REG - Seplat Energy PLC - Seplat FY22 Financial Results

Seplat EnergyAnnouncement

28/02/2023 07:00

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RNS Number : 2227R  Seplat Energy PLC  28 February 2023

 

Please see the Full Audited Results in attached PDF

 

http://www.rns-pdf.londonstockexchange.com/rns/2227R_1-2023-2-28.pdf
(http://www.rns-pdf.londonstockexchange.com/rns/2227R_1-2023-2-28.pdf)

 

Audited results

for the year ended

31 December 2022

28 February 2023

 

Lagos and London, 28 February 2023: Seplat Energy Plc ("Seplat Energy" or "the
Company"), a leading Nigerian independent energy company listed on the
Nigerian Exchange Limited and the London Stock Exchange, announces its audited
results for the full year ended 31 December 2022.

Special Dividend

§  Board recommends special dividend of US5.0 cents per share in addition to
final dividend of US2.5 cents per share

Operational highlights

§  Working interest production averaged 44 kboepd, impacted by outages of
key infrastructure predominantly in Q3

§  Use of Amukpe-Escravos Pipeline (AEP) enables high uptime in December,
exit rate of 53 kboepd

§  Completed 13 wells including two wells for the ANOH gas processing plant

§  ANOH Gas Processing Plant 95% mechanically complete, awaiting third-party
infrastructure completion

§  Safety culture maintained, one LTI recorded in October, LTIF for the full
year is 0.12

Financial highlights

§  Revenues of $951.8 million, up 29.8%

§  Adjusted EBITDA $416.9 million, up 12.1%

§  Strong full year cash generation of $571.2million against capex of
$163.3million and $140.3million transaction deposits

§  Strong balance sheet with $404.3 million cash at bank, net debt of $365.9
million

§  Full year production cost of $10.3/boe

§  2022 Ubima divestment receipts were $18.6 million out of $55.0 million
(additional $0.9million received in Jan 2023)

Corporate updates

§  Continue to pursue approvals for acquisition of entire share capital of
MPNU

§  Finalised New Energy investment plan, identified near term opportunities
for consideration and FID late 2023

§  Commenced implementation of roadmap to achieving net zero by 2050

§  Provisional applications for voluntary conversion of operated Oil Mining
Leases under Petroleum Industry Act

§  Work on-going to spin out Midstream Gas business in line with PIA
provisions

§  First Climate Risk and Resilience Report to be published at end of March
2023 under TCFD guidelines

§  Carbon intensity of production figure published: 23.9Kg/boe

Outlook for 2023

§  Full year production guidance of 45-55 kboepd (excluding ANOH), capex
expected to be $160 million

§  Increased use of AEP will improve revenue assurance

§  Sibiri appraisal wells indicating results on high side of initial Oil
In-Place estimates, FID targeted by end 2023

§  ANOH first gas guidance moved to Q4 2023 owing to delays in third-party
infrastructure

§  MPNU: continuing to pursue a reaffirmation of the Ministerial approval
received on the 8 August 2022.

Roger Brown, Chief Executive Officer, said:

"I am delighted that our strong financial performance will enable the payment
of a US7.5 cent final dividend, despite the significantly disrupted production
we experienced in the second half of the year. The full-year dividend of US15
cents represents a dividend yield of around 11% at the current LSE share
price.

As we enter 2023, the business is in a very healthy state, with new wells
coming onstream, encouraging appraisal drilling underway at Sibiri, and
alternative export routes ensuring good export performance in January and
February this year. Our gas business continues to develop, with first gas
expected from ANOH in Q4 this year, and we are now in the process of
separating our Midstream Gas business from the Upstream unit to unlock new
value for shareholders.

We are continuing to pursue the Presidential approval received on the 8 August
2022 for the MPNU acquisition and we remain focused on concluding the
transaction within the remaining term of President Buhari before a new
president is sworn into office at the end of May 2023.

We are implementing our roadmap to net zero and have made encouraging progress
with a 35% reduction in emission intensity last year. The major reduction in
carbon emissions is routine flaring which we are on target to eliminate by the
end of 2024. Alongside these efforts, and as part of our stated strategy to
become Nigeria's energy champion across the entire value chain, we are
planning to invest in gas-to-power and solar power projects with FID targeted
for later this year if the projected returns meet our internal hurdle rates.

We are confident in our outlook for 2023, with the new Amukpe-Escravos
Pipeline working well, our drilling cost reductions and efficiencies being
delivered, and ANOH's first gas expected in Q4 once 3(rd) party infrastructure
is completed, our business is on a firm footing to facilitate significant
growth and higher returns for stakeholders."

Summary of performance
                                      $ million                                   ₦ billion
                                      FY 2022     FY 2021     % change      FY 2022       FY 2021
 Total dividend including Special     US15 cents  US10 cents  50%
 Revenue                              951.8       733.2       29.8%         403.9         293.6
 Gross profit                         464.7       285.2       63.0%         197.2         114.2
 Impairment of assets *               (6.4)       36.6        nm            2.7           14.6
 EBITDA **                            416.9       371.8       12.1%         175.6         146.8
 Operating profit (loss)              274.7       250.7       9.6%          116.6         100.4
 Profit (loss) before tax             204.4       177.3       15.3%         86.7          71.0
 Cash generated from operations       571.2       376.8       51.6%         242.4         150.9
 Working interest production (boepd)  44,104      47,693      (7.5%)
 Total crude oil lifted (MMbbls)      8.3         8.9         (6.8%)
 Average realised oil price ($/bbl)   101.67      70.54       44.1%
 Average realised gas price ($/Mscf)  2.82        2.85        (1.1%)
 LTIF                                 0.12        0
 CO2 emissions intensity              23.9        36.6        (34.7%)

from operated assets, kg/boe

* FY 2021 includes reversal of $74.7m impairment charge under IAS 36

** Adjusted for impairment, fair value loss and decommissioning

 

Responsibility for publication

The Board member responsible for arranging the release of this announcement on
behalf of Seplat Energy is

Emeka Onwuka, CFO Seplat Energy Plc.

 

Signed:

Emeka Onwuka

Chief Financial Officer

 

Important notice

The information contained within this announcement is unaudited and deemed by
the Company to constitute inside information as stipulated under Market Abuse
Regulations. Upon the publication of this announcement via Regulatory
Information Services, this inside information is now considered to be in the
public domain.

Certain statements included in these results contain forward-looking
information concerning Seplat Energy's strategy, operations, financial
performance or condition, outlook, growth opportunities or circumstances in
the countries, sectors, or markets in which Seplat Energy operates. By their
nature, forward-looking statements involve uncertainty because they depend on
future circumstances and relate to events of which not all are within Seplat
Energy's control or can be predicted by Seplat Energy. Although Seplat Energy
believes that the expectations and opinions reflected in such forward-looking
statements are reasonable, no assurance can be given that such expectations
and opinions will prove to have been correct. Actual results and market
conditions could differ materially from those set out in the forward-looking
statements. No part of these results constitutes, or shall be taken to
constitute, an invitation or inducement to invest in Seplat Energy or any
other entity and must not be relied upon in any way in connection with any
investment decision. Seplat Energy undertakes no obligation to update any
forward-looking statements, whether as a result of new information, future
events or otherwise, except to the extent legally required.

 

Investor call

At 09:00 GMT / 10.00 WAT on Tuesday 28 February 2023, the Executive
Management team will host a conference call and webcast to present the
Company's results.

The presentation can be accessed remotely via a live webcast link and
pre-registering details are below. After the meeting, the webcast recording
will be made available and access details of this recording are also set out
below.

A copy of the presentation will be made available on the day of results on the
Company's website at https://seplatenergy.com/ (https://seplatenergy.com/) .

 

 Event title:                            Seplat Energy Plc: Full year results
 Event date                              9:00am (London) 10:00am (Lagos) Tuesday 28 February 2023
 Webcast Live Event Link                 https://secure.emincote.com/client/seplat/seplat016
                                         (https://protect-za.mimecast.com/s/d1sqC58x3yfpVAvhzxMUT?domain=secure.emincote.com)
 Conference call and pre-register Link:  https://secure.emincote.com/client/seplat/seplat016/vip_connect
                                         (https://protect-za.mimecast.com/s/5ML-C66y28t0nXDf69w-D?domain=secure.emincote.com)
 Archive Link:                           https://secure.emincote.com/client/seplat/seplat012
                                         (https://secure.emincote.com/client/seplat/seplat012)

 

The Company requests that participants dial in 10 minutes ahead of the call.
When dialling in, please follow the instructions that will be emailed to you
following your registration.

Enquiries:
 Seplat Energy Plc
 Emeka Onwuka, Chief Financial Officer                            +234 1 277 0400
 Eleanor Adaralegbe, Vice President, Finance
 Carl Franklin, Head of Investor Relations                        cfranklin@seplatenergy.com
 Ayeesha Aliyu, Investor Relations                                aaliyu@seplatenergy.com
 Chioma Nwachuku, Director External Affairs & Sustainability

 FTI Consulting
 Ben Brewerton / Christopher Laing                                +44 203 727 1000

                                                                  seplatenergy@fticonsulting.com

 Citigroup Global Markets Limited
 Tom Reid / Peter Catterall                                       +44 207 986 4000

 Investec Bank plc
 Chris Sim / Charles Craven / Jarrett Silver                      +44 207 597 4000

 

About Seplat Energy

Seplat Energy PLC (Seplat) is Nigeria's leading indigenous energy company.
Listed on the Nigerian Exchange Limited (NGX: SEPLAT) and the Main Market of
the London Stock Exchange (LSE: SEPL), we are pursuing a Nigeria-focused
growth strategy in oil and gas, as well as developing a Power & New Energy
business to lead Nigeria's energy transition.

Seplat's energy portfolio consists of seven oil and gas blocks in the prolific
Niger Delta region of Nigeria, which we operate with partners including the
Nigerian Government and other oil producers. We also have a revenue interest
in OML 55. We operate a 465MMscfd gas processing plant at Oben, in OML4, and
are building the 300MMscfd ANOH Gas Processing Plant in OML53 and a new
85MMscfd gas processing plant at Sapele in OML41, to augment our position as a
leading supplier of gas to the domestic power generation market.

For further information please refer to our website, http://seplatenergy.com/
(http://seplatenergy.com/)

 

Operating review
Upstream business performance
Reserves and Resources

The Group's audited 2P reserves, as assessed independently by Ryder Scott
Company, L.P., decreased by 19 MMboe from 457 MMboe at the end of 2021 to 438
MMBoe at the end of 2022. The change is mostly due to production of 9 MMbbls
of liquids and 41.0 Bscf of gas (7 MMboe). The divestment of Ubima, the
discovery at Sibiri, and reclassifications and revisions of previous estimates
makes up the difference.

 

                                2P reserves at 31/12/2022                  2P reserves at 31/12/2021
                                Liquids           Gas      Total((3))      Liquids    Gas        Total
                      Seplat %  MMbbl             Bscf     MMboe           MMbbl      Bscf       MMboe
 OMLs 4, 38 & 41      45%                138      629      246             144        651        256
 OPL 283              40%                4        61       15              5          68         17
 OML 53               40%                39       653      152             39         660        153
 OML 55               Fin. Interest      3        -        3               4          -          4
 OML 40((1))          45%                22       -        22              25         -          25
 Ubima((2))           82%                -        -        -               2          -          2
 Total                                   206      1,343    438             219        1,379      457

1.       Eland has a 45% working interest in OML40 until the Westport
loan is fully repaid in accordance with the loan agreement, reverting to
20.25%

2.       Eland had an 82% working interest in the Ubima marginal field

3.       Quantities of oil equivalent are calculated using a gas-to-oil
conversion factor of 5,800 scf of gas per barrel of oil equivalent.

 

The Group's audited 2C resources decreased by 7.3% from 75 MMboe to 70 MMBoe,
comprising 43 MMbbls of oil and condensate and 159 Bscf of natural gas. The
decrease in 2C gas resources (boe) is mostly due to revisions in Emebiam, Owu
and Oben fields.

 

                                            2C resources at 31/12/2022              2C resources at 31/12/2021
                      Liquids((1))  Gas    Total                   Liquids     Gas  Total
                      Seplat %             MMbbl       Bscf        MMboe            MMbbl      Bscf       MMBoe
 OMLs 4, 38 & 41      45%           31                 124         52               28         162        56
 OPL 283              40%           7                  24          11               4          21         8
 OML 53               40%           3                  11          5                4          14         6
 OML 40               45%           2                  0           2                3          0          3
 Ubima                82%           -                  -           -                2          0          2
 Total                              43                 159         70               41         197        75

Abiala has not been included in 2C resources because the farm in agreement had
not been concluded at the time of closure of the reserves audit

 

Consequently, the Group's working interest 2P reserves and 2C resources stood
at 507.5 MMboe as of 31 December 2022, comprising 248.5 MMbbls oil and
condensate and 1,502.2 Bscf of natural gas (259 MMBoe).

 

Production

Full-year total working interest production for 2022 was 16.1 MMboe. Within
this, liquids production was 9.03 MMbbls, down 26.6% year-on-year, and gas
production was 7.1 MMBoe (41.0 Bscf), up 4.1% year-on-year. In addition, the
Group recorded a total downtime of 37%, primarily because of problems with
third-party export infrastructure.

                                 2022                                        2021
                      Liquids   Gas       Total             Liquids          Gas       Total
                      Seplat %  bopd      MMscfd            boepd            bopd      MMscfd            boepd
 OMLs 4, 38 & 41      45%        15,422         112.3            34,791       18,243         107.9            36,844
 OPL 283              40%       1,067     -                 1,067            1,012     -                 1,012
 OML 53               40%       1,689     -                 1,689            3,164     -                 3,164
 OML 40               45%       6,557     -                 6,557            5,923     -                 5,923
 Ubima                          -         -                 -                749       -                 749
 Total                          24,735    112.3             44,104           33,714    107.9             47,693

Liquid production volumes as measured at the LACT (Lease Automatic Custody
Transfer) unit for OMLs 4, 38 and 41; OML 40 and OPL 283 flow station.

Gas conversion factor of 5.8 boe per scf.

Following the decision to exit from the Ubima asset in April 2022, volumes
from the marginal field have not been reported in 2022

Volumes stated are subject to reconciliation and will differ from sales
volumes within the period.

 

Working interest production by quarter

 

                                Q1 2022                 Q2 2022                 Q3 2022                 Q4 2022
                                Liquid  Gas     Total   Liquid  Gas     Total   Liquid  Gas     Total   Liquid  Gas     Total
 Seplat %                       kbopd   MMscfd  kboepd  kbopd   MMscfd  kboepd  kbopd   MMscfd  kboepd  bopd    MMscfd  kboepd
 OMLs 4, 38 & 41        45%     17.7    107.4   36.2    17.1    127.9   39.2    9.5     103.1   27.2    17.5    111.0   37.5
 OML 40                 45%     7.4     -       7.4     10.1            10.1    1.6     -       1.6     7.3             7.4
 OML 53                 40%     2.7     -       2.7     1.6             1.6     1.1     -       1.1     1.3             1.4
 OPL 283                40%     1.3     -       1.3     1.5             1.5     0.3     -       0.3     1.1             1.1
 Total                          29.1    107.4   47.6    30.3    127.9   52.4    12.5    103.1   30.3    27.2    111.0   46.4
 3(rd) party deferment  MMbbls                  0.7                     0.5                     2.2                     1.3

 

Liquids production for all assets was affected by evacuation issues during the
year, particularly in Q3 on the Forcados export route, and this led to total
deferred liquid volumes of 4.7 MMbbls for 2022.

For OMLs 4, 38, & 41, which rely on the Forcados route, the Forcados
Terminal (FOT) was unavailable for 146 days in 2022 (including 78 consecutive
days in Q3 2022). The force majeure declared on the Trans Forcados pipeline
(TFP) and other deferments due to maintenance activities impacted crude
production. The situation would have been more acute had we not successfully
operationalised the Amukpe to Escravos Pipeline (AEP) in the third quarter. A
total of 1.6 MMbbls or 10.1 kbopd (working interest) was exported through the
AEP from July 2022, when the pipeline became operational. As expected, there
was an improvement in performance from the fourth quarter, with 90% of our
liquids evacuated through the AEP in December 2022, enabling an exit rate for
the year of 53 kboepd across the Group.

Similarly, pipeline unavailability impacted production at OML 40. After a
39-day outage of the Forcados Oil Terminal (FOT) and Trans Escravos Pipeline
(TEP) in the fourth quarter (135 days outage for the full year), production
resumed, and evacuation commenced in November 2022.

For OML 53, with production of around 1,000 bopd (gross) from the Jisike field
being shut-in since February 2022, we could only evacuate an average of about
3,000 bopd from Ohaji to the Waltersmith Refinery.

Divestment of Ubima marginal field

Wester Ord Oil and Gas Nigeria Ltd. (WON), a wholly owned subsidiary of the
Company, agreed in Q1 2022 with the J.V. partner All Grace Energy Ltd. (AGEL)
to divest WON's rights in the Ubima Marginal Field for a consideration of
$55.0 million. Under the agreement, the Company has received a total of $19.5
million, with $18.6 million received in 2022 and $0.9 million received in
January 2023.

As a result, Ubima's production has been removed from the Group's daily
average output and WON has derecognised assets and liabilities in H1 2022,
including Ubima's current reserves of approximately 2 MMbbls.

Farm-in to Abiala marginal field

Following the 2020 marginal field bid round in Nigeria, Naphta Global E&P
Ltd. (Naphta) was awarded 100% equity in the Abiala marginal field carved out
of OML 40 by the NUPRC. The marginal field contains 2C gross oil resources of
approximately 40 MMbbls.

Elcrest (45% owned by Seplat Energy) has entered into an agreement with Naphta
for a 95% equity farm-in to the Abiala marginal field, while Naphta will have
a 5% carried interest. Elcrest will also assume the role of Operator and
Technical & Financial Partner in the Elcrest/Naphta Joint Venture. The
partners executed Heads of Agreement with a signature bonus of $12 million
paid to NUPRC. The transaction represents a consolidation of the Company's
strategic position on the OML 40 block. It provides an early monetisation
opportunity using existing OML 40 facilities, subject to agreement with NEPL
(NNPC E&P Limited, formerly NPDC), which operates the OML 40 Asset.

In developing the field, Elcrest is targeting first oil by the end of Q2 2023
and plans to focus on low-cost development with early monetisation
opportunities that leverage existing contractual positions to accelerate the
field's development. Seplat Energy will also explore optimising its tax
position to the extent possible under the new PIA.

Drilling activities

The drilling programme for 2022 spudded thirteen wells and successfully
delivered eleven wells below budgeted costs. An additional two wells (ANOH-03
& ANOH-04) were spudded by SPDC in 2022 but will not be completed until
2023 due to delays in the gas plant on-stream date.

In OML 4, 38 & 41, we spudded and delivered four wells: the Amukpe-5ST2,
Oben-52, Oben-53 and Ethiope-02 wells, which are expected to produce a
combined gross rate of c.5,000 bopd and c.3.1 MMscfd of gas.

In OML 53, we spudded three wells and delivered one well: the Owu-02 appraisal
well was spudded and completed. The OHS-08 was completed in January 2023 and
the OHS-07 expected to be completed later in Q1 2023. The expected peak
production from OHS-07 and OHS-08 is c.3,500 bopd.

In OML 40, we spudded and delivered six wells: the Opuama-12, Opuama-13,
Opuama-14, Opuama-15, Opuama-16 wells and Sibiri-1. The Opuama wells have
commenced production, with gross combined production of approximately c.9,000
bopd.

Total expected peak production for the production wells spudded in 2022 is
expected to be c.17,500 bopd of oil and c.3.1 MMscfd of gas or working
interest: c.7,700 bopd and 1.4 MMscfd.

In OML 40, the Sibiri oil discovery is being appraised by two wells. The
Sibiri-1 discovery well was drilled in Q1 2022 and as reported in our 2021
full-year results last year, encountered eight oil-bearing reservoirs with 353
ft of gross oil pay and 229 ft of net pay. The post discovery Oil In-Place was
estimated in the range 24-34-94 million barrels.

Appraisal drilling of Sibiri-2, with the objectives of testing the eastern and
south-western flanks, commenced on 30 January 2023 and reached TD on 23
February, with initial results indicating significant uplift in mid-case
Oil-In-Place volumes. In the eastern flank, four oil bearing reservoirs with
68 ft of gross oil and 48 ft net pay were encountered. In the south-western
flank, nine oil bearing reservoirs with an initial estimate of 292 ft of gross
oil and 180 ft net pay, including two new pay zones, were encountered. These
preliminary results are in line with the high side of pre-appraisal Oil
In-Place evaluation. Further well data acquisition is ongoing and subsequent
technical studies are required to confirm the initial results.

The extended well testing (EWT) of Sibiri-1 commenced on 21 February 2023 via
a 6km flow line to the OML40 Opuama facilities. Testing and evaluation of
crude properties is ongoing.

The Field Development Plan is on schedule to be completed in Q4 2023, leading
to the Final Investment Decision for the full field development soon after.
Development drilling is anticipated in Q1 2024 with expected peak production
of 5,000-6,000 barrels of oil per day in 2024-25.

Export infrastructure diversification

We continue to pursue alternative crude oil evacuation options for production
at all assets, to increase our export flexibility reduce over-reliance on any
one third-party operated export system. In line with this objective, we
successfully commenced evacuation through the AEP export route during the
third quarter of 2022. Crude oil production from OMLs 4, 38 and 41 is now sent
via the Trans Forcados Pipeline (TFP) and AEP, with significant volumes now
flowing through the latter. For a third export route, we intend to establish
regular exports of 10,000 bopd (gross) through the Warri Refinery jetty, from
which it will be sold FOB to our off-taker at the jetty. We intend to keep
this option available for the foreseeable future.

All three export routes will provide significant flexibility and ensure we
have adequate redundancy in evacuation routes, significantly reducing downtime
to promote higher levels of revenue assurance and profitability.

For OML 53, we have engaged with our J.V. partner NUIMS (formerly NAPIMS) and
the NUPRC to operationalise an alternative evacuation option of trucking for
the Jisike and Ohaji South fields in OML 53, and we will commence a pilot test
when approvals are secured.

At OML 40, the partners are exploring the potential of barging operations to
evacuate liquids from the Gbetiokun fields to the LEC floating storage and
offloading facility (FSO) to mitigate the impact of increasing FOT/TEP
unavailability.

Towards a permanent solution, the partners have begun constructing a pipeline
from Gbetiokun to Adagbassa to replace the more expensive barging operation
that we currently run. The 30cm x 30km pipeline will take produced crude from
the Gbetiokun field in OML 40 to the Adagbassa manifold, from where the
pipeline will tie into the existing 36km Opuama-Otumara export pipeline.

Midstream Gas performance

Seplat is a leading supplier of processed natural gas to the expanding
Nigerian domestic market. Working interest gas volumes for the period averaged
112.3 MMscfd (2021: 107.9 MMscfd), a contribution of 44% of the Group's total
production volume on a boe basis. Our gas business was affected by the outages
on the TFP because of the limited liquid handling capacity for condensate
produced alongside the gas.

Gas contracts and pricing

During the period, we signed short-term gas sales agreements (GSAs) with three
new customers, for a combined offtake of 86 MMscfd. As a result, Seplat now
has a total of eight GSAs for the supply of 396 MMscfd of gas.

In addition, we concluded price renegotiation with customers during the second
quarter, and following the DGDO gas pricing revision in August 2021, the
average gas price achieved was $2.82/Mscf (2021: $2.85/Mscf), which is
weighted against volumes supplied to each customer in the periodThe gas sold
under the new GSAs (mentioned above) at more favourable terms offset the
impact of the lower gas prices realised at the first half of the year.

Midstream Gas business separation from Upstream

The decision to convert to the PIA regime considered the implications for our
Midstream Gas business. In line with the provisions of the PIA, we believe the
Midstream gas business could achieve a higher value when operated as a
separate, standalone unit, independent of our Upstream business. This will
unlock new value for the Company and increase returns for stakeholders. An
implementation roadmap for the spin-out opportunity has been developed and the
process is expected to take 12 to 18 months, subject to regulatory approval
and stakeholder engagement.

Additional third-party volumes

We are focused on developing third-party gas resource opportunities that can
utilise the remaining processing capacity at Oben. Securing additional volumes
from counterparties will secure long-term supplies of raw natural gas from
which we can maximise the plant's utilisation and generate tolling revenues.
We progressed discussions with targeted third-party gas producers during the
year and are finalising contracting to facilitate a tripartite gas development
workshop with three producers.

ANOH Gas Processing Plant

To date, the IJV (AGPC) has achieved 95% overall mechanical project completion
at the gas plant site, and we expect the plant to be mechanically complete in
Q2 2023.  Our government partner, NGIC, is delivering the pipelines that will
take the gas from ANOH to the demand centres, namely the 23km spur line and
the Obiafu-Obrikom-Oben (OB3) pipeline.

The OB3 pipeline has been affected by the collapsing of the HDD wall in a
section of the river crossing.  Experts from the UK have been brought in to
'grout' the section and grouting will commence in March with the drilling and
pipe installation to commence thereafter. NGIC has confirmed that they expect
the pipeline to be complete before the end of Q2 2023.

Line pipes for the 23km spur line are in country and project completion is
almost 70%, with the revised completion date communicated by NGIC as 30 June
2023.

Despite estimated completion for the pipeline infrastructure being Q2 2023, we
have further risked the completion dates and have moved the first gas to the
final quarter of 2023. Once completed, ANOH will deliver two income streams
for Seplat Energy: from OML 53's wet gas sales to the plant, and from
dividends returned to Seplat Energy from the joint venture ANOH Gas Processing
Company, which will operate the plant.

The upstream development, including the drilling of six production wells, will
be delivered by the upstream unit operator SPDC. We expect the drilling of
ANOH-03 and ANOH-04 by SPDC to be completed in Q2 2023.

Sapele Gas Plant

Work continues on the new Sapele Gas Plant, with project progress at 60%. Upon
completion, the processing capacity will be 85 MMscfd. The upgraded facility
will produce gas that meets export specifications, and the LPG processing unit
module will enhance the economics of the plant and reduce routine gas flaring.
During this period, we accelerated the installation of A.G. Compressors to
reach mechanical completion, and we have commenced commissioning activities to
meet our target to end routine flares by the end of 2024.

 

New Energy business

At our Capital Markets Day in 2021, we announced our intention to invest in
opportunities that will capture more value across the entire energy value
chain, including renewable energy generation, on a medium to large scale.

We have completed evaluation studies and finalised a ten-year integrated Gas
and New Energy Investment Plan. Near-term opportunities we have identified in
gas-to-power and solar energy will be subject to technical and business
evaluation assessments, environment and social impact assessments, and project
licensing, and we expect to move to FID before the end of 2023. The key
investment opportunities being considered include selective entry to off-grid
power generation using gas-fired generation integrated with solar. Natural gas
will be the mainstay of our energy transition programme and this in turn will
ensure the sustainability and financial viability of the renewables program.
We are also pursuing carbon offset possibilities on a wide range of emission
reduction activities in various global carbon markets. The identified
opportunities have considered advancement in technology, availability of
resources within Nigeria and feasibility of execution.

 

Sustainability initiatives

First TCFD Report

Alongside our 2022 Annual Report we will publish a separate Sustainability
Report and our first Climate Risk and Resilience Report, which will include
the disclosures recommended by the Task Force on Climate-related Financial
Disclosures (TCFD). These reports will describe our commitment to the
environment and our approach to managing climate risk and represent disclosure
of initiatives within our corporate strategy to Build a sustainable business
and Deliver energy transition. In addition, the Corporate Scorecard for 2022
is tied to climate-related and other sustainability KPIs, which are expressly
linked to executive pay. ESG accounts for 15% of KPIs in 2022, and safety 10%.

HSE performance

Safe and responsible operations are critical to the delivery of Seplat
Energy's strategy. Staff and contractors completed a total of 8.6 million
hours in the period, and there were 93 HSE incidents in total, compared to 88
in 2021.

After achieving 31 million hours with zero LTI recorded over the last four
years, a non-operating incident was recorded in October when a third-party
contractor fractured his right leg while crossing the road during a community
awareness campaign. The contributing factors to the incident were determined,
and lessons learned have been adopted to prevent such accidents and expand the
scope of safety beyond our operations.

During 2022 we updated our environmental policy and EMS manual in line with
the ISO 14001 standard, as well as relevant local, national, and international
regulations, and industry best practice.

Despite an increase in the number of Tier 2 incidents from three to five
(>0.75bbl or equivalent to 1kg) because of sabotage to facilitate theft
from the pipelines, the volume of operational oil spills decreased by 50% in
2022, and all spills were remediated with limited environmental impact.
Throughout our activities, we took proactive measures to protect biodiversity
and groundwater, and zero groundwater contamination was maintained.

During an internal process review, it was discovered that data pertaining to
emissions sources contained discrepancies caused by an inadequate accounting
system. Therefore, we launched a new GHG Emissions Accounting System and
recalculated historical GHG emissions data. This exercise revealed a 49%
overestimation of our GHG emissions for 2020 and 43% for 2021; the restated
figures are 1.4 and 1.2 MMtonnes CO(2) equivalent, respectively.

The Scope 1 and 2 emissions recorded for 2022 were 0.7 MMtonnes CO(2)
equivalent, resulting in a carbon intensity of 23.9kg/boe (2021: 36.6kg/boe),
slightly above the upstream industry carbon intensity average of 18.9kg/boe
(Oil & Gas Climate Initiative).

LRQA Group (a leading global assurance provider) has independently verified
the new GHG accounting system. The same standards and methodologies in
previous years were applied- API and IPPC.

Reducing our emissions towards Net Zero

Our primary commitment is to reduce our GHG emissions resulting from its
direct operations. In addition, we have established a broad set of investment
activities designed to reduce emissions from its operated facilities and
offset residual emissions.

Our Flares Out project, which forms part of our commitment to achieving Net
Zero by 2050, is on schedule to reach our target of ending routine flares by
the end of 2024. In 2022, improvements in performance of the AG compressor in
Oben and Amukpe, alongside regular asset integrity checks and other facility
improvement activities, were effective and AG flare volume was reduced by
18.2% at Oben (5.7mmscfd against 6.97mmscfd in 2021) and by 39.9% at Amukpe
(1.1mmscd against 1.83mmscfd in 2021).

The Sapele Gas Plant (AG solution) with installed capacity of 40 MMscfd
achieved mechanical completion in December. The AG solution is expected to
process c.26 MMscfd and will make a significant contribution to flared gas
utilisation, reducing emissions and carbon intensity. In addition, we acquired
an LDAR system at our Oben Gas Plant and trained 40 employees on use of the
technology, which has enabled detection of invisible leaks and allowed our
in-house O&M team to act promptly.

Our diesel replacement programme seeks to increase the use of gas, a less
carbon intensive fuel for power generation and where feasible, solar power is
also being considered. We are piloting solar at our Amukpe warehouse to power
equipment on site and plan to power the security outposts located around our
operations using solar energy in 2023.

We have committed $11.5 million in 2023 towards projects that will end routine
flares in our operations, including $10.8 million towards installing gas
compression facilities at the flow stations in Amukpe, Oben and Sapele, and
$0.7 million towards incineration at the Amukpe flow station.

Upon completion of these projects, we expect to improve our gas handling
capacity and reduce flares by c.30 MMscfd in 2023 and c.20 MMscfd in 2024,
which will in turn monetise flare gas in line with our corporate strategy and
the national flare gas commercialisation initiative. In addition, we have
committed $1 million towards planting trees across Nigeria as part of
afforestation efforts that will capture residual emissions. Our focus in 2023
will be on mobilising community stakeholders and completing land acquisition
to enable the commencement of tree planting in Imo, Edo and Abuja.

Focus on asset integrity

At the core of our operations is a focus on asset integrity, process safety
management and maintenance culture to ensure and improve our facilities'
safety, reliability, and availability. This focus also promotes higher revenue
assurance and contributes to our cost savings initiatives. Our goal, through
various asset integrity initiatives, is expected to reduce deferment by
c.120kbbl annually and end routine flares, increasing revenue assurance and
profitability in line with our defined strategic priorities.

Projects completed in the period included the Oben Gas Plant life extension
project to restore health to the plant's old modules and extend life by a
minimum of 15 years, and the sectional re-routing of 5.1km x 10" Sapele to
Amukpe trunkline to reduce the risk of pipeline failure on a heavily
encroached right of way and extend the life span of the pipeline.

Seplat Energy was awarded the ISO 55001 Asset Management certification and is
now subject to annual surveillance audits in April 2023 and 2024 and a
recertification audit in April 2025 in line with ISO 55001 3-yearly
certification renewal cycle. These audits will test how we can effectively
sustain and continually improve our asset management system. In addition, the
tests will encourage a continuous improvement drive in all our asset
management processes to ensure that our asset management system remains
aligned with the ISO 55001 Standard in readiness for all future
surveillance/recertification audits. Improving asset management systems will
enable us to operate our assets more effectively and at higher rates of
return.

Proposed acquisition of MPNU

On 25 February 2022, we announced that we have entered into a Sale and
Purchase Agreement (subject to ministerial and other regulatory approvals) to
acquire the entire share capital of MPNU for a purchase price of $1,283
million plus up to $300 million contingent consideration, subject to the
lockbox, working capital and other adjustments at closing relative to the
effective date. The transaction encompasses the acquisition of the entire
offshore shallow water business of ExxonMobil in Nigeria, which is an
established, high-quality operation with a highly skilled local operating team
and a track record of safe operations, producing 95 kboepd (W.I.) in 2020 (92%
liquids).

On 8 August 2022, we announced that we had received a letter from the
Honourable Minister of State for Petroleum Resources that His Excellency
President Muhammadu Buhari had approved that Ministerial Consent be granted
for the acquisition of MPNU. Accordingly, the approval was given by His
Excellency President Muhammadu Buhari in his capacity as the Honourable
Minister of Petroleum Resources, granting Ministerial Consent according to the
powers of the Minister under Paragraphs 14-16 of the First Schedule of the
Petroleum Act, 1969.

On 10 August 2022, we noted speculation in local media about a withdrawal of
the Ministerial Approval of the proposed acquisition. However, the Sales &
Purchase Agreement remains valid and we remain confident that the transaction
will be approved. We continue to work with all parties to achieve a successful
outcome and will provide further updates as appropriate.

Outlook

Seplat Energy's long-term outlook is positive, with the AEP now operating as
expected and the ANOH Gas Processing Plant due to come onstream in the final
quarter of this year. Full-year production guidance for 2023 is set at 45,000
to 55,000 boepd on a working interest basis. This guidance does not include
any expected contribution from MPNU or ANOH.

Capital expenditure for 2023 is expected to be around $160 million, and we
plan to drill 18 new wells across our operated and non-operated assets as
follows:

·      OMLs 4, 38 & 41: Eight wells (Three oil wells, three gas
wells, one water disposal well and one exploration well)

·      OML 53: One oil well;

·      OML 40: Five wells (Four oil wells and one appraisal well;
Abiala: Development of one workover and one oil well);

·      ANOH: Two gas wells.

The 2023 drilling programme will address production decline and, along with
the completion of maintenance activities, will support long-term production
levels from the assets. Facilities and engineering projects will focus on
completing an upgraded integrated gas processing facility at Sapele. The year
under review showed the importance of the sustainability of our evacuation
options, and we will prioritise alternative route projects in 2023.

Achieving our ESG performance targets is a primary focus for 2023, and in our
climate strategy, where we have committed to being carbon neutral in 2050,
ending routine flares by the end of 2024 is a priority. We plan to complete
the Oben, Amukpe, Sapele & Jisike Flares Out projects, which will capture
and monetise gas for productive use and significantly reduce our carbon
intensity. In addition, we plan to contribute to the growth of our communities
by equipping hospitals and schools with reliable power and, in return,
progress our goal to increase access to energy while developing our power and
renewable capabilities on socially important projects.

We will exercise discretion over drilling investments and selectively consider
opportunities in our existing portfolio, focusing on delivering the highest
cash return whilst diligently preserving a strong balance sheet.

The Board is confident in the future prospects of the business, underpinned by
its strong balance sheet, and reflecting this confidence the Board has decided
to approve the payment of a special dividend of US5 cents to shareholders, in
addition to the final dividend of US2.5 cents.

 

Financial review
Revenue

Revenue from oil and gas sales in 2022 was $951.8 million, a 29.8% increase
from the $733.2 million achieved in 2021.

Crude oil revenue was 35.8% higher than for the same period in the previous
year at $839.5 million (2021: $618.4 million), reflecting higher average
realised oil prices of $101.7/bbl. for the period (2021: $70.5/bbl.). The
increase is attributable to the impact of the conflict in Ukraine on global
energy prices and the steady post-pandemic recovery in global oil demand,
particularly in China and the United States. The total volume of crude lifted
in the period was 8.3 MMbbls, 6.8% lower than the 8.9 MMbbls lifted in 2021.
The lower volumes lifted in 2022 resulted from a drop in production output,
especially in the third quarter, because of the prolonged unavailability of
the export terminals. However, significant improvements were made in Q4 2022
as we began to evacuate the bulk of our crude through the newly operational
Amukpe-Escravos underground pipeline. The average reconciliation loss factor
for the Group was 10.7%.

Gas sales revenue declined marginally by 2.1% to close the year at $112.5
million (2021: $114.8 million) because of weaker average realised gas prices
following price reviews conducted in the second quarter of the year, down 1.1%
to $2.82/Mscf (2021: $2.85/Mscf). Nevertheless, gas sales volumes improved
despite the effect of oil evacuation curtailments and increased 4.1% to 41.0
Bscf, compared to 39.4 Bscf in 2021.

Gross profit

Gross profit increased by 63.0% to $464.7 million (2021: $285.2 million) and
benefitted from higher realised oil prices.
Non-production costs consisted primarily of $180.8 million in royalties, which
was higher compared to $129.8 million in 2021 because of higher oil prices,
and DD&A of $128.7 million, which was lower compared to $141.1 million in
2021, reflecting lower depletion of reserves because of decreased production
compared to the prior year.

Direct operating costs, which include crude-handling fees, barging/trucking,
operation and maintenance costs, amounted to $166.1 million in 2022, 3.1%
lower than the $172.1 million incurred in 2021. However, on a cost-per-barrel
equivalent basis, production opex was $10.3/boe, 4.4% higher than the $9.9/boe
incurred in 2021, primarily because of the effect of lower produced volumes,
an excess storage charge on use of the Escravos terminal, and the higher cost
of crude handling on the AEP, when compared to the TFP.

Operating profit

The operating profit for the period was $274.7 million, an increase of 9.6%,
compared to $250.7 million in 2021.

The Group recognised a financial asset charge of $6.4 million related to the
ageing of some government receivables, which is expected to reverse once
recoveries are secured. Included in other income was a $13.1 million loss on
disposal for the sale of the Ubima field. In addition, there was an over-lift
charge of $27.2 million, representing 263 kbbl. and a $1.1 million loss on
foreign exchange, principally due to the translation of Naira, Pounds and
Euro-denominated monetary assets and liabilities.

General and administrative expenses of $137.4 million were 71.5% higher than
the 2021 costs of $80.1 million. The increase was driven by the impact of
global inflationary trends on expenses, including travel and training costs
(activities having increased following the relaxation of travel restrictions),
increased spending on professional and consulting fees associated with
business growth strategies and the upward adjustments to staff salaries and
emoluments to reflect the true cost of living. The bulk of the staff costs are
denominated and paid in Naira but translated in the financial statements at
the NAFEX currency exchange rate, which does not reflect fully the
macroeconomic reality of the strength of the Naira against the USD. A
correction downwards in the exchange rate will lower the USD reported costs
accordingly.

After adjusting for non-cash items, which include impairment and exchange
losses, the EBITDA of $416.9 million, equates to a margin of 43.8% for the
period (2021: $371.8 million; 50.7%).

Taxation

The income tax expense of $99.7 million includes a current tax charge (cash
tax) of $67.7 million and a deferred tax charge of $32.0 million. The deferred
tax charge is driven by the unwinding of previously unutilised capital
allowances and movements in underlift/overlift in the current year. The
effective tax rate for the period was 49% (2021: 34%). The higher tax this
year resulted from higher taxable profit due to higher oil prices.

 Effective tax rate analysis    Income tax expense          Tax rate
 Profit before tax ($'million)  Current  Deferred  Total    ETR                    Current

                                                            (Effective Tax Rate)   Tax rate
 204.4                          67.7     32.0      99.7     49%                    33%

 

Net result

The profit before tax was 15.2% higher at $204.4 million (2021: $177.3
million). The profit for the year was $104.7 million (2021: $117.2 million)
with a resultant basic earnings per share of $0.11 in 2022, compared to $0.24
per share in 2021.

 

Cash flows from operating activities

Cash generated from operations in 2022 was $571.2 million, 51.6% higher than
$376.8 million generated in 2021. Net cash flows from operating activities
were 41.6% higher at $497.3 million (2021: $352.3 million) after accounting
for tax paid of $57.5 million (2021: $13.0 million) and a hedging premium of
$10.3 million (2021: $9.0 million).  The Group continued to record
improvements in the recovery of receivables from the major JV partner and, in
2022, received $259 million towards the settlement of cash calls. As a result,
the major JV receivable balance now stands at $91 million (2021: $83.9
million); these are mainly cash calls owed within the last 60 days and are
expected to be settled within Q1 2023. As of February 2023 we have received
more than $70 million as part settlement of the 2022 outstanding amounts.

 

Cash flows from investing activities

Net capital expenditure of $163.3 million included $94 million invested in
drilling and $64 million in oil and gas engineering projects.

Deposits for investment of $140.3 million include a $128.3 million (which is
refundable) deposit for the proposed acquisition announced in February 2022 of
Mobil Producing Nigeria Unlimited and the $12.0 million farm-in fee for the
Abiala marginal field carved out of OML 40.

The Group received total proceeds of $10.8 million in the period under the
revised OML 55 commercial arrangement with BelemaOil for the monetisation of
298.4 kbbls of crude oil. In 2022, recovery was affected by sabotage along the
Nembe Creek Trunk Line and the Trans Niger Pipeline, with theft factors
ranging from 30% to 90%.

Cash flows from financing activities

The Company paid $58.8 million dividends to shareholders in the period. Other
financing charges of $12.5 million reflect the commitment fee and other
transaction costs on the Group's facilities, and $63.3 million reflects
interest paid on loans and borrowings.

Liquidity

The balance sheet remains healthy with a solid liquidity position.

 Net debt reconciliation at 31 December 2022               $ million  Coupon             Maturity
 Senior notes*                                             666.8      7.75%              April 2026
 Westport RBL*                                             8.2        SOFR rate+8%       March 2026
 Off-take facility*                                        95.2       SOFR rate+10.5%    April 2027
 Total borrowings                                          770.2
 Cash and cash equivalents (exclusive of restricted cash)  404.3
 Net debt                                                  365.9

* including amortised interest

Seplat Energy ended the year with gross debt of $770.2 million (with
maturities in 2026 and 2027) and cash at bank of $404.3 million, leaving net
debt at $365.9 million. The restricted cash balance of $23.9 million includes
$8.0 million and $12.5 million set aside in the stamping reserve and debt
service reserve accounts for the revolving credit facility; in addition to
$0.8 million and $1 million for rent deposit and unclaimed dividend,
respectively. We monitor the gearing ratio with the objective to maintain a
net debt to gearing ratio of 20%-40%. The ratio for 2022 was 17% (2021: 21%).

Refinancing of the $350 million revolving credit facility (RCF)

On 30 September 2022, Seplat Energy Plc refinanced its existing $350 million
revolving credit facility due in December 2023 with a new three-year $350
million revolving credit facility due in June 2025. The RCF includes an
automatic maturity extension until December 2026 once a refinancing of the
existing $650 million bond due in April 2026 is implemented. The RCF is
scheduled to reduce from July 2024, with such date automatically extended to
July 2025 once the existing $650million bond is refinanced. The RCF carries an
initial interest of 6% over the base rate (SOFR plus applicable credit
adjustment spread), with the margin reducing to 5% after production flowing
through the Amukpe-to-Escravos pipeline is stabilised at an average working
interest production of at least 15,000 bopd over a period of 45 consecutive
days, which was achieved on 1 February 2023 The pricing is in line with the
current RCF pricing, although it reflects a change in the base rate from LIBOR
to SOFR plus the applicable credit adjustment spread.

Final and Special Dividend

Board has recommended a final dividend of US2.5 cents per share for the
financial year 2022 and following a review of Seplat's operational, liquidity
and financial position post refinancing the Board has decided to declare an
additional special dividend of US5.0 cents per share to be paid after approval
at the Annual General Meeting, which will be held in Lagos, Nigeria, on 10 May
2023.  This brings the total dividend declared for 2022 to US15 cents per
share (2021: US10 cents per share). The payment of the special dividend
reflects the Board's confidence in the future of the business and is
underpinned by a strong balance sheet.

Hedging

Seplat's hedging policy aims to guarantee appropriate levels of cash flow
assurance in times of oil price weakness and volatility. The total volume
hedged in 2022 was 7.5 MMbbls, and the current program consists of dated Brent
put options of 3.0 MMbbls at an average premium of $1.07/bbl. Additional
barrels are expected to be hedged for 2023 in the coming months in line with
the approach to target hedging two quarters in advance. The Board and
management team closely monitor prevailing oil market dynamics and will
consider further measures to provide appropriate levels of cash flow assurance
in times of oil price weakness and volatility.

 

 Oil put options         Q1 2022  Q2 2022  Q3 2022  Q4 2022  Q1 2023  Q2 2023
 Volume hedged (MMbbls)  2.0      2.0      2.0      1.5      1.5      1.5
 Price hedged ($/bbl.)   52.5     55       57.5     65       50       50

Conversion to PIA fiscal regime

The Petroleum Industry Bill was signed into law on 16 August 2021 and provides
for the voluntary conversion of existing prospecting licenses and mining
leases to the terms of the PIA within 18 months, i.e., February 2023 or at the
expiration of such licenses and leases.

In October 2022, following the Group's review of the fiscal provisions of the
PIA, Seplat West Limited (OMLs 4, 38 & 41) and Seplat East Onshore Limited
(OML 53) together with their respective joint venture partners (NEPL and
NNPCL) made provisional applications to NUPRC "the Commission" for the
voluntary conversion of operated Oil Mining Leases according to section 92 and
93 of the PIA in October 2022. NEPL, the operator of OML 40, together with
Elcrest, also made a conversion application.

The pursuit of conversion was based on our assessment of the new PIA fiscal
terms, specifically the improved oil and gas royalty structure and rates, tax
system and introduction of production-based allowance, all of which resulted
in an overall net favourable position for Seplat Energy.

In fulfilment of section 92 (4) - (6) of the PIA, Seplat executed the
conversion contract on 15 February 2023, which confers on applicants the right
but not an obligation to complete the conversion to the PIA. The contract
includes a longstop date of 30 April 2023 (or any later date agreed by the
Commission), by which time key regulations and guidelines are expected to be
issued by the Commission, and all conversion conditions have either been
satisfied by the applicant or waived ("effective date"). Ministerial approval
of the conversion of OMLs/OPLs to PMLs/PPLs will remain subject to meeting all
Conditions Precedent.

Seplat continues to monitor the regulatory landscape ahead of 30 April and
reserves the right to withdraw or amend the application following when the
full scope of the PIA's impact on its assets is assessed.

Credit ratings

Seplat maintains corporate credit ratings with Moody's Investor Services
(Moody's), Standard & Poor's (S&P) Rating Services and Fitch. The
current corporate ratings are as follows: (i) Moody's Caa1 (stable); (ii)
S&P B (stable) and (ii) Fitch B- (stable).

The Group's substantial exposure to the Nigerian operating environment led to
a downgrade by Fitch and Moody's, in November 2022 and February 2023
respectively, as both agencies downgraded the Sovereign. Fitch downgraded
Seplat Energy Plc's Long-Term Issuer Default Rating (IDR) and senior unsecured
rating to 'B-' from 'B', and Moody's downgraded the ratings to Caa1 from B3.

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