Condor Announces 2018 Year End Results
CALGARY, March 19, 2019 – Condor Energies Inc. (“Condor” or the “Company”) (TSX: CPI), a Canadian based oil and gas company focused on exploration and production activities in Turkey and Kazakhstan, is pleased to announce the release of its Consolidated Financial Statements for the year ended December 31, 2018, together with the related Management’s Discussion and Analysis. These documents will be made available under Condor’s profile on SEDAR at www.sedar.com and on the Condor website at www.condorenergies.ca. All financial amounts in this news release are presented in Canadian dollars, unless otherwise stated.
Achieved an average production of 1,015 boepd for the three months ended December 31, 2018 and 1,144 boepd for the year ended December 31, 2018, representing a 119% and 170% increase from the same respective periods in 2017.
Realized crude oil and natural gas sales increased to $4.3 million for the three months ended December 31, 2018 and $17.5 million for the year ended December 31, 2018 representing a 168% and 210% increase from the same respective periods in 2017.
Realized a robust operating netback1 in 2018 of $11.8 million or $29.11 per boe, representing a 271% increase from $3.2 million and a 47% increase from $19.75 per boe respectively compared to 2017.
Generated cash from operating activities of $7.5 million or $0.17 per basic share in 2018 versus cash used in operating activities of $8.2 million or $0.19 per basic share in 2017.
In Kazakhstan, three new horizontal wells were drilled at Shoba and two well workovers performed at Taskuduk.
In Turkey, one new well was drilled and two workovers were performed at Poyraz Ridge.
The Ministry of Energy of the Government of Kazakhstan (“Ministry”) did not appeal the Kazakhstan court rulings that confirmed a force majeure event had occurred related to the Company’s Zharkamys exploration contract (“Zharkamys Contract”). The Company has submitted an application to the Ministry for the 630 day extension and expects the exploration period to the Zharkamys Contract to be extended during 2019.
During 2018 the reference natural gas sales price in Turkey published by BOTAS Petroleum Pipeline Company was increased five times resulting in an overall increase of 92% in Turkish Lira (“TRL”). Despite the 28% year-on-year TRL devaluation in 2018, the gas price in CAD terms increased 50% to $9.91 per Mscf as of December 31, 2018 (3.8611 TRL/CAD) from $6.60 per Mscf as of December 31, 2017 (3.0211 TRL/CAD).
The Company recorded a net loss of $3.5 million for the three months ended December 31, 2018 (three months ended December 31, 2017: net loss of $0.1 million).
In September 2018 certain terms of the Company’s existing secured non-revolving credit facility were amended to lengthen the duration of the facility and to reduce near term principal payments.
The Company produces crude oil in Kazakhstan and natural gas and associated condensate in Turkey. Overall production for the three months ended December 31, 2018 increased 119% to 93,401 boe or an average of 1,015 boepd from 42,623 boe or an average of 464 boepd for the same three month period in 2017. Overall production for 2018 increased 170% to 417,286 boe or an average of 1,144 boepd from 154,429 boe or an average of 423 boepd for 2017. The 2018 production increases are due mainly to the commencement of natural gas production in Turkey in December of 2017 and an infill drilling and workover program in Kazakhstan to offset natural production declines.
The Company produced 43,010 barrels of oil or an average of 468 bopd and realized an operating netback1 of $27.47 per barrel in Kazakhstan for the fourth quarter of 2018 (fourth quarter of 2017: produced 33,653 barrels or an average of 366 bopd and an operating netback1 of $22.40 per barrel). The Company produced 147,788 barrels of oil or an average of 405 bopd and realized an operating netback1 of $25.14 per barrel in Kazakhstan for 2018 (2017: produced 145,459 barrels or an average of 399 bopd and an operating netback1 of $19.29 per barrel).
Three horizontal wells were drilled and completed in Kazakhstan during the second half of 2018. A 493 meter lateral section was drilled at Sh-12, a 520 meter lateral section was drilled at Sh-13 and a 502 meter lateral section was drilled at Sh-15. Sh-12 and Sh-13 are currently on production and Sh-15 is shut-in after producing predominately water. There are strong indications that the Sh-15 wellbore has been placed in a hydrocarbon saturated interval and the vast majority of the wellbore is not, nor near, a water interval. However, it is believed this well intersected a fault that is in communication with the field’s oil-water contact. It is believed that the Sh-15 completion did not isolate potential water influxes as the external casing packers have not properly expanded due to the early water production impeding this process. Oil was recently placed across the packers in an attempt to have them properly expand. As per the packer manufacturer’s recommendation, the well will remain shut in until the second quarter of 2019. Completing additional pay sections on Sh-12 are also planned during this timeframe to further increase production.
Workovers were completed in the fourth quarter of 2018 to replace downhole pumps on two Taskuduk wells. Unfortunately, the metal rods that rotate the downhole progressive cavity pumps failed in both wells after limited runtime. The Company plans to install rod pumps in both wells during the second quarter of 2019 and with rod pumps, the metal rods will move vertically in the wellbore rather than in a rotating motion and is expected to lead to better pump efficiency.
In 2018, the Company targeted increasing Kazakhstan production to over 800 bopd with the infill drilling and workover program but actual production was lower due mainly to the Sh-15 and Taskuduk pump issues. During the past 21 days, Kazakhstan production has averaged 1,007 bopd. The Company expects to exceed the 800 bopd target during the second quarter of 2019 after the Taskuduk pump changes are performed, additional pay sections are added to Sh-12 and Sh-15 is returned to service. One additional development well is planned for 2019 to further grow Kazakhstan oil production and cash flows. Engineering design is also underway to expand Shoba water injection facilities and associated water flooding capabilities.
The Company produced 49,637 boe in Turkey or an average of 540 boepd and received an operating netback1 of $36.18 per boe for the three months ended December 31, 2018 (three months ended December 31, 2017: 8,970 boe in Turkey or an average of 98 boepd and received an operating netback1 of $27.83 per boe) The Company produced 264,182 boe in Turkey or an average of 724 boepd and received an operating netback1 of $30.74 per boe in 2018 (2017: 8,970 boe in Turkey or an average of 24 boepd and received an operating netback1 of $27.83 per boe). Production to date from Poyraz Ridge has been below the rates initially forecast due to greater variability in reservoir quality and continuity than originally modelled. The production history indicates reservoir compartmentalization, which is reducing each well’s effective gas drainage radius.
The PW-6 infill well was drilled and completed in 2018 and initially had negligible pressure and flow response. The well started flowing intermittently after adding perforations and performing a fluid treatment. Data is being gathered that should provide further diagnosis and additional remediation options to increase production, including stimulation and artificial lift options for these lower permeability reservoirs.
Another sand interval was also perforated on PW-5, a 2017 exploration well that targeted the footwall compartment lying to the north of the Poyraz Ridge field. Although PW-5 did not flow when tested in 2017, the newly perforated interval has started flowing intermittently. Data is being gathered at PW-5 which may identify further remediation options for this well and field development opportunities for this region. Stimulation options are also being investigated for the other producing wells.
Subsurface characterization continued on the Yakamoz sub-thrust fold prospect which is located two kilometres north of the Poyraz Ridge field and within the Company’s Poyraz Ridge Operating License. The original 2D seismic data was reprocessed and significantly improved both data quality and imaging of the structure and stratigraphy, which has since been integrated into a revised geological model. Two separate locations have been identified up-dip from the Yakamoz 1 well, where numerous gas shows were encountered while drilling in 2017. The new locations target both the proven Miocene and Upper Eocene reservoirs, in addition to the deeper Middle to lower Eocene reservoirs, which have not yet been tested. A side-track of the Yakamoz 1 into one of these up-dip targets could be drilled in 2019, subject to available funding. A successful Yakamoz 1 well would be tied into the existing Poyraz Ridge gas plant for processing and onward sales.
Cash from operating activities increased to $7.5 million for 2018 versus cash used in operating activities of $8.2 million for 2017. Cash from operating activities before changes in non-cash working capital increased to $5.3 million 2018 versus cash used in operating activities before changes in non-cash working capital of $6.3 million for 2017.
The Company’s Zharkamys Contract was due to expire on December 14, 2016. Prior to this date, the Kazakhstan Chamber of International Commerce and subsequently the Kazakhstan Civil Court (“Civil Court”) confirmed that a force majeure event had occurred which, under Kazakhstan subsurface use law, can be the basis for the Zharkamys Contract validity period to be extended for a period of 630 days. In May 2017, the Kazakhstan Court of Appeal (“Court of Appeal”), pursuant to an appeal filed by the Ministry, ruled that the force majeure event was not recognized and reversed the decision of the Civil Court. The Company referred the case to the Kazakhstan Supreme Court (“Supreme Court”) and in November 2017 the Supreme Court ruling overturned both the Civil Court and the Court of Appeal rulings and referred the case back to the Civil Court for further review by a new panel of judges. In March 2018 the Civil Court ruling confirmed that the force majeure event had occurred. In April 2018 the Ministry appealed the Civil Court ruling and in May 2018 the Court of Appeal upheld the Civil Court ruling that the force majeure event had occurred. The Ministry did not appeal to the Supreme Court within the six months permitted by Kazakhstan law. The Company has submitted an application to the Ministry for the 630 day extension and expects the exploration period to the Zharkamys Contract to be extended during 2019.
For the year ended December 31
|Transportation and selling||(422)||(512)||(103)||(1,037)||(579)||(14)||(593)|
|Transportation and selling||(2.88)||(2.00)||(23.21)||(2.55)||(3.79)||(1.62)||(3.67)|
|Sales volume (boe)||146,454||255,993||4,437||406,884||152,895||8,696||161,591|
Operating netback is a non-GAAP measure and is a term with no standardized meaning as prescribed by GAAP and may not be comparable with similar measures presented by other issuers. See “Non-GAAP Financial Measures” in this news release. The calculation of operating netback is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook.
The Company’s ability to realize assets and discharge liabilities in the normal course of business as they become due is dependent upon the ability to fund operations and the repayment of existing borrowings by generating positive cash flows from operations, renegotiating the terms of the current borrowings, securing funding from additional debt or equity financing, disposing of assets or making other arrangements. The Company is actively pursuing various strategies to enhance its liquidity position and those matters are discussed in greater detail in the Company’s financial statements and management’s discussion and analysis for the year ended December 31, 2018.
NON-GAAP FINANCIAL MEASURES
The Company refers to “operating netback” in this news release, a term with no standardized meaning as prescribed by GAAP and which may not be comparable with similar measures presented by other issuers. This additional information should not be considered in isolation or as a substitute for measures prepared in accordance with GAAP. Operating netback is calculated as sales less royalties, production costs and transportation and selling on a dollar basis and divided by the sales volume for the period on a per barrel of oil equivalent basis. The reconciliation of this non-GAAP measure is presented in the “Financial Results” section of this news release. This non-GAAP measure is commonly used in the oil and gas industry to assist in measuring operating performance against prior periods on a comparable basis and has been presented in order to provide an additional measure to analyze the Company’s sales on a per barrel of oil equivalent basis and ability to generate funds.
Certain statements in this news release constitute forward-looking statements under applicable securities legislation. Such statements are generally identifiable by the terminology used, such as “anticipate”, “appear”, “believe”, “intend”, “expect”, “plan”, “estimate”, “budget”, “outlook”, “scheduled”, “may”, “will”, “should”, “could”, “would”, “in the process of” or other similar wording. Forward-looking information in this news release includes, but is not limited to, information concerning: the ability to realize assets and discharge liabilities in the normal course of business as they become due; the timing and ability to drill new wells and the ability of the drilled wells to become producing wells; projections and timing with respect to crude oil and natural gas production; expected markets, prices and operating netbacks for future oil and gas sales; the timing and ability to increase production and cash flow by executing the planned drilling and workover programs; the timing and ability to obtain various approvals and conduct the Company’s planned exploration and development activities; the timing and ability to access oil and gas pipelines and oil and gas domestic and export sales markets; anticipated capital expenditures and cash flows; sources and availability of financing for potential budgeting shortfalls; the timing and ability to obtain future funding on favorable terms, if at all; general business strategies and objectives; possible outcomes regarding the Zharkamys Contract including the possibility that the term may be extended or, conversely, that it may revert back to the Ministry; the timing and ability to obtain exploration contract, production contract and operating license extensions; the potential for additional contractual work commitments; the ability to meet and fund the contractual work commitments; the satisfaction of the work commitments; the results of non-fulfillment of work commitments.
By its very nature, such forward-looking information requires Condor to make assumptions that may not materialize or that may not be accurate. Forward-looking information is subject to known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such information. Such risks and uncertainties include, but are not limited to: regulatory changes; the timing of regulatory approvals; the risk that actual minimum work programs will exceed the initially estimated amounts; the results of exploration and development drilling and related activities; imprecision of reserves estimates and ultimate recovery of reserves; historical production and testing rates may not be indicative of future production rates, capabilities or ultimate recovery; the historical composition and quality of oil and gas may not be indicative of future composition and quality; general economic, market and business conditions; industry capacity; uncertainty related to marketing and transportation; competitive action by other companies; fluctuations in oil and natural gas prices; the effects of weather and climate conditions; fluctuation in interest rates and foreign currency exchange rates; the ability of suppliers to meet commitments; actions by governmental authorities, including increases in taxes; decisions or approvals of administrative tribunals and the possibility that government policies or laws may change or government approvals may be delayed or withheld; changes in environmental and other regulations; risks associated with oil and gas operations, both domestic and international; international political events; and other factors, many of which are beyond the control of Condor. Capital expenditures may be affected by cost pressures associated with new capital projects, including labor and material supply, project management, drilling rig rates and availability, and seismic costs.
These risk factors are discussed in greater detail in filings made by Condor with Canadian securities regulatory authorities including the Company’s Annual Information Form, which may be accessed through the SEDAR website (www.sedar.com).
Readers are cautioned that the foregoing list of important factors affecting forward-looking information is not exhaustive. The forward-looking information contained in this news release are made as of the date of this news release and, except as required by applicable law, Condor does not undertake any obligation to update publicly or to revise any of the included forward-looking information, whether as a result of new information, future events or otherwise. The forward-looking information contained in this news release is expressly qualified by this cautionary statement.
The following is a summary of abbreviations used in this news release:
bbl Barrels of oil
bopd Barrels of oil per day
boe Barrels of oil equivalent *
boepd Barrels of oil equivalent per day
Mscf Thousand standard cubic feet
CAD Canadian dollars
TRL Turkish lira
* Barrels of oil equivalent (“boe”) are derived by converting gas to oil in the ratio of six thousand standard cubic feet (“Mscf”) of gas to one barrel of oil based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mscf to 1 barrel, utilizing a conversion ratio at 6 Mscf to 1 barrel may be misleading as an indication of value, particularly if used in isolation.
The TSX does not accept responsibility for the adequacy or accuracy of this news release.
For further information, please contact Don Streu, President and CEO or Sandy Quilty, Vice President of Finance and CFO at 403-201-9694.