Cuba's Energy Crisis: Part III**
Cuba’s Oil and Gas Potential: Truth or Myth?
Oil exploration results off Cuba’s coastal territorial waters over the last 15 years have been successful. The question still to be answered is: does the island have the potential to be another Mexico or Venezuela in its deepwater Gulf of Mexico Exclusive Economic Zone (EEZ)?
During the 1960s, oil and gas exploration results in Cuba were poor, with only several small oil discoveries made. Results changed during the 1970s with Soviet assistance and the discovery of the Varadero Oil Field in 1971. After the fall of the Soviet Union, Cuba opened its oil and gas exploration and production sector to foreign oil companies in 1993-94, with a total of 33 onshore and coastal blocks offered during its first international bidding.
In order to attract foreign oil companies to explore and extract Cuba’s hydrocarbon resources, Unión Cubapetróleo (CUPET), the state oil company under the Ministry of Basic Industry (MINBAS), adopted the internationally accepted Production Sharing Agreement (PSA) contractual format.
Most PSAs are contracts in which the international oil company assumes all risks and expenses and works as a contractor to the national oil company. In the event of a commercial discovery, the foreign oil company is allowed to recover its expenses and share in profits/volume from the field’s production. Under PSAs, the title/ownership of the hydrocarbons belongs to the state, along with associated production assets and other infrastructure.
Cuba has seen over US$1 billion spent since 1991 in its upstream oil and gas sector with very good results. Crude oil production reached a level of approximately 75,000 barrels per day in 2004 from 18,000 barrels per day in 1992. Associated natural gas production in 2004 reached approximately 18 billion cubic feet.
The majority of Cuba’s heavy sour crude oil production is from the Varadero, Puerto Escondido, and Boca de Jaruco fields along the north coast of Havana and Matanzas provinces.
Most of these recently discovered heavy oil deposits are the results of the Production Sharing Agreements between CUPET and Canadian companies Sherritt International Corp. and Pebercan Inc., using horizontal drilling technology and enhanced recovery and production methods.
Third-quarter 2005 financial statements published by Sherritt International reported gross working interest oil production in Cuba at 29,600 b/d, down from 36,086 b/d during the same period in 2004. Net working interest, or net sales volumes, which represents Sherritt’s share of gross working interest production in 3Q 2005, amounted to 15,173 b/d from 19,399 in 3Q 2004. According to Sherritt, “volumes decreased…due to natural reservoir declines, a higher gas/oil ratio in the Canasi field, and precautionary shutdowns due to hurricane activity.” (1)
Sherritt budgeted approximately US$110 million for capital expenditures in 2005 to develop the Seboruco as well as the recently discovered Santa Cruz fields. The budget also considers new exploratory work for blocks 9, 10 and 7 located in Tarara, Guanabo and Playa Larga. (2)
Another Canadian company, Montreal-based Pebercan, reported gross production for the third quarter 2005 at 13,543 b/d versus 10,747 b/d during the same period in 2004. Net share production amounted to 5,958 b/d compared with 5,437 during the first quarter of 2004. Block 7 is a 60/40 joint venture with Sherritt. Pebercan is also conducting exploration work in the Santa Cruz, Guanabo and Tarara area, east of Havana, with capital expenditures of more than US$40 million in the first nine months of 2005. (3)
Cuba’s total onshore/coastal crude oil production after the development of the Santa Cruz del Norte and Playa Larga fields could reach the 85,000-90,000 b/d range, and surpass the 100,000 b/d mark if commercial discoveries are found in Tarara and Guanabo.
Locally produced associated natural gas from the Varadero, Jaruco and Puerto Escondido fields is being used as fuel for onsite gas-fired power plants with a combined capacity of 226 megawatts (MW). The power plants and related sour gas processing units were built by Energas, a joint venture in which Sherritt has a one-third indirect interest, along with Cupet, which supplies gas at no cost to the joint venture, and Unión Eléctrica, which buys all the power from the plants. Each has a one-third interest in Energas. The $250 million dollar project was financed by Sherritt International. Additional generating capacity of 85 MW is expected to be fully installed by February 2006 in order to monetize expected production of above 20 billion cubic feet per year. (4)
The future of Cuba’s oil and gas exploration and production sector could very well be in the deep offshore Gulf of Mexico waters, along the western approaches to the Florida Straits and the eastern extension of Mexico’s Yucatan Peninsula. Cuba’s Exclusive Economic Zone (EEZ) in the Gulf of Mexico is an 112,000 square kilometers area that has been divided into 59 exploration blocks of approximately 2,000 sq km each at an average depth of 2,000 meters, with some blocks as deep as 4,000 meters.
The EEZ lies within demarcation boundaries, between Mexico, Cuba, and the United States, agreed upon during the administration of U.S. President Jimmy Carter. In June 2000, Mexico and the United States signed an agreement that demarcates each country’s rights to the Western Gulf of Mexico. The northernmost of the blocks lies south of the Dry Tortugas, off Florida’s southwest coast, and the westernmost blocks come close to what the industry has christened as the “donut holes,” deepwater areas still disputed.
CUPET has signed agreements or letters of intent with various large international oil companies interested in the deep water Gulf of Mexico, including Brazil’s Petrobras, Venezuela’s PDVSA, China’s Sinopec, India’s OVL (a subsidiary of ONGC), Spain’s Repsol-YPF, and Canada’s Sherritt.
Sherritt acquired exploration rights to the N16, N24, N23, and N33 deepwater blocks, which span 2 million acres, in 2002, and as of July 2004 the company was assessing 3D seismic data on these four offshore blocks. It is reported that Brazil’s Petrobras and/or Venezuela’s PDVSA might join Sherritt in this project.
In 2001 Spain’s Repsol partnered with Cupet to conduct seismic studies and explore six EEZ blocks; N25-N29, and N36. In July 2004 Repsol drilled its first exploratory well, Yamagua No. 1, which reached a depth of 10, 819 feet at an estimated cost of over $40 million usd. The test well is located in Block 27 about 20 miles northeast of La Habana and about 95 miles southwest of Key West.
According to Repsol, “The existence of a petroleum system has been confirmed; we have been able to prove the presence of high quality reservoirs, but we consider the well non-commercial.” At the time Repsol committed to a second exploratory well for first half of 2006.
Based on the seismic data Repsol has identified four possible drilling projects/wells: Yamagua, with an estimated capacity of 1,500-1,700 million barrels, Obatalá with an estimated capacity of 1,100-1,300 millions barrels, Ocuje with an estimated capacity of 400-500 million barrels of crude oil, and Charaguito with nearly 3,000 million barrels.
If successful, a deep water project would take from three to five years to bring into full development at an estimated total cost of between US$1 to 3 billion. To be a commercial success, the well would have to produce at a long term average rate of at least 10-20,000 barrels per day.
Repsol’s new CEO, Antoni Brufau, has confirmed that the company will drill two new wells in 2006. He also announced the addition of Norwegian oil giant Norsk Hydro and India’s ONGC as partners. The participation of Norsk Hydro and ONGC is an indication of the importance and potential of the project as both companies are recognized in industry circles for their deepwater exploration technology and operational expertise.
Another important event is a U.S. Geological Survey (USGS) report published in February 2005, which estimated a mean of 4.6 billion barrels of undiscovered oil and a mean of 9.8 trillion cubic feet of undiscovered natural gas along Cuba’s north coast.(5) The high-end potential of the North Cuba Basin could be as much as 9.3 billion barrels of undiscovered oil and of 21.8 trillion cubic feet of undiscovered natural gas, according to the report.
Foreign investment of an estimated $80 million in two new exploratory deep sea wells in 2006, along with the new USGS estimates of undiscovered reserves, underscores Cuba’s oil and natural gas offshore potential. What remains to be seen are the economic and political implications for U.S. policymakers should the Castro regime become a net crude oil exporter.
1. Cf. Sherritt International Corporation, "Management's Discussion and Analysis for Third Quarter Ended September 30, 2005," pp. 20-21, [http://www.sherritt.com/wps/wcm/resources/file/eb7a4b44dd98f0d/Q3-MDA%20-%20Nov%201%20%202005%20-%204%2030pm%20Final.pdf].
2. Ibid., p. 29.
3. Cf. Pebercan Inc., "3rd Quarter 2005: Pebercan Increases Revenues by 59% and Net Earnings by 134%," November 9, 2005, [http://www.pebercan.com/en/PDF/PBCCommPresse09112005.pdf].
4. Cf. Sherritt International Corp., Third Quarter Report 2005, p. 30.
5. Cf. USGS, "Assessment of Undiscovered Oil and Gas Resources of the North Cuba Basin, Cuba, 2004," May 2005, [http://pubs.usgs.gov/fs/2005/3009].
*Jorge R. Piñón is an international energy consultant with over 25 years of downstream oil and gas experience at leading multinational companies such as Shell, Transworld Oil, Amoco, and British Petroleum. He is currently a Research Associate at the Institute for Cuban and Cuban-American Studies, University of Miami. Mr. Piñón holds a degree in International Economics and Latin American Studies from the University of Florida.
**Final of a three-part series. See Part I: Cuba Focus, Issue 67, 15 August 2005 and Part II: Cuba Focus, Issue 68, 26 September 2005.