80% increase in Production and 54% increase in Revenues; Lower per barrel Operating Expense; Restructuring of certain borrowings and new short term credit facility
2019 Financial Highlights:
- Total revenues of
$150.5 million on working interest sales of 2,780,800 barrels of oil ("bbl") and an average realised sales price of$48.72 /bbl for 2019 - 54% annual increase in revenues versus 2018
- Q4 2019 revenues increased 14% versus Q3 2019
- The Corporation has received full payment in accordance with Production Sharing Contract entitlements for all oil sale deliveries into the Kurdistan Oil Export Pipeline through
September 2019 - Operating expenses of
$28.9 million ($10.41 /bbl) and an Oryx Petroleum Netback1 of$18.90 /bbl for 2019 - 17% decrease in operating expenses per barrel versus 2018
- Loss of
$59.2 million ($0.11 per common share) in 2019 versus Profit of$43.8 million in 2018 ($0.09 per common share) - Loss in 2019 primarily attributable to an impairment expense related to the Hawler license area and an impairment expense and a provision related to the Corporation's former interest in the Haute Mer B license area
- Profit in 2018 primarily attributable to an impairment reversal related to the Hawler license area
- Net cash generated by operating activities was
$28.1 million in 2019 versus net cash generated by operating activities of$8.1 million in 2018 comprised of Operating Funds Flow2 of$26.9 million and an$1.2 million decrease in non-cash working capital - Net cash used in investing activities during 2019 was
$35.1 million including payments related to drilling and facilities work in the Hawler license area, preparation for drilling in the AGC Central license area, and an increase in non-cash working capital $8.9 million of cash and cash equivalents as ofDecember 31, 2019
_____________________________
1 Oryx Petroleum Netback is a non-IFRS measure. See the table below for a definition of and other information related to the term.
2 Operating Funds Flow is a non-IFRS measure. See the table below for a definition of and other information related to the term.
2019 Operations Highlights:
- Average gross (100%) oil production of 11,700 bbl/d (working interest 7,600 bbl/d) for the year ended
December 31, 2019 versus 6,500 bbl/d (working interest 4,200 bbl/d) for the year endedDecember 31, 2018 - 80% increase in gross (100%) oil production in 2019 versus 2018; 12% increase in gross (100%) oil production in Q4 2019 versus Q3 2019
- Successful completion of four producing wells during 2019
- First successful completion of a well targeting the Cretaceous reservoir at the Demir Dagh field utilising a horizontal well design
- Gross (working interest) proved plus probable oil reserves of 103 million barrels as at
December 31, 2019 - Environmental and Geohazard Assessments related to planned drilling in the AGC Central license area initiated and largely completed
2020 Operations Update:
- Average gross (100%) oil production of 14,500 bbl/d (working interest 9,400 bbl/d) and 14,400 bbl/d (working interest 9,400 bbl/d) in January and
February 2020 , respectively - The drilling of a horizontal sidetrack of the previously drilled Banan-1 well in the portion of the Banan field east of the Great Zab river was completed in early 2020
- Data obtained during drilling indicate that the Tertiary reservoir in the eastern portion of the Banan field contains oil of similar density to oil produced from the Tertiary reservoir in the portion of the Banan field west of the Great Zab river
- Attempts to complete the well as a producer in the Cretaceous reservoir were unsuccessful
- Further drilling targeting both the Tertiary and Cretaceous reservoirs is planned in 2020
- Operations in recent weeks were successful in shutting off water production from the Banan-5 well which is producing oil from the Cretaceous reservoir in the portion of the Banan field west of the Great Zab river
- The worldwide outbreak of the COVID-19 virus, including within
Iraq , has not impacted operations. The Corporation is taking precautions to protect its employees and contractors but does not at this time expect that the virus outbreak will restrict operations - The planned drilling of an exploration well in 2020 in the AGC Central license area has been deferred. In 2019, the Corporation requested that the First Renewal Period of its Production Sharing Contract (due to end on
October 1, 2020 ) be extended as a result of ongoing negotiations betweenSenegal andGuinea Bissau in relation to the accord governing the jointly-administered area offshoreSenegal andGuinea Bissau . The Corporation is currently in discussions with the AGC regarding an amendment to its Production Sharing Contract that would implement the requested extension and expects the amendment to be finalised in the coming months.
2020 Forecasted Work Program and Capital Expenditures:
- 2020 capital expenditure forecast of
$53 million (versus$106 million budget). Forecast activities consist of: $50 million dedicated to the Hawler license area: six wells including two wells targeting the Banan Cretaceous reservoir, one well targeting the Zey Gawra Tertiary reservoir, one well targeting the Demir Dagh Cretaceous reservoir, one well targeting the Banan Tertiary reservoir, and a completion of the previously suspendedAin Al Safra-2 well; a pipeline connecting the Banan field to the Hawler production facilities at the Demir Dagh field; storage tanks at the Hawler production facilities and pads, flowlines and infrastructure modifications needed to accommodate incremental drilling and production and to reduce operating costs$3 million dedicated to the AGC Central license area including studies, technical support and license maintenance costs- The forecast reflects the deferment of planned drilling in the AGC license area and the deferment of two wells and certain facilities expenditures in the Hawler license area that were included in the budget.
Extension of AOG Loan and New Short Term Credit Facility:
- AOG has agreed to extend the maturity date of the credit facility provided to
Oryx Petroleum in 2015 fromJuly 1, 2020 toJuly 1, 2021 in consideration for the issuance of 33,149,000 warrants to purchase common shares ofOryx Petroleum .The Toronto Stock Exchange ("TSX") has reviewed the applicable transaction materials. It is anticipated that the TSX will conditionally approve the extension five business days after the issuance of this news release. - AOG has further agreed to provide the Corporation with a
$5 million short term credit facility to provide access to working capital in the event of any further delays in receiving payments for oil sales. The TSX has reviewed the applicable transaction materials. It is anticipated that the TSX will conditionally approve the short term credit facility five business days after the issuance of this news release.
Liquidity Outlook:
- The Corporation expects cash on hand as of
December 31, 2019 and cash receipts from net revenues and export sales will allow it to fund its forecasted capital expenditures and operating and administrative costs into early 2021. Additional capital is expected to be required to be able to both meet any contingent consideration obligations that become payable and to fund drilling in the AGC Central license area now planned in 2021.
CEO's Comment
Commenting today,
"2019 was a good year for
In the AGC Central license area, that has best estimate unrisked gross (working interest) prospective oil resources of 2.2 billion barrels, we continue to prepare for exploration drilling. In 2019 we initiated and now have largely completed environmental impact and geohazard assessments with regards to our drilling plans. However, the timing of exploration drilling remains uncertain as we wait for
Importantly, we completed our work in 2019 without incurring any Lost Time Injuries or having any significant releases or other adverse environmental incidents.
Our 2020 capital program is focused primarily on the Hawler license area in the
The combination of higher production and regular payments for oil sales in most of 2019 resulted in higher funds flow which together with cash on hand allowed us to fund our business in 2019 without seeking additional capital. We expect that cash on hand and cash receipts from net revenues will fund forecasted capital expenditures and operating and administrative costs into early 2021. AOG, our largest shareholder, has recently agreed to provide us with a short term credit facility to strengthen our liquidity position due to the recent delays in receiving cash payments for oil sales. Most of our capital expenditures are planned in the second half of 2020 and we are prepared to adjust our plans and consider other measures to strengthen our liquidity should recent market developments persist and should there be additional delays in cash receipts for oil sales.
We look forward to implementing our plans safely in 2020 and to higher production in the Hawler license area while continuing to prepare for an exploration drilling program in the AGC Central license area."
Selected Financial Results
Financial results are prepared in accordance with International Financial Reporting Standards ("IFRS") and the reporting currency is US dollars. References in this news release to the "Group" refer to
Three Months Ended | Year Ended | |||
($ in millions unless otherwise indicated) | 2019 | 2018 | 2019 | 2018 |
Revenue | 40.9 | 36.5 | 150.5 | 97.6 |
Working Interest Production (bbl) | 780,700 | 627,900 | 2,780,800 | 1,541,900 |
Average WI Production per day (bbl/d) | 8,500 | 6,800 | 7,600 | 4,200 |
Working Interest Oil Sales (bbl) | 777,800 | 626,700 | 2,781,000 | 1,542,300 |
Average Realised Sales Price ($/bbl) | 47.32 | 52.37 | 48.72 | 57.00 |
Operating Expense | 7.6 | 6.9 | 28.9 | 19.2 |
Field Production Costs ($/bbl)(1) | 7.44 | 8.43 | 7.96 | 9.54 |
Field Netback ($/bbl)(2) | 16.05 | 17.15 | 15.95 | 18.30 |
Operating expenses ($/bbl) | 9.72 | 11.03 | 10.41 | 12.48 |
Oryx Petroleum Netback ($/bbl)(3) | 19.00 | 20.36 | 18.90 | 21.68 |
Profit (Loss) | (81.3) | 56.8 | (59.2) | 43.8 |
Basic and Diluted Earnings (Loss) per Share ($/sh) | (0.15) | 0.11 | (0.11) | 0.09 |
Operating Funds Flow(4) | (3.9) | 9.1 | 26.9 | 23.2 |
(1.6) | 7.4 | 28.1 | 8.1 | |
(10.0) | (11.3) | (35.1) | (32.8) | |
Capital Expenditure | 13.4 | 9.0 | 38.2 | 36.4 |
Cash and Cash Equivalents | 8.9 | 14.4 | 8.9 | 14.4 |
Total Assets | 768.3 | 813.0 | 768.3 | 813.0 |
Total Liabilities | 209.2 | 203.4 | 209.2 | 203.4 |
Total Equity | 559.1 | 609.5 | 559.1 | 609.5 |
(1) | Field production costs represent |
(2) | Field Netback is a non-IFRS measure that represents the Group's working interest share of oil sales net of the Group's working interest share of royalties, the Group's working interest share of operating expenses and the Group's working interest share of taxes. Management believes that Field Netback is a useful supplemental measure to analyse operating performance and provides an indication of the results generated by the Group's principal business activities prior to the consideration of production sharing contract and joint operating agreement financing characteristics, and other income and expenses. Field Netback does not have a standard meaning under IFRS and may not be comparable to similar measures used by other companies. |
(3) | Oryx Petroleum Netback is a non-IFRS measure that represents Field Netback adjusted to reflect the impact of carried costs incurred and recovered through the sale of cost oil during the reporting period. Management believes that Oryx Petroleum Netback is a useful supplemental measure to analyse the net cash impact of the Group's principal business activities prior to the consideration of other income and expenses. Oryx Petroleum Netback does not have a standard meaning under IFRS and may not be comparable to similar measures used by other companies. |
(4) | Operating Funds Flow is a non-IFRS measure that represents cash generated from operating activities before changes in non-cash assets and liabilities. The term Operating Funds Flow should not be considered an alternative to or more meaningful than "cash flow from operating activities" as determined in accordance with IFRS. Management considers Operating Funds Flow to be a key measure as it demonstrates the Group's ability to generate the cash flow necessary to fund future growth through capital investment. Operating Funds Flow does not have any standardised meaning prescribed by IFRS and may not be comparable to similar measures used by other companies. |
- Revenue increased to
$150.5 million in 2019 versus$97.6 million in 2018 due to a 80% increase in oil sales volumes partially offset by a 15% decrease in average oil sales prices. Gross (working interest) production and sales of oil in 2019 were 2,780,800 barrels and 2,781,000 barrels, respectively, versus 1,541,900 barrels and 1,542,300 barrels, respectively, for 2018. The average oil sales price realised in 2019 was$48.72 per barrel versus$57.00 for 2018. In addition to oil sales, revenue includes the recovery of carried costs. - Operating expenses increased 50% to
$28.9 million in 2019 versus$19.2 million in 2018 due primarily to the costs associated with a greater number of wells and a full year of operations at the Banan field versus a partial year of operations at the Banan field during 2018. Operating expenses on a per barrel basis declined 17% in 2019 versus 2018 as increased volumes more than offset the increase in expenses.Oryx Petroleum currently carries theKurdistan Regional Government's share of production costs. The Oryx Petroleum Netback achieved in 2019 of$18.90 per barrel reflects the Field Netback plus adjustments for carried costs. - General and administrative expenses increased modestly to
$12.0 million in 2019 versus$11.9 million in 2018 due primarily to an increase in personnel costs and professional costs. - Loss for the year ended
December 31, 2019 was$59.2 million compared to a$43.8 million Profit in 2018. The lower result is primarily attributable to i) a$54.4 million impairment expense in 2019 compared to a$54.1 million impairment reversal in 2018, both on the Hawler license area, ii) an impairment of assets held for disposal and a provision for an adverse arbitration judgment and award related to the Corporation's former interest in Haute Mer B license area, iii) a$9.7 million increase in operating costs, and iv) an$8.0 million increase in the depletion charge during 2019 resulting from higher production during 2019. These negative variances were partially offset by i) an increase in net revenue of$29.6 million during 2019 in comparison with 2018, and ii)$15.2 million in income related to the change in fair value of contingent consideration during 2019 versus a$2.7 million expense during 2018. - Operating Funds Flow was
$26.9 million for 2019 compared to$23.2 million in 2018. The increase in Operating Funds Flow is primarily due to higher revenues and netback in 2019 versus 2018. Operating Funds Flow in 2019 was negatively impacted by a$15.7 million provision resulting from the arbitration and judgment related to the Corporation's former interest in the Haute Mer B license area. - Net cash generated by operating activities was
$28.1 million in 2019 as compared to net cash generated by operating activities of$8.1 million in 2018. The increase reflects higher revenues and netback and a$1.2 million decrease in non-cash working capital in 2019 versus a$15.1 million increase in non-cash working capital in 2018. - Net cash used in investing activities increased to
$35.1 million in 2019 as compared to$32.8 million in 2018 reflecting increased cash outflows for capital investment during 2019. - Capital expenditures in 2019 totalled
$38.2 million as compared to$36.4 million in 2018. In 2019,$36.4 million of capital expenditures were incurred in the Hawler license area primarily on drilling activities at the Banan and Demir Dagh fields. 2019 capital expenditures also included$1.8 million related to studies, drilling preparations and license maintenance costs in the AGC Central license area. - Cash and cash equivalents decreased to
$8.9 million atDecember 31, 2019 from$14.4 million atDecember 31, 2018 reflecting capital expenditures and movements in non-cash working capital partially offset by positive Operating Funds Flow. - In
March 2015 ,Oryx Petroleum entered into a Loan Agreement with AOG whereby AOG committed to provide a$100 million unsecured credit facility toOryx Petroleum (the "AOG Credit Facility"). As atDecember 31, 2019 , the balance owing under the AOG Credit Facility totalled$80.1 million , including$4.0 million in accrued interest which was paid to AOG in cash inJanuary 2019 . - The Corporation is obligated to make further payments to the vendor of the Hawler license area contingent upon declaration of a second commercial discovery in the Hawler license area.
- Contingent upon declaration of a second commercial discovery in the Hawler license area, a lump-sum payment of
$66.0 million plus accrued interest is payable. The estimated fair value of the contingent consideration as atDecember 31, 2019 was$56.0 million . The estimated fair value of the contingent consideration was revised downwards by$1.9 million versus Q3 2019 utilising the methodology adopted in Q3 2019 that incorporates weighted probabilities of potential outcomes including an outcome where there is no second commercial declaration of discovery. As atDecember 31, 2019 , the total balance of principal and accrued interest potentially owed under the contingent consideration obligation was$75.7 million . - An amendment to the terms of the original share purchase agreement negotiated with the vendor in the fourth quarter of 2018 to schedule the obligation as a series of annual payments in the event the contingent obligation was triggered expired on
September 30, 2019 . - In the event the contingent obligation is triggered, the Corporation expects to seek to secure a payment schedule from the vendor which, consistent with prior amendments, allows the Corporation to repay the obligation over several years.
- As at
March 11, 2020 , 552,481,662 common shares are outstanding. As atMarch 11, 2020 there are: i) unvested Long Term Incentive Plan awards which are expected to result in the issuance of up to an additional 28,862,475 common shares upon vesting, and ii) 6,132,804 warrants outstanding issued in connection with an amendment to the AOG Loan Agreement executed inDecember 2018 . The Corporation expects to issue 33,149,000 warrants in connection with the amendment to the AOG Loan Agreement datedMarch 11, 2020 .
2020 Capital Expenditure Forecast
Location | License/Field/Activity | 2020 Budget | 2020 Forecast |
$ millions | $ millions | ||
Hawler | |||
Zey Gawra-Drilling | 5 | 4 | |
Demir Dagh-Drilling | 14 | 8 | |
2 | 2 | ||
Banan-Drilling | 14 | 14 | |
Facilities | 26 | 19 | |
Other(1) | 3 | 3 | |
Total Hawler | 63 | 50 | |
AGC Central—Drilling & Prep | 40 | - | |
AGC Central—Other | 3 | 3 | |
Capex Total(2) | 106 | 53 |
Note: | |
(1) | Other is comprised primarily of license maintenance costs. |
(2) | Totals may not add-up due to rounding. |
Demir Dagh drilling -- consists of one new horizontal well targeting the Cretaceous reservoir expected to be drilled in the second half of 2020. One previously planned well targeting the Cretaceous reservoir has been deferred.
Zey Gawra drilling -- consists of a new well targeting the Tertiary reservoir. This new well has replaced the planned sidetrack of the previously drilled Zab-1 well. The drilling of the well is planned in the first half of 2020. The sidetrack of the previously drilled Zey Gawra-2 well targeting the Cretaceous reservoir has been deferred.
Banan drilling -- consists of two wells in the eastern portion of the Banan field : the workover of the Banan-1 well targeting the Cretaceous reservoir and one new well targeting the Tertiary reservoir; and one well in the western portion of the Banan field targeting the Cretaceous reservoir. The workover of the Banan-1 well was completed in early 2020 and the other two wells are planned for the second half of 2020.
Facilities -- Demir Dagh facilities expenditures comprised of infrastructure works including the construction of additional storage tanks, replacement of generators and construction of a solar power station. Zey Gawra facilities expenditures comprised of studies and minor infrastructure works including flowlines for new wells. Banan facilities expenditures comprised of studies and infrastructure needed to accommodate drilling plans and additional production, as well as a pipeline between the Banan field and the Hawler processing facilities located at the Demir Dagh field. The construction of the pipeline is expected in the second half of 2020 and is expected to be in service in early 2021. The planned construction of processing facilities at the Banan field has been deferred. The construction of the pipeline is contingent on production performance from the Banan wells.
AGC Central License Area
Consists of studies, technical support and license maintenance costs. The drilling of one exploration well in 2020 has been deferred.
Related Party Transactions
Loan Amendment
The agreement dated
As consideration for entering the Loan Amendment,
Pursuant to section 501(c) of the TSX Company Manual, shareholder approval is required for the Loan Amendment as (i) the Corporation is a non-exempt issuer, (ii) the AOG Credit Facility was not approved by shareholders in 2015, and (iii) the value of the forecast consideration to AOG under the original AOG Credit Facility (i.e.,
The Loan Amendment is subject to TSX approval. It is anticipated that the TSX will conditionally approve the Loan Amendment five business days after the issuance of this news release. A copy of the Loan Amendment has been filed by
Short Term Credit Facility
On
Any balance drawn under the Short Term Credit Facility and accrued interest and commitment fees will be repayable to the lender in cash on the maturity date,
Pursuant to section 501(c) of the TSX Company Manual, the Short Term Credit Facility requires acceptance by the TSX. Further, shareholder approval is required for the Short Term Credit Facility as (i) the Corporation is a non-exempt issuer, and (ii) the value of the forecast consideration to AOG under the Short Term Credit Facility (i.e.,
The Short Term Credit Facility is subject to TSX approval. It is anticipated that the TSX will conditionally approve the Short Term Credit Facility five business days after the issuance of this news release. A copy of the Short Term Credit Facility has been filed by
Arbitration Regarding the Haute Mer B License Area
On
Regulatory Filings
This announcement coincides with the filing with the Canadian securities regulatory authorities of
ABOUT
Reader Advisory Regarding Forward-Looking Information
Certain statements in this news release constitute "forward-looking information", including statements related to forecast work program and capital expenditure for 2020, drilling and well workover plans, development plans and schedules and chance of success, future drilling of wells and the reservoirs to be targeted, future facilities work, ultimate recoverability of current and long-term assets, plans to prepare for drilling in the AGC Central license area, possible commerciality of our projects, future expenditures and sources of financing for such expenditures, expectations that cash on hand as of
Although
Reader Advisory Regarding Certain Figures
Unless provided otherwise, all production and capacity figures and volumes cited in this news release are gross (100%) values, indicating that figures (i) have not been adjusted for deductions specified in the production sharing contract applicable to the Hawler license area, and (ii) are attributed to the license area as a whole and do not represent
Reserves Advisory
Proved oil reserves are those reserves which are most certain to be recovered. There is at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved oil reserves. Probable oil reserves are those additional reserves that are less certain to be recovered than proved oil reserves. There is at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable oil reserves. Volumes are based on commercially recoverable volumes within the life of the production sharing contract.
Contingent oil resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. Contingent oil resources entail additional commercial risk than reserves. There is no certainty that it will be commercially viable to produce any portion of the contingent oil resources. Moreover, the volumes of contingent oil resources reported herein are sensitive to economic assumptions, including capital and operating costs and commodity pricing.
Prospective oil resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective oil resources have both a chance of discovery and a chance of development. Prospective oil resources entail more commercial and exploration risks than those relating to oil reserves and contingent resources. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources.
See the Material Change Report filed by the Corporation on
SOURCE
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