TORONTO, April 10, 2012 /PRNewswire/ - PetroMagdalena Energy Corp. (TSXV: PMD) has filed today its audited consolidated financial statements for the year ended December 31, 2011, together with its Management's Discussion and Analysis ("MD&A"), Forms 51-101 F1, F2, F3 and F4, and its Annual Information Form, for the corresponding period. These documents will be posted on the Company's website at www.petromagdalena.com and at www.sedar.com under the Company's SEDAR profile.
Luciano Biondi, the Company's Chief Executive Officer, stated: "We are pleased to see strong financials results for the 2011 financial year, reflecting our focus on managing our core portfolio of oil assets in the Llanos Basin. We have increased the prospectivity of the portfolio with our most recent NI 51-101 reserves report and we are optimistic about our exploration portfolio which includes significant activity in 2012 and additional upside production potential not yet reflected in the 2011 year-end reserves. In particular, Azor-1X and Cernicalo-1ST are now on production and we are currently testing Tijereto Sur. In addition, later in 2012, we plan to drill two high potential exploration wells at Copa A Norte and Copa C in the Cubiro block."
We met our production guidance for 2011 and increased our 2011 daily production exit rate by 76% over the 2010 rate. Production increases combined with stronger realized oil and gas prices contributed to significant revenue growth for PetroMagdalena in 2011 as demonstrated by the 174% year-over-year increase in our fourth quarter revenues to $27.7 million. Together with our focus on improving operating efficiencies, we reported our fourth consecutive quarter of improved operating netback, which averaged $61.33 per boe in the fourth quarter of 2011.
With the increase in 2011 in our internally generated cash flows from our operations and the Company's liquidity situation much improved from the end of 2010, we are favourably positioned to take advantage of the exploration and development opportunities within our own portfolio of assets, and are able to consider other meaningful investments going forward."
Financial and Operating Summary
|(000s, except per share and operational data)||2011||2010||2011||2010|
|Revenue from oil and gas sales||$||27,747||$||10,125||$||86,196||$||44,440|
|Gross margin (3)||7,685||(617)||20,912||1,423|
|Basic and diluted loss per share||(0.54)||(0.39)||(0.81)||(0.51)|
|Total assets at period end||349,311||362,965||349,311||362,965|
|Total debt at period end||47,524||44,886||47,524||44,886|
|Average daily production (boed) (1)||3,625||2,515||2,761||2,413|
|Total sales (boe) (2)||279,830||149,455||972,346||751,828|
|Operating netback ($/boe) (3)||61.33||21.55||55.84||35.92|
|(1)||Company share, gross before deduction of ANH royalties|
|(2)||Company share, net after deduction of ANH royalties|
|(3)||See Additional Financial Measures in the MD&A.|
Fourth Quarter 2011 Highlights
- Production: Total production averaged 3,625 barrels oil-equivalent ("boe") per day ("boed") in the fourth quarter of 2011 as compared to 2,515 boed in the fourth quarter of 2010. Fuelled by the discoveries at Cubiro, the Company's gross share of production for the month of December 2011 averaged 4,181 boed, up 76% from the December 2010 monthly average rate of 2,374 boed.
- Revenues: Improvements in the Company's light oil marketing strategy in 2011 combined with improved oil prices and production growth, increased revenues in the fourth quarter of 2011 to $27.7 million, or 174% higher than the same period a year ago.
- Operating netback: The Company reported its fourth consecutive quarter of improved operating netbacks, which averaged $61.33 per boe in the fourth quarter of 2011.
- G&A expenses: Through cost savings initiatives implemented in early 2011 and production growth, the Company reduced G&A to approximately $12 per boe sold in the fourth quarter of 2011 compared with an average of $25 per boe sold in 2010.
Fiscal Year 2011 Highlights
- Reserves: A successful exploration drilling program at Cubiro in 2011 was the key driver behind a 4.0 MMbbl, or 43%, increase in the Company's 2P oil reserves, a 394% reserve replacement, as per the December 31, 2011 Petrotech report compared with the December 31, 2010 report.
- Production: The Company met its production guidance for 2011. The Company's gross share of production for the year averaged 2,761 boed.
- Liquidity: The Company strengthened its balance sheet in 2011. Cash at December 31, 2011 stood at $14.1 million and the working capital deficit has been reduced by $26.5 million since December 31, 2010. As a result of production growth and netback improvements in 2011, cash flow from operating netbacks amounted to $54.3 million in 2011, increasing significantly over the course of the year from $3.2 million in the fourth quarter of 2010 to $17.2 million in the fourth quarter of 2011. This provides the Company with a strong internally generated source of cash flow to meet its obligations as they become due and to re-invest in its annual work program on its properties.
- Value creation: The Company continues to take action to develop its portfolio and to reduce its risk through joint venture relationships. In 2011, the Company announced a strategic partnership with YPF S.A. to farm-out a portion of its interests in Carbonera and Catguas and to explore further business opportunities with respect to several of its other properties. In addition, the Company also announced a farm-out arrangement with respect to its Santa Cruz exploration property and executed a conditional assignment agreement to increase the Company's working interest in the Arrendajo ANH block where the Azor-1X discovery is currently on production. Each of these farm-out/ farm-in arrangements are subject to ANH approval. In December 2011, the Company sold its working interest in the Cerrito gas property for cash proceeds of $7.5 million.
The net loss for the fourth quarter of 2011 amounted to $74.8 million or $0.54 per share, bringing the fiscal year 2011 net loss to $111.8 million or $0.81 per share. The 2011 net loss includes $49.7 million of write-downs related to the Company's strategy with respect to its non-core oil and gas assets, $36.1 million related to wells drilled in 2010 and 2011 that did not ultimately result in proved reserves, a $6.5 million one-time charge for the 2011-2014 Colombian equity tax and a $6.5 million non-cash charge for stock options granted during the year.
Capital expenditure guidance for 2012 has been updated to a range of $70 million to $80 million, mainly as a result of the farm-in with Interoil Colombia E&P Inc. on block LLA-47 and investments at Cubiro to replace rental oil facilities to realize production cost savings. The 2012 capital expenditure program is fully funded by the Company's cash balances, cash flow from operations, a new $10 million local bank facility and farm-out arrangements. The Company will provide further guidance on spending and the work plan after the current first quarter exploration program is evaluated and remains subject to final board approval.
The total gross proved and probable ("2P") light and medium oil reserves of the Company, based on its working interests in five oil properties in Colombia, increased by 4.0 MMbbl or 43% in 2011 to 13.3 MMbbl, before deduction of ANH royalties, or 12.2 MMbbl net to the Company, driven primarily by four discoveries on the Cubiro block: Petirrojo, Copa B, Copa A Sur and Yopo.
The total gross 2P oil-equivalent reserves of the Company, based on its working interests in six properties in Colombia, is approximately 24.7 MMboe before deduction of ANH royalties or 22.9 MMboe net to the Company. The Company's interest in 2P oil-equivalent reserves decreased by approximately 46% compared with December 2010 as a result of the sale of Cerrito, and technical revisions at Carbonera and Rio Magdalena. Gas volumes are expressed in billions of cubic feet ("Bcf") and when expressed in oil equivalent were converted using 6,000 cubic feet of gas equivalent to one barrel.
The reserves are based on an independent reserve and resource assessment report prepared by Petrotech Engineering Ltd. ("Petrotech") following all industry standard procedures and in conformity to the COGE guidelines, as reported in the Company's NI 51-101 Form F1, filed on SEDAR at www.sedar.com and available on the Company's website at www.petromagdalena.com. The following table summarizes the change in the Company's 2P reserves from December 31, 2010 to December 31, 2011:
|L & M Oil||Natural Gas||Liquids||Oil Equivalent|
| Reserve Changes,
Net of Production
|(1)||"Gross reserves" are the Company's share of the reserve before deduction of ANH royalties.|
|(2)||"Net reserves" are the Company's share of the gross reserves after deduction of ANH royalties.|
In 2011, the before-tax net present value of the future net revenues, discounted at 10%, ("BTNPV10 future net revenues") from the Company's interest in 2P oil reserves increased by 84% to $438.9 million. Overall, the BTNPV10 future net revenues of the Company's oil-equivalent 2P reserves increased to $539.9 million, approximately 37% higher compared to the 2010 year-end assessment completed by Petrotech.
Improved oil prices contributed in part to this increase as the December 31, 2011 oil price for West Texas Intermediate ("WTI") closed at $98.83 per barrel compared with $91.40 per barrel a year ago. However, the primary value driver was the Company's shift in its focus in 2011 to its core oil properties. In 2011, the volume of 2P oil reserves increased to 54% of the total gross boe reserves at December 31, 2011. More importantly, the Company's 2P oil reserves increased to 81% of the total BTNPV10 future net revenues, up from 60% a year ago, principally as a result of the successful exploration and development program at Cubiro in 2011. At December 31, 2011, the Company's interest in the Cubiro property's BTNPV10 future net revenues increased by 180% to $383 million or 71% of the total BTNPV10 future net revenues. The following table summarizes the BTNPV10 future net revenues as reported in the Company's NI 51-101 Form F1 and the change from December 31, 2010 to December 31, 2011:
|($ millions)||L&M Oil|| Natural Gas &
|December 2010||$ 238.0||$ 156.0||$ 394.0|
|December 2011||$ 438.9||$ 101.0||$ 539.9|
|Change||$ 200.9||$ (55.0)||$ 145.9|
In 2011, the after-tax net present value of the future net revenues, discounted at 10%, from the Company's interest in 2P oil and gas reserves increased by 43% to $390.5 million.
With average production at 3,850 boed in the first quarter of 2012, the Company has had four consecutive quarters of production growth, 68% higher than the same quarter in 2011 and 6% higher than in the fourth quarter of 2011.
The Company's production guidance for 2012 remains unchanged and is expected to average between 4,300 to 4,700 boed for the year. This guidance is based on an updated production profile of the Company's thirteen producing oil fields and the ten development wells planned to be drilled from now to the end of the year. It does not include production volumes for any exploration wells currently in process. The disruptions experienced at Cubiro in the first quarter temporarily delayed the Company's production schedule but did not result in any significant impact on the annual production guidance for 2012. Production has averaged approximately 4,200 boed since the blockade ended in mid-March 2012.
Cernicalo-1ST on Production - Cubiro Block, Llanos Basin:
The Cernicalo-1ST, a sidetrack of the Cernícalo 1 exploration well in Polygon B of the Cubiro Block, was put on production on February 25, 2012 from the Guadalupe and C7 formations. The Guadalupe is producing 23.9 degree API oil and the C7 is producing 28 degree API oil. Over the last seven days of March 2012, the well produced at a combined average rate of 510 boed (Company share - 357 boed), with a water cut of 57%. The structure is on trend with the Barranquero field to the north and the Tijereto Sur-1X exploration well to the south.
Copa 4 Development well - Cubiro Block, Llanos Basin:
Copa 4, a development well in the Copa field was spud on March 31, 2012 and is currently drilling at 4,650 feet measured depth (MD) in the Carbonera Formation. The well is expected to be completed within the next two weeks in the Carbonera C5. This is the same interval in Copa-1 that has already produced 290,000 Bbls and is expected to produce to an ultimate total recovery of 497,000 bbls from this well.
Alondra-1X Exploration well - Cubiro Block, Llanos Basin:
The Alondra-1X exploration well, spudded on March 28, 2012, reached total depth (TD) of 6,513 feet MD on April 5, 2012 in the Guadalupe Formation and found the top of the Carbonera C7 sand at 5,989 feet MD.
The Alondra-1X was abandoned based on LWD logs, and on April 9, 2012, a sidetrack was started targeting a different structural compartment on the same prospect. At the present depth of 2,685 feet MD, results from the Alondra-1ST are expected in mid-April 2012. The well is in Polygon B of the Cubiro Block, where PetroMagdalena has a 70% working interest. The Alondra prospect is on trend with, and 3.4 kilometres north of, the Barranquero Field.
Santa Cruz -1X Exploration well - Santa Cruz Block, Catatumbo Basin:
The testing program continues in the Santa Cruz-1X well. During operations, it was determined that a cement squeeze was required to ensure zone isolation over the Barco Formation and the Company expects that additional cement squeezes will be required, making the testing period longer than what was originally anticipated. Results from these tests are now expected for the end of April 2012.
The Santa Cruz-1X well, located on the Santa Cruz Block in the Catatumbo Basin in North Eastern Colombia, was drilled to a TD of 11,550 feet MD. Data related to well seismic, geological age dating and logs, indicate that the well drilled the main fault plane at the level of the Leon-Guayabo formations. In the footwall of the main inverse fault, a normal section was found including sediments from the Carbonera to the Catatumbo formations. Laboratory analysis of cuttings is in progress and an interpretation effort will continue, to review the geological model.
PetroMagdalena has a 70% working interest in the Santa Cruz-1X well and is the operator of the Santa Cruz Block.
Cantaclaro-1X Exploration well - Carbonera Block, Catatumbo Basin:
The Cantaclaro-1X exploration well on the Carbonera Block, spudded on March 15, 2012, was drilled to the top of the target La Luna Formation at a depth of 4,560 feet MD. Intermediate 9-5/8 inch casing has been set and the next operation is to install underbalanced drilling equipment. The La Luna target formation will then be drilled, highly deviated, and the well is estimated to reach TD at the base of the La Luna Formation at a measured depth of 5,480 feet MD. Simultaneous underbalanced drilling and testing is planned to resume in five days. PetroMagdalena has signed an MOU to farm-out 60% of the Carbonera block to YPF as part of a $23 million work program, subject to ANH approval.
Management will hold a conference call today at 9:00 a.m. (Eastern Time) to discuss the 2011 fourth quarter and year end results and to provide an operational update. Analysts and interested investors are invited to participate as follows:
|Toronto & International:||(647) 427-7450|
|North America:||(888) 231-8191|
A playback of this conference call will be available by dialling 416-849-0833 with the above conference ID number until April 24, 2012.
PetroMagdalena is a Canadian-based oil and gas exploration and production company, with working interests in 19 properties in five basins in Colombia. Further information can be obtained by visiting our website at www.petromagdalena.com.
All monetary amounts in U.S. dollars unless otherwise stated. This news release contains certain "forward-looking statements" and "forward-looking information" under applicable Canadian securities laws concerning the business, operations and financial performance and condition of PetroMagdalena. Forward-looking statements and forward-looking information include, but are not limited to, statements with respect to estimated production and reserve life of the various oil and gas projects of PetroMagdalena; the estimation of oil and gas reserves; the realization of oil and gas reserve estimates; the timing and amount of estimated future production; costs of production; success of exploration activities; and currency exchange rate fluctuations. Except for statements of historical fact relating to the company, certain information contained herein constitutes forward-looking statements. Forward-looking statements are frequently characterized by words such as "plan," "expect," "project," "intend," "believe," "anticipate", "estimate" and other similar words, or statements that certain events or conditions "may" or "will" occur. Forward-looking statements are based on the opinions and estimates of management at the date the statements are made, and are based on a number of assumptions and subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those projected in the forward-looking statements. Many of these assumptions are based on factors and events that are not within the control of PetroMagdalena and there is no assurance they will prove to be correct. Factors that could cause actual results to vary materially from results anticipated by such forward-looking statements include changes in market conditions, risks relating to international operations, fluctuating oil and gas prices and currency exchange rates, changes in project parameters, the possibility of project cost overruns or unanticipated costs and expenses, labour disputes and other risks of the oil and gas industry, failure of plant, equipment or processes to operate as anticipated. Although PetroMagdalena has attempted to identify important factors that could cause actual actions, events or results to differ materially from those described in forward-looking statements, there may be other factors that cause actions, events or results not to be anticipated, estimated or intended. There can be no assurance that forward-looking statements will prove to be accurate, as actual results and future events could differ materially from those anticipated in such statements. PetroMagdalena undertakes no obligation to update forward-looking statements if circumstances or management's estimates or opinions should change except as required by applicable securities laws. The reader is cautioned not to place undue reliance on forward-looking statements.
Statements concerning oil and gas reserve estimates may also be deemed to constitute forward-looking statements to the extent they involve estimates of the oil and gas that will be encountered if the property is developed. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Estimated values of future net revenue disclosed do not represent fair market value.
Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
|1P: Proven reserves||G&A: General and Administrative Expenses|
|2P: Proven + Probable reserves||MMCF: Million Cubic Feet|
|3P: Proven + Probable + Possible reserves||MD: Measured Depth|
|ANH: Agencia Nacional de Hidrocarburos||MMBBLS: Million Barrels of Oil|
|API: American Petroleum Institute||MMBTU: Millions British Thermal Unit|
|BOE: Barrels of Oil Equivalent|
|BOFD: Barrels of Fluid Per Day||NPV: Net Present Value|
|BOPD: Barrels of Oil Per Day||PSI: Pounds per Square Inch. The unit of pressure.|
|BOEPD: Barrels of Oil Equivalent Per Day||TD: Total Depth of the well|
|BS&W: Basic Sediments and Water||TVD: True Vertical Depth of the well|
|E&PC: Exploration & Production Contract||TVDSS: True Vertical Depth Sub Sea|
|ESP: Electric Submersible Pump||WI: Working Interest|
|FOB: Freight on Board||WTI: West Texas Intermediate Oil Price Index|
SOURCE PetroMagdalena Energy Corp.