CALGARY, ALBERTA--(Marketwire - March 5, 2012) - Petrominerales Ltd. ("Petrominerales" or the "Company") (TSX:PMG) (BVC:PMGC) is pleased to announce our 2011 fourth quarter and year end financial results highlighted by funds flow from operations of US$213.3 million or US$2.14 per share for the fourth quarter and US$786.2 million or US$7.69 per share for the year, our highest amount ever. Production averaged 35,353 barrels of oil per day ("bopd") in the quarter and our operating netbacks grew to US$72.32 per barrel, reflecting synergistic value from our strategic OCENSA pipeline acquisition in the third quarter. Our balance sheet remains strong with a working capital surplus and undrawn, available capacity on our bank lines. This financial flexibility gives us the continued strength to execute our 2012 high-impact exploration program.
FINANCIAL & OPERATING HIGHLIGHTS
The following table provides a summary of Petrominerales' financial and operating results for the fourth quarter and year ended December 31, 2011 and 2010. Consolidated financial statements with Management's Discussion and Analysis ("MD&A") are now available on the Company's website at www.petrominerales.com and will also be available on the SEDAR website at www.sedar.com.
|Three months ended December 31||,||Year ended December 31||,|
|($ millions, except where noted)||2011||2010||% change||2011||2010||% change|
|Funds flow from operations (1)||213.3||153.4||39||786.2||597.9||31|
- basic ($)
|- diluted ($)||1.84||1.28||44||6.57||5.47||20|
|Adjusted net income (1) (2)||77.7||34.7||124||326.2||282.9||15|
- basic ($)
|- diluted ($)||0.72||0.33||118||2.94||2.73||8|
|Per share (Cdn.$)||0.13||0.13||-||0.50||0.38||32|
|Expenditures on PP&E and E&E(3)||252.4||162.8||55||787.1||506.4||55|
|Net working capital surplus(1)||73.8||580.2||(87||)||73.8||580.2||(87||)|
|Common shares, end of period (000s)||99,375||103,392||(4||)||99,375||103,392||(4||)|
|Fully diluted common shares (000s)(4)||106,883||126,970||(16||)||106,883||126,970||(16||)|
|Three months ended December 31||,||Year ended December 31||,|
|2011||2010||% change||2011||2010||% change|
|Total production (bopd)||35,353||33,142||7||38,378||37,027||4|
|Sales volumes of produced oil (bopd)||33,913||32,138||6||38,170||36,612||4|
|Operating netback ($/bbl)(1)|
|WTI benchmark price||93.87||85.34||10||95.11||79.63||19|
|Brent benchmark price||109.18||87.49||25||111.98||79.41||41|
|Discount to Brent||3.46||7.09||(51||)||10.02||5.93||69|
|Realized crude oil price||96.87||73.89||31||91.89||66.84||37|
|Operating netback (1)||72.32||48.77||48||67.90||50.17||35|
- Non-IFRS measure. See "Non-IFRS Measures" section within this press release.
- Net income has been adjusted for the IFRS accounting effects of changes in the derivative financial liability. For the year ended December 31, 2011 adjusted net income includes a $167.0 million reduction (December 31, 2010 - $139.1 million increase). For the three months ended December 31, 2011 adjusted net income includes a $29.3 million reduction (December 31, 2010 - $107.2 million increase). Management considers adjusted net income a better measure of the Company's economic performance.
- PP&E consists of property, plant and equipment assets and E&E consists of exploration and evaluation assets from the consolidated statement of cash flow.
- Consists of the sum of common shares, stock options, deferred common shares, incentive shares and potential shares issuable on conversion of in-the-money convertible debentures outstanding as at the period-end date. At December 31, 2011, the convertible debentures were considered debt since the bond conversion price of $33.76 was higher than the Company's stock price. For 2010, the convertible debentures were in-the-money and considered equity. As a result, in 2010 there were 15,828,000 shares included in the fully diluted common share total.
- Debt represents the principal amount of convertible bonds outstanding.
|HIGHLIGHTS AND SIGNIFICANT TRANSACTIONS DURING THE FOURTH QUARTER|
|(Comparisons are fourth quarter 2011 compared to the fourth quarter of 2010 unless otherwise noted)|
- We began drilling in new, high-impact acreages starting with our first exploration well in the foothills region of Colombia and our first exploration well in Peru.
- Production averaged 35,353 bopd in the fourth quarter, a seven percent increase over 2010. Production to-date in 2012 has averaged 33,403 bopd.
- Funds flow from operations was $213.3 million or $2.14 per basic share, 39 and 41 percent increases over 2010.
- Adjusted net income was $77.7 million or $0.78 per basic share, 124 and 129 percent increases over 2010. Net income of $107.0 million included a $29.3 million non-cash gain from new accounting treatment under International Financial Reporting Standards ("IFRS") for our convertible debentures.
- Our operating netbacks increased to $72.32 per barrel in the fourth quarter, a 48 percent increase over 2010, primarily due to higher world oil prices and savings achieved by our OCENSA pipeline ownership position. Our operating netbacks increased 18 percent over the third quarter of 2011, despite lower Brent oil prices, primarily due to savings obtained from our OCENSA pipeline ownership position and the effect of operating cost savings initiatives.
|HIGHLIGHTS AND SIGNIFICANT TRANSACTIONS DURING 2011|
|(All dollar amounts are denominated in United States dollars unless otherwise noted, annual comparisons are 2011 compared to 2010 unless otherwise noted)|
- We increased average production to 38,378 bopd, a four percent increase over 2010.
- We continued our top of class operating netbacks of $67.90 per barrel in 2011, a 35 percent increase over 2010.
- We generated record funds flow from operations of $786.2 million or $7.69 per basic share, 31 and 28 percent increases over 2010.
- We generated record adjusted net income of $326.2 million or $3.19 per basic share, 15 and 12 percent increases over 2010 adjusted net income. Net income of $493.2 million included a $167.0 million non-cash gain from different accounting treatment under IFRS for our convertible debentures.
- Our balance sheet remains strong. We ended the year with a cash balance of $295.4 million and an undrawn $150 million reserve-based credit facility.
- We remained the most active exploration company in Colombia, drilling 32 exploration wells representing 25 percent of all exploration wells drilled in Colombia during 2011. We had numerous exploration successes including Cobra, Macapay, Cardenal, Azalea, Disa and Pisingo.
- Starting in the fourth quarter of 2011, we began drilling in new, high-impact acreages starting with our first exploration well in the foothills region of Colombia and our first exploration well in Peru.
- We continued to define heavy oil resources in Colombia by drilling eight vertical exploration wells, our first horizontal well at Mochelo and five stratigraphic wells. Based on our activity to date, we have demonstrated significant heavy oil prospectivity on our Rio Ariari Block.
- At December 31, 2011, proved plus probable reserves totaled 51.5 million barrels with a net present value of future net revenues discounted at 10 percent of $2.3 billion.
- We acquired a five percent interest in the Oleoducto Central S.A. ("OCENSA") crude oil pipeline for US$281 million. The OCENSA pipeline is strategic to Petrominerales because it secures pipeline capacity, is the lowest cost option to transport crude oil out of the Llanos Basin, and provides us with access to international oil markets. We transported our crude oil through the OCENSA pipeline as owners starting September 1, 2011.
- We repurchased 4,678,381 common shares under our normal course issuer bid ("NCIB") during the year, representing nearly five percent of our outstanding common shares, at an average price of Cdn$26.70.
- We paid $53 million in dividends (Cdn$0.50 per share) to our shareholders in 2011.
- Our common shares began trading on the Colombian Stock Exchange ("BVC") under the symbol "PMGC" on August 3, 2011. Our liquidity, or average daily number of shares traded, has increased 59 percent since this listing, and on average, 14 percent of our shares have been traded on the BVC.
|January + February 2012||Fourth
|Third Quarter 2011|
Production averaged 33,403 bopd during the first 60 days of 2012. Current production is over 37,000 bopd and reflects our successful addition of a significant amount of down-hole water disposal capacity over the last four months allowing us to bring previously shut-in production back on-line. Currently, we still have approximately 1,800 bopd of production off-line due to operational work-overs and awaiting additional water-disposal capacity that we expect to bring on in March.
Fourth quarter average production of 35,353 bopd was impacted by approximately 2,500 bopd of high water cut production that was temporary shut-in. Our Cobra-2 well on the Corcel Block was brought on production in December offsetting natural declines.
Deep Llanos Basin (Corcel, Guatiquia and South Block 31), Colombia
During the quarter, we drilled two wells (Cobra-2, Jamuco-1) and in 2012 three more wells reached their targeted drilling depth (Iboga-1, Yatay-2 and Tente-1). We drilled two additional Corcel water disposal wells (ASWD-2 and BSWD-1), and in 2012 we drilled two additional water disposal wells (ASDW-3 and DSWD-1).
Our Cobra-2 exploration well was drilled to a total measured depth of 12,800 feet on November 11th. The Cobra-2 well targeted by-passed pay in the Guadalupe formation encountered in the original discovery well. The well was placed on production December 8th and averaged 3,100 bopd for the remainder of December.
Our Yatay-2 exploration well was drilled to a total measured depth of 11,960 feet on January 1st. The Yatay-2 well targeted by-passed pay in the Guadalupe formation encountered in the original discovery well. The well was placed on production late in January at 600 bopd.
On Block 31, we drilled our third exploration well, Jamuco-1, to a total measured depth of 14,464 feet on December 5th. Based on well logs indicating 52 feet of potential net oil pay in the Guadalupe, Lower Sand 1 and 2 formations we cased the well and completed a multi-zone testing program. During testing, we recovered trace amounts of hydrocarbons and have abandoned the well.
Our latest prospect on Block 31, Iboga-1, was drilled to total depth of 14,352 feet on January 2rd. Well logs indicate 42 feet of potential net pay in the Guadalupe and Lower Sand 2 formations. We tested the Lower Sand Formations and recovered 100 percent water. We have moved the completion rig to our Candelilla field to complete work-overs on our Candellilla-3 and 5 wells. We plan to test the remaining Guadalupe potential in Iboga at a future date. Iboga concludes our initial exploration drilling program on the southern portion of Block 31. We currently have our two drilling rigs operating on the Corcel Block. Our Tente-1 exploration prospect has been drilled to a total measured depth of 14,605 feet and well logs indicate 21 feet of potential net oil pay in the Guadalupe and Lower Sand 1 formations. We plan to case the well as a potential oil producer and expect to have test results from this well in early April. We began drilling our Chilaco-1 prospect January 29th, and we expect to have drilling results from this well in March.
Foothills Blocks (Block 25, 31, 59 and 15), Deep Llanos Basin, Colombia
We had drilled our Bromelia-1 prospect to 16,919 feet, 100 feet above the primary objective formation, when during an operation to remove the bottom-hole assembly from the well, the drill pipe parted resulting in a blockage of the well bore. After making attempts to recover the pipe and assessing the condition of the well bore, we determined a side-track well was necessary. We side-tracked the well at 12,000 feet and are currently drilling at 15,500 feet. We expect to reach our target depth and have initial drilling results in April. Following Bromelia, we plan to drill our second exploration prospect on Block 25, Canatua-1.
Central Llanos Basin (Casimena, Castor, Casanare Este, Mapache Blocks), Colombia
In the fourth quarter we drilled two exploration wells (Pisingo-1 and Gaita-1) and one appraisal well (Yenac-6) on our Casimena Block. In 2012, we drilled two more wells, Yenac-5 and Tucuso-1.
We drilled our Pisingo-1 exploration prospect to total measured depth of 8,370 feet on October 6th. Well logs indicate 13 feet of potential net pay in the Mirador formation and we cased the well as a potential oil producer. This new discovery was placed on production November 6th and the well averaged 709 bopd of 24 degree API oil for the remainder of the quarter.
Following Pisingo, we drilled our Gaita-1 prospect to a total depth of 7,740 feet on November 3rd. The well was designed to test a potential southern extension of our Yenac discovery. The well reached total depth shallower than expected due to a lost circulation zone encountered in the Gacheta Formation. No net pay was encountered in Gaita-1. Since the well was drilled outside the defined pool boundary and off our seismic control, but on trend with the mapped Yenac structure, we are currently evaluating the possibility that we penetrated the down-thown side of the bounding fault. We are evaluating our next steps that could include side-tracking or deepening the well or convert it for water disposal purposes.
Following Gaita-1, we drilled Yenac-6, an appraisal well to 7,559 feet on December 1st to define the southern boundary of the Yenac pool defined from 3D seismic. Well logs indicate 34 feet potential net oil pay in the well, 20 feet in the Upper Mirador formation and 14 feet in the Lower Mirador formation. We production-tested the Upper Mirador interval and recovered 1,664 bopd of 16 degree heavy API oil at a 31 percent water cut, and have placed this well on long-term production test. In our previously drilled Yenac-1 and 2 wells, we produced 16-18 degree API oil from the Upper Mirador, and our Yenac-3 well produced 12-14 degree API heavy oil from the Lower Mirador formation.
Following Yenac-6, we drilled our Yenac-5 appraisal well. Well logs indicate 58 feet of potential net pay, 35 feet in the Upper Mirador formation and 23 feet in the Lower Mirador formation. Yenac-5 penetrated the top of the Mirador formation 10 feet structurally higher than in Yenac-3. We placed Yenac-5 on production on January 31 and to date the well has averaged 1,773 bopd of 16 degree API oil. Our Yenac-6 well, which was placed on production December 27, 2011 at 1,500 bopd, was shut-in mid-January to install a gravel pack in the well. We placed the well back on production on February 17, 2012.
On our Mapache Block, we drilled the Tucuso prospect to 7,391 feet measured depth on February 6th. The well is located 20 kilometres southeast from our Disa oil discovery. Well logs indicate potential net hydrocarbon pay of 38 feet in four intervals, including 26 net feet in the Ubaque Formation. We completed the well for production in two sands of the Ubaque Formation. Initial test rates were 855 bopd of 14 degree API oil at over 80 percent water cut. We are planning to suspend the well and isolate production to the upper Ubaque sand to optimize oil production.
Llanos Basin Heavy Oil Blocks (Rio Ariari, Chiguiro Oeste, Chiguiro Este), Colombia
During the quarter we drilled our first horizontal heavy oil well, Tatama-1, and six stratigraphic wells (ES-1, ES-3, ES-5, ES-15, ES-17 and ES-29). Subsequent to December 31st, we drilled another four stratigraphic wells (ES-22A, ES-36, ES-42, and ES-42A).
We drilled our first horizontal well, Tatama-1, near our Mochelo discovery on our Rio Ariari Block. The well was drilled to a total measured depth of 6,550 feet including a 1,000 foot horizontal section. The well was initially completed with 96 feet of blank pipe and 889 feet of screens (Meshrite™). In our initial production tests, the productivity of the well was significantly lower than that encountered in our original Mochelo-1 vertical discovery well. We pulled the liner and re-initiated a multi-rate production test resulting in oil rates up to 250 bopd at water cuts ranging from 75 to 90 percent. Over 37 days of testing, the well produced an average of 107 bopd at a 79 percent water cut. Based on the Mochelo vertical well productivity, the horizontal well productivity is lower than we expected. We plan to run a slotted liner and production logs in the well to determine which portions of the well bore are contributing to production. Depending on the results of our production log analysis, we may extend the horizontal section of Tatama or drill a new multi-lateral well to improve overall well productivity and expected ultimate recoveries.
We recently completed the tenth stratigraphic well on the block, ES-42A, which found 37 feet of potential pay in the lower Mirador formation. The ES-42A well confirmed a play concept developed from the interpretation of our 3D seismic incorporating the 15 feet of lower Mirador pay encountered in ES-42, that the potential net sand and pay would increase on the flanks of the Paleozoic highs. This result could further increase the prospective resource potential on the block. We plan to drill up to seven more stratigraphic wells targeting existing and new play concepts to identify and quantify the heavy oil potential of our Rio Ariari Block.
Orito, Putumayo Basin, Colombia
In the fourth quarter, we drilled two wells (Orito-193 and Orito-136), increasing our total to four wells drilled for the year. In January, we production tested the Orito-193 well, designed to test a part of the Orito Field with limited well spacing previously interpreted to be a non-productive area of the field. In the primary producing Caballos Formation, we encountered a high proportion of gas over oil, restricting our ability to produce the oil from this formation. In our secondary target, the Villeta Formation, we encountered 14 feet of net oil pay and production tested the well at over 800 bopd of 26 degree API oil on natural flow with less than a ten percent water cut. Based on this result, we have identified six existing Caballos Formation wells that can be reached in the Villeta Formation, including the Orito-126 well which we have already re-entered and are currently testing. In our 2011 reserve report, we have added 16 new Villeta development drilling locations. Petrominerales is entitled to 79 percent of the production, based on current R-factor calculations and before royalties, from new wells on the Orito Field.
Neiva, Upper Magdalena Basin, Colombia
Late in the third quarter, we stopped our drilling program on the Block pending new environment permits. Once new permits are obtained, we plan to recommence our development drilling program.
Block 126, Peru
In Peru, we drilled our first exploration well, La Colpa 2X, to an initial depth of 7,870 feet. As we were drilling through the Copacabana formation, at depths ranging from 5,695 to 7,225 feet, we experienced indications of oil and significant drilling mud losses. After drilling through the entire Copacabana section to a depth of 7,870 feet, we suspended drilling operations to run logs and interpret well information obtained to-date. We ran open-hole logs, and to assist our petrophysical interpretation we used a modular formation dynamics tester tool to obtain reservoir pressure measurements along with reservoir fluid samples. The primary objective was to validate the potential net hydrocarbon pay identified on logs. Based on our analysis, we estimate an initial 72 feet of net potential oil pay in three intervals of the Copacabana reservoir. We subsequently drilled the well to targeted depth of 8,500 feet. The petrophysical interpretation of the lower section of the well indicates the presence of 18 feet of net potential oil pay in the Tarma Sandstone. We are currently casing the well and expect to have testing results by the end of April, subject to favorable weather conditions.
Our initial drilling plan for La Copla 2X had identified up to eight potential hydrocarbon formations. The following is a summary of the formations we have encountered to date:
|Formation||Result from original discovery well La Colpa 1X (1)||Initial result from La Colpa 2X||Note|
|Agua Caliente||Logs indicate 26 feet of potential net oil pay; swab tested 44 barrels of 22 degree API oil||Reservoir shaled out; Top Agua Caliente 12 feet structurally lower than La Colpa 1X|
Cushabatay / Ene
||Logs indicate 15 feet of net oil pay; formation not tested||Penetrated reservoir with low permeability and appears wet||2|
|Copacabana||Logs indicate 98 feet of potential net oil pay; DST(3) recovered 8 barrels of 26 degree API oil||Found 72 feet of potential net oil pay||4|
|Tarma||DST recovered 8 barrels of 30 degree API oil||18 feet of net potential oil pay||4|
|Ambo||Logs indicate 24 feet of net oil pay; formation not tested||No pay found on logs|
|Green Sandstone||Logs indicate 10 feet of net oil pay; DST recovered 6 barrels of 32 degree API oil||No pay found on logs|
- The original La Colpa 1X was drilled in 1989 by a prior land holder.
- Potential exists for this reservoir to contain hydrocarbons elsewhere on the Block.
- DST means Drill Stem Test, an open-hole test to obtain reservoir pressure and short-term flow test data.
- To be production tested after the well is completed.
Following La Colpa 2X, we plan to move equipment to drill our Sheshea-1X prospect on the Block. The Sheshea prospect is an independent prospect from La Colpa and we are targeting multiple reservoir formations in the well.
Blocks 114 and 131, Peru
Petrominerales holds a 30 percent working interest in Blocks 114 and 131. On Block 131, the operator has identified two drillable prospects. The Environmental Impact Assessment ("EIA") for drilling was submitted in June 2011 and the first well is planned for late 2012 with a second well to spud in April 2013. The next exploration phase requirement is to drill one exploration well on the Block by February 2013. On Block 114, the next exploration phase includes the acquisition of 325 kilometres of 2D seismic by July 2013. To date, four drillable prospects and six leads have been identified on this Block. The operator applied for and was granted force majeure status over the block in December 2011 due to unusually high river levels and heavy rainfall which has flooded out a portion of this block making seismic acquisition impossible. The operator is responsible for our share of the costs under the current seismic exploration phase, as well as our share of costs for the first exploration well on each block.
Block 161 and 141, Peru
Block 161, situated in east central Peru, is 1.2 million acres in size and Petrominerales has an 80 percent working interest. We submitted an EIA that covers our planned 353 kilometre 2D seismic program and we are waiting on the ministry of environment's approval. We are also awaiting feedback on first round of community workshops. Block 141, situated in southern Peru, is 1.3 million acres in size and Petrominerales has an 80 percent working interest. In September 2011, the Block went into a force majeure and remains so due to new government regulations requiring additional community consultations. As a result, our current commitment to complete a 300 kilometre 2D seismic program by July 2012 has been suspended pending resolution of these consultation issues. No timeline for resolution has been announced.
Our long term objective is to focus on delivering high impact exploration success building net asset value, and generating attractive total returns for shareholders through the following strategies:
- Material growth in reserves through the execution of a balanced, diversified exploration drilling program;
- Maintain a multi-year drilling inventory of exploration prospects by continually adding to our land position and acquiring high quality 3D seismic over those lands;
- Explore and develop large heavy oil resource accumulations;
- Rapidly convert new discoveries into production and cash flow;
- Leadership in oil and gas exploration using technology, innovation and continued regard for the health and safety of our employees, emphasis on industry leading environmental performance and meaningful dialogue with our stakeholders;
- Internally funded growth through cash flow generation from our established assets; and
- Providing a dividend yield to investors.
The key challenges that need to be effectively managed to enable our growth are commodity price volatility, government permits and approvals, exploration risk, environmental regulations and competitive pressures within our industry. Additional detail regarding the impact of these factors on our 2011 results is discussed in the 'Risks and Uncertainties' section of our MD&A.
Our base 2012 exploration plan includes:
- Drilling 19 exploration wells, 16 in Colombia and three in Peru, targeting over 280 million barrels of Undiscovered Petroleum Initially in Place ("UPIIP") on our conventional light oil exploration acreage. Five of the 19 exploration wells target large prospects in the foothills region of the Llanos Basin and on Block 126 in Peru;
- Drilling up to 24 stratigraphic wells on our heavy oil acreage and obtaining production results from at least two horizontal wells to support our longer-term heavy oil strategy; and
- Acquiring over 700 square kilometres of new 3D seismic data on our Llanos Basin Foothills acreage to position our 2013 drilling program with new high impact drilling prospects.
Our base 2012 work program is highly flexible and subject to change based on results as our exploration drilling plan is focused on numerous high impact opportunities that, with success, could result in significant increases to our 2012 program. Throughout 2012, we plan to update our shareholders on our progress and future work program as it evolves.
FOURTH QUARTER AND ANNUAL RESULTS CONFERENCE CALL
Management of Petrominerales will be holding a conference call for investors, financial analysts, media and any interested persons on Monday, March 5, 2012 at 9:00 a.m. (Mountain Time) (11:00 a.m. Eastern Time) to discuss our 2011 year-end and fourth quarter financial and operating results.
The investor conference call details are as follows:
Live call dial-in number(s): 416-695-6617 / 800-952-4972
Live audio webcast link: http://events.digitalmedia.telus.com/petrominerales/030512/index.php
Replay dial-in numbers: 905-694-9451 / 800-408-3053
Replay Pass code: 7233541
Petrominerales also announces that Corey Ruttan, President and Chief Executive Officer, will be presenting at the FirstEnergy/Société Générale East Coast Energy Conference in New York, USA, on Friday March 9, 2012 at 8:50 AM Eastern Standard Time. The presentation will be available via live webcast at: http://jetslides.tv/lobby/684 and will also be available in an archived version at this link for 60 days following the live presentation.
Petrominerales Ltd. is an international oil and gas company operating in Latin America since 2002. Today, Petrominerales is the most active exploration company and the fourth largest oil producer in Colombia. Our high quality land base and multi-year inventory of exploration opportunities provides long-term growth potential for years to come.
Forward‐Looking Statements. Certain information provided in this press release constitutes forward‐looking statements. Specifically, this press release contains forward‐looking statements relating to the Company's future exploration and development activities and the timing for bringing wells on production. The forward‐looking statements are based on certain key expectations and assumptions, including expectations and assumptions concerning the availability of capital, the success of future drilling and development activities, the performance of existing wells, the performance of new wells, prevailing commodity prices and economic conditions, the availability of labour and services, the ability to transport and market our production, timing of completion of infrastructure and transportation projects, weather and access to drilling locations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. You can find a discussion of those risks and uncertainties in our Canadian securities filings. Such factors include, but are not limited to: general economic, market and business conditions; fluctuations in oil prices; the results of exploration and development drilling, recompletions and related activities; timing and rig availability; availability of transportation and offloading capacity, outcome of exploration contract negotiations; fluctuation in foreign currency exchange rates; the uncertainty of reserve estimates; changes in environmental and other regulations; risks associated with oil and gas operations; and other factors, many of which are beyond the control of the Company. There is no representation by Petrominerales that actual results achieved during the forecast period will be the same in whole or in part as those forecast. Except as may be required by applicable securities laws, Petrominerales assumes no obligation to publicly update or revise any forward‐looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.
UPPIP . Undiscovered Petroleum Initially-In-Place ("UPIIP"), equivalent to undiscovered resources, are those quantities of petroleum that are estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of UPIIP is referred to as prospective resources, the remainder as unrecoverable. Undiscovered resources carry discovery risk. There is no certainty that any portion of these resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. A recovery project cannot be defined for this volume of UPIIP at this time.
This press release contains financial terms that are not considered measures under Canadian generally accepted accounting principles ("GAAP"), such as funds flow from operations, funds flow per share, net working capital surplus, operating netback, finding and development costs and recycle ratio. These measures are commonly utilized in the oil and gas industry and are considered informative for management and shareholders. These
terms do not have any standardized meaning as prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other issuers. Specifically, funds flow from operations and funds flow per share reflect cash generated from operating activities before changes in non-cash working capital. Management considers funds flow from operations and funds flow per share important as they help evaluate performance and demonstrate the Company's ability to generate sufficient cash to fund future growth opportunities and dividends. Net working capital surplus includes current assets less current liabilities and the current amount of convertible debentures (when they are out of the money and not repayable in shares at maturity) and is used to evaluate the Company's financial leverage. Operating netback is determined by dividing oil sales less royalties, transportation and operating expenses by sales volume of produced oil. Management considers operating netback important as it is a measure of profitability per barrel sold and reflects the economic quality of production. Funds flow from operations, funds flow per share, net working capital surplus, operating netbacks, finding and development costs and recycle ratio may not be comparable to those reported by other companies nor should they be viewed as an alternative to cash flow from operations, net income or other measures of financial performance calculated in accordance with GAAP.
Non-IFRS Measures. This report contains financial terms that are not considered measures under International Financial Reporting Standards ("IFRS"), such as funds flow from operations, adjusted net income, funds flow per share, adjusted net income per share, working capital, net (debt) surplus and operating netback. These measures are commonly utilized in the oil and gas industry and are considered informative for management and shareholders. We evaluate our performance and that of our business segments based on funds flow from operations and adjusted net income. Funds flow from operations is a non-IFRS term that represents cash generated from operating activities before changes in non-cash working capital. Adjusted net income is determined by adding back any losses or deducting any gains on the derivative liabilities. Management considers funds flow from operations, funds flow per share, adjusted net income and adjusted net income per share important as they help evaluate performance and demonstrate the Company's ability to generate sufficient cash to fund future growth opportunities and repay debt. Working capital includes current assets less current liabilities and is used to evaluate the Company's short-term financial leverage. Net (debt) surplus includes current assets less current liabilities and the principal amount of out-of-the-money convertible debentures (i.e. when they are out of the money and not repayable in shares at maturity) and is used to evaluate the Company's financial leverage. Operating netback is determined by dividing oil revenue less royalties, transportation and production expenses by sales volume of produced oil. Management considers operating netback important as it is a measure of profitability per barrel sold and reflects the quality of production. Funds flow from operations, funds flow per share, adjusted net income, adjusted net income per share, working capital, net (debt) surplus and operating netbacks may not be comparable to those reported by other companies nor should they be viewed as an alternative to cash flow from operations, net income or other measures of financial performance calculated in accordance with IFRS.