Bengal Energy Announces Fourth Quarter and Fiscal 2020 Year End Results
Calgary, Alberta--(Newsfile Corp. - June 25, 2020) - Bengal Energy Ltd. (TSX: BNG) ("Bengal" or the "Company") today announces its financial and operating results for the fourth quarter and the fiscal year ended March 31, 2020.
FISCAL YEAR END & FOURTH QUARTER 2020 HIGHLIGHTS:
The following is an overview of the financial and operational results during the three and twelve month periods ended March 31, 2020:
Sales Revenue - Crude oil sales revenue was $1.1 million in the fourth quarter of fiscal 2020, which is 59% lower than the $2.7 million recorded in Q4 fiscal 2019. Full year fiscal 2020 sales revenue was $8.1 million compared to $11.2 million for the full year fiscal 2019. The lower full year performance in fiscal 2020 compared to fiscal 2019 was due primarily to the significant decline in US Brent at the end of March 2020 due to the Saudi/Russian price war coupled with demand destruction associated with the COVID-19 pandemic which impacted both sales revenue and the value of pipeline oil.
Hedging - The Company's Credit Facility (as defined herein) requires that a minimum of 50% of oil production be hedged forward by a minimum of 12 months. During the month of March 2020, when the Company would normally place the required hedges for the following year, forward price volatility was so impacted by COVID-19 and global oil price decline due to the Saudi/Russian price war that Westpac Banking Corporation's ("Westpac") hedging group was not taking any orders on any forward contracts or options and Westpac was not requiring the Company to enter into hedges that would lock in low prices. As the hedging requirement is not a covenant, no waiver was required and the Banks acknowledgement was sufficient for the Company to be compliant. Once oil price markets are less volatile and Westpac resumes taking orders on forward contracts and options, the Company intends to place the appropriate hedges on its production. At year-end fiscal 2020, the realized gain on financial instruments was $0.5 million while an unrealized gain on financial instruments of $1.3 million was recorded. The quarter ended March 31, 2020 had hedges in place at US$63.74/bbl while the two subsequent quarters have a portion of expected production hedged at approximately US$59/bbl and US$56/bbl respectively. For the quarter ending December 31, 2020, 4,200 bbls of production, representing 50% of the expected production of 8,400 bbls in Q3 FY 2021, has been hedged at approximately US$58/bbl.
Funds generated (used in) Operations1 - Bengal had funds used in operations of $0.9 million during Q4 fiscal 2020 compared to $0.8 million of funds generated from operations in Q4 fiscal 2019. For the full year fiscal 2020, the Company generated funds from operations of $0.5 million, down from $2.2 million of funds from operations in fiscal 2019. The primary reason for the decrease in funds from operations during fiscal 2020 as compared to fiscal 2019 was the impact of lower commodity pricing in Q4 fiscal 2020.
Net loss - Bengal reported a net loss of $2.2 million for the current quarter compared to a net loss of $2.1 million in the fourth quarter of fiscal 2019. For the full year fiscal 2020, the Company reported a net loss of $2.9 million compared to fiscal 2019 net loss of $2.6 million. Despite the lower price environment in Q4 fiscal 2020, the Company was able to substantially mitigate the financial impact with a cost reduction program and strong hedging strategy.
Adjusted Net Income2 - Bengal reported an adjusted net loss of $1.1 million for the current quarter and $1.1 million for the full year fiscal 2020. Net income is adjusted for unrealized gain (loss) on financial instruments, the unrealized foreign exchange gain (loss) for the period and the non-cash impairment of non-current assets.
Production Volumes - The Company's share of total production in the current quarter was 23,117 bbls of light crude oil, which is a 9% decline from the 25,303 bbls produced in the fourth quarter of fiscal 2019. The current quarter production averaged 254 bbls/day compared to 281 bbls/day produced in the fourth quarter of fiscal 2019. Full year fiscal 2020 saw total production of 102,230 compared to 108,731 for full year fiscal 2019. The full year fiscal 2020 production per day averaged 279 bbls compared to 298 bbls/day for the full year fiscal 2019. Normal production declines and lower than expected results from the 2019 drilling campaign are the reasons for the reduction in production year over year.
Capital Expenditures - Bengal commenced its five well development drilling program in the fourth quarter of fiscal 2019. The drilling program was completed at the end of Q2 FY 2020. The remaining capital expenditure required for this program of $2.0 million was incurred during fiscal 2020. The waterflood pilot, originally planned for Q3 FY 2020 and delayed due to engineering and equipment issues, is now expected to commence in Q2 fiscal 2021. Due to COVID-19, the 2020 drilling campaign has been postponed until 2021. There are no other capital expenditures expected during fiscal 2021. Subsequent to year end fiscal 2020, the Company negotiated a reduction in the commitment liability for Authority to Prospect ("ATP") 934 from AUS$12.3MM to AUS$1.2MM by relinquishing a portion of ATP 934 block.
On May 29, 2019, the Company and Westpac entered into an amendment to its reserved based revolving credit facility (the "Credit Facility") that had principal payments deferred from February 15, 2020 to April 1, 2020. All previous terms under the November 19, 2018 amendment have transferred directly to the May 29, 2019 amendment. The Credit Facility requires the Company to make a single payment of the outstanding amount owing on the Credit Facility. The interest rate under the Credit Facility remained unchanged at US LIBOR plus 3.75%.
On November 5, 2019, the Company and Westpac agreed to further delay the maturity date of the Credit Facility to October 31, 2020. All previous terms and conditions remain the same except for the interest rate which moved from 3.75% to 3.95%.
Management continues to discuss with the lender the opportunity to lengthen the term of the current facility particularly in light of the recent acquisition which has the potential to both increase reserves and improve cash flow. There would be an adverse impact on the Company's liquidity and its ability to continue as a going concern should it be unsuccessful in negotiating an amendment and deferral of principal payments to the Credit Facility.
The Credit Facility's reserve-based covenants include a debt service coverage ratio (cash available for debt payments divided by mandatory debt repayments) as well as a loan life coverage ratio (net present value of future cash available for debt service divided by the available facility). These covenants impact the Company's available facility limit, and therefore the ability to secure its debt as a percentage of reserve forecasts and are evaluated at each calculation date. These covenants are calculated using inputs as prescribed by Westpac, and a default event triggered by a breach of covenants may result in a full redemption of all outstanding borrowings under the terms of the Credit Facility. The Company was not in compliance with its debt service coverage ratio covenant at March 31, 2020. Subsequent to March 31, 2020, the Company received a waiver from its lender in respect of the March 31, 2020 covenant breach.
Table 1: Operating Summary
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(1) Operating netback is a non-IFRS measure and includes realized gain (loss) on financial instruments. Operating netback per bbl is calculated by dividing revenue (including realized gain (loss) on financial instruments) less royalties and operating costs by the total production of the Company measured in bbls. A reconciliation of the measures can be found on page 8 of the Company's management's discussion and analysis for the Q4 and fiscal year ended March 31, 2020.
(2) Funds from (used in) operations is a non-IFRS measure which is calculated by adding back all non-cash expense deductions to the net loss for the quarter and year. Funds from (used in) operations per share is a non-IFRS measure calculated as calculated by dividing funds from (used in) operations by weighted average basic and diluted shares outstanding for the periods disclosed. A reconciliation of the measures can be found in the table on page 21 of the Company's management's discussion and analysis for the Q4 and fiscal year ended March 31, 2020.
(3) Adjusted net income (loss) and adjusted net income (loss) per share are non-IFRS measures. The comparable IFRS measure is net income (loss). A reconciliation of the two measures can be found in the table on page 21 of the Company's management's discussion and analysis for the Q4 and fiscal year ended March 31, 2020.
(4) The above non-IFRS measures do not have any standardized meaning under GAAP (as that term is defined in National Instrument 52-107 Acceptable Accounting Principles and Auditing Standards) and therefore may not be comparable to similar measures presented by other issuers.
Bengal has filed its consolidated financial statements and management's discussion and analysis for the fourth fiscal quarter of 2020 and year ended March 31, 2020 with the Canadian securities regulators. The documents are available on SEDAR at www.sedar.com or by visiting Bengal's website at www.bengalenergy.ca.
AUSTRALIA - Cooper Basin, Queensland
Significant Economic Developments
In March 2020, the World Health Organization declared a global pandemic related to COVID-19. In addition, global commodity prices have declined significantly due to disputes between major oil producing countries combined with the negative impact to oil demand from the COVID-19 pandemic. Governments worldwide, including those in Canada and Australia, 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 slowdown. 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.
The current challenging economic climate may have significant adverse impacts on the Company, including material declines in revenue and cash flows, and related impacts to working capital levels and/or debt balances, which may also have a direct impact on the Company's operating results and financial position. These and other factors may adversely affect the Company's liquidity and the Company's ability to generate income and cash flows to meet the Company's current and future obligations. The situation is dynamic and the ultimate duration and magnitude of the impact on the economy and the financial effect on the Company is not known at this time. Estimates and judgements made by management in the preparation of the financial statements are increasingly difficult and subject to a higher degree of measurement uncertainty during this volatile period.
Bengal's producing and non-producing assets are situated in Australia's Cooper Basin, a region featuring large accumulations of very light and high quality crude oil and natural gas. The Company's core Australian assets, Petroleum Lease ("PL") 303 Cuisinier, ATP 934 Barrolka, ATP 732 Tookoonooka, and four recently acquired petroleum licenses are situated within an area of the Cooper Basin that is well served with production infrastructure and take-away capacity for produced crude oil and natural gas. Still in early stages in terms of appraisal and development, Bengal believes these assets offer attractive upside potential for both oil and gas. Australia presents a stable political, fiscal and economic environment in which to operate, and a favourable royalty regime for oil and gas production.
Under the State of Queensland Regulatory process, ATPs are granted by the State generally for a period of twelve years with one third of the original grant area expiring every four years. At the end of the final term of the ATP, an application can be made to continue a portion of the permit in the form of a PCA (Potential Commercial Area). PCAs have a life span of five to fifteen years. In the case of ATP 752, with the producing Cuisinier Oil Field offsetting and oil shows in the Murta zone as well as the deeper Jurassic Birkhead zone in the Hudson 1, Koki 1 and Barta 1 wells previously drilled and abandoned and the evidence of structural continuity from the 3 D seismic control acquired over the last few years applications for PCA's 205 and 206 were made on the Barta block and approved by the Queensland regulatory authority. These applications include a commercial viability report that indicates the area is likely to be commercially viable within the applied term. This allows for extra time to commercialize the resource. Similarly application was made and approved for PCA 155 on the Wompi block and approved. These PCA's remain a part of the ATP until expiry. If a discovery of oil or gas is made, an application for a petroleum lease) is made to allow for production. PLs are granted for up to a thirty-year term. Bengal has two PLs on the former ATP 752 Barta block, PL 303 and PL 1028, in addition to three PCAs, PCA 206, 207 Barta West and PCA 155 Wompi block-Nubba/Yilgarn. Bengal also acquired four PLs adjacent to ATP 934 in Q2 FY 2020.
AUSTRALIA - Cooper Basin, Queensland
PL303 and PL 1028 Cuisinier (controlling permit ATP 752) (30.357% WI)
The Cuisinier 29 well is on production from the newly discovered DC-50 zone. After initial decline the well has stabilized at approximately 100 bbls/d of light crude (30 bbls/d net).
Planning and drilling location selection for the 2020 multi-well development and appraisal drilling campaign has been deferred due to the COVID 19 pandemic and exacerbated by current low oil prices. Timing of restarting the campaign will be re-assessed in future periods based on pricing and financial conditions at that time.
A pilot reservoir pressure maintenance scheme (water flood pilot) is planned to commence injection during Q3 of calendar 2020. The location of this pilot is in the southeast quadrant of the Cuisinier pool, with injection of water to take place at the Cuisinier 24 well. The broad nature of the Cuisinier structure combined with variable flank aquifer pressure support has resulted in pressure depletion within the central portion of the Cuisinier pool. The injection of produced formation water is anticipated to increase production in up to four offsetting wells. In addition, if expected results are achieved, the program is expected to also support and enable future water flood expansion phases currently in the initial planning stages. Apart from increased oil recovery in the offsetting wells, another major benefit is reduction in produced water treatment tariffs. These tariffs are currently incurred as produced water is exported and treated at the Cook facility. The tariff structure is a tiered volume based arrangement; the water injection scheme would allow the joint venture to reduce the overall operating cost for Cuisinier oil.
PCA 155 Nubba/Yilgarn, (controlling permit ATP 752, Wompi Block) (38.08% WI)
The Company and joint venture partners are planning to conduct an extended production test on the Nubba gas discovery well. Initially planned for Q4 calendar 2019, the project is now delayed until there is certainty over a tie in point that can be accessed at a reasonable connection cost. Plans to tie in the well are subject to commercial flow rates and gas reserves being achieved, but otherwise not expected until 2022.
ATP 934 Barrolka (100% WI)
ATP 934 is the Company's 100% owned natural gas exploration block. In order to mitigate both financial and development risk, Bengal has done extensive state-of-the-art geophysical work that has not been widely applied in Australia and which gives a higher degree of confidence in the block and focuses on the most likely prospects.
Discussions are ongoing with a third party who have an interest in farming-in on a portion of this block, supporting the next phase of exploration and thereby further de-risking the natural gas potential of the permit. Management believes this will progress to a firm agreement imminently.
PL 114 Wareena, PL 157 Ghina, PL 188 Ramses, PL 411 Karnak, PPL 138 pipeline (100% WI)
As announced in the Bengal press release of September 12, 2019, the Company has acquired a 100% working interest in four PLs and a natural gas pipeline connected to transportation infrastructure into the Eastern Australia Gas Market. These non-producing PLs are highly compatible with and in close proximity to ATP 934. The Company obtained ownership of the respective PLs in Q2 FY 2020 subject to applicable regulatory approvals. Bengal continues to integrate subsurface data from the PLs to enhance the Company's understanding of ATP 934 and to finalize the selection of exploration and appraisal drilling locations and completion programs on selected wells.
Included in this program is an oil-zone completion in a cased well, which recovered 588 bbls/d of light crude oil, based on a 105-minute drill stem test period when it was drilled in 2007. Upon completion of a successful test, this well is expected to be immediately equipped for production and the oil sold into the regional market. The Company is in discussions with potential industry and financial partners to fund this activity.
The 100% ownership of these assets presents an appraisal and development opportunity that will be operated by the Company and is seen to be not only complementary to our proven producing, non-operated Cuisinier asset, but also as a key stepping stone for Bengal's natural gas platform with immediate market access to an existing pipeline upon which future exploration growth through ATP 934 can be undertaken.
ATP 732 Tookoonooka (100% WI)
In June 2019, the Company applied for an amendment to the Later Work Program (LWP) for the third term of ATP 732 permit, On October 22, 2019, the Company received approval from the Queensland regulatory authority for an amended LWP for the third, four-year term commencing April 1, 2019 to March 31, 2023. The approved LWP was revised to minimum activities of reprocessing seismic and inversion work with an estimated cost of $50K and geological and geophysical investigation at an estimated cost of $50K during the four-year term.
During the quarter, the Company engaged in early stage, confidential and non-binding discussions with a number of third parties respecting potential business development opportunities, including possible business combination transactions expected to assist in reducing combined costs, increasing scale and advancing external financing options. Following the period, such early stage discussions have continued, however unfavourable and volatile market conditions have posed a material challenge to advancing such discussions. The Company cautions that all discussions are preliminary and non-binding and there are no assurances that such discussions will advance or that any transaction will be pursued or ultimately be undertaken.
Subsequent to the fiscal year ended on March 31, 2020, on April 24, 2020, the Company received regulatory approval for the special amendment of the initial work program on ATP 934 which reduces the total commitment from $12.3 million to $1.2 million. The Company has no further expenditure commitments on the permit before February 28, 2021 when the permit is up for renewal. As a condition of the approval, the Company agreed to relinquish an additional 17% of the permit in addition to the 33% mandatory relinquishment for a total of 50% (240 sub-blocks) of the acreage at the end of the first term on the permit. The acreage subject to the 50% relinquishment was determined by Bengal and consisted of the least prospective land from a technical perspective and with the most challenging access conditions under the terms of the existing Environmental Authority granted by the regulator. At March 31, 2020, ATP 934 was evaluated for any impairment triggers according to International Accounting Standards (IAS) 36 and no impairment triggers were uncovered.
Bengal Energy Ltd. is an international junior oil and gas exploration and production company with assets in Australia. The Company is committed to growing shareholder value through international exploration, production and acquisitions. Bengal's common shares trade on the TSX under the symbol "BNG". Additional information is available at www.bengalenergy.ca.
This news release contains certain forward-looking statements or information ("forward-looking statements") as defined by applicable securities laws that involve substantial known and unknown risks and uncertainties, many of which are beyond Bengal's control. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. The use of any of the words "plan", "expect", "future", "prospective", "project", "intend", "believe", "should", "would," "anticipate", "estimate", or other similar words or statements that certain events "may" or "will" occur are intended to identify forward-looking statements. The projections, estimates and beliefs contained in such forward-looking statements are based on management's estimates, opinions, and assumptions at the time the statements were made, including assumptions relating to: the impact of economic conditions in North America and Australia and globally; industry conditions; changes in laws and regulations including, without limitation, the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; increased competition; the availability of qualified operating or management personnel; fluctuations in commodity prices, foreign exchange or interest rates; stock market volatility and fluctuations in market valuations of companies with respect to announced transactions and the final valuations thereof; results of exploration and testing activities; and the ability to obtain required approvals and extensions from regulatory authorities. We believe the expectations reflected in those forward-looking statements are reasonable but, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Bengal will derive from them. As such, undue reliance should not be placed on forward-looking statements.
Forward-looking statements contained herein include, but are not limited to, statements regarding:
- Oil and natural gas production levels;
- Pipeline oil volume, sales and price estimates;
- Bengal's drilling program and waterflood pilot;
- The expected timing of the pilot reservoir maintenance scheme at the Cuisinier 24 well and the anticipated production increases resulting from the injection of produced formation water and future water flood expansion phases;
- The planned extended production tests on the Nubba gas discovery well and expected timing of tying in the well;
- The expectation of placing the appropriate hedges on the Company's production;
- Expectations that a firm agreement will be executed with a third party with an interest in farming-in on a portion of the ATP 934 block;
- The expectation of no other capital expenditures during fiscal 2021; and
- the expected timing of restarting the 2020 multi-well drilling on PL 303;
The forward-looking statements contained herein are subject to numerous known and unknown risks and uncertainties that may cause Bengal's actual financial results, performance or achievement in future periods to differ materially from those expressed in, or implied by, these forward-looking statements, including but not limited to, risks associated with: the failure to obtain required regulatory approvals or extensions; the failure to satisfy the conditions under farm-in and joint venture agreements; the failure to secure required equipment and personnel; changes in general global economic conditions including, without limitations, the economic conditions in North America and Australia; increased competition; the availability of qualified operating or management personnel; fluctuations in commodity prices, foreign exchange or interest rates; changes in laws and regulations including, without limitation, the adoption of new environmental and tax laws and regulations and changes in how they are interpreted and enforced; the results of exploration and development drilling and related activities; the ability to access sufficient capital from internal and external sources; and stock market volatility. Readers are encouraged to review the material risks discussed in Bengal's annual information form for the year ended March 31, 2019 under the heading "Risk Factors" and in Bengal's management's discussion and analysis for the Q4 and fiscal year ended March 31,2020 under the heading "Risk Factors". The Company cautions that the foregoing list of assumptions, risks and uncertainties is not exhaustive. The forward-looking statements contained in this news release speak only as of the date hereof and Bengal does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be require pursuant to applicable securities laws.
The following terms used in this news release have the meanings set forth below:
bbl - barrel
bbls - barrels
bbls/d -barrels per day
$/bbl - dollars per barrel
FY - fiscal year
Q1 - three months ended June 30
Q2- three months ended September 30
Q3 - three months ended December 31
Q4 - three months ended March 31
WI - working interest
YTD - year to date
Within this news release references are made to terms commonly used in the oil and gas industry. Funds from (used in) operations, funds from (used in) operations per share, operating netback, netback per bbl, adjusted net income (loss) and adjusted net income (loss) per share do not have any standardized meaning under IFRS and previous GAAP and are referred to as non-IFRS measures. Funds from (used in) operations per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of net income (loss) per share. Operating netback includes realized losses on financial instruments. Netback per bbl is calculated by dividing revenue (including realized loss on financial instruments) less royalties, operating expenses by the total production of the Company measured in bbl. Adjusted net income (loss) and adjusted net income (loss) per share are calculated based on Net income (loss) plus unrealized loss (gain) on financial instruments less unrealized foreign exchange loss (gain) and non-cash impairment of non-current assets. The Company's calculation of the non-IFRS measures included herein may differ from the calculation of similar measures by other issuers. Therefore, the Company's non-IFRS measures may not be comparable to other similar measures used by other issuers. Funds from operations is not intended to represent operating profit for the period nor should it be viewed as an alternative to operating profit, net income, cash flow from operations or other measures of financial performance calculated in accordance with IFRS. Non-IFRS measures should only be used in conjunction with the Company's annual audited and interim financial statements. A reconciliation of these measures can be found in the tables on pages 8 and 21 of Bengal's management's discussion and analysis for the Q4 and fiscal year ended March 31, 2020.
Disclosure of Oil and Gas Information
This document discloses unbooked drilling locations. Unbooked locations are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors.
FOR FURTHER INFORMATION PLEASE CONTACT:
1 See "Non-IFRS Measurements" on page 20 of this MD&A
2 See "Non-IFRS Measurements" on page 20 of this MD&A
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