Why Dukas Is Not Being Drilled

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    The directors of CT&P...

    1 like
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    Shareholders of CT&P

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    And here I thought that bottle tops were a thing of the past.

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    Central Petroleum Limited (ASX:CTP) (“Central”) has been advised by Santos QNT Pty Ltd
    (“Santos”) as the Operator of the EP112 Joint Venture (“EP112 JV”) (Santos 70% / Central
    30%) that it requires further time to complete technical studies before a proposal can be put
    forward for EP112 JV approval in relation to further drilling at the Dukas prospect. No definitive
    guidance has been provided by Santos in relation to timing for EP112 JV approval on the
    Dukas drilling program.
    As Central announced on 16 July 2020, the intention of the EP112 JV was to make a decision
    on the Dukas drilling program by the end of 2020. Central is disappointed that no drilling
    proposal has been put forward but recognises the need for technical confidence when
    contemplating such a costly onshore well. A decision on the Dukas drilling program remains
    outstanding at this time.
    As the minority non-Operator partner in the EP112 JV, Central has little control over the timing
    for drilling at Dukas, although the minimum permit commitment requires a well to be drilled by
    mid-December 2022.
    In the interim, Central will focus its efforts on the large sub-salt and potentially shallower
    targets in EP115 in the Amadeus Basin, including the Zevon prospect, in which Central holds
    a 100% interest.
    Managing Director and CEO of Central, Leon Devaney commented, “The delay in progressing
    a drilling program at the Dukas prospect is frustrating but it is beyond Central’s control. We
    will continue to work constructively with Santos to accelerate an EP112 JV decision. In the
    meantime we will focus our exploration activities on EP115 where we think the sub-salt
    prospects could be larger and less complex and where we have better control over the pace
    of exploration.” Mr Devaney said.

    courtesy of Bell Direct
    ( DYOR )

    i do not hold this share ( but do hold MQG 'free-carried' )

    gee i am not sure which share-holders was polite enough to call the wait 'frustrating ' ( especially not at the AGM )

    even T4me gave up bagging this March last year

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    Dear Shareholders,
    I am pleased to be writing to you, for the first time as your Chair, to outline the financial performance of your company
    for the half year ending 31 December 2020, together with an overview of our activities in that time.
    Regarding our financial performance, we are reporting a net profit after tax of $2.5m for the half year, which is up
    15% on the previous half reflecting lower exploration activity, corporate cost savings and lower interest and
    depreciation charges. This performance was achieved on the back of Earnings Before Interest, Tax, Depreciation,
    Amortisation and Exploration of $12.9 million, an increase of 51% on the previous half excluding the benefit of the
    $7.7 million settlement for the transfer of a 50% interest in the Range CSG Project in the June 2020 half year. The
    strong result reflects our effective term-gas contracting strategies, cost containment initiatives and solid operations
    at Central’s gas and oil fields in the Northern Territory.
    Pleasingly, our cash balance remains strong at $38.5 million up from $25.9 million at 30 June 2020, and importantly
    our net debt of $31.2 million has decreased from $46.1 million as at 30 June 2020.
    After the market turbulence of early 2020, the last six months have seen global energy markets starting to recover,
    which has given us the confidence and opportunity to lay the groundwork for an active 2021, with a busy schedule
    of drilling and growth activities planned.
    Rising spot gas prices on the east coast have seen increasing demand from our as-available customers throughout
    the period and sales volumes overall were steady compared with the preceding six months. Sales would have been
    higher in aggregate if not for the impact of planned maintenance at Mereenie, Dingo and the Northern Gas Pipeline
    and seasonal demand reductions in December. Even with the lingering market constraints, our producing assets
    have provided sustaining cash flows which have covered all our operating and corporate costs, debt service and
    capital expenditure for the six months.
    With market confidence improving, we are in a solid financial position to progress with several important growth
    projects in 2021.
    In coming months we will drill two new production wells at Mereenie and re-complete four existing wells to increase
    the production capacity of the Mereenie field toward 45 TJ/day (Central share 22.5 TJ/day) by mid-year. This
    campaign will target more than 40 PJ of gas for future sale (Central share 20 PJ). To help finance this investment,
    we pre-sold 3.5 PJ of gas in December 2020 for delivery in 2022/2023.
    The Range Coal Seam Gas Project in Queensland was reactivated in November and a three-well pilot program is
    scheduled to commence in April 2021, with production testing planned for mid year. Results from the pilot wells will
    be critical in determining optimal production rates and designing cost efficient surface facilities, both of which play
    an important part of a Final Investment Decision which we anticipate in H1 2022, allowing for first gas from Range
    to be delivered by 2024.
    Preparations for our proposed exploration program of up to four wells in the Amadeus Basin are almost complete.
    The wells will target significant gas and oil resources in formations known to be productive in other fields. It is
    intended that the Amadeus exploration program will be funded from a partial farm-out of our producing fields. Our
    progress with a preferred farm-out partner is tracking well with a target of first quarter CY2021 to announce agreed
    terms of this transaction, allowing us to plan for exploration drilling to begin in Q3 CY2021.
    The Federal Government’s Energy Plan announced last year identifies the important role of natural gas in the
    transition to reliable renewable energy and promotes large emerging basins for new supply and new gas pipelines
    for efficient gas delivery. As a large under-explored basin with over 30 years of production, the Amadeus Basin
    promises to play an important role in Australia’s energy future. We have made direct representations to the Federal
    Government to have the Amadeus Basin included in its plans to help develop gas supplies from emerging basins.
    The targets of our 2021 Amadeus exploration program are complemented by larger sub-salt leads such as Dukas
    and Zevon, which we hope to advance through 2021 and beyond.
    Our agreement with Australian Gas Infrastructure Group (AGIG) as a potential foundation customer for the proposed
    Amadeus to Moomba Gas Pipeline (AMGP) brings the possibility of a new, shorter and more cost-efficient route to
    get our Amadeus Basin gas to eastern markets.
    At this time it’s appropriate for me to acknowledge the efforts of Central’s management and staff in ensuring gas
    continues to be delivered to our customers safely and without interruption during the COVID 19 pandemic. In
    addition, we appreciate the constructive engagement from all our stakeholders including our joint venture partners
    and various Government agencies. We also acknowledge the Traditional Owners and custodians of the land on
    which we operate, and thank them for their continued and crucial support of our operations. And finally, to our
    shareholders, we thank you for your continued support.
    Central Petroleum Limited ABN 72 083 254 308 33
    All up, having weathered the market challenges of 2020, the foundation is set for the implementation in 2021 of
    these growth initiatives which have the potential to add significant value to your company. We look forward to
    keeping you up to date as we work to deliver on these opportunities.
    Yours faithfully

    courtesy of Bell Direct
    ( DYOR )

    i do not hold this share ( but do hold MQG 'free-carried' )

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    Operating highlights
    The principal continuing activity of the consolidated entity (“the Group”) during the period was the exploration,
    development and production of hydrocarbons.
    Highlights for the half-year reporting period and up to the date of this report
    • Sales of oil and gas were steady at 5.11 PJE for the half year, compared with 5.19 PJE sold in the previous
    six months to 30 June 2020, but 28% below December 2019 half year levels due to weak market
    • Operating revenue was $28.9 million, slightly lower than the $29.3 million recognised in the previous six
    months to June and 19% lower than the $35.7 million in the half year ending December 2019.
    • Secured a new Gas Supply Agreement to supply 3.5 PJ of gas over calendar years 2022 and 2023. The
    sale proceeds were pre-paid in full in December 2020 and will help finance new production capacity at
    Mereenie in 2021.
    • Stronger cash position, with net debt of $31.2 million, down from $46.1 million at 30 June, including cash
    balances of $38.5 million.
    • Extended the Group's finance facility for a further 12 months to 30 September 2022.
    • Restarted work on the Range CSG Project in the Surat Basin, with a three well appraisal program planned
    to be drilled in April 2021.
    • Executed a Memorandum of Understanding with Australian Gas Infrastructure Group with the aim of
    becoming a foundation customer of a proposed new gas pipeline from Central’s Amadeus Basin fields to
    the Moomba gas hub, potentially providing a more cost-efficient route to the larger east coast gas markets.
    • A preferred bidder for an interest in Central’s Amadeus Basin producing assets was selected and is
    conducting final due diligence.
    • Welcomed Michael (Mick) McCormack to the Board and his subsequent appointment as Chair, bringing to
    Central his experience as one of Australia’s energy industry leaders.
    Central Petroleum Limited ABN 72 083 254 308 55
    Operating and Financial Review
    The Consolidated Entity had an operating profit after income tax for the half year to 31 December 2020 of
    $2.5 million (Dec 2019: $3.2 million).
    The above result was after expensing exploration costs of $1.4 million (Dec 2019: $1.1 million). The Group’s policy
    is to expense all exploration costs as incurred. To assist understanding of the Group’s underlying financial
    performance before exploration costs, earnings before interest, tax, depreciation, amortisation and exploration
    (EBITDAX) is reported below.
    The result for the half year continues to reflect the significant market downturn that began in early CY2020 as well
    as natural field decline. Spot oil and gas prices are now starting to recover, but sales volumes were marketconstrained for the first quarter of FY2021 and impacted by scheduled maintenance later in the period. The table
    below shows key metrics for the Group:

    The Group recorded $28.9 million of operating revenue for the half year, consistent with $29.3 million in the
    immediately preceding six months to June 2020, but 19% lower than $35.7 million for the previous corresponding
    period in 2019. The drop in revenues from 2019 result from a 28% decrease in volumes, partly offset by higher
    realised prices, reflecting the significant market downturn that began in early CY2020 as well as natural field decline.
    Spot oil and gas markets are starting to recover, but sales volumes were market-constrained for the first quarter of
    FY2021 and impacted by scheduled maintenance in the second quarter. The Group’s revenues were underpinned
    by fixed price contracted gas sales with take or pay provisions which provide a stable revenue base. Current firm
    gas supply contracts have various terms that extend beyond 2025, including 7.5 PJ in CY2022 and 5.2 PJ in
    Gross Profit
    A Gross Profit of $14.7 million was recorded, 14% higher than the six months to June 2020 which included the cost
    of returning higher volumes of previously over-lifted gas, but 22% lower than the December 2019 half year, reflecting
    the lower production revenues achieved. Unit costs of sale were slightly higher than the FY2020 average at $2.78
    /GJE (FY2020: $2.71 /GJE) as fixed costs were spread over lower volumes.
    The Group repaid 0.35 PJ of previously over-lifted gas volumes to its joint venture partner (June 2020: 0.63 PJ, Dec
    2019: nil).
    Other Expenses
    Net employee and administration costs (including share based benefits) for the half year were $1.8 million compared
    to $2.4 million for the prior corresponding period, including the benefit from the JobKeeper subsidy for the first
    quarter. The annual Short Term Incentive Plan for key management personnel and their direct reports were awarded
    as share rights with a 3-year vesting period rather than as cash to preserve the Group’s cash position.
    Net Assets/Liabilities
    At 31 December 2020 the Group had a net asset position of $5.0 million compared to $1.6 million at 30 June 2020.
    The improvement reflects the positive operating cash flows during the period.
    Included in liabilities on the Group’s balance sheet are amounts relating to pre-paid gas sales and take-or-pay
    receipts recognised as deferred revenue amounting to $44.7 million (June 2020: $33.9 million). These liabilities will
    be transferred to revenue as gas is supplied to the customer or forfeited under take-or-pay contracts and therefore
    do not represent a cash liability to the Group.
    During the half year, 0.35 PJ of previously over-lifted gas was repaid to joint venture partners and 0.87 PJ of presold gas was delivered.
    The Group repaid $2.0 million of loan principal during the period. EBITDAX of $12.9 million covered service of loan
    facilities of $4.2 million (x 3.0) during the half year. There were no new borrowings during the period.
    Net debt including lease liabilities was $31.2 million at 31 December 2020, significantly lower than the $46.1 million
    at 30 June 2020 and $59.2 million 12 months ago, due to loan repayments and a higher cash balance of $38.5
    million (June 2020: $25.9 million; December 2019: $14.9 million).
    The balance of outstanding debt at 31 December 2020 was $68.8 million. The loan facility with Macquarie Bank
    was extended for a further 12 months during the half year and is now due to expire on 30 September 2022. Principal
    repayments continue at $1.0 million per quarter until 30 September 2021, then increase to $2.0 million per quarter
    on and from 31 December 2021.

    Operating and Financial Review (continued)
    Net cashflow from operations
    Net cashflow from operations was $17.6 million (six months to June 2020: $7.4 million, 2019 half year: $8.3 million),
    with the increase reflecting receipts from the pre-sale of gas to be delivered in CY2022 and CY2023, lower interest
    costs and JobKeeper subsidies, partly offset by lower sales volumes.
    Expenditure on exploration activities of $1.3 million was relatively modest, as certain exploration programs were
    deferred in response to uncertain market conditions in 2020.
    Central continued its strong focus on Health, Safety and Environmental performance, implementing improvements
    across all operations. One MTI / LTI was recorded. There were no reportable environmental incidents in the half
    Environmental, Aboriginal Areas Protection Authority and Central Land Council approvals were granted for the
    proposed Amadeus exploration drilling program and the new production wells planned for Mereenie.
    Mereenie Oil and Gas Field (OL4 and OL5) – Northern Territory
    (CTP – 50% interest [Operator], Macquarie Mereenie Pty Ltd – 50% interest)
    During the half-year:
    • Gas production was market-constrained, averaging 28.5 TJ/d over the half-year (100% JV), an increase
    of 10% on the preceding June half year as markets started to recover from the downturn in early CY2020.
    • Oil sales averaged 205 barrels of oil per day over the half-year (Central’s share) netting an average of
    A$57.74 /bbl after selling and transport costs, an increase of 10% from A$52.32 /bbl realised in the six
    months to June 2020.
    • Field capacity was 32 TJ/d at 31 December.
    A campaign to recomplete four existing wells and to drill two new crestal production wells is scheduled to commence
    in March 2021 with the aim of returning Mereenie’s gross production capacity to around 45 TJ/d (100% JV) in 2021
    and produce an additional 40 PJ of gas over the lifetime of these wells (20 PJ net to Central).
    Palm Valley Gas Field (OL3) – Northern Territory
    (CTP – 100% Interest)
    Gas production averaged 9.6 TJ/d over the six months to December 2020, down 10% from the preceding six months
    due to scheduled maintenance on the Northern Gas Pipeline and natural field decline.
    The successful horizontal PV13 well, which was commissioned in May 2019, continued to outperform and is
    declining slower than first anticipated. As a result of this success, another horizontal production well (PV12) is
    planned to be drilled using the wellbore of the proposed Palm Valley Deep exploration well which is part of the
    Amadeus exploration program planned for later in CY2021.
    Dingo Gas Field (L7) and Dingo Pipeline (PL30) – Northern Territory
    (CTP – 100% Interest)
    The Dingo field supplies gas to the Owen Springs Power Station, with gas sales averaging 2.8 TJ/d over the halfyear, a decrease of 18% from the 3.4 T/day sold in the preceding six months. The balance of the contracted volume
    of 4.4 TJ/d is subject to take-or-pay provisions and is paid annually to Central in January for the preceding year.

    courtesy of Bell Direct
    ( DYOR )

    i do not hold this share ( but do hold MQG 'free-carried' )

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