(Energy Analytics Institute, Piero Stewart, 18.Jul.2018) – The risk-rating agency Moody’s increased the baseline credit assessment (BCA) two notches, to ba1 from ba3 for Colombia’s state oil company.
The agency said the higher BCA was primarily due to Ecopetrol’s “solid metrics and progress in its strategy of growth and adding to reserves, with a reserves replacement index of 126% at the end of 2017,” reported Ecopetrol in an official statement, citing a Moody’s press release.
In the release, Moody’s highlighted Ecopetrol’s four areas of growth:
1. Implementation of improved recovery and infill projects,
3. Assessment of opportunities in non-conventional deposits, and
4. Inorganic growth leveraged on its strong cash position.
Moody’s also stressed “Ecopetrol’s solid liquidity and the management team’s commitment to protecting credit metrics.”
The agency maintained Ecopetrol’s rating at Baa3 with a stable outlook.
(Reuters, 18.Jul.2018) – Colombia’s President-elect Ivan Duque on Wednesday named Maria Fernanda Suarez as mining and energy minister when he takes office in August, a role that will require her to bolster oil production to help weak economic growth and settle messy mining disputes.
Suarez, 44, is currently executive vice president at state oil company Ecopetrol. She served as director of public credit at the finance ministry and as vice president of investments for the Porvenir pension fund. She has also held senior positions at Citibank, ABN AMRO and Bank of America.
Suarez has a Masters degree in public policy from Georgetown University. She will replace German Arce.
“She has a brilliant resume in the public and private sectors,” Duque said in a statement.
As mines and energy minister, Suarez faces a difficult task as Colombia struggles to increase oil production to help increase revenue and bolster the weak economy after years of weak international oil prices.
“With her, we will promote greater diversification of national energy, efficiency and competitiveness in the sector, provide energy security for Colombia, and social and environmental responsibility in all energy mining production sectors,” Duque said.
At current rates of production, Colombia has less than six years worth of oil reserves, the energy ministry says, and urgent investment in exploration is needed to replace reserves.
Duque’s solution to dwindling oil reserves is to encourage investment in exploration, which he says could provide years more oil production, and give tax relief to the sector.
He has also pledged additional investment at state-run Ecopetrol’s refineries to allow exports of more higher-value derivatives.
Still, with the economy growing at an expected pace of just 2.7 percent this year and a budget deficit that needs to be reduced, funding such expenditure may be tough.
The Colombian Petroleum Association (ACP), says the industry needs to spend up to $7 billion a year just to keep output between 800,000 and 860,000 barrels per day.
Oil companies are already grappling with security concerns as well as local referendums – on whether to allow mining in certain areas – and environmental court rulings that have stymied major mining projects in Latin America’s fourth-largest economy.
A recent paper by the ACP, which represents private crude producers, warned that planned referendums put one-fifth of oil production at risk.
Private oil companies plan to invest up to $4.9 billion this year, ACP said, while Ecopetrol plans to spend up to $4 billion.
(Reporting by Helen Murphy Editing by Nick Zieminski)
(Energy Analytics Institute, Piero Stewart, 18.Jul.2018) – Colombia’s President elect Iván Duque named Ecopetrol Executive Vice President María Fernanda Suárez as the country’s new mining minister, according to reports in the daily newspaper La Republica.
(Reuters, 17.Jul.2018) – Pumping through the Colombia’sCano Limon-Covenas oil pipeline restarted after a 180-day stoppage due to repeated attacks by Marxist ELN rebels, military and industry sources said on Tuesday.
The 485-mile (780-km) pipeline has been attacked 58 times this year by the National Liberation Army (ELN), the country’s largest active guerrilla group, according to military sources.
Apart from bombing damage, 41 illegal valves used to steal crude were found on the pipeline, said state-owned Ecopetrol SA, which owns the pipeline via its subsidiary Cenit.
Although this is one of the most extensive paralyses since the pipeline opened in the mid-1980s, activity in the Cano Limon field, operated by Occidental Petroleum Corp and located in the northern Arauca province, has not been affected.
Crude from the field had been transported using a smaller pipeline, which is still at risk of attack, sources said.
Ecopetrol which produces around 60 percent of Colombia’s 866,000 barrels a day of oil.
The ELN, considered a terrorist group by the United States and European Union, has about 1,500 combatants and opposes multinational companies, claiming they seize natural resources without benefiting Colombians.
Outgoing President Juan Manuel Santos and the ELN launched peace negotiations in 2017 but the talks, which shifted from Ecuador to Cuba in May, have been fraught. The guerrillas stepped up their attacks after the end of a bilateral ceasefire in January.
President-elect Ivan Duque, who was voted in last month, has said he will halt the talks unless the ELN declares a unilateral ceasefire and concentrates its forces into a single area.
Cano Limon has been bombed more than 1,400 times during its 32-year history. The attacks have kept it offline for the equivalent of 11 years and spilled about 2 million barrels of crude.
(Seeking Alpha, Carl Surran, 17.Jul.2018) – Colombia’s Cano Limon-Covenas pipeline has resumed pumping oil after a 180-day stoppage due to repeated attacks by Marxist ELN rebels, according to loval military and industry sources.
Apart from bombing damage, 41 illegal valves used to steal crude were found on the pipeline, says Ecopetrol (NYSE:EC), which owns the pipeline.
While this was one of the most extensive stoppages ever for the 485-mile pipeline, activity in the Cano Limon field, operated by Occidental Petroleum (NYSE:OXY), reportedly has not been affected, as crude from the field had been transported using a smaller pipeline, which is still at risk of attack.
(Energy Analytics Institute, Ian Silverman, 12.Jul.2018) – Foreign Direct Investment (FDI) in Latin America and the Caribbean fell for a third straight year in 2017, reported the Economic Commission for Latin America and the Caribbean or CEPAL by its Spanish acronym.
(Frontera Energy Corporation, 9.Jul.2018) – Frontera Energy Corporation announced that, effective July 6, 2018, it has terminated its agreement to purchase 36.36% of Pacific Midstream Limited (PML).
Frontera elected to terminate its share sale agreement with the International Finance Corporation (IFC) and related funds to purchase the IFC’s 36.36% stake in PML, which had an acquisition price of $225 million. As a result of the termination, the company will be required to pay the IFC a $5 million break fee.
With the termination of the Share Sale Agreement, Frontera will continue to be a 63.64% shareholder in PML, with the IFC holding the remaining 36.36% interest. PML currently holds interests in Oleoducto Bicentenario de Colombia S.A.S (43% ownership) and Oleoducto de los Llanos Orientales S.A (35% ownership).
Frontera does not expect this transaction to have any impact on previously disclosed 2018 guidance metrics.
(Frontera Energy Corporation, 9.Jul.2018) – Frontera Energy Corporation intends to implement a normal course issuer bid (NCIB) for its common shares.
The NCIB will be made in accordance with the policies of the Toronto Stock Exchange (TSX) and the commencement of purchases under the NCIB is subject to approval of the TSX.
Under the NCIB, Frontera intends to purchase, during a 12 month period, up to 3,543,270 Common Shares, representing approximately 3.5% of the Company’s 100,011,664 issued and outstanding Common Shares as at July 9, 2018.
In connection with its NCIB, Frontera also intends to enter into an automatic share purchase plan with a designated broker to facilitate the purchase of Common Shares under the NCIB at times when Frontera would ordinarily not be permitted to purchase its Common Shares due to regulatory restrictions or self-imposed blackout periods. Frontera self-imposes regular blackouts during the period commencing 15 days prior to the end of each fiscal quarter (and 30 days prior to the end of each fiscal year) and ending at the opening of trading on the first business day following public release of its financial results for such periods. Pursuant to the Plan, before entering a blackout period, Frontera may, but is not required to, instruct the designated broker to make purchases under the NCIB based on parameters established by Frontera. Such purchases will be determined by the designated broker based on Frontera’s parameters in accordance with the rules of the TSX, applicable securities laws and the terms of the Plan.
Frontera believes that, from time to time, the market price of its Common Shares may not fully reflect the underlying value of its business and future prospects and financial position. In such circumstances, Frontera may purchase for cancellation outstanding Common Shares, thereby benefitting all shareholders by increasing the underlying value of the remaining Common Shares.
The average daily trading volume of Frontera’s Common Shares was 56,920 Common Shares over the period between January 1, 2018 and June 30, 2018. Consequently, under TSX rules, Frontera would be allowed under its NCIB to purchase daily, through the facilities of the TSX or alternative trading systems, if eligible, a maximum of 14,230 Common Shares representing 25 per cent of the average daily trading volume, as calculated per the TSX rules. In addition, Frontera would be able to make, once per week, a block purchase of Common Shares not directly or indirectly owned by insiders of Frontera, in accordance with TSX rules.
(Energy Analytics Institute, Piero Stewart, 6.Jul.2018) – Colombia’s state oil company Ecopetrol will prepay the entire syndicated loan it entered into in 2013 with local banks.
The loan was scheduled to be amortized up to 2025, announced Ecopetrol in an official statement.
As stipulated in the loan agreement, Ecopetrol can at any time pay off all the principal voluntarily, with no penalty whatsoever, subject to at least 30 calendar days’ advance notice to the lenders. Pursuant thereto, the prepayment will be made August 6, 2018 in the total amount of COP$1,430,333,333,333, which includes principal and interest.
(Energy Analytics Institute, Piero Stewart, 5.Jul.2018) – A find at the Búfalo-1 well confirmed the presence of oil in the Valle Medio del Magdalena, located near the town of Guaduas, Department of Cundinamarca.
The well is the first discovery in the VMM32 Exploration Contract and is located very close to Ecopetrol’s transport infrastructure, which could facilitate its commercial production stage, the company announced in an official statement
The finding recorded a depth of 1,153 meters, in the Middle Magdalena Valley basin, where the presence of dry gas and light crudes was evident in the Grupo Honda.
Ecopetrol holds a 51% interest in the Bufalo-1 well and is the operator. Its partner, CPVEN E&P Corp, holds the remaining 49% interest.
(Energy Analytics Institute, Ian Silverman, 30.Jun.2018) – Ecopetrol announced an oil spill of 125 barrels into the Magdalena River.
The spill occurred while repair activities were being conducted to an underwater pipeline that transports crude from the auxiliary station of the municipality of Cantagallo (Bolívar) to the Isla 6 station located in the town of Puerto Wilches (Santander). The incident, which occurred on June 13, 2018, caused oil to spill into the Magdalena River, reported the daily newspaper El Tiempo.
The estimates, of the barrel amounts, were made utilizing hydraulic simulation computer tools, data about the length and altitude of the pipeline, pressure, the observed failure area of the pipeline, fluid characteristics, water cut of the transported fluid, the time at which the event started, as well as filling volume during commissioning.
(Energy Analytics Institute, Ian Silverman, 28.Jun.2018) – The rating agency affirmed the investment rating for Ecopetrol, S.A.
Standard & Poor’s kept Ecopetrol’s long-term international rating at BBB-, with stable outlook, and stand-alone credit rating at bb+, reported Ecopetrol in an official statement.
In a recent report, the agency highlighted Ecopetrol’s solid financial results, with strengthened credit metrics, thanks to the capital discipline and efficiencies it has implemented, according to Ecopetrol. The rating agency noted the positive performance of the downstream and midstream segments, emphasizing the Cartagena refinery’s operating results during its stabilization stage. S&P also recognized Ecopetrol’s focus on increasing reserves, with the positive results posted on the 2017 balance sheet.
(Energy Analytics Institute, Ian Silverman, 28.Jun.2018) – Colombia’s state oil company has filed a collective labor agreement claim with the Ministry of Labor.
As prescribed by law, signatories of collective labor agreements are authorized to state their intentions to amend them through a claim and, if petitions are filed by the unions, the company, in this case Ecopetrol, and the union organizations would have to initiate negotiations for a new collective labor agreement, reported the company in an official statement.
The collective labor agreement between Ecopetrol and its direct employees is for a four (4) year period that began in 2014 and expires on June 30, 2018. Therefore, as explained in the paragraph above, the purpose of the claim filed by Ecopetrol is to state its intention to modify certain provisions of the agreement, consistent with the company’s growth and future prospects.
(Renews, 26.Jun.2018) – The Colombian government will next month publish the initial heads of terms for the South American country’s first ever auction for renewables other than large hydro.
Energy regulator CREG and mining and energy planning unit UPME are finalising rules and regulations ahead of the auction slated to take place by the year-end.
Deputy head of mission at the Colombian Embassy to the UK German Espejo said more than 300 projects across onshore wind, solar, biomass and small hydro have registered to participate in the initiative.
Of those projects, around 215 with a combined capacity of 1.2GW had been certified as viable by UPME, he added at the Canning House Latin America renewables conference in London.
European participants are set to include Paris-based outfit Voltalia, which is developing three wind farms rated between 50MW and 200MW in the windy Caribbean region of La Guajira.
The developer said there was limited information about the possible market design of the auction, which is expected to back at least 1GW across all technologies.
CREG has previously announced four options for incentivising renewables in its wholesale market, including a green premium added to the spot price or a sealed bid auction similar to the UK’s Contracts for Difference regime.
Renewables trade association SER Colombia has proposed auctions offering fixed priced, 20-year contracts with a centralised buyer.
Solar, wind and biomass comprise less than 5% of Colombia’s 17GW installed renewables capacity. Large hydro dominates, but is suffering from reliability problems due to dwindling water levels.
In a further effort to boost its nascent clean power sector, Bogota is offering 50% annual reduction of taxable income for the first five years of investment in renewables projects.
The country has also introduced exemptions of import duties and VAT plus accelerated depreciation for accounting purposes on equipment and machinery for use in renewables.
(Energy Analytics Institute, Ian Silverman, 25.Jun.2018) – The Canadian company plans to use majority of proceeds to repurchase notes due in 2021.
Frontera Energy Corporation completed the offering of $350 million in senior unsecured notes due 2023 at a coupon rate of 9.70% pursuant to Rule 144A and Regulation S of the U.S. Securities Act of 1933, as amended, the company announced in an official statement.
Certain proceeds from the offering were used to repurchase, at a premium, the company’s $250 million 10.0% senior secured notes due 2021 pursuant to a tender offer. The remaining proceeds will be used for general corporate purposes.
(Energy Analytics Institute, Piero Stewart 22.Jun.2018) – Canada’s Frontera Energy Corporation successfully priced an offering of $350 million.
The offering was comprised of senior unsecured notes due 2023 at a coupon rate of 9.70% pursuant to Rule 144A and Regulation S of the U.S. Securities Act of 1933, as amended, with closing expected to occur on or about June 25, 2018. There is no guarantee issuance and sale of the notes will be consummated, announced Frontera in an official statement on its website.
Frontera, a public company, has operations focused in Latin America that consist of portfolio of assets with interests in more than 30 exploration and production blocks in Colombia and Peru.
Proceeds from the offering will be used for the following purposes: 1) to repurchase, at a premium, the company’s $250 million 10% senior secured notes due 2021 pursuant to a tender offer, and 2) for general corporate purposes.
The Notes have been assigned a rating of BB-(EXP) by S&P Global Ratings and B+(EXP)/RR4 by Fitch Ratings.
(Energy Analytics Institute, Aaron Simonsky, 22.Jun.2018) – Colombia boosted the number of exploration wells drilled by 77% during the most recent seven years compared to the earlier seven.
Colombia drilled 697 exploration wells during the seven-year period 2010-2017, representing 303 more wells when compared to the 394 exploration wells drilled during the seven-year period 2002-2009, Colombia’s National Hydrocarbon Agency (ANH by its Spanish acronym) reported in a Twitter post.
Additionally, the ANH reported that a maximum 131 exploration wells were drilled in 2012 during the 2010-2017 time frame compared to a maximum of just 99 exploration wells that were drilling in 2008 during the 2002-2009 time frame.
(Energy Analytics Institute, Ian Silverman, 22.Jun.2018) – Frontera Energy Corporation aims to lower certain costs in Colombia.
The Canadian company continues with efforts to reduce its transportation costs, including those associated to the Bicentenario pipeline, which has been continuously affected by attacks directed at the Caño Limon pipeline, the company announced in an official statement.
Frontera expects talks involving Colombia’s state owned or majority state owned companies (such as Bicentenario) will continue past the second quarter of 2018 due to the ongoing presidential elections.
(Energy Analytics Institute, Aaron Simonsky, 22.Jun.2018) – Wind capacity in Colombia will add 1,360 megawatts of generation capacity to its energy grid.
The South American country’s Mines and Energy Ministry reported in a Twitter post that the energy source would be connected to the National Interconnected System through specialized connections, without providing further details.
(PentaNova Energy Corp., 21.Jun.2018) – PentaNova Energy Corp. announced signing of the SN-9 Farm Out Agreement with Panacol Oil & Gas, a wholly owned subsidiary of LATAM Oil & Gas.
“The SN-9 block has all the hallmarks of being an exceptional core asset for PentaNova being adjacent to the prolific Canacol Energy Ltd. gas producing assets. By entering into this Agreement with Panacol, PentaNova is in a position to execute the exploration program required to confirm the gas potential of the block,” said PentaNova President and CEO Ralph Gillcrist.
Under the terms of the Agreement, Panacol will fully fund the company’s commitments during the first phase of the SN-9 Exploration and Production Contract for the amount of $22.29 million, which will give Panacol the right to earn up to a 40% economic beneficial interest in the SN-9 Block from the company’s 80% economic beneficial interest. Assignment of working interests for both parties is subject to approval from the National Hydrocarbon Agency of Colombia.
The Agreement is expected to close within the next 30 days during which time Panacol will be required to place $3 million in escrow to fund near-term activities. In addition, Panacol is required to provide a standby letter of credit for $3.0 million to guarantee further payments into the escrow account and pay approximately $650,000 in past costs. Under the terms of the Agreement, Panacol will recover 50% of the funds invested from 70% of the proceeds of the company’s net production.
“We look forward to leveraging the abundant experience of the Panacol team to complement the PentaNova team and accelerating our operational activities,” said Gillcrist.
The 313,638 acre SN-9 block is located in the northern province of Cordoba, in the Lower Magdalena Basin of Colombia directly adjacent to, and west of, the major gas producing area operated by Canacol. Canacol produces 88% of its 106 million cubic feet per day (MMscf/d) gas production from this area and reported aggressive expansion plans in their Q1 2018 investor update on May 16, 2018, reflected in their 1Q 2018 Conference Call Transcript published on the Canacol website (www.Canacolenergy.com). PentaNova believes that the gas play being developed by Canacol extends into the south eastern portion of the SN-9 block. The SN-9 block has over 736 km of 2D seismic lines and one discovery well, Hechizo-1, drilled in 1992 that tested a combined rate of 10.3 MMscfd, confirming the likely extension of the gas play from Canacol’s area into SN-9. Given the proximity to the gas infrastructure that supplies the north of Colombia, the south eastern structures of the SN-9 block will be the focus of immediate activities for the Company.
SN-9 Future Planned Activities
The company anticipates completing the prior consultation process required to acquire seismic in the block by the end of June 2018 and plans to issue tenders for the acquisition of 140km2 of 3D seismic, and related services, over the next two weeks. The company expects to acquire the 3D seismic in October and November of 2018.
The prior consultation and permitting process required for drilling on the block is expected to start in July 2018, as soon as the prior consultation for seismic is complete. On completion of this process, anticipated for mid 2019, civil works will be initiated with a view to spudding the first exploration well midyear 2019.
(Oilprice.com, Tsvetana Paraskova, 20.Jun.2018) – While oil industry analysts and market participants are watching Venezuela closely for clues about how low its oil production will go, several other countries in Latin America are holding key elections this year, elections that will no doubt shape the countries’ short and medium-term oil policies. These developments could spell trouble for oil supply and oil investment in South America’s biggest crude-producing nations.
A populist leftist candidate pledging to undo energy reforms is widely expected to win Mexico’s presidential election in two weeks. There has been recent turmoil in Brazil’s fuel sector policies ahead of a wide-open presidential race for the October elections. A newly elected president in Colombia is vowing to amend a historic peace deal with the FARC rebels.
All these events add uncertainties to how politics will influence Latin American countries’ oil policies and investment climate for foreign oil companies, Paul Ruiz and Jena Merl write for The Fuse.
In Colombia, a conservative political newcomer, Iván Duque, won the presidential election this past weekend in the traditionally conservative country. The new president, however, has pledged to revise the 2016 deal with the Revolutionary Armed Forces of Colombia (FARC) rebels that put an end to 50 years of armed conflict. Duque wants to re-write the deal that guaranteed the rebels seats in Congress and allowed them to run in elections.
The new president, like the outgoing president Juan Manuel Santos, will have to face another rebel group, the National Liberation Army (ELN)—a Marxist guerrilla group that sabotages oil industry facilities to protest against foreign companies operating in Colombia. In January this year, Colombia suspended talks with ELN after bombings killed police officers. ELN has repeatedly attacked the second-largest oil pipeline in Colombia, Cano Limon-Covenas, causing oil spills and shutdowns.
Mexico is holding a presidential election on July 1, and a few weeks ahead of the vote, all polls point to populist leftist candidate Andrés Manuel López Obrador having a comfortable lead over other candidates. López Obrador pledges to roll back the landmark 2013 energy reform of outgoing president Enrique Peña Nieto, who opened Mexico’s oil sector to private investment for the first time in seven decades. The jury is still out as to whether López Obrador will backtrack entirely on the oil reforms, but uncertainties remain regarding the investment environment in the country—at least for this year.
Brazil is holding elections in October and the race is still wide open.
But in recent weeks, the country came to an economic standstill due to widespread truckers’ strikes over high fuel prices. President Michel Temer announced subsidies on diesel at the end of May, freezing prices for 60 days.
The recent turmoil in the country’s oil industry and renewed anxiety over political meddling in the energy sector add an uncertainty ahead of the election later this year. Pedro Parente, chief executive at state-run oil company Petrobras, resigned on June 1, after the strikes forced the government to cut diesel prices and after oil workers demanded that Brazil end the one-year-old policy to allow fuel prices be dictated by the market and international crude oil benchmarks.
Yet, some of the world’s biggest oil companies—including Exxon, Chevron, Shell, BP, and Equinor—bid aggressively in Brazil’s latest offshore bid round on June 7, snapping up acreage in three blocks in the coveted pre-salt layer.
Nevertheless, uncertainty over how Brazil will handle oil sector policies until and immediately after the October elections has increased.
Brazil is still expected to be one of the largest contributors to non-OPEC oil supply growth in the coming years. According to the International Energy Agency’s (IEA) Oil 2018 outlook from March, oil production growth from the United States, Brazil, Canada, and Norway “can keep the world well supplied, more than meeting global oil demand growth through 2020.”
According to OPEC’s latest Monthly Oil Market Report, non-OPEC oil supply in the second half of this year is expected to increase by 2.0 million bpd year on year, with the United States leading the pack, contributing 1.4 million bpd to growth, followed by Canada and Brazil.
While uncertainties mount in the political shifts and oil policy choices in other Latin American countries, there’s only one uncertainty left for Venezuela—how fast production from the collapsing oil industry will sink to as low as 1 million bpd. Some analysts reckon the plunge to 1 million bpd is imminent.
(Energy Analytics Institute, Ian Silverman, 20.Jun.2018) – Colombia’s state oil company Ecopetrol S.A. announced it will prepay all loans entered into in 2013 with international banks and guaranteed by the US Export-Import Bank, which had been subject to a payment schedule to 2023.
The loan agreements allow Ecopetrol to prepay without penalty all principal on the interest payment dates, which are scheduled for July 6 and 25, 2018. Total principal plus accrued interest owed is $155,979,564, the company announced in an official statement.
Ecopetrol said it is able to make this prepayment due to its cash position of COP 16.6 billion as of the first quarter of 2018. The Colombian company expects this cash position will remain strong and thus allow it to better confront crude price volatility scenarios and be prepared to seize opportunities that might arise for inorganic growth.
(Finance Colombia, Jared Wade, 14.Jun.2018) –Colombia produced an average of 865,987 barrels of oil per day in May, an uptick of 1.6% over May 2017 according to government figures.
This level also represents a 0.1% increase from April, and the slight increase marks the third straight month of rising production, according to the Ministry of Mines and Energy.
After five months, the annual average for the country now stands at 854,190 barrels of oil per day. This is almost exactly in line with the 2017 average of 854,121 barrels of oil per day yet still below the 885,000-barrel daily average of 2016.
The annual figure, however, still exceeds the Ministry of Mines’ previously released “medium-term” estimate of 840,000 barrels of oil per day.
The vast majority of the oil in Colombia is produced by state-controlled oil company Ecopetrol. The Bogotá-based company has set a goal of 725,000 barrels of petroleum-equivalent per day for 2018 and expects to drill at least 620 development wells and 12 exploration wells during the year to help replace falling reserves.
Frontera Energy, formerly known as Pacific Rubiales, produced an average of 52,195 barrels of oil per day in Colombia the first quarter of 2018. This was a slight decrease from the 56,593 it produced in the country compared to the first quarter of 2017.
(Energy Analytics Institute, Jared Yamin, 15.Jun.2018) – Colombia’s National Hydrocarbon Agency (ANH by its Spanish acronym) approved the new oil and gas exploration and exploitation contract model for offshore areas.
The contract aims to entice large petroleum companies to make favorable investments in Colombia — especially those made in the most vulnerable regions — through investments and work programs that benefit communities, royalties, economic rights and via a percentage participation in production that favors the state.
“This is great news for the country, given that a good contractual scheme is a fundamental element when it comes to a petroleum company defining its investments. Today, we are more competitive in the proposal to attract large investments,” announced the agency, citing ANH President Orlando Velandia Sepúlveda.“We look for companies with experience, the best technology and a robust financial structure,” he added.
This contractual model, when compared to the previous, represents a great advance in all aspects, and creates a positive environment for companies and investments to remain in Colombia, said Sepúlveda.
The new contractual model applies to operators executing technical evaluation contracts, and companies that have rights to convert contracts into exploration and production contracts, as well as the companies selected in future competitive processes in offshore areas.
(Energy Analytics Institute, Ian Silverman, 12.Jun.2018) – Canada’s Frontera Energy Corporation continues its active drilling program in Colombia.
The company had six (6) drilling rigs operating continuously in the first two months of the second quarter of 2018, of which three (3) were active in the Quifa heavy oil area, two (2) on the light oil-focused Guatiquia block, and one (1) drilling the high impact Acorazado-1 well in the Llanos 25 block, the company announced in an official statement.
Frontera commenced drilling the Alligator-3 development well on the Guatiquia block on May 10, 2018. On April 27, 2018, the well reached a total depth of 12,416 feet (12,189 feet TVD), encountering 31.5 feet of net pay in the Lower Sand-1A formation. The well was completed in the Lower Sand-1A formation with an electrical submersible pump.
The Lower Sand-1A formation has been flow tested for approximately 13 days at an average rate of 1,800 barrels per day (b/d) of 18.2 degree API oil with an average water cut of 40% at stabilized bottomhole flowing pressure with an approximate 34% drawdown. The well has produced a total of 27,500 barrels of oil since start of production.
At the Guatiquia block, Frontera continues to have exploration success. During the quarter, the company completed testing the Coralillo-1 well in two zones. On May 10, 2018, the company reported the Lower Sand-1A formation was flow tested for approximately 11 days at an average rate of 1,050 b/d of 15.3 degree API oil with an average water cut of 1% at stabilized bottomhole flowing pressure with a 60% drawdown. Subsequently, the well was shut-in for a 5-day pressure buildup test. Results confirmed positive reservoir properties, low formation damage and no depletion during the testing period.
Additionally, on May 18, 2018, the company began testing the well in the Guadalupe formation. In this formation, the well was initially flow tested for 10 days at an average rate of 800 b/d of 17.1 degree API oil with an average water cut of 1.1% at stabilized bottomhole flowing pressure with an approximate 38% drawdown. Since discovery, the Guadalupe formation has produced a total of 8,140 barrels of oil. Following the initial production test in the Guadalupe formation, the well was shut-in for a pressure buildup test. Given the positive results, on May 22, 2018, the company requested permission from the Agencia Nacional de Hidrocarburos (ANH by its Spanish acronym) to conduct long term testing for the well.
Frontera has drilled nine (9) horizontal oil development wells to date at the Quifa block during the second quarter of 2018. In addition, the company commenced construction of facilities to expand its water handling capabilities on the block, which is expected to be operational during the fourth quarter of 2018. The company plans to boost the number of active drilling rigs in the Quifa area from three (3) to five (5) in mid-June. As the company adds water handling capacity during the third quarter it expects the number of active drilling rigs to increase to six (6).
(Energy Analytics Institute, Ian Silverman, 12.Jun.2018) – Frontera Energy Corporation entered into an unsecured loan agreement with Puerto Bahia.
The agreement is pursuant to which Frontera has agreed to loan an aggregate amount of $30.46 million to Puerto Bahia, subject to certain terms and conditions. The loan bears an annual interest rate of 14% and will mature on May 31, 2019.
Puerto Bahia is a private company organized and existing under the laws of Colombia that is responsible for the design, construction, ownership, operation and maintenance of a large-scale multi-purpose port facility located in the Cartagena Bay in Colombia.
On October 4, 2013, Pacinfra Holding Ltd., a wholly-owned subsidiary of the Company, Pacific Infrastructure Inc., an entity in which Frontera indirectly owns a 39.22% interest, Puerto Bahia, a wholly-owned subsidiary of Pacific Infrastructure, and Wilmington Trust, National Association (as administrative agent) entered into an equity contribution agreement pursuant to which Pacinfra Holding and Pacific Infrastructure agreed to both jointly and severally cause equity or debt contributions to be made to Puerto Bahia up to an aggregate amount of $130 million in circumstances where it is determined that there were certain deficiencies related to operation and maintenance of the a multi-purpose port facility developed by Puerto Bahia and Puerto Bahia’s ability to make payments towards its bank debt obligations.
In accordance with the equity contribution agreement, a deficiency notice to Pacinfra Holding was issued requesting the company fund, or cause to be funded, a total amount of $30.46 million to Puerto Bahia, due May 31, 2018. The loan agreement was entered into to satisfy this funding commitment.
(Energy Analytics Institute, Ian Silverman, 12.Jun.2018) – The offer will consist of a two-for-one share split of the company’s issued and outstanding common shares.
The record date of the Share Split will be June 21, 2018 at the close of business, announced Frontera Energy Corporation in an official statement. The company’s transfer agent, Computershare Investor Services Inc., will send shareholders of record one additional common share for every share held on June 26, 2018. No action is required to be taken by the shareholders.
The Toronto Stock Exchange has determined to implement due bill trading in connection with the Share Split. Anyone purchasing common shares during the period commencing June 20, 2018 and ending on June 26, 2018 inclusively shall receive a due bill. Frontera’s common shares will commence trading on an ex-distribution basis on June 27, 2018 and the due bill redemption date will be June 28, 2018.
DIRECT REGISTRATION SYSTEM
Frontera announced use of the direct registration system or DRS to electronically register common shares issued pursuant to the Share Split. Computershare will send out DRS advice statements to registered shareholders, indicating the number of additional common shares that they are receiving as a result of the Share Split. In addition, Computershare will electronically issue the appropriate number of common shares to CDS Clearing and Depositary Services Inc. and The Depository Trust Company for distribution to the non-registered shareholders of the Company. Beneficial shareholders who hold their common shares in an account with their investment dealer or other intermediary will have their accounts automatically updated to reflect the Share Split in accordance with the applicable brokerage account providers’ usual procedures.
(Energy Analytics Institute, Jared Yamin, 8.Jun.2018) – Colombia’s National Hydrocarbon Agency (ANH by its Spanish acronym) says it has no plans to carry out fracking activities in Boyacá department.
The ANH, which is studying the subsoil in the area, plans to utilize very low impact geophysical acquisition tools, such as seismic vibros and magnetotelluric, the agency announced in an official statement on its website.
In the statement, the agency emphasized that it maintains dialogue and communication with neighboring communities in order to overcome any perceived obstacles or inconveniences, and continues to hold meetings with local and departmental authorities to evaluate the potential impact of any of its projects.
(Energy Analytics Institute, Jared Yamin, 29.May.2018) ‐- Spain’s Gas Natural Fenosa is finally exiting Colombia.
The company sold 15.46 million shares, representing the remaining 41.89% interest in gas distributor Gas Natural ESP, to Canada’s Brookfield Asset Management, which had officially launched a takeover bid, announced the daily La Republica, citing a report from the Colombian Stock Exchange (BVC by is Spanish acronym).
The total value of the transaction is valued at COL$1.124 billion, according to the daily. With the closing of this deal, Brookfield, which already held a 59.1% interest in Gas Natural Fenosa, will be the outright owner of the company.
(Energy Analytics Institute, Jared Yamin, 27.May.2018) ‐- Thefts of elements from producing wells coupled with infrastructure sabotage at the Tibú field in the municipality by the same name in Northern Santander continue to harm the environment and neighboring communities.
To date in 2018, Colombia’s state oil company Ecopetrol has registered 428 offenses, of which 246 include illegal valve connections that have led to the loss of an estimated 30,447 barrels of petroleum, announced the company in a post on its website. This compares to 202 illegal connections detected in the same period in 2017.
In terms of the environment, an estimated 98 incidents have been reported in 2018, which affected more than 11,700 square meters of ground cover and 5,700 square meters of different bodies of water.
Ecopetrol announced that some 127 offenses related to the operation of 59 producing and injector wells have been detected, including thefts of equipment such as solar panels, pipes, transformers, cables, and electric systems, among other materials.
Besides the cost aspect, these actions continue to produce negative environmental impacts and/or increase the possibility of incidents that could result in injuries or loss of life to people in/and around the area, Ecopetrol concluded.
(Energy Analytics Institute, Ian Silverman, 26.May.2018) – Canacol Energy Ltd., the exploration and production company with operations focused in Colombia, announced its Annual General Meeting of Shareholders will be held on July 3, 2018, in Calgary, Canada.
Canacol’s common stock trades on the Toronto Stock Exchange, the OTCQX in the United States of America, and the Colombia Stock Exchange under ticker symbol CNE, CNNEF, and CNE.C, respectively.
(Energy Analytics Institute, Jared Yamin, 25.May.2018) – The International Monetary Fund (IMF) approved a new two-year flexible credit line with Colombia for nearly $11.4 billion. The new credit replaces the former one, which was approved in 2016, reported the daily newspaper El Espectador.
(Energy Analytics Institute, Ian Silverman, 24.May.2018) – Ecopetrol and Talisman Colombia Oil & Gas (TCOG), a company of Repsol group, plan to initiate drilling of new production wells in late May 2018 at the Akacías field, located in the Acacías municipality in Meta.
Activities slated for the Akacías field development stage in 2018 consist of drilling a total of 19 wells, Ecopetrol announced in an official statement.
Currently, 9 active wells at the Akacías field produce an average 6,300 barrels per day of petroleum.
(Energy Analytics Institute, Aaron Simonsky, 24.May.2018) – Canacol Energy Ltd. announced it has mobilized a rig to drill the Borojo 1 exploration well.
Located on the 100% operated Esperanza E&E contract, the Borojo 1 well will target gas-bearing reservoirs located in the Cienaga de Oro sandstones, announced Canacol in a company press release. The well will spud in the first week of June 2018 and take approximately 4 weeks to drill and complete. And similar to Breva 1, the Borojo well will be perforated and tested with a workover rig approximately 1 week after the drilling rig moves off to drill the Canahuate Este exploration well.
(Energy Analytics Institute, Ian Silverman, 24.May.2018) – Colombia’s state oil company Ecopetrol announced plans to make social investments of 1.3 billion Colombian pesos in Meta department, where the company and its partner Talisman Colombia Oil & Gas (TCOG) operate in the Acacías municipality.
Investments will be directed to the immediate area of influence and include activities at La Esmeralda, Loma de Tigre, Montelíbano, in Acacías and Santa Ana in Guamal, the state entity reported in an official statement.
Other related projects to receive assistance include: programs related to musical education and sports; improving education centers; boosting productive projects; finding solutions for potable water in villages; improving sports and health programs; among others.
(Energy Analytics Institute, Aaron Simonsky, 24.May.2018) – Energy Analytics Institute, formerly LatinPetroleum Inc., continues to promote its “Energy Education Initiative” in the Americas, also known as “NRG ED.”
NRG ED is structured to work with K-12 schools, community colleges, four-year colleges and universities, workforce training programs, communities and businesses, and aims to promote reduction of non-renewable energy usage in favor of renewable energies. However, the core of the initiative is education, without which the NRG ED initiative would not be.
“At its core the initiative is really focused on education,” said Chad Archey, Editor-in-Chief at Energy Analytics Institute from Atlanta, Georgia.
EAI views basic education as most important in the overall learning process and also promotes educational initiatives and research from grade school to the professional level related to the energy sector. EAI aims to foment constructive dialogue regarding energy usage as well as ways to reduce the carbon footprint left by non-renewable energy resources through the following: 1) educational consultancy, 2) development and distribution of educational and training materials, and 3) promotion of debate and discussion regarding renewable energy alternatives.
Energy Analytics Institute (EAI), formerly LatinPetroleum Inc. (dba LatinPetroleum.com), is a Houston-based independent company focused on producing non-biased news, updates and special reports for investors interested in the Latin America and Caribbean petroleum sectors.
(Energy Analytics Institute, Jared Yamin, 24.May.2018) – Canacol Energy Ltd. announced results of the Breva 1 natural gas exploration well located on its 100% operated VIM 21 block in the Lower Magdalena Valley Basin of Colombia.
The Breva 1 exploration well is located approximately 1.5 kilometers north of the Toronja 1 Porquero gas discovery announced by Canacol on June 27, 2017. Toronja 1 encountered approximately 14 feet true vertical depth (TVD) of net gas pay within the Middle Porquero sandstone reservoir, and tested at a rate of 24.4 million standard cubic feet per day (MMscf/d) of dry gas with no water. Nelson 6, Canacol’s first discovery in the shallow Porquero sandstone play, encountered 39 ft TVD of net gas pay and tested 23 MMscf/d of gas.
Using the Pioneer 302 drilling rig, Breva 1 spud on April 29, 2018, and reached a total depth of 7,560 feet measured depth in 13 days. The well encountered 29 ft TVD of net gas pay with average porosity of 27% within the primary Porquero sandstone reservoir target. The well has been completed and cased, and Canacol is currently mobilizing a work over rig to perforate and production test the well. The work over rig is anticipated to arrive in 2 weeks, and the testing program is anticipated to take approximately 1 week to complete.
After Nelson 6 and Toronja 1, Breva 1 represents the third consecutive discovery in the emerging and important new Porquero play type in Canacol’s exploration portfolio. By means of the application of the AVO methodology proven to be so successful locating gas‐charged reservoir sandstones in the Cienaga de Oro play type, the company has demonstrated the same relationship between gas and reservoir sandstones in the Porquero Formation. Going forward, the successful outcome of the three exploration wells in the Porquero sets up at least five exploration and appraisal locations on the VIM 21 concession. It also provides critical technical information regarding the AVO methodology enabling Canacol’s exploration team to investigate the potential for the Porquero play type across the company’s expansive acreage position (1.1 mm net acres) in the Lower Magdalena Valley Basin.
(Reuters, 23.May.2018) – Mexican energy investment firm Vista Oil & Gas will tie up with Jaguar Exploracion y Produccion on three onshore projects, the company said on Tuesday, acquiring 50 percent stakes with an initial payment of nearly $27.5 million.
Vista will pay Monterrey-based Jaguar a further $10 million to compensate the firm for past investments in the projects, or so-called carry costs, the firm said in a statement.
The three onshore projects were won at auctions last July by Jaguar, an upstart oil firm owned by Mexico’s Grupo Topaz, and are located in the Gulf coast states of Tabasco and Veracruz.
Two of the blocks will be operated by Vista, while the other will be run by Jaguar, in what Vista described as Mexico’s first joint venture between two private oil firms.
The joint venture between the two must still be approved by the National Hydrocarbons Commission, the Mexican oil regulator that supervises exploration and production contracts.
Last year, Vista became Mexico’s first publicly traded oil firm, four years after a landmark energy reform ended the decades-long monopoly enjoyed by state-owned Pemex.
Vista, which has targeted assets for possible acquisition in Mexico, Brazil, Colombia and Argentina, is backed by private equity firm Riverstone Capital.
(By Rodolfo Guzman, Paola Perez, Paola Carvajal, Roberto Imperatore, Arthur D. Little, 22.May 2018) – Unconventional oil production has grown these past few years despite low oil prices since 2014. Although production in the US decreased in 2015, stabilization of prices and improvements in several operational areas allowed unconventionals to maintain a relevant role in the global supply. Last year, Arthur D. Little published a viewpoint analyzing the perspectives for unconventional resources in selected Latin American countries. While our outlook for Latin American opportunities remains positive, there are new factors to consider. The key shale players have stayed strongly focused on the US, the moderate oil price recovery expectations persist, and concerns about fracking operations are increasing. Therefore, host countries, especially in Latin America, are now under greater pressure to create conditions that favor the development of these resources.
In recent years, countries such as Mexico, Colombia and Chile with potential in unconventional hydrocarbons have been evaluating their prospective resources. However, these activities have not been enough to build momentum and attract resources to speed up the de-risking process for unconventional hydrocarbons. Building momentum requires a strategy for aligning technical, regulatory, and economic conditions to boost the de-risking process of the greenfield plays prior to the take-off of massive developments. Two major forces can, in our opinion, help build momentum: national oil company leadership and/or government promotion & incentives. Besides these levers, a deeper understanding of the local conditions of the oil & gas industry is fundamental for defining the strategy and tactics for building momentum.
In our view, the development of unconventional hydrocarbons in different geographies will continue shaping the global oil and natural gas markets. Countries with high potential and interest in expanding their production, such as Mexico, Colombia, and Chile, still need to build momentum to ensure the inflow of capital investments to speed up the exploration/evaluation phases. Although there is still uncertainty regarding the feasibility of large developments, the growing demand for hydrocarbons presents an opportunity for oil companies.
As the energy industry continues evolving, trends in supply and demand could change the incentives to develop the unconventional plays (growing share of renewable, peak of oil demand, etc.). Therefore, there is a closing window of opportunity for adopting a strategy to provide the required support to oil & gas players and take advantage of unconventional developments.
Download the full report here: http://www.adlittle.com/en/BuildingMomentum
(Energy Analytics Institute, Aaron Simonsky, 21.May.2018) – Colombia’s state oil company Ecopetrol announced that it has controlled a fire at the HDT plant of the Barrancabermeja refinery.
No injuries were reported and the refinery is operating normally, according to Ecopetrol.
Ecopetrol workers brought the fire — which occurred at the fuel hydrotreating unit that is out of service for programmed maintenance — under control, according to an Ecopetrol information sheet about the incident.
No injuries were reported and the refinery is operating normally, according to Ecopetrol.
(Canacol Energy Ltd., 16.May.2018) – Canacol Energy Ltd. announced plans to divest of non-core Colombian conventional oil assets, among other management objectives for 2018.
These objectives include: 1) sell an average of 114 to 129 MMscfpd of gas and 1,700 bopd (“barrels of oil per day”), 2) execute the necessary investments in drilling, facilities, and flowlines to ensure that the productive capacity of the Corporation is greater than 230 MMscfpd by December 1, 2018, 3) execute a four well exploration and appraisal drilling program to build reserves and 4) divest the Corporation’s non‐core Colombian conventional oil assets to focus on the exploration and commercialization of our significant Colombian gas reserves and resource base.
Highlights of the capital spending program aimed at ensuring that the Corporation achieves 230 MMscfpd of gas production capability by December 2018 include: 1) the drilling of four exploration and appraisal wells and three development wells, 2) expansion of the Corporation’s gas gathering and processing facilities at Jobo, and 3) various workovers of its existing gas wells. The Corporation also expects to acquire new 3D seismic data on its VIM‐5 contract to continue building its gas exploration drilling portfolio. Approximately 97% of the originally announced $80 million budget for 2018 is dedicated to spending on the Corporation’s gas assets, with the remainder on its oil assets, and will be fully funded from existing cash and cash flows.
Subsequent to March 31, 2018, the Corporation completed a private offering of senior unsecured notes in the aggregate principal amount of $320 million and has used the net proceeds to fully repay the outstanding amounts borrowed under its existing credit facility in the amount of $305 million plus accrued interest.
By replacing the credit facility of $305 million, the Corporation benefits from: (i) replacing the current term loan that bears an interest rate of fluctuating three month Libor +5.5% (which currently totals approximately 8%, as the three month Libor has been increasing materially during the last 14 months), to a fixed coupon of 7.25%, which provides both a reduction and certainty of debt expenses in an extremely volatile interest rate environment; (ii) deferring the quarterly $23.5 million amortization of the existing credit facility beginning in March 2019, for a bullet maturity in May 2025; (iii) an administratively less burdensome note indenture that will not require collateral or quarterly certification of maintenance covenants (only incurrence‐based covenants); (iv) no cash required to be held in a debt service reserve account as is required under the current credit facility (these amounts are scheduled to total approximately $25 million later in 2018 under the existing credit facility); and (v) achieving certain other operational and financial flexibilities, including the ability for the Corporation to pay a dividend.
With respect to the drilling program, the Corporation successfully drilled and completed the Pandereta‐3 and Chirimia‐1 appraisal wells as gas producers, with the Gaiteros‐1 exploration well resulting in a dry hole. The remainder of the drilling program includes three exploration wells and one development well. The first of the three remaining exploration wells, Breva‐1, was spud in late April 2018 and is currently being cased and completed as a Porquero gas discovery. The remaining exploration wells include the Borojo‐1 well, which will spud in early June 2018, followed immediately by the Canahuate‐East well. The final development well in the 2018 drilling program is Canahuate‐West, which will be drilled following the Canahuate‐East well.
As previously announced, forecast realized contractual gas and oil sales, which include contractual gas downtime for 2018, are anticipated to average between 21,700 and 24,300 boepd, which include 114 and 129 MMscfpd of gas, respectively, and approximately 1,700 bopd of annualized oil production. Upon a successful sale of the Colombian oil assets, this annualized oil production forecast would be revised accordingly. The base range for gas production assumes that the Promigas S.A. expansion, which will add 100 MMscfpd of transportation capacity between the Corporation’s gas processing facilities located at Jobo and the markets of Cartagena and Barranquilla, is delayed and does not materialize as of December 1, 2018. The upper range for gas production assumes that the Promigas S.A. expansion is completed on December 1, 2018, as currently planned, and that the Corporation sells additional natural gas in the interruptible market throughout 2018.
Based on the Corporation’s current portfolio of 2018 gas contracts, the average sales price, net of transportation costs where applicable, is approximately $4.75/Mcf. The Corporation has awarded a contract to build and install a new gas processing module at its Jobo gas facility to process an additional 100 MMscfpd of gas, which will raise the gas treating capability of the Jobo facility to 300 MMscfpd by December 2018.
The Corporation will purchase and operate the new gas processing module with funds sourced from existing cash and cash flows including the release of funds from the prior credit facility’s debt service reserve account, which is no longer required under the new senior unsecured notes.
(Canacol Energy Ltd., 15.May.2018) – Canacol Energy Ltd. reported its financial and operating results for the three months ended March 31, 2018.
“The first quarter of 2018 was an important milestone for Canacol, as it represents the first full quarter where the Corporation had access to the newly completed Sabanas flowline, and hence yet another step change in our natural gas production levels,” said Canacol President and CEO Charle Gamba. “We continue to diligently work towards our next goal of 230 MMscfpd by December 1, 2018, for which the Corporation is fully funded to achieve.”
Highlights for the three months ended March 31, 2018. Dollar amounts are expressed in United States dollars, except as otherwise noted. (Production is stated as working‐interest before royalties)
Financial and operational highlights of the Corporation include:
— Average production volumes increased 23% to 20,955 boepd for the three months ended March 31, 2018 compared to 16,992 boepd for the same period in 2017. The increase is primarily due to increase in gas production as a result of the additional sales related to the completion of the Sabanas pipeline, offset by production declines at LLA‐23 and the sale of the Ecuador Incremental Production Contract (the “Ecuador IPC”) (see full discussion in MD&A) in February 2018.
— Realized contractual sales volumes increased 17% to 21,115 boepd for the three months ended March 31, 2018 compared to 18,043 boepd for the same period in 2017. The increase is primarily due to increase in gas production as a result of the additional sales related to the completion of the Sabanas pipeline, offset by production declines at LLA‐23 and the sale of the Ecuador IPC in February 2018.
— Total petroleum and natural gas revenues for the three months ended March 31, 2018 increased 24% to $51.8 million compared to $41.6 million for same period in 2017. Adjusted petroleum and natural gas revenues, inclusive of revenues related to the Ecuador IPC, for the three months ended March 31, 2018 increased 14% to $53.7 million compared to $47 million for the same period in 2017.
— Adjusted funds from operations increased 12% to $23.5 million for the three months ended March 31, 2018 compared to $20.9 million for the same period in 2017. Adjusted funds from operations are inclusive of results from the Ecuador IPC, which totalled $2 million during the three months ended March 31, 2018 and $5 million during the three months ended March 31, 2017.
— The Corporation recorded a net income of $8.3 million for the three months ended March 31, 2018 compared to a net loss of $7.9 million for the same period in 2017.
— Net capital expenditures including acquisitions for the three months ended March 31, 2018 was $40.2 million, while adjusted capital expenditures including acquisitions, inclusive of amounts related to the Ecuador IPC, was $42.6 million. Net capital expenditures and adjusted capital expenditures included non‐cash costs of $14.1 million.
— At March 31, 2018, the Corporation had $61 million in cash and $13.3 million in restricted cash.
(Energy Analytics Institute, Aaron Simonsky, 14.May.2018) – Colombia’s natural gas reserve life ratio rose 13.6% year-over-year.
Colombia’s Mines Ministry said the South American country had boosted its natural gas reserve life ratio to 11.7 times or 11.7 years in 2017 due to rising reserves and reduced consumption. The details, provided in an official Twitter post, show the increase was up 13.6% compared to 10.3 years in 2016 and 10.5 years in 2015.
A company’s reserve life ratio is a factor of its reserves at year-end divided by that year’s production. It’s normally measured as a ratio or more commonly in years (i.e. 11.7x or 11.7 years), and is often expressed just as R/P.
(Reuters, 4.May.2018) – Ecopetrol, Colombia’s state-run oil company, said on Thursday that its first quarter net profit rose to 2.6 trillion pesos ($923.3 million), up 195 percent from the same period in 2017, thanks to improved efficiencies and higher crude prices.
The results were the best first quarter showing in four years, the company said in a regulatory filing.
Ecopetrol plans to invest between $3.5 billion and $4 billion during 2018, as it reboots production and exploration after being battered by the global fall in crude prices.
Consolidated oil and gas production in the first quarter fell to 701,000 barrels per day (bpd) because of February protests that led to blocked roads and the temporary closure of some fields, the company said.
Despite the output fall, Ecopetrol said it would not change its production goal for the year.
“We’re keeping our yearly production goal at between 715,000 and 725,000 barrels per day,” chief executive Felipe Bayon said in the statement.
Ecopetrol produced an average of 715,000 bpd in 2017.
Earnings before interest, taxes, depreciation and amortization in January to March increased by 23 percent compared with the same quarter in 2017, to 7.15 trillion pesos, the company said.
Total sales in the first quarter were up 9.5 percent compared with the same period last year, to 14.6 trillion pesos.
The company will hold a call with investors about the results on Friday.
(Energy Analytics Institute, Jared Yamin, 2.May.2018) – Colombia’s Ecopetrol published a brief update on emergency operations in Tumaco. In the area there are more than 100 workers, 9 control points (La Espriella, La Cortina, La Chorrera, El Muerto, La Brava, Pueblo Nuevo, Tangarial 1, Dos Quebrados, and Boca de Caunapí), 17 contention points and more than 1,000 meters of barrier to contain and then gather crude oil, according to an Ecopetrol graphic visual with information or info graphic published via Twitter.
Additionally, there are 6 tankers assigned to transport the gathered crude oil. In terms of attention to affected citizens in the area, Ecopetrol is providing some assistance and has distributed 45,000 liters of portable water to communities in La Espriella and Pueblo Nuevo.
(Energy Analytics Institute, Aaron Simonsky, 1.May.2018) – The United Nations Economic Commission for Latin America and the Caribbean, also known as ECLAC or CEPAL by its Spanish acronym, projects economic activity in troubled Venezuela will contract 8.5% in 2018.
Gross domestic product or (GDP) estimates for other important countries and regions follows:
(Energy Analytics Institute, Aaron Simonsky, 25.Apr.2018) — ConocoPhillips is active in Colombia in the Middle Magdalena Basin at VMM-3 and VMM-2, where it serves as operator at both blocks, the company reported in a Fact Sheet updated on its website in March 2018. A short summary of its Colombian interests follows:
— VMM-3: Partners in the block include ConocoPhillips (WI 80.0%, Operator) and CNE Oil & Gas S.A. (WI 20.0%)
In 2015, ConocoPhillips assumed operatorship of the VMM-3 Block, which extends over approximately 67,000 net acres. The block contains the Picoplata 1 Well, which was drilled in 2014 and 2015. In 2016 and 2017, ConocoPhillips conducted production testing operations at the Picoplata 1 Well and is continuing its evaluation of the block.
— VMM-2: Partners in the block include: ConocoPhillips (WI 80.0%, Operator) and Canacol Energy Colombia S.A. (WI 20.0%)
In 2017, ConocoPhillips acquired interest and operatorship of the VMM-2 Block, which extends over approximately 58,000 net acres and is contiguous to the VMM-3 Block. ConocoPhillips is currently undergoing an environmental impact study of the block.
(PV-Tech, Tom Kenning, 18.Apr.2018) – Colombian utility EPM has installed what it claims to be the country’s first floating solar plant, standing at 100kW at the El Peñol reservoir.
The pilot project will test the technology and its fundamentals in comparison to ground-mount and rooftop systems. For this purpose, traditional solar panels will be installed on a roof at the Guatapé Central camp, under the same irradiation conditions.
EPM general manager Jorge Londoño De la Cuesta said: “With this pilot project we seek to verify if the floating systems of solar panels have an energy performance of more than 10% or 15% compared to traditional systems on land or in the roof, thanks to its proximity to water, which allows them to be more refrigerated and take advantage of the greater radiation from reflection in the water.”
The pilot solar park has 368 panels and is located near the collection tower, so as not to interfere with the dam in its role as a tourist attraction. The plant has been set up across two 50kW modules and is expected to generate approximately 145MWh of electricity per year.
Last September, Innova Capital Partners and French floating PV specialist Ciel & Terre (C&T) also agreed to jointly develop floating solar plants in Colombia. C&T has already completed Brazil’s first floating solar project.
(Reuters, 17.Apr.2018) – Crude oil production in Colombia reached an average of 856,478 barrels per day (bpd) in March, the Mines and Energy Ministry said on Monday, up 6.5 percent compared with the same month a year ago.
Natural gas production for March totaled 937.4 million cubic feet per day, the statement said, up 3.1 percent year-on-year. State-run Ecopetrol produces the majority of Colombia’s oil.
The following is a breakdown of Colombia’s average daily oil output:
(Energy Analytics Institute, Jared Yamin, 15.Apr.2018) ‐- During the first three months of 2018, Ecopetrol reported its highest quarterly net income in the last four years.
Colombia’s state oil company Ecopetrol announced its net income rose 195% in the first quarter of 2018 to COL$2,625 billion Colombian pesos compared to COL$886 billion in the first quarter of 2017, the company reported in a Twitter post.
The company reported quarterly net income of COL$363 billion in the same period in 2016 and COL$160 billion in the same period in 2015.
(Reuters, 3.Apr.2018) – Colombia’s attorney general’s office on Monday launched an investigation to determine whether officials from state-run oil company Ecopetrol could be held criminally responsible for a oil spill of 550 barrels in Santander province.
The Lisama 158 well, which was in the process of being shut down because of low production, leaked crude into a ravine over a three-week period, contaminating the water and affecting animal and plant life.
“The investigation will seek to establish if individual officials from Ecopetrol were responsible and could be penalized,” an official from the attorney general’s office told Reuters.
The country’s procurator general – which has the power to remove officials from their jobs – and the environmental licensing agency are also conducting investigations into the leak.
Ecopetrol Chief Executive Officer Felipe Bayon Pardo told journalists late on Monday the company will cooperate fully with all three investigations.
“We will do everything necessary to re-establish environmental and social conditions in the area. It’s our commitment and we will invest the human, financial and technological resources which are required,” said Bayon.
(Reuters, 2.Apr.2018) – Canada’s Frontera Energy Corp named a new chief executive on Monday, and said it plans to more than double its investment in operations in Colombia and Peru during 2018, to up to $500 million.
Frontera will direct between $225 million and $240 million of investment to new wells and maintenance in the two countries, the company said in a statement.
The investment will fund between 125 and 135 development wells, 11 to 15 exploratory wells and 15 to 25 work-over wells, the company said. Work-over wells require major maintenance or remedial treatment.
Richard Herbert, formerly of BP Plc, will replace Barry Larson as chief executive. At BP, Herbert was responsible for exploration and development projects worldwide, Frontera said.
Frontera had an average daily production of 70,082 barrels of crude per day (bpd) in 2017, the statement said, down 32 percent from 2016 because of the end of its contract to operate Rubiales field, its top producer. The company aims to produce between 65,000 and 70,000 bpd this year, it said.
Based on a Brent oil price of $63 per barrel, the company anticipates 2018 earnings before interest, taxes, depreciation and amortization (EBITDA) of between $375 million and $425 million, it said.
Frontera had a net loss of $217 million in 2017, compared with net profit of $2.4 billion in 2016, the company said by telephone.
(Reporting by Luis Jaime Acosta; writing by Julia Symmes Cobb; editing by Jonathan Oatis)
(Efe, 23.Mar.2018) – The world must accelerate its transition from a carbon-based to a clean energy-based economy to put the brakes on a climate catastrophe that already causes 4.8 million deaths annually, the director of an organization that aims to facilitate understanding of global climate change said Friday at a conference in this northern Colombian city.
Klimaforum Latinoamerica Network Director Manuel Guzman Hennessey made his remarks during a panel discussion on the final day of a Colombian Natural Gas Association (Naturgas) conference in Cartagena.
He said that when the current fossil-fuels-based energy model was developed “no was thinking about creating an economy that would kill people.”
But the pollution and climate change stemming from greenhouse gas emissions have caused a catastrophic situation, according to the expert.
“The problem with this economy is that it causes 4.8 million deaths each year worldwide,” Guzman Hennessey said at Congreso Naturgas 2018, citing World Bank figures.
He added that the situation would grow more severe, with a much worse financial and human toll, if effective measures are not taken.
Guzman Hennessey said the world must devote 1.7 percent of global gross domestic product to address climate change-triggered catastrophes.
He added that at the present pace by 2030 climate change-induced disasters will cause agricultural damage, flooding and other phenomena that plunge some 100 million people into poverty.
“If we as a civilization are not able to stop this, before 2030 we’ll need to invest 3.2 percent of global GDP in dealing no longer with 4.8 million deaths but between 6.5 and 7 million deaths each year,” Guzman Hennessey said, referring to World Bank projections.
Congreso Naturgas 2018 concludes Friday after three days of debates on the use of natural gas as a transition fuel between oil and coal, the most contaminating energy sources, and clean energy sources such as solar and wind.
(Energy Analytics Institute, Ian Silverman, 15.Mar.2017) – The Oxford Business Group said that Colombia only stands to benefit from further internationalizing its currency as it attempts to diversify its sources of foreign exchange, reported the Trinidad Guardian newspaper, citing a report last month launched at Lloyds of London during a visit by Colombian President Juan Manuel Santos.
(Energy Analytics Institute, Jared Yamin, 10.Mar.2017) – Colombian energy generator TermoCandelaria was fined 35,410 million pesos, equivalent to 48,000 minimum salaries, by the country’s Public Services Superintendent.
The entity justified its fine by saying the company had put the entire electrical system at risk in an ‘unjust manner’ during a time when the country confronted the Niño phenomena, reported the daily newspaper El Tiempo.
“TermoCandelaria unjustly failed to complete its obligations to generate electric energy during moments of scarcity,” reported the daily, citing the government entity.
(Gran Tierra Energy Inc., 1.Mar.2017) – Gran Tierra Energy Inc. intends to implement a normal course issuer bid through the facilities of the Toronto Stock Exchange (TSX) and the NYSE MKT. Pursuant to the Bid and subject to regulatory approval, Gran Tierra would be able to purchase for cancellation up to approximately 5% of its issued and outstanding shares of common stock for a one year period at prevailing market prices at the time of purchase.
Management of Gran Tierra believes the Shares, at times, have been trading in a price range, which does not adequately reflect their value in relation to Gran Tierra’s current operations, growth prospects and financial position. At such times, the purchase of Shares for cancellation may be advantageous to stockholders by increasing the value of the remaining Shares.
(GeoPark Limited, 2.Mar.2017) – GeoPark Limited announced the successful drilling and testing of the Jacana 11 appraisal well in the Jacana oil field in the Llanos 34 Block (GeoPark operated with a 45% working interest) in Colombia.
GeoPark drilled and completed the Jacana 11 appraisal well to a total depth of 11,618 feet. A production test conducted with an electric submersible pump in the Guadalupe formation resulted in a production rate of approximately 2,100 bopd of 18.7 degrees API, with less than 1% water cut, through a choke of 33/64 mm and well head pressure of 98 pounds per square inch. The well is still cleaning up and additional production history is required to determine stabilized flow rates of the well. Surface facilities are in place and the well is already in production.
The Jacana 11 well was drilled to a bottom-hole location that is approximately 2,500 meters south-west of the recent Jacana 6 appraisal well, and did not encounter the oil-water contact. With the preliminary production test results, the Jacana 11 well extends the Tigana/Jacana oil play towards the south-west limits of the Llanos 34 Block. The next well to be drilled will be the Jacana South 2 well, which is targeted to further test the extension of the field in the north-west direction.
James F. Park, Chief Executive Officer of GeoPark, said: “More oil, more production, more area, more value, more to come. A great beginning already from the start-up of our 30+ well 2017 drilling program.”
(Gran Tierra Energy Inc., 1.Mar.2017) – Gary Guidry, President and Chief Executive Officer of Gran Tierra, commented “2017 is off to an exciting start for Gran Tierra. We are pleased to report that the Acordionero field in the Middle Magdalena Basin continues to exceed our expectations and are encouraged by the discovery of a new and deeper 24 degree API gravity oil reservoir in the field, which we plan to effectively exploit using our existing infrastructure. We continue to see encouraging results with the A Limestone play in the Costayaco field in the Putumayo Basin, with a recent third recompletion in the field in the CYC-2 well producing at an initial rate of 2,023 barrel of oil per day (bopd). In the Putumayo-7 Block (PUT-7), the Confianza-1 exploration/appraisal well has encountered potential oil pay in three reservoirs, two of which would be new zones for this block. We believe that our focused strategy is delivering results on several fronts in Colombia. With our positive results from development drilling in Acordionero, our exciting new A Limestone play at Costayaco, and our high potential Putumayo N Sand and A Limestone exploration program, Gran Tierra is well positioned for potential growth in 2017 and beyond.”
Development Program Update
Acordionero Field Development (Gran Tierra 100% Working Interest (“WI”) and Operator)
The AC-8i development well was spud on December 26, 2016 and drilled to a total depth of 10,340 feet (ft) total measured depth (MD) and 10,028 ft true vertical depth (TVD). This well is planned as a water injector in the Lisama A and C reservoirs as a pilot test for enhanced oil recovery. The well was drilled in the lowest structural position to date in the field, and crossed the oil-water contact (OWC) in the Lisama A at a depth 143 feet deeper than the previous Lowest Known Oil depth (LKO). Petrophysical analysis of the AC-8i’s well logs indicates that the Lisama C reservoir’s 2P OWC was likely found at approximately the expected depth. The AC-8i was drilled below the Lisama C in order to appraise the lower part of the Lisama interval, and an oil-bearing Lisama D sand was found. A total of 8 ft of gross pay was perforated in the Lisama D sand for testing. Over a three day period, the well flowed naturally and produced 24 degree API oil at an average rate of 144 bopd and 0.2% water cut from only 8 feet of perforated pay. The test results for the Lisama D sand at AC-8i are positive since they indicate the existence of a previously untested reservoir at the deepest position in the reservoir that has been drilled to date. The AC-8i will be completed initially as a Lisama C injector. The initial waterflood pilot for Acordionero is forecasted to be onstream in early second quarter 2017.
The AC-9 development well was spud on February 6, 2017 and reached 8,929 ft MD and 8,708 ft TVD on February 23, 2017 and completion operations began on the same day. The Lisama A sand was cored and 88 ft of core was recovered. Total cost to drill, core, complete and tie-in this well is forecasted to be $4.4 million, which the lowest cost to date in Acordionero. Based on logging while drilling (LWD) data, the following potential net pays were identified: Lisama A (240 ft); Lisama C (140 ft); and Lisama D (19 ft). The completion plan for AC-9 is to start with the lowest productive interval and conduct a short term test of the Lisama D before completing the Lisama C and equipping with an electric submersible pump (ESP).
Based on petrophysical analysis of logs, the Lisama-D is also present in the AC-3 well with 13 ft of net pay and in the AC-4 well with 18 ft of net pay. Both of these wells were drilled by the previous operator, however they were not tested.
The next well, AC-10, is designed to target reserves in the Lisama A and C reservoirs. This will be the first well in the next phase of the development targeting the northern portion of the field from a pad where the existing AC-2 well is located.
Costayaco Field Development (Gran Tierra 100% WI and Operator)
CYC-2 was drilled in first quarter 2008 and was producing 247 bopd at a 95% water cut (approximately 4,750 barrels of water per day) from the Caballos and T Sands. Potential pay was identified in the A Limestone and M2 Limestone and a packer was set to temporarily isolate the active Caballos and T Sands. A 36-ft interval was perforated in the lower A Limestone, with no initial pressure or fluid flow response. The lower A Limestone interval was stimulated with acid, and a pump run to clean up the well. The well cleaned up and tested 2,023 bopd of 30 degree API oil, along with a low water cut of 1.1% over a 24 hour time period on February 25, 2017. Over the past 24 hours the production from the well has averaged 2,083 bopd with a water cut of 0.6%. CYC-2 is now the third well producing from the A Limestone formation in the Costayaco field. Production from the lower A Limestone interval will continue to be evaluated before making a decision to move uphole to perforate and stimulate an additional 18 feet of pay in the upper A Limestone, and 54 feet of pay in the M2 Limestone intervals.
CYC-28 was spud on December 31, 2016 and will be the first horizontal well into the A Limestone. A pilot hole was successfully drilled into the A Limestone formation where 78 feet of core was recovered. The core showed extensive fracturing and strong oil shows including visible oil not only from the fractures but also the matrix structure of the rock. Extensive core analysis is currently underway to better understand the A Limestone throughout the Costayaco field and the Putumayo basin. While oil shows were found throughout the cored interval, a specific 25-ft interval has been identified as having the best fracture density and will be the targeted zone for the 1,000-meter horizontal leg. The well has been kicked off and was landed 8 feet below the top of the targeted 25-ft zone within the A Limestone as planned. Casing is currently being set and drilling will continue within the next couple of days.
The two recompleted A Limestone wells, CYC-9 and CYC-19, continue to perform well and have produced an average of 527 and 1,587 bopd respectively (2017 year to date) of 30 degree API oil along with an average gas-oil ratio (GOR) of 201 standard cubic feet per stock tank barrel (“scf/stb”) and an average water cut of 0.9%.
Water injection was a key focus throughout the second half of 2016 where injection volumes were increased by 33%. Several plans are in place to continue to increase injection volumes through 2017. By converting wells to injectors, stimulating existing injectors and adding pump capacity, injection volumes should increase by another 25% through the year to provide pressure support and optimize recoveries.
Moqueta Field Development (Gran Tierra 100% WI and Operator)
With the previously reported increase in water injection into Moqueta, the overall GOR in this field has started to decrease and production has started to increase in a number of wells. In particular, MQT-12 production has increased by about 400 bopd since September of 2016 and is currently producing record high volumes for that well of around 1,000 bopd. We anticipate the trend to continue and therefore, we are not forecasting any oil production decline at Moqueta in 2017, with little capital requirements.
On February 1, 2017, a total of 168 ft of pay was perforated across the A and M2 Limestones in the MQT19 wellbore. The final completion string was run in the hole to allow for selective stimulations and testing of each zone. An 84 gallon/ft concentration of hydrochloric acid was used to stimulate both zones and although injectivity plots demonstrated that the acid was effective, the stimulation volumes may not have been large enough to effectively access the fractures within the reservoir. A higher volume acid stimulation of this well is currently being evaluated and will be performed in the first half of 2017.
Exploration Program Update
Putumayo 7 (“PUT-7”) Block (Gran Tierra 100% WI and Operator)
Confianza-1 is the third exploration/appraisal well drilled within the Cumplidor-Alpha field within PUT-7. This well was located on amplitudes interpreted from two dimensional (2D) seismic between the Cumplidor-1 and Alpha-1 wells. The well was spud on January 17, 2017. In addition to serving as an appraisal well for the N Sand of the Villeta formation discovered in Cumplidor-1 and Alpha-1, the well was planned to test deeper prospective horizons including the “A” Limestone and the “U” Sand of the Villeta formation. A final depth of 12,500 ft MD and of 10,118 ft TVD was reached in the Caballos formation on February 24, 2017.
Based on well logs and oil show while drilling, the well has encountered interpreted oil pay in the U Sand (6 ft), the A Limestone (50 ft of gross interval with 15 ft of net pay), and the N Sand. The N Sand shows three potential reservoir intervals totaling 24 ft of net pay. The pay thickness encountered in the N Sand based on amplitudes from 2D seismic was as expected. Therefore, our confidence continues to build in the interpretation of seismic amplitudes as correlated to pay thickness.
The Confianza-1 is a significant step out from current A Limestone production in the northern portion of the Putumayo Basin at Costayaco. Testing of all three interpreted zones (U Sand, N Sand and A Limestone) is planned to begin immediately with the drilling rig onsite. Information collected from this well could be helpful with the interpretation of the evolving basin-wide A Limestone play.
The Cumplidor-1 well produced 19 degree API oil with a GOR of less than 100 scf/stb and a water cut of less than 1% at a rate of 236 to 1,403 bopd. A maximum instantaneous rate of 1,900 bopd was achieved just prior to jet pump failure. Progressively larger jet pump nozzles were run in the well, and the last attempt resulted in sticking a tool string and wireline in the well. The well is on the same pad as the Confianza-1 well, and a workover will be conducted once the testing on Confianza-1 is completed.
Gran Tierra has obtained the regulatory approvals to acquire 95 square kilometers of three dimensional (3D) seismic starting in late second quarter 2017 in two separate programs, over the Cumplidor field area and the N Sand prospects in the central area of PUT-7 called Pomorroso and Northwest. The seismic fulfills the contractual commitments for the block in this phase. Acquiring 43 square kilometers of 3D seismic over the Cumplidor-field area is expected to provide high quality amplitude information to optimize potential future development well locations and for future waterflooding of the field. The seismic project timing was sequenced to locate the exploration wells to be drilled to the west at Pomorroso and Northwest based on 3D seismic amplitudes. These exploration wells are expected to be drilled in fourth quarter 2017.
Putumayo 4 (“PUT-4”) Block (Gran Tierra 100% WI and Operator)
On December 30, 2016, the license was granted to drill the Siriri-1 exploration well which is planned to test both N Sand amplitudes on 2D seismic and the deeper A Limestone exploration play. Civil works are forecasted to start in early March 2017 for access road and lease construction.
Putumayo 1 (“PUT-1”) Block (Gran Tierra 55% WI and Operator)
The Vonu-1 exploration well is expected to spud during second quarter 2017. The well is planned to be a directional drill with the pad located in the adjacent Chaza Block which contains the Costayaco and Moqueta fields. Civil works preparations are underway on the existing pad site within the Costayaco field and a contracted drilling rig is planned to be mobilized to this pad after civil works are completed.
The Vonu-1 is planned to target an interpreted structural prospect, similar to the Costayaco field. It is a multi-zone prospect with potential in the Caballos formation, the Villeta U and T Sands, the A Limestone and the N Sand.
Nancy-Burdine-Maxine (“NBM”) Block
Gran Tierra announced the acquisition of this block from Ecopetrol late fourth quarter 2016. This block is strategic for both its infrastructure and prospective resource potential. Existing drilling pads may be used to test some of the potential exploration upside in this new block.
The planned near term exploration program calls for permitting, followed by acquisition of approximately 100 square kilometers of 3D seismic, permitting of three new drilling pad locations, and then the potential drilling of several multi-zone prospects. Similar to the northern Putumayo, Gran Tierra plans to explore for N Sand, A Limestone and deeper U, T, and Caballos Sands potential in this new block.
Llanos – El Porton Block (Gran Tierra 100% WI and Operator)
The civil works for road access and pad construction have been completed for the Prosperidad-1 exploration well. The drilling rig has commenced mobilizing to the lease site. This well is planned to target a multi-zone structural exploration prospect with oil potential in the Mirador, Gacheta, and Une formations.
Middle Magdalena Valley Basin – Acordionero Exploitation Area (Gran Tierra 100% WI and Operator)
Progress is underway to obtain site access to drill the Totumillo-1 structural exploration prospect that is immediately south of the Acordionero field. The structural prospect is planned to target reservoirs of the Lisama Formation, as found in the Acordionero field. The prospect is within the Acordionero exploitation license, and the Totumillo-1 exploration well is planned to spud in the second quarter of 2017.
Sinu-San Jacinto Basin – Sinu-Sinu-3 Block (Gran Tierra 51% WI and Operator)
The recently acquired 2D seismic has been interpreted and a new prospect has been identified on this block called Tonga-1. An integrated scouting team is reviewing the existing environmental license for potential site access. The planned spud of this well is in late second quarter 2017.
(Ecopetrol, 27.Feb.2017) – The Chief Executive Officer of Ecopetrol S.A. announced details of the Annual General Shareholders’ Meeting held on March 31, 2017 at the International Center of Business and Exhibitions (Centro Internacional de Negocios y Exposiciones, Corferias), Bogotá, Colombia.
The agenda for the meeting included:
— Safety guidelines
— Quorum Verification
— Opening by the Chief Executive Officer
— Approval of the Agenda
— Appointment of the Meeting’s President
— Appointment of the Commission in charge of scrutinizing elections and polling
— Appointment of the Commission in charge of reviewing and approving the minutes of the meeting
— Presentation of the report concerning the Board of Directors’ activities, the Board’s evaluation of the Chief Executive Officer’s performance, as well as the company’s compliance with the corporate governance code
— Presentation of 2016 performance report by the Board of Directors and by the Chief Executive Officer
— Review and consideration of financial statements and consolidated financial statements as of December 31, 2016
— Review of the External Auditor’s Report
— Approval of reports presented by the Management, and the External Auditor and approval of Financial Statements
— Approval of proposal for dividend distribution
— Election of the External Auditor and assignment of remuneration
— Election of the Board of Directors
— Propositions and miscellaneous
As from March 8, 2017, shareholders will exercise the right to inspect the books and documents that the Colombian Commercial Code refers to. This information may be consulted at the company’s main offices (Cra. 7 No. 37-69 Bogota, Colombia), in a time schedule from 7:30 a.m. to 4:00 p.m. 2015 performance report may be consulted on Ecopetrol web site.
(Ecopetrol S.A., 17.Feb.2017) – This valuation was made at a regulatory price of $44.5/barrel, lower prices negatively impacted 202 million barrels …
Ecopetrol S.A. announced its proven reserves (1P, according to the international designation) of crude oil, condensate and natural gas owned by the company, including its interest in affiliates and subsidiaries, as of December 31, 2016. The reserves were estimated based on the U.S. Securities and Exchange Commission (SEC) standards and methodology. 99% of them were audited by two well-known specialized independent companies (Ryder Scott Company and DeGolyer and MacNaughton).
Ecopetrol’s proven net hydrocarbon reserves were 1,598 million barrels of oil equivalent (mmboe) at the close of 2016, a 14% reduction compared with 1,849 mmboe at the end of 2015. It is estimated that price was the cause of most of the negative impact on proven reserves (-202 mmboe). In 2016, the SEC price used for the valuation had a 20% decrease compared to 2015, from $55.57 per barrel Brent to $44.49 per barrel and a 56% decrease compared to 2014, which was $101.80 per barrel.
This effect was partially offset by the addition of 186 mmboe, attributable to continued optimization of operating costs, higher efficiencies, new drilling projects as planned in the Palagua-Caipal fields and extensions of the proven area in fields such as Castilla, Rubiales and Chichimene, among others. The reserve replacement ratio, excluding price effect, was 79%. By including the price factor, the reserve replacement ratio stands at -7%. The reserves/production ratio (average life of reserves) was 6.8 years.
Ecopetrol’s proven reserves as of December 31 of 2016
Fields operated directly by Ecopetrol as Rubiales and Chichimene, presented positive reviews of reserves due to good performance in production and optimization of their conditions, among others. The 95% of proven reserves are owned by Ecopetrol, while Hocol, Ecopetrol América and Equión and Savia Perú contribute 5%.
(Ecopetrol S.A., 15.Feb.2017) – Ecopetrol S.A. reported results of the fourth auction corresponding to Stage Two of the Program to Transfer and Award its 28,465,035 shares of Empresa de Energía de Bogotá S.A. E.S.P. The bidding session was declared void.
(Ecopetrol S.A., 8.Feb.2017) – Ecopetrol S.A. announced on February 8, 2017, as established in the Offering Notice of Second Stage, the company published the offering notice regarding the fourth auction for the second stage of Ecopetrol’s equity divestment plan for its shares in Empresa de Energía de Bogota S.A. E.S.P. (EEB) in a newspaper widely circulated in Colombia.
The fourth auction is part of the second stage of the equity divestment plan and the purpose is to offer publicly, in Colombia and/or abroad, the shares that were not acquired during the first, second and third auctions.
The public offering will be conducted prior to the start of common stock trading in the Colombian Stock Exchange on February 15, 2017, in accordance with the provisions set forth in the Divestment Regulation and the applicable addenda.
Ecopetrol’s equity divestment plan, including the second stage, was approved by the National Government of Colombia through Decree 2305 of November 13, 2014, with an extension to December 31, 2017 through Decree 2110 of December 22, 2016.
(GeoPark Limited, 6.Feb.2017) – GeoPark Limited announced its independent oil and gas reserves assessment, certified by DeGolyer and MacNaughton (D&M), under PRMS methodology, as of December 31, 2016.
Year-End 2016 D&M Certified Reserves and Company Highlights:
— Per Share Value: Net debt adjusted 2P NPV10 increased by 19% to $23.6 per share, mainly resulting from increased net debt adjusted 2P NPV10 in Colombia (up 112%) to $10.2 per share
— PDP Reserves: Net proven developed producing (PDP) reserves increased 12% (by 2.1 MMBOE) to 19.4 MMBOE, with a PDP reserve replacement index (RRI) of 126%
— 1P Reserves: Net proven (1P) reserves increased 10% (by 7.1 MMBOE) to 78.3 MMBOE, with 1P reserve life index (RLI) of 9.5 years and a 1P RRI of 187%. Total NPV10 of 1P reserves increased by $228 million (up 26%) to $1.1 billion
— 2P Reserves: Net proven and probable (2P) reserves increased 14% (by 17.5 MMBOE) to 142.8 MMBOE, with a 2P RLI of 17.4 years and a 2P RRI of 312%. Total NPV10 of 2P reserves increased by $241 million (up 15%) to $1.9 billion
— Colombia 2P Reserves: Net 2P reserves in Colombia increased 45% (by 20.9 MMBOE) to 67.4 MMBOE with a 2P RLI of 11.8 years and a 2P RRI of 468%. Total NPV10 of 2P reserves in Colombia increased by $351 million (up 54%) to $1.0 billion
— F&D Costs: Net finding and development costs (F&D Costs) for 2016 were $2.9 per boe on a 1P basis and $1.7 per boe on a 2P basis, including F&D Costs for Colombia of $1.8 per boe on a 1P basis and $0.9 per boe on a 2P basis, following unaudited capital expenditures in 2016 of $44 million for the total Company, and $25 million in Colombia
“Oil and gas reserves are up. Total asset value is up. Per share value is up. Costs are down. Opportunities are expanding. Coming out of two years of industry turbulence, our important certified gains demonstrate the strength and quality of our people, assets and plan to be able to continuously create and deliver big value across our rich asset portfolio in any price environment,” said GeoPark CEO James F. Park. “GeoPark can look forward to a meaningful and rewarding 2017, with one of the most compelling new land-based oil plays in Latin America today – our Tigana/Jacana fields in Colombia – and backed by a forceful drilling and work program this year across our high potential project inventory.”
(GeoPark Limited, 2.Feb.2017) – GeoPark Limited announced new drilling successes in the Llanos 34 Block (GeoPark operated with a 45% working interest), in Colombia, consisting of:
Discovery of the new Chiricoca oil field, following the successful drilling and testing of the Chiricoca 1 exploration well, and
Further expansion of the Tigana oil field, following the successful drilling and testing of the Tigana Sur 6 development well.
Chiricoca 1 Well
GeoPark drilled and completed the Chiricoca 1 exploration well to a total depth of 11,966 feet. A production test conducted with an electric submersible pump in the Mirador formation resulted in a production rate of approximately 1,000 bopd of 34 degrees API, with 9% water cut, through a choke of 33/64 mm and wellhead pressure of 34 pounds per square inch. The deeper Guadalupe formation was also tested and produced water with traces of heavy oil. Additional production history is required to determine stabilized flow rates of the well. Surface facilities are in place and the well is already in production.
Tigana Sur 6 Well
GeoPark drilled and completed the Tigana Sur 6 development well to a total depth of 11,645 feet. A production test conducted with an electric submersible pump in the lower Guadalupe formation resulted in a production rate of approximately 1,600 bopd of 15 degrees API, with 8% water cut, through a choke of 52/64 mm and wellhead pressure of 70 pounds per square inch. Additional production history is required to determine stabilized flow rates of the well. Surface facilities are in place and the well is already in production.
The Tigana Sur 6 well encountered a good quality reservoir in the lower Guadalupe formation, with a net pay of approximately 57 feet as well, which represents a significant thickening (almost 60% more) of the average net pay of the lower Guadalupe formation in other producing wells in the Tigana oil field. In addition, the well encountered a new set of reservoir sands in the upper Guadalupe formation, which appear to be oil-bearing from preliminary petrophysical logging information. Further production testing will be required to confirm if this zone is oil productive.
James F. Park, CEO of GeoPark, commented: “GeoPark’s active drilling program in the first half of 2017 is already paying off – all underpinned by continued exciting results from our Colombia projects; especially the Tigana and Jacana oil fields, where our team keeps drilling to push out and define field boundaries. During 2017, additional big rewards are expected from our total 30-35 well drilling program in Colombia and across our rich asset platform in Latin America – including high potential prospects in Argentina, Chile, and Brazil.”
(Gran Tierra Energy Inc., 30.Jan.2017) – Gran Tierra Energy Inc. announced its financial and operating results for the fourth quarter and year ended December 31, 2016. Unless otherwise expressly stated, all reserves and resources values have been calculated in compliance with Canadian National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and are based on the company’s 2016 year-end estimated reserves as evaluated by the company’s independent qualified reserve evaluator McDaniel & Associates Consultants Ltd. in a report with an effective date of December 31, 2016.
— Announced two successful strategic acquisitions in the Ecopetrol 2016 Bidding Round in the Putumayo Basin on November 28, 2016, which are expected to close by end of first quarter 2017.
— Increased average WI production before royalties in 2016 to 27,062 barrels of oil equivalent per day (BOEPD), 16% higher than 2015’s average WI production before royalties of 23,401 BOEPD.
— Increased average WI production before royalties in fourth quarter 2016 to 31,031 BOEPD, 34% higher than fourth quarter 2015’s average WI production before royalties of 23,138 BOEPD.
— Increased net asset value to $4.852 per share, based on before tax net present value (NPV) discounted at 10% of 2P reserves, and year-end 2016 net working capital deficit and long term debt of $220.4 million (including convertible senior notes).
— Demonstrated ongoing strong financial performance in 2016, with full year average operating, transportation and general and administrative (G&A) expenses on a per BOE basis decreasing by 9%, 37% and 28%, respectively, compared to 2015, while fourth quarter 2016 operating netback1 of $20.79 per BOE increased 31% relative to the third quarter 2016.
— Successfully drilled and cased the Acordionero-7 development oil well and spud the Acordionero-8i development water injection well during the fourth quarter of 2016, both of which pushed down the depth of the lowest known oil in Acordionero’s reservoirs.
— Continued evaluating an exciting new oil play in Costayaco’s “A” Limestone, where the Costayaco-9 and 19 wells continue to produce an average of 527 and 1,587 barrels of oil per day (bopd), respectively (2017 year-to-date), from the “A” Limestone with virtually no water; commenced drilling of the Costayaco-28, Gran Tierra’s first dedicated “A” Limestone horizontal well, which continues with testing expected to begin on or around March 15, 2017; a second horizontal well, Costayaco-29, is expected to spud immediately after Costayaco-28 and is planned to test the “A” Limestone in a different part of the Costayaco structure.
— Continued drilling in the “N” Sands and “A” Limestone exploration plays in the Putumayo Basin, and spud the Confianza-1 exploration well on January 17, 2017, which is designed to test both formations.
— Maintained financial flexibility with an increased committed borrowing base of $250 million, of which only $90 million was drawn as of December 31, 2016.
Message to Shareholders
Gary Guidry, President and Chief Executive Officer of Gran Tierra, commented “During 2016, Gran Tierra successfully transformed its portfolio by delivering on our strategy of building a high-quality, diversified suite of assets in Colombia with high netback production, low base production declines, an expanded drilling inventory and a large resource base. Now that we have transformed the portfolio, our focus is on execution. With our delivery of strong production growth in fourth quarter 2016, we are demonstrating that Gran Tierra has created a sustainable business model which we expect to be fully funded point-forward by forecasted cash from operating activities. Since we operate over 90% of our production, Gran Tierra also has significant control and flexibility on capital allocation and timing.
We transformed our portfolio through four strategic, accretive acquisitions in Colombia in 2016 (three completed, one pending), which established a dominant land position in the highly prospective, underexplored Putumayo Basin and a new core area in the prolific Middle Magdalena Valley Basin. Our high quality asset base now has 74% of its 2P reserves contained in three large operated, conventional, onshore Colombian oil assets: Acordionero, Costayaco and Moqueta.
As we reported on January 23, 2017, this transformed portfolio delivered, during 2016, proved (1P), proved plus probable (2P) and proved plus probable plus possible (3P) WI reserves growth of 51%, 91% and 146% respectively, compared to 2015. Our inventory of net undrilled development locations has grown to 36 (2P) and 54 (3P) during the year. We are also pleased that we were able to increase our 2P reserve life index from 7.8 years to 11.1 years3. This robust set of assets is now expected to have visibility to 2018 WI production greater than 40,000 BOEPD by 2018, based on the 2P forecast. With our large resource base, we also plan to drill 30 to 35 exploration wells over the next three years, which are all expected to be funded by cash from operating activities. Our exploration campaign is designed to test the majority of our portfolio of prospective resources with these wells, including our now dominant Putumayo position in the emerging “N” Sand and “A” Limestone oil play fairways.
We believe Gran Tierra ended 2016 on a strong note by delivering strong production growth in fourth quarter 2016, as we realized the first full three months of production from the PetroLatina acquisition which closed August 23, 2016. Fourth quarter 2016 WI production averaged 31,031 BOEPD, an increase of 34% from fourth quarter 2015’s level of 23,138 BOEPD and an increase of 20% from the prior quarter. Commensurate with our increased production, our funds flow from operations1 saw a substantial increase of 54% in fourth quarter 2016 to $36.2 million compared with $23.5 million in the Prior Quarter.
Oil prices increased in fourth quarter 2016, with Brent prices averaging $51.13 per barrel, a 9% increase from the prior quarter, while Gran Tierra’s realized oil price also rose by 9% to $31.89 per BOE in the same time period. Gran Tierra continued to be successful in driving down combined operating and transportation expenses to $11.10 per BOE in the fourth quarter, a decrease of 17% from the prior quarter. We believe our low cost structure and growing production base allow us to be successful in a variety of pricing environments. Our ongoing focus on cost reductions allowed us to increase our operating netback in fourth quarter 2016 to $20.79 per BOE, up 31% from the prior quarter, a larger increase than the 9% increase in the Brent oil price over the same period.
Financial and operating highlights for the year include:
— WI production before royalties for the quarter averaged 31,031 BOEPD, or 26,263 BOEPD NAR, compared with 25,835 BOEPD WI production before royalties and 21,980 BOEPD NAR in the Prior Quarter. WI annual production before royalties for 2016 averaged 27,062 BOEPD, or 23,187 BOEPD NAR, compared with 23,401 BOEPD WI annual production before royalties or 19,489 BOEPD NAR in 2015.
— Sales volumes for the fourth quarter were 26,477 BOEPD compared with 21,485 BOEPD in the Prior Quarter. Sales volumes increased due to higher working interest production (5,196 BOEPD) and a reduction of inventory (709 BOEPD), partially offset by higher royalty volumes (913 BOEPD). Annual sales volumes were 23,954 BOEPD compared with 18,260 BOEPD in 2015.
— Gran Tierra expects 2017 average WI production before royalties to be 34,000 to 38,000 BOEPD from the Company’s assets in Colombia and Brazil, which would represent an increase of 26% to 40% from our 2016 average WI production before royalties of 27,062 BOEPD. The 2017 guidance includes 1,200 to 1,500 BOEPD of production from Brazil. The Company’s production guidance only includes forecasted volumes from existing operations and expected development projects; no volumes are assumed for any exploration success. Financial:
— Funds flow from operations(1) was $105.0 million for the year ended December 31, 2016 compared with $107.6 million in 2015, and, for the fourth quarter, $36.2 million compared with $23.5 million in the Prior Quarter.
— Net loss was $465.6 million, or $1.45 per share basic and diluted, for the year ended December 31, 2016 compared with $268 million, or $0.94 per share basic and diluted, in 2015. The increase in net loss was primarily due to higher impairment losses. Impairment losses increased by $183.1 million, net of income tax recovery, compared to 2015. For the fourth quarter, net loss was $127.4 million, or $0.36 per share basic and diluted, compared with $229.6 million, or $0.71 per share basic and diluted, in the prior quarter. Impairment losses decreased by $76.1 million, net of income tax recovery, compared with the prior quarter.
— At December 31, 2016, cash and cash equivalents (including current restricted cash) were $33.5 million, working capital deficiency (including cash and cash equivalents) was $23.3 million and $90 million was outstanding on the company’s revolving credit facility. The working capital deficiency was primarily a result of current tax related to a one-time restructuring.
— Average realized prices decreased to $28.38 per BOE for the year ended December 31, 2016 from $34.06 per BOE in 2015, but for the fourth quarter increased to $31.89 per BOE from $29.28 per BOE in the prior quarter.
— Operating expenses decreased to $8.51 per BOE for the year ended December 31, 2016 from $9.31 per BOE in 2015, primarily as a result of Colombian operating cost savings, partially offset by the effect of the weakening of the U.S. dollar against local currencies in South America. Workover expenses increased by $0.46 per BOE compared with the prior year. Excluding workover expenses, operating costs decreased by $1.26 per BOE to $6.28 per BOE. For the fourth quarter, operating expenses decreased to $8.50 per BOE from $10.93 per BOE in the prior quarter, primarily as a result of workover expenses of $1.92 per BOE compared with $4.30 per BOE in the Prior Quarter. Excluding workover expenses, operating costs per BOE were consistent with the prior quarter.
— Transportation expenses decreased to $3.12 per BOE for the year ended December 31, 2016 from $4.96 per BOE in 2015 primarily due to a lower percentage of volumes sold using pipelines, and the use of alternative transportation routes, which had lower costs per BOE than the routes used in 2015. For the quarter, transportation expenses increased to $2.60 per BOE from $2.47 per BOE in the prior quarter. The increase was primarily due to a lower percentage of sales at the wellhead, 50% in the current quarter, compared with 56% in the prior quarter.
— G&A expenses per BOE for the year ended December 31, 2016 decreased to $2.66 per BOE from $3.67 per BOE in 2015.
(Gran Tierra Energy Inc., 23.Jan.2017) – Gran Tierra Energy Inc. announced its 2016 year-end estimated reserves as evaluated by independent qualified reserve evaluator McDaniel & Associates Consultants Ltd. in a report with an effective date of December 31, 2016. Gran Tierra has also updated its corporate presentation, which is available on the company’s website. Gary Guidry, President and Chief Executive Officer of Gran Tierra, commented:
Gran Tierra had a transformational year during 2016 in which we expanded, upgraded and diversified our portfolio in Colombia through four strategic and accretive acquisitions: Petroamerica, PetroGranada, PetroLatina and the Ecopetrol 2016 Bid Round, which is expected to close in 2017. In 2016 the company was able to add approximately 9.2 million barrels of oil equivalent (MMBOE) of Proved plus Probable (2P) working interest before royalties (WI) reserves organically in both existing assets and our new assets postacquisition, despite only commencing exploration and appraisal drilling in late September 2016. The 2016 exploration drilling delivered 2016 2P WI reserve additions of 2.1 MMBOE in the N-sands exploration play in the acquired Putumayo-7 (“PUT-7”) Block. Total 2P WI reserves booked on PUT-7 are now 5.4 MMBOE.
Development activities delivered 2P WI reserves additions of 2.6 MMBOE in the newly acquired asset at Acordionero in the Middle Magdalena Basin and 2.0 MMBOE of 2P WI reserves in the legacy asset at Costayaco in the Putumayo Basin from the “A” Limestone. In 2017 the company looks to further proving up Acordionero through ongoing development drilling which targets 48 MMBOE of Possible reserves (out of Acordionero’s total Proved plus Probable plus Possible (3P) WI reserves of 96 MMBOE), and developing the “A” Limestone in Costayaco through horizontal drilling, which commenced at the end of 2016.
During 2016, Gran Tierra’s total 2P WI reserves increased by 91% compared with year-end 2015, while the company’s 3P WI reserves increased by 146% over the same time period. In addition, the company’s exploration portfolio has been substantially enhanced and expanded. Our 2P reserves replacement ratio in 2016 was 708%1 including acquisitions. The company also inceaesed its 2P reserve life index from 7.8 years to 11.1 years.
Since the senior management team joined the company in May 2015, 2016 represents the first full year in which the company has been delivering on its focused strategy. The company has grown its before tax net asset value per share during 2016 by 5%, on a 2P reserves basis and by 37% on a 3P reserves basis, despite a 10% decrease in forecasted pricing. The company increased 2P WI reserves by 60 MMBOE, increased 3P WI reserves by 118 MMBOE and exploration inventory has increased to 72 locations and over 680 MMBOE WI unrisked net prospective resources. After effectively no reserves growth between 2010 and 2015, the company is once again significantly growing reserves on an accretive basis. During 2016, Gran Tierra’s portfolio achieved a 2P finding, development and acquisition, excluding changes in future development costs, cost of $9.81 per barrel of oil equivalent (BOE) and a 2P recycle ratio of 2.1 times excluding changes in future developments costs and 1.5 times including changes in future development costs. Gran Tierra now has visible production growth from its existing asset base through 2019 on a 2P reserves basis and through 2020 on a 3P reserves basis and a world class exploration portfolio that can be funded through cash flow.
The developed reserves base is currently producing approximately 32,000 barrels of oil equivalent per day (BOEPD) (January 2017 year to date) and it is expected cash flow from the 2P WI reserves base will be more than enough to fund exciting exploration portfolio. The asset portfolio is forecasted to generate cumulative net cash provided by operating activities on a 2P basis of approximately $1.0 billion during the next three years (2017 – 2019), with is expected to fund development and exploration programs over this time period. With an operated, low cost, high netback, positive cash-flowing asset base, the company will focus on organic reserves development for production growth and drilling 30 to 35 exploration wells over the next three years, all funded from cash from operating activities.
(Energy Analytics Institute, Piero Stewart, 4.Jan.2017) – Venezuela, the South American country with the region’s largest crude oil and natural gas reserves, initiated the sale of its gasoline in Paraguachón, located in the La Guajira Department in Colombia.
Cooperation between the governments of Colombia and Venezuela has allowed activities to move forward.
Venezuelan President Nicolas Maduro thanked his Colombian counterpart Juan Manuel Santos for his collaboration which allowed for the distribution of gasoline along the border area near the Colombian and Venezuelan border, reported PDVSA in an official Twitter post.
(GeoPark Limited, 4.Jan.2017) – GeoPark Limited announced the successful drilling and testing of the Tigana Sur 4 development well in the Tigana oil field in the Llanos 34 Block (GeoPark operated with a 45% working interest) in Colombia, resulting in consolidated net exit production of approximately 24,400 boepd.
GeoPark drilled and completed the Tigana Sur 4 development well to a total depth of 11,414 feet. A test conducted with an electric submersible pump in the Guadalupe formation resulted in a production rate of approximately 1,800 bopd of 14.7 degrees API, with 3% water cut, through a choke of 46/64 mm and wellhead pressure of 78 pounds per square inch. Additional production history is required to determine stabilized flow rates of the well. Surface facilities are in place and the well is already in production.
The Tigana Sur 4 well was drilled to total depth in a record time of 8.8 days, with an estimated drilling and completion cost of $3.1 million. At current oil prices and production rates, this well is expected to have a payback period of less than 6 months and an IRR greater than 500%. The Tigana oil field, discovered by GeoPark in December 2013, has a current production rate of approximately 17,000 bopd gross from 9 wells that have produced over 10 million barrels of oil to-date. Adjacent to Tigana, the Jacana oil field, discovered by GeoPark in September 2015, has a current production rate of approximately 12,600 bopd gross from 6 wells that have produced more than 3 million barrels of oil to-date.
GeoPark has initiated its 2017 work program, with completion activities currently underway in the Chiricoca 1 exploration well – located northwest of the Tigana oil field – with testing expected in midJanuary 2017, and with the spudding of the Tigana Sur 6 development well. By the end of January, a second rig will be used to start drilling the Jacana 11 appraisal well.
GeoPark’s dynamic and fully funded 2017 work program includes a Base Case ($45-50/bbl Brent Oil Price) with capital expenditures of $80-90 million to accelerate production growth by 20-25% to 26,50027,500 boepd with the drilling of approximately 30-35 gross wells and an estimated exit production of 30,000+ boepd. Approximately 70-75% of capital expenditures will be allocated to Colombia where GeoPark expects to continue exploring and appraising the Tigana/Jacana oil field trend to determine the full extent of the oil accumulation.
(GeoPark Limited, 4.Jan.2017) – GeoPark Limited announced appointment of Mr. Michael D. Dingman as a new member of the Board of Directors of the company, effective January 1, 2017.
Dingman is a respected and successful international investor, businessman and philanthropist, with more than 50 years of investment experience and an impressive track record of building companies and conglomerates in the U.S. and emerging markets. Dingman currently is Founder, President and CEO of the Shipston Group, an international private investment firm with diverse holdings around the globe.
In addition to a successful career on Wall Street as a partner of Burnham & Company, Dingman has been Chairman and Chief Executive or President of several major US-based industrial corporations, including Wheelabrator-Frye, Signal, AlliedSignal, the Henley Group and Fisher-Scientific. His energy investment experience includes working with the Liedtke family of Pennzoil at Pogo Producing Company and as an early investor of Sidanco, one of Russia’s largest oil companies, where he spearheaded the introduction of best management practices.
Dingman is a former director of Ford Motor Company (21 years), Time and then Time Warner (24 years), the Mellon Bank, Temple Industries, Temple-Inland, Continental Telephone and Teekay Shipping. He is the founder of the Michael D. Dingman Center for Entrepreneurship at the University of Maryland, a center that fosters entrepreneurship and provides mentoring services to emerging growth companies around the world. He is a benefactor and former trustee of the Boston Museum of Fine Arts and the John A. Hartford Foundation.
“I am pleased to be joining GeoPark’s Board of Directors and working with its management to support the Company’s exciting expansion. GeoPark has high quality assets, a strong team, a proven operational track record and a unique platform across Latin America, a region that is poised for outsized energy growth and development,” said Dingman.
(Fitch, 1.Jan.2017) – Ecopetrol S.A. reported that on March 14, 2017, rating agency Fitch Ratings improved the outlook for the company’s rating from a negative to a stable outlook. At the same time it maintained the local and foreign currency long-term risk rating at BBB.
According to Fitch, the improved outlook for the rating of Ecopetrol incorporates the improvement to stable of the rating of the Republic of Colombia.
(Ecopetrol, 12.Dec.2016) – Ecopetrol S.A. reported the risk rating agency Fitch Ratings kept the company at investment grade, with an international rating of BBB.
Fitch notes the important link between the company and the Republic of Colombia’s rating, and the Ecopetrol business group’s strategic relevance to the country.
The agency further reported that Ecopetrol’s individual rating is also investment grade with a rating of BBB; and including the government’s support this rating raises to BBB. The aspects the rating agency took into account in issuing its rating included: the company’s solid financial profile, a downward-trending debt/EBITDA ratio, solid liquidity and a schedule of moderate debt maturities in coming years.
The agency also noted Ecopetrol’s operational metrics and the decline in extraction costs in recent years.
Finally, it maintained the company’s negative perspective, consistent with the Republic of Colombia’s outlook.
(Ecopetrol, 10.Dec.2016) – Ecopetrol S.A. announced that on December 10, 2016, as established in the Offering Notice of Second Stage, the company published the offering notice regarding the fourth auction for the second stage of Ecopetrol’s equity divestment plan for its shares in Interconexión Eléctrica S.A. E.S.P (ISA) in a newspaper widely circulated in Colombia.
The fourth auction is part of the second stage of the equity divestment plan and the purpose is to offer publicly, in Colombia and/or abroad, the shares that were not acquired during the first, second and third auctions.
The public offering will be conducted prior to the beginning of common stock trading in the Colombian Stock Exchange on December 14, 2016, in accordance with the provisions set forth in the Divestment Regulation and the applicable addenda.
Ecopetrol’s equity divestment plan, including the second stage, was approved by the National Government of Colombia through Decree 1800 of September 09, 2015.
(Gran Tierra Energy Inc., 29.Nov.2016) – Gran Tierra Energy Inc. closed the previously announced underwritten public offering of shares of its common stock. The company sold 43,335,000 shares of its common stock at a public offering price of US$3 per share, for aggregate gross proceeds to the company of approximately $130 million. The company intends to use the net proceeds from the offering to repay borrowings outstanding under the company’s revolving credit facility, which amounts may be reborrowed for general corporate purposes, including to fund appraisal and development and to finance potential acquisitions.
The offering was made to the public in the United States and Canada through a syndicate of underwriters led by Scotia Capital Inc., RBC Capital Markets and Dundee Capital Markets as joint book-running managers. The syndicate also included TD Securities Inc. as co-lead manager and Peters & Co. Limited, GMP Securities L.P., Morgan Stanley Canada Limited, CIBC World Markets, Canaccord Genuity Corp., Cormark Securities Inc., HSBC Securities (Canada) Inc., Natixis Securities Americas LLC and Paradigm Capital Inc. as co-managers.
The company has also granted underwriters an over-allotment option to purchase up to an additional 6,500,250 shares of its common stock solely to cover over-allotments, if any, on the same terms and conditions as the offering, including the offer price, exercisable at any time, in whole or in part, until 30 days after the date of the execution of the definitive agreement in respect of the offering. If the overallotment option is exercised in full, the aggregate gross proceeds from the offering will be approximately $149.5 million.
(Gran Tierra Energy Inc., 28.Nov.2016) – Gran Tierra Energy Inc. announced that it submitted winning bids totaling a combined $30.4 million for two blocks which Ecopetrol S.A., Colombia’s national oil company, offered as part of the Ronda Campos Ecopetrol 2016 (Bid Round) in an electronic live auction held on November 25, 2016. Gran Tierra’s winning bids are for the Santana and Nancy-Burdine-Maxine Blocks, which are located in the Putumayo Basin. Under the terms of the Bid Round, a purchase and sale agreement relating to each block must be submitted to Ecopetrol by December 7, 2016, and executed by December 22, 2016. Gran Tierra intends to finance these acquisitions with cash on hand and available borrowings under its revolving credit facility.
Ecopetrol holds operatorship and a 100% working interest (WI) in each of the Santana and NancyBurdine-Maxine Blocks. Upon execution of definitive documents relating to the purchase of these blocks, Ecopetrol will transfer ownership of the blocks’ assets, contracts, permits and licenses, as well as 100% ownership of Ecopetrol’s rights and obligations in respect of the oil and gas assets, by entering into assignment agreements with Gran Tierra. Each assignment agreement would be subject to the prior approval of Colombia’s Agencia Nacional de Hidrocarburos (ANH).
Key Attributes of Acquisitions:
Santana and Nancy-Burdine-Maxine Blocks (100% WI)
— Aggregate amount of Gran Tierra’s winning bids: $30.4 million
— Gross WI 2016 average production before royalties of approximately 600 barrels of oil per day (1) (bopd) and estimated 300 bopd behind-pipe (1)
— Gran Tierra has identified potential upside with enhanced oil recovery (EOR) waterflooding techniques, and prospective resources on the new lands from “N” sands and “A” Limestone exploration plays, with mapped prospects based on existing company 2D and 3D seismic data
— Approximately 27,400 gross WI acres (1)
— Establishes a centralized transportation and production hub in the Putumayo Basin with strategic, operated, pipeline infrastructure and gathering facilities which include:
– 26,000 bopd of pipeline capacity, 25,000 barrels of oil storage and capacity to load and unload 11,500 and 13,500 bopd by truck, respectively (1)
– the O.M.U and O.U.S pipelines which connect Costayaco, Moqueta and Guayuyaco oil fields with Santana Station
– transportation and commercialization flexibility, which is expected to further strengthen the Company’s competitive advantage in the Putumayo Basin
— 26,000 bopd of pipeline capacity, 25,000 barrels of oil storage and capacity to load and unload 11,500 and 13,500 bopd by truck, respectively (1)
— the O.M.U and O.U.S pipelines which connect Costayaco, Moqueta and Guayuyaco oil fields with Santana Station
— transportation and commercialization flexibility, which is expected to further strengthen the company’s competitive advantage in the Putumayo Basin
Note: (1) As reported in Ecopetrol’s Bid Round Summary Flyer – published December 2015
“These acquisitions are a continuation of Gran Tierra’s focused strategy to build a high-quality, diversified portfolio to efficiently create value in the multi-horizon, proven hydrocarbon producing basins of Colombia,” said Gary Guidry, President and Chief Executive Officer of Gran Tierra. “The Nancy-BurdineMaxine Block provides upside potential through EOR by investing in advanced drilling and waterflooding techniques. Having already established reserves and production in the Villeta N, T and U sands, the Nancy-Burdine-Maxine Block provides a core operating hub for the identified multi-horizon exploration drilling plans on adjoining Gran Tierra lands over the next 3 years.”
He continued: “Gran Tierra operated the Santana Block through July 2015 when the contract expired, so we know these assets well. The important fluid processing, and transportation infrastructure where we ship, under tariff, Costayaco, Moqueta and Guayuyaco production, will be the core transportation system as we explore and expand throughout the Putumayo. We will be able to scale the system as required, and maintain the efficient cost structure and appropriate investment timing being the operator of the network. As with the Nancy-Burdine-Maxine Block, the Miraflor, Mary, Linda and Toroyaco fields in the Santana Block provide upside with EOR investment, and multi-horizon exploration potential.”
(GeoPark Limited, 23.Nov.2016) – GeoPark Limited announced the successful testing of the Jacana 6 appraisal well in the Jacana Oil Field in the Llanos 34 Block (GeoPark operated with a 45% working interest) in Colombia.
GeoPark drilled and completed the Jacana 6 appraisal well to a total depth of 11,684 feet. A test conducted with an electric submersible pump in the Guadalupe formation, across multiple sand units, resulted in a production rate of approximately 1,800 bpd of 16 degrees API, with a 17% water cut, through a choke of 38/64 mm and wellhead pressure of 80 pounds per square inch. Additional selective interval testing and production history are required to determine the stabilized flow rate and water cut source. Surface facilities are in place and the well is already in production.
The Jacana 6 well was drilled to test the western limits of the field and is located approximately 1.7 km southwest of the successful Jacana 5 appraisal well which extended the northwest field boundaries and continues to produce at approximately 3,600 bopd with less than 1% water cut (at a formation depth approximately 50 feet down dip of the Jacana 6 well). The successful appraisal drilling in the Jacana Field this year has substantially increased the field size, as well as, grown field production to over 13,000 bopd gross from six wells.
As recently announced, GeoPark will focus the bulk of its 2017 work and investment program on appraising and developing the Tigana/Jacana oil trend to determine the full extent of the oil accumulation and continue to grow production. GeoPark’s total five country program (at a $45-50 oil price) is targeting 20-25% production growth from a fully-funded $80-90 million capital program and with a forecasted consolidated exit production of 30,000+ boepd net.
“Great rocks, big traps, high-recovery wells, growing scale, supporting infrastructure, good geography, efficient low costs, and fast cycle self-funding cash. The Tigana/Jacana oil complex is proving up all the ingredients of a world class oil play and a foundational asset to drive GeoPark’s value growth now and in the coming years,” said GeoPark Chief Executive Officer James F. Park. “Our team continues to push out the boundaries of the field with every new appraisal well. We still have the opportunity to drill 1-2 more development wells before the end of the year and are gearing up to drill another 15+ wells to further appraise this play in 2017.”
(Energy Analytics Institute, Pietro D. Pitts, 14.Sep.2016) – On a brief taxi ride from Punto Fijo’s Josefa Camejo International Airport to the main highway that crosses this city and connects to one of the many refining complex entrances here, a scrawny dog with mange can be seen emerging from an endless pile of discarded trash.
In this small refining town broken beer bottles, dirty diapers, and discarded personal items cling to trees and bushes as far as the eye can see in either direction along the short stretch of highway that separates the two massive refineries here: Amuay and Cardón. The refineries comprise the lion’s share of the processing capacity at PDVSA’s 971,000 barrel-a-day Paraguana Refining Complex, also commonly known as the CRP by its Spanish acronym. The CRP refineries combined with three others spread across this country have produced cumulative financial losses of $53 billion in the last eight years. Definitely not chump change.
Venezuela is home to a wealth of natural resources from gold to iron ore and holds the world’s eighth-largest natural gas reserves and the largest crude oil reserves, according to BP’s Statistical Review of World Energy. Yet, images of the immediate surroundings of the CRP paint a different financial storyboard about the well-being of Venezuela’s all important oil sector – which generates 96 percent of the country’s foreign export earnings.
Despite Venezuela’s claim to fame in terms of the size of its oil reserves, the South American country has been reduced to importing refined products because its refineries can’t meet local demand. The country’s refining sector is in a virtual state of emergency due to low processing rates, numerous unplanned plant stoppages, as well as accidents and injuries that state oil company Petróleos de Venezuela S.A. prefers to not report, according to oil union officials here. All summed up, PDVSA’s refining sector – especially within Venezuela – is a financial drain on the company as operating losses continue to mount year after year.
Venezuela – a founding member of the Organization of Petroleum Exporting Countries or OPEC — is engulfed in an economic crisis that started way before oil prices began their long downward trend. Political uncertainty, an ongoing threat of asset expropriations as well as currency and price controls have only helped to starve the capital-intense oil sector here of necessary foreign investments. PDVSA, as the Caracas-based company is known, continues to lack the necessary cash to properly revive the country’s oil sector in its majority partnership role, while local Venezuelan oil companies are few and in between and often lack the financial firepower of many of their international peers.
Many Venezuelan-based economists from Datanálisis President Luis Vicente León to Ecoanalitica Director Asdrubal Oliveros blame part of the economic crisis on the failure by former populist Venezuelan President Hugo Chávez to divert financial resources to the country’s private sector importers and the all-important upstream, midstream and downstream sectors during his tenure from 1999-2013 amid robust oil prices. In general, PDVSA’s problems mirror Venezuela’s economic crisis. The country’s economy has not fared any better under the presidential tenure of Nicolas Maduro, the man hand-picked by Chávez to succeed him prior to his untimely death in 2013. By most people’s accounts, considering the scarcities here of everything from milk to basic medicines, widespread looting, and runaway crime, things are much worst.
Oil-dependent Venezuela continues to rely heavily on its exploration and production or upstream sector to generate the bulk of its petroleum sector revenues. However, Venezuela’s oil output appears to be on an unstoppable decline, reaching 2,095,000 barrels per day in July of 2016 compared to 2,361,000 barrels per day in 2014, according to Organization of Petroleum Exporting Country’s Monthly Oil Market Report, citing secondary sources. Data from direct communications is just slightly more optimistic. Nevertheless, the downward continues.
Oil workers in red work overalls can be seen everywhere in the streets of Punto Fijo, either hailing taxis or waiting in the shade of trees for public transportation. Due to the ongoing economic crisis that has also affected Venezuela’s transportation industry – like countless other industries here – many cars and taxis in these parts and others in this resource-rich country don’t have air conditioning and/or visually lack some part or another such as a rearview or side mirror, working locks, a speedometer or a functioning trunk. The market for used tires, or anything used, is booming in Venezuela as new tire imports have come to a virtual halt.
Inside the CRP complex – physically off limits to visitors without permission from PDVSA but very visible through the wired fences — the scene within is arguably not much better, as years of under-investment on maintenance, upgrades and safety protocols by the state oil company have unfortunately left the refineries and the grounds similarly forsaken. Against a backdrop of a country in the midst of an ongoing political crisis, many refinery workers here say a combination of 12-16 hours work days, a lack of employee benefits and arguably the lowest salaries for refinery workers anywhere in the world (in dollar terms) has also taken a toll on them as well as their colleagues.
Whether the refineries or the workers are in worst condition, is a judgment call, but at first glance they both appear to be on their last legs.
In the last eight years, PDVSA’s refining, trade and supply division accumulated net losses in each of the consecutive years since 2008, which was the last time the division reported a positive gain from its combined operations in Venezuela. All tallied, the division accumulated losses of $53 billion during 2008-2015, according to data compiled from PDVSA’s financial reports.
“With a cash crunch they have focused all efforts in the upstream where you make the money,” said Francisco J. Monaldi, Ph.D. and Fellow in Latin American Energy Policy & Lecturer in Energy Economics at Rice University’s Baker Institute for Public Policy in an e-mailed response to questions. “The lack of human resources adds to the lack of investment to generate the operational difficulties.”
Refining sector stoppages and costly repairs are generating large production and economic losses for PDVSA, said oil union representative Larry López during a late afternoon sit down chat at a run-down restaurant just two blocks from the Amuay refinery.
Venezuela doesn’t need refineries to be a major exporting country, former PDVSA President Rafael Ramírez told me in 2014 during a company-sponsored media trip to visit the CRP on the anniversary of the deadly explosion at Amuay that left at least 48 people dead. To this day, it is unclear if those comments justify the lack of attention that has been given to the country’s refining sector even now under the leadership of Stanford-trained Eulogio Del Pino.
Venezuela’s Information Ministry, the clearing house for questions for all of the country’s ministries, and media officials with PDVSA and the Venezuelan Oil Ministry did not reply to emails seeking comment on the company’s refining sector strategy or general comments for this article. Venezuela’s newly elected Petroleum Chamber President was also unavailable to comment on this article.
“Our refineries have always produced products to cover demand in the domestic market as well as the Caribbean. To export to the US and Europe we really don’t need to have refineries,” said Carlos Rossi, president of Caracas-based consulting firm EnergyNomics and formerly an economist with the Venezuelan Hydrocarbons Association or AVHI, in an interview in Caracas.
“Because the refineries have been seen as a low priority, PDVSA has focused more attention on the Faja,” said Rossi referring to the Hugo Chávez Oil Belt, formerly known as the Orinoco Heavy Oil Belt, home to one of the largest non-conventional oil deposits in the world.
PDVSA’s total hydrocarbon workforce mushroomed during 2000-2015 as the company stressed more importance on political affiliation and less on university or technical experience, said Eddie Ramírez, the director of Gente del Petróleo and a former PDVSA employee, in a phone interview from Caracas. At year-end 2015, PDVSA employed 114,259 direct hydrocarbon sector workers, up from just 42,267 when Chávez rose to power in 1999, according to PDVSA data.
PDVSA’s refining sector, which employed 9,391 workers in 2015, represented just 8.2 percent of the company’s total workforce in that year. In 2010, just 3,584 workers were employed in the refining sector, which represented a mere 3.8 percent of PDVSA’s total workforce.
Given PDVSA’s cash problems and its inability to generate positive free cash flow, the company’s plans to build six new multi-billion dollar upgraders, boost oil production and refining capacity to 6,000,000 barrels per day and 1,800,000 barrels per day respectively by 2019 seem to be optimistic and represent a major challenge for the state oil company.
PDVSA owns six refineries in Venezuela, which the company reports are strategically located to supply refined products to its major consumers. The refineries – which had a total combined processing capacity of 1,303,000 barrels per day, as of year-end 2015 – produce a product slate including but limited to: 91 and 95 grade gasolines, jet and diesel fuel, light naphtha, liquefied petroleum gas, solvents and residuals.
Due to a combination of problems, the six refineries were just processing a combined 616,000 barrels per day in August 2016, translating into an average utilization for PDVSA’s domestic refineries of 47.3 percent, said Ivan Freites, an oil union official with the United Federation of Venezuelan Oil Workers or FUTPV, which represents a large portion of PDVSA’s workers, during an interview in Punto Fijo.
Two refineries are located in Venezuela’s western Falcon state including: Amuay, with a 645,000 barrel-a-day processing capacity; Cardón, with a 310,000 barrel-a-day capacity; while the smaller Bajo Grande is located in Zulia state, with a 16,000 barrel-a-day capacity. Together, the three refineries make up the CRP, according to PDVSA’s annual report for 2015, with a product slate destined 55 percent for the domestic market and 45 percent for the export market.
More centrally located is the El Palito refinery in Carabobo state with a 140,000 barrel-a-day capacity while the remaining two refineries located in Venezuela’s eastern Anzoátegui state include Puerto La Cruz, with an 187,000 barrel-a-day capacity and the smaller San Roque, with a 5,000 barrel-a-day capacity.
In 2015, Venezuela’s domestic refining sector reported average utilization rates of 66.2 percent, according to PDVSA’s operational and financial data from last year. This compares to an average utilization rate of 70.6 percent in 2014 and an average utilization rate of 72.8 percent during 2011-2014.
The CRP has suffered much more deterioration and lower utilization rates than the other refineries. Average utilization rates at the complex reached just 60.5 percent in 2015, down compared to 72 percent in 2011 and an average 67.7 percent during 2011-2014, according to PDVSA data, which differs to what oil union officials report.
“Average utilization rates at the CRP were just 53 percent in 2015,” said Freites, a stocky, long-time oil union official. “The complex is damaged to the point that it almost makes better sense to build new refineries than to fix the incalculable problems that exist.”
In contrast, average utilization rates at El Palito reached 71.4 percent in 2015, down from 90.7 percent in 2011 and an average 89.5 percent during 2011-2014 while at Puerto La Cruz rates reached 93.2 percent in 2015, up from 88 percent in 2011 and an average 88.6 percent during 2011-2014, according to PDVSA.
Figures reported by PDVSA are always overly positive and extremely optimistic, said Freites, 53, during an early happy hour brunch which included Venezuelan ‘tequeños’, a special mix here of fried cornmeal with cheese on the inside accompanied with another popular import here: whisky.
From oil towns in Midland, Texas to Maracaibo to Monagas and Punto Fijo in Venezuela, oil men have at least one thing in common: their love for food and the typical companions Grants, Chivas, and the rest of the supporting cast. However, the economic crisis here has forced many oilmen to settle for whatever is available at the kitchen table. With bottled water sometimes unavailable, Johnnie Walker becomes a name to trust.
PDVSA data differs significantly from that provided by oil union officials here and other international agencies due to the opaque operating and reporting nature of the state oil company. A quick comparison of Venezuela’s production figures as reported by PDVSA and Venezuela’s Oil Ministry as compared to figures reported by OPEC in its monthly reports or even BP in its yearly statistical review serve to prove the point.
Cash-strapped PDVSA recently reiterated plans to boost its domestic refining capacity to 1,800,000 barrels per day by 2019 but has not detailed plans for its existing refineries – which continue to process at less than optimal levels – and has been quiet about plans to build new refining capacity. Only the Puerto La Cruz refinery is known to be undergoing a deep conversion process aimed at boosting its ability to process heavier Venezuelan crudes, according to PDVSA.
Recent agreements signed by PDVSA with authorities from the governments of Aruba, Venezuela and Citgo Aruba related to the restart of a 209,000 barrel-per-day refinery located in San Nicolas, Aruba point to potential issues PDVSA may have building new refineries or even six planned new upgraders, a special type of refinery, due to financial constraints whereby at first glance it appears easier to buy refining capacity than build it from scratch.
It is not a priority to build refineries since it is much better to invest in upstream activities to maximize your limited resources, said Monaldi, also the founding director and a professor at the Center for Energy and the Environment at IESA in Venezuela. New refineries are not great moneymakers and require low capital cost to make any money, he said.
Just a handful of streets separate the Amuay refinery from the Las Piedras fishing neighborhood. Not far away, rusted out American gas-guzzlers like the Ford Maverick and even the Ford F-1, seemly pulled straight off the set of the 1970’s U.S. television show Sanford and Son, can be seen littering the narrow streets here as well as the ones behind Cardón refinery in the neighborhood that bears its name, Punta Cardón. Residents of the latter neighborhood, basically live under the constant flare of gas and whatever else might come from the refinery that is practically in their backyards.
All of PDVSA’s Venezuelan refineries seem to suffer from some type of operational deficiency. At any given time and sometimes at the same various units from different refineries are down for unplanned repairs ranging from the Amuay flexicoker, alkylation, and catalytic units; the Cardón distillation units; the three Puerto La Cruz atmospheric distillation units to the El Palito FCC unit, thus, drastically reducing domestic processing capacity and output, said Frietes. On a number of occasions in the past two years complete operations at PDVSA’s principal refineries have been halted due to operational issues.
Reduced utilization rates at the CRP have created shortages of oil derivatives including unfinished oils, lubricants, finished motor gasoline and special naphthas. As a result, Venezuela is importing more derivatives such as products for gasoline as well as light oils from the U.S. and even far off countries such as Russia and Algeria to mix with its heavy and extra-heavy crude oils produced in the Faja, even as it continues to offer oil to regional neighbors ranging from Cuba to Nicaragua under attractive financing terms.
Despite the need to import oil and products, Venezuelan oil exports continued to member countries belonging to regional initiatives ranging from the Cuba-Venezuela Cooperation Agreement (CIC) to PetroCaribe but declined 6.6 percent to 185,000 barrels per day in 2015 compared to 198,000 barrels per day in 2014, according to PDVSA data. The volumes in 2015 were down 27.3 percent compared to 255,000 barrels per day supplied to member countries in 2009.
“PDVSA continues to give away oil while in Venezuela inventories of gasoline, gasoil, diesel, LPG and lubricants are insufficient to cover domestic demand,” said Freites, a stern critic of PDVSA.
Operating deficiencies in Venezuela have created export opportunities for refiners along the North American Gulf Coast. U.S. net imports of oil and refined products from Venezuela ranging from distillate fuel oil to MTBE (oxygenate) averaged 751,000 barrels a day in the 12-month period ended June 2016 compared to 711,000 barrels a day in the same year-ago period, according to data posted to the U.S.-based Energy Information Administration’s website. However, U.S. net imports of the same products from Venezuela averaged 1,590,000 barrels-a-day in the 12-month period ended June 2001 in the early years of the Chávez government.
Productivity at the CRP is down due to the increase in workers and the decline in output, said a former PDVSA refinery safety manager who worked for 29-years at the company. He didn’t want to reveal his name since he still does contract work for PDVSA in Punto Fijo and feared retaliation from the company. Oil workers must be oil workers and not politically divided like today as it is affecting the productivity of the employees and the company, he said during an interview at a small building in downtown Punto Fijo which serves as the local office of the FUTPV.
“It is still politically hard to justify massive Imports. But the economics are very clear. In the long run, if you can sustain international market prices in the domestic market you may be able to open the downstream to private investment,” said Monaldi.
Grade school kids and university students blend into the scenery of an oil town gone bust. Many will never reach PDVSA’s professional ranks unless they have connections within the company and/or support the socialist ideas, or at least those expressed by Maduro and his government. More than anything, PDVSA refinery workers in faded red work overalls dominate the landscape in Punto Fijo and the surrounding towns seemingly unaffected by hot weather, strong wind gusts and refineries constantly emitting gas and other substances into the air. What has affected them is the continued economic crisis and low wages, many say here.
Under the sweltering sun, improvisations are the order of the day at the CRP for many refining workers frequently forced to scramble to solve recurring small problems turned into major ones due to the lack of basic replacement parts. The practice of using emergency stapling techniques to fix routine vapor leaks at processing units, or product leaks along pipelines, is commonplace nowadays, says Freites, who is the spokesperson for many refining and oil union workers not willing to go on record due to fear of retaliation or work dismissal from PDVSA.
Similar scenes are said to resonate at the Puerto La Cruz and El Palito refineries, said José Bodas, another oil union official, in a telephone interview from Carabobo state.
PDVSA is using stapling methods to fix pipeline and unit leaks instead of properly fixing or repairing them due to a lack of funds to procure the necessary replacement parts, said the former PDVSA safety manager. PDVSA is more reactive than preventative and is conducting more corrective maintenance than preventative maintenance due to the lack of financial resources. It’s not necessarily a money thing but just the way PDVSA works today, he said.
Lackluster security measures to protect the PDVSA refineries and workers have allowed crime incidents to edge up within the complexes’ gates. Stolen work bags and purses, missing clothing and other personal items and car break-ins are daily work hazards beyond those related to working in a domestic refining sector where accidents, sadly enough, are more the norm than in many other countries with refining operations. In the country with the highest murder rate in the world, according to the website WorldAtlas.com, not even the confines of the refinery complex are safe enough to shield workers from the realities on the streets in Punto Fijo, Ciudad Ojeda, Anaco and other major oil and gas towns across Venezuela.
Safety is no longer a priority for PDVSA as funds are being spent haphazardly on non-necessary projects, said the former PDVSA safety manager with his salt-and-pepper mustache and Italian surname. He says many current PDVSA bosses only respond to accidents when they are officially reported by the media.
On its part, PDVSA claims there were just 154 total injuries at the CRP, El Palito and Puerto La Cruz refineries in 2015. This compares to 173 in 2014, 276 in 2012, and 298 in 2010, according to PDVSA data in its social and environmental statements on its website. Still, union officials here say the numbers don’t reflect the real case scenario since a lot of accidents and injuries go undocumented.
As the sun falls over the horizon, workers use their mobile phones in some areas of the CRP seemly unaware of the work hazards. Thieves that regularly enter the complex via the various gate openings to rob copper, bronze, nickel as well as other materials and equipment, also rob workers of their mobile phones whenever possible. The resale market for mobile phone parts is big in Venezuela amid an economic crisis that has impacted not just food importers, but the telecommunications and airline industries as well, among others.
The multiplier effect on this town and surrounding communities can visibly be seen in the fishing regions of Punto Fijo from Las Piedras to Los Taques where white and blue collar oil workers in the good ole days would be seen almost everywhere eating and taking in the sun with family and coworkers or clients. That’s not the scene here anymore. Local mayors have for years promised money to fishing communities and fishermen in the region but many, like other family members, remain unemployed. Many have turned to crime to rob and steal things they can resell to get basics like food or medicines for their families.
“Whatever was taken over from the transnational companies doesn’t work here,” said Jaime Antonio Diaz, 44, during an interview at a lightless restaurant in Los Taques. “If the Fourth Republic was bad, then the Fifth Republic is the worst,” he said as a stray cat entered the premise through an entrance door kept open to let in fresh air and natural light.
Diaz’s comments refer to the two most recent republics in Venezuela. The Fourth Republic was the period in Venezuelan history marked by the Punto Fijo Pact in 1958 for the acceptance of democratic elections in that year. Nationalization of Venezuela’s oil industry was a point frequently criticized by Chávez as a one of many failures of the Fourth Republic. The Fifth Republic Movement (MVR by its Spanish acronym) was a leftist political party founded in the late 1990s by then-presidential candidate Chávez. It was later dissolved in 2007 to give way to Chávez’s new political party the United Socialist Party of Venezuela (PSUV).
From refinery workers fleeing low pay and increased worksite accidents to unemployed fishermen and engineers driving taxis, Punto Fijo is going through what many say is one of its worst periods in decades.
Within visible distance of the dirt roads of Los Taques nearly 30 or more towering wind power turbines can be seen off the immediate horizon on the return trip from Los Taques to Punto Fijo. Despite the strong winds here, the turbines are not operational and have yet to generate power for commercial or domestic usage, according to Freites, owing to corrupt deals between Venezuelan government officials and the company that supplied the towers. Venezuela – which has long suffered from a natural gas deficit in its industrialized western Zulia state – has plans to use non-associated natural gas production from the Cardón IV offshore project as well as power generated by these turbines to reduce the need to import costly diesel fuel. From the look of things here, it is quite obvious the latter is not something PDVSA officials want to openly talk or brag about. However, it’s safe to assume somebody made a killing on the turbine deal.
While the wind turbine project – like others envisioned in this small country with a population close to 31 million – looks good on paper in the boardroom, the corruption here more often than not turns the project into a financial bonus for some individuals at the costs of local jobs and wasted resources for a country teetering on the brink of financial default.
One thing continues to thrive here: the contraband of fuels. Contraband of cheap Venezuelan gasoline continues to nearby Colombia, Guyana, Trinidad and Tobago and Aruba despite efforts to deter it and a decision by this government to boost gasoline prices in February of 2016 to 6 bolivars a liter from 9.7 centavos. While demand for gasoline has declined in Venezuela due to economic crisis and a higher cost for gasoline, its elevated price is still quite low compared to nearby markets; thus, making it still very attractive for trade internationally.
Large fishing boats – refitted by the Venezuelan military and now under the control of military officers that pose as fishermen – continue to leave the pier near Las Piedras with domestic fuel. These so-called ‘gasoil mafias’ continue to exchange Venezuelan refined products on the high seas in international waters in seemingly another way the military is kept happy and loyal by Maduro and company, according to Rossi, author of the book ‘The Completion of the Oil Era: The Economic Impact (Energy Policies, Politics and Prices).’
Barefoot grade school kids with just shorts on, play baseball on the dirt roads and side streets in numerous poor communities in and around Punto Fijo. Using broomsticks and makeshift baseballs, they can be seen enjoying their game despite the extreme poverty they live in and not having gloves. Despite being a Latin American country, baseball, not soccer is the sport of choice here and seen here as the way to rise out of poverty, at least for many males. On the other side, females here dream of being Ms. Venezuela or Ms. World.
“This government only saves itself by changing the model,” said León, referring to what the Maduro government needs to do to stay in power.
Whether the model change comes tomorrow, next year or in 2019, Venezuela’s hydrocarbon sector is in need of drastic changes. However drastic and radical these changes may have to be, investors will continue to keep Venezuela on their radar screens, hoping for a chance to invest in the country with one of the largest resource bases on the planet. However, from the looks of things, with foreign diplomats and oil men continuing to get kidnapped here, Venezuela is not yet ready for the massive return of foreign companies or better yet the foreign companies aren’t ready to return under the existing circumstances.
The recently announced departure of Schlumberger, the world’s largest oilfield services company, should serve as a reminder to potential investors about the condition of the oil sector here which still contends with a massive brain drain of national and international talent from companies from Halliburton to Total, Chevron, Statoil and a host of smaller companies lacking the deep pockets to survive without quarterly or sometimes monthly cash flow.
“The low wages continue to produce brain drain and that makes worse the operational problems,” said Monaldi.
Top Venezuelan officials and PDVSA executives blame the economic and petroleum sector crisis here on an economic war waged they say by opposition leaders with the backing of persons and institutions from Bogotá, Miami, Washington and even Madrid. The open denial of internal problems created by widespread mismanagement, errored financial and economic decisions as well as a number of actions including asset expropriations have handcuffed the country’s private sector and brought the all-important petroleum sector to a near halt. That hasn’t stopped other countries from stepping in to fill the void when and where it is possible. Case in point: Algeria just started to supply oil to Cuba amid mounting issues at PDVSA.
The Amuay explosion on August 25, 2012, as regrettable as it was, was an early wake-up call about what PDVSA had (and has) become after more than a decade of so-called socialism. Amid continued corruption at PDVSA and a hydrocarbon sector where funds mysteriously disappear, the financial and economic dreams of a handful or more have smashed the hopes of many in Punto Fijo and all across this major oil producing South American country.
“A lot of people here are changing sides due to the mismanagement of resources by the Chávez and now the Maduro government,” said Ali, a 50-year old taxi driver of an old Toyota Corolla, who requested his last name not be used in this article for fear of retaliation from PDVSA or government officials.
Ali’s sentiment resonates across all parts of this country from many petroleum engineers and other professionals that have left the industry to drive a taxi, wait tables or do anything where the wages are better.
“The sad part of all this is that we could have another August 25th,” said Freites.
(Editing by Peter Wilson)
(Ecopetrol S.A., 24.Jun.2016) – Ecopetrol S.A. announced that it launched ‘Ronda Campos 2016,’ a public and competitive bidding process, the objective of which is to offer to oil and gas companies Ecopetrol’s stake and interests in 20 production assets located in the regions of Catatumbo, the Magdalena Middle and Upper Valley, Llanos and Putumayo.
‘Ronda Campos 2016’ is part of Ecopetrol’s new strategy for 2015-2020, which is based on creating sustainable value and more efficient operation of assets. One of the objectives of the ‘Ronda Campos 2016’ is the rotation of Ecopetrol’s portfolio in search of the greatest profitability for its shareholders.
The business opportunities offered have development potential in primary recovery and improved recovery. The fields are located near logistical facilities, which are an added attraction for small- and medium-sized oil and gas companies.
The process, which was presented to industry representatives, is a public bidding process addressed to national and international companies that would like to strengthen their position in Colombia or that seek to expand their operations in the country.
(Energy Analytics Institute, Jared Yamin, 15.Jun.2016) – Demand for fuels in Colombia increased 11 percent due to the closing of the border with Venezuela, wrote Colombia’s Energy Vice Minister in a twitter post.
The public policy is the assurance of the continuous supply of liquids, and even better when there is a sudden increase in demand.
(Ecopetrol S.A. 10.Jun.2016) – Ecopetrol S.A. reports that, on June 8, 2016, based on the authorization granted by the Ministry of Finance and Public Credit (Resolution 1657 of June 7, 2016) to subscribe, issue and place External Public Debt Bonds in the international capital markets, it reopened its 2023 Bond for $500 million.
The offering had an order book of $1.7 billion or 3.4 times the amount offered and participation of more than 130 institutional investors from the U.S.A., Europe, Asia and Latin America. This transaction ratifies investors’ confidence in the decisions that have been made to face the pricing environment and Ecopetrol’s future.
The resources obtained will be used for general corporate purposes, including the company’s investment plan for the current year. With this operation, the company has achieved financing for 2016 in an amount totaling approximately $1.27 billion, covers most of the company’s projected financing needs for 2016.
This offering was made pursuant to a shelf registration statement on Form F-3 that was filed with and declared effective by the Securities and Exchange Commission (SEC).
(GeoPark Limited, 8.Jun.2016) – GeoPark Limited announced the start-up of its drilling program in the Llanos 34 Block (GeoPark operated with a 45 percent working interest) in Colombia.
GeoPark’s 2016 drilling program in the Llanos 34 Block commenced the second week of June with the spudding of the Jacana 3 appraisal well and is expected to continue with the drilling of the Jacana 4 well. The Jacana oil field, discovered in September 2015, is currently producing approximately 5,700 b/d gross from two wells and is located south-west and on trend with the large Tigana oil field.
In Colombia, GeoPark is targeting to drill approximately 6 wells (including 1-2 exploration wells) in the Llanos 34 Block during 2016 to continue the company’s low cost economic production growth. This block became a leading geological and economic success story, providing multiple oil field discoveries year after year since it was started-up by GeoPark in early 2012.
These activities are part of the company’s risk balanced, fully funded and modular 2016 work program that can be rapidly adjusted based on different oil price scenarios to preserve cash or to accelerate growth.
(Gran Tierra Energy Inc., 8.Jun.2016) – Gran Tierra Energy Inc. announced the receipt of a positive decision from the Chamber of Commerce of Bogotá Center for Arbitration and Conciliation tribunal relating to its dispute with the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) of Colombia (ANH) with respect to whether all production from the Moqueta Exploitation Area of the Chaza Block exploration and production contract (Chaza Contract) was subject to an additional royalty (the HPR Royalty).
In its decision, the Tribunal found that the HPR Royalty under the Chaza Contract was only payable when the accumulated oil production from the Moqueta Exploitation Area exceeded five million barrels. That production threshold was reached on April 30, 2015, and since that time the Company has been paying the HPR Royalty on production from the Moqueta Exploitation Area.
“Gran Tierra values the cooperative relationship that it has with the ANH and we are pleased that this issue has been resolved,” said Gran Tierra President and Chief Executive Officer Gary Guidry.
(Fitch Ratings, 8.Jun.2018) – Fitch Ratings rates the $500 million reopening of Ecopetrol S.A.’s 5.875% notes due in 2023 ‘BBB’.
The company expects to use the proceeds from the proposed reopening for general corporate purposes, including capital expenditures.
Fitch’s Foreign and Local Currency Issuer Default Ratings (IDRs) for Ecopetrol are ‘BBB’ and ‘BBB+’, respectively, with a Stable Outlook. The company’s ratings reflect the close linkage with the Republic of Colombia (FC/LC IDRs ‘BBB’/’BBB+’), which currently owns 88.5 percent of the company.
Ecopetrol’s ratings also reflect its strong financial profile and improving production levels. Ecopetrol’s recently revised growth strategy and associated CAPEX plan are considered adequate for the company’s credit quality and cash flow generation ability. Ecopetrol is expected to maintain a financial and credit profile consistent with the assigned rating.
(Ecopetrol S.A., 7.Jun.2016) – Ecopetrol S.A. announced that its Board of Directors, in a session held on June 6, 2016, approved the implementation of “Hedge of a net investment in a foreign operation” accounting as established under the International Accounting Standard IAS 39 (paragraph 102) and Decrees 2420 and 2496 of 2015 regarding International Financial Reporting Standards (IFRS). The decision seeks to reduce the volatility within the nonoperational results of the company due to the effects of fluctuations in foreign exchange rates.
The net investment hedge will apply to a portion of the foreign currency investments that the Company owns and whose functional currency is the U.S. dollar, with the hedging instrument being the portion of our dollar denominated debt that generated a net liability position by the end of May.
As from the adoption of net investment hedge accounting, the effect of fluctuations in the foreign exchange rate on the hedged instrument will be recognized as Other Comprehensive Income (OCI) in Equity, where currently the foreign exchange effect on subsidiaries which have the U.S. dollar as their functional currency is recorded when accounted under the equity method. This policy is subject to a test of effectiveness and the ineffective portion will be recognized in profit or loss.
The amounts recognized in OCI will be taken into profit and loss only if and at such time the investments designated for purposes of the net investment hedge are sold. In the meantime such fluctuations will remain in Equity, even after debt payments are made.
The net investment hedge will be applied prospectively from June 7, 2016. This accounting change will be treated alike for both Colombian IFRS and IFRS as issued by the IASB.
(Moody’s, 4.Jun.2016) – Oleoducto Central S.A. (Ocensa) is the largest crude oil pipeline and the only public-use pipeline in Colombia. Its pipeline is ~845 km in length with 745,000 b/d of capacity starting in mid-2016. Ocensa connects the country’s largest crude producing fields in the Llanos Basin at El Porvenir to export facilities at Covenas on the Caribbean coast.
The company is owned 72.65 percent by Ecopetrol through its wholly-owned midstream subsidiary, Cenit SAS. The remaining stakes are owned 22.35 percent by Advent International and 5 percent by Darby Overseas (a subsidiary of Franklin Templeton), both private equity firms. Advent purchased its stake in December 2013 from long-time owner/shippers Total SA, Repsol Oil & Gas Canada Inc. formerly Talisman Energy Inc., and CEPSA, a Spanish refining subsidiary of IPIC, an investment fund of the government of Abu Dhabi.
(Ecopetrol S.A. 2.Jun.2016) – Ecopetrol S.A. announced that on June 1, 2016, through the X-STREAM trading system of the Colombian Stock Exchange (Bolsa de Valores de Colombia S.A.), the second auction was held for the second stage of the program to divest and sell 278,225,586 of Ecopetrol’s shares of the company Empresa de Energía de Bogotá S.A. E.S.P. (EEB).
The equity divestment plan was approved by the National Government of Colombia through Decree 2305 of 2014. As all of the shares offered in the second auction were purchased, Ecopetrol has the option of holding up to two additional auctions for the remaining number of shares, 86,585,888, in the time and manner indicated in the offering notice.
(Energy Analytics Institute, Jared Yamin, 1.Jun.2016) – Colombia needs to invest an estimated $7 billion per year over a ten-year period or under to remain self-sufficient in the production of petroleum.
The outlook for Colombia’s petroleum sector in terms of self-sufficient is ‘reserved,’ reported the daily newspaper El Tiempo, citing Colombia’s Petroleum Association (ACP by its Spanish acronym) President Francisco José Lloreda.
Expected investments of $3.82 billion on exploration and production activities may not materialize, announced the official, adding that no seismic has been shot in 2016.
“If the tendency does not change, by the year 2022 production could fall below an average of 400,000 barrels per day,” said Lloreda. “This would be when that it would be necessary to import crude for the Cartagena and Barrancabermeja refineries.”
We require a competitive fiscal regime, said Lloreda, referring to what is needed to attract investments.
(Gran Tierra Energy Inc., 31.May.2016) – Gran Tierra is increasing its base 2016 capital budget by $33 million to $43 million to a revised total of $140 million to $150 million. The company’s previously announced base capital budget was $107 million.
The increased capital investment will be entirely directed at exploration in Colombia and will allow the drilling of two additional, 100 percent working interest exploration wells, including one additional N-Sands exploration well in the Putumayo Basin. The increased budget will also allow for the acquisition of additional 2D seismic in the Sinu Basin, and accelerated lease construction and environmental impact assessment work in preparation for the company’s 2017 Colombian exploration drilling program.
Gran Tierra’s 2016 production guidance remains unchanged. The 2016 average working interest production before royalties from the company’s assets in Colombia and Brazil is expected to average approximately 27,500 to 29,000 barrels of oil equivalent per day (boe/d), representing an increase of 20 percent over our 2015 average production of 23,400 boe/d. The 2016 production guidance includes 900 to 1,000 boe/d of production from the company’s assets in Brazil.
Credit Facilities Update
The committed borrowing base under Gran Tierra’s credit facility has been modestly reduced from the previous $200 million to $185 million, with $160 million readily available and $25 million subject to the consent of all lenders. Recognizing the challenging commodity price environment and the impacts on the estimated value of producing reserves, Gran Tierra management is pleased with the continued support of the lending banks to maintain liquidity which complements operating cash flow and supports future growth. The credit facility is currently undrawn and the maturity date remains the same at September 21, 2018.
Drilling lease construction is underway for the Cumplidor-1 exploration well in the PUT-7 block, which the company continues to expect to spud in early third quarter 2016. This well is expected to be followed immediately by the Alpha-1 exploration well from the same drilling pad. These wells are the first to test the N-Sands exploration play in PUT-7 in the Putumayo Basin, which Gran Tierra believes is highly prospective and expects to lead to long term reserve and production growth.
The Moqueta-22 development well has been successfully drilled and completed and over a combined test period of 24 hours to 23:00 Bogota time on May 30, 2016, the well produced on pump an average of 438 barrels of oil per day, 205 barrels of water per day and 654 thousand standard cubic feet per day from the Caballos and T Sand formations. Clean up and running of the final completion equipment for this well continue. The Moqueta and Costayaco 2016 development drilling programs have now concluded. Both oil fields are expected to provide significant free cash flow starting in the second half of 2016, which would allow Gran Tierra to fully fund its multi-year exploration program in Colombia.
“We are pleased to be in a position to accelerate our exciting Colombian exploration program. We are expecting regulatory approvals for several key exploration prospects over the next few months,” said Gran Tierra President and Chief Executive Officer Gary Guidry. “The substantial recovery in the Brent oil price since its multi-year low in January 2016 also gives Gran Tierra an opportunity to accelerate some key exploration drilling and seismic activities in Colombia while continuing to pursue opportunities to expand the Company’s portfolio in an effort to increase net asset value per share for shareholders. ”
Guidry continued: “We are also pleased with the result of the May 2016 redetermination of the borrowing base for our credit facility. Our credit facility provides a solid foundation and readily accessible financial resources for growth in Colombia. The ongoing support we received from the lending banks demonstrates the underlying confidence in our producing assets, our team and the business environment in Colombia. Our new hedging position provides us with downside oil price protection as we increase our exploration spending in today’s volatile commodity price environment. With $81 million of working capital at March 31, 2016, $109 million of net proceeds from our convertible senior notes offering in April 2016, strong cash flow, $160 million of available borrowings under our undrawn credit facility and, subject to lender consent, an additional $25 million available under our credit facility, we continue to be well positioned to allocate capital to explore, develop and grow reserves and add value through acquisitions. Our team is focused on emerging from this low oil price environment as one of the strongest intermediate international exploration and production companies.”
(Energy Analytics Institute, Jared Yamin, 21.May.2016) – Mexican conglomerate Alfa considers its entire $1 billion in investment in Pacific Exploration & Production — the Canadian oil company with operations in Colombia — as a total loss after the oil company announced plans to restructure its debt with a private fund, reported Reuters, citing an unnamed company executive.
In April of 2016, Pacific reached an agreement with its creditors and Catalyst Capital Group investment fund related to its financial restructuring. The deal, expected to conclude during the third quarter of 2016, left Alfa out of the process.
The agreement with creditors practically made them owners of Pacific by diluting the stockholder’s participation down to zero, said Alfa General Director Álvaro Fernández.
Alfa’s investment in Pacific fell to $38 million in the first quarter of 2016 due to the fall in oil prices. Alfa invested $1 billion in the Pacific in 2014 to acquire a 19 percent interest in the company.
(Energy Analytics Institute, Jared Yamin, 11.May.2016) – Colombia needs to reinforce existing regulations to stimulate public and private sector investments in sustainable energy projects and improve its energy efficiency, announced CAF during the Seventh Energy Efficiency Seminar held on April 21, 2016 in Bogota, Colombia.
Colombia has potential to invest $30 million related to projects to improve energy efficiency on projects ranging from replacement of industrial furnaces with more efficient models to the installation of air condition sensors in hotels throughout the country, said CAF.
(Ecopetrol S.A. 10.May.206) – Ecopetrol S.A. announced that Moody’s Investors Service has maintained Ecopetrol’s credit rating at Baa3.
This confirmation means that the company will retain its investment grade rating, which had been assigned to it by Moody’s on January 18, 2016, and concludes the ratings review initiated on January 16, 2016.
In its report, Moody’s highlighted the company’s adjustment to its investment plan to protect its liquidity, the increase in refining capacity due to the start-up of the Cartagena Refinery, and favorable results in the midstream segment. It also noted the efficiency program, which has enabled Ecopetrol to successfully face the challenging low crude oil price environment.
Moody’s also established the company’s outlook as negative, due to the impact that low international crude oil prices may have on the exploration and production segments.
(Energy Analytics Institute, Jared Yamin, 10.May.2016) – EIG Global Energy Partners has proposed a $250 million capital injection in ailing oil producers Pacific Exploration & Production Corp. as part of its restructuring, reported Reuters.
(Moody’s, 4.May.2016) – Moody’s affirmed Oleoducto Central, S.A.’s (Ocensa) Baa3 senior unsecured ratings. The rating outlook was changed to negative from positive.
“The equalization of Ocensa’s ratings and outlook to those of Ecopetrol, S.A. (Ecopetrol, Baa3 negative) reflects Moody’s view that Ocensa is not insulated from the credit quality of its main shareholder and controlling entity,” said Nymia Almeida, a Senior Credit Officer in Moody’s. “The change in outlook to negative from positive also incorporates the negative oil production growth trend in Colombia, offset by our expectation that Ocensa will remain the transportation of choice in the country.”
Ocensa’s Baa3 rating reflects its leading industry position in Colombia and strategic importance to Ecopetrol as well as favorable industry dynamics in Colombia in terms of transportation demand for pipelines.
The company’s ratings also incorporate its tariff and contract structure that supports solid margins and predictable cash flow as well as a moderate financial leverage profile. These factors help offset its exposure as a single-asset pipeline, its relatively small scale within the midstream peer group, and a high dividend payout policy.
The company is close to completing its latest major growth project, which will increase its transportation capacity to 745,000 b/d from 610,000 b/d. In addition, the last tariff revision, in late 2015 and valid for the next four years, kept the prevailing tariffs unchanged. Both events will increase Ocensa’s cash generation, which will further strengthen its credit metrics starting in mid2016.
Although political and guerilla risk in Colombia is a lingering concern, Ocensa has not directly experienced any problems in recent years and its 100 percent underground pipeline system gives the company a competitive advantage.
Ocensa has adequate liquidity, with operating cash needs of about $50 million versus the company’s policies to maintain a minimum of $100 million in cash at all times as a cushion. Starting this year, CAPEX will be small and limited to maintenance only. In addition, the company’s next major debt payment is due in 2021. However, Ocensa pays out 100 percent of net profit in dividends, which is detrimental to bondholders. The company has no committed bank facilities but has close relations with Colombian banks.
Although Moody’s expects that Ocensa’s credit profile and cash flow generation will remain strong given its predictable tariff structure and high capacity utilization, the negative outlook reflects Ocensa’s strong ties with Ecopetrol, its controlling shareholder and main off-taker.
Large projects or acquisitions that increase financial leverage could trigger a negative rating action, although Moody’s believes that Ocensa’s management and Ecopetrol are aligned in a desire to maintain modest leverage at the pipeline. A downgrade of Ecopetrol’s or Colombia’s sovereign rating could result in a rating downgrade for Ocensa.
For Moody’s to consider a ratings upgrade, Ocensa would have to sustain current credit metrics but show lower vulnerability to Ecopetrol’s financial profile and have a dividend policy more aligned with the interests of bondholders. An upgrade of Ecopetrol could also result in a upgrade of Ocensa’s ratings. A rating upgrade of Colombia’s sovereign rating would not necessarily trigger a rating upgrade of Ocensa.
(By Ecopetrol S.A. 3.May.2016) – Ecopetrol S.A. announced Ecopetrol Group’s financial results for the first quarter of 2016, prepared and filed in Colombian pesos (COP$) and under International Financial Reporting Standards (IFRS) applicable in Colombia.
— Amid the lowest Brent price of the last 12 years, in the first quarter of 2016 the Group achieved a net income attributable to shareholders of Ecopetrol of COP$363 billion.
— Net income attributable to shareholders of Ecopetrol, increased 127 percent as compared to the first quarter of 2015.
— Solid cash flow generation with an Ebitda margin of 39.5 percent, resulting in an Ebitda of COP$4.1 trillion for the first quarter of 2016.
— Group’s savings amounted COP$421 billion during the first quarter of 2016. The company continues to demonstrate its capacity to adapt under an adverse price scenario.
Ecopetrol S.A. President Juan Carlos Echeverry G. commented on the results:
“The price environment in the first quarter of 2016 continued to defy the oil industry, which saw the value of crude reach $28/barrel, a 12 year record low. Ecopetrol, however, managed to generate profits amid this challenging environment, focusing its efforts on reducing costs, increasing efficiency, producing profitable barrels and prioritizing cash generation.
During the first quarter of 2016 the price of Ecopetrol’s crude basket fell 43 percent and its refining margin fell 24 percent in comparison to those of the same period of 2015. The actions undertaken to operate more efficiently and with lower costs, coupled with the positive impact of the devaluation of the exchange rate over our revenues and the recording of a lower financial net loss allowed to register a growth of 127 percent in net profit attributable to shareholders and to improve the EBITDA margin compared to those of the first quarter of 2015. Additionally, the company maintained its operating margins and EBITDA at approximately COP$4,000 billion compared to the same quarter.
Savings in costs and expenses contributed to the obtained results, these amounted to COP$421 billion in the first quarter of the year, against a target of COP$1,600 billion for all 2016. The efficiencies are mainly due to the optimization of purchasing and contracting plans, better procurement strategies and renegotiation of contracts.
The reduction of the lifting cost, cash cost of refining and transportation costs, reported in the first quarter of 2016, compared to the same period last year, are a result of the progress made by the company pursuant to the Transformation Plan, the devaluation of the COP/USD exchange rate and austerity and activity reduction measures implemented in all business segments. Ecopetrol is working so that the obtained efficiencies become structural even in an environment of increasing prices in order to ensure profitable operations and financial sustainability.
The adjustments in CAPEX and OPEX implemented since 2015, in line with lower oil prices and the strategic prioritization of value over volume led to programmed lower activity and lower production in the first quarter of 2016, which came to 737 thousand barrels equivalent per day, compared to 773 thousand in the first quarter of 2015. This fall also reflects the natural decline and the temporary closure of some fields caused by low profitability or judicial decisions. Once market conditions and cash availability improve, the company expects to increase levels of investment in exploration and production and give way to investments that have been postponed in this low crude oil price environment.
In exploration, the deep water appraisal well Leon 2 in the Gulf of Mexico of the United States was completed. This one is operated by Repsol, which holds a 60 percent stake. The remaining 40 percent belongs to Ecopetrol America Inc. The company is awaiting the results of the evaluation of the information provided by the well, located in one of the regions with the greatest potential for hydrocarbons in deep waters in the world.
Between the first quarter of 2015 and 2016 the gross margin of the refining segment decreased by $4.5 per barrel mainly as a result of market conditions marked by lower spreads between prices of middle distillates and the price of oil.
The Cartagena refinery continued its boot and stabilization process, obtaining a regular operation of the delayed coking, catalytic cracking and diesel hydro-treaters units. As of March 31, 28 units of a total of 34 were operational. It is expected that all units in the complex will be in full operation by the second half of 2016. Additionally, loads of crude up to 140 thousand barrels of oil a day have been achieved.
Test of high viscosity crude transportation were started in February 2016. Satisfactory results were obtained moving oil with a viscosity of 405 centistokes (cSt). This project, along with the expansion of capacity in Ocensa (P-135) will reduce the cost of dilution which is key to the production of heavy crudes, which today represent about 58 percent of the total production of the Group.
In December 2015 the company imposed a significant cut on its 2016 investments compared to the levels of previous years with the approval of a budget of $4,800 million. The need to preserve the financial sustainability of the company with the low oil prices environment prompted a further cut in the investment plan for 2016, which now will range between $3,000 and $3,400 million. The expected production was adjusted to this new reality from 755 thousand barrels per day to approximately 715 thousand barrels of oil equivalent per day.
2016 is a transition year for the Ecopetrol Group during which the cycle of investments in Midstream and Downstream will conclude with some transport projects and the startup of the Cartagena refinery. From 2017 on the company will devote a greater proportion of its investments to Upstream.
Financing needs for this year are in the $1,500 – $1,900 million range, without taking into account the resources that may be obtained from the company’s divestment plan. To date, $475 million has already been obtained through credit facilities with local and international banks.
Cash flow was also leveraged by the results of the auction of Ecopetrol´s stake in ISA held in April 2016, which allowed allotting shares in the amount of COP$377 billion.
Shareholders also contributed to the financial strengthening of the company with the decision not to distribute dividends in 2016, which was made during the last general meeting of shareholders.
Operational excellence, focus on capital discipline, rationalization of investments and rotation of the portfolio of assets to generate cash flow have enabled Ecopetrol to successfully navigate the current price environment.
Ecopetrol continues to position itself for the future by strengthening its portfolio of exploration and production in order to seize opportunities that may be generated in the next cycle of higher crude oil prices. In this way we can ensure growth in the long term, financial sustainability and value creation for Ecopetrol.”
(Ecopetrol S.A., 27.Apr.2016) – Ecopetrol S.A. announced that in light of the current low crude oil price environment, and with the aim of protecting the company’s cash flow and financial sustainability, its Board of Directors approved an adjustment to the 2016 Investment Plan, from $4.8 billion, as approved on December 2015, to a range between $3 and $3.4 billion.
2016 is a year of transition for the Ecopetrol Group, during which investments will be made to finish transportation projects and complete the start up the new Cartagena Refinery. Starting in 2017, the company will dedicate a larger portion of its investments to the exploration and production segments.
In exploration and production, resources will be allocated to the development of principal fields and the assessment of exploratory findings. 93 percent of funds will be invested in Colombia and the rest overseas.
The resources required for the investment plan will be obtained from internal cash generation, divestment of non-strategic assets and financing. Financing needs for 2016 remain within the range of $1.5 billion and $1.9 billion for the Ecopetrol Group.
(Gran Tierra Energy Inc., 6.Apr.2016) – Gran Tierra Energy Inc. announced, through one of its wholly owned subsidiaries, recently transacted Colombian peso (COP) hedges with two banks, providing additional stability to forecasted cash outflows for approximately 110 billion COP or $36 million from June 2016 to May 2017. To complement the recently announced commodity hedges for forecasted production which cover the same period, Gran Tierra has hedged certain forecasted COP denominated costs, with multiple underlying contracts to provide downside protection from an appreciation in COP at foreign exchange rates below 3,000 COP per USD to December 31, 2016 and 3,100 COP per USD to May 31, 2017, but also allow upside participation in a depreciation of the COP at foreign exchange rates up to 3,265 COP per USD and ranging as high as 3,370 COP per USD.
Gran Tierra management believes that the added protection from fluctuations in these USD equivalent costs is prudent and the recent weakening of COP rates provides an opportunity to stabilize cash flows.
(Gran Tierra Energy Inc., 6.Apr.2016) – Gran Tierra Energy Inc. announced that it has completed its previously announced offering of $100 million aggregate principal amount of 5.0% Convertible Senior Notes due 2021 in a private placement to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended, in the United States and pursuant to certain prospectus exemptions in Canada. Gran Tierra has also granted the initial purchasers a 30-day right to purchase up to an additional $15 million aggregate principal amount of Convertible Notes.
The Convertible Notes will pay interest semi-annually at a rate of 5 percent per annum, and will mature on April 1, 2021, unless earlier redeemed, repurchased or converted in accordance with their terms. The Convertible Notes will be convertible into shares of Gran Tierra common stock, initially at a rate of 311.4295 shares of common stock per $1,000 principal amount of Convertible Notes. This represents an initial effective conversion price of approximately $3.21 per share of common stock. The initial conversion price represents an approximately 30 percent premium to the $2.47 per share closing price of Gran Tierra’s common stock on the NYSE MKT on March 31, 2016. The Convertible Notes will be convertible at the option of the holder at any time prior to the close of business on the business day immediately preceding the maturity date. Gran Tierra will be required to offer to repurchase the Convertible Notes if a fundamental change, as defined in the indenture relating to the Convertible Notes, occurs. In addition, the conversion rate will be increased with respect to Convertible Notes converted in connection with specified fundamental change transactions.
The net proceeds from the offering were approximately $95.4 million, after deducting the initial purchasers’ discount and the offering expenses payable by Gran Tierra. Gran Tierra intends to use the net proceeds from this sale of the Convertible Notes for general corporate purposes, which may include acquisitions and/or capital expenditures.
(GeoPark Limited, 27.Aug.2015) – GeoPark Limited announces a new oil field discovery following drilling of exploration well Chachalaca 1, located on the Llanos 34 Block in Colombia. GeoPark operates and has a 45% working interest in the Llanos 34 Block.
GeoPark drilled and completed the Chachalaca 1 exploratory well to a total depth of 12,270 ft. A test conducted with an electrical submersible pump in the Mirador formation, at approximately 11,606 ft, resulted in a production rate of approximately 1,100 b/d of 30 degree API, with approximately 6% water cut. Further production history is required to determine stabilized flow rates of the well and the extent of the field.
“The Chachalaca find is our seventh oil field discovery since we entered the block in 2012,” reported GeoPark, citing company CEO James F. Park. “The Llanos 34 Block – particularly the Tigana and Tua oil fields – represents attractive low risk, low cost and high netback fields which provide a profitable production base during periods of low oil prices as currently being experienced.”
GeoPark’s drilling campaign restarted in June 2015 with 2 rigs currently operating in Colombia. As of the date of this release the company is drilling the Jacana 1 exploration well and the Tilo 2 appraisal well, both in the Llanos 34 Block. Testing of these wells is expected to be conducted in the following weeks.
For the year 2015 the company implemented a self-funded and flexible work program that can be adjusted to different oil price scenarios to match cash flows from operations.
(Ecopetrol S.A., 14.Aug.2015) – Due to the resignation of Mr. Gonzalo Restrepo Lopez and the election of his replacement, the CEO of Ecopetrol S.A. hereby calls on Shareholders to attend the extraordinary shareholders’ meeting to be held on 4.Sep.2015, starting at 7:30 a.m. at Ecopetrol’s auditorium located in Cra.13 No. 36 – 24, Bogota, Colombia.
The agenda of the meeting will be: – Safety guidelines, – Quorum verification, – Opening by the CEO of Ecopetrol, – Approval of the agenda, – Appointment of the President for the meeting, – Appointment of the Commission in charge of scrutinizing elections and polling, – Appointment of the Commission in charge of reviewing and approving the minutes of the meeting, and – Election of the Board of Directors (originated in the vacant position due to the resignation of Mr. Gonzalo Restrepo Lopez as director of the Board). The resumes of the current directors and the candidate nominated by the majority shareholder to fill the vacant position are available on Ecopetrol’s Web site.
Shareholders that are not able to attend the Shareholders’ Meeting may be represented through a proxy, granted in writing, pursuant to the requirements provided for under Colombian Corporate Law. In order to facilitate the fulfillment of these requirements, shareholders are allowed to download from the website, various proxy models that have been designed for each relevant case.
Except for the cases of legal representation, officers and employees of Ecopetrol shall not be entitled to represent shares other than their own, while in exercise of their posts, nor shall be allowed to substitute the powers of attorney conferred upon them.
In all events, shareholders’ representation shall be subject to the rules set forth under Colombian Corporate Law and Securities Regulations, concerning illegal, unauthorized and unsafe practices by the issuers of securities.
(Ecopetrol S.A., 5.Aug.2015) – Ecopetrol announced Ecopetrol Corporate Group’s financial results for the 2Q:15 and the 1H:15, prepared and filed in Colombian pesos (COP$) and on the basis of International Financial Reporting Standards (IFRS).
According to Article 3 of Decree 2784 of 28.Dec.2012 , the application date of the new technical framework is 31.Dec.2015 , therefore, the financial information presented prior to this date is subject to adjustments. As indicated in paragraphs 9 and 18 of International Accounting Standard 27 “Consolidated and Separated Financial Statements,” Ecopetrol and its Corporate Group must present their financial information on a consolidated basis, combining the financial statements of the parent company and its subsidiaries line by line, adding assets, liabilities, shareholder’s equity, revenues and expenses of a similar nature, removing the reciprocal items between the Corporate Group and recognizing the non-controlling interest.
The financial results in this report are not comparable line by line with the previously issued financial results for the 2Q:14, which were prepared in accordance with the Public Accounting Regime (Regimen de Contabilidad Publica) as adopted by the Colombian National Accounting Office. For the sake of comparison, the financial results that were already reported in the 2Q:14 are presented in this report under IFRS.
Some figures in this release are presented in U.S. dollars (US$) as indicated (Editor’s Note: Tables Not Available in this edition). The exhibits in the main body of this report have been rounded to one decimal. Figures expressed in billions of COP$ are equal to COP$1 thousand mln.
In the opinion of Ecopetrol’s CEO Juan Carlos Echeverry G.:
“Ecopetrol is disciplined with its costs adjustment program, aimed to gain efficiencies in different areas. Thus, we have already obtained savings of COP$0.6 tln. These savings are mainly the result of renegotiations with our contractors. We have solidified our long term relationship; our allies understand that the current circumstances call for extraordinary actions, and the mutual commitment to mitigate the effects of this scenario of low oil prices.
The Barrancabermeja refinery is now more efficient, thanks to the operation of the new turbo gas unit, which will translate into efficiencies in the energy generation cycle and a lower emission of greenhouse effect gases of 200 thousand tons equivalent per year. We also improved the cost of drilling by lowering the average number of days required by well, in Castilla and Chichimene fields, from 34 days in 2014 to 28 in 2015.
Facing a challenging oil price scenario, the company is adopting the adjustments required, based on its recently announced strategy, to continue searching for efficient and profitable barrels.
In our transformation plan we identified 630 initiatives throughout the company, aiming at savings of COP$ 1.4 tln in 2015. We are promoting ethic and transparency in our purchase and contracting processes, and investment projects.
We continue to prioritize the lives of people and workers, the well-being of the communities in which we operate and the environment. The accident frequency index in Ecopetrol was reduced by 38% between the 2Q:14 and the 2Q:15, from 0.77 to 0.49 accidents/million hours of labor, reflecting improved labor conditions.
On another front, Ecopetrol was subject of an irrational wave of attacks against our transportation infrastructure in June, in some provinces located next to Venezuela and Ecuador’s borders. The company demonstrated, once again, its capacity to face the crisis by deploying 500 workers to stop the leakage in the Mira River and do all the cleaning tasks necessary to mitigate the damage caused.
In the finance area, this quarter was better than the previous due to the growth trend shown by crude and product prices, while the exchange rate, which holds a negative correlation to these, reversed part of the trend toward devaluation shown in the first quarter. This was achieved despite the deterioration in environment conditions around Jun.2015, stemming from attacks on transport infrastructure, which as we have repeatedly said, not only affected operations but caused irreparable damages to the environment and surrounding communities.
Production in the 2Q:15 reached 768 Mboe/d, in line with the goal of 760 Mboe/d, announced for 2015, representing an increase of 5% compared to production in the 2Q:14. This was the result of the opening of new facilities and the new drilling campaigns in the fields Castilla and Chichimene, as well as the normal operation of Cano Limon field throughout most of the quarter.
In exploration, drilling continued on the well Kronos, located offshore in the southern Caribbean (operated 50-50 by Anadarko in partnership with Ecopetrol), and drilling began on the well Sea Eagle in the U.S. Gulf of Mexico (operated by Murphy, WI 35%; Petrovietnam, WI 15%; and Ecopetrol America Inc, WI 50%).
In Jul.2015, Kronos well confirmed the presence of gas in ultra-deep waters. The discovery proves the geological model proposed for an unexplored area, with high hydrocarbon potential.
The refining margin of the Barrancabermeja refinery was $17.20/bbl in the 2Q:15, 58% more than in the 2Q:14 ($10.9/bbl). This was the result of better prices of refined products compared to crude and the higher yield of medium distillates.
The volume of crude transported in the 2Q:15 declined by 4% compared to the 1Q:15, due to the increased number of attacks on transport infrastructure, with 2 in the 1Q:15 and 44 in the 2Q:15, 36 of these in the month of June. Compared to the 2Q:14, volume transported increased by 7.8%.
In our commercial activity, in line with our strategy of diversifying the destination of our products, we exported to South Korea and the U.S. East coast. Also, with the purpose of increasing our footprint in the Asian market, we announced our first shipment of crude to Japan, following the conclusion of negotiations with the company JX Nippon, which bought 2 MMbbls of Castilla crude to supply its refining systems.
The improved financial result in the 2Q:15 compared to the 1Q:15 is the outcome of better crude realization prices, which increased from $43/bbl in the 1Q:15 to $53/bbl in the 2Q:15. Although cost of sales showed an increase of 10% compared to the 1Q:15, given the higher costs of maintenance, purchases and product imports, when compared to the 1Q:14 we had a reduction of 11%, reflecting the cost optimization strategies that are gradually beginning to materialize. In line with this, we achieved a $2.32/bbl reduction of our lifting cost, as a result of optimizations, between the 2Q:15 and the 2Q:14.
Our operating expenditures continued under control. Although in the 1Q:15 we recorded the applicable wealth tax for year 2015, in the 2Q:15 financial expenses were also reduced due to a lower impact of the exchange rate difference.
Thus, in the 2Q:15, the Corporate Group’s net revenue, attributable to Ecopetrol shareholders, was COP$1.5 tln pesos, compared to COP$0.16 tln in the 1Q:15 and COP$2.6 tln in the 2Q:14.
On another note, this past 26.May.2015, we announced to the market our new 2015-2020 strategy, aimed at profitable growth in exploration and production and maximization of efficiencies in transport and refining.
The strategy prioritizes value over volume, with emphasis on financial discipline, streamlining investments and divestment of non-strategic assets. The plan also foresees profound transformations within the organization, both in the business segments as well as in project management, technology, environment relations and investment portfolio management.
One month after launching our strategy, we successfully placed bonds in the international market for $1.5 bln , with an 11-year term and 3 times oversubscribed. The issue demonstrated, once again, the appetite and confidence of institutional investors in our company.
Also during the quarter, the risk rating agencies Fitch Ratings, Standard & Poor’s Ratings Services and Moody’s Investors Service, confirmed Ecopetrol’s ratings of BBB, BBB and Baa2, respectively, all with stable outlook, providing us the support needed to continue with our strategic plans as an investment grade issuer in the international capital market.”
(Ecopetrol S.A., 28.Jul.2015) – Ecopetrol informs that at a depth of 3720 meters, the Kronos-1 well verified the presence of hydrocarbons in ultra-deepwater of Colombian south Caribbean area. This discovery proves the geological model proposed for an unexplored area with high hydrocarbon potential.
Kronos-1 is located in block Fuerte Sur, 53 kilometers (33 miles) offshore, where partners Anadarko, operator, and Ecopetrol, each hold 50% interest.
“This discovery adds to the one accomplished in December at the Orca-1 well, located in the deep water of Tayrona block offshore Guajira, where we are partners with Petrobras, Repsol and Statoil,” reported Ecopetrol, citing company president Juan Carlos Echeverry. “These results are very important and confirm the potential of the Colombian Caribbean petroleum system in a vast area and are aligned with Ecopetrol´s new strategy, in which one of the key areas is the exploration on high potential marine basins.”
According to operator’s quarterly operations report, after drilling at a water depth of 1,584 meters (5,195 ft), the well reached total depth of 3,720 meters (12,200 ft) and encountered a net pay thickness between 40 to 70 meters (130-230 ft) of gas bearing sandstones.
Ecopetrol and Anadarko’s integrated technical teams are continuing to evaluate the Kronos discovery results. Nowadays the drilling operation continues, aiming to reach a deeper target to determine possible additional results.
In 2012, the Ecopetrol – Anadarko partnership undertook exploration in the South Caribbean in blocks Fuerte Norte , Fuerte Sur , COL5, URA4 and Purple Angel.
Our partner, Anadarko, is one of the most recognized companies worldwide for its experience in deepwater and ultra-deepwater exploration, project management and execution. Currently Anadarko is executing the biggest seismic acquisition campaign in the history of the Colombian Caribbean with an extension of more than 16,000 square kilometers.
Once activities at Kronos-1 are concluded, the drillship Bolette Dolphin, employed in this operation, will move to Fuerte Norte Block to continue drilling Calasu-1 well, located 145 kilometers or approximately 100 miles north east of Kronos-1.
(Ecopetrol S.A., 19.Jul.2015) – Ecopetrol reports that, at the Board of Directors’ meeting on July 17, 2015, the Board of Directors decided as follows:
— To accept the resignation of Mr. Gonzalo Restrepo Lopez as member and chairman of the Board of Directors.
The Board of Directors gave special recognition to Mr. Restrepo’s work as chairman, in which he placed his unique human, managerial and leadership qualities at Ecopetrol’s service. The Board of Directors wishes him success in his new endeavor as a member of the government’s negotiating team in the peace process in Havana.
— To appoint Mr. Luis Fernando Ramirez, an independent Director, as the new chairman of the Board of Directors.
— To appoint the engineer Hector Manosalva Rojas, currently Ecopetrol’s Vice President of Development and Production, as the second alternate to Ecopetrol’s President.
— To appoint Ms. Juliana Alban as Corporate Vice President of Compliance, who will also act as the company’s Compliance Officer.
The Corporate Vice Presidency of Compliance is a unit that was recently approved within Ecopetrol’s organizational structure with the purpose of ensuring the highest standards of compliance and internal controls on the management of the company.
(GeoPark Limited, 6.Jul.2015) – GeoPark Limited announced the results of an independent audit of the company’s exploration resources as of 31.Dec.2014, prepared by Gaffney, Cline & Associates (GCA).
GeoPark has interests in 31 blocks, covering over six million acres, in 12 proven hydrocarbon basins, in five Latin American countries, with a risk-balanced mix of production, development, exploration and unconventional resource opportunities. GeoPark’s current production is approximately 19,500 boe/d and oil and gas reserves (including Peru), as of 31.Dec.2014 certified by DeGolyer & MacNaughton, include proven (P1) reserves of 63 MMboe, proven and probable (2P) reserves of 122 MMboe, and proven, probable and possible reserves (3P) of 221 MMboe. DeGolyer & MacNaughton has estimated the Net Present Value (NPV10) of GeoPark’s 2P reserves to be $1.7 Billion (using a forward oil price curve beginning at $50/bbl for 2015).
GCA’s audit was focused on the evaluation of new prospective exploration resources covering 98% of GeoPark’s total exploration resources beyond its known and certified oil and gas proven, probable and possible reserves.
Year End 2014 Exploration Resource Audit Highlights
— 768-1,465 MMboe of total exploration resources (including 220-597 MMboe in unconventional oil resources)
— Total exploration resources are contained in 148 opportunities (112 prospects, 30 leads, 4 plays and 2 unconventional projects) on 31 evaluated blocks in five countries,
— Total exploration resources (best case) include 634 MMbbl of oil (94%) and 251 Bcf (42 MMboe) of natural gas (6%),
— 38% or 257 MMboe of the total conventional exploration resources (best case) are in prospects and 35% or 238 MMboe are in leads and plays. Unconventional resources represent 27% or 181 MMboe of the company’s total exploration resources,
“This exploration resource estimate confirms the extent, depth and potential of GeoPark’s in-house project inventory and the running room we have for continued organic growth. In addition to our already discovered and significant oil and gas reserve base (with 2P reserves over 122 million BOE), we own a big mix of assets with the potential for finding 770 million to 1.5 billion BOE of new oil and gas reserves,” said James F. Park, CEO of GeoPark. “These represent attractive assets, located in proven hydrocarbon basins with existing infrastructure, and which are managed by GeoPark’s geoscience and operations team, with our 70+% drilling success rate since 2008 and consistent nine year growth track record.”
(Ecopetrol S.A., 1.Jul.2015) – Ecopetrol S.A. reported that the credit rating agency Standard & Poor’s has maintained Ecopetrol’s long term corporate credit rating at BBB with a stable outlook.
S&P’s mentioned that the new strategy presented by the company is in line with the current oil market conditions and prioritizes efficient barrels and shareholder returns. The rating decision also considers, among other things, the very important role of Ecopetrol in the Colombian economy.
(Ecopetrol S.A., 25.Jun.2015) – Ecopetrol S.A. reported that the credit rating agency Moody’s Investors Service has maintained Ecopetrol’s long term international rating at Baa2 with a stable outlook.
Moody’s mentioned that “the rating affirmation was based on Ecopetrol’s solid business strategy, now focused on expanding exploration activities to increase reserves as well as on improving production recovery and operating efficiencies across the board, which will help the company protect its credit quality through the current cycle of lower oil prices.”
The rating decision also considered, among other factors, Ecopetrol’s leading position in Colombia and the size of its operations.
(Ecopetrol S.A., 24.Jun.2015) – Ecopetrol S.A. at the direction of the Finance Superintendence, hereby publishes the earnings distribution proposal that was approved by the Shareholders Assembly of 26.Mar.2015.
Accordingly, regarding the capitalization of the occasional reserve by means of an increase in the nominal value of each of our shares from COP$250 to COP$609, which was approved by 99.9942882% of the shares represented at the meeting on March 26, 2015 , Ecopetrol reports that of the total capitalized amount of COP$14,760,894,745,774, 13.1%, or COP$1,938,434,206,789, corresponds to earnings for the year 2014 that were allocated within the 2014 Earnings Distribution Proposal for the building up of occasional reserves, and 86.9%, or COP$12,822,460,538,985, correspond to reserves of prior fiscal.
(Gran Tierra Energy Inc., 24.Jun.2015) – Gran Tierra Energy Inc. announced an increased 2015 capital program. The increased capital is intended to provide accelerated development drilling at the company’s core producing assets in the Putumayo Basin in Colombia, specifically the Moqueta and Costayaco fields on the Chaza Block. In addition, the company expects to accelerate the required laboratory and feasibility studies for enhanced oil recovery techniques in the Costayaco and Moqueta fields.
During the 1Q:15, the company incurred $74 million of the $140 million 2015 capital program. Gran Tierra’s board of Directors has approved a $45 million increase to its 2015 capital program to $185 million.
The allocation of capital includes an increase of $55 million directed at Colombia development, at negotiated reduced services costs. At forward pricing, the additional capital generates IRRs in excess of 30%, and the majority of the increased drilling impacts the 2015 exit rate and the forecasted 2016 average production. The total 2015 capital program in Colombia is now $115 million and the majority of Colombia’s capital program is expected to be spent on development drilling activities on the Moqueta and Costayaco fields. The program includes an expected three wells at Moqueta and three wells at Costayaco. These drilling programs are expected to continue into 2016.
Peru’s capital program has been reduced to $49 million, of which $11 million is expected to be incurred during the remainder of 2015. The Company is focused on limiting total costs (CAPEX and G&A) in Peru over the next 12 months to ensure retention of lands and security of assets. The company is exploring options to maximize shareholder value for the assets in Peru.
Brazil’s capital program has been reduced to $20 million, of which $6 million is expected to be incurred during the remainder of 2015.
Of the total budget of $185 million, $97 million is allocated for drilling, $45 million for facilities, pipelines and other, and $43 million for geological and geophysical expenditures. The program meets all work obligations and commitments in 2015.
Gran Tierra expects to finance its 2015 capital program through cash flows from operations and cash on hand, while retaining financial flexibility to undertake further development activities and pursue diversified growth opportunities in Colombia.
With the revised capital program, Gran Tierra expects 2015 gross working interest (WI) production to average between 22,500 and 23,500 boe/d or between 18,400 and 19,400 boe/d net after royalty (NAR). Production from Colombia is expected to be approximately 17,850 boe/d NAR, with Costayaco contributing approximately 10,400 boe/d NAR and Moqueta contributing approximately 5,100 boe/d NAR, assuming a 2% contingency for potential delivery disruptions. Production from the Company’s Brazil operation is expected to average 770 boe/d NAR. Approximately 99% of expected production is oil, with the balance natural gas.
The accelerated development associated with the increased capital program at the Moqueta field is expected to provide the production capacity for the Company to maintain consistent production during 2016.The additional development is intended to test Probable and Possible reserves recognized by the company’s external reserves auditor.
(Moody’s, 23.Jun.2015) – Moody’s affirmed Ecopetrol S.A.’s Baa2 ratings and assigned a Baa2 rating to the company’s up to $1.5 billion in proposed notes due 2026.
The proposed securities are senior unsecured and pari passu with Ecopetrol’s other senior foreign currency debt, which is also rated Baa2. Proceeds from the notes issuance will be used primarily to fund capital expenditures. The rating outlook is stable.
(Ecopetrol S.A., 22.Jun.2015) – Fitch Ratings affirmed Ecopetrol S.A.’s foreign and local currency Issuer Default Ratings at ‘BBB’ and ‘BBB+’, respectively.
Concurrently, Fitch has affirmed the company’s national scale short and long-term ratings of ‘F1+(col) and ‘AAA(col). The Rating Outlook for all ratings is Stable.
According to Fitch, “Ecopetrol’s ratings reflect its strong financial profile and improving production levels. Ecopetrol’s recently revised growth strategy and associated capex plan are considered adequate for the company’s credit quality and cash flow generation ability. Ecopetrol is expected to maintain a financial and credit profile consistent with the assigned rating.”
In the report, Fitch mentioned that, “Ecopetrol’s relatively sizable reserves, stable production levels and dominant domestic market share allow the company to generate consistently strong cash flows from operations and meet its obligations in a timely manner.”
(Ecopetrol, 26.May.2015) – Ecopetrol S.A.’s Board of Directors approved a new corporate strategy aimed at guaranteeing the company’s long-term sustainability, in which value generation based on efficient barrels and shareholder return become a priority.
Within a complex international price environment, the new strategy defines that Ecopetrol will be focused on oil and gas exploration and production, while seeking operational excellence in transportation, refining and petrochemical areas. The strategy also pursues the achievement of structural efficiencies, to allow the Group to increase its competitive levels in order to reach the best international standards.
In exploration, the Ecopetrol Group will build a portfolio that is robust and diversified, focused on high potential basins in Colombia and abroad, which is designed to increase significantly the Group’s contingent resources and reserves. In addition, the exploratory team based in Houston and Bogota will be strengthened by the addition of world-class human talent with proven track record.
In production, Ecopetrol will be focused on efficient barrels production, in major profitable fields, while carrying out a comprehensive program to increase the recovery factor. It will seek to increase average annual production between 1% and 2%, reaching a total of approximately 870 thousand barrels of oil equivalent per day by 2020, with an EBITDA target of more than $30/bbl in a price scenario for Brent crude of between $70/bbl and $80/bbl.
As for the company’s reserves, the objective is to increase proved reserves by 1,700 million barrels of oil equivalent by 2020. In the transportation segment, the company will dedicate its efforts to increase efficiency in order to achieve international operating standards. The plan includes Cenit´s consolidation, the affiliate that will ensure the transportation of national crude, with a special focus on heavy crudes, as well as transportation of refined products for the Colombian market.
In refining and petrochemical, the strategy contemplates the start-up of the new Cartagena refinery during the 4Q:15, execution of an ambitious efficiency plan that will improve the competitiveness of existing assets and the promotion of the necessary regulatory conditions to ensure the business’s profitability within a framework of financial selfsustainability.
Ecopetrol will focus on profitable investments, at an average estimated level of $6,000 million per year through 2020, oriented toward high value projects that contribute to the execution of the new strategy.
The company will prioritize the protection of available cash for its operations, maintaining its access to local and international capital markets in competitive conditions. The preservation of business and finance metrics that credit rating agencies consider will be a priority to maintain our current credit rating.
The company will continue its program to divest non-strategic assets, as announced with regard its stake in EEB and ISA, among others, as well as nonstrategic exploration and production assets.
The strategy is based on producing efficient, clean and profitable barrels, which generate returns for our shareholders, interested groups and Colombians. The perspective toward 2020 will be to attempt to double the 2014 return on capital employed.
To support its strategy, in the beginning of 2015, Ecopetrol initiated a transformation plan that provides structural efficiencies to obtain annual savings close to $1,000 million in the period 20152020. This plan contemplates fundamental changes within the company, including its business, project management and technology segments as well as relationship with local communities and active portfolio management.
The plan also provides a cultural transformation that encourages and promotes the attainment of results and is based on the principles of integrity, collaboration and creativity.
Ecopetrol will prioritize innovation and knowledge generation. In the new strategy, technology and information systems will be focused on leveraging key business projects, especially in exploration and production.
The Ecopetrol Group is committed to production with zero accidents and environmental incidents, with a solid regional presence, prompt decisionmaking, with satisfied and committed employees, and a harmonious, mutually beneficial relationship with local communities.
Ecopetrol’s new strategy and the transformation plan that supports it, have as their goal the company’s reinvention in order to successfully compete in a challenging international environment.
(Ecopetrol, 12.May.2015) – Ecopetrol S.A. reports the Group’s financial results for the 1Q:15, prepared and filed in Colombian pesos (COP$) and on the basis of International Financial Reporting Standards (IFRS).
According with the article 3 of the Decree 2784 of 28.Dec.2012, the application date of the new technical framework is 31.Dec.2015, so the financial information presented prior to this date is subject to adjustments.
As indicated in paragraphs 9 and 18 of the International Accounting Standard 27 “Consolidated and Separated Financial Statements” Ecopetrol and its Corporate Group must present their financial information on a consolidated basis as if they were a single entity, combining the financial statements of the parent company and its subsidiaries line by line, adding assets, liabilities, shareholder´s equity, revenues and expenses of similar nature, removing the reciprocal items between the Corporate Group and recognizing the non-controlling interest.
In the opinion of Ecopetrol’s CEO, Juan Carlos Echeverry:
“Despite the decline in oil prices, in the 1Q:15 the Group reached a positive financial result due to the good performance of its different segments and favorable environment conditions for the operation. Thus, operating and financial results of the Group on the 1Q:15 were better than those of the 4Q:14. Particularly, March was the best month of the 1Q:15.
With respect to our exploration activities, the first geological success for the year was reported at the Bullerengue-1 well, drilled by Hocol, located in the Sinu-San Jacinto basin, which is expected to support the natural gas supply on the Atlantic Coast region. In addition, we advanced in the drilling activities in the offshore wells Kronos and Calasu, located in the southern Caribbean Sea in partnership with Anadarko as operator (50% – 50%).
Our production activities have recorded four consecutive quarters of growth, reaching 773.4 Mboe/d in the 1Q:15, a 1% increase as compared to the first and last quarters of 2014. This increase was the result of the start-up of new facilities and wells in the Castilla and Chichimene fields, both of which set production records of 124 Mbo/d and 85 Mbo/d, respectively.
Our affiliated companies increased their production to a total 51.4 Mboe/d, a 5.8% rise as compared to the 1Q:14. Highlighting Ecopetrol America’s production alone reached 6.4 Mboe/d.
Amid this low crude oil prices scenario, our refining margin has continued to improve, reaching $18.2/bbl in the 1Q:15, a 12% gain as compared to the 1Q:14 ($16.3/bbl) and a 15% gain as compared to the 4Q:14 ($15.8/bbl).
The main contributing factors to this result were the operating stability of units and the improvements designed to give value to residual streams.
In transportation, total volumes moved during the 1Q:15 were 1,273.5 Mb/d, a 6% increase compared to 1,200.1 Mb/d transported during the 1Q:14, and 3.3% more compared to the 4Q:14. This result was primarily due to higher volumes transported in the Cano Limon-Covenas and Oleoducto Transandino systems resulting from the decreased number of attacks on transport infrastructure, which went from 35 attacks on the 1Q:14 to 2 attacks in the 1Q:15.
International crude oil prices reached its lower level in 6 years during the 1Q:15 (Brent $46.6/bbl on 13.Jan.2015). As a result, our revenues were deeply affected, decreasing from COP$18 trillion to COP$12.3 trillion in the 1Q:15, a COP$5.7 trillion decrease (31.6%). The effect of lower sales oil prices (from $101/bbl to $56/bbl between the 1Q:14 and the 1Q:15) caused a decreased of COP$8.2 trillion in our revenue, that was partially offset for the positive exchange rate effect, representing a higher income of COP$2 trillion, COP$200 billion in higher sales volumes and COP$250 billion in higher income from transportation services to third parties due to the effect of the devaluation on the tariffs.
Our cost of sales declined to COP$8.5 trillion in the 1Q:15, a 21% decrease as compared to COP$10.8 trillion in the 1Q:14. This result was primarily due to the effect of lower oil prices on our purchase costs of crude, gas and refined products, as well as lower fixed costs due to the optimization of maintenance plans and contracted services achieved during the 1Q:15.
Operating costs increased by 53% during the 1Q:15 as compared to the 1Q:14, primarily as a consequence of the recording of the wealth tax applicable for year 2015.
The Colombian peso-U.S. dollar exchange rate had significant effects on the Group’s financial expenses. The impact of the depreciation of the Colombian peso over our net liability position resulted in an expense of COP$1.4 trillion during the 1Q:15.
Income before taxes for the 1Q:15 was COP$828 billion. With the income tax provision of COP$472 billion (57%) resulted in a consolidated net income of COP$160 billion.
Considering the current scenario of low oil prices, we are focused on making our operations more efficient. Our operations will continue focusing on safety, profitability and delivering positive results for our shareholders.”
(Gran Tierra Energy Inc., 11.May.2015) – Gran Tierra Energy Inc. announced several new executive appointments effective immediately: Ryan Ellson, Chief Financial Officer; Alan Johnson, Vice President, Asset Management; Lawrence West, Vice President, Exploration; and Jim Evans, Vice President, Corporate Services.
“I am delighted to have four key members from the Caracal team join Gran Tierra,” said Gary Guidry, President and CEO of Gran Tierra. “The addition of Ryan, Alan, Lawrence and Jim will complement the existing excellent team at Gran Tierra.”
Mr. Ryan Ellson Joined the company as CFO. Ryan has 15 years of experience in a broad range of international corporate finance and accounting roles. Most recently, Ellson was Head of Finance for Glencore E&P (Canada) and prior thereto VP, Finance at Caracal Energy, a London Stock Exchange listed company with operations in Chad, Africa. While at Caracal Energy, Ellson was instrumental in negotiating a $330 million farm-out to Glencore, secured a $250 million reserve based lending facility (winner of several trade finance deals of the year), and involved in multiple capital raises totaling approximately $500 million. Ryan was also instrumental in the successful listing of the company on the London Stock Exchange. Prior to Caracal, Ellson held several management and executive positions with companies operating in Egypt, India and Canada. Ellson is a Charted Accountant and holds a Bachelor of Commerce and a Master of Professional Accounting from the University of Saskatchewan.
Ellson succeeds James Rozon. James will continue with the Company to assist with a smooth transition.
Additional appointments to complement the executive team at Gran Tierra include: Alan Johnson as VP Asset Management, Lawrence West as VP Exploration and Jim Evans as VP Compliance and Corporate Services. Alan Johnson is a professional engineer with over 21 years of experience working internationally in the oil and gas industry. His experience includes varied technical, managerial and executive roles in drilling, production, reservoir, reserves, corporate planning and asset management.
Most recently Alan was Head of Asset Management for Glencore (E&P) Canada and prior thereto Director of Asset Management at Caracal Energy where he was responsible for all development activities in Chad, Africa. Alan was instrumental in developing oil and gas assets in remote areas of southern Chad, achieving first production in less than 18 months. Johnson started his E&P career with Shell International in the Dutch North Sea. He then held positions of increasing responsibility with Shell Canada, APF Energy, Rockyview Energy, Delphi Energy and BG Australia. Johnson graduated with a 1st Class B.Eng (Hons) from Heriot Watt University in Scotland. Johnson is a Chartered Engineer in the UK and a Professional Engineer in Alberta.
Lawrence West has 35 years of experience as an executive, explorationist, and geologist. Most recently West was VP, Exploration at Caracal Energy. Lawrence built a multi-disciplinary team to assess resources and grow reserves in the interior rift basins within Chad and led a successful exploration program. During his tenure he successfully executed two large 2D/3D seismic shoots in remote frontier basins, on time and on budget. Prior to Caracal he has been involved in starting and growing several public and private companies, including Reserve Royalty Corp., Chariot Energy, Auriga Energy and Orion Oil and Gas. Lawrence worked at Alberta Energy Company (AEC), where he was on the team that merged with Conwest. He built and led the AEC East team to the Rocky Mountain USA basins. His career began with Imperial Oil working on prospect and reservoir characterization, in multi-disciplinary teams, and as a technical mentor to exploration teams. Lawrence has an Honours Bachelor of Science in Geology from McMaster University and an MBA, specializing in economics, from the University of Calgary.
Jim Evans has over 20 years of experience including working the last 10 years in the international oil and gas industry. Most recently Jim was the Head of Compliance & Corporate Services for Glenore E&P (Canada) and prior thereto VP of Compliance & Corporate Services at Caracal Energy where he oversaw the execution of corporate strategy and goals, developed and implemented a robust corporate compliance program, and managed all aspects of IT, document control, security and administration. Evans also managed the recruitment, training and retention of staff in both Calgary and Chad.
He oversaw the growth of the company from seven employees to in excess of 400 as Caracal Energy exceeded 20,000 b/d at the time of sale to Glencore. Prior to Caracal, Evans held senior management and executive positions at Orion Oil and Gas and Tanganyika Oil, with operating experience in Egypt, Syria and Canada. Evans is a Certified General Accountant and holds a Bachelor of Commerce degree from the University of Calgary.
(Gran Tierra Energy Inc., 6.May.2015) – Gran Tierra Energy Inc. announced its financial and operating results for the quarter ended 31.Mar.2015. All dollar amounts are in U.S.A. dollars unless otherwise indicated.
Earlier this year, Gran Tierra announced significant changes to the company’s leadership, strategic direction and cost structure. Gran Tierra’s operations and resources are now focused on Colombia, where, as its first quarter production demonstrates, the company has a record of success and strong performance. Gran Tierra continues to maintain a solid financial position with cash balances reflecting expenditures that were pre-committed prior to this strategic shift. With these legacy commitments largely behind Gran Tierra and the cost reductions announced earlier this year, the company has significantly improved its capital efficiency and continues to review opportunities for additional cost savings. Gran Tierra is confident that the actions it has taken better position the company for growth and value creation despite what continues to be a challenging lower oil price environment.
Financial and Operating Highlights:
— Due to strong Colombian performance, oil and natural gas production for the quarter was above company projections. Production averaged 24,015 boe/d gross working interest (WI), or 20,140 boe/d net after royalties (“NAR”) before adjustment for inventory changes and losses, or 19,399 boe/d NAR adjusted for inventory changes and losses, compared with 25,245 boe/d gross WI and 19,029 boe/d NAR before adjustment for inventory changes and losses and 18,753 boe/d NAR adjusted for inventory changes and losses in the corresponding period in 2014. Approximately 99% of this production was oil with the balance consisting of natural gas.
— The company is making progress on the Chaza Block in Colombia. The Moqueta-17 development well was successfully completed, stimulated and tiedin as an oil producer. The Moqueta-18i injection well was drilled and encountered mechanical difficulties. This well was being drilled to provide pressure support to the Moqueta field south block. It is currently suspended pending the results of injectivity testing at Zapotero-1, which is located in the same fault compartment as Moqueta 18i. Initial injectivity is proving to be successful with 2,500 b/d of water being injected, and the company expects to increase this to 5,000 b/d of water.
— Gran Tierra expects to achieve reductions of approximately 30% in general and administrative (“G&A”) expenses in 2015 compared with 2014. These expected savings are due to the previously announced 20% reduction in headcount, other cost cutting initiatives in all locations, and strengthening of the U.S. dollar against local currencies in South America, and exclude one-time severance expenses of $4.4 million. On a barrel of oil equivalent (BOE) basis, G&A expenses decreased by 41%, or $2.85/BOE in the 1Q:15 from the 4Q:14. Further optimization of G&A expenses is expected.
— Cost optimization initiatives resulted in $1.1 million of operating expense reductions in Colombia during the quarter and an 11% negotiated reduction in Colombian trucking tariffs. Operating expenses decreased by 13% to $18/boe in the 1Q:15 from $20.75/boe in the 4Q:14. The company expects to achieve up to $5 million of additional operating cost savings in Colombia in 2015, primarily as a result of its use of produced gas for power generation and renegotiated supply and service contracts.
— Due to lower oil prices, revenue and other income for the quarter was $76.7 million in the 1Q:15, a 23% decrease from $99.6 million in the 4Q:14, and a 50% decrease from $151.9 million in the comparable period in 2014.
— Net loss for the 1Q:15 was $44.9 million, or $0.16 per share basic and diluted, compared with a net loss of $269.8 million, or $0.94/share basic and diluted, in the 4Q:14, and net income of $45.1 million, or $0.16/share basic and diluted, in the 4Q:14.
Results in both this quarter and the 4Q:14 were significantly impacted by the company’s decision to cease development of the Bretaña field on Block 95 in Peru other than making those expenditures necessary to maintain tangible asset integrity and security, which resulted in impairment losses of $32.7 million and $265.1 million, respectively, in Gran Tierra’s Peru cost center. Included in the Peru cost center impairment loss of $32.7 million, was $14.0 million of drilling costs for the Bretaña Sur 953-4-1X appraisal well, $6.2 million for the construction of the long-term test facilities, $5.0 million relating to contract termination fees associated with the decision not to proceed with the long-term test, and $7.5 million of other costs including restocking fees and the front end engineering design (“FEED”) study. Total contract termination and restocking fees were $8.7 million.
— Funds flow from continuing operations for the 1Q:15 were consistent with company projections at $25.6 million, a decrease of 49% from $50.3 million in the 4Q:14, and a decrease of 71% from $86.7 million in the 1Q:14.
— The company maintains strong balance sheet with cash and cash equivalents of $203.5 million at March 31, 2015.The company’s cash balance reflects $74 million of capital expenditures in the first quarter of 2015 that were incurred largely as a result of precommitted costs associated with legacy projects and decisions made before the senior management and strategy changes. Reflecting Gran Tierra’s new strategic direction and focus on Colombia, in February 2015, Gran Tierra announced a $170 million reduction to its capital budget, and continues to expect 2015 capital expenditures of $140 million.
— In Brazil, Tiê field operations were suspended on March 11, 2015, following a regional facilities audit by the Agência Nacional de Petróleo Gás Natural e Biocombustíveis (ANP). Gran Tierra expects resumption of operations by May 20, 2015.
First Quarter 2015 Financial Highlights
For the three months ended 31.Mar.2015, revenue and other income decreased by 50% to $76.7 million compared with $151.9 million in the corresponding period in 2014 primarily due to decreased realized prices. Average realized oil prices decreased by 51% to $43.79/bbl for the 1Q:15, from $89.89/bbl in the 1Q:14 primarily as a result of lower benchmark prices. In the 1Q:15, an oil inventory and losses increase primarily in Colombia accounted for reduced production of 0.1 MMbbl or 741 bo/d.
Additionally, beginning July 1, 2014, the port operations fee component of the Ecopetrol S.A. operated Trans-Andean oil pipeline (the “OTA pipeline”) structure increased by $2.94/bbl, resulting in a reduction of realized oil prices by this amount on sales delivered through the OTA pipeline.
Revenue and other income for the 1Q:15, decreased by 23% to $76.7 million from $99.6 million compared with the 4Q:14 primarily due to decreased realized prices. Average realized oil prices decreased by 30% to $43.79/bbl for the 1Q:15, compared with $62.91/bbl in the 4Q:14, due to lower benchmark prices.
The average Brent oil price for the 1Q:15, was $53.91/bbl compared with $108.17/bbl in the 1Q:14, and $76.40/bbl for the 4Q:14. The average West Texas Intermediate oil price for the 1Q:15, was $48.63/bbl compared with $98.68/bbl in the 1Q:14, and $73.15/bbl for the 4Q:14.
During periods of OTA pipeline disruptions Gran Tierra uses transportation alternatives. These sales have varying effects on realized prices and transportation costs. During the three months ended March 31, 2015, 80% of Gran Tierra’s oil volumes sold in Colombia were through the OTA pipeline and only 20% were through these transportation alternatives. During the corresponding period in 2014, sales through the OTA pipeline were 41% of Gran Tierra’s oil volumes sold in Colombia and 59% were through transportation alternatives. The effect on the Colombian realized price for the 1Q:15, was an increase of approximately $0.01/boe, as compared with delivering all of Gran Tierra’s Colombian oil through the OTA pipeline, compared with a reduction of approximately $8.63/boe in the 1Q:14. Production during the 1Q:15, reflected approximately 10 days of oil delivery restrictions in Colombia compared with 51 days of oil delivery restrictions in the 1Q:14.
Operating expenses increased by 44% to $31.4 million for the 1Q:15, compared with $21.9 million in the 1Q:14. For the 1Q:15, the increase in operating expenses was primarily due to an increase in the operating cost per BOE. Operating expenses increased by 39% to $18/boe in the 1Q:15, from $12.96/boe in the 1Q:14, primarily as a result of higher transportation costs associated with higher sales using the OTA pipeline, which carried higher transportation costs instead of the realized price reductions that are incurred with some alternative customers, and increased workover expenses.
Operating expenses decreased by 4%, or $1.4 million, in the 1Q:15, from $32.8 million in the 4Q:14 primarily due to reduced operating costs per BOE. On a per BOE basis, operating expenses decreased by 13% to $18/boe for the 1Q:15, from $20.75/boe in the 4Q:14 as a result of cost reduction initiatives, deferral of road and equipment maintenance and higher production adjusted for inventory changes and losses.
DD&A expenses for the 1Q:15, increased to $86.2 million from $44.3 million in the 1Q:14. DD&A expenses in the 1Q:15, included $32.7 million of impairment charges in Gran Tierra’s Peru cost center relating to costs incurred in the 1Q:15 on Block 95 and a $4.3 million ceiling test impairment loss in Gran Tierra’s Brazil cost center relating to lower oil prices. Included in the Peru cost center impairment loss of $32.7 million, was $14.0 million of drilling costs for the Bretaña Sur 95-3-4-1X appraisal well, $6.2 million for the construction of the long-term test facilities, $5.0 million relating to contract termination fees associated with the decision not to proceed with the long-term test, and $7.5 million of other costs including restocking fees and the FEED study. Total contract termination and restocking fees were $8.7 million. The depletion rate increased by 88% to $49.35/boe from $26.23/boe primarily due to the 2015 impairment charges. If Brent oil prices continue at current levels, Gran Tierra believes it is reasonably likely that it would record further ceiling test impairment losses in its Brazil cost center in 2015 and, possibly, in its Colombia cost center. Additionally, Gran Tierra expects to record further impairment losses in its Peru cost center for costs incurred on Block 95 in 2015.
G&A expenses for the 1Q:15, decreased by 43% to $7.3 million ($4.18/boe) from $12.9 million ($7.62/boe) in the 1Q:14. The decrease was mainly due to the effect of the strengthening of the U.S. dollar against the Colombian peso which resulted in significant savings for costs denominated in local currency and a 20% reduction in the number of Gran Tierra’s full-time employees in March 2015 as part of the company’s cost saving measures and focus on reductions to other G&A expenses. Further optimization of G&A expenses is expected. G&A expenses in the three months ended 31.Mar.2015, are also net of a credit of $1.7 million ($0.97/boe) relating to the reversal of stock-based compensation expense for unvested options and restricted stock units on employee terminations.
Severance expenses for the 1Q:15, were $4.4 million compared with $nil in the 1Q:14. In March 2015, Gran Tierra reduced the number of its full-time employees by 20%.
Equity tax expense for the 1Q:15, of $3.8 million, represented a Colombian tax which was calculated based on Gran Tierra’s Colombian legal entities’ balance sheet equity for tax purposes at 1.Jan.2015. The legal obligation for each year’s equity tax liability arises on 1.Jan. of each year, therefore, Gran Tierra recognized the 2015 annual amount of the equity tax payable on its consolidated balance sheet at 31.Mar.2015, and a corresponding expense in its consolidated statement of operations during the 1Q:15.
Foreign exchange gain for the 1Q:15, was $11.5 million comprising an unrealized non-cash foreign exchange gain of $9.0 million and realized foreign exchange gains of $2.5 million. For the 1Q:14, there was a foreign exchange gain of $4.2 million, which was primarily a $4.2 million unrealized non-cash foreign exchange gain. Unrealized foreign exchange gains were primarily the result of the impact of the weakening of the Colombian peso versus the U.S. dollar on a net monetary liability position in Colombia.
For the 1Q:15, financial instruments gains included $2.4 million of unrealized financial instruments gains which were offset by $2.4 million of realized financial instrument losses. Financial instrument gains and losses related to unrealized gains on the Madalena Energy Inc. shares Gran Tierra received in connection with the sale of its Argentina business unit and gains and losses on Gran Tierra’s Colombia peso nondeliverable forward contracts.
Income tax expense related to continuing operations was $0.1 million for the 1Q:15, compared with $29.7 million in the 1Q:14. The decrease was primarily due to lower taxable income.
Loss from continuing operations was $44.9 million, or $0.16/share basic and diluted, for the 1Q:15, compared with income from continuing operations of $49.8 million, or $0.18/share basic and diluted, in the 1Q:14. As noted above, in the 1Q:15, Gran Tierra recorded impairment losses of $32.7 million in its Peru cost center relating to costs incurred on Block 95 and $4.3 million in its Brazil cost center due to lower oil prices.
Additionally, loss from continuing operations was impacted by decreased oil and natural gas sales as a result of lower realized oil prices, higher operating, DD&A, severance and equity tax expenses and lower financial instrument gains which were partially offset by lower G&A expenses, increased foreign exchange gains and lower income tax expenses.
Loss from discontinued operations, net of income taxes, was $nil for the 1Q:15, compared with $4.6 million, or $0.02/share basic and diluted, in the 1Q:14. Gran Tierra sold its Argentina business unit on 25.Jun.2014.
Net loss for the 1Q:15, was $44.9 million, or $0.16/share basic and diluted, compared with net income of $45.1 million, or $0.16/share basic and diluted, in the 1Q:14 and net loss of $269.8 million, or $0.94/share basic and diluted, in the 4Q:14.
Balance Sheet Highlights
The company’s repositioning strategy will help ensure that Gran Tierra maintains a strong balance sheet. Cash and cash equivalents were $203.5 million at 31.Mar.2015, compared with $331.8 million at 31.Dec.2014. The decrease was primarily due to capital expenditures incurred during the quarter of $74.0 million ($21.4 million in Colombia, $38.0 million in Peru, $13.9 million in Brazil and $0.7 million in Corporate) associated with the decisions by the prior management team and the costs associated with those legacy projects, $53.8 million of net cash outflows related to property, plant and equipment ($45.1 million outflow in Colombia, $9.4 million outflow in Peru, and a $0.7 million inflow in Brazil and Corporate), $26.1 million of net cash outflows related to assets and liabilities from operating activities and a $0.5 million increase in restricted cash, partially offset by funds flow from continuing operations of $25.6 million and proceeds from the issuance of shares of common stock of $0.5 million. Changes in assets and liabilities associated with operating and investing activities from 31.Dec.2014 to 31.Mar.2015, resulted in cash outflows of $83.1 million due to the payment of accounts payable and accrued liabilities partially offset by cash inflows of $3.2 million related to other assets and liabilities in the quarter.
Working capital (including cash and cash equivalents) was $181.3 million at 31.Mar.2015, a $58.6 million decrease from 31.Dec.2014. Gran Tierra remains debt free.
Production for the 1Q:15 averaged 24,015 boe/d WI, or 20,140 boe/d NAR before adjustment for inventory changes and losses, or 19,399 boe/d NAR adjusted for inventory changes and losses, compared with 25,245 boe/d gross WI and 19,029 boe/d NAR before adjustment for inventory changes and losses and 18,753 boe/d NAR adjusted for inventory changes and losses in the corresponding period in 2014. Production for the 1Q:15 consisted of 18,748 boe/d NAR in Colombia and 651 bo/d NAR in Brazil, all adjusted for inventory changes and losses. Production in April 2015 averaged approximately 18,700 boe/d NAR before adjustment for inventory changes and losses, due to temporary operational shut-ins and approximately one day of oil delivery restrictions in Colombia. Gran Tierra expects production to be back to normal daily production levels after resumption of operations on the Tiê field in Brazil. Approximately 99% of this production is expected to be oil, with the balance consisting of natural gas.
During the 1Q:15, an oil inventory and losses increase accounted for 0.1 MMbbls, or 741 bo/d, of reduced production, compared with an oil inventory and losses increase which accounted for 24,784 barrels, or 276 bo/d, of reduced production in the 1Q:14.
Gran Tierra anticipates 2015 production to average between 21,800 boe/d and 22,300 boe/d gross WI, or 18,200 boe/d and 18,700 boe/d both NAR before adjustments for inventory changes and losses. This includes between 17,300 boe/d and 17,800 boe/d both NAR from Colombia and 900 bo/d NAR from Brazil. Approximately 99% of this production is oil, with the balance consisting of natural gas.
2015 Capital Program
In concert with Gran Tierra’s repositioning strategy, the planned 2015 capital program was reduced to $140 million from $310 million in early February 2015. This includes $60 million for Colombia, as well as funds that were pre-committed for non-core legacy projects, including $55 million for Peru, $24 million for Brazil and $1 million associated with corporate activities. The capital spending program allocates: $45 million for drilling; $49 million for facilities, pipelines and other; and $46 million for G&G expenditures. Approximately $35 million of the capital program is dedicated to the maintenance of existing production while $21 million is dedicated to drilling in Colombia.
During the 1Q:15, the company incurred $74.0 million of capital expenditures, which included $21.4 million in Colombia, $38.0 million in Peru, $13.9 million in Brazil and $0.7 million at Corporate. Capital expenditures in Peru included $32.7 million on Block 95 and $5.3 million on Gran Tierra’s other blocks.
On Block 95, all capital expenditures recorded had been completed or committed to prior to the advent of the repositioning strategy in Feb.2015 and included: $14 million of drilling costs for the Bretaña Sur 95-3-4-1X appraisal well; $6.2 million for the construction of the long-term test facilities; $8.7 million recorded unavoidable costs for contract termination fees associated with the decision not to proceed with the long-term test, and other contract termination and restocking fees; and $3.8 million related to the FEED study and other.
Gran Tierra is evaluating all contractual commitments on the company’s blocks with the objective of rationalizing this portfolio through farm outs, transfers and relinquishment. Gran Tierra expects the 2015 capital program to be funded through cash flows from operations and cash on hand at current production and oil price levels.
First Quarter 2015 Operational Highlights
Chaza Block, Putumayo Basin (Gran Tierra 100% WI and Operator)
In the 1Q:15, Gran Tierra successfully completed, stimulated and tied-in the Moqueta-17 development well in the Moqueta field as an oil producer. Moqueta-17 is now producing approximately 400 bo/d gross from the Villeta T and Caballos reservoirs. The Moqueta-18i injection well was drilled and encountered mechanical difficulties. It is currently suspended pending the results of injectivity testing at Zapotero-1, which is interpreted to be in the same fault compartment as Moqueta 18i (the Moqueta South Block). Initial injectivity tests on Zapotero-1 have been very positive and Gran Tierra is currently injecting approximately 2,500 b/d of water into the target Moqueta reservoir compartments, and expects to increase this to 5,000 b/d of water. The company expects that the water injection will create a positive pressure response in the Moqueta South Block updip oil bearing reservoirs and support oil production.
Gran Tierra continued facilities work at the Costayaco and Moqueta fields. In the first week of Mar.2015, the Company implemented a cogeneration project which utilizes produced gas and converts it to electricity to power the facilities at the Moqueta field.
Two 500 kilowatt power generators are generating 1 megawatt (MW) of power with the gas produced from the Moqueta field. This nearly meets the 1.2MW electrical needs of Moqueta. As a third party owns the generators and sells the electricity back to Gran Tierra at a lower rate than the national electrical utility, the project required no capital investment. This project is expected to provide both environmental and cost benefits by reducing the flaring of gas and cutting the cost of electricity to the field. Additionally, when excess electricity is generated, there is an opportunity to sell that excess to the national grid. This project is estimated to generate operating cost savings of approximately $350,000 in 2015. A similar co-generation project is currently being planned for the Costayaco field before year-end.
Gran Tierra has renegotiated contracts with its suppliers and service providers during the quarter and expects to achieve savings of up to $5 million from this initiative in 2015. Also during the quarter, Colombian trucking tariffs were renegotiated from a 5% reduction in early February to an 11% reduction by quarter-end. Gran Tierra also achieved $1.1 million of savings in the quarter mainly through staff and salary reductions, lower road maintenance due to decreased trucking transportation, and operational efficiencies related to reduced energy consumption.
Gran Tierra experienced higher than expected pipeline transportation during the quarter with approximately 85% of the Company’s Colombian crude being shipped through the OTA pipeline to the Port of Tumaco or through the Oleoducto de Crudos Pesado (“OCP”) pipeline to the Port of Esmeraldas, with the remainder transported by truck or other pipelines. Gran Tierra’s crude sold at the Ports of Tumaco and Esmeraldas received higher prices due to lower oil quality discounts than volumes trucked or shipped north to Barranquilla. Trucked volumes also have higher transportation costs which either decrease realized oil prices or increase operating costs.
Cauca-7 Block, Cauca Basin (Gran Tierra 100% WI and Operator)
The acquisition of 97km of 2-D seismic on the Cauca-7 Block, which commenced in the 4Q:14, was completed in the 1Q:15. Processing and interpretation is underway.
Sinu-3 Block, Sinu San Jacinto Basin (Gran Tierra 51% WI and Operator) The acquisition of 487km of 2-D seismic on Sinu-3, which commenced in the 4Q:14, was completed in the 1Q:15. Processing and interpretation is ongoing. The company also commenced environmental impact assessments (“EIA”s) for future drilling on this block. Putumayo-10 Block, Putumayo Basin (Gran Tierra 100% WI and Operator)
To fulfill the work commitment for the first exploration phase of this contract, Gran Tierra plans to acquire 73km of 2-D seismic on this block this year. During the 1Q:15, the company continued preparations for the seismic acquisition.
Block 95, Bretaña field, Marañon Basin (Gran Tierra 100% WI and Operator)
As announced in Feb.2015, the company ceased all further development expenditures on the Bretaña field on Block 95 other than what is necessary to maintain tangible asset integrity and security. Gran Tierra has since commenced dismantling, removal and abandonment of the Bretaña long-term test facilities.
As announced in Feb.2015, the Company has refocused its strategy and resources on its core operations in Colombia. As a result of this change in strategy, in Brazil, the company will focus capital spending to facilities at the Tiê field. These facilities are expected to allow the company to maintain existing production levels.
Blocks 129, 142, 155, Recôncavo Basin (Gran Tierra 100% WI and Operator)
The First Appraisal Plan (“PAD”) phase will end 24.May.2015, before which Gran Tierra must decide whether to move to the next exploration phase. Gran Tierra has requested a suspension of the PAD phase and is awaiting a response from the ANP.
On 11.Mar.2015, the ANP suspended Tiê field operations due to region-wide facilities audits. Pursuant to this audit, Gran Tierra completed a risk analysis, prepared additional documentation and presented this to the ANP on 17.Mar.2015, and 10.Apr.2015. Gran Tierra expects operations will resume by 20.May.2015.
Gran Tierra initiated construction of an infield gas line connecting the 3-GTE-03-BA well to the Tiê Facilities. This tie-in is expected to be completed in the second quarter.
Importantly, the ANP has authorized the extension of Tiê field gas flaring through Jul.2015. The original gas flaring authorization was to expire Mar.2015. Block 224, Recôncavo Basin (Gran Tierra 100% WI and Operator) Gran Tierra received an extension to drill the Block 224 commitment well. The company now has one year following the approval of the pending EIA to drill the commitment well. Blocks 86, 117, 118, Recôncavo Basin (Gran Tierra 100% WI and Operator)
Gran Tierra completed the acquisition of the 3-D seismic program that had been initiated in the 4Q:14. Processing of the 3-D seismic is ongoing.
(Ecopetrol S.A., 14.Apr.2015) – Ecopetrol S.A. announced that pursuant to the procedures required by Law 226 of 1995, the Council of Ministers has issued an opinion in favor of the planned sale of Ecopetrol’s equity stake in Interconexión Eléctrica S.A. E.S.P. which was approved by Ecopetrol’s Board of Directors.
Ecopetrol’s equity stake in Interconexión Eléctrica amounts to 58,925,480 shares of common stock (equivalent to 5.32% of the subscribed and paid-up shares). The proceeds from the planned sale will be used for financing Ecopetrol’s investment plan.
(Ecopetrol S.A., 14.Apr.2015) – Ecopetrol S.A., as part of the procedures required for keeping available debt alternatives to finance its investment plan, has obtained authorization from the Ministry of Finance and Public Credit, pursuant to Resolution 0928 of 10.Apr.2015, to arrange for debt issuances in international capital markets in an aggregate amount of up to $3.175 billion.
This authorization in itself does not constitute an issuance of securities or a financing operation. Therefore, Ecopetrol must complete in due course all of the necessary approval procedures with the Ministry of Finance and Public Credit, as well as Ecopetrol’s own Board of Directors, before any debt issuance may be covered by this authorization.
(Energy Analytics Institute, 30.Mar.2015) – Information in this section, provided by Energy Analytics Institute editors and reporters, is hearsay and thus should be treated as such.
* A small group of Venezuelans are interested in acquiring an interest in Colombian oil company Pacific Rubiales.
* To stimulate investments in the oil sector, Venezuela has allowed almost all of the companies sell part of their dollars at the new Simadi Fx rate, which most recently closed at 191 bolivars per dollar.
* In 2014, Malaysa’s Petronas released its 11 percent interest in the PetroCarabobo heavy oil joint venture back to the Venezuelan government. PDVSA has assumed the interest in the meantime. Partners in PetroCarabobo include: PDVSA, Spain’s Repsol, and Indian companies ONGC, Oil India and Indian Oil Corp.
* Former PDVSA President Rafael Ramírez supposedly wants to run for the presidency of Venezuela.
* Venezuelan social programs are at risk unless there is an increase in the price of crude oil or there is a change by the Venezuelan government to reduce its reliance on oil income to sponsor its social programs.
* Supply of dollars unable to satisfy dollar demand thus forcing government to reduce allocation of dollars to importers and other seeking dollars.
* Russian president Vladimir Putin is expected to visit Venezuela soon to discuss bilateral trade between the countries.
* After the longest oil sector boom period in recent history in Venezuela, the country has no money set aside in a strategic oil fund or others to weather the pull back in oil prices.
* Parliament elections could take place in early December 2015.
Discussions between AVHI, PDVSA, and Venezuela’s Oil Ministry
Complaints from oil companies operating or contemplating operating and/or investing in Venezuela include, but are not limited to the following:
* The need to access the new competitive foreign exchange rate for all investments (CAPEX) and costs and expenses (OPEX) required by the mixed enterprises, licenses and PDVSA.
* The need for diluents for the projects in the Orinoco Heavy Oil Belt or Faja; application of the proposed extension to the Special Contributions Law.
* The need to be granted fiscal incentives (royalties, income taxes, etc.) according to results from basic engineering studies; the need to revise the payment of LCE over royalty volumes; the need to revise natural gas royalty payments for re-injected volumes; and the need to define a mechanism for CERTs.
In response to these stated issues, Venezuela’s Oil Ministry Asdrubal Chávez responded as such:
* We recognize this is a difficult situation and we want to work together with AVHI more intensely to find solutions to the problems.
* We acknowledge the effects of the foreign exchange system over production costs; progress has been made to solve this issue (i.e. Sicad I and Sicad II), but we need to make proposals to the government to reach a solution.
* Vice-Minister Angel González has been designating with this assignment to determine a reasonable value for a foregin exchange rate applicable to the petroleum industry.
* We are going to continue granting autonomy to the mixed enterprises or joint ventures.
* We need to work together to improve production costs, and become more efficient; it’s critical to adjust service companies’ costs.
* We want to form joint AVHI-oil ministry-PDVSA executive working groups, tasked with maintaining more regular meetings and studying proposals to solve issues of common interest.
* We are working in the oil ministry to solve the issues related to production of diluted crude oil mixed with naphtha.
In response to these stated issues, PDVSA’s President Eulogio Del Pino responded as such:
* Within our competences, we have been taking measures to solve issues discussed in the AVHI-oil ministry-PDVSA institutionalized dialogue mechanism.
* In terms of the agenda presented by AVHI, we recognize the critical issues of the foreign exchange regime and the decline in oil prices and their impact over the economic viability of the oil industry.
* We can advance information regarding the new foreign exchange system announced by President Nicolas Maduro and we plan to announce that new investments and exports from these investments will be exchanged at the new floating, market rate.
* All the resources stemming from financing and from exports from new projects will be exchanged at a new floating rate (new foreign agreement to be announced soon).
* Reviewing the previous meetings’ minutes of the AVHI-oil ministry-PDVSA dialogue, we have progressed in most of the issues discussed: increasing financial authorization levels, adapting the mixed enterprises’ structure to develop major projects, a mixed payments scheme for natural gas licenses (agreement with YPERGAS), drilling rigs and personnel managed by mixed enterprises, delegation of procurement activities to mixed enterprises, diluent availability to Faja’s new developments, internal auditing process of our HSSE policies and activities, payments of dividends to partners.
* In the Faja’s Boyacá division, we are proposing the creation of a National Strategic Development Zone aimed at the development of exploration and production activities: the objective will be to provide incentives to improve the economic viability of the projects. Some of the possible fiscal incentives applicable to the projects are: accelerated depreciation, carry-over of ten-years of losses (for income tax calculations), shadow tax exemption, royalty reduction to twenty percent, and petroleum exports exchanged at the Sicad II rate.
* We need to improve our communication with our partners; we want to enhance cooperation and use the capabilities and best practices of AVHI member companies.
* One of our main objectives is to regulate all of the activities and contracts with mixed enterprises.
* We want to maintain and reinforce this institutionalized dialogue mechanism with AVHI: we support the proposal of a joint workgroup that can agree on proposals and present them at our quarterly meetings.
(Ecopetrol S.A., 28.Mar.2015) – Ecopetrol S.A. hereby reports that, at the shareholders’ meeting held on March 26, 2015 , the following amendments to the rules and procedures governing our shareholders’ meetings were approved in order to implement the corporate governance practices recommended by the Superintendence of Finance in the New Code of Corporate Best Practices of Colombia.
The approved amendments are the following:
Voting on amendments to the bylaws: a new paragraph has been adopted providing that, in the event of a proposed amendment to the bylaws, there shall be a separate vote on any specific article being amended whenever such a vote is requested by a shareholder or group of shareholders representing at least 5% of the share capital during a shareholders’ meeting (Article 3, paragraph 1).
Increase of the advance notice time for convening ordinary and extraordinary meetings: the required advance notice for convening ordinary meetings has been increased from twenty (20) business days to thirty (30) calendar days and the required advance notice for convening extraordinary meetings has been increased from eight (8) calendar days to fifteen (15) calendar days (Article 4).
Dispensing with advanced submission of proxies: repeal of Article 7 section 4, which related to the previous proxy review stage.
(Energy Analytics Institute, Piero Stewart, 26.Mar.2015) – External issues deprived Ecopetrol of the ability to produce 64,000 barrels per day (b/d) in 2014 as follows:
An estimated 28,000 b/d was not produced due to community protests; 13,000 b/d was not produced due to terrorist acts on oil installations while 9,000 b/d was not produced due lack of or delays obtaining environmental permits, reported the daily newspaper El Espectador.
(Ecopetrol S.A., 26.Mar.2015) – Ecopetrol S.A. hereby reports that, at the Shareholders’ General Assembly held on March 26, 2015, the following changes were made to its bylaws:
The following corporate governance practices recommended by the Superintendence of Finance in the New Code of Corporate Best Practices of Colombia have been adopted:
— Extension of the deadline for convening ordinary and extraordinary meetings (amendment to Articles 19 and 20).
— Majority of the Board of Directors to be comprised of independent directors (amendment to paragraph 1, Article 23).
— Possibility of carrying out different types of evaluations of the Board of Directors (amendment to paragraph 5, Article 23).
— Reference to guidelines regulating the appointment and duties of the President of the Board of Directors and the Secretary of the Board of Directors (new paragraph 6, Article 23).
— Modification in the name of the Audit Committee of the Board of Directors in order to make explicit its risk management role (amendment to Paragraph 27.1 of Article 27).
— Obligation to comply with voluntarily adopted corporate governance practices (new Article 52).
The company’s reserves accounts amounting to COP$14.76 trillion were capitalized by increasing the nominal value of shares from COP$250 to COP$609 per share. This capitalization demonstrates the confidence of investors in the Company and boosts its long term financial sustainability.
(Energy Analytics Institute, Ian Silverman, 26.Mar.2015) – Ecopetrol continues to be a solid company with many growth opportunities in its different business segments, said Ecopetrol’s outgoing president Javier Genaro Gutiérrez said during his presentation of the company’s financial and operational results
“We have made adjustments on all fronts to overcome the drop in international prices and maintain production levels. We are also strengthening our exploration and production portfolio,” he added.
(Energy Analytics Institute, Piero Stewart, 25.Mar.2015) – Ecopetrol’s shareholder assembly approved a dividend equivalent to 70 percent of the 7.81 billion peso profit obtained in 2014.
The total dividend was for 5.47 billion or 133 pesos per share, of which 4.8 billion was destined for the government and 0.670 billion pesos was destined for minority shareholders, reported the daily newspaper El Tiempo.
In comparison to 2013, the 397,122 minority shareholders at 31 December 2014, the 2014 dividend was 0.560 billion pesos or 45.5 percent lower than the prior year.
At 31 December 2013, Ecopetrol had 425,840 shareholders. However, by 31 December 2014, an estimated 28,700 Ecopetrol shareholders had sold their shares, leaving 397,122 shareholders.
(Energy Analytics Institute, Piero Stewart, 25.Mar.2015) – During the first two months of 2015 Ecopetrol’s production remained around 725 Mb/d primarily due to record production at the Castilla and Chichimene fields located in El Meta, and in the La Cira Infantas field located in Middle Magdalena Medio.
This average represents an increase of 20 Mb/d compared to the average of 705 Mb/d registered in the first two months of 2014, reported the daily newspaper El Espectador.
Ecopetrol announced its production averaged 726 Mb/d in January 2015 and 725 Mb/d in February 2015. The volumes in both months surpassed the goal of 710 Mb/d set by the company.
Of the average production in the first two months of 2015:
– 36% came from the Orinoquía region, which includes the Meta and Casanare fields;
– 14% came from the Central Region which includes the Middle Magdalena and Catatumbo fields;
– 5% came from the South Region which includes the Huila, Tolima and Putumayo fields; and
– the remaining 45% came from partner fields that include assets operated by other companies whereby Ecopetrol has a participation.
Record production from the Castilla field, operate directly by Ecopetrol, surpassed 124 Mb/d in February 2015 while activities in the La Cira Infantas field (a contract between Oxy and Ecopetrol), helped production reach 40.6 Mb/d on March 5, a production figure that was last reached in 1945.
Another factor influencing results was the increase in production at the Chichemene field also operated directly by Ecopetrol and whereby production reached a record 85 Mb/d in January and was averaging close to 80 Mb/d in February.
Other increases in production were also reported at the Cantagallo and Casabe fields in the Middle Magdalena. Combined the two fields reported a production increase of 1.3 Mb/d.
(CGG, 19.Mar.2015) – France’s CGG has been awarded a contract by a subsidiary of Anadarko Petroleum Corporation to acquire and process a 6,299-square mile (16,314square kilometers) 3D seismic survey on the Caribbean coast offshore Colombia.
The survey will be the largest marine seismic program ever acquired in Colombia and follows CGG’s successful completion of Anadarko’s 2,213square mile (5,500-square kilometer) 3D Fuerte survey offshore Colombia in 2013. The survey, covering portions of the Col-1 and Col-2 blocks, will be acquired by the Oceanic Sirius and Oceanic Vega. These environmentally certified vessels are the flagships of CGG’s seismic fleet. Each vessel will tow a 39 x 393 x 26,574 foot (12 x 120 x 8,100 meter) spread using Sercel’s Sentinel steerable solid streamers and CGG’s proprietary Dovetail efficient acquisition solution designed to achieve more regular sampling and reduce infill. The survey will start in the second quarter of 2015, subject to regulatory approval. The survey data will be processed in CGG’s Houston subsurface imaging center.
Jean-Georges Malcor, CEO, CGG, said: “We are very pleased to have been selected for this important contract, based on our advanced technology, the tight integration between our marine seismic acquisition and subsurface imaging groups and our deep in-country operational experience in Colombia. A project award of this magnitude underlines the confidence Anadarko has in our technology and expertise. We look forward to once again helping Anadarko reach its exploration goals in Colombia.”
(Pacific Rubiales Energy Corp, 14.Mar.2015) – Pacific Rubiales Energy Corp. and Ecopetrol, S.A. have agreed not to extend the Rubiales and Pirirí Field Association Contracts, expiring in June 2016 . Ecopetrol will evaluate different alternatives for the operation of the Rubiales Field. Meanwhile, Pacific Rubiales will consider submitting a new proposal to operate the field after the contract expiry. The companies have expressed interest in developing further business opportunities for the benefit of both parties and the country.
Pacific Rubiales, a Canadian company and producer of natural gas and crude oil, owns 100% of Meta Petroleum Corp., which operates the Rubiales, Piriri and Quifa heavy oil fields in the Llanos Basin, and 100% of Pacific Stratus Energy Colombia Corp., which operates the La Creciente natural gas field in the northwestern area of Colombia. Pacific Rubiales also previously acquired 100% of Petrominerales Ltd., which owns light and heavy oil assets in Colombia and oil and gas assets in Peru , and 100% of C&C Energia Ltd., which own light oil assets in the Llanos Basin. In addition, the company has a diversified portfolio of assets beyond Colombia , which includes producing and exploration assets in Peru, Guatemala, Brazil, Guyana and Papua New Guinea.
The company’s common shares trade on the Toronto Stock Exchange and La Bolsa de Valores de Colombia and as Brazilian Depositary Receipts on Brazil’s Bolsa de Valores Mercadorias e Futuros under the ticker symbols PRE, PREC, and PREB, respectively.
(Gran Tierra Energy Inc., 12.Mar.2015) – Gran Tierra Energy Inc. announced cost reductions in line with its strategy to preserve its strong balance sheet and maximize potential for future growth. All dollar amounts are in United States (U.S.) dollars unless otherwise indicated.
In addition to recently announced reductions in 2015 capital expenditures, the company has focused on reductions to Gran Tierra’s operating expenses and general and administrative costs and lower service and transportation costs. These cost reduction initiatives and increased working efficiencies will allow the company the flexibility and financial capacity to react to opportunities that may arise from a continuing low oil price environment as well as to be able to quickly return to drilling from its own inventory in an improving price scenario. Gran Tierra has identified a number of expected cost savings for 2015:
Gran Tierra has significantly reduced full-time employees. The reduction is expected to exceed 20% from previous staffing levels, to contribute to an overall projected 22% reduction from 2014 general and administrative costs, excluding one-time termination costs and after allocations to capital and operating expenses. A few replacements for certain positions may be considered in the future, but the majority will not be replaced in the current environment;
In 2015, Gran Tierra expects to realize $14 million in total budgeted labor cost savings associated with the reduced full-time employees and contractors, excluding one-time termination costs and before allocations to capital and operating expenses. On an annualized basis the budgeted labor cost savings are expected to be approximately $19 million before allocations to capital and operating expenses and excluding one-time termination costs; Gran Tierra is in ongoing negotiations with suppliers and service providers to achieve further savings that it expects to further reduce operating costs;
In Colombia , as a result of negotiations with Gran Tierra’s crude oil transporters and a planned increase use of pipelines instead of trucking to transport oil, reduced transportation costs are anticipated to result in the company realizing a net savings of approximately $5.20 per barrel of oil equivalent (BOE). Gran Tierra plans to ship approximately 75% of production via pipeline in 2015 compared to 48% shipped via pipeline in 2014. These plans are supported by decreased downtime experienced on the Oleoducto Transandino (OTA) pipeline and by new alternate arrangements for shipping via the Oleoducto de Crudos Pesados (OCP) pipeline through Ecuador . The OCP pipeline is the primary transportation alternative when OTA is not available. Gran Tierra has also negotiated trucking tariff reductions of between 5% and 8%.
Due to the continued low oil price environment, Gran Tierra expects to pay lower “High Priced Rights” royalties and current taxes in Colombia; and,
As a result of the strengthening of the U.S. dollar against the local currencies in countries where Gran Tierra operates, the company expects to realize significant savings for costs denominated in those local currencies.
Funds flow from continuing operations before effects of foreign exchange and inventory fluctuations and assuming 75% of Colombian production is delivered via pipeline is expected to be approximately:
$85 to $105 million for 2015 assuming an average of Brent oil price of $50 for 2015 which corresponds to NAR production of 18,200 to 19,200 barrels of oil equivalent per day (BOEPD)
$105 to $125 million for 2015 assuming an average Brent oil price of $55 for 2015 which corresponds to NAR production of 17,700 to 18,700 BOEPD; or,
$135 to $155 million for 2015 assuming an average of Brent oil price of $60 for 2015 which corresponds to NAR production of 17,500 to 18,500 BOEPD.
(Ecopetrol, 6.Mar.2015) – Ecopetrol announces that its Board of Directors appointed Mr. Juan Carlos Echeverry as the new CEO of the company, effective April 6, 2015.
With extensive knowledge of economics, the ability to lead processes of change, experience in public administration and prior experience as member of the Board of the company, Mr. Echeverry meets all the conditions to carry out the reforms that the current price environment demands and execute the institutional strategy re-alignment in which the company has been engaged in recent months.
Juan Carlos Echeverry , born in 1962, is an economist from the Universidad de los Andes, and holds degrees in International Economy from the Kiel Institute for the World Economy and a PhD in Economics from New York University. He was Dean of the faculty of Economy at Universidad de los Andes and Head of the National Planning Department as well as Ministry of Finance and Public Credit. He has also been a consultant and commentator in economics and has advised several governments and companies. Until a few months ago he was Executive Director for Colombia and Ecuador at the Inter-American Development Bank.
The process of selection and appointment of the new CEO took place in three stages. The first involved the identification by a prominent international executive search firm of candidates who fulfill the conditions consistent with the profile defined by the Board. The second stage was the selection by the firm of a small number of candidates, two of whom the Board decided to interview and the third stage included the election of the new CEO, who counted on the affirmative vote of six out of the nine members of the Board.
Following the decision, the Board endorsed the appointment by consensus and instructed the management of Ecopetrol to carry out the corresponding splicing at the earliest.
The Board of Directors also appointed Camilo Marulanda as Executive Vice President. Born in 1978, Mr. Marulanda is an economist from the Universidad de los Andes, with Marketing studies and a MBA from this university. Prior to join to Ecopetrol´s Group in 2003, he worked at International Investment Intelligence and Procter Gamble.
Ecopetrol’s Board of Directors is comprised by the Ministry of Finance and Public Credit, the Ministry of Mines and Energy, the Head of the National Planning Department and six independent members of which one is appointed by the producing regions in Colombia and other by the minority shareholders.
(Ecopetrol S.A., 2.Mar.2015) – Ecopetrol announces its results for the fourth quarter of 2014 and the full year 2014.
– Net proven reserves of crude oil, condensate and natural gas owned by the company, including its interest in affiliates and subsidiaries, as of December 31, 2014, were 2,084 million barrels of oil equivalent (mmboe), a 5.7% increase compared to 1,972 mmboe in 2013. The reserve replacement ratio in 2014 was 146%, up from the 139% reported in 2013. The reserves/production ratio increased to 8.6 years.
– In the fourth quarter of 2014, the production recovery trend was reinforced, with growth of 1.4% compared to the third quarter 2014, reaching 765.1 mboed, thanks to improved environment conditions and continued development of projects at the Castilla and Chichimene fields. For the full year 2014, average production was 755.4 mboed, a decline of 4.2% versus 2013, due to environment, public order and operating issues that were particularly challenging in the second quarter.
– Net income in 2014 was COP$7,813 billion, 41% below that of 2013, primarily the result of the drop in sale prices, lower volumes sold and the cost increase.
Ecopetrol S.A. announced its audited financial results, both consolidated and unconsolidated, for the fourth quarter and full year 2014, prepared and filed in Colombian pesos (COP$) in accordance with the Public Accountancy Legal Framework (Regimen de Contabilidad Publica, RCP) of Colombia’s General Accounting Office. Some figures in this release are presented in U.S. dollars (US$), as indicated. The financial results in the main body of this report have been rounded to one decimal place. Figures presented in COP$ billion are equivalent to COP$1 thousand million (COP$1,000,000,000). Additionally, some 2013 figures have been reclassified to be comparable to those of 2014.
In the opinion of Ecopetrol’s CEO, Javier Gutierrez:
“In 2014, we obtained important achievements, such as the discoveries in offshore exploratory blocks; the strengthening of the transportation segment, which continues the optimizations needed to achieve competitive margins at the level of the best in the industry; and the generation of positive EBITDA in the refining segment as we enter the final phase of the Cartagena Refinery project. Affiliates of the Corporate Group contributed to the positive results. Ecopetrol America Inc. reached a production of 7.7 mboed in the fourth quarter of 2014, thereby beginning to generate revenues that will allow its future sustainability. As far as petrochemicals, Propilco significantly increased its earnings, benefiting from better international prices of raw material and higher volumes of propylene supply from the Barrancabermeja refinery.
The Corporate Group’s average yearly production was 755.4 mboed, 33 mboed below that of the previous year, due to operating environment situations (-22 mboed), attacks (-5 mboed), environmental constraints (-9.5 mboed), offset by the increase in production of affiliates and subsidiaries (+3.5 mboed).
The average sales price of the basket of Ecopetrol crude, gas and products was US$10.6 per barrel lower than in 2013, which, coupled with a 7% devaluation of the average exchange rate, had a significant impact on our financial results. It is important to mention that the exchange rate has two effects on the company’s financial results: regarding operations, a higher exchange rate has a positive effect given that 60% of our sales are dollar denominated, although some of our purchases are also dollar denominated, but in a lower share; on the other hand, devaluation has a negative impact on non-operational results due to the Colombian peso valuation of the dollar denominated debt.
Our net income in 2014 was COP$7,813 billion, 41% below that of 2013. This decline is explained by several factors, starting with the 7% drop in our revenues, in line with the decrease in production volumes and prices. Cost of sales, specifically variable costs, decreased 2% as a result of lower purchase price of crude, gas and products, offset by higher purchase volumes of naphtha as crude diluent. As for fixed costs, there was an increase of 18%, the result basically of the inclusion of transportation costs based on the Ship or Pay (SoP) fee as part of the implementation of the new transportation model beginning with the start-up of Cenit in April of 2013 (total fixed costs increased COP$1.7 trillion, of which COP$1.23 trillion correspond to the SoP fee). It should be noted that these additional costs generated by the new transportation business model are offset by the operating income of our affiliate Cenit. As a result of all of the above factors and variables, gross income decreased 23%.
Operating income for the year decreased 30%, affected additionally by higher exploratory expenditures resulting from an extended campaign, which in total had a higher cost of COP$646 billion more than the prior year. Furthermore, in a downward price situation as seen since mid-2014, it was necessary to revise the value of assets, inventories and oil investments. This analysis reflected adjustments in operating expenditures from oil investments and decline in the valuation of assets for a total of COP$571 billion.
Non-operating variables also affected results negatively, due mainly to higher expenditures derived from U.S. dollar-denominated debt interest and higher expenditures because of the difference in exchange rate on the outstanding debt balance.
Taking into account the above, pre-tax net income fell 36%, which, combined with a higher effective tax rate at 40.48% levels (compared to 34.48% in 2013), resulted in net income for the period of COP$7,813 billion, a decrease of 41% compared to that of 2013. EBITDA margin was 39%, a very competitive level compared to other companies in the industry.
In the fourth quarter of 2014, there were several important highlights among which I will mention the following:
In production, the field Chichimene set a record in production of 80 thousand barrels a day, and we began 8 secondary improved recovery pilots, bringing the total pilots underway for the year to 13.
In exploration, we announced two discoveries: 1) the well Orca in offshore waters of Colombia, offering a promising perspective for this basin; and 2) the well Nueva Esperanza-1, confirming the potential of the CPO-09 block in Meta province. These two discoveries add to others announced in 2014 in Colombia (Tibirita, Golosa and Cacica) and the U.S. Gulf Coast (Leon and Rydberg).
In transportation, we completed the expansion of the Ocensa Delta Project and began the operation of 23,500 additional barrels per day in the SantiagoPorvenir system.
In refining, we obtained 96.3% completion of the Cartagena refinery modernization project.
In December, we announced our investment plan for 2015 of US$7.86 billion, in accordance with the current price situation and in line with the strategy of value generation and emphasis on production.
Ecopetrol is a company that responds swiftly to challenging situations. For this reason, we have initiated a cost and expenditure optimization plan in pursuit of structural savings and economies of scale that allow us to operate in a cost-effective manner, within a context of low prices, which will continue to affect financial results in 2015, but without compromising the strength and sustainability.
Regarding the claims of possible illegal payments on behalf of third parties to former employees of Ecopetrol, we want to emphasize that we have a zero tolerance corruption policy and therefore we have filed a complaint to the authorities, we have collaborated on a timely basis with the judicial system in order to clarify such events and so that those responsible be convicted, as well as imposing internal sanctions and penalties. During the last years Ecopetrol has strengthened its internal control system, of which the Ethics and Compliance office is part of, in order to prevent, detect and penalize inappropriate behaviors that affect our ethics and Corporate Governance. The Board of Directors, the senior management, and all of the employees are committed in this anticorruption crusade.”
(Gran Tierra Energy Inc., 2 Feb.2015) – Gran Tierra Energy Inc. announced the results of an independent reserve evaluation of the company’s reserves by Gran Tierra Energy’s qualified reserve evaluator GLJ Petroleum Consultants Ltd. (GLJ) effective December 31, 2014.
Through continued strong reservoir management and appraisal drilling in Colombia and Brazil in 2014, Gran Tierra Energy was able to replace production and add reserves. However in Peru, negative well results after year-end will result in reserves being revised downward. The results of the company’s development program in the Moqueta field in Colombia have been encouraging, adding approximately 14% to it’s existing Proved (1P) company interest reserves in that country. Reservoir performance and additional development drilling contributed to positive 1P reserves technical adjustments at Costayaco.
In Brazil, due to new production from the Agua Grande formation, results of seismic reprocessing and additional reservoir volume in the Sergi formation, Gran Tierra Energy successfully increased 1P reserves in that country by 68%. Although 2014 Proved plus Probable (2P) and Proved plus Probable plus Possible (3P) reserves also appear to have increased at year-end, new drilling data from the Bretaña field in Peru subsequent to year-end indicate that the 2P reserves and 3P reserves associated with that field will be reduced after year-end. A new reserve report for the Bretaña field is expected before the end of the first quarter, once new maps, reservoir rock volumes and related data are integrated and evaluated.
Year-end 2014 highlights
Year-end 2014 highlights, calculated in accordance with United States Securities and Exchange Commission (SEC) rules (comparisons are to 2013 year-end amounts) follow:
In Peru, as announced on January 20, 2015, Gran Tierra Energy expects the Bretaña Sur well results will remove all Possible reserves associated with the southern L4 lobe of the Bretaña field booked at yearend 2014.
A reduction in Probable reserves in the field is also expected, the magnitude of which is unknown at the moment.
A new reserve report for the Bretaña field will be provided after analyzing new vertical seismic profile data from the new well, to reconcile the unexpected time-depth conversion encountered by the well against the time-depth conversion from the previous four wells in the Bretaña field that was used for the pre-drill seismic mapping. The new reserve report incorporating the new mapping and reservoir characterization is expected before the end of the first quarter;
Total 1P oil and gas reserves net after royalty (NAR) were 37. million barrels of oil equivalent (MMBOE) at December 31, 2014, compared with 42.1 MMBOE in 2013 (100% light and medium oil and liquids compared with 95% at year-end 2013), and after producing 9.2 MMBOE of company interest oil and gas before royalties, inventory adjustments and losses or 7 MMBOE NAR before inventory adjustments and losses, excluding Argentina production. The decrease was primarily due to the sale of Gran Tierra Energy’s Argentina business unit during 2014 which contributed 4.4 MMBOE NAR of 1P oil and gas reserves at December 31, 2013;
After producing 1.7 million barrels of oil (MMbbl) NAR before inventory adjustments from the Moqueta field in Colombia in 2014, appraisal drilling resulted in increased 1P reserves of 14% to 15.5 MMbbl, 2P reserves increased by 20% to 23.2 MMbbl and 3P reserves increased by 17% to 33.6 MMbbl on a company interest basis, and 1P reserves increased to 11.1 MMbbl, 2P reserves increased to 16.6 MMbbl and 3P reserves increased to 23.9 MMbbl, each on a NAR basis;
The Costayaco field in Colombia continued its strong performance. Costayaco 1P reserves decreased to 19.1 MMbbl NAR at year-end 2014 from 20.2 MMbbl NAR at year-end 2013, after production of 4.2 MMbbl NAR before inventory adjustments in 2014;
In Brazil, due to new production from the Agua Grande formation, results of seismic reprocessing, and additional reservoir volume in the Sergi formation, Gran Tierra Energy successfully increased 1P reserves by 68%;
Total 2P reserves NAR were 108.5 MMBOE at December 31, 2014, compared with 111.9 MMBOE in 2013 (99% oil and liquids compared with 97% at yearend 2013), prior to adjusting for the sale of the Argentina business unit, which had contributed 6.4 MMBOE NAR of 2P oil and gas reserves at December 31, 2013. Total 2P reserves are expected to be adjusted downward with release of the new Bretaña reserve report before the end of the first quarter;
Total 3P reserves NAR were 170.3 MMBOE at December 31, 2014, compared with 183.9 MMBOE in 2013 (99% oil and liquids compared with 94% at yearend 2013). The Argentina business unit contributed 16.7 MMBOE NAR of 3P oil and gas reserves at December 31, 2013. Total 3P reserves are expected to be adjusted downward with release of revised Bretaña reserves within a month;
In Peru, the Bretaña field contributed 2P reserves of 57.9 MMbbl NAR and 3P reserves of 104.4 MMbbl NAR. These are expected to be adjusted downward with release of a new Bretaña reserve report before the end of the first quarter;
Based on Gran Tierra Energy’s 2014 year-end SEC NAR reserves and Gran Tierra Energy’s 2014 total NAR production, Gran Tierra Energy’s 1P, 2P, and 3P reserves life indices are 5.3 years, 15.4 years, and 24.2 years respectively; The 2P and 3P reserve life indices are expected to be adjusted downward with release of the new Bretaña reserve report before the end of the first quarter;
Annual production for 2014, excluding Argentina production, averaged 25,182 company interest barrels of oil equivalent per day (BOEPD) before royalties, or 19,283 BOEPD NAR, both before inventory adjustments, or 18,523 BOEPD NAR adjusted for inventory changes and losses, including 17,619 BOEPD NAR from Colombia, and 904 BOPD NAR from Brazil. Production in the fourth quarter of 2014 was 18,953 BOEPD NAR before inventory adjustments or 17,169 BOEPD NAR adjusted for inventory changes and losses.
(Gran Tierra Energy Inc., 2.Feb.2015) – Gran Tierra Energy announced that the employment of its Chief Executive Officer and President Mr. Dana Coffield has been terminated. Coffield tendered his resignation from the Board of Directors, effective February 2, 2015. Coffield’s resignation from the Board of Directors was not the result of any disagreement with the Board of Directors.
The Board has appointed Chief Operating Officer Mr. Duncan Nightingale, as interim President and Chief Executive Officer, Mr. Jeffrey Scott as the Executive Chair of the Board of Directors and Mr. Scott Price as the Lead Independent Director.With these changes, Scott will become more involved in the operations of the company and provide day to day assistance to Nightingale. Scott resigned from the Audit Committee and Price was appointed as a member to that committee. These changes are effective immediately.
Nightingale is a 5 ½ year veteran of Gran Tierra Energy who served in the Calgary, Canada office as the Vice President of Exploration from September 2009 to January 2011, in the Bogotá, Colombia office as the Senior Manager Project Planning and Exploration from January 2011 until August 2011, as President of Gran Tierra Energy Colombia from August 2011 until August 2014, and was promoted to Gran Tierra Energy’s Chief Operating Officer on September 1, 2014.
Scott was a founder of Gran Tierra Energy and has served as the Chairman of the Board of Gran Tierra Energy since January 2005. Since 2001, Scott has served as President of Postell Energy Co. Ltd., a privately held oil and gas producing company. He has extensive oil and gas management experience, beginning as a production manager of Postell Energy Co. Ltd in 1985 advancing to President in 2001. Also, since February 2012, Scott has served as Executive Chairman of Sulvaris Inc., a private fertilizer technology company. Scott is also currently a director of Petromanas Energy Inc. He was previously a director of Tuscany International Drilling Inc., Essential Energy Services Trust, Suroco Energy, Inc., VGS Seismic Canada Inc., High Plains Energy Inc., Saxon Energy Services Inc. and Galena Capital Corp., all of which are publicly-traded companies.
Nightingale said: “I’m excited about my new position with the company and honored the Board has selected me for this position. I recognize, however, that it is not business as usual.”
“The Board feels it is time to re-examine the company’s strategy,” said Scott. “These are very challenging times and while we have a large inventory of opportunities and significant financial capacity, we believe it is unwise to accelerate certain opportunities in the current pricing environment. We will update the market as to this shift in our strategy in the near-term.”
(Gran Tierra Energy Inc., 20.Jan.2015) – Gran Tierra Energy Inc. said crude oil and natural gas production from continuing operations averaged approximately 25,200 barrels of oil equivalent per day (BOEPD) gross working interest (WI) in 2014, or approximately 19,300 BOEPD net after royalties (NAR) before adjustment for inventory changes and losses, or approximately 18,500 BOEPD NAR adjusted for inventory changes and losses. Approximately 99% of the 2014 production is oil, with the balance consisting of natural gas.
(Gran Tierra Energy Inc., 20.Jan.2015 – Gran Tierra Energy Inc. provides an operations update on its activities in the Chaza Block in the Putumayo Basin in Colombia.
The Eslabón Sur exploration well reached a true vertical depth of 9,708 feet. Mud log and electric log data acquired during and after drilling indicate only non-commercial hydrocarbons present in the primary Caballos Reservoir. The secondary Kg Reservoir was encountered twice as a result of faulting in the structure. The upper Kg Reservoir encountered 24 feet of net oil pay and the lower Kg Reservoir encountered 4 feet of net oil pay. The Eslabón Sur well has been suspended for further evaluation of these pay zones.
The Moqueta-16 and Moqueta-17 wells have successfully been drilled, with Moqueta-16 tied in and currently on production, and Moqueta-17 currently being tested.
Gran Tierra anticipates spudding the deviated Moqueta-18i well in mid-March, 2015. This well will be drilled from the existing Moqueta-1 platform and will target a downhole position down dip from the Moqueta-13 well, which is the deepest producer in the southern block. The primary objective of the well is to test the position of the Caballos reservoir oilwater contact in the eastern part of the Moqueta field. Depending on results, the well could be completed as a water injector to maintain the reservoir pressure in the southern block of the field, or if the well intersects an oil column in the Caballos, the well could be completed as a producer. Water injection in the main block of the field has yielded very positive pressure maintenance response and associated production increases.
Gran Tierra has a 100% working interest and is operator of the Chaza Block in the Putumayo Basin.
(Energy Analytics Institute, Ian Silverman, 29.Oct.2013) – Petrobras plans to sell its interest in onshore blocks and two pipelines to France’s Perenco for $380 million to focus more attention on projects in Brazil, reported the daily newspaper El Espectador
The deal includes interest in: 11 onshore blocks that are producing an average 6,530 boe/d, the Petrobras Colombia and Alto Magdalena pipelines which have capacity to transport 14,950 b/d and 9,180 b/d, respectively.
(Energy Analytics Institute, 30.Sep.2013) – Information in this section, provided by Energy Analytics Institute editors and reporters, is hearsay and thus should be treated as such.
The names of our many sources have been withheld to protect their identities and family members in Venezuela.
A number of gasoline stations along VenezuelaColombia border remain closed due to a lack of supply. [El Universal]
Venezuelan Oil Minister and PDVSA President Rafael Ramirez was named as Venezuela’s Economic Vice President by President Nicolas Maduro. [EAI]
CROSS BORDER DEALS
T&T and Venezuela signed a cross border natural gas deal. Deal signed by Venezuelan Oil Minister Rafael Ramirez and Trinidad Energy Minister Kevin Ramnarine. [EAI]
Trinidad Energy Minister Kevin Ramnarine was been under pressure in Trinidad for recent agreements reached with Venezuela regarding cross-border commercialization deals for the Loran-Manatee gas fields. [EAI]
Central American energy connection could reduce prices from Guatemala to Panama. [El Espectador]
Colombia’s state oil company Ecopetrol announces new oil discovery at Guainiez-1 well in Guaroa. [EAI]
Chile’s ENAP sells 49% interest in Primax Peru and Primax Ecuador for $312 mln. [El Universo]
YPFB Corp. completed 23,141 domestic gas connections in May.2013. [La Razon]
Interconexión Eléctrica S.A (ISA) wins bid for design, financing, construction, operation and maintenance of Encuentro-Lagunas project in Chile. [Portafolio.co]
Peru’s Energy and Mining Ministry has identified hydrocarbon and electric sector projects worth $26,530 mln thru YE:20. [El Comercio.pe]
Electric consumption in Uruguay reaches 1,808 MW on Jun.20.2013 up from record of 1,745 MW achieved on Jul.4.2011. [El Pais]
EXPLORATION & PRODUCTION
Bolivian officials search for hydrocarbon investments and technology at Russian Gas Forum [La Razon]
Gas output in Bolivia reached 57.08 MMcm/d in the 1Q:13, up 24.2% compared with 45.94 MMcm/d in the 1Q:12. [La Razon]
Bolivia’s average production was 56.2 MMcm/d in the first five months of 2013. [El Espectador]
YPFB plans investments of $8,406 mln during 2013-2016. [La Razon]
YPFB Petroandina SAM President Jaime Arancibia announced the Lliquimuni block could contain 1 Tcf. [La Razon]
France’s Total announced plans to develop the 3 Tcf Incahuasi field in Bolivia, after drilling the ICS-2 exploration well. [La Razon]
Russia’s Rosneft is interested in investing in exploration and development activities in Bolivia. [La Razon]
Repsol’s oil production in Bolivia rose to 3,400 b/d from 2,600 b/d. [La Razon]
Ecuador’s Hydrocarbon Secretariat expects oil production to average 518,503 b/d in 2013, up from 503,610 b/d in 2012. [EAI]
Ecuador’s Hydrocarbon Secretariat expects the country’s petroleum sector will realize investments of $3.6 bln in 2013, up from $2 bln in 2012. [EAI]
Extraction of oil in the Yasuni National Park will utilize new technologies, Wilson Pastor said on state television. [EAI]
Ecuador gov’t cancels $34.5 mln committed by Germany for the protection of the Yasuni National Park. [EAI]
Mexico’s state oil company Pemex creates company to search for oil deep offshore and shale gas in the USA.
Venezuela’s Oil Minister Rafael Ramirez said during an interview on Venezuelan state television or VTV that the decision to stop sending oil to the US had to be taken by Venezuelan President Nicolas Maduro. [EAI]
Mexico’s left is betting on more autonomy for Pemex without changing the constitution.
Venezuela is looking for additional partner(s) for the Mariscal Sucre gas project offshore, Venezuelan Oil Minister Rafael Ramirez says. [EAI]
Spanish gov’t requests legal security and respect for the rules of the game in Argentina. [La Nacion]
Venezuelan imports of electricity from Colombia continue to increase. [El Universal]
Gas imported by Argentina and Brazil up 56.95% and 20.26%, respectively, in the 1Q:13 compared with the 1Q:12 [La Razon]
Argentina imported 14.63 MMcm/d from Bolivia in the 1Q:13 compared with 9.32 MMcm/d in the 1Q:12 [La Razon]
Brazil imported 32.01 MMcm/d from Bolivia in the 1Q:13 compared with 26.62 MMcm/d in the 1Q:12 [La Razon]
Bolivia exported an average 14.1 MMcm/d of gas to Argentina in the first five months of 2013. [El Espectador]
Bolivia exported an average 31.3 MMcm/d of gas to Brazil in the first five months of 2013. [El Espectador]
Enarsa owes YPFB $180 mln for gas deliveries made in Mar.2013 [La Razon]
PDVSA currently exports 330,000 b/d to India but plans to increase this figure to 400,000 b/d, PDVSA President Rafael Ramirez said. The official said PDVSA is also exporting 630,000 b/d to China. [EAI]
PDVSA owed $270 mln by Paraguay’s Petropar according to Paraguayan News Portal. [EAI]
FINANCE / EQUITY AND DEBT OFFERINGS
Ecopetrol $900 mln bond issue was oversubscribed by 3.1 times. [El Espectador]
Ecopetrol road show was led by Bank of America and visited fixed income investors in Singapore, London, Hong Kong, Chile and Peru. [El Espectador]
Ecopetrol road show led by Bank of America visited the following US cities: New York, Chicago, Los Angeles and Boston. [El Espectador]
Venezuela’s Central Bank (BCV) holds auction for $330mm with PDVSA bonds.
Venezuelan Debt to China:
China has loaned Venezuela nearly $40 bln to date, excluding new agreements signed recently between the countries, of which $20 bln has been paid back. [EAI]
Venezuela currently owes $20 bln to China, which represents almost 2.4 months of PDVSA’s revenues assuming oil prices above $100/bbl. [EAI]
Assuming China were to lend Venezuela another $44 bln, the country would owe the Chinese nearly $64 bln, which is about 6 months of PDVSA revenue with oil prices above $100/bbl. [EAI]
Venezuelan debt of $64 bln to China would represent almost 7.7 months of PDVSA’s revenues assuming oil prices above $100/bbl. [EAI]
Investments in energy projects in Peru to fall 50% by YE:20. [El Comercio.pe]
China’s Industrial and Commercial Bank (ICBC) could finance 70% of Pacific Coast refinery project. [El Comercio]
Colombia’s National Hydrocarbon Agency (ANH) said the country’s oil reserves were 2,377 MMbbls at YE:12. [Portafolio.co]
S&P and Fitch raise rating on Emgesa ISA to BBB from BBB-. [Portafolio.co]
Chinese executives with LinYi Cake Trade Co. visited Bolivia to inspect the construction process and advances at a pilot lithium battery plant in La Palca in Potosi. [La Razon]
Peru to prioritize $1,500 mln in investments for the integration of heavy oil lots in the northern amazon region [El Comercio.pe]
PDVSA has 15,000 workers in the Orinoco Heavy Oil Belt of Faja but plans to increase this figure to 40,000, PDVSA President Rafael Ramirez says. [EAI]
PDVSA, Cupet (Cuba) and Sonangol (Angola) agree to create JV to produce 20,000 b/d in the Faja. [El Nacional]
PDVSA reports in 10.Oct.2013 press release that it has a 71% interest in PetroCarabobo 1 Faja project, meaning the company assumed Petronas’ 11% interest. Partners in the PetroCarabobo 1 project now include PDVSA (WI 71%), OVL (WI 11%), OIL (WI 3.5%), OIC (WI 3.5%) and Repsol (WI 11%). [EAI]
Rising drilling costs in the Faja are just one of many issues companies are confronting today. [EAI]
Russia’s Lukoil announced plans to exit the Junin Block 6 project in the Faja.
EDITOR’S NOTE: Smaller Russian companies are starting to exit the Faja, ceding more control to Rosneft or other Russian entities; a signal that something could definitely be wrong in Venezuela and the Faja. [EAI]
PDVSA announced during the HOLA 2013 conference that it was looking to utilize its heavy oil techniques in Mexico. [EAI]
Repsol turns down $5,000 mln offer from Argentine gov’t regarding 51% interest expropriated in 2012. [La Nacion]
Ecuador’s President Rafael Correa says on Ecuadorian state television that US-based Chevron Corp. is an enemy of Ecuador. [EAI]
By 2015 Uruguay’s ANCAP expects to be exporting 5 MMcm/d of gas from the Puntos de Sayago regasification plant in Uruguay to Argentina’s YPF. [LaRed21]
Peru to prioritize $3,500 mln in investments for the petrochemical industry. [El Comercio.pe]
Peru to prioritize $3,500 mln in investments for the southern gas pipeline. [El Comercio.pe]
PROTESTS / STRIKES
About 50 workers with Petrocedeno JV in Venezuela demand that PDVSA respect their benefits [El Universal]
Peru to prioritize $3,514 mln in investments for the modernization of the Talara refinery. [El Comercio.pe]
PDVSA’s participation in Abreu e Lima Refinery in Brazil:
PDVSA President Rafael Ramirez says co. and Petrobras officials continue to discuss JV prospects regarding the Abreu e Lima refinery. [EAI]
From an operational and strategic business plan point of view, PDVSA’s participation in the Abreu e Lima refinery does not make sense. [EAI]
Abreu e Lima refinery in Pernambuco could easily source sufficient oil from the Brazil’s offshore pre-salt region w/o having to look to Venezuela for heavy oil. [EAI]
Any decision PDVSA President Rafael Ramirez takes regarding the company’s participation in Abreu e Lima refinery w/Petrobras will be politically based. [EAI]
Comments regarding Amuay Refinery explosion on 25.Aug.2012:
PDVSA President Rafael Ramirez says explosion at Amuay refinery was sabotage. Amuay refinery explosion was caused by gas leak at Block B23. As a result of the explosion, 42 persons were killed, 5 are still missing, 150+ were seriously injured. published by the Energy Orientation Center (COENER). [EAI]
Amuay refinery explosion to cost PDVSA an estimated $1.8 bln, according to COENER. The refinery is processing 645,000 b/d nearly 10 months after major explosion. [Ultimas Noticias]
PDVSA to spend an estimated $585 mln on maintenance activities at the Amuay and Cardon refineries, PDVSA President Rafael Ramirez says. [EAI]
CITGO Corp. donates 625,000 energy saving light bulbs to families in 21 cities in the USA [PDVSA
(Energy Analytics Institute, Ian Silverman, 13.Sep.2013) – Pacific Rubiales plans capital expenditure outlays of $1 billion on infrastructure projects such as ports, pipelines and a ferry, reported the daily newspaper Portoflio.co.
(Energy Analytics Institute, Ian Silverman, 12.Sep.2013) – Empresa Energia de Bogota (EEB) plans CAPEX outlays of $900 million in 2013 and the $3.4 billion during 2014-2017, El Espectador said, citing EEB President Sandra Fonseca.
EEB also continues to analyze the purchase of Isagen, the daily reported.
(Energy Analytics Institute, Ian Silverman, 12.Sep.2013) – The Star project will allow Pacific Rubiales to double recovery rates at the Quifa field, El Espectador reported, citing Pacific Executive Director Ronald Pantin.