NG ENERGY INTERNATIONAL CORP. CRUZSUR ENERGY CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2020
The following is management's discussion and analysis ("MD&A") of the operating and financial results of CruzSur Energy Corp. ("CruzSur" or the "Company") for the three and six months ended June 30, 2020, as well as information and expectations concerning CruzSur's outlook based on currently available information.
This MD&A should be read in conjunction with CruzSur's interim condensed consolidated financial statements for the three and six months ended June 30, 2020 as well as the audited annual consolidated financial statements for the year ended December 31, 2019 (collectively, the "Financial Statements") prepared in accordance with IFRS (as defined below), together with the accompanying notes.
This MD&A contains forward‐looking information about our current expectations, estimates, projections and assumptions. See the reader advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward‐looking information. Additional information on the Company, its financial statements, this MD&A and other factors that could affect CruzSur's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).
All dollar values are expressed in US dollars, unless otherwise indicated, and are prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standard Board ("IASB").
This MD&A is prepared as of August 26, 2020.
Non‐GAAP Measures
Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS, and therefore are considered non‐GAAP measures. These measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. The additional information should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation of each non‐GAAP measure is presented in the Operating Results, Financial Results and Liquidity and Capital Resources sections of this MD&A.
CORPORATE OVERVIEW AND UPDATE
CruzSur is an oil and gas company incorporated in Canada and is engaged in the acquisition, exploration, development, and exploitation of oil and natural gas assets in South America, particularly in the countries of Colombia and Argentina. The Company's current asset portfolio is comprised of one appraisal and two exploration natural gas assets in Colombia and two assets in Argentina; one medium oil and one natural gas. CruzSur's common shares are listed on the TSX Venture Exchange ("TSX‐V") under the symbol "CZR".
COVID‐19 Pandemic
In March 2020, the global outbreak of COVID‐19 (coronavirus) was declared a pandemic by the World Health Organization. Governments worldwide, including those in Canada, Colombia and Argentina, have enacted emergency measures to combat the spread of the virus. These measures, which include the implementation of travel bans, self‐imposed quarantine periods and social distancing, have caused material disruption to businesses globally resulting in an economic downturn. Governments and central banks have reacted with significant monetary and fiscal interventions designed to stabilize economic conditions; however, the success of these interventions is not currently determinable. At this time, the extent of the impact the COVID‐19 outbreak may have on the Company is unknown, as this will depend on future developments that are highly uncertain and that cannot be predicted with confidence. While the extent of the impact is unknown, the current impact has delayed the Company's Colombian exploration activities currently planned for 2020 due to temporary restrictions on exploration activities implemented by the Colombian government. The scale and duration of these developments remain uncertain but could affect the Company's operations, future net earnings, cash flows and financial condition.
OIL AND NATURAL GAS PROPERTIES
Colombia
CruzSur has working interest in the Maria Conchita Block, the SN‐9 Block and the Tiburon Block. Below is a detailed description of each block:
Maria Conchita Block
The Maria Conchita Block originally covered an area of approximately 60,076 acres in the Department of Guajira, Colombia. The E&P Contract for the Maria Conchita Block (the "Maria Conchita E&P Contract") is a 2009 contract between the Agencia Nacional de Hidrocarburos ("ANH") of Colombia and MKMS Enerji Sucursal Colombia ("MKMS"), a wholly owned subsidiary of CruzSur, for the exploration and production of conventional hydrocarbons in the Maria Conchita area. The Company maintains an 80% working interest in the Maria Conchita Block with 20% being held by private joint operation partners.
The Maria Conchita E&P Contract has an initial exploration term consisting of 6 one‐year exploration phases, that are followed by a 24‐year production period from the date when commerciality is declared. Exploration phases may be longer as a result of extensions and/or temporary suspensions by the ANH following satisfaction of certain requirements set out in the Maria Conchita E&P Contract, as has been the case with Maria Conchita. Phase 1 was completed with the acquiring, processing and interpretation of 120 km2 of 3‐D seismic. The Phase 2 commitment was fulfilled with the drilling of the Istanbul‐1 well. CruzSur has decided not to proceed with the remaining exploration phases, which is discussed hereafter.
There have been two wells drilled by Texaco (Aruchara‐1 in 1980 and Aruchara‐2 in 1982), and two wells drilled by Ecopetrol, S.A. (Almirante‐1 in 1988 and Tinka‐1 in 1988). The Aruchara‐1 well tested gas in the Upper and Middle Miocene. The Tinka‐1 well tested gas in the Upper Miocene. 3‐D seismic has been acquired over both discoveries, and the Environmental Impact Assessment permit has been granted. Maria Conchita is close to both of Colombia's gas trunk lines. The Maria Conchita Block neighbors the Chuchupa Block to its north, which is one of Colombia's largest gas fields with an initial 900 MMBoe in
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place and currently accounts for approximately 40% of Colombia's daily natural gas output. The Chuchupa Block has been under production for over 35 years, and it was operated by Chevron in association with Ecopetrol, S.A. Production from the Chuchupa Block has been decreasing over the last several years, creating a need for new natural gas discoveries to replace it.
The Company commenced drilling of the Istanbul‐1 well on February 27, 2018 and reached a total depth of 8,740 feet measured depth ("MD") on March 21, 2018. Based on the interpretation of the open hole logs and mud log, 12 separate intervals covering a total thickness of 62.4 feet were selected and perforated for testing between 7,912 feet MD and 8,608 feet MD.
From April 6 to April 10, 2018, the well was tested with gas and water produced to surface. Although steady state conditions were never achieved, the well was flowed for a period of 7 hours at an average rate of 350,000 cubic feet of gas per day and 2,100 barrels of water per day. A production log ("PLT") was subsequently run, confirming that the majority of water and gas production was coming from 26 feet of perforations in the upper sand package. The PLT also confirmed that the other potential gas bearing zones (eight zones with 36.4 feet of perforations) were not contributing materially to the observed flow, being impeded by the weight of the water column in the wellbore, which severely limited the ability to achieve sufficient drawdown to initiate gas flow from these zones.
On July 17, 2018 CruzSur filed a technical discovery notice for Istanbul‐1, and on September 3, 2018 an Evaluation Program covering an area of 32,518 acres was declared around the well in which the reserves and prospective resources exist and are covered by the existing 3D seismic. The Evaluation Program consists of geological and geophysical studies and an evaluation of re‐entries on the existing wells, expiring on December 11, 2021. On December 7, 2018, CruzSur notified the ANH of its intention not to proceed to Phase 3 of the exploration program and to return the areas of the Maria Conchita Block not covered by the Evaluation Program. On December 13, 2018 the ANH returned the deposit held in guarantee of the phase 2 commitments in full to CruzSur. On September 27, 2019, MKMS officially signed documentation with the ANH to return the aforementioned area, maintaining the 32,518 acres under the Evaluation Program, and requested an extension of two additional years for this program.
Given the PLT results of the Istanbul‐1 well were inconclusive, it was decided to perform an in‐depth re‐ evaluation of the 3D seismic for the area and the amplitude versus offset (AVO) anomalies based on the new geological interpretation results. The new interpretation indicates the possibility that significant gas resources could exist for sustained development of the field.
As of April 2020, all activities had been suspended due to the COVID‐19 pandemic in Colombia. In late May 2020, the Company received authorization from the Colombia government to resume the Aruchara‐ 1 well re‐entry project. Currently the Company is in the midst of completing the re‐entry project in order to repair a gas leak detected during 2019, and performing a drill stem test (DST) to measure pressure and volumes. Based on the results, the Company will determine a subsequent work program which may include the drilling of 2 additional exploration wells in this area.
During the year 2020, it is planned to carry out further activities as part of the Evaluation Program. In order to determine the total perspectivity of the area, studies related to the design of facilities are also anticipated. Furthermore, once the evaluation studies have been completed and the field has been declared commercial, further studies will be performed related to extensive tests in the field for possible re‐entries and new wells to be drilled as part of a possible development plan.
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SN‐9 Block
The SN‐9 Block is located in the Lower Magdalena Valley, 75 km from Colombia's Caribbean coast. The SN‐9 Block has 730 km of 2‐D seismic. The Hechizo well was drilled on the block by Ecopetrol, S.A. in 1992 and tested gas in the Cienaga de Oro formation at a depth of approximately 4,250 ft.
The SN‐9 Block, which covers an area of approximately 311,353 acres in the Department of Cordoba, Colombia, has a 6‐year exploration period, divided in two phases of three years each, followed with a 24‐ year production period from the date when commerciality is declared. The SN‐9 Block is adjacent to blocks held by Canacol Energy Ltd. The area has excellent infrastructure with good roads and access to the northern gas trunk line.
The E&P Contract for the SN‐9 Block (the "SN‐9 E&P Contract"), dated October 8, 2014, was entered into between the ANH and Clean Energy Resources S.A.S., a Colombian corporation ("Clean"). The SN‐9 E&P Contract is currently in the first phase of the exploration program which includes a minimum work obligation of acquiring 125 km2 of 3‐D seismic and drilling one exploration well.
The Company is in the process of carrying out the exploration activities in stages which will satisfy the minimum work obligations. The first stage will see the finalization of the environmental impact study and prior consulting processes in order to obtain the necessary environmental licenses. This is to be followed by the drilling of two exploration wells in the Magico and Milagroso areas. The second stage will focus on evaluating the Hechicero and Hechizo areas, including drilling two additional exploration wells and acquiring 3D seismic for the development of the field. Drilling rigs are expected on site in Q4 2020. However, due to the ongoing COVID‐19 outbreak, activities related to the environmental license have been suspended and the field operator has asked the ANH for a 12‐month extension of the Phase 1 exploration commitment, with the objective of restarting activities as soon as COVID‐19 restrictions are lifted.
The terms of the agreement between the Company and Clean regarding the Company's acquisition from Clean of economic beneficial interest in the SN‐9 Block are as follows:
- The Company's participation interest is 72%. Clean's participation in the SN‐9 Block will be 13%, and will comprise two components:
- First component ‐ carried working interest of 8%
- Second component ‐ Clean will acquire an additional 5% by one of two options:
- Option 1 ‐ payment of $1.2 million to the Company if Clean chooses to only participate in
the first phase of the exploration program.
- Option 2 ‐ payment of $2.9 million to the Company if Clean chooses to participate in both phases of the exploration program.
Payment to the Company for either option will be received through the sale of 62.5% of Clean's production on the SN‐9 Block corresponding to this 5% interest. Furthermore, the share of Net Profit Interest and Overriding Royalties (as defined in the SN‐9 PSA) related to this additional 5% working interest will be the obligation of Clean and not carried by the Company.
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Tiburon Block
The Tiburon Block currently covers an area of approximately 245,850 acres in the Department of La Guajira, Colombia. The E&P Contract for the Tiburon Block (the "Tiburon E&P Contract") is a contract for the exploration and production of conventional hydrocarbons, dated June 14, 2006 and entered into between the ANH and Omimex de Colombia Ltd., which later changed its name to ColPan Oil & Gas Ltda. ("ColPan").
The Tiburon E&P Contract initially provided for an exploration period divided into six phases of twelve months each. The Tiburon E&P Contract is currently in Phase 3 of the exploration period with an existing minimum work obligation to acquire, process, and interpret 69.75 km2 of 3D seismic. The phase commitment is currently suspended due to "Force Majeure and Third‐Party Acts" due to local community issues within the region outside the control of the Company.
In light of this situation, the Company has carried out technical studies of the area in order to present for the consideration of the ANH the request to change the identified area within the Tiburon Block where the current minimum work obligation of 3D seismic is to be completed, and alternatively, complete the acquisition, processing and interpretation of 112 km 2D seismic in the Bahia Honda area within the Tiburon Block, which is equivalent to the current Phase 3 commitment of the E&P Contract of 69.75 km2 of 3D seismic. Once the ANH approves the change, the Company intends to start environmental and social analyses to execute the seismic activities, pending the outcome of the ongoing COVID‐19 outbreak.
The previous request is based on the technical study carried out on the area of the Tiburon Block, as well as on the analysis of its geological model. Through the study and re‐interpretation of the existing information, the Company has concluded that the Bahia Honda area (La Guajira) shows a higher level of perspectivity, being able to determine structures, leads and geological prospects of interest. In addition, there exists less uncertainty regarding social acceptance and the completion of the requisite prior consultation in this area, which can be completed expeditiously. This will ultimately allow the Company to execute the exploration activities and commitments of the E&P Contract with a high probability of success.
The terms of the agreement between the Company and ColPan outlining the Company's acquisition from ColPan of economic beneficial interest in the Tiburon Block are based on the execution of the following work program:
- 10% working interest on the completion of the Phase 3 3D seismic commitment
- An additional 15% working interest on the drilling and testing of one exploration well
- A further 15% working interest on the drilling and testing of a second exploration well
After completing the seismic commitment, CruzSur is not obligated to drill any of the exploration wells and can exit the contract with no further commitments, but will lose the original $0.3 million performance guarantee currently held in deposit with the ANH; alternatively, CruzSur may elect to stay in the license with a 10% working interest. $120,000 of management fees paid by the Company will be returned to CruzSur if the Company is still participating in the block when the ANH performance guarantee is returned at the end of the Phase 3 commitment. In the event that CruzSur does not fulfill the Phase 3 commitment, except for reasons beyond its control, CruzSur will cede a 1.5% carried working interest in the SN‐9 Block to Clean and forfeit the aforementioned $120,000 payment.
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Due to the ongoing COVID‐19 outbreak, the Company has requested from the ANH a one‐year extension of the exploration commitment.
Argentina
Sur Río Deseado Este Production Area
The Sur Río Deseado Este Production Area ("SRDE") is located in the Santa Cruz province in the Southern Flank of the Golfo San Jorge Basin. The Sur Río Deseado Este Production area covers approximately 12,000 acres and includes three heavy oil fields (Estación Tehuelches, La Frieda and La Frieda Oeste). The oil production is from a depth of approximately 2,800 ft. The Company maintains 79.06% working interest in SRDE after the acquisition of additional working interest from a former joint operation partner in October 2019. In 2020, the Company is preparing a formal request for the extension of the current exploration and production license for an additional ten years. The current license expires in March 2021.
Sur Río Deseado Este Exploration Area
The Sur Río Deseado Este Exploration Area neighbors the Sur Río Deseado Este Production Area and includes the right to exploit and carry out complementary exploration for hydrocarbons located in a concession with an area of 63,000 acres. Three wells have been drilled in the area to a depth of 3,820 ft to 4,100 ft and tested heavy oil. The Company maintains 11.52% working interest in this asset after the acquisition of additional working interest from a former joint operation partner in October 2019.
Estancia La Mariposa, Lomita de la Costa and Cerro Mangrullo
The Company acquired an 18% carried interest (before royalties) in the Estancia La Mariposa, Lomita de la Costa and Cerro Mangrullo Blocks (collectively, the "Mariposa Asset") through the acquisition of Alianza. The 3 blocks are located in the province of Santa Cruz and constitute a fully carried working interest in a gas prone area in the center of the Golfo San Jorge basin in the Santa Cruz province. Estancia La Mariposa covers 6,910 acres, Lomita de la Costa covers 2,525 acres, and Cerro Mangrullo covers 12,360 acres. The exploitation permits were granted in 2008. Current production comes from Estancia La Mariposa and is predominantly gas.
Negotiations with Panacol for the Joint Development of Oil & Gas Assets
In August 2019, the Company agreed to a non‐binding Memorandum of Understanding ("MOU") with Panacol Oil & Gas ("Panacol"), a company associated with a director of CruzSur, wherein Panacol will be responsible for the project management of the activities carried out by CruzSur in its different exploration blocks located in Colombia and Argentina following the guidelines of the Board of Directors of CruzSur. With a primary focus on the E&P Contract for the SN‐9 Block, the initial project management responsibilities of Panacol will be as follows:
- Procure all the activities necessary to obtain the required licenses, amend the obligations of the contract, operate the SN‐9 Block, negotiate and finalize the joint operating agreement with Clean.
- Negotiate with petroleum services providers who will be in charge of performing the required seismic, roads/infrastructure and drilling services estimated at $22.3 million.
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An estimated total of 6,800,000 common shares of the Company will be issued for the services being provided under the MOU in the development of the oil & gas assets. The issuance of the aforementioned common shares under the MOU is subject to the completion of Phase 1 of the E&P Contract for the SN‐9 Block. The estimated $22.3 million in expenditures for the completion of the SN‐9 Block phase 1 commitment are to be paid to contracted petroleum service providers as follows: $12 million as a non‐ recourse vendor financing to be paid out of 50% of the Company production share in the SN‐9 Block and $10 million by another service provider that will be negotiated as an operating tariff on the SN‐9 Block. The terms of the MOU are non‐binding until the execution of a definitive agreement between the parties that sets forth the terms and conditions of the MOU is completed. Under the terms of the MOU, the definitive agreement is to be finalized by August 2020.
OUTLOOK
The Company continues to move forward with its planned exploration program in the SN‐9 Block as was mentioned above. The Company believes the SN‐9 Block could be an important new source of natural gas in Colombia. Through a phased approach, CruzSur expects to grow reserves and provide a stable supply of natural gas in the country. The Company currently expects exploration activities to begin during Q4 2020, pending sufficient resolution of the ongoing COVID‐19 outbreak which is causing delays on necessary environmental license activities.
Furthermore, the aforementioned evaluation program is underway in the Maria Conchita Block to define total resources and determine the most appropriate development plan for the Uitpa and Jimol formations. The re‐entry project of the Aruchara‐1 well is anticipated to confirm the size of the accumulation of natural gas in the Aruchara area, which will allow the Company to design the best development project for this area of the field. Re‐entry of the Tinka‐1 and Istanbul‐1 wells at a future date could test several prospective zones based on new geological and seismic re‐interpretation. Regardless of operational delays in April and May 2020 due to the COVID‐19 pandemic, equipment mobilization to the Aruchara‐1 well site took place during June 2020 with re‐entry operations commencing in July 2020.
In Argentina, the Company will work towards the realization of the SRDE license extension of ten additional years with the objective to continue the development of this block to increase oil production, taking into account the current situation of the oil sector being highly impacted by the reduction of global oil prices on account of oil price wars and the reduction of global demand due to the COVID‐19 pandemic.
The Company anticipates prudently pursuing asset prioritization strategies, additional and/or alternative production and exploration opportunities, and the development of its undeveloped reserves. The Company may choose to delay development, depending on a number of circumstances, including the existence of higher priority expenditures, prevailing commodity prices and the availability of funds.
DISCUSSION OF OPERATING RESULTS
SRDE Operating Results
SRDE Asset production figures below represent CruzSur's net working interest of 54.14% in 2019 and 79.06% in 2020 due to the acquisition of additional working interest from a former joint operation partner in 2020, as previously mentioned.
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During the six months ended June 30, 2020, the SRDE concession produced a total of 4,097 boe (2019 comparative period ‐ 1,309 boe). This equated to average daily production of 23 boe/d (Q2 2019 ‐ 7 boe/d). No sales of SRDE oil production were realized during either Q2 2019 or Q2 2020. The crude oil production (and attributed production costs) was held in inventory at each respective period end.
The combined operating and royalty expenses incurred on SRDE production for the six months ended June 30, 2020 exceeded the net realizable value of the crude inventory. Thus, crude oil inventory is written down to its recoverable amount based on prevailing crude market prices. Loss on revaluation of SRDE crude inventory of $266,085 was recognized for the six months ended June 30, 2020 (2019 comparative period ‐ $57,590).
Net Revenue on Carried Working Interest
USD $ | Q2 2020 | Q2 2019 | Q1 2020 | Q4 2019 | Q3 2019 |
Ma ri pos a revenues before royalties | 104,031 | 248,288 | 145,209 | 144,558 | 336,431 |
Royalties | |||||
Government royalties | (13,959) | (34,363) | (17,769) | (19,206) | (35,005) |
Turnover tax | (1,334) | 741 | (742) | (715) | (1,817) |
Overriding royalties | ‐ | (2,714) | ‐ | ‐ | ‐ |
Mariposa revenues after royalties | 88,738 | 211,952 | 126,698 | 124,637 | 299,609 |
Transport, treating and processing | (2,867) | (4,274) | (3,225) | (5,393) | (4,531) |
Net Mariposa revenue | 85,871 | 207,678 | 123,473 | 119,244 | 295,078 |
The net revenue on carried working interest is derived from the carried interest held by the Company in the Mariposa Asset. The carried working interest entitles the Company to 18% (before royalties) of the oil, natural gas and condensate sales, while the operator carries 100% of the capital expenditures and the majority of operating costs. The net revenue figures associated with the Mariposa Asset are presented net of any applicable royalties and certain operating costs of transportation, treatment and processing. Oil and natural gas production is sold on behalf of the Company, for which the Company receives proceeds from the operator, net of applicable royalties and other specific costs. The net revenue generated from this asset has not been included in any "per barrel" pricing herein. Production revenue from this carried working interest is predominantly from natural gas production.
General and Administrative Expenses
General and administrative expenses ("G&A") for the six months ended June 30, 2020 totaled $921,201 (2019 comparative period ‐ $2,620,234). The G&A expenses relate to the normal course of the Company's operations, and are constituted as follows:
USD $ | Q2 2020 | Q2 2019 | Q1 2020 | Q4 2019 | Q3 2019 |
Profes s i ona l Fees | 356,057 | 202,974 | 199,986 | 356,840 | 284,939 |
Wages & Salaries | 46,500 | 413,763 | 85,569 | 174,706 | 167,588 |
Severance & Restructuring | ‐ | 1,130,925 | ‐ | ‐ | ‐ |
Fees, Rent, Investor Relations & Other | 132,022 | 191,609 | 101,067 | 180,830 | 235,533 |
Total | 534,579 | 1,939,271 | 386,622 | 712,376 | 688,060 |
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Professional fees are comprised of legal, audit, tax, and other fees that have been incurred by the Company for operations. Wages and salaries are amounts paid to employees of the Company. Severance costs consist of severance payments paid and/or owed to former employees of the Company. Other expenses comprise the normal operations of the Company and include office rent, public relations, insurance, travel, and other general and administrative expenses.
Share‐Based Payments
In June 2020, the Company granted 1,556,000 options to acquire common shares to certain directors, officers, employees and consultants of the Company at a price of C$0.275 per common share. The options were for a ten‐year term, expiring on June 24, 2030. All of the options granted vested immediately on the date of grant.
The value of the stock options vesting in the six months ended June 30, 2020 equated to $261,052 (2019 comparative period - recovery of $100,078), which was expensed as share‐based payments.
Depletion and Depreciation ("D&D")
The Company's depletion and depreciation expense in each of the reporting periods is as follows:
USD $ | Q2 2020 | Q2 2019 | Q1 2020 | Q4 2019 | Q3 2019 |
Ma ri pos a | 68,309 | 116,262 | 74,027 | 82,409 | 115,817 |
Depletion on oil and gas assets | 68,309 | 116,262 | 74,027 | 82,409 | 115,817 |
Fixed asset depreciation | 24,848 | 15,856 | 24,721 | 23,304 | 18,746 |
Total depletion and depreciation | 93,157 | 132,118 | 98,748 | 105,713 | 134,563 |
Finance Income and Expense
The Company's finance related income and expenses for each of the reporting periods are as follows:
USD $ | Q2 2020 | Q2 2019 | Q1 2020 | Q4 2019 | Q3 2019 |
Cash: | |||||
Interes t income | (27,658) | (52,350) | (31,628) | (9,534) | (47,585) |
Interest expenses and bank charges | 135,714 | 46,915 | 133,099 | 101,716 | 69,396 |
Total net cash finance expense (income) | 108,056 | (5,435) | 101,471 | 92,182 | 21,811 |
Non‐cash: | |||||
Accretion on decommissioning obligation | 2,131 | 23,019 | 2,078 | 2,117 | 2,202 |
Accretion on liability component of | |||||
convertible debentures | 27,656 | 14,608 | 27,636 | 26,920 | 25,978 |
Amortization of transaction costs on | |||||
Aruchara Loan | 3,474 | ‐ | 3,375 | 951 | ‐ |
Total net non‐cash finance expense | 33,261 | 37,627 | 33,089 | 29,988 | 28,180 |
Total net finance expense (income) | 141,317 | 32,192 | 134,560 | 122,170 | 49,991 |
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Foreign Exchange
The Company incurred a foreign exchange loss of $632,399 for the six months ended June 30, 2020 ( 2019 comparative period ‐ gain of $19,935). Foreign exchange losses are due to the decrease in the value of the US dollar when compared to the Canadian dollar, Colombian peso, and the Argentina peso in the period. Conversely, foreign exchange gains are due to an increase in the value of the US dollar in comparison to these foreign currencies.
Cash used in Operations
For the six months ended June 30, 2020, the Company used cash in operations of $882,964 (2019 comparative period ‐ $1,748,202). The cash used in operations is primarily comprised of operating expenses, G&A expenses and business development expenses incurred partially offset by oil and natural gas revenues generated during these periods.
CAPITAL ADDITIONS
For the six months ended June 30, 2020, the Company had additions (prior to recognition of any impairments, disposals or revisions of estimates) of $766,968 relating to exploration and evaluation assets and $2,567 relating to property, plant and equipment assets. Additions to exploration and evaluation assets relate primarily to 1) preparatory activities for the Aruchara well re‐entry project; and 2) SN‐9 community relations and environmental license compliance work.
LIQUIDITY AND CAPITAL RESOURCES AND GOING CONCERN
The Company's capital management objective is to have sufficient capital to be able to execute its business plan. The Company manages its capital structure and makes adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying oil and natural gas assets. The continued development of the Company's oil and natural gas assets is dependent on the ability of the Company to secure sufficient funds through operations, credit facilities and other sources. Such funds may not be available on acceptable terms or at all.
During the six months ended June 30, 2020, the Company incurred a loss from operations of $2.4 million and used $0.9 million of cash flow in its operating activities. While as at June 30, 2020 the Company had a working capital balance of $2.6 million, this is not considered sufficient to fund administrative budget and capital commitment amounts that exist for the upcoming year and beyond.
The Company will continue to utilize its financial resources to fund existing administrative budgets and capital commitments. There is uncertainty as to the future operating and development ability of the Company as it will be contingent upon the Company's ability to successfully identify and procure necessary capital. There is material uncertainty as to the future ability of the Company to fulfill existing commitments as it will be contingent upon the Company's ability to successfully identify and procure necessary capital, which may be by way of strategic transactions to obtain financing and/or generate profitable operations that are beneficial to the Company and its shareholders.
The Financial Statements have been prepared on a going concern basis, which assumes that the Company will be able to discharge its obligations and realize its assets in the normal course of operations for the foreseeable future.
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Management believes that the going concern assumption is appropriate for the Financial Statements and that the Company will be able to meet its budgeted capital and administrative costs as well as its other potential capital commitments during the upcoming year and beyond. There is no guarantee that the Company will be successful in its exploration and development activities and no certainty as to the timing of the Company's impending exploration commitments. Should the going concern assumption not be appropriate and the Company is not able to realize its assets and settle its liabilities, the Financial Statements would require adjustments to the amounts and classifications of assets and liabilities, and these adjustments could be significant.
The Company's Colombian oil and gas interests are in the exploration stage and the Company has yet to establish operations to achieve sustainable production from its acquired oil and gas assets. Accordingly, the recoverability of amounts recorded as oil and natural gas properties is dependent upon successful development of its assets in order to put them into production and then achieve future profitable production, the ability of the Company to secure adequate sources of financing to continue to fund the development of its assets, and the political stability of Colombia. The outcome of these matters cannot be predicted with certainty at this time.
Certain Argentine oil and gas interests are in the early exploration stage and are still being analyzed to assess an appropriate development plan. Accordingly, the recoverability of amounts recorded as oil and natural gas properties is dependent upon the existence, discovery, and exploitation of economically recoverable oil and gas reserves on blocks, the political stability of Argentina, and the ability of the Company to secure adequate sources of financing to continue to fund the development of its assets and achieve future profitable production. The outcome of these matters cannot be predicted with certainty at this time.
Convertible Debentures
In May 2019, the Company completed a non‐brokered private placement of secured convertible debentures for aggregate proceeds of $2.5 million (C$3.35 million), before transaction costs. The debentures mature on May 7, 2024, bear interest at the rate of 10% per annum and are secured by a general security agreement on the assets of the Company. Under the terms of the debentures, the lenders may, at any time prior to the maturity date convert any or all of the principal amount of the debentures into units of the Company at a conversion price of C$0.15 per unit. Each unit is comprised of one common share of the Company and one share purchase warrant. Each warrant entitles the holder to purchase one common share of the Company at a price of C$0.15 until May 7, 2024. At the option of the Company, accrued interest may be paid in cash or converted into common shares of the Company at the then‐market price of the Company's common shares, subject to TSX‐V approval.
As of the date of this MD&A, convertible debentures with a face value of $2.3 million (C$3.2 million) remaining outstanding. Please refer to the "Share Capital" section below for further details regarding debenture conversions into units of the Company and interest installment payments by way of issuance of shares that have transpired in the 2020 year.
Aruchara Loan
In December 2019, the Company entered into a loan in the amount of $1.6 million, secured by the assets of the Company. The loan is denominated in US dollars, matures on December 5, 2021, and bears interest at the rate of 15% per annum. The proceeds of the loan are to be utilized for the costs of the re‐entry
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project of the Aruchara well in the Maria Conchita block. Under the terms of the loan agreement, the lenders have also been granted a 2.5% overriding royalty derived from the production of the Maria Conchita block. Total interest and principal is payable at the maturity date, although the lenders have an option to convert the loan principal and interest into another 2.5% overriding royalty from the Maria Conchita block at the lenders' discretion at any point prior to the maturity date. Currently, no value has been attributed to the 2.5% overriding royalty or the conversion option for an additional 2.5% overriding royalty as this is contingent upon the successful realization of commercially viable operations within the Maria Conchita block.
Bridge Loan
In May 2020, the Company entered into a bridge loan in the amount of $100,000. The loan is denominated in US dollars and bears interest at the rate of 12% per annum. The proceeds of the loan are to be utilized to finance immediate operations for the SN‐9 block. Total interest and principal is payable at the maturity date, which is defined as five days after the receipt of the proceeds of the SN‐9 Debt Agreement (see below).
Maria Conchita Debt Agreement
In July 2020, the Company entered into a loan in the amount of $350,000. The loan is denominated in US dollars and bears interest at the rate of 20% per annum. The loan matures at the earlier of six months from the advance date or such time as proceeds to the Company from gross production in the Maria Conchita block total or exceed the principal amount plus accrued interest. The proceeds of the loan are to be utilized to fund exploration activities in the Maria Conchita block.
SN‐9 Debt Agreement
In August 2020, the Company entered into a loan in the amount of $2.5 million, secured by the assets of the Company. The loan is denominated in US dollars, matures in August 2022, and bears interest at the rate of 15% per annum. The proceeds of the loan are to be utilized for the costs of exploratory activities in the SN‐9 block. Under the terms of the loan agreement, the lenders have also been granted a 3% overriding royalty on CruzSur's working interest in the gross production of the SN‐9 block. Total interest and principal is payable at the maturity date, although the lenders have an option to convert the loan principal and interest into another 3% overriding royalty on CruzSur's working interest in the gross production of the SN‐9 block at the lenders' discretion at any point prior to the maturity date.
Restricted Cash
As of June 30, 2020, funds totaling $2,469,408 (December 31, 2019 ‐ $2,824,705) were classified as restricted cash. The composition of this amount is as follows:
2020 | 2019 | |
SN‐9 ANH Guarantee Deposit | 2,159,127 | 2,476,084 |
Tiburon ANH Guarantee Deposit | 310,281 | 348,621 |
Restricted cash | 2,469,408 | 2,824,705 |
Term deposits of $2.4 million and $0.3 million were established to secure performance guarantees required by the ANH under the E&P Contracts for the SN‐9 and Tiburon Block. The SN‐9 and Tiburon
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deposits amounts are defined in US dollars by the ANH but are held in Colombian pesos with Colombian banks and are subject to foreign currency fluctuation risks in relation to the US dollar. These deposits are to be released to the Company once current phase commitments under each E&P Contract are completed. As of June 30, 2020, the balances of the SN‐9 term deposit and Tiburon term deposit were $2,159,127 and $310,281, respectively.
SHARE CAPITAL
Common shares
As at June 30, 2020, the Company was authorized to issue an unlimited number of common shares, with no par value, with holders of common shares entitled to one vote per share and to dividends, if declared. Outstanding common shares as of June 30, 2020 are as follows:
Common shares | Amount ($) | |
Balance, December 31, 2018 | 24,220,160 | 63,799,393 |
Shares issued as severance payment | 3,692,481 | 756,312 |
Shares issued as payment of contractual amounts | 925,925 | 187,362 |
Conversion of debentures | 666,666 | 41,724 |
Shares issued for interest payment | 670,608 | 127,240 |
Balance December 31, 2019 | 30,175,840 | 64,912,031 |
Shares issued through private placement (net of costs) | 12,000,000 | 1,072,031 |
Conversion of debentures | 446,666 | 29,727 |
Shares issued for interest payment | 806,719 | 115,122 |
Balance June 30, 2020 | 43,429,225 | 66,128,911 |
March 2020 private placement
In March 2020, the Company completed a non‐brokered private placement of 2,000,000 units at a price of C$0.15 per unit, for gross proceeds of C$300,000 before transaction costs. Each unit consisted of one common share and on share purchase warrant, with each warrant entitling the holder to purchase one additional share at a price of C$0.18 until March 27, 2022.
May 2020 private placement
In May 2020, the Company completed a non‐brokered private placement of 10,000,000 units at a price of C$0.18 per unit, for gross proceeds of C$1,800,000 before transaction costs. Each unit consisted of one common share and on share purchase warrant, with each warrant entitling the holder to purchase one additional share at a price of C$0.23 until May 27, 2022. All securities issued in connection with the private placement are subject to a four month and one day statutory holding period, expiring on September 28, 2020.
Convertible debt interest instalment payment and conversion exercise
In May 2020, the Company made the second instalment payment on accrued interest of $115,122 (C$161,344) corresponding to the convertible debentures issued in May 2019. In accordance with the
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terms of the convertible debentures, the Company elected to issue 806,719 common shares having a deemed price of C$0.20 per share in satisfaction of the aggregate accrued interest. The price per share was determined using the 30‐day volume weighted average price of the common shares on the TSX‐V ending on May 6, 2020. These common shares will be subject to a four month hold period in accordance with applicable Canadian securities laws and are subject to the acceptance of the TSX‐V.
Furthermore, in May 2020, certain debenture holders elected to convert C$67,000 face value of their debentures to units of the Company at the conversion price of C$0.15 per unit, resulting in the issuance of 446,666 common shares and 446,666 share purchase warrants.
Stock Options
The Company's stock option plan provides for the issue of stock options to directors, officers, employees, charities and consultants, who are all considered related parties to the Company. The plan provides that stock options may be granted up to a number equal to 10% of the Company's outstanding shares. Vesting terms are determined by the Board of Directors as they are granted and currently include periods ranging from immediately to one‐third on each anniversary date over three years. The options' maximum term is ten years.
As at June 30, 2020, a total of 4,342,600 (December 31, 2019 - 2,876,600) options were issued and outstanding under this plan. Options which are forfeited/expired are available for reissue.
A summary of the changes in stock options is presented below:
Weighted average | ||
Stock options | exercise price (C$) | |
Balance, December 31, 2018 | 1,542,100 | 6.76 |
Options issued | 2,462,500 | 0.45 |
Options forfeited | (1,128,000) | 6.37 |
Options amended (old price) | (72,500) | 7.87 |
Options amended (new price) | 72,500 | 0.45 |
Balance, December 31, 2019 | 2,876,600 | 1.33 |
Options issued | 1,556,000 | 0.28 |
Options expired | (90,000) | 0.45 |
Balance, June 30, 2020 | 4,342,600 | 0.97 |
The following summarizes information about stock options outstanding as at June 30, 2020:
Number of options | Weighted average term to | Number of options | |
Exercise prices (C$) | outstanding | expiry (years) | exercisable |
0.28 | 1,556,000 | 9.98 | 1,556,000 |
0.45 | 2,445,000 | 9.02 | 2,195,000 |
6.10 | 31,600 | 6.14 | 31,600 |
8.00 | 310,000 | 7.11 | 310,000 |
4,342,600 | 9.21 | 4,092,600 |
In June 2020, the Company granted 1,556,000 options to acquire common shares to certain directors, officers, employees and consultants of the Company at a price of C$0.275 per common share. The options
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were for a ten‐year term, expiring on June 24, 2030. All of the options granted vested immediately on the date of grant.
The value of the stock options vesting in the six months ended June 30, 2020 equated to $261,052 (2019 comparative period - recovery of $100,078), which was expensed as share‐based payments.
Warrants
Private purchase warrants
Pursuant to the non‐brokered private placement of units in March 2020 (see above), the Company issued 2,000,000 units, each consisting of one common share and one share purchase warrant. Each warrant can be exercised to purchase one additional common share at a price of C$0.18 until March 27, 2022 (the "Private Purchase Warrants"). A fair value of $62,156 (C$87,366), net of issue costs, was recognized at the time of the issuance of the Private Purchase Warrants.
Pursuant to the non‐brokered private placement of units in May 2020 (see above), the Company issued 10,000,000 units, each consisting of one common share and one share purchase warrant. Each warrant can be exercised to purchase one additional common share at a price of C$0.23 until May 27, 2022 (the "Private Purchase Warrants"). A fair value of $358,943 (C$494,624), net of issue costs, was recognized at the time of the issuance of the Private Purchase Warrants.
Purchase warrants
Pursuant to various transactions in 2017, the Company issued a total of 5,625,000 Units, each consisting of one common share and one share purchase warrant, each exercisable into one additional common share at a price of C$10.50 per share until July 31, 2022 (the "Purchase Warrants"). A fair value of $10,201,910 (C$12,754,916), net of issue costs, was recognized at the time of the issuance of the Purchase Warrants.
The 5,625,000 Purchase Warrants are publicly listed for trading on the TSX‐V under the symbol "CZR.WT".
Purchase warrants on conversion of debentures
Pursuant to the convertible debentures issued in May 2019 (see above), debenture holders may convert any or all of the principal amount of the debentures into units of the Company at a conversion price of C$0.15 per unit. Each unit is comprised of one common share of the Company and one share purchase warrant. Each warrant entitles the holder to purchase one common share of the Company at a price of C$0.15 until May 7, 2024.
In October 2019, a certain debenture holder elected to convert C$100,000 face value of their debentures to units of the Company at the conversion price of C$0.15 per unit, resulting in the issuance of 666,666 purchase warrants. Of the overall value assigned to these debentures, $31,354 was reclassed to warrants as the attributable value of the issued purchase warrants.
In May 2020, a certain debenture holder elected to convert C$67,000 face value of their debentures to units of the Company at the conversion price of C$0.15 per unit, resulting in the issuance of 446,666
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purchase warrants. Of the overall value assigned to these debentures, $14,964 was reclassed to warrants as the attributable value of the issued purchase warrants.
The following summarizes information about total purchase warrants outstanding as at June 30, 2020:
Number of warrants | Weighted average term | Number of warrants | |
Exercise prices (C$) | outstanding | to expiry (years) | exercisable |
0.15 | 1,113,332 | 3.85 | 1,113,332 |
0.18 | 2,000,000 | 1.74 | 2,000,000 |
0.23 | 10,000,000 | 1.91 | 10,000,000 |
10.50 | 5,625,000 | 2.08 | 5,625,000 |
18,738,332 | 2.06 | 18,738,332 |
COMMITMENT SUMMARY UPDATE
A summary of the Company's estimated capital commitments (in millions of dollars) are as follows:
Block | 2020 | 2021 | 2022 | Total |
SN‐9 Block (1) | 22.3 | ‐ | ‐ | 22.3 |
Tiburon Block (2) | 3.0 | ‐ | ‐ | 3.0 |
Total | 25.3 | ‐ | ‐ | 25.3 |
- CruzSur's ANH commitment to carry out the minimum requirement to process and interpret 204.4 km of 2D seismic and drill one exploration well (for which the Company will pay 100% of the costs under the terms of the SN‐9 Acquisition) according to Phase 1 of the contractual exploration program, which must be fulfilled by December 2020, pending extensions granted on account of the ongoing COVID‐ 19 outbreak, due to which non‐essential oil & gas operations have been suspended by the Government of Colombia. The Company assumes that operations will commence in 2020.
- Relates to CruzSur's share of the ANH commitment to carry out the minimum requirement to acquire, process, and interpret 69.75 km2 of 3D seismic according to Phase 3 of the contractual exploration program. Currently, operations are delayed due to disputes in the region, with current ANH deadline of 2020 with extensions if disputes were resolved in 2020. The Company has submitted a request to the ANH for a change in the area of the seismic activities and an extension of the deadline for this phase of exploration due to the ongoing COVID‐ 19 outbreak. The commencement date for seismic acquisition is unknown at this time and will depend upon approval of the revised seismic area and the start of the social and environmental activities, all of which are dependent upon the COVID‐19 situation. The Company assumes that activities related to the permits for the new seismic survey will commence in 2020.
The expenditures provided in the above table only represent the Company's estimated cost to satisfy contract requirements. Actual expenditures to satisfy these commitments, initiate production or create reserves may differ from these estimates. The expenditures in the above table are based on the latest possible date required per contract and may be incurred at an earlier date.
RELATED PARTIES
During the period ended June 30, 2020, there were separate related party transactions as follows:
- The Company paid a monthly advisory fee to a firm affiliated with a director of CruzSur. As per the consulting agreement with this firm, CruzSur pays a monthly fee of C$10,000 plus reimbursable expenses. Furthermore, additional fees are to be paid pursuant to the closing of successful financing arrangements, divestitures, or acquisitions for which the firm provides advisory services. During the period ended June 30, 2020, administrative success fees were paid
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upon closing of the private placements through units summarized in Note 9, which resulted in the Company paying C$21,000 to the firm. As at June 30, 2020, outstanding payables to the firm totaled $C23,500.
- In March 2020, the Company completed the aforementioned non‐brokered private placement through units for proceeds of C$300,000, before issue costs. Of the total proceeds, approximately C$165,000 were from subscriptions by directors of the Company.
- In May 2020, the Company completed the aforementioned non‐brokered private placement through units for proceeds of C$1,800,000, before issue costs. Of the total proceeds, approximately C$275,580 were from subscriptions by directors of the Company.
SELECTED QUARTERLY INFORMATION
The following table sets out selected quarterly financial information of CruzSur and is derived from unaudited quarterly financial data prepared by management in accordance with IFRS.
Q2 2020 | Q1 2020 | Q4 2019 | Q3 2019 | ||
Net Revenue | 85,871 | 123,473 | 226,961 | 394,843 | |
Net income (loss) | (511,638) | (1,875,837) | (2,933,720) | (2,221,789) | |
Comprehensive income (loss) | (675,276) | (1,518,155) | (3,002,598) | (2,203,593) | |
Net income (loss) per share | |||||
(basic & diluted): | (0.01) | (0.06) | (0.09) | (0.08) | |
Q2 2019 | Q1 2019 | Q4 2018 | Q3 2018 | ||
Net Revenue | 430,583 | 367,343 | 904,045 | 207,772 | |
Net loss | 3,287,691 | (829,538) | (32,893,354) | (1,620,843) | |
Comprehensive loss | 3,270,781 | (853,708) | (32,840,845) | (1,585,006) | |
Net loss per share | |||||
(basic & diluted): | 0.14 | (0.03) | (1.36) | (0.07) |
Changes in net loss reported between each quarterly period to date is primarily a function of variances in foreign exchange gains/losses, general and administrative expense, and business development expenses recorded in each quarter. Significant corporate and administrative expenses are incurred each year with the establishment of corporate operations in Canada, Colombia and Argentina, including administrative and operations staff. Additionally, in Q4 2019, impairment losses of $2.1 million were recognized in relation to E&E assets. In 2018, impairment losses of $58.9 million were recognized in relation to E&E assets, with $25.0 million being recognized in Q2 2018 and $33.9 million being recognized in Q4 2018. The relinquishment of the Llancanelo Asset resulted in a significant reduction in production revenue and associated operating costs per quarter, commencing in Q3 2018. A gain of $5.0 million was recognized in Q2 2019 as a result of the settlement on the Alianza acquisition, as mentioned previously. In Q3 2019, a loss on disposal of $0.4 million was recognized with the disposition of the KM8 Asset and operator entity.
ADOPTION OF NEW AND REVISED ACCOUNTING STANDARDS
The Company has adopted certain new and revised IFRSs that have been issued effective January 1, 2019. Detailed discussions of new accounting policies that may affect the Company are provided in the Financial Statements.
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USE OF ESTIMATES AND JUDGEMENTS
The timely preparation of the financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of the financial statements are outlined below.
Critical judgments in applying accounting policies
The following are the critical judgments that management has made in the process of applying the Company's accounting policies and that have the most significant effect on the amounts recognized in these consolidated financial statements:
-
Identification of cash‐generating units
The Company's assets are aggregated into cash‐generating units, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows. By their nature, these estimates and assumptions are subject to measurement uncertainty and may impact the carrying value of the Company's assets in future periods. - Impairment of property, plant and equipment and exploration and evaluation assets
Judgments are required to assess when impairment indicators, or reversal indicators, exist and impairment testing is required. In determining the recoverable amount of assets, in the absence of quoted market prices, impairment tests are based on estimates of reserves, production rates, future oil and natural gas prices, future costs, discount rates, market value of land and other relevant assumptions. - Exploration and evaluation assets
The application of the Company's accounting policy for exploration and evaluation assets requires management to make certain judgments as to future events and circumstances as to whether economic quantities of reserves have been found in assessing economic and technical feasibility. - Income taxes
Judgments are made by management to determine the likelihood of whether deferred income tax assets at the end of the reporting period will be realized from future taxable earnings. To the extent that assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in profit or loss in the period in which the change occurs. - Right‐of‐use assets and lease liabilities
The Company has applied judgment and estimates when determining the estimated lease payments including the lease term. The assessment of whether a renewal, extension, termination or purchase option is reasonably certain to exercise was considered, based on facts and circumstances, and has the potential to significantly impact the amount of right‐of‐use asset and lease obligation recognized.
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Key sources of estimation uncertainty
The following are the key assumptions concerning the sources of estimation uncertainty at the end of the reporting period, that have a significant risk of causing adjustments to the carrying amounts of assets and liabilities.
-
Reserves and resource assessment
The assessment of reported recoverable quantities of proved and probable reserves and prospective resource estimates include estimates regarding production profile, commodity prices, exchange rates, remediation costs, timing and amount of future development costs, and production, transportation and marketing costs for future cash flows. It also requires interpretation of geological and geophysical models in anticipated recoveries. The economical, geological and technical factors used to estimate reserves and prospective resources may change from period to period. Changes in reported reserves and prospective resources can impact the carrying values of the Company's petroleum and natural gas properties and exploration and evaluation assets and equipment, the calculation of depletion and depreciation, the provision for decommissioning obligations, and the recognition of deferred tax assets due to changes in expected future cash flows.
The Company's petroleum and natural gas reserves represent the estimated quantities of petroleum, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be economically recoverable in future years from known reservoirs and which are considered commercially viable. Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon (i) a reasonable assessment of the future economics of such production; (ii) a reasonable expectation that there is a market for all or substantially all the expected petroleum and natural gas production; and (iii) evidence that the necessary production, transmission and transportation facilities are available or can be made available. Reserves may only be considered proven and probable if the ability to produce is supported by either actual production or conclusive formation tests. Prospective resource are determined using an externally prepared valuation report which reflects estimated prospective resources and external pricing and costs assumptions reflective of the current market. The Company's petroleum and gas reserves and prospective resources are determined pursuant to National Instrument 51‐101, Standard of Disclosures for Oil and Gas Activities. - Decommissioning obligations
The Company estimates future remediation costs of production facilities, wells and pipelines at different stages of development and construction of assets or facilities. In most instances, removal of assets occurs many years into the future. This requires assumptions regarding abandonment date, future environmental and regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the removal cost and liability‐specific discount rates to determine the present value of these cash flows. - Business combinations
In a business combination, management makes estimates of the fair value of assets acquired and liabilities assumed which includes assessing the value of oil and gas properties based upon the estimation of recoverable quantities of proven and probable reserves being acquired.
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-
Share‐based payments
All equity‐settled, share‐based awards issued by the Company are recorded at fair value using the Black‐Scholes option‐pricing model. In assessing the fair value of equity‐based compensation, estimates have to be made regarding the expected volatility in share price, option life, dividend yield, risk‐free rate and estimated forfeitures at the initial grant date. - Tax provisions
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in profit or loss both in the period of change, which would include any impact on cumulative provisions, and in future periods. Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse.
PRINCIPAL BUSINESS RISKS
The Company's business and results of operations are subject to a number of risks and uncertainties including, but not limited to the following:
Crude Oil and Natural Gas Development
Exploration, development, production of oil and natural gas involves a wide variety of risks which include but are not limited to the uncertainty of finding oil and gas in commercial quantities, securing markets, commodity price fluctuations, exchange and interest rate exposure and changes to government regulations, including regulations relating to prices, taxes, royalties and environmental protection. The oil and gas industry is intensely competitive and the Company competes with a large number of companies with greater resources.
The Company's ability to obtain reserves in the future will depend not only on its ability to develop its current properties but also on its ability to acquire new prospects and producing properties. The acquisition, exploration and development of new properties also require that sufficient capital from outside sources will be available to the Company in a timely manner. The availability of equity or debt financing is affected by many factors many of which are beyond the control of the Company.
Foreign Operations
There are a number of risks associated with conducting foreign operations over which the Company has no control, including political instability, potential and actual civil disturbances, ability to repatriate funds, changes in laws affecting foreign ownership and existing contracts, environmental regulations, oil and gas prices, production regulations, royalty rates, income tax law changes, potential expropriation of property without fair compensation and restriction on exports.
Addition of Reserves and Resources
The Company's future crude oil and natural gas reserves, production, and cash flows to be derived therefrom are highly dependent on the Company successfully discovering and developing or acquiring new reserves and resources. The addition of new reserves and resources will depend not only on the Company's ability to explore and develop properties but also, in the case of reserves, on its ability to select and acquire suitable producing properties or prospects. There can be no assurance that the Company's
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exploration, development or acquisition efforts will result in the discovery and development of commercial accumulations of oil and natural gas.
Reserve Estimates
There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the control of the Company. Estimates of reserves depend in large part upon the reliability of available geological and engineering data and require certain assumptions to be made in order to assign reserve volumes. Geological and engineering data is used to determine the probability that a reservoir of oil and/or natural gas exists at a particular location, and whether, and to what extent, such hydrocarbons are recoverable from the reservoir. Accordingly, the ultimate reserves discovered by the Company may be significantly less than the total estimates.
Exploration Risks
The exploration of the Company's properties may from time to time involve a high degree of risk that no production will be obtained or that the production obtained will be insufficient to recover drilling and completion costs. The costs of seismic operations and drilling, completing and operating wells are uncertain to a degree. Cost overruns can adversely affect the economics of the Company's exploration programs and projects. In addition, the Company's seismic operations and drilling plans may be curtailed, delayed or cancelled as a result of numerous factors, including, among others, equipment failures, weather or adverse climate conditions, shortages or delays in obtaining qualified personnel, shortages or delays in the delivery of or access to equipment, community issues and social unrest, necessary governmental, regulatory, or other third party approvals and compliance with regulatory requirements.
Management's Report on Internal Control over Financial Reporting
In connection with National Instrument 52‐109 ‐ Certification of Disclosure in Issuer's Annual and Interim Filings ("NI 52‐109") adopted by each of the securities commissions across Canada, the Chief Executive Officer and Chief Financial Officer of the Company are required to file a Venture Issuer Basic Certificate with respect to the financial information contained in the unaudited interim financial statements and the audited annual financial statements and respective accompanying Management's Discussion and Analysis. The Venture Issuer Basic Certificate does not include representations relating to the establishment and maintenance of disclosure controls and procedures and internal control over financial reporting, as defined in NI 52‐ 109.
FINANCIAL AND OTHER INSTRUMENTS
The Company has exposure to the following risks from its use of financial instruments:
- Credit risk
- Liquidity risk
- Market risk
This note presents information about the Company's exposure to each of the above risks and the Company's objectives, policies and processes for measuring and managing these risks, and the Company's management of capital. The Board of Directors has overall responsibility for the establishment and oversight of the Company's risk management framework. The Company's risk management policies are
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established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities.
Credit risk
Credit risk reflects the risk of loss if counterparties do not fulfill their contractual obligations. The carrying amount of cash and cash equivalents, short‐term investments, accounts receivable and restricted cash represent the maximum credit exposure. As at June 30, 2020, the Company had $2,469,408 (December 31, 2019 ‐ $2,824,705) in restricted cash towards development activity and joint operations in Colombia. The Company mitigates credit risk exposure related to restricted cash by ensuring that drawdowns on these accounts can not be performed without prior authorization by the Company.
As at June 30, 2020, the company had $2,482,197 (December 31, 2019 ‐ $2,272,352) in accounts receivable and prepaids. The Company's policy to mitigate credit risk associated with these balances is to establish marketing relationships with large purchasers. In Argentina, the Company's oil production is sold principally to YPF. The Company does not consider any of its receivables past due.
The Company held cash and cash equivalents of $1,146,940 (December 31, 2019 ‐ $1,423,184) as at June 30, 2020. The Company manages the credit exposure related to cash and cash equivalents and short‐term investments by selecting counter parties based on credit ratings and monitors all investments to ensure a stable return, avoiding complex investment vehicles with higher risk such as asset‐backed commercial paper.
Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due and describes the Company's ability to access cash. The Company's approach to managing liquidity is to ensure, as far as possible, that it will have sufficient cash resources in order to finance operations, fund capital expenditures, and to repay debt and other liabilities of the Company as they come due, without incurring unacceptable losses or risking harm to the Company's reputation. The Company's processes for managing liquidity risk include preparing and monitoring capital and operating budgets, coordinating and authorizing project expenditures, and authorization of contractual agreements. The Company seeks additional financing based on the results of these processes. The budgets are updated when required as conditions change.
The following table outlines the contractual maturities of the Company's financial liabilities at June 30, 2020:
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Less than 1 year | 1‐2 years | Thereafter | Total | |
Convertible debentures ‐ principal | ‐ | ‐ | 2,335,633 | 2,335,633 |
Trade accounts payable | 2,411,073 | ‐ | ‐ | 2,411,073 |
Aruchara loan ‐ principal | ‐ | 1,600,000 | ‐ | 1,600,000 |
Bridge loan ‐ principal | ‐ | ‐ | 100,000 | 100,000 |
Consideration payable on acquisition | 450,000 | ‐ | ‐ | 450,000 |
Capital payables | 679,407 | ‐ | ‐ | 679,407 |
Joint venture payables | 138,301 | ‐ | ‐ | 138,301 |
Convertible debentures ‐ interest | 34,481 | ‐ | ‐ | 34,481 |
Aruchara loan ‐ interest | ‐ | 136,667 | ‐ | 136,667 |
Bridge loan ‐ interest | 1,333 | ‐ | ‐ | 1,333 |
3,714,595 | 1,736,667 | 2,435,633 | 7,886,895 |
Market risk
Market risk is the risk or uncertainty that changes in price, such as commodity prices, foreign exchange rates, and interest rates will affect the Company's net earnings and the value of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns. From time to time, the Company may utilize financial derivative contracts to manage market risks in accordance with the risk management policy that has been approved by the Board of Directors. There were no financial derivative contracts or embedded derivatives outstanding at June 30, 2020 nor were there any in the previous year ended December 31, 2019.
Commodity price risk
Commodity price risk is the risk that the fair value of the future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by not only the United States dollar, but also by world economic events that dictate the levels of supply and demand.
The Company's oil revenue is primarily derived from oil production on the SRDE Asset in Argentina. SRDE oil revenue is based on the periodic sale of the minimal production from this exploration asset throughout the calendar year, considering storage capacity and market prices. In May 2020, the Government of Argentina reinstated a mandatory benchmark price for oil, setting it at $45 per barrel in an attempt to shore up oil prices. Because comparable free‐floating benchmarks such as Brent crude were generally below the Government of Argentina's benchmark). As a result, no oil revenue from the sale of SRDE oil inventory was realized for the six months ended June 30, 2020 as the Company retains realized oil production in storage facilities until such time that prevailing market prices become more certain in light of factors affecting the Argentina oil market and economic situation, including the economic impact of the COVID‐19 outbreak.
Gas prices in Argentina are subject to seasonal demand and are negotiated between the producer and the buyer. Net revenue from the carried working interest on the Mariposa Asset is predominantly from natural gas production.
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Foreign currency risk
Foreign currency risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign currency exchange rates. Some of the Company's business transactions and commitments occur in currencies other than US dollars. A portion of the Company's oil and natural gas activities in Colombia and Argentina transact in Colombian Peso (COP$) and Argentine Peso (ARS$). In addition, the majority of the Company's financing and a portion of the administrative costs will be based in Canadian dollars, COP$, or ARS$ and paid in Canadian dollars, COP$, or ARS$. Therefore, the Company is exposed to the risk of fluctuations in foreign exchange rates between US dollars, COP$, ARS$ and Canadian dollars. As at June 30, 2020, the Company had not entered into any foreign currency derivatives to manage its exposure to currency fluctuations nor were there any foreign currency derivatives as at the previous year ended December 31, 2019.
Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in prevailing market interest rates. The Company is exposed to interest rate risk on its cash and cash equivalents and short‐ term investments that have a floating interest rate. Fluctuations of interest rates for the period ending June 30, 2020 would not have had a significant impact on cash and cash equivalents and short‐term investments. Furthermore, the Company is not currently exposed to interest rate risk on its interest‐ bearing loans given these debt instruments are all subject to fixed interest rates.
READER ADVISORIES
Forward‐Looking Statements
This MD&A may include forward‐looking statements including opinions, assumptions, estimates and management's assessment of future plans and operations, capital expenditures and the timing and funding thereof. When used in this document, the words "anticipate," "believe," "estimate," "expect," "intent," "may," "project," "plan", "should" and similar expressions are intended to be among the statements that identify forward‐looking statements. Forward‐looking statements are subject to a wide range of risks and uncertainties, and although the Company believes that the expectations represented by such forward‐looking statements are reasonable, there can be no assurance that such expectations will be realized. Any number of important factors could cause actual results to differ materially from those in the forward‐looking statements including, but not limited to, risks associated with petroleum and natural gas exploration, development, exploitation, production, marketing and transportation, the volatility of petroleum and natural gas prices, currency fluctuations, the ability to implement corporate strategies, the state of domestic capital markets, the ability to obtain financing, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, changes in petroleum and natural gas acquisition and drilling programs, delays resulting from inability to obtain required regulatory approvals, delays resulting from inability to obtain drilling rigs and other services, labour supply risks, environmental risks, competition from other producers, imprecision of reserve estimates, changes in general economic conditions, ability to execute farm‐in and farm‐out opportunities, and other factors, all of which are more fully described from time to time in the reports and filings made by the Company with securities regulatory authorities.
Management believes that the expectations reflected in the forward‐looking information are reasonable, but no assurance can be given that these expectations will prove to be correct. Such forward‐looking
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information included in this MD&A should not be unduly relied upon as the plans, assumptions, intentions or expectations upon which it is based may not occur. Actual results or events may vary from the forward‐ looking information.
In particular, this MD&A may contain forward‐looking information pertaining to the following:
- the resource potential of the Company's assets,
- the Company's strategy and opportunities,
- performance characteristics of the Company's oil properties and estimated capital commitments and probability of success,
- crude oil production and recovery estimates and targets,
- the existence and size of the oil reserves and resources,
- the Company's drilling plans,
- capital expenditure programs and estimates, including the timing of activity,
- the Company's plans for, and results of, exploration and development, activities, and factors that may affect such activities,
- projections of market prices and costs,
- the supply and demand for oil,
- expectations regarding the ability to raise equity and debt capital on acceptable terms and to add continually to reserves through acquisitions and development, including the ability to negotiate and complete the agreements contemplated in this MD&A,
- the timing for receipt of regulatory approvals, and
- treatment of the Company under governmental regulatory regimes and tax laws.
The purpose of providing any financial outlook in this MD&A is to illustrate how the business of the Company might develop without the benefit of specific historical financial information. Readers are cautioned that this information may not be appropriate for other purposes.
The forward‐looking information herein is based on certain assumptions and analysis by the management of the Company in light of its experience and perception of historical trends, current conditions and expected future developments and other factors that it believes are appropriate and reasonable under the circumstances. The forward‐looking information herein is based on a number of assumptions, including but not limited to:
- the availability on acceptable terms of funds for capital expenditures,
- the availability in a cost‐efficient manner of equipment and qualified personnel when required,
- continuing favourable relations with Latin American governmental agencies,
- continuing strong demand for oil,
- the stability of the regulatory framework governing royalties, taxes and environmental matters in Colombia and any other jurisdiction in which the Company may conduct its business in the future,
- the Company's future ability to market production of oil successfully to customers,
- the Company's future production levels and oil prices,
- the applicability of technologies for recovery and production of the Company's oil reserves,
- the existence and recoverability of any oil reserves,
- geological and engineering estimates in respect of the Company's resources and reserves,
- the geography of the areas in which the Company is exploring, and
- the impact of increasing competition on the Company.
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The actual results, performance and achievements of the Company could differ materially from those anticipated in these forward‐looking statements as a result of the risks and uncertainties set forth elsewhere in the MD&A and the following risks and uncertainties:
- global financial conditions,
- general economic, market and business conditions,
- volatility in market prices for oil and natural gas, the stock market, foreign exchange and interest rates,
- risks inherent in oil and gas operations, exploration, development and production,
- risks inherent in the Company's international operations, including security, political, sovereignty and legal risks in Colombia and Argentina,
- the failure by counterparties to make payments or perform their operational or other obligations to the Company in compliance with the terms of contractual arrangements between the Company and such counterparties,
- risks related to the timing of completion of the Company's projects and plans,
- uncertainties associated with estimating oil and natural gas reserves and resources,
- competition for, among other things, capital, acquisitions of resources, undeveloped lands and skilled personnel,
- the Company's ability to hold existing leases through drilling or lease extensions or otherwise,
- incorrect assessments of the value of acquisitions or title to properties,
- the failure of the Company or the holder of certain licenses or leases to meet specific requirements of such licenses or leases,
- claims made in respect of the Company's properties or assets,
- geological, technical, drilling and processing problems, including the availability of equipment and access to properties,
- environmental risks and hazards,
- failure to estimate accurately abandonment and reclamation costs,
- the inaccuracy of third parties' reviews, reports and projections,
- rising costs of labour and equipment,
- the failure to engage or retain key personnel,
- changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry, and
- the other factors discussed under "Principal Business Risks" in this MD&A.
Readers are cautioned that the foregoing lists of assumptions, risks and uncertainties are not exhaustive. The forward‐looking information contained in this MD&A is expressly qualified by this cautionary statement. The forward‐looking information speaks only as of the date of this MD&A, and the Company does not undertake any obligation to publicly update or revise any forward‐looking information except as required by applicable securities laws.
Analogous Information
Certain information in this MD&A may constitute "analogous information" as defined in National Instrument 51‐101 ‐ Standards of Disclosure for Oil and Gas Activities ("NI 51‐101"), including, but not limited to, information relating to areas, assets, wells, industry activity and/or operations that are in geographical proximity to or believed to be on‐trend with lands held by CruzSur. In particular, this document notes specific analogous oil and gas discoveries and corresponding details of said discoveries in the Chuchupa Block as well as blocks owned by Canacol Energy Ltd. and makes certain assumptions
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about the Maria Conchita Block and SN‐9 Block as a result of such analogous information and potential recovery rates as a result thereof. Such information has been obtained from public sources, government sources, regulatory agencies or other industry participants. Management of CruzSur believes the information may be relevant to help define the reservoir characteristics within lands on which CruzSur holds an interest and such information has been presented to help demonstrate the basis for CruzSur's business plans and strategies. However, management cannot confirm whether such analogous information has been prepared in accordance with NI 51‐101 and the Canadian Oil and Gas Evaluation Handbook and CruzSur is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor. CruzSur has no way of verifying the accuracy of such information. There is no certainty that the results of the analogous information or inferred thereby will be achieved by CruzSur and such information should not be construed as an estimate of future production levels or the actual characteristics and quality CruzSur's assets. Such information is also not an estimate of the reserves or resources attributable to lands held or to be held by CruzSur and there is no certainty that such information will prove to be analogous in the future. The reader is cautioned that the data relied upon by CruzSur may be in error and/or may not be analogous to such lands to be held by CruzSur.
Barrels of Oil Equivalent
Where amounts are expressed in a barrel of oil equivalent ("boe"), or barrel of oil equivalent per day ("boe/d"), natural gas volumes have been converted to barrels of oil equivalent on the basis that 6 thousand cubic feet ("mcf") is equal to one barrel of oil. Use of the term boe may be misleading, particularly if used in isolation. This boe conversion ratio is based on an energy equivalence methodology and does not represent a value equivalency. Indeed, the energy and value relationships may differ widely with market conditions. The conversion does conform to the Canadian Securities Regulators' National Instrument 51‐101 - Standards of Disclosure for Oil and Gas Activities.
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Abbreviations
$/bbl dollars per barrel
$/boe dollars per barrel of oil equivalent $/GJ dollars per gigajoule
$/mcf dollars per thousand cubic feet bbl barrel
bbl/d barrels per day bcf billion cubic feet
boe barrel of oil equivalent
boe/d barrel of oil equivalent per day GJ gigajoule
GJ/d gigajoules per day km kilometer
mcf thousand cubic feet
mcf/d thousand cubic feet per day mmbbl million barrels
mmboe million barrels of oil equivalent mmcf/d million cubic feet per day NGLs natural gas liquids
API American Petroleum Industry gravity m3 meters cubed
ppm parts per million
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Cruzsur Energy Corp. published this content on 27 August 2020 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 28 August 2020 07:37:04 UTC
