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Gulfport EnergyDIVERSIFIED, CONVENTIONAL OIL &
GAS PRODUCTION AND EXPLORATION
IN NORTH AMERICA
ANNUAL REPORT 2019
30 JUNE 2019 | OTTO ENERGY LIMITED
ANNUAL REPORT 2019
CONTENTS
CHAIRMAN’S REPORT
MANAGING DIRECTOR’S REPORT
HIGHLIGHTS OF THE YEAR
STRATEGY
ASSET OVERVIEW
RESERVES & PROSPECTIVE
RESOURCES
FINANCIAL REPORT 2019
4-5
6-7
8-9
10-11
12-21
22-28
29
3
CHAIRMAN’S
REPORT
Dear Shareholders,
It is my pleasure to present the 15th Annual Report to shareholders as Otto Energy
continues to build its North American oil and gas business.
Gulf of Mexico this year, including three discoveries
with several more wells to drill in this current
program. Looking forward we are excited by the
investment opportunities we see in the Gulf of
Mexico which will allow us to grow Otto Energy into
a profitable mid-size oil and gas company whilst
remaining strictly focused on what we know best,
ie building a portfolio of profitable conventional oil
and gas projects.
Last but not least, I have recently announced
that, after 12 years on the Board and 3 years as
Chairman, I have elected to retire as Chairman,
although I will remain on the Board as an
independent non executive director. It has been a
privilege to be able to guide Otto Energy through its
recent period of transition and I wish my successor
Mr Ian Boserio much success as Chairman. I thank
you the shareholders for your support, the directors
for their guidance and the management and staff
for their commitment.
John Jetter
Chairman
The last 12 months have again been an exciting
and successful period of activity for the company
with the establishment of a growing presence in the
Gulf of Mexico, with new discoveries at Lightning,
Green Canyon 21, and potentially Mustang (of
which Lightning is already in production) and thus
the establishment of a more stable and growing
production base spread over multiple projects.
Otto Energy has successfully made the transition
from an exploration company to a production
company with further exploration upside.
The company drilled six wells in North America
last year with three successes in the Gulf of Mexico,
establishing a strong reputation as a committed
and proficient partner.
In addition, we are negotiating a financing package
that is expected to cover our ongoing and future
development expenditure.
We are proud of our partnerships with Hilcorp
Energy, Talos Energy and Byron Energy as operators.
That having been said we are determined not to
lose focus on the creation of value for shareholders.
We will maintain our analytical discipline and only
invest in projects which meet our strategic and
financial criteria. We will focus on smart capital
management to maximize returns as we continue
to build our portfolio and pipeline.
Our local team in Houston has been established
and has a significant depth of experience that has
contributed to our successful partnerships in the
4
5
ANNUAL REPORT 2019 MANAGING DIRECTOR’S
REPORT
Dear Shareholders,
It is my pleasure to present Otto Energy’s FY 2019 annual report. The year has seen
Otto grow its platform of production in the Gulf of Mexico with the commencement of
production from the Lightning project with partner, Hilcorp Energy. This production,
in addition to the already producing SM 71, will underpin Otto’s future activities within
the core focus area of the Gulf of Mexico.
The Houston office is now well-established, with a
highly experienced team who have previously delivered
significant success in the Gulf of Mexico. The team
has enabled technical evaluation of a large number of
potential opportunities, now screened and short-listed.
The support of Otto’s shareholders has been
significant and we look forward to rewarding that
support with the achievement of our growth goals
and targets leading to value creation of shareholder
value. The outlook for 2020 encompasses significant
activity in the coming year, with the expected drilling
of the Beluga exploration well with Hilcorp, a second
development well at Lightning with Hilcorp, further
activity at SM 71 with Byron Energy, the testing of
the Mustang discovery with Hilcorp Energy and the
completion of the GC 21 well for production with
partner Talos Energy.
The support of Otto’s shareholders, staff and my
fellow directors throughout this period has been
greatly appreciated. Thank you once again for your
ongoing endorsement of Otto Energy and I look
forward to releasing the results of our active program
of projects in North America in FY20.
Matthew Allen
Managing Director
Otto has positioned itself with quality partnerships
and assets, with an active pipeline of development
and exploration projects to advance the business and
create shareholder value through successful
execution of strategy.
Our core focus on the Gulf of Mexico stems from
its attractiveness with respect to established and
accessible infrastructure, well-understood geology
and petroleum systems, and availability of services
and partnerships focused on conventional oil and
gas. The use of new technology in seismic processing
has enabled overlooked opportunities to be unlocked.
There is opportunity for a company such as Otto to
grow a business with key partnerships in the Gulf of
Mexico whilst competition for conventional oil and
gas assets is historically low.
Otto’s near-term focus is on building a 5000 boepd
business by the end of CY 2020. Otto’s flagship SM
71 development plus discoveries at Lightning, Green
Canyon 21 and potentially Mustang have created a
platform to achieve this strategic goal. We have made
further major steps in this year setting up the next
round of exploration drilling activities and beyond.
Otto has 3-4 wells remaining in its exploration drilling
portfolio, with other opportunities under evaluation.
Development drilling at Lightning and SM 71 also
present opportunities to step-up production from
existing projects. Development funding is being
finalized to enable Otto to participate in these value
accretive, lower risk opportunities stemming from its
successful partnerships and drilling.
6
ANNUAL REPORT 2019
Perth, Western Australia
7
2019 HIGHLIGHTS
Otto Energy Limited is an oil and gas exploration
and production company with a regional focus on
North America.
2019 saw an increase of production
to 741,626 boe, growth of
282%
over 2018 production.
Net Revenue
US$31.2m
up from US$9.5 m in 2018.
EBITDAX1 of
US$23.5m
up from US$5.0m in 2018.
Cashflow from operating activities
(before exploration costs)1 of
US$23.7m
Proved Reserves2 (1P) growth of
49% to 3.670 MMboe
(Net to Otto)
2P Reserves2 of
7.103 MMboe
(Net to Otto)
3P Reserves2 of
10.152 MMboe
(Net to Otto)
One new project began production
in the Gulf of Mexico (Lightning) to
add to steady production from the
SM 71 project.
Three exploration discoveries
from wells drilled in 2019
reported in the Gulf of Mexico
at Lightning, Mustang and
Green Canyon 21 shallow
and deep targets (reported
subsequent to year end).
Perth
Australia
1 Refer to ASX announcement, Financial Report for the year
to June 2019, released 26 September 2019 for notes regarding
non-IFRS information and reconciliation.
2 Refer to Reserves & Prospective Resources statement for
the year ended 30 June 2019 on pages 22-28 of this report for
additional disclosures.
8
ANNUAL REPORT 2019
Alaska Project
OTTO HAS NO DEBT,
EXTINGUISHING OUTSTANDING
CONVERTIBLE NOTES DURING
FY19 FOLLOWING A SUCCESSFUL
PLACEMENT AND RIGHTS ISSUE.
OTTO’S GROWTH STRATEGY IS
UNDERPINNED BY PRODUCTION
AND CASH FLOW FROM FLAGSHIP
GULF OF MEXICO SM 71 ASSET
AND THE LIGHTNING FIELD.
Louisiana &
Gulf of Mexico
production and
exploration
projects
9
STRATEGY
The company’s core strategic goal is to grow
production in the Gulf of Mexico to 5000 boepd by
the end of 2020.
As at the date of this report the status of execution
of this strategy is as follows.
•
•
•
•
•
Through successful exploration Otto has built a
portfolio of four conventional oil and gas properties
in the US Gulf of Mexico and Gulf Coast with two in
production and two in the development/evaluation
stage. These four projects, when all in full
production (anticipated in the second half of 2020),
are expected to take Otto close to its stated goal of
5,000 boepd;
Growth strategy underpinned by strong production
and cash flow from flagship Gulf of Mexico SM
71 asset and the onshore Lightning field that
commenced production in May 2019;
Exciting pipeline of up to four high-impact
exploration opportunities as well as development
wells taking place over the next six months;
Progressing a finance facility for funding current
and future developments thus allowing Otto to
continue to look for further growth opportunities in
the Gulf of Mexico; and
An experienced team located in Houston with a
track record of successfully growing, operating
and divesting oil and gas assets globally who
understand risk and capital management.
Gulf of Mexico
The Company’s strategy is currently focused on
growing its business in the Gulf of Mexico for the
following reasons:
•
Proven prolific hydrocarbon province where
technologies such as RTM seismic processing
continue to create new opportunities;
• Low sovereign risk;
•
•
High margin oil with breakeven economics around
US$20/barrel;
Short cycle time from discovery to development of
8-18 months;
• Low cost drilling and development;
• Relatively low risk exploration;
•
•
Deal flow is liquid and a full spectrum of
opportunity size is available;
Otto has area expertise and well developed
business relationships; and
• Otto has production in the area.
10
In order to deliver on the strategy, the Company’s business development focus over the past year in the Gulf of
Mexico has been on pursuing prospects with the following characteristics:
•
•
•
Miocene/Pliocene/Oligocene geology which are
amplitude supported;
Investing capital into drilling, not seismic;
Seeking early cashflow/ROI – Approximately 12-18
months from exploration to production;
•
Progressing from the shallow water
( 300 feet) and onshore to smaller manageable
working interests in the deeper transition zone
following exploration success – keeping capex
manageable; and
• High liquids yields to increase margins.
11
ANNUAL REPORT 2019 ASSET OVERVIEW |
Otto Energy SMI Block 71 Platform
TODAY, ABOUT HALF OF
THE USA’S FOSSIL FUEL
REFINING AND PROCESSING
CAPACITY IS ALONG THE
GULF OF MEXICO.
US Energy Information
Administration
12
ANNUAL REPORT 2019
ASSET OVERVIEW
North America
GULF OF MEXICO
Otto Energy considers the Gulf of Mexico a core
region for its exploration and production focus.
Today, Otto produces oil and gas from two projects
in the Gulf of Mexico, SM 71 and Lightning.
The Gulf of Mexico (GoM) region is one of the
most prolific oil and gas producing regions on
earth. About half of the USA’s fossil fuel refining and
processing capacity is along the GoM. The high density
and availability of production platforms utilised for the
development of primary reservoirs contributes to low
production costs in the region, making projects viable
even in a sustained, low oil price environment.
Otto has focused on a partnership strategy in the
GoM to build a portfolio of diverse, conventional oil
and gas opportunities. Otto’s current operating
partners in the Gulf of Mexico are Byron Energy
(ASX: BYE), Hilcorp Energy, and Talos Energy
(NYSE: TALO). Otto drilled four wells with Hilcorp
Energy in 2019. This lead to a discovery at Lightning,
and resulting maiden production and reserves, and
a potential discovery at Mustang, which commenced
production testing in October 2019.
Otto has up to four additional wells to drill with
Hilcorp Energy as part of its original eight exploration
well agreement signed in July 2018. Otto drilled
an appraisal well with exploration upside with Talos
Energy at GC 21, which, subsequent to year end,
discovered commercial hydrocarbons and is currently
undergoing development planning set for completion
in mid-2020.
Summary of Gulf of Mexico Assets as at 30 June 2019
Asset
Gulf of Mexico Region
South Marsh Island 71 (SM 71)
Lightning
Green Canyon 21 (GC 21)
Mustang
Beluga
Mallard
Tarpon
Oil Lake
Vermillion 232 (VR 232)
Otto
Working
Interest
(WI)
Otto net
revenue
interest
(NRI)
50%
37.5%
16.67%
37.50%
37.50%
37.50%
37.50%
37.50%
100%
40.63%
28.57%
13.34%
28.50%
30.00%
29.63%
29.06%
29.06%
87.50%
Joint Venture
Partners
Byron Energy
Hilcorp Energy
Talos Energy (Operator) /
EnVen Energy Ventures, LLC
Hilcorp Energy
Hilcorp Energy
Hilcorp Energy
Hilcorp Energy
Hilcorp Energy
n/a
Notes
Production
Production
Development
Production Testing
Exploration
Exploration
Exploration
Exploration
Exploration
13
ASSET OVERVIEW (continued)
Production - South Marsh Island 71
Otto owns a 50% Working Interest (‘WI’) and a
40.625% Net Revenue Interest (‘NRI’) in the South
Marsh Island block 71 (‘SM 71’), with Byron Energy
Limited (‘Byron’) the operator, holding an
equivalent WI and NRI. Water depth in the area
is approximately 137 feet.
Following the initial discovery by Otto and Byron
in 2016, oil and gas production from the SM 71 F
platform began in late March 2018 from two wells
with the third well coming on line in early April 2018.
The F1 and F3 wells are completed in the primary
D5 Sand reservoir and the F2 well is completed in
the B55 Sand, a secondary exploration target.
14
The SM 71 F facility has now produced over 1.6 million
barrels of oil (gross) since initial production began.
The facility has also produced over 2.4 billion cubic
feet of gas (gross) which, on a revenue basis, is
approximately equivalent to an additional 128,000
barrels of oil.
After the initial expected decline in production,
aquifer support stabilized and in fact, increased
oil production over the second half of the
financial year.
ANNUAL REPORT 2019
ASSET OVERVIEW (continued)
Production and revenue details for the year ended 30 June 2019 are set out below.
Production Volumes
Gross (100%)
SM 71 – Oil (bbls)
SM 71 – Oil (bopd)
SM 71 – Gas (Mscf)
Otto WI Share (50%)
SM 71 – Oil (bbls)
SM 71 – Oil (bopd)
SM 71 – Gas (Mscf)
Otto NRI Share (40.625%)
SM 71 – Oil (bbls)
SM 71 – Oil (bopd)
SM 71 – Gas (Mscf)
30-Sep-18
31-Dec-18
31-Mar-19
30-Jun-19
Quarter Ended
324,597
3,528
355,605
162,298
1,764
177,802
131,868
1,433
144,464
271,074
2,946
582,593
135,537
1,473
291,296
110,124
1,197
236,678
255,880
2,843
607,580
127,940
1,422
303,790
103,951
1,155
246,829
264,992
2,912
469,196
132,496
1,456
234,598
107,653
1,183
190,611
Sales Revenue –
Otto 50% WI share (before royalties)
USD
Quarter Ended
30-Sep-18
31-Dec-18
31-Mar-19
30-Jun-19
SM 71 – Oil - $’million
SM 71 – Oil - $ per bbl
SM 71 – Gas - $’000
SM 71 – Gas – $ per MMbtu
Notes
11.17
68.82
615
3.17
8.25
60.85
1208
3.81
6.99
54.65
977
2.93
8.16
61.59
643
$2.49
1.
Otto sells its high quality Louisiana Light Sweet crude (‘LLS’) produced at SM 71 at premium to West Texas Intermediate (‘WTI’) based on
current LLS versus WTI price differentials. Deductions are then applied for transportation, oil shrinkage, basic sediment & water (BS&W),
and other applicable adjustments.
2.
Gas revenues include NGLs. 1 Mscf = 1.09 MMbtu in June for SM 71 production. The thermal content of SM 71 gas may vary over time.
Production - Lightning
The Green #1 well on the Lightning prospect in
Matagorda County, Texas commenced drilling in
early December 2018. The well reached total depth of
15,218ft MD (15,216ft TVD) in early February 2019 with
wireline logs indicating 180 feet of net pay, significantly
in excess of pre-drill expectations.
Through participation in the drilling of the Lightning
exploration well, Otto earned a 37.5% working interest
in the leases covering the Lightning prospect.
Following the discovery, facilities were installed and
the well was connected to a nearby sales gas pipeline.
Perforations and testing occurred during April
and May with the well reaching steady state production
of 12 MMscf/day in raw gas and 365 bbl/day in
condensate (Otto’s 37.5% Working Interest is 4.5
MMscf/d and 137 bbls/d) in late June 2019.
Commissioning hydrocarbon sales in May and
June 2019 contributed to Otto revenue for FY 2019,
with the first full month of contribution occurring in
July 2019. First sales proceeds were received in
July 2019.
15
ASSET OVERVIEW (continued)
Production and revenue details for the year ended 30 June 2019 are set out below.
Production Volumes*
Gross (100%)
Lightning – Oil (bbls)
Lightning – Gas (Mscf)
Lightning – NGLs (bbls)
Otto WI Share
Lightning – Oil (bbls)
Lightning – Gas (Mscf)
Lightning – NGLs (bbls)
Otto NRI Share
Lightning – Oil (bbls)
Lightning – Gas (Mscf)
Lightning – NGLs (bbls)
2019
5,685
167,393
7,591
2,132
62,772
2,847
1,624
47,822
2,169
Sales Revenue –
Otto 37.5% WI share (before
royalties) Volumes*
USD
Oil - $’million
Oil - $ per bbl
Gas - $’000
Gas – $ per MMbtu
NGLs - $’000
NGLs – $ per bbl
2019
0.13
60.70
143.33
2.32
31.54
11.08
* Lightning annual production reflects only limited production during start up and commissioning of field during May and June 2019.
July 2019 full month production totalled 10,000 bbl and 343 MMscf of Raw Gas (8/8ths).
The joint venture is progressing the drilling of a second well, Green #2 development well, in the field commencing
in October 2019. Full field development may require up to five wells to fully develop the Lightning accumulation.
Lightning location map
16
ANNUAL REPORT 2019
ASSET OVERVIEW (continued)
Development - Green Canyon 21
On 29 March 2019 Otto announced that it has
entered into a joint venture with Talos Energy
(NYSE: TALO) which will see it earn a 16.67%
working interest in the Green Canyon 21 (GC-21)
lease in the Gulf Mexico through paying 22.22% of
the cost of the drilling of the ‘Bulleit’ appraisal
well in GC-21.
The ‘Bulleit’ appraisal well commenced drilling
on 6 May 2019. On 13 June 2019, The Company
announced that the upper target, the DTR-10
sand, was intersected and a commercial
outcome was confirmed.
On 8 August 2019 Otto announced that the
GC 21 ‘Bulleit’ well, operated by Talos Energy,
had been successfully drilled to Total Depth
despite challenging conditions. The well drilled
through the deeper exploration target, the MP
sands, after intersecting oil pay in the shallower
DTR-10 sand package as announced to the ASX on
13 June 2019. The well intersected the following
discovered intervals:
•
•
DTR-10 interval –net 140 feet of TVD oil pay
encountered; and
MP interval – approximately net 110 feet of
TVD oil pay expected to be delivered in high
quality reservoir consistent with analogue
wells in the GC18 field.
Following the discovery in the DTR-10 sands,
attempts to drill to the deeper objective MP
sands were delayed due to poor hole conditions
and compromised drilling operations requiring
sidetracking. In addition, the passing of Hurricane
Barry required the rig to disconnect to ensure safe
operations. As a result of these operations, the cost of
drilling the GC21 ‘Bulleit’ well exceeded the pre-drill
estimates of US$9.0m net to Otto.
The GC 21 development plan is being progressed
by the Operator to complete the discovery well in
mid-2020. The Operator will complete the well as
a production well and then tie it back to the Talos-
owned and operated Green Canyon 18 (GC 18A) facility
approximately 10 miles (~16 km) west of the ‘Bulleit’
well. The development will involve the use of a subsea
completion that is common for projects of this nature
and water depth in the Gulf of Mexico.
The joint venture undertook a review of the
development plan in late September 2019. Under the
plan the operator expects to complete the well in mid-
2020 with first production in late Q3 2020.
Subject to the commitment to development outlined
above, Otto will report maiden reserves from the GC21
discovery incorporating the development plans.
17
ASSET OVERVIEW (continued)
Green Canyon 21 proximity to Green Canyon 18A platform
GC21 and GC18 location map
18
ANNUAL REPORT 2019
ASSET OVERVIEW (continued)
Testing - Mustang
On 1 May 2019, Otto announced that drilling of the
Mustang exploration prospect had commenced.
On 23 July 2019, Otto announced that the Mustang
prospect exploration well, Thunder Gulch #1,
successfully intersected a minimum 57 feet TVT
of net hydrocarbon pay and would be completed
for production testing. On 19 September 2019 Otto
announced that the operator has sourced equipment
required for the testing of the deep, high pressure
Mustang discovery. With reservoir pressures at the
discovery location of over 15,000 psi, specialised high-
pressure equipment is required that is not commonly
Mustang location map
used. The initial testing will involve the perforation
of various discovery intervals in order to understand
reservoir deliverability and the design of a completion
program to optimise ultimate production.
Once the testing phase of the discovery is
completed, the joint venture would then plan for the
installation of surface production equipment and
the connection into a nearby sales pipeline to enable
production to commence. This is expected to occur
during Q4 2019, subject to the outcome of the current
test program.
19
ASSET OVERVIEW (continued)
Exploration – Hilcorp Package
In late July 2018, Otto announced that it had entered into a joint venture with Hilcorp Energy to drill an eight
well portfolio of prospects in the Onshore/Near Shore USA Gulf Coast (Gulf of Mexico), with Hilcorp as Operator.
Four wells have now been drilled (Big Tex, Lightning, Don Julio 2 and Mustang) with Lightning and Mustang being
discoveries. There are four wells left in the eight well program with Hilcorp which are expected to be drilled over
the next 6-9 months, subject to finalising regulatory and permitting approvals. Beluga is expected to commence
drilling in the fourth quarter of 2019.
Prospect Name
(State)
Working
Interest
Net
Revenue
Interest
Target
Depth
(TVD) ft
Probability
of Success
Beluga, TX
Mallard, LA
Tarpon, TX
Oil Lake, LA
37.5%
37.5%
37.5%
37.5%
28.5%
29.63%
29.06%
29.06%
13,000
11,000
14,000
14,500
45%
64%
34%
45%
Prospective Resources (MMboe)
Otto Net Revenue Interest
P90
0.2
0.1
2.2
0.3
P50
0.9
0.3
7.0
1.0
Mean
1.4
0.5
10.5
1.3
P10
3.4
1.3
23.5
2.7
Prospective Resources Cautionary Statement -
The estimated quantities of petroleum that may potentially be recovered by the application of future development
projects relate to undiscovered accumulations. These estimates have both an associated risk of discovery and
a risk of development. Further appraisal and evaluation is required to determine the existence of a significant
quantity of potentially moveable hydrocarbons.
Additional Upside – Hilcorp Package
With the successful drilling of the Mustang
prospect, Otto has ground floor rights (ie pays only
its working interest) to participate in the nearby
Corsair/Hellcat opportunities. These wells are in
addition to the eight wells in the original program
announced with Hilcorp. Should the Tarpon
prospect be successful then Otto has ground
floor rights (ie. It pays only its working interest) to
participate in the nearby Damsel opportunity.
Under a Joint Exploration and Development
Agreement (JEDA) with Hilcorp, Otto has a right
of first offer to a subsequent Gulf Coast program,
if Hilcorp elect to offer such a program to
third parties.
20
Exploration - VR 232
In May 2019 Otto acquired Byron Energy’s 50% interest
in, and operatorship of, VR 232 at no cost. Following
completion of the transfer, Otto’s interest is now 100%
and net revenue interest is 87.5%.
VR 232 is adjacent to Otto’s 50% owned SM 71 oil field
and adds drilling opportunities which increase Otto’s
potential upside around the SM 71 facilities. Over 2 Bcf
of gas and 30 Mbbls of oil have been produced from
VR 232 between 1995 and 1997.
Otto has recently acquired a modern, high quality 3D
seismic data set over the SM 71 area (including VR
232) and part of the work being done will focus on the
prospectivity of VR 232 given its proximity to SM 71.
ANNUAL REPORT 2019
ASSET OVERVIEW (continued)
Exploration - ALASKA
Asset
Otto Working
Interest (WI)
Otto net revenue
interest (NRI)
Joint Venture Partners
Notes
Alaska North Slope (Western Blocks)
22.50%
18.75%
Alaska North Slope (Central Blocks)
8-10.8%
6.7%-9.5%
88 Energy (ASX:88E) /
Red Emperor Resources NL
(ASX:RMP)
Pantheon Resources
(AIM:PANR)
Exploration
Exploration
Western Blocks
Otto holds a 22.5% working interest in the joint
venture with 88 Energy (ASX:88E) and Red Emperor
Resources NL (ASX:RMP) in four leases comprising
the ‘western blocks’ totaling over 22,710 acres. Key
activities during the year included the drilling of the
Winx Prospect. The Winx-1 well commenced drilling
on 15 February 2019 and intersected all of the pre-drill
targets safely and efficiently. Total Depth of 6,800’
was reached on 3 March 2019. A comprehensive
wireline logging program was then successfully
run and completed.
Provisional petrophysical analysis of the wireline
logging program indicated low oil saturations in
the primary Nanushuk Topset objectives; testing
and fluid sampling indicated that reservoir quality
and fluid mobility at this location was insufficient to
warrant production testing, despite encouragement
from oil shows and logging while drilling (LWD)
data. Winx-1 was subsequently plugged and
abandoned.
The forward plan is to further evaluate and integrate
the valuable data acquired at Winx and reprocess
the Nanuq 3D seismic (2004) in order to evaluate
the remaining prospectivity on the Western Leases
including the Nanushuk Fairway potential.
Central Blocks
Through its agreements with Great Bear
Petroleum Operating (‘Great Bear’) in 2015,
Otto has between an 8% and 10.8% working
interest in 54 leases (covering 154,295 gross
acres) held by Pantheon Resources plc
(AIM:PANR) on the Alaskan North Slope
(‘Central Blocks’).
The leases are in a major play fairway south of the
Prudhoe Bay and Kuparuk giant oil fields.
Extensive, modern 3D seismic coverage, existing
well control and proximity to the all-weather Dalton
Highway and Trans-Alaskan Pipeline System (TAPS)
means the acreage is well positioned for exploration.
The existing 3D seismic has allowed development of
an extensive prospect portfolio which includes at
least 4 well locations.
Otto’s exposure on the first two wells is limited to
US$2.6m/well. Otto had no activity in this area during
the year ended 30 June 2019. 19 leases deemed
unprospective were relinquished during the year and
a further 17 transferred to Burgundy Xploration
LLC for US$6,054.
21
RESERVES & PROSPECTIVE RESOURCES
On 19 September 2019 the Company released its statement of reserves and
prospective resources as at 30 June 2019. The statement of reserves included
SM 71 and the maiden statement of reserves for Lightning. The reserves for SM 71
and Lightning were compiled by independent consultants Collarini and Associates
and Ryder Scott Company respectively. The summary statement of reserves and
prospective resources at 30 June 2019 is set out below. SM 71 and Maiden reserves for
the Lightning gas/condensate field are set out separately following the summary table.
Reserves Summary 30 June 2019
Total
Proved Producing
Proved Behind Pipe
Proved Undeveloped
Proven (1P)
Probable
Proven Plus Probable (2P)
Probable
Proven Plus Probable Plus Possible (3P)
Total Propsective Resource
(best estimate, unrisked)
Oil
(Mbbl)
3,219
682
1,927
5,828
6,094
11,922
3,664
15,586
Gross (100%)
Gas
(MMscf)
12,599
3,765
11,117
27,481
19,823
47,304
34,468
81,772
MBoe
5,318
1,310
3,779
10,407
9,398
19,806
9,409
29,214
Oil
(Mbbl)
1,271
265
746
2,282
2,417
4,699
1,371
6,070
OTTO Net
Gas
(MMscf)
3,910
1,118
3,292
8,320
6,101
14,421
10,072
24,492
MBoe
1,923
452
1,295
3,670
3,434
7,103
3,049
10,152
67,309
89,875
82,289
Prospective Resources Cautionary Statement
The estimated quantities of petroleum that may potentially be recovered by the application of a future development project(s) relate to undiscovered
accumulations. These estimates have both an associated risk of discovery and a risk of development. Further exploration appraisal and evaluation is
required to determine the existence of a significant quantity of potentially moveable hydrocarbons.
Otto Energy Limited net reserves and resources for all fields as at 30 June 2019 are summarised below (see additional disclosures provided in the
following pages and appendices).
Changes to reserves and resources since 30 June 2018
OTTO ENERGY LIMITED: Reserves (NRI Net to OTTO)
Total
Reserves
Reconcilliation
Proved (1P)
Probable
Proved and
Probable (2P)
Possible Reserves
Proved, Probable
and Possible (3P)
Oil (Mbbl)
Gas (MMCF)
Mboe
Remaining
30/06/18
Production
2019
Additions &
Revisions
2019
Remaining
30/06/19
Remaining
30/06/18
Production
2019
Additions &
Revisions
2019
Remaining
30/06/19
Remaining
30/06/18
Production
2019
Additions &
Revisions
2019
Remaining
30/06/19
2,226
3,668
5,894
1,890
7,784
(455)
512
-
(1,251)
(455)
(740)
-
(519)
(455)
(1,259)
2,282
2,417
4,699
1,371
6,070
1,372
2,833
4,205
1,613
5,818
(879)
-
7,827
3,267
8,320
6,100
(879)
11,095
14,420
-
8,459
10,072
(879)
19,553
24,492
2,455
4,140
6,595
2,159
8,754
(602)
-
(602)
1,816
(707)
1,109
3,669
3,433
7,102
-
891
3,050
(602)
2,000
10,152
22
ANNUAL REPORT 2019
RESERVES & PROSPECTIVE RESOURCES (continued)
South Marsh Island 71 Reserves
and Resources Statement:
Comment on the changes to reserves and resources:
•
•
•
SM 71 has now recovered over 1.6 MMbbl of oil
and 2.4 Bcf of gas since production commenced
in March 2018 and is currently producing
approximately 3,200 bopd of oil and 3.4 MMscf/d
of gas;
Production history: Increase in D5 Sand Proved
EUR reserves due to the high rate, water free
production from the D5 reservoir;
Higher gas-to-oil ratio (‘GOR’) observed in
F1 production which effectively increases the
calculated gas in place and in turn decreases
oil in place resulting in a negative revision to
D5 estimated ultimate recoveries and therefore
remaining reserves; and
•
Removal of 68% of the B65 probable reserves as
a result of remapping of the undeveloped B65
reservoir with recently reprocessed 2019 seismic
indicating a smaller area of prospectivity than
previously mapped.
SM71
Proved Producing
Proved Behind Pipe
Proved Undeveloped
Proven (1P)
Probable
Proven Plus Probable (2P)
Probable
Proven Plus Probable Plus Possible (3P)
Total Propsective Resource
(best estimate, unrisked)
Oil
(Mbbl)
2,928
580
1,622
5,120
5,608
10,728
2,686
13,414
Gross (100%)
Gas
(MMscf)
2,575
355
962
3,892
3,627
7,519
1,861
9,380
MBoe
3,347
639
1,782
5,768
6,213
11,981
2,996
14,977
3,665
49,569
11,927
OTTO Net (40.625%)
Gas
(MMscf)
1,046
Oil
(Mbbl)
1,185
236
659
2,080
2,278
4,358
1,091
5,449
1,489
144
391
1,581
1,473
3,055
756
3,811
20,137
MBoe
1,360
260
724
2,344
2,524
4,867
1,217
6,085
4,845
OTTO ENERGY LIMITED: Reserves SM71 (NRI Net to OTTO)
Gulf of Mexico, offshore Louisiana, USA
Oil (Mbbl)
Gas (MMCF)
Mboe
Remaining
30/06/18
Production
2019
Additions &
Revisions
2019
Remaining
30/06/19
Remaining
30/06/18
Production
2019
Additions &
Revisions
2019
Remaining
30/06/19
Remaining
30/06/18
Production
2019
Additions &
Revisions
2019
Remaining
30/06/19
2,226
3,668
5,894
1,890
7,784
(454)
308
-
(1,390)
(454)
(1,082)
-
(798)
(454)
(1,881)
2,080
2,278
4,358
1,092
5,450
1,372
2,833
4,205
1,613
5,818
(819)
-
(819)
1,027
(1,360)
(332)
1,581
1,473
3,054
-
(857)
756
(819)
(1,189)
3,810
2,455
4,140
6,595
2,159
8,754
(590)
-
(590)
479
(1,617)
(1,138)
-
(941)
(590)
(2,079)
2,344
2,523
4,867
1,218
6,085
Reserves
Reconcilliation
SM71(developed &
undeveloped)
Proved (1P)
Probable Reserves
Proved and
Probable (2P)
Possible Reserves
Proved, Probable
and Possible (3P)
Otto holds a 50% working interest (40.625% net revenue interest) in SM 71 through a wholly owned subsidiary Otto Energy (Louisiana) LLC. The operator,
Byron Energy Limited (ASX:BYE) holds the remaining 50% working interest.
23
RESERVES & PROSPECTIVE RESOURCES (continued)
Lightning Reserves
and Resources Statement:
Comment on the changes to reserves and resources:
•
•
Lightning (Green #1): The startup of production
at Lightning in May 2019 has resulted in maiden
additional Probable Reserves (2P) to Otto Energy
of 2,235 Mboe significantly exceeding the pre-drill
prospective resource of 1,300 Mboe
•
Lightning (Green #2): The joint venture is
progressing the drilling of a second well, Green
#2, in the field commencing in October 2019.
Full field development may require up to five wells
to fully develop the Lightning accumulation.
Production from the Green #1 well began in
2Q 2019 and has plateaued at 12 Mscf/day and
360 bopd of condensate since July 2019.
Lightning
Proved Producing
Proved Behind Pipe
Proved Undeveloped
Proven (1P)
Probable
Proven Plus Probable (2P)
Probable
Proven Plus Probable Plus Possible (3P)
Total Propsective Resource
(best estimate, unrisked)
Oil
(Mbbl)
301
102
305
708
486
1.194
978
2,172
Gross (100%)
Gas
(MMscf)
10,024
3,410
10,155
23,589
16,196
39,785
32,607
72,392
MBoe
1,971
671
1,997
4,639
3,185
7,824
6,413
14,237
-
OTTO Net (28.569%)
Gas
(MMscf)
2,864
Oil
(Mbbl)
86
29
87
202
139
341
279
620
-
974
2,901
6,739
4,627
11,366
9,315
20,682
-
MBoe
563
192
571
1,326
910
2,235
1,835
4,067
-
OTTO ENERGY LIMITED: Reserves Lightening (NRI Net to OTTO)
Offshore Texas, USA
Oil (Mbbl)
Gas (MMCF)
Mboe
Remaining
30/06/18
Production
2019
Additions
&
Revisions
2019
Remaining
30/06/19
Remaining
30/06/18
Production
2019
Additions &
Revisions
2019
Remaining
30/06/19
Remaining
30/06/18
Production
2019
Remaining
30/06/19
Additions
&
Revisions
2019
-
-
-
-
-
-
-
(2)
(2)
(2)
204
139
343
279
622
202
139
341
279
620
-
-
-
-
-
(61)
-
6,800
4,627
6.739
4,627
(61)
11,427
11,366
-
9,315
9,315
(61)
20,743
20,682
-
-
-
-
-
(12)
1,337
1,325
-
910
910
(12)
2,247
2,235
-
(12)
1,832
4,079
1,832
4,067
Reserves
Reconcilliation
Total
Proved (1P)
Probable Reserves
Proved and
Probable (2P)
Possible Reserves
Proved, Probable
and Possible (3P)
Note: Gas volumes reported above exclude a 2% shrinkage factor.
Otto holds a 37.5% working interest (28.569% net revenue interest) in Lightning through a wholly owned subsidiary Otto Energy USA Inc. The operator,
Hilcorp, holds the remaining working interest.
24
ANNUAL REPORT 2019
RESERVES & PROSPECTIVE RESOURCES (continued)
Prospective Resource as at 30 June 2019
Refer to comments and notes below the tables for commentary on recent activity related to Prospective Resources.
Gulf Coast Package
Prospect Name
Working
Interest
Net
Revenue
Interest
Prospective Resources
100%
OTTO Net Revenue Interest
Gas (Bcfe)
Oil (Mmbbl)
Mmboe
Gas (Bcfe)
Oil (Mmbbl)
Mmboe
Mean
Mean
Mean
Mean
Mean
Mean
Beluga
Mustang1
Oil Lake
Tarpon
Mallard
37.50%
37.50%
37.50%
37.50%
37.50%
30.00%
28.50%
29.06%
29.06%
29.63%
21.25
37.80
6.73
161.97
7.79
1.21
2.26
3.34
9.21
0.45
4.75
8.56
4.46
47.07
2.31
6.38
10.77
1.95
47.07
2.31
0.36
0.64
0.97
2.68
0.13
1.43
2.44
1.30
10.52
0.52
1 Mustang prospective reserves are pre-drill estimates. The Mustang well is currently being prepared for flow
testing and analysis.
Green Canyon 21
Prospect Name
Working
Interest
Net
Revenue
Interest
GC 21 Bulleit2
16.67%
13.34%
100%
OTTO Net Revenue Interest
Gas (Bcfe)
Oil (Mmbbl)
Mmboe
Gas (Bcfe)
Oil (Mmbbl)
Mmboe
Mean
9.43
Mean
12.93
Mean
14.50
Mean
1.26
Mean
1.72
Mean
1.93
Prospective Resources
2 GC 21 Bulleit prospective reserves are pre-drill estimates. The GC 21 development plan is being progressed by
the Operator to complete the discovery well in mid-2020. The joint venture will undertake a review of the Operator’s
plan of development in the coming month with formal commitment to the development expected shortly thereafter.
Alaska Central North Slope
Prospect Name
Working
Interest
Net
Revenue
Interest
100%
OTTO Net Revenue Interest
Gas (Bcfe)
Oil (Mmbbl)
Mmboe
Gas (Bcfe)
Oil (Mmbbl)
Mmboe
Prospective Resources
Blackbird
Helio
Hellcat
Skywagon
Avenger
Corsair
10.80%
10.80%
10.80%
10.80%
10.80%
10.80%
9 - 9.45%
9 - 9.45%
9 - 9.45%
9 - 9.45%
9 - 9.45%
9 - 9.45%
Mean
Mean
28.40
67.90
74.30
57.70
100.10
330.60
Mean
28.40
67.90
74.30
57.70
100.10
330.60
Mean
Mean
Mean
2.56
6.11
6.69
5.19
9.01
2.56
6.11
6.69
5.19
9.01
29.75
29.75
25
RESERVES & PROSPECTIVE RESOURCES (continued)
Comment on the changes to prospective resources:
•
•
•
Mustang (Thunder Gulch #1): Otto announced on 23 July 2019 that the Thunder Gulch #1 well had
successfully drilled to final total depth of 18,164 feet MD and that petrophysical evaluation had confirmed
the well had intersected a minimum of 57 feet of net pay. Production casing has been run with the well
set for completion and testing due to occur in the coming weeks. Subject to the results of well testing and
commencement of production, Otto expects to convert the Mustang Prospective Resource into Reserves in
the coming months.
Green Canyon 21 (‘Bulleit’): Otto announced on 8 August 2019 that the GC21 Bulleit well had successfully
reached total depth of 15,675 feet MD. The well has intersected 140 feet TVD of net pay in the DTR-10 interval
and a further approximately 110 feet TVD of net pay in the MP interval. The well has been suspended as a
future production well. Otto expects to convert the GC21 Bulleit Prospective Resource into Reserves upon
sanction of the field development expected in the coming months.
Alaska Central North Slope: Otto notes that the operator of the Alaska North Slope, Pantheon Resources
PLC (AIM: PANR) has announced that it will hold an Alaskan Project update in London on 24 September 2019.
Pantheon has entered a partnership with eSeis Inc, a Houston based pioneer in high tech geophysics and
seismic petrophysics, to support Pantheon furthering the geophysical and petrophysical understanding of the
Alaskan Central North Slope exploration potential. Further information will be provided to the market following
Pantheon’s update.
•
VR 232: VR232 is undergoing evaluation after Otto Energy acquired Byron Energy’s (ASX:BYE) 50% interest and
operatorship in VR 232 at no cost (announced to the ASX on 9 May 2019).
Notes to Reserves and Resources Statement
Reserves and Resources Governance
Otto’s reserves estimates are compiled annually.
The operator of SM 71, Byron Energy, engages
Collarini and Associates, a qualified external petroleum
engineering consultant, to conduct an independent
assessment of the SM 71 reserves on behalf of the joint
venture. Collarini and Associates is an independent
petroleum engineering consulting firm that has been
providing petroleum consulting services in the USA for
more than fifteen years. Collarini and Associates does
not have any financial interest or own any shares in the
Company. The fees paid to Collarini and Associates are
not contingent on the reserves outcome of the
reserves report.
own any shares in the Company. The fees paid to Ryder
Scott Company are not contingent on the reserves
outcome of the reserves report.
Competent Persons Statement
The information in this report that relates to oil and
gas reserves and resources at SM 71 was compiled
by technical employees of independent consultants
Collarini and Associates, under the supervision of Mr
Mitch Reece BSc PE. Mr Reece is the President of
Collarini and Associates and is a registered professional
engineer in the State of Texas and a member of the
Society of Petroleum Evaluation Engineers (SPEE),
Society of Petroleum Engineers (SPE), and American
Petroleum Institute (API). The reserves and resources
included in this report have been prepared using
definitions and guidelines consistent with the 2007
Society of Petroleum Engineers (SPE)/World Petroleum
Council (WPC)/American Association of Petroleum
Geologists (AAPG)/Society of Petroleum Evaluation
Engineers (SPEE) Petroleum Resources Management
System (PRMS). The reserves and resources
information reported in this Statement are based on,
Otto engages Ryder Scott Company, a qualified
external petroleum engineering consultant, to conduct
an independent assessment of the Lightning Field
reserves on behalf of Otto. Ryder Scott Company is
an independent petroleum engineering consulting
firm that has been providing petroleum consulting
services in the USA for more than fifty years. Ryder
Scott Company does not have any financial interest or
26
ANNUAL REPORT 2019
RESERVES & PROSPECTIVE RESOURCES (continued)
and fairly represents, information and supporting
documentation prepared by, or under the supervision
of, Mr Reece. Mr Reece is qualified in accordance with
the requirements of ASX Listing Rule 5.41 and consents
to the inclusion of the information in this report of the
matters based on this information in the form and
context in which it appears.
The information in this report that relates to oil and
gas reserves and resources at the Lightning Field
was compiled by technical employees of independent
consultants Ryder Scott Company, under the
supervision of Mr. Ali Porbandarwala PE.
Mr. Porbandarwala is a Senior Vice President at
Ryder Scott Company and is a registered professional
engineer in the State of Texas and a member of the
Society of Petroleum Engineers (SPE). He has a B.S.
Chemical Engineering from the University of Kansas
and an MBA from the University of Texas. The reserves
included in this report have been prepared using
definitions and guidelines consistent with the 2007
Society of Petroleum Engineers (SPE)/World Petroleum
Council (WPC)/American Association of Petroleum
Geologists (AAPG)/Society of Petroleum Evaluation
Engineers (SPEE) Petroleum Resources Management
System (PRMS). The reserves information reported
in this Statement are based on, and fairly represents,
information and supporting documentation prepared
by, or under the supervision of Mr. Porbandarwala.
Mr. Porbandarwala is qualified in accordance with the
requirements of ASX Listing Rule 5.41 and consents
to the inclusion of the information in this report of the
matters based on this information in the form and
context in which it appears.
The information in this report that relates to oil and
gas prospective resources in relation to the Gulf Coast
Package (Mustang, Beluga, Oil Lake, Tarpon and
Mallard) in the Gulf of Mexico was compiled by technical
employees of Hilcorp Energy Company, the Operator
of the Gulf Coast Package, and subsequently reviewed
by Mr Ed Buckle B.S. Chemical Engineering (Magna
Cum Laude) who has consented to the inclusion of such
information in this report in the form and context in
which it appears.
The information in this report that relates to oil and gas
resources in relation to Green Canyon 21 (GC 21) in the
Gulf of Mexico was compiled by technical employees
of Talos Energy and reviewed by Mr Ed Buckle B.S.
Chemical Engineering (Magna Cum Laude), who has
consented to the inclusion of such information in this
report in the form and context in which it appears.
Mr Buckle is an full-time contractor of the Company,
with more than 30 years relevant experience in the
petroleum industry and is a member of The Society of
Petroleum Engineers (SPE). The resources included
in this report have been prepared using definitions
and guidelines consistent with the 2007 Society of
Petroleum Engineers (SPE)/World Petroleum Council
(WPC)/ American Association of Petroleum Geologists
(AAPG)/ Society of Petroleum Evaluation Engineers
(SPEE) Petroleum Resources Management System
(PRMS). The resources information included in this
report are based on, and fairly represents, information
and supporting documentation reviewed by Mr
Buckle. Mr Buckle is qualified in accordance with the
requirements of ASX Listing Rule 5.41 and consents
to the inclusion of the information in this report of the
matters based on this information in the form and
context in which it appears.
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.
27
RESERVES & PROSPECTIVE RESOURCES (continued)
Prospective Resources Cautionary
Statement
The estimated quantities of petroleum that may
potentially be recovered by the application of
future development projects relate to undiscovered
accumulations. These estimates have both an
associated risk of discovery and a risk of development.
Further appraisal and evaluation is required to
determine the existence of a significant quantity of
potentially moveable hydrocarbons.
Pricing Assumptions
Oil price assumptions used in the independent
report represent forward prices (CME Nymex) as
at 28 June 2019.
ASX Reserves and Resources Reporting Notes
(vii) The method of aggregation used in calculating estimated
(i)
(ii)
(iii)
(iv)
(v)
(vi)
The reserves and prospective resources information in
this document is effective as at 30 June, 2019 (Listing Rule
(LR) 5.25.1)
The reserves and prospective resources information in this
document has been estimated and is classified in accordance
with SPE‐PRMS (Society of Petroleum Engineers-Petroleum
Resources Management System) (LR 5.25.2)
The reserves and prospective resources information in this
document is reported according to the Company’s economic
interest in each of the reserves and prospective resource net
of royalties (LR 5.25.5)
The reserves and prospective resources information in
this document has been estimated and prepared using the
probabilistic method (LR 5.25.6)
The reserves and prospective resources information in this
document has been estimated using a ratio of 6,000 cubic feet
of natural gas to one barrel of oil. This conversion ratio is based
on an energy equivalency conversion method and does not
represent value equivalency (LR 5.25.7)
The reserves and prospective resources information in this
document has been estimated on the basis that products are
sold on the spot market with delivery at the sales point on the
production facilities (LR 5.26.5)
reserves was the arithmetic summation by category of
reserves. As a result of the arithmetic aggregation of the
field totals, the aggregate 1P may be a very conservative
estimate and the aggregate 3P may be a very optimistic
estimate due to the portfolio effects of arithmetic
summation (LR 5.26.7 & 5.26.8)
(viii) Prospective resources are reported on a best estimate basis
(LR 5.28.1)
(ix)
For prospective resources, the estimated quantities of
petroleum that may potentially be recovered by the application
of a future development project(s) relate to undiscovered
accumulations. These estimates have both an associated risk
of discovery and a risk of development. Further exploration,
appraisal and evaluation is required to determine the existence
of a significant quantity of potentially moveable hydrocarbons
(LR 5.28.2)
(x)
The reserve numbers assume some investment over the life
of the field outlined above.
Glossary
Bbl
barrels
Btu
British Thermal Units
MMBL million barrels of oil
bcf
billion cubic feet
EUR
Economic Ultimate Recovery
Mboe
thousand barrels of oil equivalent
Bcfe
billion cubic feet equivalent
Mcfg
thousand cubic of gas
MMboe million barrels of oil equivalent
boe
barrels of oil equivalent
Mcfgpd thousand cubic feet of gas per day
MCF
thousand cubic feet
Bopd barrels of oil per day
MMcf million cubic feet
mmbtu million British Thermal Units
MBL
thousand barrels of oil
28
ANNUAL REPORT 2019
FINANCIAL
REPORT
2019
For the year ended 30 June 2019
2929
FINANCIAL REPORT 2019
CONTENTS
Corporate Directory
Directors’ Report
Auditor’s Independence Declaration
Income
Consolidated Statement of Financial Position
Consolidated Statement of Changes in Equity
Consolidated Statement of Cash Flows
Notes to the Consolidated Financial Statements
Directors’ Declaration
Consolidated Statement of Profit or Loss and Other Comprehensive
Independent Audit Report to the Members of Otto Energy Limited
FINANCIAL REPORT 2019
Additional ASX Information
Financial Report 2019
CONTENTS
CONTENTS
Corporate Directory
Directors’ Report
Auditor’s Independence Declaration
Consolidated Statement of Profit or Loss and Other Comprehensive
Income
Consolidated Statement of Financial Position
Consolidated Statement of Changes in Equity
Consolidated Statement of Cash Flows
Notes to the Consolidated Financial Statements
Directors’ Declaration
Independent Audit Report to the Members of Otto Energy Limited
Additional ASX Information
31
32
64
65
66
67
68
69
110
111
114
31
32
64
65
66
67
68
69
110
111
114
Annual General Meeting
The Annual General Meeting of Otto Energy Limited will be held in Sydney on 21 November 2019.
Annual General Meeting
The Annual General Meeting of Otto Energy Limited will be held in Sydney on 21 November 2019.
30
ANNUAL REPORT 2019
CORPORATE DIRECTORY
CORPORATE DIRECTORY
Directors
Mr John Jetter – Non-Executive Chairman
Mr Matthew Allen – Managing Director and Chief Executive Officer
Mr Ian Macliver – Non-Executive Director
Mr Ian Boserio – Non-Executive Director & Deputy Chairman
Mr Paul Senycia – Non-Executive Director
Mr Kevin Small – Executive Director
Company Secretary
Mr David Rich
Key Executives
Principal registered office
in Australia
Share Registry
Auditors
Mr Matthew Allen – Managing Director and Chief Executive Officer
Mr Will Armstrong – Vice President Exploration and New Ventures
Mr Kevin Small – Senior Exploration Consultant
Mr Philip Trajanovich – Senior Commercial Manager
Mr David Rich – Chief Financial Officer and Company Secretary
32 Delhi Street
West Perth WA 6005
Tel: + 61 8 6467 8800
Fax: + 61 8 6467 8801
Link Market Services Limited
Level 12 QV1 Building
250 St Georges Terrace
Perth WA 6000
Tel: + 61 8 9211 6670
Fax: + 61 2 9287 0303
BDO Audit (WA) Pty Ltd
38 Station Street
Subiaco WA 6008
Tel: + 61 8 6382 4600
Fax: + 61 8 6382 4601
Securities Exchange Listing
Australian Securities Exchange
ASX Code: OEL
Website address
www.ottoenergy.com
ABN
56 107 555 046
1
31
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the year ended 30 June 2019
For the Year Ended 30 June 2019
The Directors present their report together with the consolidated financial statements of the Group
comprising Otto Energy Limited (referred to as ‘Otto’ or the ‘Company’) and its subsidiaries for the financial
year ended 30 June 2019 and the auditors’ report thereon.
Directors
The Directors in office at any time during the financial year and until the date of this report are set out below.
All Directors were in office for the entire period except for Kevin Small appointed 29 January 2019.
Mr John Jetter BLaw, BEcon, INSEAD
Chairman (Independent Non-Executive)
Appointed Non-Executive Director 10 December 2007, Non-Executive Chairman 25 November 2015
Mr John Jetter is the former Managing Director, CEO and head of investment banking of JP Morgan in Germany
and Austria, and a member of the European Advisory Council, JP Morgan London. Mr Jetter has held senior
positions with JP Morgan throughout Europe, focusing his attention on major corporate clients advising on
some of Europe's largest corporate transactions. Mr Jetter has been a non-executive Director of Venture
Minerals Limited since June 2010 and Peak Resources Limited since April 2015 and is Chairman of the
Remuneration and Nomination Committee and a member the Audit and Risk Management Committee.
Mr Jetter, has confirmed to the Board, and the Board has agreed, that he will step down from the role of
Chairperson at the coming Annual General Meeting of shareholders on 21 November 2019. Mr Jetter will
remain as a non-executive director in order to oversee the seamless transition of the role of Chairperson and
the successful delivery of Otto’s Board renewal which has commenced under his guidance. Mr Jetter will not
seek re-election at the Annual General Meeting in 2020.
Mr Matthew Allen BBus, FCA, F Fin, GAICD
Managing Director and Chief Executive Officer
Appointed 24 June 2015
Mr Matthew Allen was appointed Chief Executive Officer in February 2014 and Managing Director in June 2015.
Mr Allen joined Otto Energy in 2009 as Chief Financial Officer and has played an integral role in implementing
Otto’s strategy since joining Otto. Prior to joining Otto, Mr Allen worked for Woodside Energy for over 8 years
in leadership roles in a number of Woodside business units, including within Woodside’s overseas businesses
in Africa.
Mr Allen’s experience lies in the operation and management of oil & gas companies with particular focus on
strategic, commercial and financial aspects of the business. Mr Allen has global upstream experience in the
USA, Asia, Africa, Australia and the Middle East. He is a Fellow of Chartered Accountants Australia and New
Zealand, Fellow of the Financial Services Institute of Australasia and Graduate Member of the Australian
Institute of Company Directors.
Mr Ian Boserio BSc Hons First Class (Geophysics), BSc (Geology) GAICD
Deputy Chairman (Independent Non-Executive)
Appointed Non-Executive Director 2 September 2010 and Deputy Chairman 8 September 2019
Mr Ian Boserio brings to the Otto Board more than 35 years international experience in the oil and gas
business, focused predominantly on exploration and management. Mr Boserio was formerly at Shell as the
Australian New Business Manager, prior to that he led the Shell Australia and New Zealand exploration team
developing its gas portfolio for LNG development. Mr Boserio also worked with Shell internationally, including
roles in Australia, North Sea, Middle East, India and Indonesia, including a five year secondment into
Woodside. He is currently co-owner and technical director of private oil and gas company Pathfinder Energy
Pty Ltd.
Mr Boserio is a member of the Audit and Risk Management Committee and the Remuneration and Nomination
Committee. The Board has nominated Mr Boserio to become Chairman after the Company’s 2019 Annual
General Meeting on 21 November 2019 when Mr Jetter steps down.
32
2
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
Mr Ian Macliver BCom, FCA, SF Fin, FAICD
Director (Independent Non-Executive)
Appointed 7 January 2004
Mr Ian Macliver is Managing Director of Grange Consulting Group Pty Ltd, which provides specialist corporate
advisory services to listed and unlisted companies. Mr Macliver has held senior executive and Director roles
in both resource and industrial companies, specifically responsible for capital raising and other corporate
initiatives. Mr Macliver has been the non-executive Chairman of Western Areas Limited since November 2013,
and non-executive Director since October 2011. Mr Macliver is Chairman of the Audit and Risk Management
Committee.
Mr Macliver has advised the Board that he will retire upon the appointment of a suitably qualified, independent
non-executive director to assume the roles he currently occupies. A process has commenced to identify a
candidate for this role and Mr Macliver has advised that he will retire from the Board of Otto Energy at the
time his replacement is appointed, or at the latest by 30 June 2020.
Mr Paul Senycia BSc (Hons), MAppSc
Director (Non-Executive)
Appointed 24 April 2018, became non-executive on 1 January 2019
Mr Paul Senycia is an seasoned geoscientist with over 35 years of international oil and gas experience in both
commercial and technical aspects of the business. Mr Senycia has held senior roles in large and small
companies worldwide including Shell, Woodside and Beach Petroleum. Over the last twenty years Mr Senycia
has accumulated substantial Gulf of Mexico expertise both on the shelf and in the deep water. This has
included deal capture, asset management and project divestment activities. Outside the Gulf of Mexico, Mr
Senycia has worked in Europe, Asia, Africa and Australasia both on and offshore.
Up until his retirement on 31 December 2018, Mr Senycia was the Vice President – Exploration and New
Ventures for the Company. Mr Senycia is a member of the Remuneration and Nomination Committee.
Mr Kevin Small BSc Goephysical Engineering (Hons)
Director (Executive)
Appointed 29 January 2019
Mr Kevin Small is an exploration geoscientist with over forty years’ experience in the Gulf of Mexico both
onshore and offshore, and has been responsible for the generation, farm-in, drilling and development of
numerous Gulf Coast discoveries. Kevin brings extensive networks and relevant experience to Otto’s Gulf
Coast business.
Prior to joining Otto Mr Small worked with Tri-C Resources, a privately owned Houston based oil and gas
company, developing Gulf Coast conventional prospects for drilling. Between 2003 and 2012, Mr Small worked
for Bluestreak Exploration Group developing prospects exclusively for LLOG Exploration which resulted in
successful discoveries on the Gulf of Mexico Shelf and Deepwater. Mr Small was the Exploration Manager and
a founding member of the Houston office of Westport Oil and Gas Company between 1996 and 2003, ultimately
helping them go public in October 2000. Mr Small also has worked for the Superior Oil Company and McMoran
Oil and Gas. During his time with LLOG, Westport, and McMoRan, Mr Small drilled wells with cumulative
production of over 692 BCFG and 82 MMBO.
Company Secretary
Mr David Rich BCom, FCA, GAICD, AGIA, Grad.Dip.CSP
Appointed 31 January 2017
Mr Rich is an experienced public company CFO and Company Secretary with over 30 years commercial
experience including 17 years as CFO of ASX listed upstream oil and gas companies with international
interests including Australia, Europe, Asia, Africa and the USA. As at the date of this report, Mr Rich had
resigned as Company Secretary and Chief Financial Officer with effect from 1 November 2019.
3
33
DIRECTORS’ REPORT
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
For the year ended 30 June 2019
For the Year Ended 30 June 2019
Director’s interests
Director’s interests
As at the date of this report, the interests of the Directors in the shares and rights of Otto Energy Limited
were:
As at the date of this report, the interests of the Directors in the shares and rights of Otto Energy Limited
were:
Director
Director
Mr J Jetter
Mr M Allen
Mr J Jetter
Mr I Macliver
Mr M Allen
Mr I Boserio
Mr I Macliver
Mr P Senycia
Mr I Boserio
Mr K Small
Mr P Senycia
Mr K Small
Number of
ordinary shares
Number of
28,940,834
ordinary shares
10,770,801
28,940,834
7,490,352
10,770,801
3,612,763
7,490,352
4,711,468
3,612,763
12,371,515
4,711,468
12,371,515
Number of
rights
Number of
rights
1,804,667
8,908,000
1,804,667
1,212,667
8,908,000
1,082,333
1,212,667
5,069,000
1,082,333
4,840,000
5,069,000
4,840,000
Principal activities
Principal activities
The principal activity of the Group is oil and gas exploration, development, production and sales in North
America.
The principal activity of the Group is oil and gas exploration, development, production and sales in North
America.
Dividends
Dividends
No dividend has been declared for the year ended 30 June 2019.
No dividend has been declared for the year ended 30 June 2019.
Operating and Financial Review
Operating and Financial Review
During the year ended 30 June 2019 Otto participated in the drilling of seven exploration/appraisal wells and
of these, three resulted in discoveries. One of these, Lightning, commenced production in May 2019, bringing
During the year ended 30 June 2019 Otto participated in the drilling of seven exploration/appraisal wells and
Otto’s number of producing assets in the Gulf of Mexico area to two.
of these, three resulted in discoveries. One of these, Lightning, commenced production in May 2019, bringing
Otto’s number of producing assets in the Gulf of Mexico area to two.
Financial Summary
Financial Summary
Otto’s net revenue from production during the year was US$31.2 million (2018: US$9.5 million) generating a
significant operating gross profit of US$23.4 million (2018: US$7.9 million). Costs of production included
Otto’s net revenue from production during the year was US$31.2 million (2018: US$9.5 million) generating a
US$5.0 million for amortisation of oil and gas properties (2018: US$0.9 million).
significant operating gross profit of US$23.4 million (2018: US$7.9 million). Costs of production included
US$5.0 million for amortisation of oil and gas properties (2018: US$0.9 million).
Under Otto’s accounting policy, exploration expenses are written off as incurred and for the year Otto’s
exploration expenditure was US$37.8 million (2018: US$4.8 million) which included the following wells; Winx-
Under Otto’s accounting policy, exploration expenses are written off as incurred and for the year Otto’s
1, Bivouac Peak, Green Canyon 21, Lightning, Mustang, Big Tex and Don Julio 2.
exploration expenditure was US$37.8 million (2018: US$4.8 million) which included the following wells; Winx-
1, Bivouac Peak, Green Canyon 21, Lightning, Mustang, Big Tex and Don Julio 2.
Overall the Group recognised a loss after income tax for the year of $18.4 million (2018: loss $5.2 million).
Administration costs were US$5.1 million, up from US$4.0 million in 2018. This includes business
Overall the Group recognised a loss after income tax for the year of $18.4 million (2018: loss $5.2 million).
development costs of US$0.7 million (2018: US$0.5 million) and the costs of establishing the office and
Administration costs were US$5.1 million, up from US$4.0 million in 2018. This includes business
management team in Houston and transitioning roles and duties from Perth.
development costs of US$0.7 million (2018: US$0.5 million) and the costs of establishing the office and
management team in Houston and transitioning roles and duties from Perth.
Finance costs included the reversal (credit) of the previous fair value adjustment on the embedded derivative
element of convertible note of US$3.2 million (2018: US$2.4 million expense) (all non-cash). With this reversal,
Finance costs included the reversal (credit) of the previous fair value adjustment on the embedded derivative
the total finance cost for the year was a credit (income) of US$1.0 million (2018: US$4.4 million expense).
element of convertible note of US$3.2 million (2018: US$2.4 million expense) (all non-cash). With this reversal,
Finance costs also included other non-cash items of accretion of effective interest on convertible notes
the total finance cost for the year was a credit (income) of US$1.0 million (2018: US$4.4 million expense).
(US$0.4 million (2018: US$0.3 million)), and amortisation of borrowing costs (US$0.2 million (2018: US$0.2
Finance costs also included other non-cash items of accretion of effective interest on convertible notes
million)). The other material component of finance costs was interest on the convertible notes (US$1.2 million
(US$0.4 million (2018: US$0.3 million)), and amortisation of borrowing costs (US$0.2 million (2018: US$0.2
(2018: US$1.2 million)).
million)). The other material component of finance costs was interest on the convertible notes (US$1.2 million
(2018: US$1.2 million)).
Two capital raisings totaling US$36.6 million [before costs] were undertaken during the year to fund the
exploration drilling. A detailed review of the operations of the Group during the financial year are set out below.
Two capital raisings totaling US$36.6 million [before costs] were undertaken during the year to fund the
exploration drilling. A detailed review of the operations of the Group during the financial year are set out below.
4
4
34
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
1. Production and Development
Reserves Statement as at 30 June 2019
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
On 19 September 2019 the Company released its statement of reserves and resources as at 30 June 2019,
which included the maiden reserves booking for the Lightning discovery. The summary is set out below and
further details are included in the subsequent events section.
Total
Gross (100%)
Proved Producing
Proved Behind Pipe
Proved Undeveloped
Proven (1P)
Probable
Proven Plus Probable (2P)
Possible
Proven Plus Probable Plus
Possible (3P)
Total Prospective Resource
(best estimate, unrisked)
Otto Net
Gas
Oil (Mbbl)
3,219
Gas
(MMscf) MBoe
(MMscf) MBoe
Oil
(Mbbl)
12,599 5,318 1,271 3,910 1,923
1,118 452
682 3,765 1,310 265
3,292 1,295
11,117 3,779 746
27,481
2,282 8,320 3,670
10,407
19,823 9,398 2,417 6,101 3,434
7,103
4,699
19,806
47,304
14,421
10,072 3,049
34,468 9,409 1,371
1,927
5,828
6,094
11,922
3,664
15,586
81,772
29,214
6,070
24,492
10,152
67,309
89,875
82,289
South Marsh Island 71 (SM 71) – Offshore Gulf of Mexico. Otto WI 50.0%
Otto owns a 50% Working Interest (“WI”) and a 40.625% Net Revenue Interest (“NRI”) in the South Marsh Island
block 71 (“SM 71”), with Byron Energy Limited (“Byron”) the operator, holding an equivalent WI and NRI. Water
depth in the area is approximately 137 feet.
Following the initial discovery by Otto and Byron in 2016, oil and gas production from the SM 71 F platform
began in late March 2018 from two wells with the third well coming on line in early April 2018. The F1 and F3
wells are completed in the primary D5 Sand reservoir and the F2 well is completed in the B55 Sand, a
secondary exploration target.
The SM 71 F facility has now produced over 1.6 million barrels of oil (gross) since initial production began. The
facility has also produced over 2.4 billion cubic feet of gas (gross) which, on a revenue basis, is approximately
equivalent to an additional 128,000 barrels of oil.
After the initial expected decline in production, aquifer support has stabilized and in fact, increased oil
production over the second half of the financial year. The field is currently producing in excess of initial
expectations.
5
35
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the year ended 30 June 2019
For the Year Ended 30 June 2019
Production and revenue details for the year ended 30 June 2019 are set out below:
Production Volumes
Gross (100%)
SM 71 – Oil (bbls)
SM 71 – Oil (bopd)
SM 71 – Gas (Mscf)
Otto WI Share (50%)
SM 71 – Oil (bbls)
SM 71 – Oil (bopd)
SM 71 – Gas (Mscf)
Otto NRI Share (40.625%)
SM 71 – Oil (bbls)
SM 71 – Oil (bopd)
SM 71 – Gas (Mscf)
Sales Revenue – Otto 50% WI
share (before royalties)
30-Sep-18
31-Dec-18
31-Mar-19
30-Jun-19
Quarter Ended
324,597
3,528
355,605
162,298
1,764
177,802
131,868
1,433
144,464
271,074
2,946
582,593
135,537
1,473
291,296
110,124
1,197
236,678
255,880
2,843
607,580
127,940
1,422
303,790
103,951
1,155
246,829
Quarter Ended
264,992
2,912
469,196
132,496
1,456
234,598
107,653
1,183
190,611
USD
30-Sep-18
31-Dec-18
31-Mar-19
30-Jun-19
SM 71 – Oil - $’million
SM 71 – Oil - $ per bbl
SM 71 – Gas - $’000
SM 71 – Gas – $ per MMbtu
11.17
68.82
615
3.17
8.25
60.85
1208
3.81
6.99
54.65
977
2.93
8.16
61.59
643
$2.49
Notes
1. Otto sells its high quality Louisiana Light Sweet crude (“LLS”) produced at SM 71 at premium to West
Texas Intermediate (“WTI”) based on current LLS versus WTI price differentials. Deductions are then
applied for transportation, oil shrinkage, basic sediment & water (BS&W), and other applicable
adjustments.
2. Gas revenues include NGLs. 1 Mscf = 1.09 MMbtu in June for SM 71 production. The thermal content of
SM 71 gas may vary over time.
On 19 September 2019 Otto released its annual reserves statement as at 30 June 2019. The table below
summarises the SM 71 reserves and resources position at 30 June 2019. Refer to the subsequent events
section for further details on this and progress on development wells in SM 71.
36
6
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
For the Year Ended 30 June 2019
SM 71
SM 71
Gross (100%)
Gross (100%)
Otto Net (40.625%)
Otto Net (40.625%)
Gas
Gas
Gas
Gas
Oil (Mbbl)
Oil (Mbbl)
9,380 14,977
9,380 14,977
Oil
Oil
(Mbbl)
(MMscf) MBoe
(MMscf) MBoe
(Mbbl)
236
639
639
236
1,782 659
1,782 659
3,665 49,569 11,927 1,489 20,137 4,845
3,665 49,569 11,927 1,489 20,137 4,845
(MMscf) MBoe
(MMscf) MBoe
2,918 2,575 3,347 1,185 1,046 1,360
2,918 2,575 3,347 1,185 1,046 1,360
260
144
580 355
260
144
580 355
724
391
1,622 962
1,622 962
724
391
3,892 5,768 2,080 1,581 2,344
5,120
3,892 5,768 2,080 1,581 2,344
5,120
5,608 3,627 6,213 2,278 1,473 2,524
5,608 3,627 6,213 2,278 1,473 2,524
4,358 3,055 4,867
7,519 11,981
10,728
7,519 11,981
4,358 3,055 4,867
10,728
1,217
2,686 1,861 2,996 1,091 756
2,686 1,861 2,996 1,091 756
1,217
5,449 3,811 6,085
13,414
5,449 3,811 6,085
13,414
Proved Producing
Proved Producing
Proved Behind Pipe
Proved Behind Pipe
Proved Undeveloped
Proved Undeveloped
Proven (1P)
Proven (1P)
Probable
Probable
Proven Plus Probable (2P)
Proven Plus Probable (2P)
Possible
Possible
Proven Plus Probable Plus
Proven Plus Probable Plus
Possible (3P)
Possible (3P)
Total Prospective Resource
Total Prospective Resource
(best estimate, unrisked)
(best estimate, unrisked)
Lightning – Onshore Matagorda County, Texas. Otto WI 37.5%
Lightning – Onshore Matagorda County, Texas. Otto WI 37.5%
The Green #1 well on the Lightning prospect in Matagorda County Texas commenced drilling in early
December 2018. The well reached total depth of 15,218ft MD (15,216ft TVD) in early February 2019 with wireline
The Green #1 well on the Lightning prospect in Matagorda County Texas commenced drilling in early
logs indicating 180 feet of net pay, significantly in excess of pre-drill expectations.
December 2018. The well reached total depth of 15,218ft MD (15,216ft TVD) in early February 2019 with wireline
logs indicating 180 feet of net pay, significantly in excess of pre-drill expectations.
Through participation in the drilling of the Lightning exploration well, Otto earned a 37.5% working interest in
the leases covering the Lightning prospect.
Through participation in the drilling of the Lightning exploration well, Otto earned a 37.5% working interest in
the leases covering the Lightning prospect.
Following the discovery, facilities were installed and the well was connected to a nearby sales gas pipeline.
Perforations and testing occurred during April and May with the well reaching steady state production of 12
Following the discovery, facilities were installed and the well was connected to a nearby sales gas pipeline.
MMscf/day in raw gas and 365 bbl/day in condensate (Otto’s 37.5% Working Interest is 4.5 MMscf/d and 137
Perforations and testing occurred during April and May with the well reaching steady state production of 12
bbls/d) in late June 2019.
MMscf/day in raw gas and 365 bbl/day in condensate (Otto’s 37.5% Working Interest is 4.5 MMscf/d and 137
bbls/d) in late June 2019.
Commissioning hydrocarbon sales in May and June 2019 contributed to Otto revenue, with the first full month
of contribution occurring in July 2019. First sales proceeds were received in July 2019.
Commissioning hydrocarbon sales in May and June 2019 contributed to Otto revenue, with the first full month
of contribution occurring in July 2019. First sales proceeds were received in July 2019.
Sales Revenue – Otto 37.5%
Sales Revenue – Otto 37.5%
WI share (before royalties)
WI share (before royalties)
Volumes*
USD
Volumes*
USD
USD
Oil - $’million
USD
Oil - $’million
Oil - $ per bbl
Oil - $ per bbl
Gas - $’000
Gas - $’000
Gas – $ per MMbtu
Gas – $ per MMbtu
NGLs - $’000
NGLs - $’000
NGLs – $ per bbl
NGLs – $ per bbl
Gross (100%)
Gross (100%)
Lightning – Oil (bbls)
Lightning – Oil (bbls)
Lightning – Gas (Mscf)
Lightning – Gas (Mscf)
Lightning – NGLs (bbls)
Lightning – NGLs (bbls)
Otto WI Share (37.5%)
Otto WI Share (37.5%)
Lightning – Oil (bbls)
Lightning – Oil (bbls)
Lightning – Gas (Mscf)
Lightning – Gas (Mscf)
Lightning – NGLs (bbls)
Lightning – NGLs (bbls)
0.13
0.13
60.70
60.70
143.33
143.33
2.32
2.32
31.54
31.54
11.08
11.08
Production Volumes*
Production Volumes*
5,685
5,685
167,393
167,393
7,591
7,591
2,132
2,132
62,772
62,772
2,847
2,847
2019
2019
2019
2019
Otto NRI Share
Otto NRI Share
(28.5686%)
Lightning – Oil (bbls)
(28.5686%)
Lightning – Oil (bbls)
Lightning – Gas (Mscf)
Lightning – Gas (Mscf)
Lightning – NGLs (bbls)
Lightning – NGLs (bbls)
1,624
1,624
47,822
47,822
2,169
2,169
* Lightning annual production reflects only limited production during start up and commissioning of field
during May and June 2019. July 2019 full month production totalled 10,000 bbl and 343 MMscf of Raw Gas
* Lightning annual production reflects only limited production during start up and commissioning of field
(8/8ths).
during May and June 2019. July 2019 full month production totalled 10,000 bbl and 343 MMscf of Raw Gas
(8/8ths).
7
7
37
DIRECTORS’ REPORT
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the year ended 30 June 2019
For the Year Ended 30 June 2019
For the Year Ended 30 June 2019
The joint venture is progressing the drilling of a second well, Green #2, in the field commencing in October
2019. Full field development may require up to five wells to fully develop the Lightning accumulation.
The joint venture is progressing the drilling of a second well, Green #2, in the field commencing in October
2019. Full field development may require up to five wells to fully develop the Lightning accumulation.
On 19 September 2019 Otto released its annual reserves statement as at 30 June 2019 which included the
maiden reserves statement for the Lightning field. The table below summarises the Lightning reserves and
On 19 September 2019 Otto released its annual reserves statement as at 30 June 2019 which included the
resources position at 30 June 2019. Refer to the subsequent events section for further details on this and
maiden reserves statement for the Lightning field. The table below summarises the Lightning reserves and
progress on the Green#2 development well.
resources position at 30 June 2019. Refer to the subsequent events section for further details on this and
progress on the Green#2 development well.
Lightning
Lightning
Proved Producing
Proved Producing
Proved Behind Pipe
Proved Behind Pipe
Proved Undeveloped
Proved Undeveloped
Proven (1P)
Proven (1P)
Probable
Probable
Proven Plus Probable (2P)
Proven Plus Probable (2P)
Possible
Possible
Proven Plus Probable Plus
Proven Plus Probable Plus
Possible (3P)
Possible (3P)
Total Prospective Resource
Total Prospective Resource
(best estimate, unrisked)
(best estimate, unrisked)
Gross (100%)
Gross (100%)
Gas
Gas
Oil (Mbbl)
Oil (Mbbl)
Oil
Oil
(Mbbl)
(MMscf) MBoe
(MMscf) MBoe
(Mbbl)
301 10,024 1,971 86
301 10,024 1,971 86
29
102 3,410 671
102 3,410 671
29
305 10,155 1,997 87
305 10,155 1,997 87
4,639 202
708 23,589
4,639 202
708 23,589
486 16,196 3,185 139
486 16,196 3,185 139
7,824 341
39,785
1,194
39,785
1,194
7,824 341
978 32,607 6,413 279
978 32,607 6,413 279
620
2,172
620
2,172
14,237
14,237
72,392
72,392
Otto Net (28.569%)
Otto Net (28.569%)
Gas
Gas
(MMscf) MBoe
(MMscf) MBoe
2,864 563
2,864 563
192
974
974
192
2,901 571
2,901 571
6,739 1,326
6,739 1,326
4,627 910
4,627 910
2,235
11,366
11,366
2,235
9,315 1,832
9,315 1,832
4,067
20,682
4,067
20,682
-
-
-
-
-
-
-
-
Green Canyon 21 (GC 21) – Offshore Gulf of Mexico. Otto WI 16.67%
Green Canyon 21 (GC 21) – Offshore Gulf of Mexico. Otto WI 16.67%
On 29 March 2019 Otto announced that it has entered into a joint venture with Talos Energy (NYSE: TALO)
which will see it earn a 16.67% working interest in the Green Canyon 21 (GC-21) lease in the Gulf Mexico
On 29 March 2019 Otto announced that it has entered into a joint venture with Talos Energy (NYSE: TALO)
through paying 22.22% of the cost of the drilling of the “Bulleit” appraisal well in GC-21. The well was to be
which will see it earn a 16.67% working interest in the Green Canyon 21 (GC-21) lease in the Gulf Mexico
drilled by Talos Energy, a highly experienced Gulf of Mexico operator based in Houston. Talos had the Noble
through paying 22.22% of the cost of the drilling of the “Bulleit” appraisal well in GC-21. The well was to be
Don Taylor drillship contracted to undertake the drilling of the Bulleit prospect.
drilled by Talos Energy, a highly experienced Gulf of Mexico operator based in Houston. Talos had the Noble
Don Taylor drillship contracted to undertake the drilling of the Bulleit prospect.
The “Bulleit” appraisal well commenced drilling on 6 May 2019. On 13 June 2019, The Company announced
that the upper target, the DTR-10 sand, was intersected and a commercial outcome was confirmed.
The “Bulleit” appraisal well commenced drilling on 6 May 2019. On 13 June 2019, The Company announced
that the upper target, the DTR-10 sand, was intersected and a commercial outcome was confirmed.
On 8 August 2019 Otto announced that the GC 21 “Bulleit” well, operated by Talos Energy, Inc (“Talos”) (NYSE:
TALO) had been successfully drilled to Total Depth. The well drilled through the deeper exploration target, the
On 8 August 2019 Otto announced that the GC 21 “Bulleit” well, operated by Talos Energy, Inc (“Talos”) (NYSE:
MP sands, after intersecting oil pay in the shallower DTR-10 sand package as announced to the ASX on 13
TALO) had been successfully drilled to Total Depth. The well drilled through the deeper exploration target, the
June 2019. The well intersected the following discovered intervals:
MP sands, after intersecting oil pay in the shallower DTR-10 sand package as announced to the ASX on 13
June 2019. The well intersected the following discovered intervals:
- DTR-10 interval –net 140 feet of TVD oil pay encountered; and
- DTR-10 interval –net 140 feet of TVD oil pay encountered; and
- MP interval – approximately net 110 feet of TVD oil pay expected to be delivered in high quality reservoir
- MP interval – approximately net 110 feet of TVD oil pay expected to be delivered in high quality reservoir
consistent with analogue wells in the GC18 field.
consistent with analogue wells in the GC18 field.
Following the discovery in the DTR-10 sands, attempt to drill to the deeper objective MP sands were delayed
due to poor hole conditions and compromised drilling operations requiring sidetracking. In addition, the
Following the discovery in the DTR-10 sands, attempt to drill to the deeper objective MP sands were delayed
passing of Hurricane Barry required the rig to disconnect to ensure safe operations. As a result of these
due to poor hole conditions and compromised drilling operations requiring sidetracking. In addition, the
operations, the cost of drilling the GC21 “Bulleit” well exceeded the pre-drill estimates of US$9.0m net to Otto.
passing of Hurricane Barry required the rig to disconnect to ensure safe operations. As a result of these
The effect of these events is now expected to increase Otto’s financial exposure to the Bulleit well by
operations, the cost of drilling the GC21 “Bulleit” well exceeded the pre-drill estimates of US$9.0m net to Otto.
approximately US$6.5 to US$7.5m net to Otto.
The effect of these events is now expected to increase Otto’s financial exposure to the Bulleit well by
approximately US$6.5 to US$7.5m net to Otto.
The GC 21 development plan is being progressed by the Operator to complete the discovery well in the first
half of 2020. The Operator will complete the well as a production well and then tie it back to the Talos-owned
The GC 21 development plan is being progressed by the Operator to complete the discovery well in the first
and operated Green Canyon 18 (GC 18A) facility approximately 10 miles (~16 km) west of the “Bulleit” well.
half of 2020. The Operator will complete the well as a production well and then tie it back to the Talos-owned
and operated Green Canyon 18 (GC 18A) facility approximately 10 miles (~16 km) west of the “Bulleit” well.
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DIRECTORS’ REPORT
For the Year Ended 30 June 2019
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
The development will involve the use of a subsea completion that is common for projects of this nature and
water depth in the Gulf of Mexico. The joint venture will undertake a review of the operator’s plan of
development in the coming month with formal commitment to the development expected shortly thereafter.
2. Exploration and Appraisal
Gulf Coast Package - Hilcorp
On 31 July 2018 Otto announced that it had entered into a joint venture with Hilcorp Energy which will see it
earn a 37.5% working interest in an eight well portfolio of prospects in the Onshore/Near Shore USA Gulf
Coast (Gulf of Mexico). The wells are being drilled by Hilcorp, a highly experienced operator based in Houston.
Otto will earn a 37.5% working interest by paying 50.0% of the costs of drilling and either setting casing or
plugging and abandoning the initial exploration well plus lease acquisition costs at each of the eight prospects.
Four wells have now been drilled (Big Tex, Lightning, Don Julio 2 and Mustang) with Lightning and Mustang
being discoveries.
Lightning was a discovery with net pay of 180 feet which is significantly in excess of the pre-drill estimates.
The well is now in production. Further details on Lightning are covered in the production section of this report.
On 23 July 2019 Otto announced that the initial exploration well on the Mustang prospect had discovered a net
57 foot TVT interval of hydrocarbon pay. The well is currently being prepared for testing for final evaluation of
the well before being tied back for production. Refer to the subsequent events section of this report for further
information on the Mustang discovery.
The initial exploration well on the Big Tex prospect, SL 192 PP 031, commenced on 28 August 2018 and reached
a final total depth of 13,722ft MD (13,172ft TVD). A triple combo wireline logging suite was subsequently
acquired over the target prospective Middle Miocene Tex W16 and Tex W18 Sand intervals as well as several
sidewall cores. Petrophysical log evaluation indicated the presence of a number of hydrocarbon bearing zones,
however insufficient producible reservoir was encountered to justify the additional cost of completing the well
for production. The Joint Venture subsequently plugged and abandon the well as sub-commercial.
On 11 March 2019 the Company advised that the initial exploration well on the Don Julio 2 exploration prospect,
Middleton Trust #1 well, was drilled to a final total depth of 11,900 ft MD/ 11,799 ft TVD. Quad-combo wireline
and sidewall cores were then acquired over the prospective interval. Evaluation of the wireline logs indicated
the well had not intersected producible reservoir and no indications of hydrocarbons were evident whilst
drilling. The well was then plugged and abandoned.
The well was testing an Oligocene age, upper Vicksburg prospect that was generated on modern 3D seismic.
The well targeted a typical AVO anomaly using seismic data but encountered an unexpected volcanic ash bed
immediately above the target interval, creating an AVO “false positive” anomaly. There are no other known
volcanic ash beds within this interval in the area.
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39
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the year ended 30 June 2019
For the Year Ended 30 June 2019
There are four wells left in the program which are expected to be drilled over the next 6 - 9 months, subject
to finalising regulatory and permitting approvals. With Beluga expected to commence drilling in the fourth
quarter of 2019.
Prospect
Name
(State)
Working
Interest
Net
Revenue
Interest
Target
Depth
(TVD)
ft
Probability
of Success
Prospective Resources (MMboe)
Otto Net Revenue Interest
Beluga, TX
37.5%
28.5%
13,000
Mallard, LA
37.5%
29.63%
11,000
Tarpon, TX
37.5%
29.06%
14,000
Oil Lake, LA
37.5%
29.06%
14,500
45%
64%
34%
45%
P90
P50
Mean
P10
0.2
0.1
2.2
0.3
0.9
0.3
7.0
1.0
1.4
0.5
10.5
1.3
3.4
1.3
23.5
2.7
Prospective Resources Cautionary Statement - The estimated quantities of petroleum that may potentially
be recovered by the application of future development projects relate to undiscovered accumulations. These
estimates have both an associated risk of discovery and a risk of development. Further appraisal and
evaluation is required to determine the existence of a significant quantity of potentially moveable
hydrocarbons.
Additional Upside
With the successful drilling of the Mustang prospect, Otto has ground floor rights (ie pays only its working
interest) to participate in the nearby Corsair/Hellcat opportunities. These wells are in addition to the eight
wells in the original program announced with Hilcorp. Should the Tarpon prospect be successful then Otto
has ground floor rights (ie. It pays only its working interest) to participate in the nearby Damsel opportunity.
Under the agreement with Hilcorp (JEDA) Otto has a right of first offer to a subsequent Gulf Coast program,
if Hilcorp elect to offer such a program to third parties.
Bivouac Peak
Drilling of the Weiss-Adler, et. al. No. 1 well by the Parker 77B rig commenced on 25 of August 2018 by the
Operator, Byron Energy. The well was drilled to a depth of 17,766 feet MD and evaluated utilising quad combo
wireline logging tools, tied to seismic using a synthetic generated from such data, and deemed
uncommercial. The plug and abandonment operations were completed on 22 October 2018 and the Parker
77B rig released. Otto has no ongoing interest in the Bivouac Peak leases.
Vermillion 232 (VR 232)
In June 2018 Byron Energy Inc, a wholly owned subsidiary of Byron Energy Limited was advised by the Bureau
of Ocean Energy Management (“BOEM”) that its bid for VR 232 was deemed acceptable by the BOEM and the
lease was awarded to Byron. Pursuant to the terms of a Participation Agreement, effective 1 December 2015,
between Byron and Otto, Otto elected to participate in VR 232 at a fifty percent (50%) working interest. The
lease is subject to a 12.5% Federal Government royalty.
Having elected to participate in VR 232 at a 50% working interest, Otto’s right to participate in new assets or
projects under the December 2015 Participation Agreement with Byron had been fulfilled.
In May 2019 Otto acquired Byron Energy’s 50% interest in, and operatorship of, VR 232 at no cost. Upon
completion of the transfer, Otto’s working interest will be 100% and net revenue interest will be 87.5%.
VR 232 is adjacent to Otto’s 50% owned SM 71 oil field and adds drilling opportunities which increase Otto’s
potential upside around the SM 71 facilities. Over 2 Bcf of gas and 30 Mbbls of oil have been produced from
VR 232 between 1995 and 1997.
Otto has recently acquired a modern, high quality 3D seismic data set over the SM 71 area (including VR 232)
and part of the work being done will focus on the prospectivity of VR 232 given its proximity to SM 71.
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10
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
Alaska Western Blocks
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
On 25 June 2018 Otto, along with 88 Energy Limited (ASX:88E) and Red Emperor Resources NL (ASX:RMP)
(collectively the “Consortium Partners”), announced they had executed a binding term sheet agreement with
Great Bear Petroleum Ventures II LLC (“Great Bear”) to acquire the majority of Great Bear’s working interest
in four leases comprising the “Western Blocks” (ADL#s 391718, 391719, 319720 and 391721) totaling over
22,710 acres. On 30 July 2018 Otto advised that the definitive agreements had been executed with Otto holding
a 22.5% working interest in the new joint venture (18.75 Net Revenue Interest).
The Winx Prospect was a very large, 3D seismic defined oil prospect in the successful Nanushuk play fairway.
Sitting immediately adjacent to one of the largest North American conventional oil discoveries made in recent
times, the Winx-1 well will exposed Otto’s shareholders to a prospect of significant size with similar
attributes.
The Winx-1 well commenced drilling on 15 February 2019 and intersected all of the pre-drill targets safely
and efficiently. Total Depth of 6,800’ was reached on 3 March 2019. A comprehensive wireline logging
program was then successfully run and completed.
Provisional petrophysical analysis of the wireline logging program indicated low oil saturations in the
primary Nanushuk Topset objectives; testing and fluid sampling indicated that reservoir quality and fluid
mobility at this location was insufficient to warrant production testing, despite encouragement from oil
shows and logging while drilling (LWD) data. Winx-1 was subsequently plugged and abandoned.
The forward plan is to further evaluate and integrate the valuable data acquired at Winx and reprocess the
Nanuq 3D seismic (2004) in order to evaluate the remaining prospectivity on the Western Leases including
the Nanushuk Fairway potential.
Alaska Central Blocks
Through its agreements with Great Bear Petroleum Operating ("Great Bear") in 2015, Otto has between an
8% and 10.8% working interest in 54 leases (covering 154,295 gross acres) held by Pantheon Resources plc
(AIM:PANR) on the Alaskan North Slope (“Central Blocks”).
Pantheon’s acquisition of Great Bear Petroleum Ventures I LLC and Great Bear Petroleum Ventures II LLC
(collectively: Great Bear) completed in January 2019.
The leases are in a major play fairway south of the Prudhoe Bay and Kuparuk giant oil fields.
Extensive, modern 3D seismic coverage, existing well control and proximity to the all-weather Dalton
Highway and Trans-Alaskan Pipeline System (TAPS) means the acreage is well positioned for exploration.
The existing 3D seismic has allowed development of an extensive prospect portfolio which includes at least
4 well locations.
Otto’s exposure on the first two wells is limited to US$2.6m/well. Otto had no activity in this area during the
year ended 30 June 2019. 19 leases deemed unprospective were relinquished during the year and a further
17 transferred to Burgundy Xploration LLC for US$6,054.
3. Corporate and Administration
Houston Office
During the year the Company has completed the establishment of its Houston office and appointment of a
US-based technical team. Managing Director Matthew Allen relocated to Houston in August 2018 to lead the
team. In addition, Otto announced the following technical appointments in Houston:
Will Armstrong – Vice President, Exploration and New Ventures
Philip Trajanovich – Senior Commercial Manager
Mark Sunwall – Senior Exploration Consultant
Kevin Small – Senior Exploration Consultant
The exploration team is led by Will Armstrong, who has more than 30 years of experience across the Gulf of
Mexico. Will’s exploration work has seen the drilling of 162 prospects across his career at a commercial
success rate in excess of 66%.
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41
DIRECTORS’ REPORT
For the year ended 30 June 2019
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
The exploration team were engaged as consultants inside the Otto business since early 2018. This involved
the screening of a number of prospects and investment opportunities including the Hilcorp Gulf Coast
package.
Tanzania
During the year the Company also received the full US$800,000 owed by Swala under settlement and other
commercial arrangements as set out in Otto’s ASX release of 26 May 2017.
Commodity Price Risk Management
On 3 April 2019 Otto announced that it has implemented a hedging program in the United States for its SM
71 oil production. The hedging program is designed to provide certainty of cash flows and funding during a
period of significant investment in growth projects.
Otto acquired US$60/bbl puts over 111,000 bbls of oil production from its interest in the SM 71 oil field. The
monthly volumes covered by the put options are between 50% and 70% of the forecast Proved Developed
Producing (PDP) production from the field (PDP forecast is as per the Collarini 30 June 2018 reserves
estimation. See the ASX release of 6 August 2018) .
The puts are based on the LLS benchmark and the premium for the puts is US$1.75/bbl amounting to a total
of US$194,000, payable up front.
The use of US$60/bbl strike price put options provide Otto with a minimum price receivable for those barrels.
Otto still maintains the upside exposure where the LLS benchmark price achieved is over US$60/bbl.
On 20 September 2019 Otto acquired $55.00 per barrel put options over 34,500 barrels of oil from October
2019 to January 2020 at a premium of $1.83 per barrel in accordance with its commodity price risk
management policy.
Strategy
The Company’s core strategic goal is to grow production in the Gulf of Mexico to 5,000 boepd by the end of
2020.
As at the date of this report the status of execution of this strategy is as follows:
•
Through successful exploration Otto has built a portfolio of four conventional oil and gas properties in
the US Gulf of Mexico and Gulf Coast with two in production and two in the development/evaluation
stage. These four projects, when all in full production (anticipated in the second half of 2020), are
expected to take Otto close to its stated goal of 5,000 boepd;
• Growth strategy underpinned by strong production and cash flow from flagship Gulf of Mexico SM 71
asset and the onshore Lightning field that commenced production in May 2019;
• Exciting pipeline of up to four high-impact exploration opportunities as well as development wells taking
place over the next six months;
• Progressing a finance facility for funding current and future developments thus allowing Otto to
continue to look for further growth opportunities in the Gulf of Mexico; and
• An experienced team located in Houston with a track record of successfully growing, operating and
divesting oil and gas assets globally who understand risk and capital management.
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12
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
Gulf of Mexico
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
The Company’s strategy is currently focused on growing its business in the Gulf of Mexico for the following
reasons:
• Proven prolific hydrocarbon province where technologies such as RTM seismic processing continue to
create new opportunities;
•
Low sovereign risk;
• High margin oil with breakeven economics around US$20/barrel;
• Short cycle time from discovery to development of 8-18 months;
•
Low cost drilling and development;
• Relatively low risk exploration;
• Deal flow is liquid and a full spectrum of opportunity size is available;
• Otto has area expertise and well developed business relationships; and
• Otto has production in the area.
In order to deliver on the strategy, the Company’s business development focus over the past year in the Gulf
of Mexico has been on pursuing prospects with the following characteristics:
• Miocene/Pliocene/Oligocene geology which are amplitude supported;
•
Investing capital into drilling, not seismic;
• Seeking early cashflow/ROI – Approximately 12-18 months from exploration to production;
• Progressing from the shallow water (<300 feet) and onshore to smaller manageable working interests
in the deeper transition zone following exploration success – keeping capex manageable; and
• High liquids yields to increase margins.
Key Risks
The key areas of risk, uncertainty and material issues that could affect the achievement of Otto’s strategic
goals and delivering on its targets are described below. Note that this is not an exhaustive list of risks that
may potentially affect the Company.
Operating Risk
Sustained, unplanned interruption to production may impact Otto’s financial performance and its ability to
fund its forward programs. The facilities in which we currently have a non-operated working interest and
third party pipelines, refineries and gas plants which are utilized for sales and transportation of
hydrocarbons are subject to operating hazards associated with major accident events, cyber-attack and
weather events, which can result in a loss of hydrocarbon containment, diminished production, additional
costs, environmental damage and harm to people or reputation. This risk also extends to unexpected sub-
surface outcomes.
Otto, through its exploration program, has been working to diversify its production base so it is not solely
reliant on one asset (SM 71) should any event such as those mentioned above occur.
Otto has insurance cover for a number of these risks where it is appropriate and commercially justifiable to
do so. For example, for SM 71 Otto has insurance cover for property damage, but does not have cover for
loss of profits as the cost is prohibitive.
As Otto is non-operator, the operating risks are extended to include the performance of the operator. These
risks could include inadequate resourcing or systems, misalignment of interest, inadequate capture or
provision of data and information, poor financial position or unfavourable or inadequate agreement with the
operator. Consequences of poor performance by an operator could extend to operational incidents, financial
loss, loss of opportunity, non-compliance, legal disputes or less than optimal financial returns from the field.
13
43
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the year ended 30 June 2019
For the Year Ended 30 June 2019
Otto seeks to manage the risks around performance of the operator by entering into ventures with operators
who have demonstrated competencies and financial capacity. Through its due diligence Otto seeks to ensure
that the operator’s reputation is sound and that Otto’s interests are in alignment before committing to
participation.
Unsuccessful Exploration and Oil and Gas Reserves Depletion Risk
Without additions to reserves through exploration and development drilling success or acquisitions, Otto’s
oil and gas production, and hence revenues and cash flows, will decrease over time as production from
existing fields declines naturally. The rate of decline is dependent on reservoir characteristics.
Exploration for and development of reserves may be unsuccessful or unprofitable due to a number of factors
that are inherent in the oil and gas industry and are outside Otto’s control. These include the risk that Otto
will not discover commercially productive reservoirs or discovers reservoirs that do not produce sufficient
revenues to return a profit. Drilling and development operations may be curtailed, delayed or cancelled as a
result of other sub-surface, mechanical or environmental factors or events causing significant financial
losses.
Otto seeks to mitigate the risk of unsuccessful exploration by having an exploration strategy based around a
strict set of criteria including geographical restrictions, probabilities of success, partner and operator
capacity and reputation (including drilling contractors) and required rates of return. Otto then seeks to
ensure that it has suitably qualified and experienced staff and advisors to generate and evaluate
opportunities within the set criteria. Any acquisition of reserves is subject to the same discipline.
Where possible, Otto also seeks to reduce the likelihood or impact of such risks through commercial
agreements where possible.
Key Management Risk
As Otto is a non-operator of its key interests, it has a small management team. Therefore the Company relies
heavily on the services of its Chief Executive Officer and senior management. Having a suitably qualified and
reputable operating team in place with appropriate relationships and experience in the Gulf of Mexico oil and
gas business is critical to Otto’s success so far and in the future. The loss of the services of members of the
Houston operating team, and the Chief Executive Officer in particular, could have a negative impact on the
Company’s operations and relationships. Particularly in the short term until suitable replacements could be
recruited. Otto does not maintain or plan to obtain any insurance against the loss of any key management
personnel.
The Board is aware of this risk and is always looking to ensure there is some level of succession planning,
while managing ongoing costs.
Commodity price risk
Otto’s revenues, profitability and generation of cash flows depend significantly on crude oil and natural gas
prices. Oil and natural gas prices are volatile and low prices could have a material adverse impact on
profitability and cash flow. There are a number of factors that can cause fluctuations in price that are beyond
the control of Otto.
Otto monitors and analyses the oil and gas markets and seeks to reduce price risk where reasonable and
practical. The Company has policies and procedures for entering into hedging contracts to mitigate against
the fluctuations in oil price and exchange rates.
Significant changes in the state of affairs
Significant changes in the state of affairs of the Group during the financial year were as follows:
•
In May 2019 production commenced from Otto’s second discovered oil and gas field – the Lightning field
onshore Texas. The field is now producing at approximately 12 MMscf/day and 360 barrels of oil a day
(100%). A second development well is currently being contemplated on the field.
• Since the end of the year Otto has announced exploration discoveries at Mustang (onshore Texas) and
Green Canyon 21 (offshore Gulf of Mexico). The Company is confident that these discoveries will lead to
44
14
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
producing fields taking Otto’s total number of producing assets to four in 2020. Refer to the subsequent
events section of the report for further details.
• During August 2018 Otto completed a capital raising of A$20 million through a placement and
accelerated entitlement offer as set out below.
a) The Placement raised a total of A$10m through the issue of approximately 169.5 million shares at
A$0.059 per share.
b) The Institutional Entitlement Offer raised a total of A$3m through the issue of approximately 51.6
million shares at A$0.059 per share with a take up of 34%. The Institutional Entitlement Offer
shortfall was strongly oversubscribed by institutional shareholders. Shares issued under the
placement and Institutional Entitlement Offer were allotted and commenced trading on 10 August
2018.
c) A total of A$7 million was raised from the Retail Entitlement Offer through the issue of 118.5 million
shares at A$0.059 per share.
A$5.5 million (78%) of Entitlements were taken up leaving a Shortfall of A$1.5 million. A further
A$6.0 million in subscriptions were received for Additional New Shares which was A$4.5 million in
excess of the Shortfall of A$1.5 million, therefore the A$4.5 million was refunded. Accordingly,
given the Retail Entitlement Offer was oversubscribed, there was no allocation to underwriters.
Morgans Corporate Limited acted as lead manager and underwriter to the entitlement offer with Allens
acting as legal advisor.
• During April 2019, Otto completed a capital raising of approximately A$31 million as follows:
a) a Placement raising a total of A$11.0m through the issue of approximately 207.5 million shares at
A$0.053 per share;
b) an accelerated Institutional Entitlement Offer raising a total of A$7.6m through the issue of
approximately 143.2 million shares at A$0.053 per share. The Institutional Entitlement Offer
shortfall was strongly oversubscribed by institutional shareholders.
c)
the retail component of the Entitlement Offer raised A$12.3 million. The Company received
applications for Entitlements totalling A$5.7 million (before costs) representing acceptances of
46%. In addition, the Company has received applications for A$1.2 million of Additional New Shares
to give a total of A$6.9 million in applications under the Retail Entitlement Offer. Overall 56% of the
new shares issued will go to existing shareholders. The Shortfall of A$5.4 million was allocated
pursuant to the Underwriting Agreement with Morgans Financial Limited.
Morgans Corporate Limited acted as Lead Manager and Underwriter to the Entitlement Offer, Adelaide
Equity Partners Limited as Financial Advisor and Allens acting as legal advisor. Euroz Securities Limited
were Managers to the offer.
The funds were raised to be used in conjunction with cash flows from Otto’s 50% owned SM 71 oil field
and future cash flows from the Lightning development to fund Otto’s US$9.0 million share of the GC-21
drilling program, redeem US$8.1 million of the convertibles notes that were on issue and for working
capital including contingent development wells.
• Under the terms of the Convertible Notes issued on 2 August 2017, Otto issued a redemption notice to
the Noteholders on 26 March 2019 for the full 8.2 million convertible notes. The Noteholders elected to
convert 100,000 of the notes with the balance of 8.1 million notes redeemed on 30 April 2019. As a result,
the Company had no debt as at 30 June 2019.
15
45
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
For the year ended 30 June 2019
Significant events after the balance date
No matters or circumstances have arisen since 30 June 2019 that have significantly affected, or may
significantly affect the Group’s operations, the results of those operations, or the Group’s state of affairs in
future financial years apart from those listed below:
• GC 21 – Bulleit Well
On 8 August 2019 Otto announced that the GC 21 “Bulleit” well, operated by Talos Energy, Inc (“Talos”)
(NYSE: TALO) had been successfully drilled to Total Depth. The well drilled through the deeper
exploration target, the MP sands, after intersecting oil pay in the shallower DTR-10 sand package as
announced to the ASX on 13 June 2019. The well intersected the following discovered intervals:
- DTR-10 interval –net 140 feet of TVD oil pay encountered; and
- MP interval – approximately net 110 feet of TVD oil pay expected to be delivered in high quality
reservoir consistent with analogue wells in the GC18 field.
Following the discovery in the DTR-10 sands, attempt to drill to the deeper objective MP sands were
delayed due to poor hole conditions and compromised drilling operations requiring sidetracking. In
addition, the passing of Hurricane Barry required the rig to disconnect to ensure safe operations. As a
result of these operations, the cost of drilling the GC21 “Bulleit” well exceeded the pre-drill estimates
of US$9.0m net to Otto. The effect of these events is expected to increase Otto’s financial exposure to
the Bulleit well by approximately US$6.5 to US$7.5m net to Otto.
The GC 21 development plan is being progressed by the Operator to complete the discovery well in the
first half of 2020. The Operator will complete the well as a production well and then tie it back to the
Talos-owned and operated Green Canyon 18 (GC 18A) facility approximately 10 miles (~16 km) west of
the “Bulleit” well. The development will involve the use of a subsea completion that is common for
projects of this nature and water depth in the Gulf of Mexico. The joint venture will undertake a review
of the operator’s plan of development in the coming month with formal commitment to the development
expected shortly thereafter.
Subject to the commitment to development outlined above, Otto will report maiden reserves from the
GC21 discovery incorporating the development plans.
The Company is working on a finance facility to fund the development.
• Mustang
On 23 July 2019 Otto advised that the initial exploration well, Thunder Gulch #1, within the Mustang
prospect in Chambers County Texas, has reached final total depth of 18,164 ft MD (18,001 ft TVD).
Petrophysical evaluation of wireline logging data together with mudlog hydrocarbon shows seen whilst
drilling indicated the presence of a total net hydrocarbon filled sand interval of approximately 57 feet
TVT (True Vertical Thickness). This petrophysical evaluation was undertaken using historical
parameters for production performance in the play trend. The Operator, Hilcorp Energy, then ran
production casing and completed the well.
The operator has sourced equipment required for the testing of the deep, high pressure Mustang
discovery. With reservoir pressures at the discovery location of over 15,000 psi, specialised high-
pressure equipment is required that is not commonly used. The initial testing will involve the perforation
of various discovery intervals in order to understand reservoir deliverability and the design of a
completion program to optimise ultimate production.
Once the testing phase of the discovery is completed, the joint venture would then plan for the
installation of surface production equipment and the connection into a nearby sales pipeline to enable
production to commence. This is expected to occur during the fourth quarter of 2019, subject to the
outcome of the impending test program.
Through participation in the drilling of the Thunder Gulch #1 exploration well, Otto has earned a 37.5%
working interest in the leases covering the entire prospect.
16
46
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
• SM 71
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
Otto announced on 22 August 2019 that Byron Energy, the operator of SM 71, had advised that it had
completed the interpretation of reprocessed seismic data, resulting in the identification of two areas in
the D5 Sand reservoir which it believes will not be drained efficiently by the currently producing SM 71F1
and SM 71 F3 wells. To effectively drain these two areas, the Operator has estimated that two additional
wells will be needed to fully develop the D5 Sand reservoir at SM 71.
The first of these proposed wells, the SM 71 F4, would test a D5 Sand reservoir anomaly that is outboard
of the main D5 field, (see attached illustration). If successful, this would extend and prove up additional
reserves in the D5 reservoir. The second proposed well, the SM 71 F5, will test an area that the Operator
believes will be poorly drained, if at all, by the F3.
The Operator estimates that after the SM71 F4 and SM71 F5 wells are completed, assuming success,
the D5 reservoir at SM 71 will be fully developed except for an attic well required in three- or four-years’
time.
Otto has the right to participate in the wells at its working interest of 50%. Otto is currently considering
all materials provided by the operator and evaluating the proposed wells using its own recently
reprocessed 3D data over the area. Operator has advised that it is in final stages of negotiating a rig
contract for this drilling program and it is expected to be available and on location in early October,
pending final permit approvals.
Currently the field is producing approximately 3,100 bopd and 3.3 mmcfgpd, on a gross basis after
shrinkage at the sales meter.
• Board and Executive Changes
On 11 September 2019 the Company announced that its Chairperson, Mr John Jetter, had confirmed to
the Board, and the Board of Otto had agreed, that he will step down from the role of Chairperson at the
coming Annual General Meeting of shareholders on 21 November 2019. Mr Jetter will remain as a non-
executive director and serve on the current Board Committees of which he is a member in order to
oversee the seamless transition of the role of Chairperson and the successful delivery of Otto’s Board
renewal which has commenced under his guidance. Mr Jetter will not seek re-election at the Annual
General Meeting in 2020.
Mr Ian Boserio has been nominated by the Board as Chairperson Elect to assume the role vacated at
the 2019 Annual General Meeting by Mr Jetter. In the meantime Mr Boserio will assume the role of
Deputy Chair.
In addition, Mr Ian Macliver, has advised the Board that he also will retire upon the appointment of a
suitably qualified, independent non-executive director to assume the roles he currently occupies. A
process has commenced to identify a candidate for this role and Mr Macliver has advised that he will
retire from the Board of Otto Energy at the time his replacement is appointed, or at the latest by 30 June
2020.
The Board renewal process will be an ongoing focus of the Board to ensure that its composition reflects
the nature of the business as it evolves from being primarily focused on exploration activities towards
development and production activities.
On 23 August 2019 the Company advised that had accepted the resignation of its Chief Financial Officer
and Company Secretary, Mr. David Rich. Mr. Rich joined Otto in January 2017 and has been a highly
valued member of the management team in supporting the successful development of the US Gulf of
Mexico business. Mr Rich will continue in his current roles until 1 November 2019. The Board thanked
Mr. Rich for his contribution to the business over the last two and a half years.
The Board has commenced a process to appoint a new Chief Financial Officer in Houston as part of the
ongoing commitment it made in April 2018 to supporting the growth of the US Gulf of Mexico business.
This will involve the transition of the majority of the financial and accounting support functions from
Perth to Houston.
17
47
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
For the year ended 30 June 2019
• Reserves Statement
On 19 September 2019 the Company released its statement of reserves and prospective resources as
at 30 June 2019. The statement of reserves included SM 71 and the maiden statement of reserves for
Lightning. The reserves for SM 71 and Lightning were compiled by independent consultants Collarini
and Associates and Ryder Scott Company respectively. The summary statement of reserves and
prospective resources at 30 June 2019 is set out below. The individual statements for SM 71 and
Lightning are included in the Production and Development section above. Full details including the
reconciliations and notes on the statements are included in the ASX release of 19 September 2019.
Total
Gross (100%)
Otto Net
Gas
Oil (Mbbl)
3,219
Gas
(MMscf) MBoe
(MMscf) MBoe
Oil
(Mbbl)
12,599 5,318 1,271 3,910 1,923
1,118 452
682 3,765 1,310 265
3,292 1,295
11,117 3,779 746
27,481
2,282 8,320 3,670
10,407
19,823 9,398 2,417 6,101 3,434
14,421
47,304
7,103
4,699
19,806
10,072 3,049
34,468 9,409 1,371
1,927
5,828
6,094
11,922
3,664
15,586
81,772
29,214
6,070
24,492
10,152
67,309
89,875
82,289
Proved Producing
Proved Behind Pipe
Proved Undeveloped
Proven (1P)
Probable
Proven Plus Probable (2P)
Possible
Proven Plus Probable Plus
Possible (3P)
Total Prospective Resource
(best estimate, unrisked)
• Hedging
On 20 September 2019 Otto acquired $55.00 per barrel put options over 34,500 barrels of oil from October
2019 to January 2020 at a premium of $1.83 per barrel in accordance with its commodity price risk
management policy.
Likely developments and expected results
Likely developments in the operations of the Group that were not finalised at the date of this report included:
•
•
•
•
•
Finalisation of the development plan for the DTR-10 and MP sands on the Green Canyon 21 lease
offshore Gulf of Mexico, USA;
Testing of the Mustang discovery in Matagorda County, Texas. The results of which will determine the
development plan for the field to take it to production;
Participate in the drilling of another three to four wells on the Gulf Coast with Hilcorp;
Participate in the drilling of further wells on the SM 71 lease; and
Completion of a finance facility to fund future developments including GC 21.
Additional comments on expected results of certain operations of the Group are included in the Review of
Operations above. In accordance with its objectives, the Group intends to participate in a number of
exploration and appraisal wells and will consider growing its exploration effort by farm-in, permit application
and/or acquisition within its existing operational focus area of North America with a specific target of the
onshore and offshore Gulf of Mexico. Further information on likely developments in the operations of the
Group and the expected results of operations have not been included in this annual financial report because
the Directors believe it would be likely to result in unreasonable prejudice to the Group.
48
18
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
Environmental regulation and performance
So far as the Directors are aware, there have been no breaches of environmental conditions of the Group’s
exploration or production licences. Procedures are adopted for each exploration program to ensure that
environmental conditions of the Group’s tenements are met.
Directors’ meetings
The number of meetings of Directors (including meetings of committees of Directors) held during the year
and the numbers of meetings attended by each Director were as follows:
Board meetings
Audit and risk
management
committee
Remuneration and
nomination committee
Director
Number
attended
Number
eligible to
attend
2
-
2
-
-
-
*Mr Jetter was appointed to the Audit and Risk Management Committee on 17 December 2018.
Number
eligible to
attend
1
-
2
2
-
-
Number
eligible to
attend
16
16
16
16
16
7
Mr J Jetter*
Mr M Allen
Mr I Macliver
Mr I Boserio
Mr P Senycia
Mr K Small
15
16
16
16
16
7
Number
attended
-
-
2
2
-
-
Number
attended
2
-
2
-
-
-
Indemnification and insurance of Directors and officers
During the financial year, the Company paid a premium of $151,111 to insure the Directors and officers of
the Company and its controlled entities, and the managers of each of the divisions of the Group.
The liabilities insured are legal costs that may be incurred in defending civil or criminal proceedings that
may be brought against the officers in their capacity as officers of entities in the Group, and any other
payments arising from liabilities incurred by the officers in connection with such proceedings. This does not
include such liabilities that arise from conduct involving a wilful breach of duty by the officers or the improper
use by the officers of their position or of information to gain advantage for them or someone else or to cause
detriment to the Company. It is not possible to apportion the premium between amounts relating to the
insurance against legal costs and those relating to other liabilities.
Proceedings on behalf of company
No person has applied to the Court under section 237 of the Corporations Act 2001 for leave to bring
proceedings on behalf of the Company, or to intervene in any proceedings to which the Company is a party,
for the purpose of taking responsibility on behalf of the Company for all or part of those proceedings.
No proceedings have been brought or intervened in on behalf of the Company with leave of the Court under
section 237 of the Corporations Act 2001.
Rounding of amounts
The Company is of a kind referred to in ASIC Corporations (Rounding in Financial/Directors’ Reports)
Instrument 2016/191, and in accordance with that instrument, amounts in the consolidated financial
statements and Directors’ Report have been rounded off to the nearest thousand dollars, unless otherwise
indicated.
19
49
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the year ended 30 June 2019
For the Year Ended 30 June 2019
Non-audit services
The following non-audit services were provided by the entity's auditor, BDO Australia. The Directors are
satisfied that the provision of non-audit services is compatible with the general standard of independence
for auditors imposed by the Corporations Act 2001. The nature and scope of each type of non-audit service
provided means that auditor independence was not compromised.
BDO Australia received or are due to receive the following amounts for the provision of non-audit services:
Tax compliance services
Tax consulting and tax advice
2019
US$
2018
US$
13,058
1,410
14,468
3,751
1,056
4,807
Auditor’s independence declaration
The auditor’s independence declaration is included on page 64 of this report.
Remuneration report (audited)
The Directors of the Company have prepared this remuneration report to outline the overall remuneration
strategy, policies and practices which were in place during 2019. This structure includes the share rights
and option plans approved by the shareholders at the Company’s Annual General Meeting on 16 November
2016. The report has been prepared in accordance with Section 300A of the Corporations Act 2001 and its
regulations.
Otto Energy’s remuneration policy is designed to ensure that the level and form of compensation achieves
certain objectives, including:
a) attraction and retention of employees and management to pursue the Group’s strategy and goals;
b) delivery of value-adding outcomes for the Group;
c)
d)
fair and reasonable reward for past individual and Group performance; and
incentive to deliver future individual and Group performance.
Remuneration consists of base salary, superannuation, short term incentives (STI) and long term incentives
(LTI). Remuneration is determined by reference to market conditions and performance. Performance is
evaluated at an individual level as well as the performance of the Group as a whole.
The remuneration policies and structure in 2019 were generally the same as for 2018.
Key management personnel disclosed in this report are:
Directors
Mr John Jetter
Mr Matthew Allen
Mr Ian Macliver
Mr Ian Boserio
Mr Paul Senycia
Mr Kevin Small
Non-Executive Chairman
Managing Director and Chief Executive Officer
Non-Executive Director
Non-Executive Director
Non-Executive Director
Executive Director and Senior Exploration Consultant, commenced as a Consultant
on 4 April 2018 and became a director on 29 January 2019
Executives
Mr Will Armstrong
Mr Philip Trajanovich Senior Commercial Manager (US) commenced 4 April 2018
Mr David Rich
Vice President – Exploration and New Ventures (US) commenced 4 April 2018
Chief Financial Officer and Company Secretary, commenced 28 February 2017 and
31 January 2017 respectively
50
20
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
Remuneration governance
Role of the Remuneration and Nomination Committee
The Remuneration and Nomination Committee’s role is to review and recommend remuneration for key
management personnel and review remuneration policies and practices including Company incentive
schemes and superannuation arrangements.
The Committee considers independent advice, where circumstances require, on the appropriateness of
remuneration to ensure the Group attracts, motivates and retains high quality people. An advisor was not
retained for the 2018 calendar year review.
The ASX Listing Rules require that the maximum aggregate amount of remuneration to be allocated among
the non-executive Directors be approved by shareholders in a general meeting. In proposing the maximum
amount for consideration by shareholders and in determining the allocation, the Remuneration and
Nomination Committee takes account of the time demands made on Directors and such factors as fees paid
to non-executive Directors in comparable Australian companies.
The Remuneration and Nomination Committee comprises of two non-executive Directors.
Remuneration arrangements for Directors and executives are reviewed by the Remuneration and
Nomination Committee and recommended to the Board for approval. The Remuneration and Nomination
Committee considers external data and information, where appropriate, and may engage independent
advisors where appropriate to establish market benchmarks.
Remuneration arrangements are determined in conjunction with the annual review of the performance of
Directors, executives and employees of the Group. Performance of the Directors and the CEO of the Group
is evaluated by the Board, assisted by the Remuneration and Nomination Committee. The CEO reviews the
performance of executives with the Remuneration and Nomination Committee. These evaluations take into
account criteria such as the achievement toward the Group’s performance benchmarks and the achievement
of individual performance objectives.
Non-executive director remuneration policy
Non-executive Directors of the Group are remunerated by way of fees, statutory superannuation, and LTI’s
where applicable. Fees are set to reflect current market levels based on the time, responsibilities and
commitments associated with the proper discharge of their duties as members of the Board.
The current base fees were reviewed in June 2018. Prior to this there had been no increase in non-executive
director fees since 2012. Non-executive Directors’ fees are determined within an aggregate non-executive
Directors’ fee pool limit, which is periodically recommended for approval by shareholders. The maximum
currently stands at A$500,000 per annum and was approved by shareholders at the Annual General Meeting
in January 2008.
Non-executive Directors received a grant of performance rights on 15 November 2018 following approval by
shareholders at the Company’s Annual General Meeting. The grant was based on 50% of FAR. The Board
believes that the issue constituted reasonable remuneration having considered the peer group comparisons,
the recent history of the Company, the experience of each of the Directors and the responsibilities involved
in that office.
21
51
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the year ended 30 June 2019
For the Year Ended 30 June 2019
Directors’ fees
The following fees have applied:
Base fees
Chair
Non-executive Directors
From 1 July
2017 to
30 June
2018
From 1 July
2018
A$150,000
A$90,000
A$ 125,000
A$ 75,000
Additional fees
Audit and Risk Management Committee Chair
A$10,000
A$ 10,000
Retirement allowances for non-executive Directors
In line with ASX Corporate Governance Council, non-executive Directors’ remuneration does not include
retirement allowances. Superannuation contributions required under the Australian superannuation
guarantee legislation continue to be made and are deducted from the Directors’ overall fee entitlements.
Appointment
The term of appointment is determined in accordance with the Company’s Constitution and is subject to the
provisions of the Constitution dealing with retirement, re-election and removal of Directors of the Company.
The Constitution provides that all Directors of the Company, other than the Managing Director, are subject
to re-election by shareholders by rotation at least every three years during the term of their appointment.
Directors and executive remuneration policy and framework
The remuneration arrangement for Directors and executives of the Group for the year ended 30 June 2019 is
summarised below.
The remuneration structure in place for the year ended 30 June 2019 applies to all employees including key
management personnel and staff members of the Group. The Group‘s remuneration structure has three
elements:
fixed annual remuneration (FAR) or base salary (including superannuation);
a)
b) short term incentive (STI) award which provides a reward for performance in the past year; and
c)
long term incentive (LTI) award which provides an incentive to deliver future Company performance.
Executive remuneration mix
In accordance with the Group’s objective to ensure that executive remuneration is aligned to Group’s
performance, a significant portion of the executives’ target pay is “at risk”.
a) Fixed annual remuneration (FAR) or base salary (including superannuation);
To attract and retain talented, qualified and effective employees, the Group pays competitive base salaries
which have been benchmarked to the market in which the Group operates. The Group compiles competitive
salary information on companies of comparable size in the oil and gas industry from several sources. Where
appropriate, information is obtained from surveys conducted by independent consultants and national and
international publications. In the past the Board has engaged independent advisors to review the
remuneration levels paid to the Group’s key management personnel. An advisor was not retained for the
2018 calendar year review.
FAR is paid in cash and is not at risk other than by termination. Individual FAR is set each year based on job
description, competitive salary information sourced by the Group and overall competence in fulfilling the
requirements of the particular role.
52
22
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
There is no guaranteed base pay increases included in any executives’ contracts.
Superannuation contributions required under the Australian superannuation guarantee legislation continue
to be made and are deducted from the executives overall FAR entitlements.
b) Short-term incentives
Executives have the opportunity to earn an annual short-term incentive (STI) if predefined targets are
achieved. The CEO and other members of the executive team have an STI opportunity of approximately 20%
of FAR. The targets are reviewed annually.
STI awards for the executive team in the 2019 financial year were based on the scorecard measures and
weightings as disclosed below. Objectives and measures aligned to the Company’s strategic and business
objectives were set and monitored by the Board. These included the following general categories:
• Health, safety & environment
• Total shareholder return
• Asset specific
• New business development
• Leadership
The Board and Remuneration and Nomination Committee are responsible for assessing whether the
predefined targets are met. The Committee review in February 2019 concluded that no STI payments would
be awarded.
Separately, in October 2018 the Board awarded the Chief Financial Officer a A$50,000 bonus in recognition
of his exceptional performance and contribution during the period July to October 2018.
c) Long-term incentives
The Group believes that encouraging its employees to become shareholders is the best way of aligning their
interests with those of its shareholders. Long-term incentives are provided to certain employees via the Otto
Energy Limited Performance Rights and Employee Share Option Plans which were approved by shareholders
at the 2013 Annual General Meeting and again at the 2016 Annual General Meeting.
The Otto Energy Limited Performance Rights and Employee Share Option Plans are designed to provide long-
term incentives for employees to deliver long-term shareholder returns. Under the plans, participants are
granted performance rights or options which only vest if certain performance conditions are met and the
employees are still employed by the Group at the end of the vesting period. Participation in, and
administration of, the plan is at the Board’s discretion and no individual has a contractual right to participate
in the plan or to receive any guaranteed benefits.
The amount of performance rights that will vest depends on the vesting period and/or Otto Energy Limited’s
total shareholder return (‘TSR’), including share price growth, dividends, and capital returns. For the rights
on issue during, and at the end of the year, vesting of the rights for directors, the CEO and other members of
the executive team were based on TSR performance only. Other employees’ rights (40,000 rights in total)
were based 50% on time and 50% on TSR. The TSR performance required for all rights on issue as at 30 June
2018 is 10% per annum (based on 30 day VWAP) and for the rights granted during the current year ended 30
June 2019 is 15%, compounding from the date of grant to the measurement date (based on 90 day VWAP). If
the TSR vesting condition is not met on a measurement date, no rights vest and those performance rights
continue to exist as unvested performance rights to be retested at the next measurement date or expiry date
if there are no further measurement dates.
On the measurement date of 29 November 2018, 4,729,000 performance rights held by key management
personnel vested based on TSR. The TSR from the grant date of 29 November 2017 to the measurement date
was 19.8%, in excess of the required 10% TSR.
23
53
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the year ended 30 June 2019
For the Year Ended 30 June 2019
On the measurement date of 1 February 2019, a total of 4,600,000 rights granted to key management
personnel (4,630,000 rights in total) on 23 April 2015 did not vest as the TSR hurdle was not met and hence
the rights continue to exist to be tested at the expiry date of 31 December 2019. On 1 February 2019 10,000
time based rights vested and shares were issued to non-KMP staff.
Once vested, the performance rights are automatically converted into shares. Performance rights are
granted under the plan for no consideration.
For the award of performance rights to key management personnel on 15 November 2018, a flat rate of 50%
of FAR was used to calculate the number of rights awarded.
The total number of performance rights granted is subject to being reduced proportionately so that the total
number for performance rights is within:
i)
the Board’s determined cap on the total number of performance rights which are issued as LTI awards
in a given year; and
ii) any discretionary cap on the total number of rights on issue at any given time.
The Board has established an initial guideline that the total number of performance rights to be issued in a
single year will be capped at 1.7% of the fully paid issued capital of the Company as at the end of the prior
year. In the event that the potential total number of performance rights exceeds the cap then all awardees
receive a pro-rated reduced number of performance rights. This cap is at the discretion of the Board and
may be altered depending on the prevailing context.
During the year, the Board exercised its discretion regarding the cap and issued a total of 32,668,000
performance rights on 21 December 2018, which amounted to 2.1% of the issued capital at 30 June 2018. The
Board discretion was exercised considering the following important factors:
i)
ii)
the issue amounted to 1.7% of the shares on issue prior to the granting of the rights as there had been
a share issue since 30 June 2018; and
the rights issued included the one-off issue of sign on performance rights to three new, highly qualified
and experienced US staff members recruited to form the US-based technical team as set out in Otto’s
ASX release of 16 July 2018. The sign on performance rights formed an important part of their
remuneration packages and provide incentives linked to increases in shareholder value. Such sign on
benefits are customary in the US.
Share trading policy
The trading of shares issued to participants under any of the Company’s employee equity plans is subject to,
and conditional upon, compliance with the Company’s Securities Trading Policy. Executives are prohibited
from entering into any hedging arrangements over unvested rights. While the Employee Share Option Plan
does not specifically prohibit holders from entering into hedging arrangements over options, the Board
would include such restrictions in any offer under the Plan. The Company would consider a breach of this
policy as gross misconduct which may lead to disciplinary action and potentially dismissal.
Voting and comments made at the Group’s 2018 Annual General Meeting
At its 2018 Annual General Meeting, the Company received more than 93% of “yes” votes on its remuneration
report for the 2018 financial year and the Company did not receive any specific feedback at the Annual
General Meeting on its remuneration practices.
In the lead up to the 2018 Annual General Meeting and in discussions since with shareholders and proxy
advisors, concern has been expressed regarding equity grants to non-executive Directors. After considering
this feedback the Board has determined that it will not be seeking to make equity grants to non-executive
Directors at the 2019 Annual General Meeting.
Following concerns raised by investors and proxy advisors regarding the Board composition, including
matters of tenure, independence and alignment with the US strategy, the Company announced on 11
September 2019 that it had commenced a renewal process with several changes already taking place. Refer
to the subsequent events section of this report for further details.
54
24
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
Performance of Otto Energy Limited
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
The Corporations Act requires disclosure of the Company’s remuneration policy to contain a discussion of
the Company’s earnings and performance and the effect of the Company’s performance on shareholder
wealth in the reporting period and the four previous financial years. The table below provides a five year
financial summary.
30 June
2015
30 June
2016
30 June
2017
30 June
2018
30 June
2019
16,404
(20,086)
(5,247)
(5,194)
(18,409)
0.069
1.42
5.64
0.76
0.044
(1.70)
-
-
0.025
(0.44)
-
-
0.064
(0.37)
-
-
0.054
(0.95)
-
-
Net profit/(loss) after
tax (US$’000)
Share price at year
end (AUD)
Basic earnings/(loss)
(US cents per share)
Return of capital
(AU cents per share)
Total dividends
(AU cents per share)
Details of remuneration
The following table shows details of the remuneration received by Directors and executives of the Group for
the current and previous financial year.
Remuneration and other terms of employment for the Managing Director & Chief Executive Officer and other
executives are formalised in service agreements. For the US staff other than the Managing Director, terms
have been agreed and service agreements are currently being formalised. Each of these agreements
provides for performance related conditions and details relating to remuneration are set out below.
25
55
DIRECTORS’ REPORT
For the year ended 30 June 2019
0
2
6
,
0
2
1
6
7
9
,
1
0
1
9
9
9
,
4
9
6
4
0
2
,
6
2
4
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5
8
,
0
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5
6
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6
,
2
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9
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6
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,
3
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8
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,
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,
1
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,
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7
0
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,
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3
3
4
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6
,
3
0
3
0
7
2
,
7
2
4
-
3
6
4
,
8
1
4
4
6
6
,
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0
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0
4
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,
4
8
1
,
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8
2
1
,
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,
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9
2
5
,
6
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,
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F
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
(i)
(ii)
(iii)
(iv)
(v)
(vi)
(vii)
Performance rights have been valued using a single share price model. Further details of the
Performance Rights Plan is contained in this Remuneration Report on pages 58 to 62 and Note
21.
Mr M Allen (Managing Director and CEO) was seconded to the Houston office in August 2018.
Reflects the value of allowances and non-monetary benefits (including relocation, travel, health
insurance, car parking and any associated fringe benefits tax). Non-monetary benefits for M
Allen include one off relocation costs of $30,196. In addition to the non-monetary benefits
disclosed above for M Allen, the Company also incurred $55,255 of expatriate benefits relating
to future financial years. These will be expensed to the profit and loss in the relevant financial
year.
Mr P Senycia ceased employment with Otto on 31 December 2018 and continued on the Board
as a Non-executive Director from 1 January 2019.
Mr K Small was appointed a Director in January 2019. Mr Small consults to the Company as a
Senior Exploration Consultant in Houston.
Mr W Armstrong was appointed VP, Exploration and New Ventures in July 2019 based in
Houston
Mr P Trajanovich was appointed Senior Commercial Manager in July 2019 based in Houston.
The relative proportions of remuneration that are linked to performance and those that are not are as
follows:
Directors
Mr J Jetter
Mr P Senycia(iii)
Mr M Allen
Mr I Macliver
Mr I Boserio
Mr K Small
Executives
Mr D Rich
Mr W Armstrong(ii)
Mr P Trajanovich(iv)
Fixed and other
2018
2019
At risk – STI
At risk – LTI (i)
2019
2018
2019
2018
88%
88%
92%
88%
88%
96%
83%
95%
94%
94%
87%
88%
94%
94%
-
87%
-
-
-
-
-
-
-
-
10%
-
-
-
-
-
-
-
-
8%
-
-
12%
12%
8%
12%
12%
4%
7%
5%
6%
6%
13%
12%
6%
6%
-
5%
-
-
(i)
(ii)
(iii)
(iv)
Since long-term incentives are provided exclusively by way of performance rights or options, the
percentages disclosed also reflect the value of remuneration consisting of performance rights and
options, based on the value of performance rights or options expensed during the year.
Mr W Armstrong was appointed VP, Exploration and New Ventures in July 2019
Mr P Senycia ceased employment with Otto on 31 December 2018 and continued on the Board as a
Non-executive Director from 1 January 2019.
Mr P Trajanovich was appointed Senior Commercial Manager in July 2019
Service agreements
On appointment to the Board, all non-executive Directors enter into a service agreement with the Company
in the form of a letter of appointment. The letter summarises the Board policies and terms, including
remuneration, relevant to the office of Director.
Remuneration and other terms of employment for the Managing Director and Chief Executive Officer, Chief
Financial Officer and other executives (including executive Directors) are also formalised in service
agreements. Each of these service agreements provide for the provision of performance related cash
bonuses, and participation, when eligible, in the Otto Energy Limited Performance Rights and Employee
27
57
DIRECTORS’ REPORT
For the year ended 30 June 2019
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
Share Option Plans. For the US staff other than the Managing Director, terms have been agreed and service
agreements are currently being formalised. Other major provisions of the agreements relating to
remuneration are set out below.
All contracts with executives may be terminated early by either party with notice, per individual agreement,
subject to termination payments as detailed below.
Name
Mr Matthew Allen
Managing Director and
Chief Executive Officer
Mr Kevin Small
Senior Exploration
Consultant (iii)
Mr Paul Senycia
Executive Director &
Vice President
Exploration and New
Ventures (iv)
Mr David Rich
Chief Financial Officer
and Company Secretary
Mr W Armstrong
VP, Exploration and New
Ventures
Mr P Trajanovich
Senior Commercial
Manager
Commencement of
contract
24 June 2015
Base salary including
superannuation/other
retirement benefits(i)
$US per annum
$377,867
Termination benefit(ii)
6 months base salary
1 January 2019
$307,200
1 week notice
1 January 2016
$272,291
3 months base salary
9 January 2017
$250,136
3 months base salary
1 August 2018
$358,636
3 months base salary
1 August 2018
$338,143
3 months base salary
(i) Base salaries quoted are as at 30 June 2019; they are reviewed annually by the Board and the
Remuneration and Nomination Committee.
(ii) Termination benefits are payable on early termination by the Company, other than for gross misconduct.
(iii) Mr Small consults to the Company as a Senior Exploration Consultant under a 12 month consulting
agreement. The base salary quoted assumes 4 days per week for 48 weeks per annum. Mr Small was
appointed a Director in January 2019.
(iv) Mr Senycia ceased employment with Otto on 31 December 2018 and continues on the Board as a Non-
executive Director from 1 January 2019.
Share-based compensation
Otto Energy Limited has two forms of share based compensation for key management personnel. They are
performance rights and options.
Performance rights over equity instruments granted
Performance rights granted to key management personnel were granted as remuneration unless otherwise
noted. The rights granted have no exercise price and are exercisable from the date of vesting. Details of
vesting periods are set out at Note 21. All rights expire on the earlier of their expiry date or termination of
individual’s employment. Performance rights granted carry no dividend or voting rights.
The value of rights included in remuneration for the year is calculated in accordance with Australian
Accounting Standards. The assessed fair value at grant date of the performance rights is allocated equally
58
28
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
over the period from grant date to vesting date and the amount is included in the remuneration tables. Where
rights vest fully in the year of grant, the full value of the rights is recognised in remuneration for that year.
The value of performance rights at the grant date is calculated as the fair value of the rights at grant date,
using a Hoadley hybrid single share price model, multiplied by the number of rights granted.
No adjustment is made to the value included in remuneration or the financial results where the right
ultimately has a lesser or greater value than as at the date of grant. The inputs into the fair value calculation
of the rights granted and outstanding as at 30 June 2018 are set out in the following table. As set out below,
25,489,000 performance rights were granted to key management personnel in the year to 30 June 2019
(11,913,000 in 2018) (32,668,000 performance rights in total were granted across the Company).
The number of performance rights that will vest depends on the vesting period and/or Otto Energy Limited’s
Total Shareholder Return (“TSR”), including share price growth, dividends, and capital returns. Once vested,
the performance rights are automatically converted to shares. If the vesting condition is not met on a
measurement date (no rights vest), the performance rights will not lapse and will continue to exist as
unvested performance rights to be retested at the next measurement date or expiry date, whichever is later.
Performance rights are granted under the plan for no consideration. All the rights issued to KMP within the
30 June 2019 financial year require a compound TSR of 15% per annum from the grant date to the
measurement date in order to vest. (All rights issued prior to 1 July 2018 require a compound TSR of 10%
per annum from the grant date to the measurement date in order to vest).
29
59
DIRECTORS’ REPORT
For the year ended 30 June 2019
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d
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R
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S
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D
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60
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
Year ended 30 June 2018 – TSR based performance rights
For the Year Ended 30 June 2019
Measurement
Year ended 30 June 2018 – TSR based performance rights
date
Year ended 30 June 2018 – TSR based performance rights
Measurement
Grant date
date
Measurement
date
Expiry date
Grant date
29 Nov
2018
29 Nov
29 Nov
2017
2018
29 Nov
29
29 Nov
2018
Nov2022
2017
29 Nov
29
2017
Nov2022
29
Nov2022
1,309,000
29 Nov
2019
29 Nov
29 Nov
2017
2019
29 Nov
29 Nov
29 Nov
2019
2022
2017
29 Nov
29 Nov
2017
2022
29 Nov
2022
1,309,000
29 Nov
2020
29 Nov
29 Nov
2017
2020
29 Nov
29 Nov
29 Nov
2020
2022
2017
29 Nov
29 Nov
2017
2022
29 Nov
2022
1,309,000
Grant date
KMP rights on
Expiry date
issue at year
Expiry date
end:
KMP rights on
issue at year
Mr M Allen
KMP rights on
end:
issue at year
Mr J Jetter
Mr M Allen
end:
Mr I Macliver
Mr M Allen
Mr J Jetter
Mr I Boserio
Mr J Jetter
Mr I Macliver
Mr D Rich
Mr I Macliver
Mr I Boserio
Mr P Senycia
Mr I Boserio
Mr D Rich
KMP total rights
Mr D Rich
Mr P Senycia
on issue at year
end
KMP total rights
Mr P Senycia
Share price at
on issue at year
KMP total rights
grant date – A$
end
on issue at year
Expected
Share price at
end
volatility
grant date – A$
Share price at
Expected
Expected
grant date – A$
dividend yield
volatility
Expected
Expected
Risk free rate
volatility
dividend yield
Expected
Fair value – A$
Risk free rate
dividend yield
Total value – A$
Risk free rate
Fair value – A$
Fair value – A$
Total value – A$
344,333
1,309,000
234,333
1,309,000
344,333
206,667
344,333
234,333
826,667
234,333
206,667
1,050,000
206,667
826,667
826,667
1,050,000
3,971,000
1,050,000
3,971,000
0.04
3,971,000
20%
0.04
0.04
Nil
20%
20%
2.09%
Nil
0.026
Nil
2.09%
103,246
2.09%
0.026
0.026
103,246
344,333
1,309,000
234,333
1,309,000
344,333
206,667
344,333
234,333
826,667
234,333
206,667
1,050,000
206,667
826,667
826,667
1,050,000
3,971,000
1,050,000
3,971,000
0.04
3,971,000
20%
0.04
0.04
Nil
20%
20%
2.09%
Nil
0.020
Nil
2.09%
79,420
2.09%
0.020
0.020
79,420
344,334
1,309,000
234,334
1,309,000
344,334
206,666
344,334
234,334
826,666
234,334
206,666
1,050,000
206,666
826,666
826,666
1,050,000
3,971,000
1,050,000
3,971,000
0.04
3,971,000
20%
0.04
0.04
Nil
20%
20%
2.09%
Nil
0.015
Nil
2.09%
59,565
2.09%
0.015
0.015
59,565
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
1 Feb 2017
(i)
23 Apr
1 Feb 2017
2015
(i)
1 Feb 2017
31 Dec
23 Apr
(i)
2019
2015
23 Apr
31 Dec
2015
2019
31 Dec
2019
766,667
-
766,667
-
766,667
-
-
-
-
-
-
-
766,667
-
-
-
766,667
1,533,334
766,667
1,533,334
0.11
1,533,334
47.7%
0.11
0.11
Nil
47.7%
47.7%
1.95%
Nil
0.060
Nil
1.95%
92,000
1.95%
0.060
0.060
92,000
1 Feb 2018
1 Feb 2019
23 Apr
1 Feb 2018
2015
1 Feb 2018
31
23 Apr
Dec2019
2015
23 Apr
31
2015
Dec2019
31
Dec2019
766,667
23 Apr
1 Feb 2019
2015
1 Feb 2019
31
23 Apr
Dec2019
2015
23 Apr
31
2015
Dec2019
31
Dec2019
766,666
-
766,667
-
766,667
-
-
-
-
-
-
-
766,667
-
-
-
766,667
1,533,334
766,667
1,533,334
0.11
1,533,334
51.2%
0.11
0.11
Nil
51.2%
51.2%
1.90%
Nil
0.070
Nil
1.90%
107,333
1.90%
0.070
0.070
107,333
-
766,666
-
766,666
-
-
-
-
-
-
-
766,666
-
-
-
766,666
1,533,332
766,666
1,533,332
0.11
1,533,332
51.2%
0.11
0.11
Nil
51.2%
51.2%
1.90%
Nil
0.070
Nil
1.90%
107,333
1.90%
0.070
0.070
107,333
92,000
79,420
59,565
107,333
103,246
Total value – A$
The expected price volatility is based upon the historic volatility (based on the remaining life of the
107,333
rights), adjusted for any expected changes to future volatility due to publicly available information.
The expected price volatility is based upon the historic volatility (based on the remaining life of the
rights), adjusted for any expected changes to future volatility due to publicly available information.
No cash benefit is received by key management personnel of the Group, until the sale of the resultant
The expected price volatility is based upon the historic volatility (based on the remaining life of the
shares, which cannot be done unless and until the rights have vested and the shares issued.
rights), adjusted for any expected changes to future volatility due to publicly available information.
No cash benefit is received by key management personnel of the Group, until the sale of the resultant
shares, which cannot be done unless and until the rights have vested and the shares issued.
The number of performance rights over ordinary shares held, granted to, vested and/or
No cash benefit is received by key management personnel of the Group, until the sale of the resultant
lapsed/expired by Directors and executives of Otto Energy Limited as part of compensation during the
shares, which cannot be done unless and until the rights have vested and the shares issued.
The number of performance rights over ordinary shares held, granted to, vested and/or
year ended 30 June 2019 is set out below.
lapsed/expired by Directors and executives of Otto Energy Limited as part of compensation during the
The number of performance rights over ordinary shares held, granted to, vested and/or
year ended 30 June 2019 is set out below.
lapsed/expired by Directors and executives of Otto Energy Limited as part of compensation during the
year ended 30 June 2019 is set out below.
Key
Management
Key
Personnel
Management
Key
Directors
Personnel
Management
Mr J Jetter
Directors
Personnel
Mr M Allen
Mr J Jetter
Directors
Mr P Senycia
Mr J Jetter
Mr M Allen
Mr I MacIiver
Mr M Allen
Mr P Senycia
Mr I Boserio
Mr P Senycia
Mr I MacIiver
Mr K Small
Mr I MacIiver
Mr I Boserio
Mr I Boserio
Mr K Small
Mr K Small
Balance at
start of year
Balance at
start of year
Balance at
start of year
1,033,000
6,227,000
1,033,000
5,450,000
1,033,000
6,227,000
703,000
6,227,000
5,450,000
620,000
5,450,000
703,000
-
703,000
620,000
14,033,000
620,000
-
-
14,033,000
14,033,000
Granted as
compensation
Granted as
compensation
Granted as
compensation
1,116,000
3,990,000
1,116,000
669,000
1,116,000
3,990,000
744,000
3,990,000
669,000
669,000
669,000
744,000
4,840,000
744,000
669,000
12,028,000
669,000
4,840,000
4,840,000
12,028,000
12,028,000
Vested and
exercised
Vested and
exercised
Vested and
(344,333)
exercised
(1,309,000)
(344,333)
(1,050,000)
(344,333)
(1,309,000)
(234,333)
(1,309,000)
(1,050,000)
(206,667)
(1,050,000)
(234,333)
-
(234,333)
(206,667)
(3,144,333)
(206,667)
-
-
(3,144,333)
(3,144,333)
Lapsed/
expired
Lapsed/
expired
Lapsed/
expired
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Balance at
end of year
Balance at
end of year
Balance at
1,804,667
end of year
8,908,000
1,804,667
5,069,000
1,804,667
8,908,000
1,212,667
8,908,000
5,069,000
1,082,333
5,069,000
1,212,667
4,840,000
1,212,667
1,082,333
22,916,667
1,082,333
4,840,000
4,840,000
22,916,667
22,916,667
61
31
31
31
DIRECTORS’ REPORT
DIRECTORS’ REPORT
For the year ended 30 June 2019
For the Year Ended 30 June 2019
Executives
Mr D Rich
Mr P
Trajanovich
Mr W
Armstrong
Balance at
start of year
2,480,000
2,274,000
Granted as
compensation
2,643,000
3,466,000
Vested and
exercised
Lapsed/
expired
(826,667)
(758,000)
-
7,352,000
-
4,754,000
13,461,000
(1,584,667)
Balance at
end of year
4,296,333
4,982,000
7,352,000
16,630,333
-
-
-
-
Options over equity instruments granted
Options granted to the Directors and executives are granted as remuneration unless otherwise noted.
Options are issued under the Employee Option Plan. There were no options issued during the financial
year.
Shareholding
The number of shares in the Company held during the financial year by key management personnel
of the Group, including their personally related parties, is set out below:
Key
Management
Personnel
Balance at
start of
year
Granted/
purchased
during the
year
Convertible
note
redemption
Received
through
conversion
of
performance
rights during
the year
Sold
during
the year
Balance at
end of year
Directors
Mr J Jetter
Mr M Allen
Mr P Senycia
Mr I MacIiver
Mr I Boserio
Mr K Small
Executives
Mr D Rich
Mr W
Armstrong
Mr P
Trajanovich
19,446,318
6,900,000
3,300,158
5,406,864
2,073,571
-
37,126,911
6,550,972
2,561,801
361,310
1,849,155
1,332,525
12,371,515
25,027,278
344,333
1,309,000
1,050,000
234,333
206,667
-
3,144,333
2,599,211
-
-
-
-
-
2,599,211
-
-
-
-
-
-
-
28,940,834
10,770,801
4,711,468
7,490,352
3,612,763
12,371,515
67,897,733
795,252
463,947
826,667
-
(513,671)
1,572,195
-
750,000
-
-
-
750,000
-
795,252
37,922,163
-
1,213,947
26,241,225
758,000
1,584,667
4,729,000
-
-
2,599,211
-
(513,671)
(513,671)
758,000
3,080,195
70,977,928
Outstanding balances arising from sales/purchases of goods and services
There are no balances outstanding at the end of the reporting period in relation to transactions with
key management personnel and their related parties (2018: nil).
62
32
ANNUAL REPORT 2019
DIRECTORS’ REPORT
For the year ended 30 June 2019
DIRECTORS’ REPORT
For the Year Ended 30 June 2019
Diversity
Proportion of women employees at 30 June 2019:
Whole organisation*
Senior executive
positions
Board
Number
3/14
0/3
Proportion
21%
0%
0/5
0%
*Includes four non-executive Directors
Performance rights on issue at 30 June 2019
Date granted
23 April 2015
29 November 2017
15 November 2018
21 December 2018
Date of expiry
31 December
2019
29 November
2022
15 November
2023
15 November
2023
Number
4,630,000
9,458,000
7,188,000
25,480,000
46,756,000
No performance right holder has any right under the performance rights to participate in any other
share issue of the Company or any other entity. There were no options on issue at 30 June 2019.
No options were granted as remuneration to key management personnel during the year. Details of
performance rights and options granted to key management personnel are disclosed on pages 56 to
58.
This report is made in accordance with a resolution of Directors.
Mr I Macliver
Director
25 September 2019
63
33
AUDITOR’S INDEPENDENCE DECLARATION
For the year ended 30 June 2019
Tel: +61 8 6382 4600
Fax: +61 8 6382 4601
www.bdo.com.au
38 Station Street
Subiaco, WA 6008
PO Box 700 West Perth WA 6872
Australia
DECLARATION OF INDEPENDENCE BY JARRAD PRUE TO THE DIRECTORS OF OTTO ENERGY LIMITED
As lead auditor of Otto Energy Limited for the year ended 30 June 2019, I declare that, to the best of
my knowledge and belief, there have been:
1. No contraventions of the auditor independence requirements of the Corporations Act 2001 in
relation to the audit; and
2. No contraventions of any applicable code of professional conduct in relation to the audit.
This declaration is in respect of Otto Energy Limited and the entities it controlled during the period.
Jarrad Prue
Director
BDO Audit (WA) Pty Ltd
Perth, 25 September 2019
64
BDO Audit (WA) Pty Ltd ABN 79 112 284 787 is a member of a national association of independent entities which are all members of BDO Australia Ltd ABN 77 050 110 275,
an Australian company limited by guarantee. BDO Audit (WA) Pty Ltd and BDO Australia Ltd are members of BDO International Ltd, a UK company limited by guarantee, and
form part of the international BDO network of independent member firms. Liability limited by a scheme approved under Professional Standards Legislation.
34
ANNUAL REPORT 2019
CONSOLIDATED STATEMENT OF PROFIT OR LOSS
AND OTHER COMPREHENSIVE INCOME
CONSOLIDATED STATEMENT OF PROFIT OR LOSS
AND OTHER COMPREHENSIVE INCOME
For the year ended 30 June 2019
For the year ended 30 June 2019
Note
2019
US$’000
2018
US$’000
Operating Revenue (Net)
Cost of sales
Gross profit
Other income
Profit/(loss) on disposal of property, plant and
equipment
Exploration expenditure
Finance income/(costs)
Administration and other expenses
Loss before income tax
Income tax expense
Loss after income tax for the year
Other comprehensive income that may be recycled to
profit or loss
Total other comprehensive income
Total comprehensive loss for the year
Earnings per share
Basic loss per share (US cents)
Diluted loss per share (US cents)
2
3
2
4
5
5
7
6
6
31,258
(7,833)
23,425
168
(2)
(37,849)
965
(5,114)
(18,407)
(2)
(18,409)
9,551
(1,622)
7,929
213
2
(4,827)
(4,436)
(4,072)
(5,191)
(3)
(5,194)
-
(18,409)
-
(5,194)
(0.95)
(0.95)
(0.37)
(0.37)
The above consolidated statement of profit or loss and other comprehensive income should be read in
conjunction with the accompanying notes.
65
35
CONSOLIDATED STATEMENT
OF FINANCIAL POSITION
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
For the year ended 30 June 2019
For the year ended 30 June 2019
Current assets
Cash and cash equivalents
Trade and other receivables
Other assets
Total current assets
Non-current assets
Oil and gas properties
Property, plant and equipment
Other assets
Total non-current assets
Total assets
Current liabilities
Trade and other payables
Provisions
Convertible note
Convertible note derivative
Total current liabilities
Non-current liabilities
Provisions
Total non-current liabilities
Total liabilities
Net assets
Equity
Contributed equity
Reserves
Accumulated losses
Total equity
Note
2019
US$’000
2018
US$’000
8
10
11
12
11
13
15
14
14
15
16
17
7,383
3,311
1,238
11,932
30,982
106
393
31,481
43,413
4,473
173
-
-
4,646
1,589
1,589
6,235
37,178
5,945
4,028
287
10,260
27,151
82
355
27,588
37,848
4,763
202
7,542
3,183
15,690
1,128
1,128
16,818
21,030
125,041
14,067
(101,930)
37,178
90,704
13,847
(83,521)
21,030
The above consolidated statement of financial position should be read in conjunction with the
accompanying notes.
66
36
ANNUAL REPORT 2019
CONSOLIDATED STATEMENT
OF CHANGES IN EQUITY
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
For the year ended 30 June 2019
For the year ended 30 June 2019
Contributed
equity
US$’000
Share-
based
payments
reserve
US$’000
Foreign
currency
translation
reserve
US$’000
Balance at 1 July 2017
Loss for the period
Other comprehensive income
Total comprehensive loss for the year
Transactions with owners in their
capacity as owners:
Issue of shares (net of costs)
Equity benefits issued to employees
Balance at 30 June 2018
Balance at 1 July 2018
Loss for the period
Other comprehensive income
Total comprehensive loss for the year
Transactions with owners in their
capacity as owners:
Issue of shares (net of costs)
Equity benefits issued to employees
Balance at 30 June 2019
81,895
-
-
-
8,809
-
90,704
90,704
-
-
-
34,337
-
125,041
9,549
-
-
-
-
110
9,659
9,659
-
-
-
-
220
9,879
4,188
-
-
-
-
-
4,188
4,188
-
-
-
-
-
4,188
Accumulated
losses
Total
US$’000
US$’000
(78,327)
(5,194)
-
(5,194)
17,305
(5,194)
-
(5,194)
-
-
(83,521)
(83,521)
(18,409)
-
(18,409)
8,809
110
21,030
21,030
(18,409)
-
(18,409)
-
-
(101,930)
34,337
220
37,178
The above consolidated statement of changes in equity should be read in conjunction with the
accompanying notes.
67
37
CONSOLIDATED STATEMENT
OF CASH FLOWS
CONSOLIDATED STATEMENT OF CASH FLOWS
For the year ended 30 June 2019
For the year ended 30 June 2019
Note
2019
US$’000
2018
US$’000
Cash flows from operating activities
Oil and Gas Sales (net)
Other income
Payments to suppliers and employees
Payments for exploration and evaluation
Interest received
Income tax paid
Net cash outflow from operating activities
9
Cash flows from investing activities
Payments for property, plant and equipment
Proceeds from sale of property, plant and equipment
Payments for development and evaluation
Bond for development asset
Net cash outflow from investing activities
Cash flows from financing activities
Proceeds from issue (repayment) of convertible notes
Transaction costs relating to convertible notes issue
Interest paid on convertible notes
Proceeds from issue of shares
Transaction costs - shares
Net cash inflow from financing activities
Net decrease in cash and cash equivalents
Cash and cash equivalents at the beginning of the financial year
Effects of exchange rate changes on cash
Cash and cash equivalents at the end of the financial
year
8
32,042
11
(8,504)
(36,867)
157
-
(13,161)
(87)
-
(8,904)
(38)
(9,029)
(8,100)
-
(2,327)
36,613
(2,375)
23,811
1,621
5,945
(183)
6,300
54
(4,688)
(3,949)
159
(2)
(2,126)
(91)
2
(20,587)
(150)
(20,826)
8,200
(311)
-
9,166
(356)
16,699
(6,253)
20,309
(1)
7,383
5,945
The above consolidated statement of cash flows should be read in conjunction with the accompanying
notes.
68
38
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
ANNUAL REPORT 2019
ABOUT THIS REPORT
Otto Energy Limited (referred to as ‘Otto’ or the ‘Company’) is a for-profit entity limited by shares,
incorporated and domiciled in Australia. Its shares are publicly traded on the Australian Securities
Exchange. The nature of operations and principal activities of Otto and its subsidiaries (referred to as
the ‘Group’) are described in the Directors’ Report.
The consolidated general purpose financial report of the Group was authorised for issue in accordance
with a resolution of the Directors on 24 September 2019.
Basis of preparation
The financial report is a general purpose financial report which:
• has been prepared in accordance with the requirements of the Corporations Act 2001,
Australian Accounting Standards and other authoritative pronouncements of the Australian
Accounting Standards Board (AASB) and International Financial Reporting Standards (IFRS) as
issued by the International Accounting Standards Board (IASB);
• has been prepared on a historical cost basis, except for certain financial instruments which
have been measured at fair value;
• presents reclassified comparative information where required for consistency with the current
year’s presentation; and
•
adopts all new and amended Accounting Standards and Interpretations issued by the AASB that
are relevant to the Group and effective for reporting periods beginning on or before 1 July 2018.
Refer to note 28 for further details.
Basis of consolidation
The consolidated financial statements comprise the financial statements of the Group. A list of
controlled entities (subsidiaries) is contained in note 19.
Subsidiaries are consolidated from the date on which control is obtained by the Group and cease to be
consolidated from the date that control ceases. In preparing the consolidated financial statements, all
intercompany balances and transactions, income and expenses and profits or losses resulting from
intra-group transactions have been eliminated.
Currency
Items included in the financial statements of each of the Group’s entities are measured using the
currency of the primary economic environment in which the entity operates (‘the functional currency’).
The consolidated financial statements are presented in United States dollars, which is Otto Energy
Limited’s functional and presentation currency.
Foreign currency transactions are translated into the functional currency using the exchange rates
prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the
settlement of such transactions and from the translation at year end exchange rates of monetary assets
and liabilities denominated in foreign currencies are recognised in profit or loss.
Rounding of amounts
The amounts contained in these financial statements have been rounded to the nearest thousand
dollars ($’000) unless otherwise stated, in accordance with ASIC Instrument 2016/191.
39
69
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
ABOUT THIS REPORT (continued)
Other accounting policies
Significant and other accounting policies that summarise the measurement basis used and are relevant
to an understanding of the financial statements are provided throughout the notes to the consolidated
financial statements.
Going concern
Otto’s financial statements have been prepared on a going concern basis.
Key estimates and judgements
In applying the Group’s accounting policies, management has made a number of judgements and
applied estimates of future events. Judgements and estimates which are material to the financial
report are found in the following notes:
• Note 7
• Note 12
• Note 14
• Note 15
• Note 21
Income tax
Oil and gas properties
Convertible note
Provisions
Share-based payments
70
40
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
ANNUAL REPORT 2019
Financial performance
1. Segment information
2. Revenue and other income
3. Cost of sales
4. Exploration expenditure
5. Other expenses
6. Earnings per share
7.
8. Cash and cash equivalents
9. Reconciliation of loss after income tax to net cash outflow
Income tax
from operating activities
Operating assets and liabilities
10. Trade and other receivables
11. Other assets
12. Oil and gas properties
13. Trade and other payables
14. Convertible note
15. Provisions
Capital structure, financial instruments and risk
16. Contributed equity
17. Reserves
18. Financial instruments
Other disclosures
19. Subsidiaries
20. Interest in joint operations
21. Share-based payments
22. Related parties
23. Auditor’s remuneration
24. Contingent liabilities
25. Commitments
26. Events after the reporting period
27. Parent entity disclosures
28. New accounting standards and interpretations
72
73
74
74
75
75
76
78
78
79
79
80
83
83
85
87
88
88
94
94
94
100
101
102
102
103
106
107
71
41
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
FINANCIAL PERFORMANCE
1. Segment information
The Group has identified its operating segments based on the internal management reports that are
reviewed and used by the executive management team in assessing performance and in determining
the allocation of resources. The operating segments identified by management are based on the
geographical locations of the business which are as follows: Gulf of Mexico (USA), Alaska (USA) and
Other. Discrete financial information about each of these operating segments is reported to the
executive management team on at least a monthly basis.
Operating segments are reported in a manner consistent with the internal reporting provided to the
chief operating decision maker. The chief operating decision maker, who is responsible for allocating
resources and assessing performance of the operating segments, has been identified as the Board.
The Group had 3 reportable segments during 2019.
The segment information for the reportable segments for the year ended 30 June 2019 is as follows:
2019
Operating Revenue
Cost of Production
Gross Profit
Other income
Profit/(loss) on disposal of property, plant
and equipment
Exploration expenditure
Finance costs
Administration and other expenses
Profit (Loss) before income tax
Income tax expense
Profit (Loss) after income tax for the
year
Gulf of
Mexico
(USA)
US$’000
31,258
(7,833)
23,425
17
-
(33,708)
(119)
(4,154)
(14,539)
-
(14,539)
Alaska
(USA)
US$’000
-
-
-
-
(cid:3)
-
(4,231)
-
(56)
(4,287)
-
(4,287)
Total non-current assets
Total assets
Total liabilities
31,478
38,769
5,555
-
-
24
Other
Consolidated
US$’000
US$’000
-
-
-
151
(2)
90
1,084
(904)
419
(2)
417
3
4,644
656
31,258
(7,833)
23,425
168
(2)
(37,849)
965
(5,114)
(18,407)
(2)
(18,409)
31,481
43,413
6,235
Gross oil revenue ($34.684m) from Gulf of Mexico SM71, net oil revenue ($0.094m) and net gas revenue
($0.111m) from Lightning were all sold to different single customers. Gross gas revenue ($3.433m)
from Gulf of Mexico SM71 production was sold to two different customers.
72
42
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
ANNUAL REPORT 2019
1. Segment information (continued)
The segment information for the reportable segments for the year ended 30 June 2018 is as follows:
2018
Gulf of Mexico
(USA)
US$’000
Alaska (USA)
Other
Consolidated
US$’000
US$’000
US$’000
Operating Revenue
Cost of Production
Gross Profit
Other income
Profit on disposal of property,
plant and equipment
Exploration expenditure
Finance costs
Administration and other
expenses
Profit (Loss) before income
tax
Income tax expense
Profit (Loss) after income tax
for the year
Total non-current assets
Total assets
Total liabilities
9,551
(1,622)
7,929
11
-
(4,683)
(24)
(1,311)
1,922
-
1,922
27,581
35,865
4,153
2. Revenue and other income
SM71 Sales
Oil Sales
Gas Sales
Total Sales
Less: Royalties(i)
SM71 Operating Revenue (Net)
Lightning Sales(ii)
Oil Sales
Gas Sales
Natural Gas Liquids Sales
Lightning Operating Revenue (Net)
Total Operating Revenue (Net)
Interest income(ii)
Other income
-
-
-
-
-
(222)
-
(27)
(249)
-
(249)
-
-
7
-
-
-
202
2
78
(4,412)
(2,734)
9,551
(1,622)
7,929
213
2
(4,827)
(4,436)
(4,072)
(6,864)
(5,191)
(3)
(6,867)
7
1,983
12,658
(3)
(5,194)
27,588
37,848
16,818
2019
US$’000
2018
US$’000
34,684
3,433
38,117
(7,064)
31,053
94
89
22
205
31,258
157
11
168
11,312
432
11,744
(2,193)
9,551
-
-
-
-
9,551
159
54
213
73
43
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
(i) SM71 Operating Revenue is shown net of royalty payments payable to the (USA) Office of Natural
Resources Revenue. Royalty payments are 18.75% of revenue under the terms of the SM 71 lease.
(ii) Proceeds from the sale of oil and gas from the Lightning field are received net of royalty payments.
(iii) Interest income is recognised using the effective interest rate method.
Recognition and measurement
Revenue is recognised when or as the Group transfers control of goods or services to a customer at
the amount to which the Group expects to be entitled. If the consideration promised includes a variable
component, the Group estimates the expected consideration for the estimated impact of the variable
component at the point of recognition and re-estimated at every reporting period.
Sale of oil & gas
Revenue from the sale of oil & gas is recognised and measured in the accounting period in which the
goods and/or services are provided based on the amount of the transaction price allocated to the
performance obligations.
The performance obligation is the supply of oil & gas over the contractual term; the units of supply
represent a series of distinct goods that are substantially the same with the same pattern of transfer
to the customer. The performance obligation is considered to be satisfied as the customer receives
the supply through the pipeline, based on the units delivered. Hence revenue is recognised over time.
3. Cost of Sales
Gathering and Production charges
Amortisation of capitalised developments – Note 12
Total Cost of Sales
4. Exploration expenditure
Exploration expenditure – Gulf of Mexico/Gulf Coast
Exploration expenditure – Alaska North Slope
Exploration expenditure – Other
2019
US$’000
2018
US$’000
2,874
4,959
7,833
33,708
4,231
(90)
37,849
745
877
1,622
4,683
222
(78)
4,827
Recognition and measurement
Costs incurred in the exploration stages of specific areas of interest are expensed against the profit or
loss as incurred. All exploration expenditure, including general permit activity, geological and
geophysical costs, new venture activity costs and drilling exploration wells, is expensed as incurred.
The costs of acquiring interests in new exploration licences are expensed. Once an exploration
discovery has been determined, evaluation and development expenditure from that point on is
capitalised to the Consolidated Statement of Financial Position as oil and gas properties.
Exploration expenditure in relation to the Gulf of Mexico/Gulf Coast includes the initial $4M payment to
Hilcorp on signing of the Joint Exploration and Development Agreement for initial land and other costs,
the exploration drilling of the Bivouac Peak ($4.9M), Big Tex ($5.2M), Don Julio 2 ($2.7M), Lightning
($5.1M) and Mustang ($5.5M) prospects as well costs incurred to 30 June 2019 in the drilling to the MP
sands exploration target in the GC 21 Bulleit well ($5.7M).
Exploration expenditure on the Alaska North Slope includes the drilling of the WInx-1 exploration well.
44
74
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
ANNUAL REPORT 2019
5. Other expenses
5. Other expenses
i) Finance costs
Interest on convertible note – refer Note 14
i) Finance costs
Accretion of effective interest on convertible note – refer Note 14
Interest on convertible note – refer Note 14
Fair value adjustment on embedded derivative element of
Accretion of effective interest on convertible note – refer Note 14
convertible note – refer Note 14
Fair value adjustment on embedded derivative element of
Amortisation of borrowing costs
convertible note – refer Note 14
Success Fee – refer Note 14
Amortisation of borrowing costs
Convertible note extension fee
Success Fee – refer Note 14
Accretion of decommissioning fund
Convertible note extension fee
(Gain)/Loss on derivatives
Accretion of decommissioning fund
Total finance costs/ (income)
(Gain)/Loss on derivatives
Total finance costs/ (income)
ii) Administration and other expenses
Employee benefits expense
ii) Administration and other expenses
Defined contribution superannuation expense
Employee benefits expense
Share-based payment expense
Defined contribution superannuation expense
Other employee benefits expenses
Share-based payment expense
Other employee benefits expenses
Depreciation expense
Depreciation expense – furniture and equipment
Depreciation expense
Depreciation expense – furniture and equipment
Other expenses
Corporate and other costs (net of recharges)
Other expenses
Business development
Corporate and other costs (net of recharges)
Foreign currency losses
Business development
Foreign currency losses
Total administration and other expenses
Total administration and other expenses
2019
US$’000
2019
US$’000
2018
US$’000
2018
US$’000
1,214
400
1,214
400
(3,183)
262
(3,183)
24
262
200
24
51
200
67
51
(965)
67
(965)
80
220
80
3,214
220
3,514
3,214
3,514
48
48
48
48
675
694
675
183
694
1,552
183
1,552
5,114
5,114
1,225
347
1,225
347
2,436
241
2,436
163
241
-
163
24
-
-
24
4,436
-
4,436
108
110
108
1,780
110
1,998
1,780
1,998
26
26
26
26
1,508
539
1,508
1
539
2,048
1
2,048
4,072
4,072
iii) Depreciation
Depreciation and amortisation charges are included above in Note 3 Cost of sales and Note 5(ii) other
iii) Depreciation
expenses. Total depreciation and amortisation for the Consolidated Entity is $5.0 million (2018: $0.9
Depreciation and amortisation charges are included above in Note 3 Cost of sales and Note 5(ii) other
million)
expenses. Total depreciation and amortisation for the Consolidated Entity is $5.0 million (2018: $0.9
million)
6. Earnings per share
6. Earnings per share
Basic earnings per share is calculated by dividing the profit or loss attributable to owners of the
Company, excluding any costs of servicing equity (other than dividends), by the weighted average
Basic earnings per share is calculated by dividing the profit or loss attributable to owners of the
number of ordinary shares, adjusted for the bonus element.
Company, excluding any costs of servicing equity (other than dividends), by the weighted average
number of ordinary shares, adjusted for the bonus element.
Diluted earnings per share adjusts the figures used in the determination of basic earnings per share to
take into account the after income tax effect of interest and other financing costs associated with
Diluted earnings per share adjusts the figures used in the determination of basic earnings per share to
dilutive potential ordinary shares, and the weighted average number of additional ordinary shares that
take into account the after income tax effect of interest and other financing costs associated with
would have been outstanding assuming the conversion of all dilutive potential ordinary shares.
dilutive potential ordinary shares, and the weighted average number of additional ordinary shares that
would have been outstanding assuming the conversion of all dilutive potential ordinary shares.
75
45
45
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
6. Earnings per share (continued)
The following table reflects the income and share data used in the basic and diluted EPS calculations:
2019
2018
Loss attributable to owners of the Company (US$’000)
Weighted average number of ordinary shares on issue for basic
and diluted loss per share (number)
Basic and diluted loss per share (US cents)
(18,409)
(5,194)
1,946,641,840
1,403,062,899
(0.95)
(0.37)
Due to the Company reporting a loss for the 2019 and 2018 financial years, the impact of potential
shares are not included in calculating diluted EPS because they are anti-dilutive.
2019
US$’000
2018
US$’000
7. Income tax
The components of tax expense comprise:
Current tax
Deferred tax – origination and reversal of temporary differences
Prior period under provision
Reconciliation of income tax expense to prima facie tax payable:
Loss before income tax
Prima facie income tax at 30%
Difference in overseas tax rates
Non-assessable income
Tax effect of amounts not deductible in calculating taxable income
Benefit of deferred tax assets not brought to account
Prior period under/(over) provision
Income tax expense
Deferred tax assets
Temporary differences
– provisions and other corporate costs
– exploration and evaluation costs
Tax losses - revenue
Tax losses - foreign
Offset against deferred tax liabilities recognised
Deferred tax assets not brought to account
Deferred tax assets brought to account
76
2
-
-
2
(18,407)
(5,523)
3,524
-
(5,285)
7,286
-
2
566
-
566
7,030
12,673
19,703
(8,324)
(11,379)
-
3
-
-
3
(5,191)
(1,427)
(3)
-
479
954
-
3
131
-
131
6,259
6,809
13,199
(6,838)
(6,361)
-
46
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
ANNUAL REPORT 2019
7. Income tax (continued)
7. Income tax (continued)
Deferred tax liabilities
Temporary differences – Oil and gas properties
Deferred tax liabilities
Offset by deferred tax assets recognised
Temporary differences – Oil and gas properties
Deferred tax liabilities brought to account
Offset by deferred tax assets recognised
Deferred tax liabilities brought to account
2019
US$’000
2019
US$’000
8,324
(8,324)
8,324
-
(8,324)
-
2018
US$’000
2018
US$’000
6,838
(6,838)
6,838
-
(6,838)
-
Recognition and measurement
The income tax expense for the period is the tax payable on the current period’s taxable income based
Recognition and measurement
on the applicable income tax rate for each jurisdiction adjusted by changes in deferred tax assets and
The income tax expense for the period is the tax payable on the current period’s taxable income based
liabilities attributable to temporary differences and to unused tax losses.
on the applicable income tax rate for each jurisdiction adjusted by changes in deferred tax assets and
liabilities attributable to temporary differences and to unused tax losses.
Included in the foreign tax losses of US$12.7 million is tax losses of US$10.1 million that can be offset
against future tax payable on US profits from US Gulf of Mexico operations.
Included in the foreign tax losses of US$12.7 million is tax losses of US$10.1 million that can be offset
against future tax payable on US profits from US Gulf of Mexico operations.
Deferred income tax is provided in full, using the liability method, on temporary differences arising
between the tax bases of assets and liabilities and their carrying amounts in the consolidated financial
Deferred income tax is provided in full, using the liability method, on temporary differences arising
statements. However, deferred tax liabilities are not recognised if they arise from the initial recognition
between the tax bases of assets and liabilities and their carrying amounts in the consolidated financial
of goodwill. Deferred income tax is also not accounted for if it arises from initial recognition of an asset
statements. However, deferred tax liabilities are not recognised if they arise from the initial recognition
or liability in a transaction other than a business combination that at the time of the transaction affects
of goodwill. Deferred income tax is also not accounted for if it arises from initial recognition of an asset
neither accounting nor taxable profit or loss. Deferred income tax is determined using tax rates (and
or liability in a transaction other than a business combination that at the time of the transaction affects
laws) that have been enacted or substantially enacted by the end of the reporting period and are
neither accounting nor taxable profit or loss. Deferred income tax is determined using tax rates (and
expected to apply when the related deferred income tax asset is realised or the deferred income tax
laws) that have been enacted or substantially enacted by the end of the reporting period and are
liability is settled.
expected to apply when the related deferred income tax asset is realised or the deferred income tax
liability is settled.
Deferred tax assets are recognised for deductible temporary differences and unused tax losses only if
it is probable that future taxable amounts will be available to utilise those temporary differences and
Deferred tax assets are recognised for deductible temporary differences and unused tax losses only if
losses.
it is probable that future taxable amounts will be available to utilise those temporary differences and
losses.
Deferred tax liabilities and assets are not recognised for temporary differences between the carrying
amount and tax bases of investments in foreign operations where the Company is able to control the
Deferred tax liabilities and assets are not recognised for temporary differences between the carrying
timing of the reversal of the temporary differences and it is probable that the differences will not
amount and tax bases of investments in foreign operations where the Company is able to control the
reverse in the foreseeable future.
timing of the reversal of the temporary differences and it is probable that the differences will not
reverse in the foreseeable future.
Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current
tax assets and liabilities and when the deferred tax balances relate to the same taxation authority.
Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current
Current tax assets and tax liabilities are offset where the entity has a legally enforceable right to offset
tax assets and liabilities and when the deferred tax balances relate to the same taxation authority.
and intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously.
Current tax assets and tax liabilities are offset where the entity has a legally enforceable right to offset
Current and deferred tax is recognised in profit or loss, except to the extent that it relates to items
and intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously.
recognised in other comprehensive income or directly in equity. In this case, the tax is also recognised
Current and deferred tax is recognised in profit or loss, except to the extent that it relates to items
in other comprehensive income or directly in equity, respectively.
recognised in other comprehensive income or directly in equity. In this case, the tax is also recognised
in other comprehensive income or directly in equity, respectively.
Key estimates and judgements
The Group is subject to income taxes in Australia and jurisdictions where it has foreign operations.
Key estimates and judgements
Significant judgement is required in determining the worldwide provision for income taxes. There are
The Group is subject to income taxes in Australia and jurisdictions where it has foreign operations.
certain transactions and calculations undertaken during the ordinary course of business for which the
Significant judgement is required in determining the worldwide provision for income taxes. There are
ultimate tax determination is uncertain. The Group estimates its tax liabilities based on the Group’s
certain transactions and calculations undertaken during the ordinary course of business for which the
understanding of the tax law. Where the final tax outcome of these matters is different from the
ultimate tax determination is uncertain. The Group estimates its tax liabilities based on the Group’s
amounts that were initially recorded, such differences will impact the current and deferred income tax
understanding of the tax law. Where the final tax outcome of these matters is different from the
assets and liabilities in the period in which such determination is made.
amounts that were initially recorded, such differences will impact the current and deferred income tax
assets and liabilities in the period in which such determination is made.
In addition, the Group recognises deferred tax assets relating to carried forward tax losses to the extent
there are sufficient taxable temporary differences (deferred tax liabilities) relating to the same taxation
In addition, the Group recognises deferred tax assets relating to carried forward tax losses to the extent
there are sufficient taxable temporary differences (deferred tax liabilities) relating to the same taxation
47
47
77
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
For the year ended 30 June 2019
7. Income tax (continued)
7. Income tax (continued)
7. Income tax (continued)
jurisdiction and the same subsidiary against which the unused tax losses can be utilised. However,
jurisdiction and the same subsidiary against which the unused tax losses can be utilised. However,
utilisation of the tax losses depends on the ability of the entity to satisfy certain tests at the time the
jurisdiction and the same subsidiary against which the unused tax losses can be utilised. However,
utilisation of the tax losses depends on the ability of the entity to satisfy certain tests at the time the
losses are recouped.
utilisation of the tax losses depends on the ability of the entity to satisfy certain tests at the time the
losses are recouped.
losses are recouped.
2019
2019
US$’000
2019
US$’000
US$’000
2018
2018
US$’000
2018
US$’000
US$’000
7,383
7,383
7,383
7,383
7,383
7,383
5,945
5,945
5,945
5,945
5,945
5,945
8. Cash and cash equivalents
8. Cash and cash equivalents
8. Cash and cash equivalents
Cash at bank and on hand
Cash at bank and on hand
Cash at bank and on hand
Recognition and measurement
Recognition and measurement
Cash and cash equivalents include cash on hand, deposits held at call with financial institutions and
Recognition and measurement
Cash and cash equivalents include cash on hand, deposits held at call with financial institutions and
other short-term, highly liquid investments with original maturities of three months or less that are
Cash and cash equivalents include cash on hand, deposits held at call with financial institutions and
other short-term, highly liquid investments with original maturities of three months or less that are
readily convertible to known amounts of cash and which are subject to an insignificant risk of changes
other short-term, highly liquid investments with original maturities of three months or less that are
readily convertible to known amounts of cash and which are subject to an insignificant risk of changes
in value. Cash at bank earns interest at floating rates based on daily bank deposit rates.
readily convertible to known amounts of cash and which are subject to an insignificant risk of changes
in value. Cash at bank earns interest at floating rates based on daily bank deposit rates.
in value. Cash at bank earns interest at floating rates based on daily bank deposit rates.
9. Reconciliation of loss after income tax to net cash
9. Reconciliation of loss after income tax to net cash
9. Reconciliation of loss after income tax to net cash
2019
2019
US$’000
2019
US$’000
US$’000
2018
2018
US$’000
2018
US$’000
US$’000
outflow from operating activities
outflow from operating activities
outflow from operating activities
Loss after income tax
Loss after income tax
Non-cash items:
Loss after income tax
Non-cash items:
Depreciation expense – furniture and equipment
Non-cash items:
Depreciation expense – furniture and equipment
Share-based payments
Depreciation expense – furniture and equipment
Share-based payments
Finance costs/(income) – see note 5(i)
Share-based payments
Finance costs/(income) – see note 5(i)
Amortisation of deferred costs
Finance costs/(income) – see note 5(i)
Amortisation of deferred costs
Other non-cash items
Amortisation of deferred costs
Other non-cash items
Other non-cash items
Change in assets and liabilities:
Change in assets and liabilities:
(Increase)/Decrease in trade and other receivables
Change in assets and liabilities:
(Increase)/Decrease in trade and other receivables
(Increase) Decrease in other assets
(Increase)/Decrease in trade and other receivables
(Increase) Decrease in other assets
Increase in trade and other payables
(Increase) Decrease in other assets
Increase in trade and other payables
Increase/(Decrease) in provisions
Increase in trade and other payables
Increase/(Decrease) in provisions
Net cash outflow from operating activities
Increase/(Decrease) in provisions
Net cash outflow from operating activities
Net cash outflow from operating activities
Changes in financing liabilities arising from cash flow and
Changes in financing liabilities arising from cash flow and
non-cash flow items
Changes in financing liabilities arising from cash flow and
non-cash flow items
non-cash flow items
Convertible note
Convertible note
Balance at the start of the year
Convertible note
Balance at the start of the year
Proceeds/repayment on convertible notes
Balance at the start of the year
Proceeds/repayment on convertible notes
Convertible note transaction costs
Proceeds/repayment on convertible notes
Convertible note transaction costs
Share redemption
Convertible note transaction costs
Share redemption
Non-cash item - interest accretion
Share redemption
Non-cash item - interest accretion
Balance at the end of the year
Non-cash item - interest accretion
Balance at the end of the year
Balance at the end of the year
Refer to note 14 for further details on the convertible note.
Refer to note 14 for further details on the convertible note.
Refer to note 14 for further details on the convertible note.
78
(18,409)
(18,409)
(18,409)
48
48
220
48
220
(1,284)
220
(1,284)
4,959
(1,284)
4,959
305
4,959
305
305
784
784
(1,073)
784
(1,073)
1,307
(1,073)
1,307
(18)
1,307
(18)
(13,161)
(18)
(13,161)
(13,161)
(5,194)
(5,194)
(5,194)
26
26
110
26
110
4,436
110
4,436
877
4,436
877
(1)
877
(1)
(1)
(3,165)
(3,165)
109
(3,165)
109
630
109
630
46
630
46
(2,126)
46
(2,126)
(2,126)
7,542
7,542
(8,100)
7,542
(8,100)
258
(8,100)
258
(100)
258
(100)
400
(100)
400
-
400
-
-
-
-
8,200
-
8,200
(311)
8,200
(311)
-
(311)
-
(347)
-
(347)
7,542
(347)
7,542
7,542
48
48
48
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
OPERATING ASSETS AND LIABILITIES
10. Trade and other receivables
Trade receivables(i)
Other receivables
Allowance for doubtful debts (ii)
2019
US$’000
2018
US$’000
3,213
98
-
3,311
3,997
831
(800)
4,028
Recognition and measurement
Other receivables are initially recognised at fair value and subsequently measured at amortised cost
less an allowance for uncollectible amounts.
Impairment
The Group assesses on a forward looking basis the expected credit losses associated with its debt
instruments carried at amortised cost and FVOCI. The impairment methodology applied depends on
whether there has been a significant increase in credit risk. The Group makes use of a simplified
approach in accounting for trade and other receivables as well as contract assets and records the loss
allowance at the amount equal to the expected lifetime credit losses. In using this practical expedient,
the Group uses its historical experience, external indicators and forward looking information to
calculate the expected credit losses using a provision matrix.
The Group considers a financial asset in default when contractual payment are 90 days past due.
However, in certain cases, the Group may also consider a financial asset to be in default when internal
or external information indicates that the Group is unlikely to receive the outstanding contractual
amounts in full before taking into account any credit enhancements held by the Group.
(i)
(ii)
Trade receivable relates to June 2019 Lightning (net of royalties) and SM 71 oil and gas sales
(before deduction of SM 71 royalties).
Included in other receivables and allowance for doubtful debts in 2018 was $0.8 million receivable
from Swala Oil and Gas (Tanzania) Plc relating to settlement of the various claims and disputes
concerning the Pangani licence. This amount was recovered during the 2019 year.
11. Other assets
Current
Prepayments
Other assets
Non-current
Bonds(i)
2019
US$’000
2018
US$’000
925
313
1,238
393
393
239
48
287
355
355
(i)
Development bond for SM 71 ($325,000), VR232 collateral security deposit ($50k) and Houston
apartment rental bond ($18k).
79
49
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
For the year ended 30 June 2019
11. Other assets (continued)
11. Other assets (continued)
Recognition and measurement
Recognition and measurement
Other financial assets are initially measured at fair value. Transaction costs are included as part of the
Other financial assets are initially measured at fair value. Transaction costs are included as part of the
initial measurement, except for financial assets at fair value through profit or loss. They are
initial measurement, except for financial assets at fair value through profit or loss. They are
subsequently measured at either amortised cost or fair value depending on their classification.
subsequently measured at either amortised cost or fair value depending on their classification.
Classification is determined based on the purpose of the acquisition and subsequent reclassification to
Classification is determined based on the purpose of the acquisition and subsequent reclassification to
other categories is restricted.
other categories is restricted.
Financial assets are derecognised when the rights to receive cash flows from the financial assets have
Financial assets are derecognised when the rights to receive cash flows from the financial assets have
expired or have been transferred and the Group has transferred substantially all the risks and rewards
expired or have been transferred and the Group has transferred substantially all the risks and rewards
of ownership.
of ownership.
12. Oil and gas properties
12. Oil and gas properties
Producing and development assets
Producing and development assets
At cost
At cost
SM71 balance at beginning of year
SM71 balance at beginning of year
SM71 expenditure for the year
SM71 expenditure for the year
SM71 amortisation of assets
SM71 amortisation of assets
SM71 balance at end of year
SM71 balance at end of year
Lightning balance at beginning of year
Lightning balance at beginning of year
Lightning expenditure for the year
Lightning expenditure for the year
Lightning balance at end of year
Lightning balance at end of year
GC-21 balance at beginning of year
GC-21 balance at beginning of year
GC-21 expenditure for the year
GC-21 expenditure for the year
GC-21 balance at end of year
GC-21 balance at end of year
Total oil and gas properties including decommissioning assets
Total oil and gas properties including decommissioning assets
Recognition and measurement
Recognition and measurement
2019
2019
US$’000
US$’000
2018
2018
US$’000
US$’000
27,151
27,151
1,440
1,440
(4,959)
(4,959)
23,632
23,632
-
-
1,934
1,934
1,934
1,934
-
-
5,416
5,416
5,416
5,416
30,982
30,982
6,272
6,272
21,756
21,756
(877)
(877)
27,151
27,151
-
-
-
-
-
-
-
-
-
-
-
-
27,151
27,151
Producing and development assets
Producing and development assets
i)
i)
Producing projects are stated at cost less accumulated amortisation and impairment charges.
Producing projects are stated at cost less accumulated amortisation and impairment charges.
Development assets include evaluation, construction, installation or completion of production and
Development assets include evaluation, construction, installation or completion of production and
infrastructure facilities such as platforms and pipelines, development wells, acquired development or
infrastructure facilities such as platforms and pipelines, development wells, acquired development or
producing assets, capitalised borrowing costs and the estimated costs of decommissioning,
producing assets, capitalised borrowing costs and the estimated costs of decommissioning,
dismantling and restoration. Evaluation is deemed to be activities undertaken from the beginning of the
dismantling and restoration. Evaluation is deemed to be activities undertaken from the beginning of the
definitive feasibility study or testing conducted to assess the technical commercial viability of extracting
definitive feasibility study or testing conducted to assess the technical commercial viability of extracting
a resource before moving into the development phase.
a resource before moving into the development phase.
Once an exploration discovery has been determined, subsequent evaluation and development
Once an exploration discovery has been determined, subsequent evaluation and development
expenditure is capitalised to the Consolidated Statement of Financial Position as oil and gas properties
expenditure is capitalised to the Consolidated Statement of Financial Position as oil and gas properties
as it is probable that future economic benefits associated with the item will flow to the Group. Once
as it is probable that future economic benefits associated with the item will flow to the Group. Once
such costs are capitalised as oil and gas properties, they will be tested for impairment and assessed
such costs are capitalised as oil and gas properties, they will be tested for impairment and assessed
for impairment indicators for periods thereafter.
for impairment indicators for periods thereafter.
80
50
50
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
12. Oil and gas properties (continued)
12. Oil and gas properties (continued)
12. Oil and gas properties (continued)
The carrying value of oil and gas properties is reviewed annually by directors to ensure it is not in excess
The carrying value of oil and gas properties is reviewed annually by directors to ensure it is not in excess
of the recoverable amount. This assessment is based on key estimates, the most significant of which
The carrying value of oil and gas properties is reviewed annually by directors to ensure it is not in excess
of the recoverable amount. This assessment is based on key estimates, the most significant of which
are estimated hydrocarbon reserves, future production profiles, commodity prices, operating costs and
of the recoverable amount. This assessment is based on key estimates, the most significant of which
are estimated hydrocarbon reserves, future production profiles, commodity prices, operating costs and
any future development costs necessary to produce the reserves.
are estimated hydrocarbon reserves, future production profiles, commodity prices, operating costs and
any future development costs necessary to produce the reserves.
any future development costs necessary to produce the reserves.
ii) Prepaid drilling and completion costs
ii) Prepaid drilling and completion costs
Where the Company has a non-operated interest in an oil or gas property, it may periodically be
ii) Prepaid drilling and completion costs
Where the Company has a non-operated interest in an oil or gas property, it may periodically be
required to make a cash contribution for its share of the Operator’s estimated drilling and/or
Where the Company has a non-operated interest in an oil or gas property, it may periodically be
required to make a cash contribution for its share of the Operator’s estimated drilling and/or
completion costs, in advance of these operations taking place.
required to make a cash contribution for its share of the Operator’s estimated drilling and/or
completion costs, in advance of these operations taking place.
completion costs, in advance of these operations taking place.
Where these contributions relate to a prepayment for exploratory or early stage drilling activity, prior
Where these contributions relate to a prepayment for exploratory or early stage drilling activity, prior
to a decision on the commerciality of a well having been made, the costs are expensed in profit or loss
Where these contributions relate to a prepayment for exploratory or early stage drilling activity, prior
to a decision on the commerciality of a well having been made, the costs are expensed in profit or loss
when the cash call is paid. The Operator notifies the Company as to how funds have been expended and
to a decision on the commerciality of a well having been made, the costs are expensed in profit or loss
when the cash call is paid. The Operator notifies the Company as to how funds have been expended and
any relevant costs are reclassified from exploration expense and capitalised to deferred oil and gas
when the cash call is paid. The Operator notifies the Company as to how funds have been expended and
any relevant costs are reclassified from exploration expense and capitalised to deferred oil and gas
properties.
any relevant costs are reclassified from exploration expense and capitalised to deferred oil and gas
properties.
properties.
Where these contributions relate to a prepayment for well completion, these costs are capitalised as
Where these contributions relate to a prepayment for well completion, these costs are capitalised as
prepaid completion costs within oil and gas properties.
Where these contributions relate to a prepayment for well completion, these costs are capitalised as
prepaid completion costs within oil and gas properties.
prepaid completion costs within oil and gas properties.
iii) Commencement of production
iii) Commencement of production
When a well demonstrates commercial feasibility or comes into commercial production, accumulated
iii) Commencement of production
When a well demonstrates commercial feasibility or comes into commercial production, accumulated
development and evaluation expenditure for the relevant area of interest is amortised on a units of
When a well demonstrates commercial feasibility or comes into commercial production, accumulated
development and evaluation expenditure for the relevant area of interest is amortised on a units of
production basis.
development and evaluation expenditure for the relevant area of interest is amortised on a units of
production basis.
production basis.
iv) Amortisation and depreciation of producing projects
iv) Amortisation and depreciation of producing projects
The Group uses the units of production (UOP) approach when amortising and depreciating field-specific
iv) Amortisation and depreciation of producing projects
The Group uses the units of production (UOP) approach when amortising and depreciating field-specific
assets. Using this method of amortisation and depreciation requires the Group to compare the actual
The Group uses the units of production (UOP) approach when amortising and depreciating field-specific
assets. Using this method of amortisation and depreciation requires the Group to compare the actual
volume of production to the reserves and then to apply this determined rate of depletion to the carrying
assets. Using this method of amortisation and depreciation requires the Group to compare the actual
volume of production to the reserves and then to apply this determined rate of depletion to the carrying
value of the depreciable asset.
volume of production to the reserves and then to apply this determined rate of depletion to the carrying
value of the depreciable asset.
value of the depreciable asset.
fields are
Capitalised producing project
fields are
Capitalised producing project
depreciated/amortised using the UOP basis once commercial quantities are being produced within an
Capitalised producing project
fields are
depreciated/amortised using the UOP basis once commercial quantities are being produced within an
area of interest. The reserves used in these calculations are the proved plus probable reserves (2P)
depreciated/amortised using the UOP basis once commercial quantities are being produced within an
area of interest. The reserves used in these calculations are the proved plus probable reserves (2P)
and are reviewed at least annually.
area of interest. The reserves used in these calculations are the proved plus probable reserves (2P)
and are reviewed at least annually.
and are reviewed at least annually.
Key estimates and judgements
Key estimates and judgements
Carrying value of oil and gas assets
Key estimates and judgements
Carrying value of oil and gas assets
Judgement is required to determine when an exploration activity ceases and an evaluation or
Carrying value of oil and gas assets
Judgement is required to determine when an exploration activity ceases and an evaluation or
development activity commences. Evaluation is deemed to be activities undertaken from the beginning
Judgement is required to determine when an exploration activity ceases and an evaluation or
development activity commences. Evaluation is deemed to be activities undertaken from the beginning
of the definitive feasibility study or testing conducted to assess the technical commercial viability of
development activity commences. Evaluation is deemed to be activities undertaken from the beginning
of the definitive feasibility study or testing conducted to assess the technical commercial viability of
extracting a resource before moving into the development phase. Development assets include
of the definitive feasibility study or testing conducted to assess the technical commercial viability of
extracting a resource before moving into the development phase. Development assets include
evaluation, construction, installation or completion of production and infrastructure facilities such as
extracting a resource before moving into the development phase. Development assets include
evaluation, construction, installation or completion of production and infrastructure facilities such as
platforms and pipelines, development wells, acquired development or producing assets, capitalised
evaluation, construction, installation or completion of production and infrastructure facilities such as
platforms and pipelines, development wells, acquired development or producing assets, capitalised
borrowing costs and the estimated costs of decommissioning, dismantling and restoration.
platforms and pipelines, development wells, acquired development or producing assets, capitalised
borrowing costs and the estimated costs of decommissioning, dismantling and restoration.
borrowing costs and the estimated costs of decommissioning, dismantling and restoration.
Circumstances vary for each area of interest and where exploration, evaluation and development
Circumstances vary for each area of interest and where exploration, evaluation and development
activities are conducted within a continual timeframe as part of the same project or drilling campaign
Circumstances vary for each area of interest and where exploration, evaluation and development
activities are conducted within a continual timeframe as part of the same project or drilling campaign
with common service providers, a degree of estimation is required in determining the amount of costs
activities are conducted within a continual timeframe as part of the same project or drilling campaign
with common service providers, a degree of estimation is required in determining the amount of costs
capitalised as evaluation and development assets under oil and gas properties.
with common service providers, a degree of estimation is required in determining the amount of costs
capitalised as evaluation and development assets under oil and gas properties.
capitalised as evaluation and development assets under oil and gas properties.
Assessment of costs associated with non-operated interests is also influenced by notification from the
Assessment of costs associated with non-operated interests is also influenced by notification from the
Operator as to how funds have been expended.
Assessment of costs associated with non-operated interests is also influenced by notification from the
Operator as to how funds have been expended.
Operator as to how funds have been expended.
commercially producing
commercially producing
commercially producing
relating
relating
relating
costs
costs
costs
to
to
to
81
51
51
51
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
12. Oil and gas properties (continued)
12. Oil and gas properties (continued)
For GC-21, the well had two planned target intervals. The shallower DTR-10 sand was an appraisal
target, having already been discovered by previous wells (prior to Otto’s involvement). The deeper MP
For GC-21, the well had two planned target intervals. The shallower DTR-10 sand was an appraisal
sand was an exploration target. Therefore the accounting for the drilling of the GC-21 Bulleit well
target, having already been discovered by previous wells (prior to Otto’s involvement). The deeper MP
involved capitalising drilling expenses initially while the DTR-10 sand was tested. Once the DTR-10 sand
sand was an exploration target. Therefore the accounting for the drilling of the GC-21 Bulleit well
was deemed a discovery and casing successfully set, drilling costs from that point on were then
involved capitalising drilling expenses initially while the DTR-10 sand was tested. Once the DTR-10 sand
expensed as the well progressed through the exploration stage of testing the MP sand exploration
was deemed a discovery and casing successfully set, drilling costs from that point on were then
target. At 30 June 2019 the well was drilling ahead toward the MP sand.
expensed as the well progressed through the exploration stage of testing the MP sand exploration
target. At 30 June 2019 the well was drilling ahead toward the MP sand.
Impairment
Assets are tested for impairment in line with the accounting policies disclosed in Note 12(i) whenever
Impairment
events or changes in circumstances indicate that the carrying amount may not be recoverable. An
Assets are tested for impairment in line with the accounting policies disclosed in Note 12(i) whenever
impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its
events or changes in circumstances indicate that the carrying amount may not be recoverable. An
recoverable amount. The recoverable amount is the higher of an asset’s fair value less cost to sell and
impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its
value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for
recoverable amount. The recoverable amount is the higher of an asset’s fair value less cost to sell and
which there are separately identifiable cash inflows which are largely independent of the cash inflows
value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for
from other assets or groups of assets (cash-generating units).
which there are separately identifiable cash inflows which are largely independent of the cash inflows
from other assets or groups of assets (cash-generating units).
At 30 June 2019, the Group has separately assessed the SM 71 and Lightning cash-generating units
and determined that no impairment indicators existed.
At 30 June 2019, the Group has separately assessed the SM 71 and Lightning cash-generating units
and determined that no impairment indicators existed.
As at 30 June 2019 the GC-21 Bulleit well was drilling ahead to the MP sand exploration target, having
successfully intersected the DTR-10 appraisal target. Subsequent to year end, the well successfully
As at 30 June 2019 the GC-21 Bulleit well was drilling ahead to the MP sand exploration target, having
intersected the MP sand target logging approximately 110 feet of net oil pay. The well has been declared
successfully intersected the DTR-10 appraisal target. Subsequent to year end, the well successfully
a commercial success and the joint venture is currently planning the tie back of the well to the GC-18
intersected the MP sand target logging approximately 110 feet of net oil pay. The well has been declared
production platform. Utilising the data available, the Company has determined that it is probable that
a commercial success and the joint venture is currently planning the tie back of the well to the GC-18
future economic benefits in excess of the carrying value will flow to the Group from the GC-21 asset.
production platform. Utilising the data available, the Company has determined that it is probable that
GC-21 was assessed for impairment indicators as at 30 June 2019. No impairment indicators were
future economic benefits in excess of the carrying value will flow to the Group from the GC-21 asset.
identified.
GC-21 was assessed for impairment indicators as at 30 June 2019. No impairment indicators were
identified.
Amortisation
Estimation of amortisation of the SM 71 oil and gas asset is based on the updated 2P reserves estimate
Amortisation
and estimated future development costs as at 30 June 2019. Producing assets are amortised on a unit
Estimation of amortisation of the SM 71 oil and gas asset is based on the updated 2P reserves estimate
of production basis on 2P reserves. The 2P reserves have been determined by an independent expert.
and estimated future development costs as at 30 June 2019. Producing assets are amortised on a unit
The method of amortisation necessitates the estimation of oil and gas reserves over which the carrying
of production basis on 2P reserves. The 2P reserves have been determined by an independent expert.
value of the relevant asset will be expensed to profit or loss. See below for judgements relating to
The method of amortisation necessitates the estimation of oil and gas reserves over which the carrying
reserve estimates
value of the relevant asset will be expensed to profit or loss. See below for judgements relating to
No amortisation has been applied to the Lightning oil and gas field for the year to 30 June 2019 as the
reserve estimates
field only reached steady state production in June 2019, hence the amortisation amount was not
No amortisation has been applied to the Lightning oil and gas field for the year to 30 June 2019 as the
material.
field only reached steady state production in June 2019, hence the amortisation amount was not
There is no amortisation for the GC-21 asset as the Bulleit well was still drilling as of 30 June 2019,
material.
hence production had not commenced.
There is no amortisation for the GC-21 asset as the Bulleit well was still drilling as of 30 June 2019,
hence production had not commenced.
Reserve Estimates
Estimation of reported recoverable quantities of proved and provable reserves include judgemental
Reserve Estimates
assumptions regarding commodity prices, exchange rates, discount rates and production and
Estimation of reported recoverable quantities of proved and provable reserves include judgemental
transportation cost for future cash flows. It also requires interpretation of complex geological and
assumptions regarding commodity prices, exchange rates, discount rates and production and
geophysical models in order to make an assessment of the size, shape, depth and quality of reservoirs
transportation cost for future cash flows. It also requires interpretation of complex geological and
and their anticipated recoveries. The economic, geological and technical factors used to estimate
geophysical models in order to make an assessment of the size, shape, depth and quality of reservoirs
reserves may change from period to period. Changes in reported reserves can impact assets’ carrying
and their anticipated recoveries. The economic, geological and technical factors used to estimate
amounts, provision for restoration and recognition of deferred tax asses due to changes in expected
reserves may change from period to period. Changes in reported reserves can impact assets’ carrying
future cash flows. Reserves are integral to the amount of depreciation, amortisation and impairment
amounts, provision for restoration and recognition of deferred tax asses due to changes in expected
charged to the income statement.
future cash flows. Reserves are integral to the amount of depreciation, amortisation and impairment
charged to the income statement.
82
52
52
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
12. Oil and gas properties (continued)
Property, plant and equipment
Recognition and measurement
Property, plant and equipment are stated at historical cost less depreciation. Historical cost includes
expenditure that is directly attributable to the acquisition of the items.
Depreciation is calculated using the straight-line method to allocate their cost, net of their residual
values, over their estimated useful lives. The following estimated useful lives are used in the calculation
of depreciation:
Plant and equipment
Furniture and equipment
5 years
3 - 10 years
The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at the end of each
reporting period. An asset’s carrying amount is written down immediately to its recoverable amount if
the asset’s carrying amount is greater than its estimated recoverable amount.
Gains and losses on disposals are determined by comparing proceeds with the carrying amount. These
are included in profit or loss. When revalued assets are sold, it is Group policy to transfer any amounts
included in other reserves in respect of those assets to retained earnings.
13. Trade and other payables
Trade payables
Success Fee – convertible note see note 14
Interest payable – convertible note see note 14
Other Accrued expenses
2019
US$’000
2018
US$’000
2,874
187
-
1,412
4,473
2,141
163
1,225
1,234
4,763
Recognition and measurement
Trade payables are initially recognised at their fair value and subsequently measured at amortised cost.
They represent liabilities for goods and services provided to the Group prior to the end of the financial
year that are unpaid and arise when the Group becomes obliged to make future payments in respect of
the purchase of these goods and services. The amounts are unsecured and generally paid within 30
days of recognition.
14. Convertible Note
Convertible note
Balance at the beginning of the year
Convertible note debt host liability – at cost
Interest accretion (reversal)
Convertible note transaction costs – at cost
Balance at the end of the year
2019
US$’000
7,542
(7,453)
(347)
258
-
2018
US$’000
-
7,453
347
(258)
7,542
53
83
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
14. Convertible Note (continued)
Convertible note derivative
Balance at the beginning of the year
Convertible note embedded derivative – at fair value through
statement of profit or loss
Balance at the end of the year
2019
US$’000
2018
US$’000
3,183
(3,183)
-
-
3,183
3,183
On 2 August 2017 the Company issued $8.2 million secured convertible notes (the ‘Notes’) to Molton
Holdings Limited, a major Otto shareholder ($8.0 million) and Mr John Jetter, Otto’s Chairman ($0.2
million).
Under the terms of the Convertible Notes issued on 2 August 2017, Otto issued a redemption notice to
the Noteholders on 26 March 2019 for the full 8.2 million convertible notes. The Noteholders elected to
convert 100,000 of the notes into ordinary shares with the balance of 8.1 million notes redeemed on 30
April 2019.
On 30 April 2019, J Jetter converted 100,000 convertible notes to 2,599,211 shares at a conversion price
of AUD0.05418 (USD conversion rate 0.7101). As at 30 June 2019 there was a success fee payable to the
noteholders of $187,000. This was fully paid by the due date of 30 July 2019.
As at 30 June 2019 there was no principle outstanding and no interest payable.
Key estimates and judgements
For accounting purposes, the Notes had two elements: a debt host liability component and an
embedded derivative component. On initial recognition, the fair value of the embedded derivative
component was calculated first and the residual value assigned to the debt host component. No gain
or loss was recognised on inception.
The debt host liability component was subsequently carried at amortised cost whereby the initial
carrying value of the liability was accreted to the principal amount over the life of the Note. The
accretion was recognised as a finance cost together with the interest expense (refer note 5). The debt
host liability balance reduced to nil on redemption of the convertible notes on 30 April 2019.
The fair value of the embedded derivative was determined each balance date using the Black Scholes
model and any changes in fair value recorded in profit or loss. On the date of issue of the Notes, the
fair value of the embedded derivative liability was determined to be $0.747 million using a Black Scholes
valuation based on the time to expiry, the Company’s share price of A$0.028, risk free interest rate of
1.8% and assuming 68% volatility. The fair value of the embedded derivative liability at 30 June 2018
was determined to be $3.183 million using a Black Scholes valuation based on the time to expiry, the
Company’s 30 June 2018 share price of A$0.065 (note this is above the conversion price of A$0.055),
risk free interest rate of 2.0% and assuming 65% volatility. At 30 June 2019 the entries were reversed
as the convertible notes were redeemed in April 2019. The reversal of the fair value balance of $3.183
million has been recognized in the profit and loss (refer note 5).
84
54
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
15. Provisions
15. Provisions
Current
Current
Employee benefits
Employee benefits
Tax
Tax
Decommissioning fund (ii)
Decommissioning fund (ii)
Non-current
Non-current
Employee benefits (i)
Employee benefits (i)
Decommissioning fund - Lightning(ii)
Decommissioning fund - Lightning(ii)
Decommissioning fund – SM 71 (ii)
Decommissioning fund – SM 71 (ii)
2019
2019
US$’000
US$’000
2018
2018
US$’000
US$’000
170
170
3
3
-
-
173
173
17
17
111
111
1,461
1,461
1,589
1,589
201
201
1
1
-
-
202
202
6
6
-
-
1,122
1,122
1,128
1,128
(i)
(i)
The non-current provision for employee benefits includes amounts not expected to be settled
The non-current provision for employee benefits includes amounts not expected to be settled
within the next 12 months.
within the next 12 months.
(ii) The total present value of the estimated expenditure required to decommission the wells and
(ii) The total present value of the estimated expenditure required to decommission the wells and
facilities. The expenditure is expected to be settled at the end of the field life for the 2P production
facilities. The expenditure is expected to be settled at the end of the field life for the 2P production
profile.
profile.
Recognition and measurement
Recognition and measurement
Employee benefits
Employee benefits
A liability is recognised for benefits accruing to employees in respect of wages and salaries, annual
A liability is recognised for benefits accruing to employees in respect of wages and salaries, annual
leave and long service leave when it is probable that settlement will be required and they are capable
leave and long service leave when it is probable that settlement will be required and they are capable
of being measured reliably.
of being measured reliably.
Liabilities recognised in respect of employee benefits expected to be settled within 12 months are
Liabilities recognised in respect of employee benefits expected to be settled within 12 months are
measured at their nominal values using the remuneration rate expected to apply at the time of
measured at their nominal values using the remuneration rate expected to apply at the time of
settlement.
settlement.
Liabilities recognised in respect of employee benefits which are not expected to be settled within 12
Liabilities recognised in respect of employee benefits which are not expected to be settled within 12
months are measured as the present value of the estimated future cash outflows to be made by the
months are measured as the present value of the estimated future cash outflows to be made by the
Group in respect of services provided by employees up to reporting date.
Group in respect of services provided by employees up to reporting date.
Contributions to superannuation plans are expensed when incurred.
Contributions to superannuation plans are expensed when incurred.
Decommissioning fund
Decommissioning fund
Provisions are recognised when the Group has a present obligation (legal or constructive) as a result
Provisions are recognised when the Group has a present obligation (legal or constructive) as a result
of past events, it is probable that the Group will be required to settle the obligation and the amount of
of past events, it is probable that the Group will be required to settle the obligation and the amount of
the provision can be measured reliably.
the provision can be measured reliably.
The amount recognised as a provision is the best estimate of the consideration required to settle the
The amount recognised as a provision is the best estimate of the consideration required to settle the
present obligation at the reporting date, taking into account the risks and uncertainties surrounding
present obligation at the reporting date, taking into account the risks and uncertainties surrounding
the obligation. Where a provision is measured using the cash flows estimated to settle the present
the obligation. Where a provision is measured using the cash flows estimated to settle the present
obligation, its carrying amount is the present value of those cash flows. The unwinding of the discount
obligation, its carrying amount is the present value of those cash flows. The unwinding of the discount
is expensed as incurred and recognised in the Consolidated Statement of Profit or Loss and Other
is expensed as incurred and recognised in the Consolidated Statement of Profit or Loss and Other
Comprehensive Income as a finance cost.
Comprehensive Income as a finance cost.
85
55
55
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
15. Provisions (continued)
Provision is made for the estimated cost of legal and constructive obligations to restore operating
locations in the period in which the obligation arises. The estimated costs are capitalised as part of the
cost of the related project where recognition occurs upon acquisition of an interest in the operating
locations. The carrying amount capitalised is amortised on a unit of production basis during the
production phase of the project.
Work scope and cost estimates for restoration are reviewed annually and adjusted to reflect the
expected cost of restoration. The Group accounts for changes in cost estimates on a prospective basis.
Key estimates and judgements
Decommissioning costs will be incurred by the Group at the end of the operating life of some of the
Group’s facilities and properties. The Group assesses its decommissioning provision at each reporting
date. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to
many factors, including changes to relevant legal requirements, the emergence of new restoration
techniques or experience at other production sites. The expected timing, extent and amount of expense
can also change. Therefore, significant estimates and assumptions are made in determining the
provision for decommissioning. As a result, there could be significant adjustments to the provisions
established which would affect future financial results. The provision at reporting date represents
management’s best estimate of the present value of the future decommissioning costs required.
86
56
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
CAPITAL STRUCTURE, FINANCIAL INSTRUMENTS AND RISK
CAPITAL STRUCTURE, FINANCIAL INSTRUMENTS AND RISK
16. Contributed equity
16. Contributed equity
a) Share capital
a) Share capital
Balance at beginning of year
Balance at beginning of year
Shares issued – placement
Shares issued – placement
Shares issued – entitlement offers
Shares issued – entitlement offers
Shares issued – share purchase
Shares issued – share purchase
plan
plan
Shares issued - directors
Shares issued - directors
Shares issued on conversion of
Shares issued on conversion of
notes
notes
Shares issued on exercise of
Shares issued on exercise of
performance rights
performance rights
Balance at end of year
Balance at end of year
2019
2019
Number
Number
1,530,928,490
1,530,928,490
377,038,698(i)
377,038,698(i)
545,159,326(ii)
545,159,326(ii)
2018
2018
Number
Number
1,186,298,324
1,186,298,324
236,857,143
236,857,143
-
-
2019
2019
US$’000
US$’000
90,704
90,704
14,235
14,235
20,002
20,002
2018
2018
US$’000
US$’000
81,895
81,895
5,986
5,986
-
-
-
-
-
-
100,000,166
100,000,166
6,142,857
6,142,857
2,599,211(iii)
2,599,211(iii)
-
-
-
-
-
-
100
100
4,739,000(iv)
4,739,000(iv)
2,460,464,725
2,460,464,725
1,630,000
1,630,000
1,530,928,490
1,530,928,490
-
-
125,041
125,041
2,660
2,660
163
163
-
-
-
-
90,704
90,704
(i) Share placements
(i) Share placements
a. August 2018 at AUD0.059 per share, converted to USD at the exchange rate on the
a. August 2018 at AUD0.059 per share, converted to USD at the exchange rate on the
transaction date of 0.7372. Net of share issue costs.
transaction date of 0.7372. Net of share issue costs.
b. April 2019 at AUD0.053 per share, converted to USD at the exchange rate on the
b. April 2019 at AUD0.053 per share, converted to USD at the exchange rate on the
transaction date of 0.7124. Net of share issue costs.
transaction date of 0.7124. Net of share issue costs.
(ii) Share entitlements:
(ii) Share entitlements:
a.
a.
b.
b.
Institutional entitlement issued August 2018 at AUD0.059 per share, converted to USD
Institutional entitlement issued August 2018 at AUD0.059 per share, converted to USD
at the exchange rate on the transaction date of 0.7372. Net of share issue costs.
at the exchange rate on the transaction date of 0.7372. Net of share issue costs.
Institutional entitlement issued April 2019 at AUD0.053 per share, converted to USD at
Institutional entitlement issued April 2019 at AUD0.053 per share, converted to USD at
the exchange rate on the transaction date of 0.7124. Net of share issue costs.
the exchange rate on the transaction date of 0.7124. Net of share issue costs.
c. Retail entitlement issued August 2018 at AUD0.059 per share, converted to USD at the
c. Retail entitlement issued August 2018 at AUD0.059 per share, converted to USD at the
exchange rate on the transaction date of 0.7307. Net of share issue costs.
exchange rate on the transaction date of 0.7307. Net of share issue costs.
d. Retail entitlement issued April 2019 at AUD0.053 per share, converted to USD at the
d. Retail entitlement issued April 2019 at AUD0.053 per share, converted to USD at the
exchange rate on the transaction date of 0.7020. Net of share issue costs.
exchange rate on the transaction date of 0.7020. Net of share issue costs.
(iii) Shares issued to J Jetter on conversion of 100,000 convertible notes April 2019 at conversion
(iii) Shares issued to J Jetter on conversion of 100,000 convertible notes April 2019 at conversion
price AUD0.05418 and converted to USD at 0.7101
price AUD0.05418 and converted to USD at 0.7101
(iv) Shares issued on exercise of performance rights November 2018 (4,729,000) and February 2019
(iv) Shares issued on exercise of performance rights November 2018 (4,729,000) and February 2019
(10,000)
(10,000)
b) Ordinary shares
b) Ordinary shares
Ordinary shares entitle the holder to participate in dividends and the proceeds on winding up of the
Ordinary shares entitle the holder to participate in dividends and the proceeds on winding up of the
Company in proportion to the number and amount paid on the shares held. On a show of hands every
Company in proportion to the number and amount paid on the shares held. On a show of hands every
holder of ordinary shares present at a meeting in person or by proxy, is entitled to one vote, and upon
holder of ordinary shares present at a meeting in person or by proxy, is entitled to one vote, and upon
a poll each share is entitled to one vote. The ordinary shares have no par value and the Company does
a poll each share is entitled to one vote. The ordinary shares have no par value and the Company does
not have a limited amount of authorised capital.
not have a limited amount of authorised capital.
c) Options
c) Options
Information relating to the Otto Energy Employee Option Plan, including details of options issued,
Information relating to the Otto Energy Employee Option Plan, including details of options issued,
exercised and lapsed during the financial year and options outstanding at the end of the reporting
exercised and lapsed during the financial year and options outstanding at the end of the reporting
period, is set out in Note 21.
period, is set out in Note 21.
87
57
57
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
For the year ended 30 June 2019
16. Contributed Equity (continued)
16. Contributed Equity (continued)
16. Contributed Equity (continued)
d) Performance rights
d) Performance rights
d) Performance rights
Information relating to the Otto Energy Employee Performance Rights Plan, including details of
Information relating to the Otto Energy Employee Performance Rights Plan, including details of
performance rights issued, exercised and lapsed during the financial year and performance rights
Information relating to the Otto Energy Employee Performance Rights Plan, including details of
performance rights issued, exercised and lapsed during the financial year and performance rights
outstanding at the end of the reporting period, is set out in Note 21.
performance rights issued, exercised and lapsed during the financial year and performance rights
outstanding at the end of the reporting period, is set out in Note 21.
outstanding at the end of the reporting period, is set out in Note 21.
Recognition and measurement
Recognition and measurement
Ordinary shares are classified as equity.
Recognition and measurement
Ordinary shares are classified as equity.
Ordinary shares are classified as equity.
Incremental costs directly attributable to the issue of new shares or options are shown in equity as a
Incremental costs directly attributable to the issue of new shares or options are shown in equity as a
deduction, net of tax, from the proceeds.
Incremental costs directly attributable to the issue of new shares or options are shown in equity as a
deduction, net of tax, from the proceeds.
deduction, net of tax, from the proceeds.
17. Reserves
17. Reserves
17. Reserves
Share-based payments reserve
Share-based payments reserve
Foreign currency translation reserve
Share-based payments reserve
Foreign currency translation reserve
Foreign currency translation reserve
Share-based payments reserve
Share-based payments reserve
Balance at beginning of year
Share-based payments reserve
Balance at beginning of year
Share-based payment expense
Balance at beginning of year
Share-based payment expense
Balance at end of year
Share-based payment expense
Balance at end of year
Balance at end of year
Foreign currency translation reserve
Foreign currency translation reserve
Balance at beginning of year
Foreign currency translation reserve
Balance at beginning of year
Reversal of FCTR to other comprehensive income
Balance at beginning of year
Reversal of FCTR to other comprehensive income
Balance at end of year
Reversal of FCTR to other comprehensive income
Balance at end of year
Balance at end of year
2019
2019
US$’000
2019
US$’000
US$’000
2018
2018
US$’000
2018
US$’000
US$’000
9,879
9,879
4,188
9,879
4,188
14,067
4,188
14,067
14,067
9,659
9,659
220
9,659
220
9,879
220
9,879
9,879
4,188
4,188
-
4,188
-
4,188
-
4,188
4,188
9,549
9,549
4,188
9,549
4,188
13,737
4,188
13,737
13,737
9,549
9,549
110
9,549
110
9,659
110
9,659
9,659
4,188
4,188
-
4,188
-
4,188
-
4,188
4,188
The share-based payments reserve is used to recognise the value of share-based payments provided
The share-based payments reserve is used to recognise the value of share-based payments provided
to employees (including key management personnel) as part of their remuneration and share options
The share-based payments reserve is used to recognise the value of share-based payments provided
to employees (including key management personnel) as part of their remuneration and share options
and performance rights issued as part of consideration for acquisitions. Refer to Note 21 for further
to employees (including key management personnel) as part of their remuneration and share options
and performance rights issued as part of consideration for acquisitions. Refer to Note 21 for further
details of these plans.
and performance rights issued as part of consideration for acquisitions. Refer to Note 21 for further
details of these plans.
details of these plans.
The foreign currency translation reserve is used to record currency differences arising from the
The foreign currency translation reserve is used to record currency differences arising from the
translation of the financial statements of foreign operations. The FCTR balance has been carried
The foreign currency translation reserve is used to record currency differences arising from the
translation of the financial statements of foreign operations. The FCTR balance has been carried
forward since 2011 when the functional currency for the financial statements of Otto Energy Philippines
translation of the financial statements of foreign operations. The FCTR balance has been carried
forward since 2011 when the functional currency for the financial statements of Otto Energy Philippines
Inc. was changed from PHP to USD following the election by Otto Energy Philippines Inc to use USD as
forward since 2011 when the functional currency for the financial statements of Otto Energy Philippines
Inc. was changed from PHP to USD following the election by Otto Energy Philippines Inc to use USD as
it’s functional currency.
Inc. was changed from PHP to USD following the election by Otto Energy Philippines Inc to use USD as
it’s functional currency.
it’s functional currency.
18. Financial instruments
18. Financial instruments
18. Financial instruments
The Group is exposed to market risk, credit risk and liquidity risk. The Group’s overall risk management
The Group is exposed to market risk, credit risk and liquidity risk. The Group’s overall risk management
program focuses on the unpredictability of financial markets and seeks to minimise potential adverse
The Group is exposed to market risk, credit risk and liquidity risk. The Group’s overall risk management
program focuses on the unpredictability of financial markets and seeks to minimise potential adverse
effects on the financial performance of the Group. The Group uses different methods to measure
program focuses on the unpredictability of financial markets and seeks to minimise potential adverse
effects on the financial performance of the Group. The Group uses different methods to measure
different types of risk to which it is exposed.
effects on the financial performance of the Group. The Group uses different methods to measure
different types of risk to which it is exposed.
different types of risk to which it is exposed.
Otto’s Board of Directors (‘Board’) is responsible for approving Otto’s policies on risk oversight and
Otto’s Board of Directors (‘Board’) is responsible for approving Otto’s policies on risk oversight and
management and ensuring management has developed and implemented effective risk management
Otto’s Board of Directors (‘Board’) is responsible for approving Otto’s policies on risk oversight and
management and ensuring management has developed and implemented effective risk management
and internal controls. Risk management is carried out by the senior executives under these policies
management and ensuring management has developed and implemented effective risk management
and internal controls. Risk management is carried out by the senior executives under these policies
which have been approved by the Board. Management identifies, evaluates and, if necessary, hedges
and internal controls. Risk management is carried out by the senior executives under these policies
which have been approved by the Board. Management identifies, evaluates and, if necessary, hedges
which have been approved by the Board. Management identifies, evaluates and, if necessary, hedges
88
58
58
58
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
18. Financial instruments (continued)
financial risks within the Group’s operating units. The Board then receives reports as required from the
Chief Financial Officer or Senior Commercial Manager in which they review the effectiveness of the
processes implemented and appropriateness of policies it sets. At all times during the year, and to the
date of this report, the Group did not apply any form of hedge accounting.
a) Market risk
Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate
because of changes in market prices. Market risk for the Group comprises three types of risk: currency
risk, interest rate risk and commodity price risk.
i) Currency risk
The Group’s source currency for the majority of revenue and costs is in US dollars. Given the location
of the group’s offices and operations there is a small exposure to foreign exchange risk arising from
the fluctuations in the USD to AUD exchange rate on Australian dollar cash balances and monetary
items at year end.
Currency risk arises where the value of a financial instrument or monetary item fluctuates due to
changes in foreign currency exchange rates. The exposure to currency risk is measured using
sensitivity analysis and cash flow forecasting.
The Board has formed the view that in the ordinary course of business it would not be beneficial for the
Group to purchase forward contracts or other derivative financial instruments to hedge this currency
risk. Factors which the Board considered in arriving at this position included the expense of purchasing
such instruments and the inherent difficulties associated with forecasting the timing and quantum of
cash inflows and outflows compared to the relatively low volume and value of commercial transactions
and monetary items denominated in a currency which is not US dollars.
During the year the company undertook capital raising activities via the issue of new shares on the ASX.
These capital raisings are priced and received in AUD. Over the time period of a capital raising there is
some short-term exposure to movements in the AUD to USD exchange rates. During the year the
company utilised some forward contracts to buy USD in order to mitigate the currency risk. There are
no outstanding currency hedges at year end.
A hypothetical change of 10% (2018: 10%) in the Australian dollar exchange rate was used to calculate
the Group’s sensitivity to foreign exchange rates movements, as this is management’s estimate of
possible rate movements over the coming year taking into account current market conditions and past
volatility. At 30 June 2019, management has assessed that the entity’s exposure to foreign exchange
movements is immaterial and therefore no further analysis is provided.
ii)
Interest rate risk
Interest rate risk is the risk that the Group’s financial position will fluctuate due to changes in market
interest rates. At 30 June 2019 the Group’s exposure to the risk of changes in the market interest rates
relates to interest income on cash and cash equivalents held with financial institutions. The convertible
notes facility that the Group had entered into was redeemed in the year and had a fixed interest rate so
was not exposed to interest rate risk. Refer note 14.
89
59
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
18. Financial instruments (continued)
The financial instruments exposed to movements in variable interest rates are as follows:
Cash and cash equivalents
2019
US$’000
2018
US$’000
7,383
7,383
5,945
5,945
The following sensitivity analysis is based on the interest rate risk exposures in existence at the
reporting date. The 1.0% sensitivity is based on reasonably possible changes, over a financial year,
using an observed range of historical short term deposit rate movements over the last 3 years.
Judgements of reasonably possible movements
Increase 100 basis points
Decrease 100 basis points
iii) Commodity price risk
Effect on post tax losses
Increase/(decrease)
2018
2019
US$’000
US$’000
74
(74)
59
(59)
During the year the Group generated revenue from its SM 71 oil production and in May 2019 commenced
selling gas and condensate from the Lightning field. With this oil and gas production and sales, the
group is exposed to US oil and gas price fluctuations.
Exposure to oil and gas price risk is measured by monitoring and stress testing the Group’s forecast
financial position and cash flows against sustained periods of low oil and gas prices. This analysis is
regularly performed on the Group’s portfolio and, as required, for discrete projects and acquisitions.
Commodity hedging may be undertaken where the Board of Directors determines that a hedging
strategy is appropriate to mitigate potential periods of adverse movements in commodity price and
protect forward cash flows to meet commitments. This will be balanced against the desire to expose
shareholders to oil price upside and the reliability of production forecasts. Commodity hedging may
also be undertaken when there is a hedging requirement under a lending facility.
On 3 April 2019 Otto announced that it has implemented a hedging program in the United States for its
SM 71 oil production. The hedging program is designed to provide certainty of cash flows and funding
during a period of significant investment in growth projects.
Otto acquired US$60/bbl puts over 111,000 bbls of oil production from its interest in the SM 71 oil field.
The monthly volumes covered by the put options were between 50% and 70% of the forecast Proved
Developed Producing (PDP) production from the Sm 71 field (PDP forecast is as per the Collarini 30
June 2018 reserves estimation).
The puts are based on the LLS benchmark and the premium for the puts is US$1.75/bbl amounting to
a total of US$194,000 for the program which was paid up front.
90
60
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
18. Financial instruments (continued)
The use of US$60/bbl strike price put options provide Otto with a minimum price receivable for those
barrels. Otto still maintains the upside exposure where the LLS benchmark price achieved is over
US$60/bbl.
As at 30 June 2019 Otto has US$60/bbl puts remaining over 65,000 bbls of SM 71 production for the
moths of July to October
b) Credit risk
Credit risk is the risk that a contracting entity will not complete its obligation under a financial
instrument that will result in a financial loss to the Group. Credit risk arises from the financial assets
of the Group, which comprise trade and other receivables and deposits with banks and financial
institutions.
To manage credit risk from cash and cash equivalents, it is the Group’s policy to only deposit with banks
maintaining a minimum independent rating of ‘AA’, ‘A+’ or ‘A-‘. Contracts for the sale of production
from SM 71 and Lightning are with creditworthy customers and counterparties.
Receivables balances are monitored on an ongoing basis with the result that the Group’s exposure to
bad debts in the ordinary course of business is not significant. At reporting date no receivables were
overdue.
The maximum exposure to credit risk at reporting date was as follows:
Cash and cash equivalents
Trade and other receivables
c) Liquidity risk
2019
US$’000
2018
US$’000
7,383
3,311
10,694
5,945
4,028
9,973
Liquidity risk is the risk that Group will encounter difficulty in meeting obligations associated with
financial liabilities that are settled by delivering cash or another financial asset.
It is the policy of the Board to ensure that the Group is able to meet its financial obligations and maintain
the flexibility to pursue attractive investment opportunities through the Group maintaining sufficient
working capital and access to further funding when required through debt, equity or other means.
The Group manages liquidity risk by continuously monitoring forecast and actual cash flows with
scenario analysis. As at reporting date the Group had sufficient cash reserves to meet its current
requirements and no receivables were overdue.
91
61
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
18. Financial instruments (continued)
The contractual maturity analysis of payables at the reporting date was as follows:
Carrying
Value
US$’000
Total
US$’000
Less than
1 year
US$’000
Between
1-2 years
US$’000
Between
2-5 years
US$’000
Trade and other payables
2019
2018
4,473
4,763
4,473
4,763
4,473
4,763
Convertible Notes – refer note 14
2019
2018
-
7,542
-
7,542
-
7,542
-
-
-
-
-
-
-
-
Capital risk management
The Group manages its capital to ensure that it will be able to continue as a going concern while
maximising the potential return to shareholders through the optimisation of the debt and equity
balance.
The capital structure of the Group at year end comprises equity and no debt (2018: Debt to equity ratio
of 51% based on the accounting carrying value of the convertible note as at 30 June 2018).
In determining the funding mix of debt and equity (total borrowings/total equity), consideration is given
to the relative impact of the gearing ratio on the ability of the Group to service interest and repayment
schedules, credit facility covenants and also to generate adequate free cash available for corporate and
oil and gas exploration, development and production activities.
The Group may consider raising capital when an opportunity to invest in an opportunity, business or
company is seen as value adding relative to the company's current share price at the time of the
investment.
c) Equity price risk
The Group is not exposed to equity price risk on its financial liabilities
d) Fair values
The following table shows the carrying amounts and fair values of financial liabilities, including their
levels in the fair value hierarchy. It does not include fair value information for financial liabilities not
measured at fair value if the carrying value is a reasonable approximation of fair value. The different
valuation methods are called hierarchies and they are described below:
92
62
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
18. Financial instruments (continued)
Level
Carrying Amount
2018
2019
US$’000
US$’000
Fair Value
2019
US$’000
2018
US$’000
Financial liabilities
measured at fair value
Convertible note derivative
Financial liabilities not
measured at fair value
Convertible note liability
Level 2
Level 2
-
-
-
-
3,183
3,183
7,542
7,542
-
-
-
-
3,183
3,183
7,542
7,542
Fair value hierarchy
Level 1 – the instrument has quoted prices (unadjusted) in active markets for identical assets or
liabilities;
Level 2 – the fair values are measured using inputs (other than quoted prices) that are observable for
the asset or liability either directly or indirectly; or
Level 3 – the fair values are measured using inputs for the assets or liability that are not based on
observable market data.
Cash and cash equivalents, trade and other receivables, trade creditors, other creditors and accruals
have been excluded from the above analysis as their fair values are equal to the carrying values.
The 2018 fair value of convertible note derivatives was determined using a Black-Scholes model
based on the time to expiry. The key drivers of this value included the Group’s own share price and the
foreign exchange rate.
93
63
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
OTHER DISCLOSURES
19. Subsidiaries
Significant investments in subsidiaries
The consolidated financial statements incorporate the assets, liabilities and results of the following
principal subsidiaries:
Subsidiaries of Otto Energy Limited
Country of
incorporation
Functiona
l currency
Class of
shares
Otto Energy (Tanzania) Pty Limited
Otto Energy Investments Limited
Otto Energy Philippines Inc
Otto Energy (Galoc Investment 1) Aps
Otto Energy (Galoc Investment 2) Aps
GPC Investments SA
Borealis Petroleum Pty Ltd
Borealis Alaska LLC
Otto Energy (USA) Inc
Otto Energy (Louisiana) LLC
Otto Energy (Gulf One) LLC
Otto Energy (Gulf Two) LLC
Otto Operating LLC(ii)
Otto Energy (Lightning) LLC(iii)
Otto Energy (Patrick Henry) LLC(iv)
Australia
Bermuda
Philippines
Denmark
Denmark
Switzerland
Australia
USA
USA
USA
USA
USA
USA
USA
USA
USD
USD
USD
USD
USD
USD
USD
USD
USD
USD
USD
USD
USD
USD
USD
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
(i) The proportion of ownership interest is equal to the proportion of voting power held.
(ii) Otto Operating LLC was incorporated on 9th April 2018.
(iii) Otto Energy (Lightning) LLC was incorporated on 6th February 2019.
(iv) Otto Energy (Patrick Henry) LLC was incorporated on 6th February 2019.
Ownership
Interest (i)
2019
(%)
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
2018
(%)
100
100
100
100
100
100
100
100
100
100
100
100
100
-
-
20. Interest in joint operations
a) Joint operations
The Group’s share of the assets, liabilities, revenues and expenses of joint arrangement operations
have been incorporated into the financial statements in the appropriate items of the Consolidated
Statement of Profit or Loss and Other Comprehensive Income and Consolidated Statement of Financial
Position.
94
64
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
20. Interest in joint operations (continued)
The Group’s interest in joint arrangement assets is detailed below. Oil and Gas exploration and
production is the principal activity performed across these assets.
Asset
South Marsh Island 71
Bivouac Peak (i)
VR 232 (ii)
Onshore Alaska North Slope – Western Blocks
Onshore Alaska North Slope – Central Blocks
Lightning(iii)
Mustang(iv)
Country
USA
USA
USA
USA
USA
USA
USA
2019
Group interest
50%
-
100%
22.5%
8 – 10.8%
37.5%
37.5%
2018
Group interest
50%
45%
50%
22.5%
8 – 10.8%
-
-
(i) Otto’s interest in Bivouac Peak was on an earn-in basis. As the well was not a commercial discovery
there was no transfer of ownership, therefore no JV interest held at 30 June 2019.
(ii) Otto increased it’s working interest in VR 232 to 100% in May 2019.
(iii) Otto entered into a Joint Operating Agreement with Hilcorp for a 37.5% working interest in
Lightning on 1 November 2018.
(iv) Otto entered into a Joint Operating Agreement with Hilcorp for a 37.5% working interest in Mustang
on 1 March 2019.
b) Commitments through joint operations
The aggregate of the Group’s commitments through jointly controlled assets is as follows:
Exploration expenditure commitments – not later than 1 year
Capital expenditure commitments – not later than 1 year
2019
US$’000
2018
US$’000
5,744
-
5,744
750
-
750
Operating lease arrangements
Operating lease arrangements relate to the lease of a compressor on the SM 71 F platform. The term
is for a minimum 36 months with a 30 day notice period option to discontinue the arrangement beyond
the 3 year period. These obligations are not provided for in the financial statements and the Group
doesn’t have a purchase option.
(a) Payments recognised as an expense
Net minimum lease payments recognised as an expense
(b) Minimum net future lease payments
Not longer than 1 year
Between 1 and 5 years
2019
2018
US$’000
US$’000
54
56
9
65
26
54
65
119
65
95
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
21. Share-based payments
a) Employee share option plan
The establishment of the Employee Share Option Plan was approved by shareholders at the 2013
Annual General Meeting and again at the 2016 Annual General Meeting. The Employee Share Option
Plan is designed to provide long term incentives for employees and key management personnel (KMP)
to deliver long term shareholder returns. Under the plan, participants are granted options at the
Board’s discretion and no individual has a contractual right to participate in the plan or to receive any
guaranteed benefits. Options granted under the plan carry no dividend or voting rights.
The exercise price of options is based on the weighted average price at which the Company’s shares
are traded on the Australian Securities Exchange (ASX) during the week up to and including the date of
the grant. An option may only be exercised after that option has vested and any other conditions
imposed by the Board on exercise are satisfied. Options are granted under the plan for no consideration.
There were no options on issue during the 2019 financial year.
The Company did not grant any options during the 2019 or 2018 financial years. During the year ended
30 June 2019, nil (2018: nil) options expired.
b) Performance rights
The Performance Rights Plan was approved by shareholders at the 2013 Annual General Meeting and
again at the 2016 Annual General Meeting. The Performance Rights Plan is designed to provide long
term incentives for senior managers and employees to deliver long term shareholder returns.
Participation in the plan is at the Board’s discretion and no individual has a contractual right to
participate in the plan or to receive any guaranteed benefits.
The amount of performance rights that will vest depends on vesting period and/or Otto Energy Limited’s
TSR, including share price growth, dividends, and capital returns. Once vested, the performance rights
are automatically converted to shares. If the vesting condition is not met on a measurement date (no
rights vest), the performance rights will not lapse and will continue to exist as unvested performance
rights to be retested at the next measurement date or expiry date, whichever is later. Performance
rights are granted under the plan for no consideration.
Rights granted under the plan carry no dividend or voting rights.
96
66
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
21. Share-based payments (continued)
Set out below are summaries of rights granted under the Performance Rights Plan:
2019
Grant date
Fair value
on date of
issue
Balance
at start of
the year
A$
Number
Rights
issued
during
the year
Number
Exercised/
vested
Lapsed/
expired
Balance at
end of the
year
Number
Number
Number
Expiry
date
31 Dec 2019
31 Dec 2019
29 Nov 2022
29 Nov 2022
29 Nov 2022
15 Nov 2023
15 Nov 2023
15 Nov 2023
15 Nov 2023
15 Nov 2023
15 Nov 2023
15 Nov 2023
15 Nov 2023
23 Apr 2015
23 Apr 2015
29 Nov 2017
29 Nov 2017
29 Nov 2017
21 Dec 2018
21 Dec 2018
15 Nov 2018
21 Dec 2018
15 Nov 2018
21 Dec 2018
15 Nov 2018
21 Dec 2018
Total
Weighted average exercise price – A$
0.06
0.07
0.05
0.05
0.04
0.07
0.08
0.07
0.07
0.08
0.08
0.10
0.10
1,543,334
3,096,666
4,729,000
4,729,000
4,729,000
-
-
-
-
-
-
-
-
18,827,000
0.05
-
-
-
-
-
5,919,333
2,959,667
2,396,000
5,533,667
2,396,000
5,533,667
2,396,000
5,533,666
32,668,000
0.08
Rights
issued
during
the year
Number
-
(10,000)
(4,729,000)
-
-
-
-
-
-
-
-
-
-
(4,739,000)
0.05
Exercised/
vested
Lapsed/
expired
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,543,334
3,086,666
-
4,729,000
4,729,000
5,919,333
2,959,667
2,396,000
5,533,667
2,396,000
5,533,667
2,396,000
5,533,666
46,756,000
0.07
Balance at
end of the
year
Number
Number
Number
Fair value
on date of
issue
Balance at
start of
the year
Expiry date
A$
Number
2018
Grant
date
3 Oct 2014
31 Dec 2018
3 Oct 2014
31 Dec 2018
23 Apr 2015 31 Dec 2019
23 Apr 2015 31 Dec 2019
23 Apr 2015 31 Dec 2019
14 Aug 2015 31 Dec 2017
29 Nov 2017 29 Nov 2022
29 Nov 2017 29 Nov 2022
29 Nov 2017 29 Nov 2022
Total
0.05
0.06
0.06
0.07
0.08
0.04
0.05
0.04
0.04
10,000
1,610,000
1,543,334
3,096,666
10,000
1,400,000
-
-
-
-
-
-
-
-
-
4,729,000
4,729,000
4,729,000
(10,000)
(1,610,000)
-
-
(10,000)
-
-
-
-
-
-
-
-
-
(1,400,000)
-
-
-
-
-
1,543,334
3,096,666
-
-
4,729,000
4,729,000
4,729,000
7,670,000
14,187,000
(1,630,000)
(1,400,000)
18,827,000
Weighted average exercise price – A$
0.06
0.05
0.06
0.04
0.05
67
97
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
21. Share-based payments (continued)
Set out below is the share based payment expense:
Performance rights issued in financial year 2015
Performance rights issues in financial year 2018
Performance rights issues in financial year 2019
Total
2019
US$’000
2018
US$’000
13
93
114
220
24
86
-
110
The fair value of the performance rights granted under the Plan in 2019 is estimated at the date of grant
using a single share price barrier model. The amount of performance rights that will vest depends on
the vesting period and/or Otto Energy Limited’s total shareholder return (‘TSR’), including share price
growth, dividends, and capital returns. For the rights on issue during, and at the end of the year, vesting
of the rights for directors, the CEO and other members of the executive team were based on TSR
performance only. Other employees’ rights (40,000 rights in total) were based 50% on time and 50% on
TSR. The TSR performance required for all rights on issue as at 30 June 2018 is 10% per annum (based
on 30 day VWAP) and for the rights granted during the current year ended 30 June 2019 is 15%,
compounding from the date of grant to the measurement date (based on 90 day VWAP). If the TSR
vesting condition is not met on a measurement date, no rights vest and those performance rights
continue to exist as unvested performance rights to be retested at the next measurement date or expiry
date if there are no further measurement dates
The following table lists inputs to the models used for grants made during the year ended 30 June 2019.
Total Return on Shareholders (‘TSR’) based performance rights
2019
Measurement date
Grant date
Expiry date
Share price at grant
date – A$
Expected volatility
Expected dividend
yield
Risk free rate
Fair value – A$
15 Nov 2019 15 Nov 2020 15 Nov 2021 15 Nov 2019 15 Nov 2020 15 Nov 2021
21Dec 2018 15 Nov 2018 15 Nov 2018 15 Nov 2018
15 Nov 2023 15 Nov 2023 15 Nov 2023 15 Nov 2023 15 Nov 2023 15 Nov 2023
21Dec 2018
21Dec 2018
0.035
70%
Nil
1.97%
0.035
70%
Nil
1.97%
0.035
70%
Nil
1.90%
0.050
70%
Nil
2.08%
0.050
70%
Nil
2.08%
0.050
70%
Nil
2.16%
0.0078
0.0121
0.0145
0.0216
0.0251
0.0272
The expected price volatility of 70% is based on a standard deviation of OEL’s closing share price over
a period of 3 years to grant date.
The weighted average remaining contractual life of performance rights outstanding at 30 June 2019
was 3.8 years (2018: 3.7 years).
98
68
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
21. Share-based payments (continued)
2018
Measurement date
Grant date
Expiry date
Share price at grant date – A$
Expected volatility
Expected dividend yield
Risk free rate
Fair value – A$
29 Nov 2018
29 Nov 2017
29 Nov 2022
0.04
20%
Nil
2.09%
0.0260
29 Nov 2019 29 Nov 2020
29 Nov 2017 29 Nov 2017
29 Nov 2022 29 Nov 2022
0.04
20%
Nil
2.09%
0.0200
0.04
20%
Nil
2.09%
0.0150
The expected price volatility of 20% was based on the 30 day volume weighted average price (VWAP)
which is the applicable volatility measure for the rights given vesting is determined by a 30 day VWAP.
The expected price volatility is based on the historic volatility (based on the remaining life of the rights),
adjusted for any expected changes to future volatility due to publicly available information.
For the year ended 30 June 2019, the Group recognised share-based payments expense of $219,923 in
the Consolidated Statement of Profit or Loss and Other Comprehensive Income (2018: $109,556).
Recognition and measurement
The Group has provided benefits to its employees and key management personnel in the form of share-
based payments, whereby services were rendered partly or wholly in exchange for shares or rights over
shares. The Board has also approved the grant of options or performance rights as incentives to attract
employees and to maintain their long-term commitment to the Company. These benefits were awarded
at the discretion of the Board or following approval by shareholders (equity-settled transactions).
The costs of these equity-settled transactions are measured by reference to the fair value of the equity
instruments at the date on which they are granted. The fair value of performance rights granted in
2019 is determined using a single share price barrier model.
The costs of these equity-settled transactions is recognised, together with a corresponding increase in
equity, over the period in which the performance and/or service conditions are fulfilled (the vesting
period), ending on the date on which the relevant employees become fully entitled to the equity
instrument (vesting date).
At each subsequent reporting date until vesting, the cumulative charge to the Consolidated Statement
of Profit or Loss and Other Comprehensive Income is the product of (i) the fair value at grant date of the
award; (ii) the current best estimate of the number of equity instruments that will vest, taking into
account such factors as the likelihood of employee turnover during the vesting period and the likelihood
of any non-market performance conditions being met and (iii) the expired portion of the vesting period.
The charge to the Consolidated Statement of Profit or Loss and Other Comprehensive Income for the
period is the cumulative amount as calculated above less the amounts already charged in previous
periods. There is a corresponding credit to equity.
Until an equity instrument has vested, any amounts recorded are contingent and will be adjusted if
more or fewer equity instruments vest than were originally anticipated to do so. Any equity instrument
subject to a market condition is considered to vest irrespective of whether or not that market condition
is fulfilled, provided that all other conditions are satisfied.
99
69
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
For the year ended 30 June 2019
21. Share-based payments (continued)
21. Share-based payments (continued)
If the terms of an equity-settled award are modified, as a minimum, an expense is recognised as if the
If the terms of an equity-settled award are modified, as a minimum, an expense is recognised as if the
terms had not been modified. An additional expense is recognised for any modification that increases
terms had not been modified. An additional expense is recognised for any modification that increases
the total fair value of the share-based payment arrangement, or is otherwise beneficial to the recipient
the total fair value of the share-based payment arrangement, or is otherwise beneficial to the recipient
of the award, as measured at the date of modification.
of the award, as measured at the date of modification.
If an equity-settled transaction is cancelled (other than a grant cancelled by forfeiture when the vesting
If an equity-settled transaction is cancelled (other than a grant cancelled by forfeiture when the vesting
conditions are not satisfied), it is treated as if it had vested on the date of cancellation, and any expense
conditions are not satisfied), it is treated as if it had vested on the date of cancellation, and any expense
not yet recognised for the award is recognised immediately. However, if a new equity instrument is
not yet recognised for the award is recognised immediately. However, if a new equity instrument is
substituted for the cancelled award and designated as a replacement award on the date that it is
substituted for the cancelled award and designated as a replacement award on the date that it is
granted, the cancelled and new equity instrument are treated as if they were a modification of the
granted, the cancelled and new equity instrument are treated as if they were a modification of the
original award, as described in the preceding paragraph.
original award, as described in the preceding paragraph.
Key estimates and judgements
Key estimates and judgements
The Group measures the cost of equity-settled transactions with employees by reference to the fair
The Group measures the cost of equity-settled transactions with employees by reference to the fair
value of the equity instruments at the date at which they are granted. The fair value is determined by
value of the equity instruments at the date at which they are granted. The fair value is determined by
using a single share price barrier model taking into account the terms and conditions upon which the
using a single share price barrier model taking into account the terms and conditions upon which the
instruments were granted. The accounting estimates and assumptions relating to equity-settled share-
instruments were granted. The accounting estimates and assumptions relating to equity-settled share-
based payments would have no impact on the carrying amounts of assets and liabilities within the next
based payments would have no impact on the carrying amounts of assets and liabilities within the next
annual reporting period but may impact profit or loss and equity.
annual reporting period but may impact profit or loss and equity.
22. Related parties
22. Related parties
Key management personnel compensation
Key management personnel compensation
Short-term employee benefits
Short-term employee benefits
Post-employment benefits
Post-employment benefits
Other benefits
Other benefits
Termination benefits(i)
Termination benefits(i)
Share-based payments
Share-based payments
Total USD
Total USD
Total AUD equivalent
Total AUD equivalent
2019
2019
US$
US$
2018
2018
US$
US$
2,041,107
2,041,107
83,028
83,028
356,632
356,632
61,676
61,676
200,687
200,687
2,743,130
2,743,130
3,840,540
3,840,540
1,125,219
1,125,219
70,914
70,914
3,264
3,264
(17,553)
(17,553)
95,100
95,100
1,276,944
1,276,944
1,647,979
1,647,979
Detailed remuneration disclosures are provided in the remuneration report on pages 50 to 62.
Detailed remuneration disclosures are provided in the remuneration report on pages 50 to 62.
Transactions with key management personnel
Transactions with key management personnel
On 2 August 2017 the Company issued $8.2 million secured convertible notes (the ‘Notes’). $0.2 million
On 2 August 2017 the Company issued $8.2 million secured convertible notes (the ‘Notes’). $0.2 million
of the Notes were issued to Mr John Jetter, Otto’s Chairman. Refer to note 14 for more information on
of the Notes were issued to Mr John Jetter, Otto’s Chairman. Refer to note 14 for more information on
the Notes.
the Notes.
Under the terms of the Notes, Otto issued a redemption notice to the Noteholders on 26 March 2019 for
Under the terms of the Notes, Otto issued a redemption notice to the Noteholders on 26 March 2019 for
the full 8.2 million convertible notes. Mr Jetter elected to convert 100,000 of the notes into ordinary
the full 8.2 million convertible notes. Mr Jetter elected to convert 100,000 of the notes into ordinary
shares with the balance redeemed on 30 April 2019.
shares with the balance redeemed on 30 April 2019.
On 30 April 2019, the 100,000 Notes were converted and 2,599,211 ordinary shares were issued to Mr
On 30 April 2019, the 100,000 Notes were converted and 2,599,211 ordinary shares were issued to Mr
Jetter at a conversion price of AUD0.05418 (USD conversion rate 0.7101). As at 30 June 2019 there was
Jetter at a conversion price of AUD0.05418 (USD conversion rate 0.7101). As at 30 June 2019 there was
a success fee payable to the noteholders of $187,000 of which $4,562 was payable to Mr Jetter. This
a success fee payable to the noteholders of $187,000 of which $4,562 was payable to Mr Jetter. This
was fully paid by the due date of 30 July 2019. As at 30 June 2019 there was no principle outstanding
was fully paid by the due date of 30 July 2019. As at 30 June 2019 there was no principle outstanding
and no interest payable under the terms of the Notes.
and no interest payable under the terms of the Notes.
100
70
70
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
22. Related parties (continued)
Pathfinder Energy Pty Ltd, a company of which Mr Ian Boserio is a director ceased the sublease of
premises with Otto Energy Ltd at 32 Delhi St, West Perth on 31 May 2019. The sublease was on a month
to month basis at $1,000 per month until 30 November 2018 and $1,383.25 thereafter. There were no
amounts outstanding at balance date.
During the period the Company engaged the services of US consulting firm Amvest Capital. Amvest
capital is a related party by virtue of non-executive director Ian Macliver’s son being a partner in the
firm. Ian Macliver has no financial, ownership or other interest in Amvest Capital beyond his
relationship with his son. Ian Macliver was not involved in the negotiation with, or appointment of,
Amvest Capital as an advisor to Otto. The fees paid to Amvest Capital during the period for US investor
relations consulting services was $32,768.
23. Auditor’s remuneration
During the year the following fees were paid or payable for services provided by the auditor of the parent
entity, its related practices and non-related audit firms:
2019
US$
2018
US$
BDO Australia
Audit and review of financial statements
Tax compliance services
Tax consulting and tax advice
Total remuneration of BDO Australia
Network firms of BDO Australia
Audit and review of financial statements
Tax compliance services
International tax consulting
Total remuneration of network firms of BDO Australia
Non-BDO
Audit and review of financial statements
Tax compliance services
Total remuneration of non-BDO audit firms
Total auditors’ remuneration
34,450
13,058
1,410
48,918
24,196
11,067
968
36,231
1,160
-
1,160
86,309
34,419
3,751
1,056
39,226
7,681
14,001
12,265
33,947
6,021
1,764
7,785
80,958
It is the Group’s policy to employ BDO on assignments additional to their statutory audit duties where
BDO’s expertise and experience with the Group are important. These assignments are principally tax
advice where BDO is awarded assignments on a competitive basis. It is the Group’s policy to seek
competitive tenders for all major consulting projects.
101
71
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
24. Contingent liabilities
There are no contingent liabilities at balance date.
25. Commitments
a) Exploration expenditure commitments
Exploration expenditure contracted for at the reporting date but not recognised as liabilities are as
follows:
Not later than 1 year
Later than one year but not later than five years
2019
US$’000
2018
US$’000
5,234
510
5,744
750
-
750
Under the Joint Exploration and Development Agreement with Hilcorp dated 31 July 2018, in the event
of a default of its obligations, Otto Energy (USA) Inc is required to pay Hilcorp liquidated damages (LDs)
of $1,000,000 for each prospect that is not an earned prospect. As at 30 June 2019, the potential
contractual LD’s are $4,000,000, representing 4 undrilled wells.
b) Capital expenditure commitments
There was no capital expenditure committed to at reporting date that was not recognised a liability in
the financial statements.
c) Lease commitments
The Group has entered into non-cancellable operating leases for corporate offices, a photocopier and
a compressor (in JV with Byron Energy Ltd for the SM 71 Development). The leases have varying terms,
including escalation and renewal rights.
Commitments for minimum lease payments in relation to non‑cancellable operating leases are
payable as follows:
Not later than 1 year
Later than 1 year but not later than 5 years
2019
US$’000
2018
US$’000
203
195
398
170
389
559
Recognition and measurement
Leases in which a significant portion of the risks and rewards of ownership are not transferred to the
Group as lessee are classified as operating leases. Payments made under operating leases (net of any
incentives received from the lessor) are charged to profit or loss on a straight-line basis over the period
of the lease.
Commitments are disclosed net of the amount of GST recoverable from, or payable to, the tax authority.
Lease rentals due on the Group’s exploration leases can be cancelled and the leases relinquished.
Therefore the lease rentals are not non-cancellable and hence are not included in the above.
102
72
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
26. Events after the reporting period
No matters or circumstances have arisen since 30 June 2019 that have significantly affected, or may
significantly affect the Group’s operations, the results of those operations, or the Group’s state of affairs
in future financial years apart from those listed below:
• GC 21 – Bulleit Well
On 8 August 2019 Otto announced that the GC 21 “Bulleit” well, operated by Talos Energy, Inc
(“Talos”) (NYSE: TALO) had been successfully drilled to Total Depth. The well drilled through the
deeper exploration target, the MP sands, after intersecting oil pay in the shallower DTR-10 sand
package as announced to the ASX on 13 June 2019. The well intersected the following discovered
intervals:
- DTR-10 interval –net 140 feet of TVD oil pay encountered; and
- MP interval – approximately net 110 feet of TVD oil pay expected to be delivered in high quality
reservoir consistent with analogue wells in the GC18 field.
Following the discovery in the DTR-10 sands, attempt to drill to the deeper objective MP sands were
delayed due to poor hole conditions and compromised drilling operations requiring sidetracking. In
addition, the passing of Hurricane Barry required the rig to disconnect to ensure safe operations.
As a result of these operations, the cost of drilling the GC21 “Bulleit” well exceeded the pre-drill
estimates of US$9.0m net to Otto. The effect of these events is expected to increase Otto’s financial
exposure to the Bulleit well by approximately US$6.5 to US$7.5m net to Otto.
The GC 21 development plan is being progressed by the Operator to complete the discovery well in
the first half of 2020. The Operator will complete the well as a production well and then tie it back
to the Talos-owned and operated Green Canyon 18 (GC 18A) facility approximately 10 miles (~16 km)
west of the “Bulleit” well. The development will involve the use of a subsea completion that is
common for projects of this nature and water depth in the Gulf of Mexico. The joint venture will
undertake a review of the operator’s plan of development in the coming month with formal
commitment to the development expected shortly thereafter.
Subject to the commitment to development outlined above, Otto will report maiden reserves from
the GC21 discovery incorporating the development plans.
The Company is working on a finance facility to fund the development.
• Mustang
On 23 July 2019 Otto advised that the initial exploration well, Thunder Gulch #1, within the Mustang
prospect in Chambers County Texas, has reached final total depth of 18,164 ft MD (18,001 ft TVD).
Petrophysical evaluation of wireline logging data together with mudlog hydrocarbon shows seen
whilst drilling indicated the presence of a total net hydrocarbon filled sand interval of approximately
57 feet TVT (True Vertical Thickness). This petrophysical evaluation was undertaken using historical
parameters for production performance in the play trend. The Operator, Hilcorp Energy, then ran
production casing and completed the well.
The operator has sourced equipment required for the testing of the deep, high pressure Mustang
discovery. With reservoir pressures at the discovery location of over 15,000 psi, specialised high-
pressure equipment is required that is not commonly used. The initial testing will involve the
perforation of various discovery intervals in order to understand reservoir deliverability and the
design of a completion program to optimise ultimate production.
Once the testing phase of the discovery is completed, the joint venture would then plan for the
installation of surface production equipment and the connection into a nearby sales pipeline to
enable production to commence. This is expected to occur during the fourth quarter of 2019, subject
to the outcome of the impending test program.
103
73
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
For the year ended 30 June 2019
26. Events after the reporting period (continued)
26. Events after the reporting period (continued)
Through participation in the drilling of the Thunder Gulch #1 exploration well, Otto has earned a
37.5% working interest in the leases covering the entire prospect.
Through participation in the drilling of the Thunder Gulch #1 exploration well, Otto has earned a
37.5% working interest in the leases covering the entire prospect.
• SM 71
• SM 71
Otto announced on 22 August 2019 that Byron Energy, the operator of SM 71, had advised that it had
completed the interpretation of reprocessed seismic data, resulting in the identification of two areas
Otto announced on 22 August 2019 that Byron Energy, the operator of SM 71, had advised that it had
in the D5 Sand reservoir which it believes will not be drained efficiently by the currently producing
completed the interpretation of reprocessed seismic data, resulting in the identification of two areas
SM 71F1 and SM 71 F3 wells. To effectively drain these two areas, the Operator has estimated that
in the D5 Sand reservoir which it believes will not be drained efficiently by the currently producing
two additional wells will be needed to fully develop the D5 Sand reservoir at SM 71.
SM 71F1 and SM 71 F3 wells. To effectively drain these two areas, the Operator has estimated that
two additional wells will be needed to fully develop the D5 Sand reservoir at SM 71.
The first of these proposed wells, the SM 71 F4, would test a D5 Sand reservoir anomaly that is
outboard of the main D5 field, (see attached illustration). If successful, this would extend and prove
The first of these proposed wells, the SM 71 F4, would test a D5 Sand reservoir anomaly that is
up additional reserves in the D5 reservoir. The second proposed well, the SM 71 F5, will test an
outboard of the main D5 field, (see attached illustration). If successful, this would extend and prove
area that the Operator believes will be poorly drained, if at all, by the F3.
up additional reserves in the D5 reservoir. The second proposed well, the SM 71 F5, will test an
area that the Operator believes will be poorly drained, if at all, by the F3.
The Operator estimates that after the SM71 F4 and SM71 F5 wells are completed, assuming success,
the D5 reservoir at SM 71 will be fully developed except for an attic well required in three- or four-
The Operator estimates that after the SM71 F4 and SM71 F5 wells are completed, assuming success,
years’ time.
the D5 reservoir at SM 71 will be fully developed except for an attic well required in three- or four-
years’ time.
Otto has the right to participate in the wells at its working interest of 50%. Otto is currently
considering all materials provided by the operator and evaluating the proposed wells using its own
Otto has the right to participate in the wells at its working interest of 50%. Otto is currently
recently reprocessed 3D data over the area. Operator has advised that it is in final stages of
considering all materials provided by the operator and evaluating the proposed wells using its own
negotiating a rig contract for this drilling program and it is expected to be available and on location
recently reprocessed 3D data over the area. Operator has advised that it is in final stages of
in early October, pending final permit approvals.
negotiating a rig contract for this drilling program and it is expected to be available and on location
in early October, pending final permit approvals.
Currently the field is producing approximately 3,100 bopd and 3.3 mmcfgpd, on a gross basis after
shrinkage at the sales meter.
Currently the field is producing approximately 3,100 bopd and 3.3 mmcfgpd, on a gross basis after
shrinkage at the sales meter.
• Board and Executive Changes
• Board and Executive Changes
On 11 September 2019 the Company announced that its Chairperson, Mr John Jetter, had confirmed
to the Board, and the Board of Otto had agreed, that he will step down from the role of Chairperson
On 11 September 2019 the Company announced that its Chairperson, Mr John Jetter, had confirmed
at the coming Annual General Meeting of shareholders on 21 November 2019. Mr Jetter will remain
to the Board, and the Board of Otto had agreed, that he will step down from the role of Chairperson
as a non-executive director and serve on the current Board Committees of which he is a member in
at the coming Annual General Meeting of shareholders on 21 November 2019. Mr Jetter will remain
order to oversee the seamless transition of the role of Chairperson and the successful delivery of
as a non-executive director and serve on the current Board Committees of which he is a member in
Otto’s Board renewal which has commenced under his guidance. Mr Jetter will not seek re-election
order to oversee the seamless transition of the role of Chairperson and the successful delivery of
at the Annual General Meeting in 2020.
Otto’s Board renewal which has commenced under his guidance. Mr Jetter will not seek re-election
at the Annual General Meeting in 2020.
Mr Ian Boserio has been nominated by the Board as Chairperson Elect to assume the role vacated
at the 2019 Annual General Meeting by Mr Jetter. In the meantime Mr Boserio will assume the role
Mr Ian Boserio has been nominated by the Board as Chairperson Elect to assume the role vacated
of Deputy Chair.
at the 2019 Annual General Meeting by Mr Jetter. In the meantime Mr Boserio will assume the role
of Deputy Chair.
In addition, Mr Ian Macliver, has advised the Board that he also will retire upon the appointment of
a suitably qualified, independent non-executive director to assume the roles he currently occupies.
In addition, Mr Ian Macliver, has advised the Board that he also will retire upon the appointment of
A process has commenced to identify a candidate for this role and Mr Macliver has advised that he
a suitably qualified, independent non-executive director to assume the roles he currently occupies.
will retire from the Board of Otto Energy at the time his replacement is appointed, or at the latest
A process has commenced to identify a candidate for this role and Mr Macliver has advised that he
by 30 June 2020.
will retire from the Board of Otto Energy at the time his replacement is appointed, or at the latest
by 30 June 2020.
The Board renewal process will be an ongoing focus of the Board to ensure that its composition
reflects the nature of the business as it evolves from being primarily focused on exploration
The Board renewal process will be an ongoing focus of the Board to ensure that its composition
activities towards development and production activities.
reflects the nature of the business as it evolves from being primarily focused on exploration
activities towards development and production activities.
On 23 August 2019 the Company advised that had accepted the resignation of its Chief Financial
Officer and Company Secretary, Mr. David Rich. Mr. Rich joined Otto in January 2017 and has been
On 23 August 2019 the Company advised that had accepted the resignation of its Chief Financial
a highly valued member of the management team in supporting the successful development of the
Officer and Company Secretary, Mr. David Rich. Mr. Rich joined Otto in January 2017 and has been
US Gulf of Mexico business. Mr Rich will continue in his current roles until 1 November 2019. The
a highly valued member of the management team in supporting the successful development of the
Board thanked Mr. Rich for his contribution to the business over the last two and a half years.
US Gulf of Mexico business. Mr Rich will continue in his current roles until 1 November 2019. The
Board thanked Mr. Rich for his contribution to the business over the last two and a half years.
104
74
74
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
26. Events after the reporting period (continued)
The Board has commenced a process to appoint a new Chief Financial Officer in Houston as part of
the ongoing commitment it made in April 2018 to supporting the growth of the US Gulf of Mexico
business. This will involve the transition of the majority of the financial and accounting support
functions from Perth to Houston.
• Reserves Statement
On 19 September 2019 the Company released its statement of reserves and prospective resources
as at 30 June 2019. The statement of reserves included SM 71 and the maiden statement of reserves
for Lightning. The reserves for SM 71 and Lightning were compiled by independent consultants
Collarini and Associates and Ryder Scott Company respectively. The summary statement of
reserves and prospective resources at 30 June 2019 is set out below. The individual statements for
SM 71 and Lightning are included in the Production and Development section above. Full details
including the reconciliations and notes on the statements are included in the ASX release of 19
September 2019.
Total
Gross (100%)
Otto Net
Gas
Oil (Mbbl)
3,219
Gas
(MMscf) MBoe
(MMscf) MBoe
Oil
(Mbbl)
12,599 5,318 1,271 3,910 1,923
1,118 452
682 3,765 1,310 265
3,292 1,295
11,117 3,779 746
2,282 8,320 3,670
10,407
27,481
19,823 9,398 2,417 6,101 3,434
14,421
47,304
7,103
4,699
19,806
10,072 3,049
34,468 9,409 1,371
1,927
5,828
6,094
11,922
3,664
15,586
81,772
29,214
6,070
24,492
10,152
67,309
89,875
82,289
Proved Producing
Proved Behind Pipe
Proved Undeveloped
Proven (1P)
Probable
Proven Plus Probable (2P)
Possible
Proven Plus Probable Plus
Possible (3P)
Total Prospective Resource
(best estimate, unrisked)
• Hedging
On 20 September 2019 Otto acquired $55.00 per barrel put options over 34,500 barrels of oil from
October 2019 to January 2020 at a premium of $1.83 per barrel in accordance with its commodity
price risk management policy.
105
75
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
27. Parent entity disclosures
As at, and throughout the financial year ended 30 June 2019, the parent company of the Group was Otto
Energy Limited.
Summarised statement of profit or loss and other
comprehensive income
Loss for the year after tax
Total comprehensive loss for the year
Summarised statement of financial position
Current assets
Non-current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Net assets
Total equity of the parent entity comprises:
Share capital
Share based payments reserves
Foreign currency translation reserve
Accumulated losses
Total equity
Parent entity
2019
US$’000
2018
US$’000
(40,071)
(40,071)
(5,486)
(5,486)
4,536
33,128
37,664
469
17
486
1,936
51,185
53,121
12,471
6
12,477
37,178
40,644
125,041
9,878
118
(97,859)
37,178
90,704
9,658
118
(59,836)
40,644
Guarantees entered into by the parent in relation to the debts of its subsidiaries
Parent company guarantees are extended on a case by case basis. Otto Energy Limited has provided
a number of performance guarantees for subsidiaries under the terms of joint operations operating
agreements, participation agreements and agreements with Governments pertaining to oil & gas
exploration.
Otto Energy Limited has a guarantee in place to Byron Energy Inc, for the performance of Otto Energy
(Louisiana) LLC’s obligations in relation to SM 71.
Contingent liabilities
The parent entity had no contingent liabilities as at 30 June 2019 and 30 June 2018 beyond those listed
in Note 24
106
76
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
27. Parent entity disclosures (continued)
Commitments
The parent entity had no capital commitments as at 30 June 2019 and 30 June 2018. The parent entity
has an operating lease on office premises expiring 30 November 2019.
Not later than 1 year
Later than 1 year but not later than 5 years
Significant accounting policies
2019
US$’000
2018
US$’000
11
-
11
3
-
3
The accounting policies of the parent entity are consistent with those of the Group, except for the
following: Investments in subsidiaries are accounted for at cost, less any impairment in the parent
entity.
28. New accounting standards and interpretations
New, revised or amended Accounting Standards and Interpretations adopted by the Group
The Group has applied the following standards for the first time for their interim reporting period
commencing 1 July 2018.
• AASB 9 Financial Instruments (“AASB 9”), and
• AASB 15 Revenue from Contracts with Customers (“AASB 15”).
The Group had to change its accounting policies and make certain adjustments following the adoption
of AASB 15, however adoption did not give rise to any material transitional or reporting date
adjustments.
The Group had to change its accounting policies following the adoption of AASB 9, however adoption did
not give rise to any material transitional or reporting date adjustments.
AASB 15
The Group has adopted AASB 15 with a date of initial application of 1 July 2018. As a result of adoption
of AASB 15, the Group has changed its accounting policy for revenue recognition as detailed below:
Revenue is measured based on the consideration specified in a contract with a customer and excludes
amounts collected on behalf of third parties. The Group recognises revenue when it transfers control
over a product or service to a customer.
Impact of Adoption of AASB 15
The Group has determined that the application of AASB 15’s requirements at transition 1 July 2018 did
not result in any adjustment.
AASB 9
The Group has adopted AASB 9 with a date of initial application of 1 July 2018 and has elected not to
restate its comparatives. As a result, the Group has changed its accounting policy for financial
instruments as detailed below.
107
77
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
For the year ended 30 June 2019
28. New accounting standards and interpretations (continued)
28. New accounting standards and interpretations (continued)
Recognition and derecognition
Recognition and derecognition
Financial assets and financial liabilities are recognised when the Group becomes a party to the
contractual provisions of the financial instrument.
Financial assets and financial liabilities are recognised when the Group becomes a party to the
contractual provisions of the financial instrument.
Financial assets are derecognised when the contractual rights to the cash flows from the financial asset
expire, or when the financial asset and substantially all the risks and rewards are transferred. A
Financial assets are derecognised when the contractual rights to the cash flows from the financial asset
financial liability is derecognised when it is extinguished, discharged, cancelled or expires.
expire, or when the financial asset and substantially all the risks and rewards are transferred. A
financial liability is derecognised when it is extinguished, discharged, cancelled or expires.
Classification and initial measurement of financial assets
Financial assets are classified according to their business model and the characteristics of their
Classification and initial measurement of financial assets
contractual cash flows and are initially measured at fair value adjusted for transaction costs (where
Financial assets are classified according to their business model and the characteristics of their
applicable).
contractual cash flows and are initially measured at fair value adjusted for transaction costs (where
applicable).
Subsequent measurement of financial assets
For the purpose of subsequent measurement, financial assets, other than those designated and
Subsequent measurement of financial assets
effective as hedging instruments, are classified into the following four categories:
For the purpose of subsequent measurement, financial assets, other than those designated and
effective as hedging instruments, are classified into the following four categories:
• Financial assets at amortised cost
• Financial assets at fair value through profit or loss (“FVTPL”)
• Financial assets at amortised cost
• Debt instruments at fair value through other comprehensive income (“FVTOCI”)
• Financial assets at fair value through profit or loss (“FVTPL”)
• Equity instruments at FVTOCI
• Debt instruments at fair value through other comprehensive income (“FVTOCI”)
• Equity instruments at FVTOCI
All income and expenses relating to financial assets that are recognised in profit or loss are presented
within finance costs, finance income or other financial items, except for impairment of trade receivables
All income and expenses relating to financial assets that are recognised in profit or loss are presented
which is presented within other expenses.
within finance costs, finance income or other financial items, except for impairment of trade receivables
which is presented within other expenses.
Financial assets at amortised cost
Financial assets with contractual cash flows representing solely payments of principal and interest and
Financial assets at amortised cost
held within a business model of ‘hold to collect’ contractual cash flows are accounted for at amortised
Financial assets with contractual cash flows representing solely payments of principal and interest and
cost using the effective interest method. The Group’s trade and most other receivables fall into this
held within a business model of ‘hold to collect’ contractual cash flows are accounted for at amortised
category of financial instruments.
cost using the effective interest method. The Group’s trade and most other receivables fall into this
category of financial instruments.
Impairment
The Group assesses on a forward looking basis the expected credit losses associated with its debt
Impairment
instruments carried at amortised cost and FVOCI.
The Group assesses on a forward looking basis the expected credit losses associated with its debt
The impairment methodology applied depends on whether there has been a significant increase in
instruments carried at amortised cost and FVOCI.
credit risk.
The impairment methodology applied depends on whether there has been a significant increase in
credit risk.
The Group makes use of a simplified approach in accounting for trade and other receivables as well as
contract assets and records the loss allowance at the amount equal to the expected lifetime credit
The Group makes use of a simplified approach in accounting for trade and other receivables as well as
losses. In using this practical expedient, the Group uses its historical experience, external indicators
contract assets and records the loss allowance at the amount equal to the expected lifetime credit
and forward looking information to calculate the expected credit losses using a provision matrix.
losses. In using this practical expedient, the Group uses its historical experience, external indicators
and forward looking information to calculate the expected credit losses using a provision matrix.
The Group considers a financial asset in default when contractual payment are 90 days past due.
However, in certain cases, the Group may also consider a financial asset to be in default when internal
The Group considers a financial asset in default when contractual payment are 90 days past due.
or external information indicates that the Group is unlikely to receive the outstanding contractual
However, in certain cases, the Group may also consider a financial asset to be in default when internal
amounts in full before taking into account any credit enhancements held by the Group.
or external information indicates that the Group is unlikely to receive the outstanding contractual
amounts in full before taking into account any credit enhancements held by the Group.
108
78
78
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2019
28. New accounting standards and interpretations (continued)
Impact of the adoption of AASB 9
The Group has determined that the application of AASB 9’s requirements at transition 1 July 2018 did
not result in a material adjustment.
Impact of standards issued but not yet applied by the entity
AASB 16 Leases is effective for the reporting period commencing 1 July 2019. It will result in almost all
leases being recognised on the balance sheet, as the distinction between operating and finance leases
is removed. Under the new standard, an asset (the right to use the leased item) and a financial liability
to pay rentals are recognised. The only exceptions are short-term and low-value leases.
The Group is still in the process of fully assessing the impact on the Group’s financial results and
position when it is first adopted for the year ending 30 June 2020.
109
79
DIRECTORS’ DECLARATION
DIRECTORS’ DECLARATION
For the year ended 30 June 2019
For the year ended 30 June 2019
In accordance with a resolution of the Directors of Otto Energy Limited, I state that:
1.
In the opinion of the Directors:
a.
b.
c.
d.
the financial statements, notes and the additional disclosures included in the audited 2019
Remuneration Report, comply with Australian Accounting Standards (including Australian
Accounting Interpretations) and the Corporations Act 2001;
the financial statements and notes give a true and fair view of the financial position of the Group
as at 30 June 2019 and of its performance for the year ended on that date;
the financial statements and notes comply with International Financial Reporting Standards as
disclosed in the ‘Basis of Preparation’ section within the notes to the 2019 Financial Report;
and
there are reasonable grounds to believe that the Company will be able to pay its debts as and
when they become due and payable.
2. This declaration has been made after receiving the declarations required to be made to the
Directors in accordance with section 295A of the Corporations Act 2001 for the year ended 30 June
2019.
On behalf of the Board
Mr I Macliver
Director
25 September 2019
110
80
INDEPENDENT AUDITOR’S REPORT
For the year ended 30 June 2019
Tel: +61 8 6382 4600
Fax: +61 8 6382 4601
www.bdo.com.au
38 Station Street
Subiaco, WA 6008
PO Box 700 West Perth WA 6872
Australia
38 Station Street
Subiaco, WA 6008
PO Box 700 West Perth WA 6872
Australia
Tel: +61 8 6382 4600
Fax: +61 8 6382 4601
www.bdo.com.au
INDEPENDENT AUDITOR'S REPORT
INDEPENDENT AUDITOR'S REPORT
To the members of Otto Energy Limited
To the members of Otto Energy Limited
Report on the Audit of the Financial Report
Opinion
Report on the Audit of the Financial Report
We have audited the financial report of Otto Energy Limited (the Company) and its subsidiaries (the
Group), which comprises the consolidated statement of financial position as at 30 June 2019, the
Opinion
consolidated statement of profit or loss and other comprehensive income, the consolidated statement
We have audited the financial report of Otto Energy Limited (the Company) and its subsidiaries (the
of changes in equity and the consolidated statement of cash flows for the year then ended, and notes
Group), which comprises the consolidated statement of financial position as at 30 June 2019, the
to the financial report, including a summary of significant accounting policies and the directors’
consolidated statement of profit or loss and other comprehensive income, the consolidated statement
declaration.
of changes in equity and the consolidated statement of cash flows for the year then ended, and notes
In our opinion the accompanying financial report of the Group, is in accordance with the Corporations
to the financial report, including a summary of significant accounting policies and the directors’
Act 2001, including:
declaration.
Giving a true and fair view of the Group’s financial position as at 30 June 2019 and of its
(i)
In our opinion the accompanying financial report of the Group, is in accordance with the Corporations
financial performance for the year ended on that date; and
Act 2001, including:
(ii)
(i)
Complying with Australian Accounting Standards and the Corporations Regulations 2001.
Giving a true and fair view of the Group’s financial position as at 30 June 2019 and of its
financial performance for the year ended on that date; and
Basis for opinion
Complying with Australian Accounting Standards and the Corporations Regulations 2001.
(ii)
We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under
those standards are further described in the Auditor’s responsibilities for the audit of the Financial
Basis for opinion
Report section of our report. We are independent of the Group in accordance with the Corporations
We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under
Act 2001 and the ethical requirements of the Accounting Professional and Ethical Standards Board’s
those standards are further described in the Auditor’s responsibilities for the audit of the Financial
APES 110 Code of Ethics for Professional Accountants (the Code) that are relevant to our audit of the
Report section of our report. We are independent of the Group in accordance with the Corporations
financial report in Australia. We have also fulfilled our other ethical responsibilities in accordance
Act 2001 and the ethical requirements of the Accounting Professional and Ethical Standards Board’s
with the Code.
APES 110 Code of Ethics for Professional Accountants (the Code) that are relevant to our audit of the
We confirm that the independence declaration required by the Corporations Act 2001, which has been
financial report in Australia. We have also fulfilled our other ethical responsibilities in accordance
given to the directors of the Company, would be in the same terms if given to the directors as at the
with the Code.
time of this auditor’s report.
We confirm that the independence declaration required by the Corporations Act 2001, which has been
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis
given to the directors of the Company, would be in the same terms if given to the directors as at the
for our opinion.
time of this auditor’s report.
Key audit matters
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis
for our opinion.
Key audit matters are those matters that, in our professional judgement, were of most significance in
our audit of the financial report of the current period. These matters were addressed in the context of
Key audit matters
our audit of the financial report as a whole, and in forming our opinion thereon, and we do not provide
Key audit matters are those matters that, in our professional judgement, were of most significance in
a separate opinion on these matters.
our audit of the financial report of the current period. These matters were addressed in the context of
our audit of the financial report as a whole, and in forming our opinion thereon, and we do not provide
111
a separate opinion on these matters.
BDO Audit (WA) Pty Ltd ABN 79 112 284 787 is a member of a national association of independent entities which are all members of BDO Australia Ltd ABN 77 050 110 275,
an Australian company limited by guarantee. BDO Audit (WA) Pty Ltd and BDO Australia Ltd are members of BDO International Ltd, a UK company limited by guarantee, and
form part of the international BDO network of independent member firms. Liability limited by a scheme approved under Professional Standards Legislation.
BDO Audit (WA) Pty Ltd ABN 79 112 284 787 is a member of a national association of independent entities which are all members of BDO Australia Ltd ABN 77 050 110 275,
an Australian company limited by guarantee. BDO Audit (WA) Pty Ltd and BDO Australia Ltd are members of BDO International Ltd, a UK company limited by guarantee, and
form part of the international BDO network of independent member firms. Liability limited by a scheme approved under Professional Standards Legislation.
81
81
INDEPENDENT AUDITOR’S REPORT
For the year ended 30 June 2019
Carrying Value of Oil and Gas Properties
Key audit matter
How the matter was addressed in our audit
Carrying Value of Oil and Gas Properties
The Group’s carrying value of oil and gas properties as
Key audit matter
disclosed in note 12 is a key audit matter as the
Our work included but not limited to the following
How the matter was addressed in our audit
procedures:
assessment of carrying value requires management to
The Group’s carrying value of oil and gas properties as
exercise judgement in assessing whether facts and
disclosed in note 12 is a key audit matter as the
circumstances exists to suggest that the carrying
assessment of carrying value requires management to
amount of this asset may exceed its recoverable
exercise judgement in assessing whether facts and
amount.
circumstances exists to suggest that the carrying
amount of this asset may exceed its recoverable
amount.
Obtaining and reviewing available reserve report
Our work included but not limited to the following
•
procedures:
data from the management’s experts to
•
•
•
•
•
•
•
•
•
determine whether they indicate a significant
Obtaining and reviewing available reserve report
change that would impact the value of the asset.
data from the management’s experts to
This included assessing the competency and
determine whether they indicate a significant
objectivity of management’s experts;
change that would impact the value of the asset.
Benchmarking and analysing management’s oil
This included assessing the competency and
objectivity of management’s experts;
and gas price assumptions against external
Benchmarking and analysing management’s oil
market data, to determine whether they indicate
and gas price assumptions against external
a significant change that would impact the value
market data, to determine whether they indicate
of the asset;
a significant change that would impact the value
Reviewing the Director’s minutes and ASX
of the asset;
announcements for evidence of consistency of
Reviewing the Director’s minutes and ASX
information with management’s assessment of
announcements for evidence of consistency of
the carrying value;
information with management’s assessment of
Considering whether there were any other facts
the carrying value;
and circumstances that existed to indicate
Considering whether there were any other facts
impairment testing was required; and
and circumstances that existed to indicate
Assessing the adequacy of the related disclosures
impairment testing was required; and
in note 12 to the financial report.
Assessing the adequacy of the related disclosures
in note 12 to the financial report.
Other information
Other information
The directors are responsible for the other information. The other information comprises the
The directors are responsible for the other information. The other information comprises the
information in the Group’s annual report for the year ended 30 June 2019, but does not include the
information in the Group’s annual report for the year ended 30 June 2019, but does not include the
financial report and the auditor’s report thereon.
financial report and the auditor’s report thereon.
Our opinion on the financial report does not cover the other information and we do not express any
Our opinion on the financial report does not cover the other information and we do not express any
form of assurance conclusion thereon.
form of assurance conclusion thereon.
In connection with our audit of the financial report, our responsibility is to read the other information
In connection with our audit of the financial report, our responsibility is to read the other information
and, in doing so, consider whether the other information is materially inconsistent with the financial
and, in doing so, consider whether the other information is materially inconsistent with the financial
report or our knowledge obtained in the audit or otherwise appears to be materially misstated.
report or our knowledge obtained in the audit or otherwise appears to be materially misstated.
If, based on the work we have performed, we conclude that there is a material misstatement of this
If, based on the work we have performed, we conclude that there is a material misstatement of this
other information, we are required to report that fact. We have nothing to report in this regard.
other information, we are required to report that fact. We have nothing to report in this regard.
Responsibilities of the directors for the Financial Report
Responsibilities of the directors for the Financial Report
The directors of the Company are responsible for the preparation of the financial report that gives a
The directors of the Company are responsible for the preparation of the financial report that gives a
true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001
true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001
and for such internal control as the directors determine is necessary to enable the preparation of the
and for such internal control as the directors determine is necessary to enable the preparation of the
financial report that gives a true and fair view and is free from material misstatement, whether due to
financial report that gives a true and fair view and is free from material misstatement, whether due to
fraud or error.
fraud or error.
82
82
112
INDEPENDENT AUDITOR’S REPORT
For the year ended 30 June 2019
In preparing the financial report, the directors are responsible for assessing the ability of the group to
continue as a going concern, disclosing, as applicable, matters related to going concern and using the
In preparing the financial report, the directors are responsible for assessing the ability of the group to
going concern basis of accounting unless the directors either intend to liquidate the Group or to cease
continue as a going concern, disclosing, as applicable, matters related to going concern and using the
operations, or has no realistic alternative but to do so.
going concern basis of accounting unless the directors either intend to liquidate the Group or to cease
operations, or has no realistic alternative but to do so.
Auditor’s responsibilities for the audit of the Financial Report
Auditor’s responsibilities for the audit of the Financial Report
Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free
from material misstatement, whether due to fraud or error, and to issue an auditor’s report that
Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free
includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an
from material misstatement, whether due to fraud or error, and to issue an auditor’s report that
audit conducted in accordance with the Australian Auditing Standards will always detect a material
includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an
misstatement when it exists. Misstatements can arise from fraud or error and are considered material
audit conducted in accordance with the Australian Auditing Standards will always detect a material
if, individually or in the aggregate, they could reasonably be expected to influence the economic
misstatement when it exists. Misstatements can arise from fraud or error and are considered material
decisions of users taken on the basis of this financial report.
if, individually or in the aggregate, they could reasonably be expected to influence the economic
decisions of users taken on the basis of this financial report.
A further description of our responsibilities for the audit of the financial report is located at the
Auditing and Assurance Standards Board website (http://www.auasb.gov.au/Home.aspx) at:
A further description of our responsibilities for the audit of the financial report is located at the
Auditing and Assurance Standards Board website (http://www.auasb.gov.au/Home.aspx) at:
http://www.auasb.gov.au/auditors_responsibilities/ar1.pdf
http://www.auasb.gov.au/auditors_responsibilities/ar1.pdf
This description forms part of our auditor’s report.
This description forms part of our auditor’s report.
Report on the Remuneration Report
Report on the Remuneration Report
Opinion on the Remuneration Report
Opinion on the Remuneration Report
We have audited the Remuneration Report included in pages 50 to 62 of the directors’ report for the
year ended 30 June 2019.
We have audited the Remuneration Report included in pages 50 to 62 of the directors’ report for the
year ended 30 June 2019.
In our opinion, the Remuneration Report of Otto Energy Limited, for the year ended 30 June 2019,
complies with section 300A of the Corporations Act 2001.
In our opinion, the Remuneration Report of Otto Energy Limited, for the year ended 30 June 2019,
complies with section 300A of the Corporations Act 2001.
Responsibilities
Responsibilities
The directors of the Company are responsible for the preparation and presentation of the
Remuneration Report in accordance with section 300A of the Corporations Act 2001. Our responsibility
The directors of the Company are responsible for the preparation and presentation of the
is to express an opinion on the Remuneration Report, based on our audit conducted in accordance with
Remuneration Report in accordance with section 300A of the Corporations Act 2001. Our responsibility
Australian Auditing Standards.
is to express an opinion on the Remuneration Report, based on our audit conducted in accordance with
Australian Auditing Standards.
BDO Audit (WA) Pty Ltd
BDO Audit (WA) Pty Ltd
Jarrad Prue
Jarrad Prue
Director
Director
Perth, 25 September 2019
Perth, 25 September 2019
83
83
113
ADDITIONAL ASX INFORMATION
ADDITIONAL ASX INFORMATION
As at 19 September 2019
As at 19 September 2019
Distribution of shareholdings
Range
1 – 1,000
1,001 – 5,000
5,001 – 10,000
10,001 – 100,000
100,001 and over
Total
Shareholders by location
Australian holders
Overseas holders
Unmarketable parcels
Number of holders
Number of shares
157
229
524
2,412
1,604
4,926
24,384
722,041
4,396,966
101,620,758
2,353,700,576
2,460,464,725
Number of holders Number of shares
2,344,035,513
116,429,212
2,460,464,725
4,691
235
4,926
There were 691 shareholders holding less than a marketable parcel of shares.
Twenty largest shareholders
Name
Ordinary shares
HSBC Custody Nominees (Australia) Limited
Citicorp Nominees Pty Limited
BNP Paribas Nominees Pty Ltd
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