Frontera Significantly Expands Georgian Gas Fields May 21, 2012
Frontera Reports Resource Estimates for Georgia Block September 22, 2010
Georgia Frontera Drills Ahead Mtsare Khevi Field 12/19/08
Frontera Georgia production of 130 b/d
Frontera Makes Headway in Third Quarter at Georgia's Block 12 Frontera Resources Corp. 11/18/2008
Georgia 3/7/08 Ninotsminda field Kura basin av 425 b/d of oil /2.36 MMcfd of gas
Georgian Black Sea Sector has High Potential
Georgia Challenging Drilling Conditions Met By Frontera
Frontera Resources 4/8/2008
Expands Georgian Gas Fields May 21, 2012
by Jon Mainwaring Rigzone Staff Monday, May 21, 2012
Republic of Georgia-focused Frontera Resources Corporation's operations update, released Monday, revealed that the firm's Mtsare Khevi gas complex has "significantly expanded in potential and area".
Frontera said that throughout the first few months of this year efforts have continued to evaluate the extent of the Mtsare Khevi field's gas potential. In support of this, approximately 40 Soviet-era wells throughout an expanded area have been analyzed and many of these encountered gas.
The firm added that, based on its internal estimates, analysis has revealed significant gas potential throughout the area of as much as 1.2 trillion cubic feet of gas in place and approximately 700 billion cubic feet of recoverable gas.
"This is a massive increase on the 0.5 Bcf recoverable previously attributed," commented oil analysts at Frontera's London-based house broker finnCap.
However, despite this good news, Frontera also reported that a series of problems – including extreme winter weather conditions during 1Q 2012, a slower-than-expected government permitting process and delays associated with locating and modifying customized gas compression components – caused a delay to the installation of the firm's planned gas sales infrastructure. Instead of the original target month of April, this installation is now scheduled for July.
Since January, the firm's oil sales have generated average monthly revenues of $760,000 and these are now projected to increase to $1.2 million when gas sales begin in 3Q 2012.
Meanwhile, the firm is currently negotiating a strategic partnership for the development of the Block 12/ Taribani field ahead of the start of a four-well campaign.
"Our multiple initiatives throughout Block 12 in Georgia are advancing with an objective of increasing revenues and profitability in the near term," commented Frontera Chairman and Chief Executive Officer Steve Nicandros.
|Frontera Reports Resource
Estimates for Georgia Block September
Frontera Resources Corp
Frontera provided an operations update as well as an update of oil and gas resources associated with its Shallow Fields Production Unit, located within the Block 12 license area in the country of Georgia. Netherland, Sewell & Associates ("NSA") has finalized the results of its estimate of contingent and prospective resources associated with fields and prospects situated within the Shallow Fields Production Unit as of July 1, 2010 in accordance with standards established by the Society of Petroleum Engineers
◦Mirzaani, Mtsare Khevi, Nazarlebi and Patara Shiraki Fields*: "Best Estimate" for gross (100 percent) original oil-in-place of 626.2 million barrels, with a "low"-to-"high" range of 397.4-991.9 million barrels; and "Best Estimate" for associated recoverable gross contingent and unrisked prospective oil resources of 52.1 million barrels, with a "low"-to-"high" range of 24.9-101.3 million barrels. (*Includes Mirzaani Northwest Extension and Mtsare Khevi Prospects.)
◦Kakabeti, Lambalo, Mkralihevi, Mlashiskhevi-Oleskhevi and Tsitsmatiani Prospects: "Best Estimate" for gross (100 percent) original oil-in-place of 91.9 million barrels, with a "low"-to-"high" range of 57.7-147.7 million barrels; and "Best Estimate" for associated recoverable unrisked prospective oil resources of 8.7 million barrels, with a "low"-to-"high" range of 4.8-16.2 million barrels.
◦Mtsare Khevi Field**: "Best Estimate" for gross (100 percent) original gas-in-place of 2.6 billion cubic feet, with a "low"-to-"high" range of 2.1-3.1 billion cubic feet; and "Best Estimate" for associated gross contingent and unrisked prospective resources of 1.5 billion cubic feet, with "low"-to-"high" range of 1.2-1.9 billion cubic feet. (**Includes Mtsare Khevi Prospect.)
Shallow Fields Production Unit
Frontera's Shallow Fields Production Unit is located in the central portion of Block 12 and represents what the Company believes to be an extensive trend of low-cost, low-risk oil and gas resources. Containing the Mirzaani Field, Mtsare Khevi Field, Nazarlebi Field, and Patara Shiraki Field, these assets represent discovered yet undeveloped or underdeveloped fields that have additional associated exploitation potential. In addition, this unit contains an inventory of look-alike prospects known as the Kakabeti, Lambalo, Mkralihevi, Mlashiskhevi-Oleskhevi and Tsitsmatiani prospects. Each of these prospects contains Soviet-era wells that demonstrated hydrocarbon shows while drilling but were never placed on production or adequately appraised. Objectives are considered to be traditional, well-known reservoirs of Pliocene and Miocene age that are situated at depths from 10 meters to 1,500 meters.
Schlumberger has been contracted to provide services for a multi-zone frac completion at the #5 well. Frac operations have now commenced and are on-schedule to be completed in late September 2010.
Investments made within the past year have resulted in the discovery and confirmation of large undeveloped or underdeveloped portions of the field. In addition, operations resulted in the acquisition of important new technical information related to the reservoirs associated with the large undeveloped area of the Mirzaani Field. While it was not originally expected that frac completions would be necessary to bring the field into commercial production, analysis indicates that fracing is the key to maximizing production rates and enhancing the economic value of the field. In this context, small-scale, internally designed test fracs were successfully applied to two of the three wells to further validate this premise ahead of contracting Schlumberger to apply conventional large-scale fracs.
Discovered in 1932, the Mirzaani Field has historically produced approximately 7 million barrels of oil, but contains extensive undeveloped and underdeveloped areas. The Mirzaani #1, #2 and #5 wells are the newest wells to be drilled in the field since the Soviet-era. In 2006, Frontera acquired approximately 100 kilometers of new 2D seismic data over the field area as part of an effort to re-map and identify new potential associated with the field.
The new independent assessment by NSA places a "Best Estimate" for gross original oil-in-place for the Mirzaani Field and Mirzaani Northwest Extension of 541.7 million barrels, with a "low"-to-"high" range of 343.8-857.3 million barrels; and a "Best Estimate" for associated recoverable gross contingent and unrisked prospective oil resources of 43.8 million barrels, with a "low"-to-"high" range of 20.5-86.1 million barrels. This assessment is consistent with Frontera's internal estimates.
Evaluation and production testing have continued at the Mirzaani Field, focusing on preparation for future frac completions at the Mirzaani #1, Mirzaani #2 and Mirzaani #5 wells. Frontera's analysis has continued to underscore the potential commerciality that can be achieved from frac completions of wells within the underdeveloped portions of the field. The first frac completion is expected in late September on the Mirzaani #5 well.
Mtsare Khevi Field
The Mtsare Khevi Field is located in the western portion of Block 12 with multiple objective reservoirs situated at depths between 200 meters and 1,100 meters. The field was discovered, nominally produced and partially delineated with multiple exploration wells from 1989 to 1994, but never developed. After completing a field study in 2007, Frontera designed a plan to bring the shallow reservoirs from the Akchagil formation into production.
The new independent assessment by NSA places a "Best Estimate" for gross original oil-in-place for the Mtsare Khevi Field of 14.9 million barrels, with a "low"-to-"high" range of 11.3-19.7 million barrels; and a "Best Estimate" for associated recoverable gross contingent and unrisked prospective oil resources of 2.1 million barrels, with a "low"-to-"high" range of 1.4-3.2 million barrels. This assessment is generally consistent with Frontera's internal estimates for the Akchagil formation.
For gas, NSA places a "Best Estimate" for gross original gas-in-place for the Mtsare Khevi Field of 2.6 billion cubic feet, with a "low"-to-"high" range of 2.1-3.1 billion cubic feet; and a "Best Estimate" for associated gross contingent and unrisked prospective resources of 1.5 billion cubic feet, with "low"-to-"high" range of 1.2-1.9 billion cubic feet. Frontera's internal estimates reflect additional resource potential along the northwest trend of the fault block, which NSA was not asked to evaluate.
Steve C. Nicandros, Chairman and Chief Executive Officer, commented, "Netherland, Sewell & Associates' recent assessment of the potential associated with our Shallow Fields Production Unit represents a new and important validation of the significant value that our historical investment programs have uncovered to date. We look forward to updating the reserves category of resources associated with the Mirzaani Field and Mtsare Khevi Field as new operations progress and as production increases from the Shallow Fields Production Unit."
Georgia Frontera Drills Ahead at Mtsare Khevi Field
Frontera Resources Corp. 12/18/2008
Frontera has announced an update of its ongoing development drilling program at the Mtsare Khevi Field within its Shallow Fields Production Unit, Block 12, in the country of Georgia.
Progress has continued in the development of the Mtsare Khevi Field since drilling operations commenced in August. Since the last operations update in November, three wells have been drilled in addition to the ten wells previously announced, each targeting the Upper Pliocene age Akchagil formation as part of a rolling development program.
All 13 wells drilled to date have reached total measured depths of approximately 355 meters (1,170 feet) and each has encountered multiple hydrocarbon bearing zones situated between 200 meters and 315 meters in depth. Well log analysis continues to indicate approximately 20-30 meters of gross pay in each well.
Since the start of the development drilling campaign, ten wells have been tested as oil wells with initial rates from single horizons as high as 40 barrels per day of 21 degree to 28 degree API oil. In addition, two wells located high on the field structure have tested gas with initial rates of as much as 1.2 million cubic feet of gas per day.
The Akchagil formation of the Mtsare Khevi Field has three main reservoirs for development: Horizons I, II and III. The wells drilled to date are first being brought into production from Horizon I, the deepest of these reservoirs, with each well undergoing planned production and optimization tests over a 30-60 day period prior to being placed on production. Daily production from the field is currently approximately 130 barrels per day. Production is expected to increase as a result of ongoing efforts that include optimization of pump performance and the addition of perforations to currently producing horizons. In addition, work plans are in progress to co-mingle production from the shallower Horizons II and III, which is expected to significantly enhance production. The company is also examining the feasibility of adding gas development to the commercialization agenda for the Mtsare Khevi Field, given the discovery of gas. Rigs and equipment sourced from within Georgia are being utilized to undertake the ongoing development program.
The Mtsare Khevi Field is located in the western portion of Block 12 with multiple objective reservoirs situated at depths between 200 meters and 1,100 meters. The field was discovered and partially delineated with multiple exploration wells from 1989 to 1994, but never developed and produced. After completing a field study in 2007 that indicated this field potentially contains as much as 5 million barrels of recoverable oil reserves, Frontera designed a plan to bring the shallow reservoirs from the Akchagil formation into production. Additional potential exists in deeper Miocene age sandstone horizons that have previously tested and flowed oil. This potential is currently under study and will become a focus of future operations to fully develop the Mtsare Khevi Field.
Steve C. Nicandros, Chairman and Chief Executive Officer, commented, "We have been delighted with the results from the continued efficient, low-cost development progress that has been made to date in our Mtsare Khevi Field operations. As this field continues to come to life, results are supporting our belief in the substantial value contained within this asset."
Frontera's Shallow Fields Production Unit is located in the central portion of Block 12 and represents what the company believes to be an extensive trend of low-cost, low-risk undeveloped oil and gas reserves. Containing four discovered yet undeveloped or underdeveloped fields that have additional exploration potential, objectives are considered to be traditional, well-known reservoirs of Pliocene and Miocene age that are situated at depths from 10 meters to 1,500 meters.
|Frontera Georgia production of 130 b/d
By OGJ editors HOUSTON, Dec. 18 2008
Frontera Resources Corp., Houston, established production of 130 b/d of 21-28° gravity oil at Mtsare Khevi field in its shallow fields production unit in Block 12 in Georgia.
Frontera has drilled 13 wells since August 2008 to the Upper Pliocene Akchagil formation that encountered multiple hydrocarbon zones at 200-315 m with 20-30 m of gross pay per well.
The wells are producing from Horizon I, deepest of the three Akchagil reservoirs I, II, and III. The plan is to commingle production from II and III. Further potential exists in Miocene sandstones as deep as 1,500 m that previously flowed oil.
Two wells high on the structure also tested gas with initial rates of as much as 1.2 MMcfd, and the company is studying feasibility of developing the gas.
The field was discovered and delineated in 1989-94 -- never developed. A 2007 Frontera field study indicated as much as 5 million bbl of recoverable oil.
|Frontera Makes Headway
in Third Quarter at Georgia's Block 12
Frontera Resources Corp. 11/18/2008
Frontera has announced results for the quarterly period ended September 30, 2008 and provided a review and update of its operations in Block 12, Georgia.
* Revenues for the first nine months of 2008 were $2.9 million, which is $1.0 million higher than the same period in 2007. To date, revenues in 2008 are $4.9 million, which is $3.0 million higher than the comparable period in 2007 as a crude oil sale of $2.0 million was completed subsequent to quarter end.
* Results for the quarter ended September 30, 2008 reflect a net loss of $10.4 million, or $0.14 per share on a fully-diluted basis, in line with the early stage nature of the company's asset portfolio and expenditures required to evaluate the company's undeveloped fields and exploration opportunities.
* Strong working capital position at September 30, 2008.
* Favorable ruling received in arbitration with GAC Energy Company and GAC International Holdings Ltd.
* Russia's invasion of Georgia in August and current international financial and oil markets downturn presented unanticipated business environment challenges.
Shallow Fields Production Unit
* Commenced development drilling program at the Mtsare Khevi Field in August, with 10 wells completed to date and an 11th currently underway associated with a rolling 20-well drilling campaign. Development drilling at Mtsare Khevi Field has been very successful thus far, with 100 percent of the wells finding and testing hydrocarbons. Since the start of the drilling campaign, eight wells have come on stream as oil wells and two have found gas.
* Commenced development drilling operations at the Nazarlebi Field and Patara Shiraki Field in July, with 20 wells completed to date.
* Continued production operations at Mirzaani Field and completed technical evaluation program for new development drilling expected to commence prior to year end.
* Achieved a 110 percent increase in production to date this year as a result of ongoing development operations. The unit has generated revenues of $1.3 million since mid-year.
Taribani Field Unit
* Continued analysis of ongoing production results from frac-stimulation completions associated with initial Zone 9 development wells. Production data has provided the basis for optimization of future frac completion designs in Zone 9 and provided technical basis for re-design of future development wells to also include completion in Zones 14/15. Multi-zone completions within a single wellbore will increase cost effectiveness and accelerate value creation in ongoing 20-well development program at the Taribani Field.
* Delayed drilling of the next planned development well to early 2009 in favor of incorporating optimized engineering and frac completion designs, in addition to monitoring changing industry cost structure associated with current business climate.
* Achieved a substantial increase in production to date this year as a result of ongoing development operations. The unit has generated revenues of $0.7 million since mid-year.
Basin Edge Play Unit
* Completed depth migration of 80 square kilometer 3D seismic survey associated with the "C" Prospect. Results have revealed that previous structural interpretation remains intact and provided an enhanced understanding of the prospectivity associated with this large prospect in anticipation of future drilling operations.
* Continued efforts to secure a technically appropriate rig for completion of currently suspended drilling operations at the "C" Prospect's Lloyd #1 well with a focus on successfully reaching primary Cretaceous objectives within the prospect. Amidst a changing market environment for oilfield services and equipment, current plans are targeting resumption of drilling during the second quarter of 2009.
Steve C. Nicandros, Chairman and Chief Executive Officer, commented, "Despite unanticipated challenges presented by Russia's invasion of Georgia in August, Frontera's operations since mid-year have marked a continued period of progress and growth.
"Development drilling operations within the Shallow Fields Production Unit have successfully provided the basis for an increasing oil production profile. This work has also defined opportunity for developments that are generally larger than originally anticipated and has revealed the new possibility to add gas reservoir development to our commercialization agenda. As a result, we are optimistic that this business unit will continue to add important near-term value to our company.
"At the Taribani Field Unit, analysis of production and reservoir performance data over the past several months has permitted us to reach important new milestones in evolving the technical efficiency and resulting commercial strength of our ongoing development program. Based on investments to date related to frac-stimulation of Zone 9 reservoirs, we now understand that we can improve the efficiency of future fracs as well as add additional reservoirs to individual frac-stimulation well completions.
"These advancements now provide us with confidence in our ability to frac and produce Zones 9, 14 and 15 from a single wellbore in future development wells, thereby allowing us to more cost effectively accelerate development of this large field. While recent geopolitical events in Georgia contributed to a delay in commencing planned drilling operations at the Taribani South #1 well in September, this provided an opportunity to incorporate ongoing technical analysis into current development plans such that we have altered our planned drilling schedule in favor of implementing a more efficient program.
"At the Basin Edge Play Unit, our ongoing technical analysis of results from recent drilling operations and associated depth migration of extensive geophysical data continues to enhance our view of the giant reserve potential that this business unit contains. However, economic conditions presented a tight and expensive service sector climate throughout the third quarter of this year, providing a challenging atmosphere for the procurement of equipment necessary to complete our exploration drilling plans at the Lloyd #1 well. As market conditions improve, our desire is to return to drilling this important prospect during the second quarter of 2009.
"Our rigorous approach to securing liquidity has ensured a strong working capital position as we continue our work programs. Nevertheless, we recognize that recent turbulence in the international financial markets and the dramatic decline in oil prices may present challenges to execution of our future funding strategy, in particular through project financing and internally generated cash flow. While we continue to pursue available sources of capital for continued growth, we are cautious in the management of our discretionary work programs in consideration of the possibility that financial markets may remain sluggish and that lower oil prices may also persist for the near term.
"Overall, amidst the current international economic environment, we remain encouraged with respect to the results we have seen from operations in each of our business units. Accordingly, as we move forward to the end of this year and into 2009, we will continue to responsibly manage our growth with a focus on increasing near-term production from development drilling while ensuring that associated costs are in line with current market conditions."
Georgia Challenging Drilling Conditions Met By Frontera
Frontera Resources 4/8/2008
Frontera Resources Corporation announced an update of operations at the Lloyd #1 well at its Basin Edge Play Unit, Block 12, Georgia.
In the most recent Operations Update of February 19, 2008 for drilling operations at the "C" Prospect, it was reported that drilling operations at the Lloyd #1-Sidetrack #1-3 were in progress with the expectation of reaching the top of the primary objective Cretaceous formations at a measured depth of approximately 2,950 meters. As previously reported, the well was originally sidetracked (Sidetrack #1-2) in December 2007 in an effort to more optimally encounter the well's Cretaceous age primary geologic formation targets and also to appraise the Tertiary age geologic formations in an up-dip position to where oil and gas shows were encountered low on the structure in the original well bore. Sidetrack #1-3 was commenced in February 2008 in order to overcome challenging drilling conditions encountered within the Eocene formation, which is expected to lie stratigraphically directly above the primary Cretaceous target.
Since February, ongoing analysis determined that the challenging drilling conditions associated with the Eocene formation are most likely attributable to the highly tectonized nature of this formation. Sidetrack #1-3 commenced drilling from a measured depth of approximately 2,200 meters and again encountered encouraging hydrocarbon shows in the Tertiary section of the well, but after reaching approximately 2,600 meters, difficult drilling conditions were once again encountered.
With the primary objective Cretaceous interval expected to be within 300 meters, a new sidetrack (Sidetrack #1-4) commenced from a depth of about 2,500 meters and progressed to a depth of approximately 2,700 meters. Hydrocarbon shows were also seen in the #4 sidetrack. However, the well once again encountered well bore instability within the Eocene formation.
Based on the difficult drilling conditions associated with the Eocene formation, a formation that was not originally expected to be encountered within the "C" Prospect, a new approach to drilling this section of the well has been designed. As a result, appropriate changes have been made to well plan design for continued drilling and it has been concluded that it will be necessary to replace the existing drilling rig and associated equipment in favor of a new rig with capabilities and specifications that are better suited for the drilling challenges that we have encountered. This is being done with a focus on efficiently and successfully reaching our primary Cretaceous objective within the "C" Prospect. Based on this, efforts are currently underway to mobilize a new rig to continue operations in June.
Steve C. Nicandros, Chairman and Chief Executive Officer, commented: "Since February, Frontera's drilling operations at the 'C' Prospect have continued to be encouraging based on the ongoing analysis of mud logs, cuttings, cores, electronic logs and other technical data. Given that we are so close to our primary Cretaceous objective, we have deemed it prudent to evolve our approach to completing this important exploration well. Despite the unexpectedly difficult drilling conditions that have put us within 300 meters of our anticipated primary objective, we remain extremely encouraged about what we have discovered thus far with our work at the 'C' Prospect. In this context, the overall effort on the part of our integrated exploration and operations team has been very commendable and we believe the revisions we have now made to our overall plan will allow us to successfully reach our objectives on this important prospect."
Ninotsminda field Kura basin av 425 b/d of oil /2.36 MMcfd of gas
HOUSTON, By OGJ editors
Ninotsminda field in the Kura basin of former Soviet Georgia averaged 425 b/d of oil and 2.36 MMcfd of gas in January, said CanArgo Energy Corp., Guernsey, Channel Islands, UK.
The company is working on a production enhancement strategy, subject to financing, that could include drilling horizontal wells in the eastern part of the field, drilling a vertical well to tap Oligocene oil in the northern part of the field, and using new technology to access isolated reserves in shallower reservoirs.
A gas pipeline that connects the field to the Georgian gas network was completed in February that may provide an alternate gas market. The associated gas has been sold to local villages at 71¢/Mcf the past several years with little payment.
Selling part of the gas to villages and part to the distribution company at $4.73/Mcf may result in a future average realization of $2.72/Mcf. The country also plans to privatize its gas distribution companies.
In a recent radio address by Georgian President Eduard Shevardnadze, he said he expects that Georgia might be able to meet its own oil requirements within the next few years. He said Anadarko Petroleum informed him that the results of research in the Georgian sector of the Black Sea confirmed the possibility of oil and gas deposits.
The president noted that at the moment there are seven or eight foreign oil companies working in Georgia, including Frontera and CanArgo, which are not only involved in exploration, but in production also. He noted in particular that CanArgo recently used directional drilling to restore an old well at the Ninotsminda field and is currently producing 170 tons of oil per day there.
The president expressed certainty that positive results would be received in the near future at the Dedoplistskaro, Taribana and other fields, where foreign companies are working and have invested tens of millions of dollars over several years. "Today almost nobody doubts that Georgia has quite large oil and gas resources," he said.
The Georgian leader said that the Anadarko representatives "are convinced that there are rich deposits of oil and gas in the Georgian sector of the Black Sea and that with the use of modern technology their extraction is totally possible." He also said that the southern-gas pipeline corridor has entered the practical implementation stage and in two to three years Georgia will receive a very serious source of natural gas.
According to agreements, Georgia would receive 5% of the Azerbaijani gas transported through the pipeline to the world market. "This is more than 1.5 billion cubic meters of gas per annum," he said, adding that if necessary Georgia would be able to buy extra gas at a reduced price.
Georgia is of strategic importance as a potential transit state for oil and gas from the Caspian Sea region to Western markets.
Information contained in this report is the best available as of April
2001 and is subject to change.
After its independence from the Soviet Union in 1991, Georgia was beset by civil conflict and political turmoil, including the overthrow of the country's first democratically elected president and separatist struggles in Abkhazia (northwest Georgia) and South Ossetia (north central Georgia). A Russian-enforced cease-fire in 1994 brought an end to the conflict in Abkhazia, and both conflicts have been dormant for several years now, but Russian troops remain stationed in Abkhazia. Russia's war in Chechnya has led to fighting along the Georgian-Chechen border, and the dispute over the withdrawal of Russian forces from Georgian territory and Russia's accusation of Georgian support for Chechen rebels has strained Georgian-Russian relations.
Georgia's economy, already reeling from the loss of Soviet subsidies after independence, was severely damaged by the Abkhazia and South Ossetia civil conflicts. Hyperinflation in the early 1990s reached 7,000% per year by 1994, and by 1995, Georgia's gross domestic product (GDP) had fallen to 20% of 1990 levels. Since then, however, GDP has leveled off and, with the help of the International Monetary Fund (IMF) and World Bank, a recovery has begun. Georgia's currency, the lari, was introduced in September 1995 and has remained relatively stable with the backing of an IMF stabilization fund. Inflation, estimated at 4.6% in 2000, has been brought under control, and GDP growth has resumed, although it has been moderated (1.9% in 2000) by the lingering negative effects of Russia's August 1998 financial crisis.
Georgia continues to experience large budget deficits due to a failure to collect tax revenues, and the country is burdened by a growing foreign debt problem. Much of Georgia's foreign debt is to Russia and Turkmenistan for fuel supplies; Georgia's only sizable internal energy resource is hydropower, and a drought in 2000 reduced the country's hydropower potential. However, Georgia privatized its electricity distribution network in 1998, and deliveries are improving, despite a crisis in January 2001 due to a cutoff of Russian gas supplies for electricity. Georgia is pinning its hopes for long-term economic recovery on the development of an international energy transportation corridor via Tbilisi and the key Black Sea ports of Poti and Batumi, as well as foreign investment in the country's own nascent oil industry.
Georgia has limited oil resources, but with investment increasing and active exploration underway, both along Georgia's Black Sea coast and onshore, the country's domestic production is set to rise dramatically in coming years. In 2000, Georgia produced 2,200 barrels per day (bbl/d) of oil, and with the country's consumption of 23,000 bbl/d projected to increase as Georgia continues its recovery from civil strife in the mid-1990s, Georgia will need to develop its oil sector to meet domestic needs.
Georgian authorities have estimated that $453 million is to be invested in oil and gas exploration and production in Georgia by nine joint ventures between 2001 and 2005. The joint ventures are conducting operations in a number of blocks, including Ninotsminda, Manavi, Rustavi Kartli, Samgori, Patardzeuli, Mtiani Kakheti, Mirzaani, Taribana, Patara Shiraki, Nazvrebi, Georgia's Black Sea shelf, Supsa, Chaladidi, and Shromisubani. While the majority of companies are prospecting for oil and gas, several companies already have discovered oil fields of commercial value and are actively developing those deposits. Some forecasts suggest that Georgia may produce up to 20,000 bbl/d in 2001, with production increasing to two to three million tons per year (40,000-60,000 bbl/d) by 2005.
In July 2000, Frontera Eastern Georgia, a Georgian-American joint venture, began extracting 120 tons of oil per day (800 bbl/d) from the Taribana field in Kakhetia. According to specialists, the Taribana deposit could begin producing about 400 tons per day (2,666 bbl/d) in the near future. The Taribana field, the first of Frontera's development projects, which contains an estimated 1 billion barrels of oil equivalent. Frontera holds 100% of the foreign company operating interest in the production-sharing agreement and is in partnership with Saknavtobi, the Georgian state oil company.
CanArgo-Georgia, a Georgian-British oil company, has discovered commercial oil reserves in Georgia in the Ninotsminda field. The company, whose activities are conducted through its wholly owned subsidiary, Ninotsminda Oil Company Ltd., is planning to produce 150,000 tons of oil (3,000 bbl/d) in 2001, as well as to drill four deep exploratory wells and to continue with geological survey work. Saknavtobi and Anadarko (U.S.) already have worked out a package of production-sharing agreements on the Black Sea shelf, where exploration engineers have discovered roughly 580 million tons of oil (42.5 billion barrels), including about 200 million tons (14.7 billion barrels) offshore. In March 2001, Anadarko completed its first stage of exploration, with plans to drill the first test boreholes as early as the summer of 2001. Georgian officials have said that Anadarko may invest up to $1 billion to develop the offshore oil fields.
Georgia has negotiated several production-sharing agreements and joint ventures in the Kura Basin east of Tbilisi, as well as in the Black Sea region in western Georgia. In August 2000, Saknavtobi and the German company GWDF International signed an agreement to develop the Chaladidi, Supsa, and Shromisubani fields in western Georgia. Kakheti Oil Ltd., the local operating company managed by Ramco Energy through its 1998 agreement with Saknavtobi, drilled its first well onshore in Kakhetia at the end of 2000.
Georgia has a 106,000-bbl/d refinery at Batumi and a smaller, 4,000-bbl/d refinery at Sartichala, the Georgian-American Oil Refinery (GAOR). Georgia has awarded a $250-million contract to Japan's Marubeni Corporation and JGC Corporation to expand and modernize the Batumi refinery, and Georgia is working with the EBRD to finance the reconstruction of the Gardabani-Batumi pipeline, which has transported oil to the refinery at Batumi.
In November 2000, CanArgo Energy Corp. purchased an additional 38% in the GAOR, giving it a controlling interest in the refinery, which is situated in proximity to CanArgo's producing Ninotsminda field and Tbilisi. CanArgo intends to expand the capacity of the refinery, as well as broaden the refinery's product stream to include high-octane gasoline. Georgia also has awarded Frontera the right to construct a new refinery near Tbilisi as part of its production-sharing agreement.
Oil and Gas Transit
Georgia's importance in world energy markets stems from its geographic location as a growing transit center for oil and gas from the Caspian Sea region. Georgia is part of the designated Eurasian Transport Corridor (TRACECA) to bring oil, gas, and other products from the Caspian/Caucasus region to Europe. In addition to transporting the "early oil" from the Azerbaijan International Operating Company (AIOC) through its Black Sea port at Supsa, Georgia is playing a key role as a transit state for the planned 1-million bbl/d Main Export Pipeline (MEP) that will carry Caspian oil from Baku, Azerbaijan, via Tbilisi to the Turkish Mediterranean port of Ceyhan and on to world markets.
Georgia has small natural gas resources, leaving it almost entirely dependent on foreign suppliers. Georgia's natural gas production in 1999 was 2.1 billion cubic feet (Bcf), which Georgian leaders hope to increase in coming years with foreign investors helping to develop the country's gas deposits. In January 2001, CanArgo-Georgia began work on drilling a new gas well at the Ninotsminda gas deposit in Georgia, which has estimated gas reserves of less than 706 Bcf.
Georgia's natural gas consumption in 1999 was 41 Bcf, far exceeding the country's natural gas production capacity. In addition, Georgia's inability to pay its suppliers has limited the country's consumption, as both Russia and Turkmenistan have cut off gas to Georgia for lack of payment. Georgia's 1999 natural gas consumption was less than 25% of the country's 1992 natural gas consumption (177 Bcf).
Turkmenistan claims that Georgia still owes it $400 million for past natural gas supplies, and as a result Turkmenistan has ceased gas shipments to Georgia, leaving Russia Georgia's sole gas supplier. This tenuous situation led to a crisis when, on January 1, 2001, Russia's Inneftegazstroi, part of the Gazprom group, halted supplies of natural gas to the Tbilisi State Regional Power Plant, causing blackouts throughout Tbilisi. Representatives of AES (U.S.), which runs the electricity distribution network in the Tbilisi area, said that the cutoff violated their contract with Inneftegazstroi, which supplied 1,000 cubic meters of gas at a cost of $41 (compared with $53 per 1,000 cubic meters in a recent contract between the Georgian Energy Ministry and Itera, the international energy corporation). Gas shipments to the power plant resumed on January 4th by Itera on a temporary basis until the problem with Inneftegazstroi was solved.
In an effort to restructure Georgia's gas-distributing pipelines and to receive guarantees of future gas supply at a firm price, Georgian authorities previously have offered Itera the option of taking part in the privatization of Tbilgaz, the state company controlling Georgia's gas transportation pipelines. In July 2000, Itera had offered $1.5 million for 75% in Tbilgaz, and was prepared to undertake rescheduling of the company's debts, but Georgia postponed the official announcement of the privatization tender. On October 4, 2000, Itera executives said that the company preferred only to take part in a consortium of a few investors to buy out Tbilgaz. Negotiations on a new privatization scheme are continuing.
Georgia's coal industry, already small by world standards in 1991, has become even smaller since the country's independence. Between 1992 and 1999, Georgia's coal consumption plummeted 97%--from 480,000 short tons in 1992 to just 15,000 short tons in 1999. Similarly, the country's domestic coal production has witnessed a drastic 95% reduction, from 220,000 short tons in 1999 to 11,000 short tons in 1999. Nevertheless, the country's coal industry has rebounded somewhat from the effects of the separatist conflicts in the early and mid-1990s, and since 1997, Georgia's coal production and consumption actually have increased, albeit slowly.
The weakness of Georgia's power sector is one of the biggest obstacles to the country's economic growth. Although Georgia technically generates more electricity than it consumes (8.0 billion kilowatt-hours--Bkwh--generated in 1999, compared to 7.1 Bkwh consumed in the same year), power outages are a daily occurrence in much of the country, and parts of Georgia do not receive any electricity at all. Georgia's total electricity demands have been estimated at nearly twice the amount that is actually generated, and the Georgian Energy Ministry estimates that 40% of all power that is generated is wasted due to equipment and maintenance problems in the transmission sector. In addition, the power sector is plagued by frequent customer non-payment, as well as the country's dependence on foreign gas supplies.
To meet some of its power needs, Georgia imports electricity from both Armenia and Russia. Georgia has ran up large electricity debts to both countries; at the end of 2000, Georgia owed Armenia approximately $4.4 million and Russia approximately $50 million for past electricity supplies. The debts have stopped growing since Georgia privatized the Telasi electricity distribution network in 1998. AES purchased 75% of Telasi, which serves the Tblisi area, for $25.5 million, and made a commitment to pay $10 million of Telasi's debt and $80 million in investment to provide consumers with 24-hour electricity.
Georgians continue to suffer from power shortages, and a drought in the summer of 2000 meant that hydropower plants, which generate nearly 80% of the country's electricity, seriously depleted hydropower reservoirs, dashing hopes that the winter of 2000-2001 would be the first without periodic electricity disruptions. Tbilisi residents were enraged when Georgian officials announced they would only receive six to eight hours per day of electricity during the winter, but most parts of the Georgian capital had electricity only two hours per day on average. Residents use kerosene for heating.
Russia's decision to cut off gas supplies to power-producing units at Tbilisi State Regional Power Plant on January 1, 2001, following the summer drought, triggered a full-fledged energy crisis in Georgia and further soured Georgian-Russian relations. Georgia's Foreign Ministry said that the shut-off came despite prepayment for January shipments. Russia resumed natural gas supplies to the Georgian capital after a three-day break in service during which electricity supplies in Georgia were cut by up to 80%.
In addition, in an effort to boost its electricity supply, Georgia had rejoined the Russian power grid in November 2000, but on January 25, 2001, Russia's electricity monopoly UES reduced its power deliveries to Georgia because of Georgia's electricity debts. UES cut power deliveries from 2.5 million kilowatt-hours to 1 million kilowatt-hours. Russia has since increased power supplies to Georgia with an eye towards exporting electricity to Turkey via Georgia. Russian and Turkish officials have been in negotiations towards concluding an electricity export deal.
In an effort to resolve the problems in the power sector, Georgia is actively privatizing Sakenergo, the state energy and power company. With support from the World Bank and the EBRD, most of Georgia's hydro and thermal generation units have been restructured as joint-stock companies, and the Georgian Ministry for the Management of State Property is proceeding with privatization in three stages.
In the first stage, AES purchased 75% of the Tbilisi State Regional Power Plant (Gardabani), as well as a 75% share of the Relasi distribution power company in Rustavi, and a 25-year management contract for the Khrami I and II hydroelectric power stations (223-megawatt (MW) combined capacity). The second stage will offer 75% of the shares in the Kutaissky distribution company (Kalasi), and management of 100% of the shares in 5 hydroelectric plants (Ladjanuri, Tkibuli, Shaori, Gumati, Rioni), while the third offer will contain 75% of the shares in the remaining 58 distribution companies.
Investment/Renovation in Hydropower Projects
Georgia is courting foreign equity participation for both new capacity and rehabilitation hydropower projects. Georgia has a substantial amount of untapped hydro energy that could be exploited, with plans already made to build two new hydroelectric plants on the Rioni River (the 250-MW Namakhvani and the 100-MW Zhoneti), as well as a plan to build the 40-MW Minadze station on the Kura river.
Dengen Kaihatsu (Japan) has announced its readiness to invest both in construction of new hydroelectric stations in Georgia and restoration of the old ones, and in February 2001, Chinese and Georgian officials signed an agreement on the construction of a hydropower station near the Georgian-Russian border, in the Pankisi Gorge, that will meet the electricity needs of the eastern Kakheti region.
In addition, in November 2000, Georgia announced a tender for the rehabilitation of the Inguri hydropower station, the country's largest. The project, which will cost an estimated $62 million, will boost capacity at the plant to 1,300 MW from 400-450 MW currently The EBRD will provide $39 million in the form of a long-term credit, with the EU and Japan providing grants totaling $10 million, and Georgia financing the remainder.
President: Eduard Shevardnadze (previously elected chairman of the Government Council March 10,1992; Council has since been disbanded; previously elected chairman of Parliament Oct. 11,1992; president since Nov. 26, 1995; re-elected to a five-year term on April 9, 2000)
Minister of State: Gia Arsenishvili
Independence: April 9, 1991 (from Soviet Union); Independence Day: May 26 1991
Population (7/00E): 5.0 million
Location: Southwest Asia on Black Sea between Armenia, Azerbaijan, Russia, and Turkey
Size: 26,911 square miles, slightly smaller than South Carolina
Major Cities: Tbilisi (capital), Batumi, Poti, Rustavi
Language: Georgian 71% (official), Russian 9%, Armenian 7%, Azeri 6%, other 7% (includes Abkhaz, official in Abkhazia)
Ethnic Groups: Georgian 70.1%, Armenian 8.1%, Russian 6.3%, Azeri 5.7%, Ossetian 3%, Abkhaz 1.8%, other 5%
Religion: Georgian Orthodox 65%, Muslim 11%, Russian Orthodox 10%, Armenian Apostolic 8%, unknown 6%
Finance Minister: Zurab Nogaideli
Economics and Industry Minister: Vano Chkhartishvili
Market Exchange Rate (3/9/2001): US$1=2.08 Lari
Nominal Gross Domestic Product (GDP) (2000E): $3.0 billion; (2001E): $3.1 billion
Real GDP Growth Rate (2000E): 1.9%; (2001E): 2.1%
Inflation Rate (Change in Consumer Prices, December 1999 - December 2000): 4.6%; (2001E): 4.7%
Official Unemployment Rate (2000E): 6.3%; (2001E): 4.7%
Current Account Balance (2000E): -$181 million
Major Trading Partners: Russia, Turkey, European Union, Azerbaijan, Armenia, United States (1997)
Merchandise Exports (2000E): $465 million
Merchandise Imports (2000E): $1.021 billion
Merchandise Trade Balance (2000E): -$556 million
Major Exports: citrus fruits, tea, wine, other agricultural products; diverse types of machinery and metals; chemicals; fuel re-exports; textiles
Major Imports: fuel, grain and other foods, machinery and parts, transport equipment
Foreign Exchange Reserves (2000E): $110 million
External Debt (9/00E): $1.49 billion
Minister of Fuel and Energy: David Mirtskhulava
Proven Oil Reserves (1/1/2001E): 35 million barrels
Oil Production (2000E): 2,200 barrels/day (bbl/d)
Oil Consumption (2000E): 23,000 bbl/d
Net Oil Imports (2000E): 20,800 bbl/d
Refining Capacity (1/1/2001E): 106,000 bbl/d
Natural Gas Reserves (1/1/2001E): 300 billion cubic feet (Bcf)
Natural Gas Production (1999E): 2.1 Bcf
Natural Gas Consumption (1999E): 41 Bcf
Coal Production (1999E): 11,000 short tons
Coal Consumption (1999E): 15,000 short tons
Electric Generation Capacity (1999E): 4.4 gigawatts
Electricity Generation (1999E): 8.0 billion kilowatt-hours (Bkwh)
Electricity Consumption (1999E): 7.1 Bkwh
State Oil Company: Saknaftobi Saknavtobproductebi (Georgian Oil Products), Saknakhshiri (Georgian Coal), Sakenergo (Georgian Energy), Saknaftobi (Georgian Oil)
State Joint Stock Company: Georgian Gas International Corporation (GIC)
Major Oil and Gas Fields: None; small fields in both eastern Georgia and on the Black Sea shelf in western Georgia.
Major Pipelines: 100,000 bbl/d Supsa-Baku (Azerbaijan) oil pipeline; Grozny (Russia) to Tbilisi (Georgia) to Yerevan (Armenia) gas pipeline.
Refineries (crude oil capacity): Batumi (106,000 bbl/d), Georgian-American Oil Refinery (Sartichala) (4,000 bbl/d)
Major Ports: Supsa, Batumi, Poti, Sukhumi
State Electric Utilities: Sakenergo-Generatsia (Generation) and Sakenergo-Gadatsema (Transmission)
Major Power Plants (capacity): Inguri hydroelectric plant (1325 megawatts, MW), Tbilisi State Regional Power Plant (Gardabani) (1280 MW)
For more information from EIA on Georgia, please see:
EIA - Country Information on Georgia