Otto Energy : H1 FY21 Results and Half Year Report

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RESULTS

H1 FY21 HIGHLIGHTS

Otto Energy Limited (ASX:OEL) (Otto or the Company) is pleased to provide its financial results for the half year ended 31 December 2020.

STRATEGIC DELIVERY

• ▪ Development and release of updated Otto strategic plan at Annual General Meeting in November 2020; built upon three pillars:

  • o Pillar 1 - Base asset delivery excellence

  • o Pillar 2 - Organic growth within existing base

  • o Pillar 3 - Inorganic growth via opportunity capture to enhance value

• ▪ Intensive and ongoing implementation of organisation-wide cost reduction and efficiency drive.

• ▪ Successful sale of Borealis Alaska LLC subsidiary to Pantheon Resources Plc for 14.27 million Pantheon shares (LSE:PANR) on 20 January 2021.

FINANCIAL DELIVERY

EARNINGS

• ▪ Production increased by 35% to 3,068 boe/d at 55% liquids (H1 FY20: 2,268 boe/d at 71% liquids), driven by Green #2 gas well commencing production in February 2020.

• ▪ Total WI revenue reduced by 17% to US$14.4 million (H1 FY20: US$17.5 million), predominantly attributable to lower market oil prices.

• ▪ Net operating revenue decreased 20% to US$11.2 million (H1 FY20: US$14.0 million).

• ▪ Strong operating cost-out performance in challenging market environment

  • o 68% reduction in field lifting costs per barrel (operating expenses, business development, exploration costs), compared to prior period.

  • o 38% reduction in non-field lifting costs per barrel (G&A costs), compared to prior period, across multiple areas including administrative, licensing, legal and advisory/consultant costs.

• ▪ Adjusted EBITDAX reduced by 50% to US$4.2 million (H1 FY20: US$8.4 million), excluding non-cash impairment charges.

• ▪ Underlying EBITDA increased by 718% to US$2.5 million (H1 FY20: US$0.3 million), as a result of less exploration expenditures.

• ▪ Net loss before taxes (excluding impairment) of US$1.4 million (H1 FY20: US$2.7 million loss).

• ▪ Net loss after tax of US$14.3M (H1 FY20: US$2.7M loss), which includes US$12.9 million pre-tax impairment pertaining to GC 21.

CASHFLOW

• ▪ Net operating cashflow (pre-exploration) of US$8.3 million (H1 FY20: US$10.7 million).

• ▪ Net operating cashflow (post exploration) of US$4.6 million (H1 FY20: US$3.1 million).

• ▪ Free cashflow (operating net investing) of -US$2.3 million (H1 FY20: -US$1.1 million).

• ▪ Debt repayment of US$4.6M during the half.

LIQUIDITY

• ▪ Balance date cash of US$9.7 million.

• ▪ Balance date debt (drawn credit facility) of US$16.1M.

• ▪ On 21 January 2021, Otto announced that its credit facility had been amended to:

  • o Extend the potential drawdown of Tranche A2 (US$10M) out to 31 March 2022

  • o Establish timing for a GC 21 mitigation plan to be implemented (by 31 July 2021)

  • o Establish a minimum quarterly average production requirement of 1,900 boe/d until the GC 21 mitigation is completed (Otto net WI volume)

OPERATIONS

The below table summarizes the Company's production, WI revenue and prices received during the six months ended 31 December 2020 and 2019:

*Average oil price does not consider the effects of hedges. If including hedges, the average realized oil price would be $42.07 and $55.75 for the Half-Year ended 31 December 2020 and 2019, respectively.

Included in the H1 FY21 production figures is the "Bulleit" appraisal well located at GC 21 which commenced production from the deeper MP sands on 15 October 2020 (16.67% WI; 13.34% NRI). Initial production rates were less than what the collected rock property data and analogue reservoirs would suggest. Additional engineering analysis is underway to determine whether a well intervention and stimulation could enhance the current well deliverability, or if a recompletion in the shallower DTR-10 sands is warranted. Production was approximately 916 Boe/d as of 31 December 2020.

The Company originally estimated approximately $23.5 million to drill, complete and bring the Bulleit well to production status, as provided by the Operator. At 31 December 2020, the final cost to drill, complete and bring the Bulleit well to production status was estimated to be approximately $39.2 million. Of this amount, $34.3 million had been paid as of 31 December 2020, with another $3.8 million paid to date in Q3 FY21. The Company expects to pay the final remaining balance by the end of Q3 FY21.

Per Otto's Reserve Update as of 30 June 2020, approximately 70% of current GC 21 proven reserves are contained in the independent shallower DTR-10 sand which can be produced from the existing well bore. As a result of the cost overruns and lower than expected performance of the Bulleit well at GC 21, the Company engaged Ryder Scott Company, a qualified external petroleum engineering consultant, to revise its independent assessment of the Green Canyon 21 Field reserves. After reviewing the results of the revised reserves estimates, the Company recognised an impairment loss of $12.8 million. The revised GC 21 reserves as at 31 December 2020 are set out in the table below.

Green Canyon 21

56

8

53

17

Reserves Cautionary Statement

Oil and gas reserves and resource estimates are expressions of judgment based on knowledge, experience and industry practice. Estimates that were valid when originally calculated may alter significantly when new information or techniques become available. Additionally, by their very nature, reserve and resource estimates are imprecise and depend to some extent on interpretations, which may prove to be inaccurate. As further information becomes available through additional drilling and analysis, the estimates are likely to change. This may result in alterations to development and production plans which may, in turn, adversely impact the Company's operations. Reserves estimates and estimates of future net revenues are, by nature, forward looking statements and subject to the same risks as other forward-looking statements.

COMMENT FROM CHAIRMAN & CEO, MR. MICHAEL UTSLER

Overall, we are pleased with our results for the six months ended 31 December 2020. Our production increased 35% while our exploration and administrative costs decreased 65%. Additionally, we were able to monetize our working interest in Alaska subsequent to quarter end for meaningful proceeds which we look forward to closing in the coming months. The non-cash impairment charge of $12.9 million adversely affected our earnings, but excluding that and all other non-cash charges, our earnings for the period would have been $4.8 million.

Protecting our liquidity is also a priority for us. Consequently, the recent increase in commodity prices has allowed us to price protected approximately 80% of our forecasted PDP oil production for the remainder of 2021 with swaps at a weighted-average price of $51.34 per barrel and 75% of our forecasted PDP oil production for 2022 at a weighted-average price of $49.92 per barrel.

This release has been approved by the Company's Board of Directors

Definitions

• - "$m" means USD millions of dollars

• - "bbl" means barrel

• - "bbls" means barrels

  • - "Mboe" means thousand barrels of oil equivalent ("boe") with a boe determined using a ratio of 6,000 cubic feet of natural gas to one barrel of oil - 6:1 conversion ratio is based on an energy equivalency conversion method and does not represent value equivalency

• - "bopd" means barrels of oil per day

  • - "MMscf" means million standard cubic feet

• - "Mbbl" means thousand barrels

• - "Mscf" means 1000 standard cubic feet

  • - "MMboe" means million barrels of oil equivalent ("boe") with a boe determined using a ratio of 6,000 cubic feet of natural gas to one barrel of oil - 6:1 conversion ratio is based on an energy equivalency conversion method and does not represent value equivalency

  • - "MMbtu" means million British thermal units

• - "NGLs" means natural gas liquids

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