its burgeoning demand. In 2002, Mexico imported some 263 Bcf of gas from the U.S., nearly double the 140 Bcf it bought from the U.S. in 2001. Even so, demand for gas in Mexico is expected to as much as double by the end of the decade. While Mexico enjoys ample gas resources, its dilemma is that years of low investment levels have left it lagging on the down side of the supply equation. It needs thousands of new wells, many kilometers of pipelines, and a plethora of processing plants and compressors. Pemex's new direction Petroleos Mexicanos (Pemex), formed in 1938 after Mexico nationalized its oil industry, is the country's single most important business entity. Oil is the lynchpin of the Mexican economy, as the taxes paid by Pemex fund fully one-third of the national budget. Although oil exploration and production have always garnered the lion's share of Pemex's budget, the amount of money it could invest back into its business has been limited by its crucial role in supporting the federal government. Many fundamental changes occurred in Mexico's energy industry in the 1990s: the NAFTA agreement was signed, clean air laws were passed, independent power production was encouraged, private investment was welcomed in the midstream and downstream gas sectors, and Mexico faced a huge fiscal crisis and devalued the peso. Change has also swept through Pemex. In 1992, the national entity was reorganized into four divisions and efforts to improve efficiencies and access state-of-the-art technologies were begun. Still, the 1994-95 economic crisis was a tremendous blow, and Pemex struggled with a bare-bones budget. The election of President Vicente Fox Quesada in 2000 marked a sea change in Mexico. Fox appointed Raul Munoz Leos, formerly the president of DuPont-Mexico and a highly respected private businessman, to the position of director general of Pemex. Both men embraced the clear need to dramatically raise capital spending at Pemex, to maintain the country's place among top oil-exporting nations and to ensure a robust supply of natural gas. The result: the upstream unit of Pemex has a 2003 budget of $10.8 billion, its largest ever. Capital investment will likely continue at that level at least until 2006, when the next presidential elections are held. Production replacement is Pemex's most immediate goal. From 1990 to 2002, Pemex was adding reserves each year that were equivalent to 26% of its production. The company is now hoping to achieve 75% reserve replacement by 2006 and 100% by 2010. Pemex also plans to increase oil production to 4.2 million barrels per day by 2006. Gratifying results have already been obtained at supergiant Cantarell, Mexico's premier field, from a nitrogen-injection program that Pemex began in 1997. Cantarell is on the Campeche Shelf in the Gulf of Mexico, the area that supplies about 75% of Mexico's crude oil. At the end of 2002, daily production from Cantarell was 1.7 million barrels. Pemex continues to develop the field, aiming to produce 2.2 million barrels per day next year. Beneath Cantarell lies Sihil Field, a 1.4-billion-barrel accumulation. Pemex discovered Sihil in 2000 and has already begun limited development. A priority is raising production from the Ku-Zaap-Maloob heavy-crude complex, also located on the Campeche Shelf, to 800,000 barrels per day by 2011. The project, announced in 2002, calls for 17 new platforms, 82 wells and 32 pipelines. The complex has proven reserves of more than 2.1 billion barrels and probable reserves of 5 billion barrels. Light-oil exploration is also a focus. "The Mexican sector of the Gulf of Mexico has very attractive light-oil potential that has really not been explored," says Alfredo E. Guzman, subdirector of Pemex's north region. Pemex is changing that, and it recently made a light-oil discovery containing 70 million barrels in the venerable Golden Lane area, offshore the state of Veracruz. Pemex is also expanding its reach toward deeper waters. Until recently, the company has confined its offshore efforts to developing oil production in water depths less than 100 meters. The newest wave of exploration is employing all the latest industry techniques. "We are using 3-D seismic, visualization techniques, seismic attributes, and drilling techniques that make the wells smarter, faster and cheaper." A key piece of Pemex's future oil supply puzzle is Chicontepec, an onshore project in Veracruz State. During the next 15 to 25 years, Pemex plans to spend $30 billion to develop Chicontepec's estimated reserves of 18 billion barrels of oil equivalent. Chicontepec is a 3,500-square-kilometer Paleocene accumulation that can be compared to the Spraberry in West Texas. The flysch-like deposit is thick, but suffers from low permeability. U.S.-based reservoir engineering firm DeGolyer & McNaughton calculates that Chicontepec contained 139 billion barrels of original oil in place and 50 Tcf of gas in place, out of which roughly 12 billion barrels of oil and 31 Tcf of gas are recoverable. Based on certified reserves, the project ranks as Pemex's largest asset. "We calculate that we will require on the order of 16,000 wells to extract the 12 billion barrels of reserves," says Guzman. Discovered in 1926, Chicontepec's first commercial production didn't occur until 1952. The wells were expensive and the flow rates were low, and until the mid-1970s, the marginal returns deterred large-scale development. To date, some 1,000 wells have produced just 111 million barrels of oil and 195 Bcf of gas; current production is 6,800 barrels of oil per day. Pemex has authorized $600 million for the first phase of the project, an integrated service contract it tendered to a Schlumberger-led group that includes Fluor Daniel and Drillers Technology Corp. Schlumberger and Pemex are jointly managing the project, which is the first venture in which Pemex has outsourced all services. The project calls for 200 wells to be drilled by Schlumberger and 100 by Pemex between now and 2005. Schlumberger will complete 250 of those wells and Pemex will complete 50. In addition, Schlumberger and its partners will perform integrated reservoir studies and construct facilities, roads, pipelines and compressor stations. The group will also handle all engineering, procurement and logistics. "The reservoir offers many challenges-it has low porosity and permeability, and consists of sandstones interbedded with shales," says Hugo Alberto Moran, Schlumberger general manager, Chicontepec project. In addition, the environment is very sensitive: "This is a rural, agricultural area with many protected plant species." The first target area is in the Agua Fria, Coapechaca and Tajin blocks, just west of Poza Rica. Here, the reservoir occurs at about 1,900 meters. "Our initial work plan is very aggressive," he says. Schlumberger will use three rigs, supplied by its Canadian partner Drillers Technology. The wells will be directionally drilled from pad locations, each pad hosting three to 18 wells. The rigs are state-of-the-art, with top drives and telescoping masts. They will be able to move between wells on the same pad with pipe in the derrick. "Operations will be simultaneous, and we will use rig-less perforating, fracturing, coiled tubing and testing." The first well in the project was spudded in early May; up to 60 wells will be drilled by year-end. "We have to drill 200 wells in 1,400 days, and we have to increase capacity on existing facilities and pipelines and build new ones to handle all the production." Chicontepec marks Pemex's first major investment to exploit onshore oil in many years, and its scale is astonishing. "We have already requested to expand the initial budget to $3 billion, which contemplates 1,400 wells," says Guzman. Natural gas initiatives Pemex has crafted a three-pronged plan to ensure adequate natural gas supplies in the coming years: it will explore new areas of the country, initiate multiple service contracts in the Burgos Basin, and increase imports via both pipelines and liquefied natural gas (LNG) terminal facilities. Already, Pemex has enjoyed success in its exploration efforts. Last spring, it discovered three new gas fields in the Mexican Gulf, offshore the state of Veracruz. The largest of these is Lankahuasa, a find that opened a new trend in the Upper Miocene section of the Tampico-Misantla Basin. Lankahuasa is estimated to hold proven, possible and probable reserves of 840 Bcf. "We are building the platform and have already contracted the pipeline and onshore facilities," says Guzman. "We expect first production in December, which will be a discovery-to-production record for Mexico." The field will produce 200- to 250 million cubic feet of gas per day, which will flow into a 48-inch pipeline that comes up from southern Mexico. "We feel that Lankahuasa is a foot in the door. It is the first gas field developed offshore in the Mexican Shelf." Much of Pemex's recent attention has been directed at the Burgos, its largest dry-gas basin. Located along the country's border with the U.S. in the states of Tamaulipas and Nuevo Leon, the Burgos contains some 30,000 feet of Upper Mesozoic and Tertiary clastic sediments. The same Vicksburg, Wilcox and Lobo sandstones that are productive in South Texas continue into the Burgos. As in Texas, the reservoirs are highly compartmentalized and have steep depletion rates. Burgos Basin is lightly drilled compared with its Texas cousin, however. Only about 1,100 wells are currently producing in the Burgos, whereas Starr, Hidalgo, Zapata and Webb counties in Texas host some 7,500 producing gas wells. Production commenced in the Burgos in 1945, but by December 1993, flow rates had declined to just 183 million cubic feet per day, notes Guzman. Pemex started drilling again in the area in 1994. Today, 1.02 Bcf per day is produced from the basin. "New technology and procedures are already having a noticeable impact. The average Burgos Basin well used to produce 1 million cubic feet per day; now the average is 4.5 million cubic feet per day." Reserves are correspondingly higher-a well used to produce 1.5 Bcf; today Burgos wells drain 2.5 to 3 Bcf. "The economics of projects that used to be marginal are now attractive." Guzman credits the remarkable turnaround in the Burgos to teamwork, technology, good planning, and the vision that abundant resources could still be found and developed. Pemex has been supplementing its own efforts in the basin with integrated service contracts. It has held nine tenders, and Schlumberger has won five of those. Calgary-based Precision Drilling has won one, Halliburton has one, and local companies were awarded the remaining two. Schlumberger started drilling for Pemex in the Burgos in 1996, and has drilled 280 wells since then, says Silvio Raul Bresciani, general manager of northern Mexico. "We are currently drilling 12 wells a month, and we will double the number of wells this year compared with last year." In the Burgos alliance, Pemex picks all the locations, obtains the permits, provides the casing and supplies, and performs all the surface work. Pemex employs fixed-price contracts in the Burgos Basin. "We deliver a flowing gas well to Pemex, and once we meet all the specifics of the contract we get paid," says Ramon Gomez, project manager. Pemex supplies four rigs and crews to the alliance, and Schlumberger supplies four rigs. Two additional rigs were to be added in June. This July, Schlumberger expects to be drilling 16 to 17 wells per month, up to 5,000 meters. "Our capital expenditures for this region have gone from $1 billion in 2001 to $2 billion in 2003," says Guzman. "In the north region, we plan on drilling on the order of 600 wells, most in the Burgos. In addition to our contracts with Schlumberger and Precision Drilling, we have more than 20 rigs of our own drilling there." Multiple-service contracts Pemex is also staking great expectations on its multiple-service contracts, which are debuting in the Burgos Basin. Via these contracts, Pemex hopes to raise gas output to 2 Bcf per day within three years, twice the current production from the basin. Eight blocks are being offered for bid, located close to the U.S. border. The blocks vary greatly in size and potential, as Pemex hoped to make opportunities available to both major integrated companies and smaller independents. Certainly, some choice lands are included: the gas reserve estimates for the blocks total 4 Tcf. The bidding is slated for July, and winners will be announced in August. Schlumberger's IndigoPool unit is hosting the online data rooms. "We want companies to come into Mexico and participate as operators in all the activities of locating wells, doing the subsurface work, drilling and completing the wells, building facilities and operating the wells," says Guzman. Essentially, the contracts are contractor agreements that compensate private companies for services and work performed. The contracts are in force for 20 years, staged in increments. A company will tender an area, and develop it if it wins. Bidding is based on the amount of discount a company will offer Pemex from a price schedule. "Under the multiple service contracts, a company performs services, and if it finds incremental gas, and if the market price of that gas is sufficiently high so that a credit is built up in its account, then the company will be paid the price that was agreed on previously," says George Baker, president of Houston-based Baker & Associates, a business intelligence service that specializes in Mexico. As the production from a block will be used to pay back the capital costs, the project itself is financing the cost of its development and Pemex does not have to put up any capital. After a year, the companies are paid back monthly, depending on the production of gas from the block. There is a cap on how much can be paid back each month as well. "The multiple-service contracts are Pemex's first major step in trying to reach to the private sector for help in investment," says Lisa M. Pearl, associate director, Mexico gas and power, Cambridge Energy Research Associates. "It's been a process of soliciting for suggestions, talking to Congress, consulting with experts in constitutional law, and working internally within Pemex." The whole process has taken two and half years, she notes. Many companies are interested; the problem is that a lot of that interest is not going to be translated into actual bidders. "There are still numerous concerns, mainly because Mexico's constitution, the public works law and the public service law are very restraining and restrictive." The multiple-service contracts do appear to be within the framework of the existing law, says Pearl. "Pemex is doing this to the 'T.' But this is a politically charged year in Mexico, and energy has been taken hostage. Anything that touches the energy sector will be highly scrutinized because there is a big political shift at the moment." The first contract that gets signed will most likely go to the Supreme Court, she predicts. Another problem with Pemex's multiple-service contracts is that they don't fit the traditional business model of oil companies, says Baker. Essentially, Pemex is offering a Mexican hybrid of an oilfield-service contract and a production-risk contract. "Oil companies-small, medium and large-want proportional compensation. The more they find, the more they are rewarded. And, they want to be rewarded in two ways-they want payments for production, and they want the intangible value of booking reserves. The ability to book reserves has many multiplier effects on a company's status in the industry." South Texas operator Saxet Energy agrees with this assessment. Saxet works all along the international border on the U.S. side. "We've looked at the Burgos Basin contracts, but to my mind they are fitted for service companies and not the producers," says president Robert O'Brien. "There's no upside-it's like a financial play. A company goes there and performs work, and it gets paid a fee. We would rather take the risk and be rewarded with upside." That said, there are positives to the multiple-service contracts. They offer a company the opportunity to come into Mexico and produce gas. Some companies are very savvy about South Texas gas production, and know that they can drill successful wells for quite a bit less than Pemex will pay. "An experienced company can see whether Pemex's prices make sense," says Baker. "The right company could make some serious money in Mexico." Majors might be interested in the contracts as well, for longer-term reasons. "There is little doubt that the concept of multiple-service contracts is headed offshore, and it's headed toward oil," he says. "The timeline between Burgos development through multiple-service contracts and offshore contracts is unknown; nevertheless, many believe it will happen in the next four or five years. "A prudent company might want to establish itself as an operator in Mexico, as an investment in gaining corporate knowledge, experience and credentials to position itself for future opportunities offshore." Pemex, of course, isn't saying anything about that possibility. It does plan to expand the use of the contracts, however: "We expect to eventually have multiple-service contracts in the Chicontepec area as well," says Guzman. "It is an excellent candidate to have operators change their frame of mind, and instead of considering themselves traditional operators come in as operators to a third party. Chicontepec can give excellent returns if operators apply concepts that have worked in developments elsewhere." Growing gas imports Even if Pemex's exploration and development efforts are wildly successful and the multiple-service contracts are heartily embraced by foreign operators, Mexico's gas demand will still outstrip supply growth, and imports will be required to fill the gap. The crossborder trade in natural gas is surging. The Comision Reguladora de Energia (CRE), Mexico's energy regulator, anticipates eight new pipeline interconnections at various points along its northern border between now and 2006. Those will raise Mexico's import capacity to 3 Bcf per day, triple the current level. Houston-based Kinder Morgan Energy Partners recently opened an $87-million crossborder pipeline. The 95-mile line, which has a capacity of 375 million cubic feet of gas per day, stretches from Starr County, Texas, to Monterrey, Mexico. "Although the line has only been in service since March, we are already operating at near capacity," says Steven J. Kean, president, Kinder Morgan's Texas intrastate pipeline group. The company has a 15-year contract with Pemex for all the gas the pipeline can carry, which Pemex uses for system supply and for consumption at a 1,000-megawatt power plant. Kinder Morgan finished the contract negotiations with Pemex for the transmission pipeline at the end of June 2002, and the line was in service by March of this year. "It was a remarkable success," says Kean. "Even though this was a fairly new effort-we were a U.S. company building a pipeline into the interior of the country-the permitting went relatively smoothly. Mexico has a sophisticated group of informed regulators and professional staff, and we had strong cooperation on both sides of the border." The Mier-Monterrey project is KM's second pipeline serving the Mexican market. The firm's Border pipeline interconnects with Pemex near Arguelles, Mexico, and carries about 200 million cubic feet per day. "We deliver right around half of the total imports to Mexico each day." Tidelands Oil and Gas Corp., a small public company based in Corpus Christi, Texas, is also involved in the crossborder trade. Its Reef International subsidiary is constructing a 12-inch, eight-mile pipeline between Eagle Pass, Texas, and Piedras Negras. The line will carry 50 million cubic feet of gas per day from the Maverick Basin. The crossing will be completed this September. Initially, Tidelands expects to sell some 15 million per day, says Bob Tucker, investor relations. The company's future plans call for constructing a six-inch natural gas liquids line along the same route. Additionally, it is permitting a pipeline crossing at El Paso. "The border area is growing at an unbelievable rate," says Tucker. In separate activity, San Diego-based Sempra Energy International is looking to expand its North Baja system, a 220-mile, 30-inch pipeline that stretches from Ehrenberg, Arizona, to Tijuana. Sempra completed the line, which has a capacity of 500 million per day, last September. It and PG&E Gas Transmission recently launched an open season to solicit shipper interest in additional capacity. Liquefied natural gas LNG will also play a crucial role in meeting the country's gas demand. Several projects are far into the planning stages, and construction could start on one or more within the year. Marathon Oil Corp., and its partners Grupo GGS and Golar LNG Ltd., plan to build the Tijuana Regional Energy Center, an ambitious project that encompasses an LNG offloading terminal, a regasification plant, a 1,200-megawatt power-generation plant, a seawater desalination plant, and wastewater treatment and pipeline infrastructure. The $1.6-billion-plus project will be located near Tijuana in Baja California. In early May, the group received Mexico's first federal permit for an LNG terminal from the CRE. The project is fully integrated, transferring heat and cold between the power project and the regasification plant for greatest efficiencies. "It's a very complementary design," says Paul Weeditz, Marathon spokesman. Marathon and its partners will offload LNG and regasify it at the terminal, which will have a capacity of 750 million cubic feet per day. The power plant will require some 150 million cubic feet of gas per day; the remaining 600 million per day will be sold to markets. "We're locating the project in Baja California because of the huge projected growth in demand for natural gas and electricity in the greater Tijuana area," says Weeditz. By 2020, the population of Tijuana is expected to be close to 4 million, equal to that of San Diego County. Although the primary market is Baja California, to the extent that excess gas or power is available, it will be exported to the U.S., he says. Water is an issue of great concern for the region, and the desalination plant will process 20 million gallons of potable water per day that will used by the communities. Wastewater from Tijuana's municipal system will be treated, supplying the 8 million gallons of cooling tower water that will be needed for the power plant each day. The project aims to be state-of-the-art and a model of sustainable development. The energy complex will occupy only about 16% of the 600-acre site, which is in La Joya, right on the coast. "The rest of the site will be a buffer between us and the community, and a very large portion of the remaining land will be a nursery for rare species of plants," he says. The partners are now shepherding the project through Mexico's permitting process. It needs two more key approvals, from the Secretaría de Medio Ambiente y Recursos Naturales (SEMARNAT), Mexico's environmental agency, and the local land-use authority. If the necessary approvals and financing are in place, construction could begin later this year. Start-up is slated for late 2006 or early 2007. Another project in Baja California, also in the permitting stage, is Sempra's Costa Azul. In April, Sempra received its environmental permit from SEMARNAT to build an LNG receiving terminal 14 miles north of Ensenada; it expects to receive the remaining permits shortly. The Costa Azul project will be able to process 1 Bcf of gas per day. The $600-million project has a 2006 start-up date. A third LNG project has been put out for bid by Mexico's regulatory body, the Comision Federal de Electricidad (CFE). This terminal will be sited in Altamira, a port on the Gulf of Mexico in Tamaulipas State. The Altamira project will regasify 500 million cubic feet per day, and all of that gas will be used to generate electricity. The CFE plans to announce the winning bidder on the project sometime this summer. Companies reportedly interested in the project include Shell, BP and Iberdrola. Clearly, Mexico is facing many challenges in its future. It is now inviting foreign companies into its industry, but strictly under its own terms. "We take a lot of things for granted when we come from the outside," says Luis Roca Ramisa, Schlumberger marketing director, Mexico and Central America. "But we have to realize that Mexico has been an island. The process of how things are done was developed internally, and the contracts and tenders follow Mexican law." To be successful in Mexico, a company must understand the legal limitations in the Public Works Law, he says. "The service providers cannot receive incentives for producing more oil or gas due to current legal restrictions. They make a profit through their efficiencies and their ability to manage liabilities." Mexico offers some of the best growth opportunities in the world, and foreign firms finally have the chance to join in its energy sector. For some, the terms of participation are palatable; others will take a pass and see what changes may come in the future.