REG - Pantheon Resources - Unaudited Interim Results
31/03/2023 07:00
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RNS Number : 8583U Pantheon Resources PLC 31 March 2023
31(st) March 2023
Pantheon Resources plc
Interim Results (unaudited) for the six months ended 31 December 2022
Pantheon Resources plc ("Pantheon" or "the Company"), the AIM-quoted oil and
gas exploration and production company with 100% working interests in several
conventional projects on the North Slope of Alaska, announces its interim
results for the six months ended 31 December 2022 (the "Period"), together
with operational highlights for the half year and the period beyond.
HIGHLIGHTS
Operational
· Drilling and long term production testing of the Alkaid #2 well -
confirmed discovery
· Confirmed better than expected reservoir deliverability; very positive
for future development
· Flow data and hydrocarbon mix adversely impacted by fracking
intercepting a gas cap
· Future Alkaid wells to be positioned slightly deeper within the
>400ft section to avoid the gas cap
· SLB (previously Schlumberger) completion of first module of project
review and estimated Pantheon's projects to contain 17.8 billion barrels of
oil in place
· Receipt of a report by the independent experts at Baker Hughes AHS
('Advanced Hydrocarbon Stratigraphy') titled "Pantheon Great Bear Theta West
1 well: Characterization of a World Class Petroleum System Using AHS's
Cuttings' Volatiles Stratigraphy."
· Recent appointment of independent non-executive director, Mr David
Hobbs, +40 years' experience
· Strengthening of operational team - recent appointment of Tony
Beilman, +40 years drilling, completions and production experience
· Wood Mackenzie ('WoodMac') report Pantheon's Theta West #1 well as
"the fourth largest discovery well globally in 2022". Consistent with
Pantheon's own assessment WoodMac characterise Theta West as a contingent
resource requiring additional drilling and testing before potentially being
considered commercial.
Financial
· Loss for the period $1.6 million (2021: $4.4 million). Impacted by
$4.8 million net credit from mark to market revaluation of derivative
component and interest expenses on the Convertible Bond
· G&A slightly higher at $3.7 million (2021: $3.2 million)
reflecting the growth in the operational activity
· Cash on hand 31 December 2022: $16.3 million (2021: $92.7 million)
· Cash on hand 30 March 2023: $10.8 million
Jay Cheatham, CEO of Pantheon Resources, said:
"The period to 31 December 2022 and beyond has continued to be one of great
achievement for our Company with an enormous volume of work having been
undertaken, further supporting our confidence in our projects. Globally
recognised WoodMac referred to Theta West #1 as being the fourth largest
discovery well of 2022. Importantly, it is the only onshore well in the top
four. AHS Baker Hughes also referred to Theta West #1 as a 'World Class
Petroleum System.' We should all be very proud of these achievements. As I
stated last year, which I repeat again, Pantheon's projects have the potential
to be a nationally significant oil resource in a safe jurisdiction onshore
USA.
"We do understand that Pantheon's share price has suffered, as a result of a
number of factors including the results at Alkaid which represents less than
4% of our resource, social media mistruths, a lower oil price, and rising
interest rates.. I reiterate again to shareholders that we see great potential
in the Alkaid project. We know the flow test result was impacted because our
fracks intercepted a gas cap. We will adjust for this in future wells by
positioning them a little deeper and would expect to see significant
improvement. Alkaid #2 was designed as a test well to gain data to optimise
future wells. This is industry standard practice - at Prudhoe Bay, America's
largest oilfield and only 20 miles north of us, the initial wells were dry
holes! Alkaid was anything but a dry hole; far from it, our modelling points
to Alkaid being a potential commercial development."
Further information:
Pantheon Resources plc +44 20 7484 5361
Jay Cheatham, CEO
Justin Hondris, Director, Finance and Corporate Development
Canaccord Genuity Limited (Nominated Adviser and broker)
Henry Fitzgerald-O'Connor, James Asensio, Gordon Hamilton +44 20 7523 8000
BlytheRay
Tim Blythe, Megan Ray, Matthew Bowld +44 20 7138 3204
Notes to Editors
Pantheon Resources plc is an AIM listed Oil & Gas company focused on
several large projects located on the North Slope of Alaska ("ANS"),
onshore USA where it has a 100% working interest in 153,000 highly
prospective acres with potential for multi billion barrels of oil recoverable.
A major differentiator to other ANS projects is its close proximity to
transport and pipeline infrastructure which offers a significant competitive
advantage to Pantheon, allowing for materially lower capital costs and much
quicker development times. The Group's stated objective is to create material
value for its stakeholders through oil exploration, appraisal and development
activities in high impact, highly prospective conventional assets, in
the USA; a highly established region for energy production with
infrastructure, skilled personnel and low sovereign risk. All operations are
onshore USA, with drilling costs materially below that of offshore wells.
For further information on Pantheon Resources plc, see the website
at: www.pantheonresources.com (http://www.pantheonresources.com/)
STATEMENT FOR THE SIX MONTHS ENDED 31 DECEMBER 2022
_______________________________________________________________________________________
The period 1 July 2022 and beyond has seen Pantheon continue to progress its
projects across its large Alaskan portfolio spanning 153,000 acres, which
management estimate to contain over 20 billion barrels of oil in place and
more than 2 billion recoverable barrels of oil. At the same time, the macro
energy environment we faced during the first half of 2022 faded somewhat in
the last half year and into 2023 in reaction to global macroeconomic and
geopolitical events. Supply chain issues impacted operations at Alkaid #2
materially, as did high cost inflation which was particularly impacted by
extremely high diesel prices (although these have since eased), service
provider and material costs.
Pantheon continued advancing its high-impact projects on the Alaska North
Slope from the exploration phase to appraisal and development planning. The
long term production test at Alkaid #2 was an important milestone in our
passage to becoming an oil development and production company. Over that
period, Pantheon produced and sold oil from its successful production test at
Alkaid #2.
Pantheon's operational ambitions over 2023 and beyond are to test the Shelf
Margin Deltaic ("SMD") which we believe has the potential to contain 2.6
billion barrels of OIP and a P50 Contingent Resource (recoverable) of 404
million barrels oil ("mmbo") in the Alaskan late spring/summer, prior to
shifting our efforts into evaluating our 1.7 billion barrel discovered
resource at Theta West as well as assessing the various discovered horizons at
Talitha. Completion of these activities will require additional capital and
in this regard Pantheon has prioritised the opening its data room in the near
term to commence the process of finding a suitable farmout partner, or to
otherwise raise capital to fund operations. Activities at Theta West and
Talitha will include additional drilling and testing to increase our
contingent resources with an aim to ultimately transition these resources to
reserves allowing investors and the industry to recognize a higher valuation
for the discoveries which have now been ranked amongst the largest in the
world by several global research organizations. This is a credit to our team
which have done a tremendous job in discovering this large resource and now
working hard to unlock its value and deliver a commercial outcome for our
shareholders.
Opening of Data Room
Pantheon has engaged SLB (nee Schlumberger) to manage and operate Pantheon's
data room which is expected to open in the near term. In December 2022, SLB
completed phase 1 of the project which included preparation of dynamic and
static models over Pantheon's projects which they estimate to contain over 17
billion barrels of oil in place and which will form an important component of
the data room. The purpose of the data room is to attract a potential farm
in partner into one or more of Pantheon's projects, all of which Pantheon has
a 100% working interest in. Pantheon is seeking a 'pay to earn' type
arrangement (which may or may not include an additional up-front cash payment)
where any potential farminee would fund a mutually agreed drilling/activity
programme in exchange for a working interest in either a specific asset (for
example, Alkaid) or across the entire portfolio. Pantheon recognizes the
benefit in actively exploiting its portfolio which, in a success case, has the
potential to create very significant value for shareholders given the large
size of its projects. Historically at an industry level, Pantheon has
maintained a low profile to protect its competitive advantage (Pantheon has
sole access to c.1000 square miles of high quality 3D seismic) while
prosecuting its acreage strategy. Pantheon has now successfully executed its
acreage strategy and as such intends to increase the profile of the Company
within both industry and in the investment community.
Alkaid #2 Drilling, Completion and Flow Testing
After more than a decade of exploration and appraisal on the North Slope of
Alaska, Pantheon/Great Bear drilled and completed a pilot production test at
its Alkaid oil accumulation. The Alkaid location was selected for this first
test because of the positive test result from the nearby Alkaid #1 in 2019
coupled with the low cost location from which to drill and run a long term
production test, being immediately adjacent to the highway. The Alkaid ZOI,
being the deeper horizon and having flowed previously in the Alkaid #1 well,
was the logical primary objective because we would subsequently be able to
come up the hole to test the independent and five times larger SMD resource in
the same wellbore where we expect to encounter high quality reservoir. A
successful long term production test at Alkaid had the objective of proving
the production capability and characteristics for the reservoir to allow for
field development planning and as a tool for potential future debt financing.
The Alkaid #2 well bore reached a measured depth of 14,300' including a 5,300'
horizontal section which was all oil bearing. This lateral was successfully
fracture stimulated with 30 frac stages, including the placement of +/- 8
million pounds of sand proppant. Production testing operations at Alkaid #2
commenced in October. Initially, frac sand production was higher than expected
which necessitated a cleanout. Due to the lack of availability of a workover
rig, a thru tubing coiled tubing cleanout procedure was undertaken which
successfully cleared all but c.1000ft of the wellbore blockage. The Company
used this hiatus to transition from temporary flow back facilities into its
larger permanent facilities.
After returning to production in December, Pantheon reported production at a
rate of over 500 barrels per day (bpd) of hydrocarbon liquids including oil,
condensate and natural gas liquids (NGLs), as well as c2.5 mmcfpd natural gas,
from approximately 4,000 ft of clean lateral wellbore. At this time, much
discussion centred around the value of liquids produced at Alkaid #2. When
separated and sold, condensate and NGLs are estimated to achieve 80% - 90%, or
potentially higher, of ANS crude oil price (ANS crude typically trades at a
premium to WTI oil). All liquids produced on the North Slope are blended and
sent through the Trans Alaska Pipeline System (TAPS) to Valdez and on to
market as ANS crude. The crude oil produced and sold during this time period
averaged c.$87/Bbl.
In order to maximise data, Alkaid #2 was then shut in awaiting the arrival of
the Nordic Calista #2 workover rig to pull the tubing and then clean out the
remaining 1000 ft of blocked wellbore with a larger coiled tubing unit (CTU).
During this shut in period extensive analysis was carried out to understand
the much higher than anticipated gas production. Pantheon along with SLB
(previously known as Schlumberger) now believe Alkaid #2 was drilled near a
small gas cap which was not clearly visible from available seismic resolution
and fracked into that gas cap. Gas production is now estimated as a
combination of free gas from the gas cap along with gas from solution. The
nearby Alkaid #1 well, tested in 2019 had a producing gas oil ratio (GOR) many
times less than that of Alkaid #2 despite being in the same reservoir,
suggesting an anomalous result. Pantheon will drill future development wells
deeper to avoid the gas cap which should result in a lower GOR consistent with
what we saw at Alkaid #1.
Post the cleanout of the sand blockage in the final 1,000ft (c.20%) of the
wellbore, Alkaid #2 returned to production with flow rates only marginally
higher than pre-cleanout, suggesting that despite the sand blockage, the final
1,000ft was likely connected and already contributing to the main wellbore
through the fractures communicating with each other. The well soon returned to
production along the pre cleanout decline profile. The initial 30 day
Production (IP30) production rate is calculated at c.505 barrels per day (BPD)
of marketable liquid hydrocarbons consisting of c.180 BOPD oil, c.325 BPD of
condensate and NGLs, along with c.2,300 mcfpd natural gas after shrinkage.
Encouragingly, the quantum of liquid and gas production flowing without
artificial lift from Alkaid #2 demonstrates the good deliverability of the
reservoir, which is a significant de-risking event for Alkaid development.
The well has now flowed for c.90 days including the initial start up, and
the reservoir engineering team has determined we have collected sufficient
data to determine decline rates, a primary objective of the long term test.
Given also the greater than forecast gas being produced, we have not sought an
extension from the State of Alaska for a second 90 day flaring permit and have
proactively shut in Alkaid#2.
In January, for illustrative purposes, Pantheon stress tested the Alkaid
development model using an estimated development well drilling cost of $19.5
million, which for conservatism modelled in a 50% increase over the then
Company estimate of $13 million. The Company has continued to analyse and
review this figure and currently estimates development drilling costs in the
region of +/- $13.5 million per well. Applying $13.5 million well cost,
assuming a 10,000ft lateral and no improvement in individual well
productivity, our modelled Alkaid development economics yield a c.20% IRR at
an $80 ANS crude price. This indicates that without including the benefit of
any expected improvement in hydrocarbon liquid flow from deeper and down dip
completions, Alkaid is modelled as economic even as a stand-alone development.
However, in practice, Alkaid is unlikely to ever be a stand-alone development
because of the other oil accumulations, such as the SMD, in and around the
Alkaid structure that were not included in the economics and will be evaluated
as part of our future activities mentioned above. The ability to share
infrastructure between projects significantly enhances modelled field
economics.
Alkaid represents less than 4% of Pantheon's resource base, is not
representative of Pantheon's other discoveries and is Pantheon's first
production test well in a new geological play type. As is typical for first
time operations in new fields, there is a learning curve with any first well
that will be optimized over subsequent wells to yield the best results.
Commissioning of Independent Expert Reports
Pantheon has commissioned Netherland Sewell & Associates (NSAI), a
worldwide leader in petroleum property analysis and one of the most respected
names in independent reserves reporting, to undertake two independent expert
reports (Competent Persons Report) over each of the Company's Theta West and
Alkaid projects. Additionally, SLB (nee Schlumberger) is updating the
dynamic reservoir models across Pantheon's portfolio to incorporate into the
NSAI report. The SLB and NSAI work will run in parallel to the farmout
process providing investors and financiers an independent assessment of the
resources.
Strengthening Board and Technical Team
Pantheon announced the appointment of David Hobbs as an independent
non-executive Director.
David is an outstanding addition to our team, bringing great experience and
technical knowledge to Pantheon. David graduated as a Petroleum Engineer
from Imperial College in 1984, initially working at British Gas as a
drilling engineer before moving into commercial and business development roles
at Monument Oil & Gas and Hardy Oil and Gas, two UK listed
international independent E&P companies. He joined Cambridge Energy
Research Associates (CERA), now part of S&P Global, ending up as Chief
Energy Strategist, advising Government officials, senior executives and Boards
of Directors across the energy sector. He also spent six years as part of the
leadership team establishing the King Abdullah Petroleum Studies and Research
Center (KAPSARC) in Riyadh, Saudi Arabia. David is an adjunct professor at
the University of Calgary.
Pantheon has also enhanced its technical and operational team with the
addition of Tony Beilman. Tony has over 40 years' experience in the industry
starting his career at Phillips Petroleum. Tony specializes in drilling and
completions especially in horizontal well bores, with an emphasis on fracture
stimulation. Tony also co-founded a drilling and production company and his
wealth of experience is undoubtedly going to improve Pantheon's operational
execution.
We enthusiastically welcome both David and Tony to the team.
Financial & Corporate
The interim results show a loss for the period of $1.6m (2021: $4.4m) which
is lower than the comparative interim period, largely impacted by a $4.8m net
credit which resulted from the combined mark to market revaluation of the
derivative component of the unsecured Convertible Bond and interest charges on
the debt component. General and administration expenses of $3.7m (2021: $3.2m)
were slightly higher than the prior year reflecting the growth of the Company.
Revenue generated during the period was $0.5m (2021: $Nil), resulting from oil
sales during testing of the Alkaid #2 well. Due to the disproportionate start
up commissioning and operations costs, there was a gross loss of $0.6m (2021:
Nil) on operations.
At 31 December 2022, cash and cash equivalents amounted to $16.3m
(2021: $92.7m). As previously announced, the Company had a successful
operational campaign since 1 July 2021, encountering oil in all three wells
drilled and/or tested/testing by the Group including Theta West #1, Talitha #A
and Alkaid #2. The data and analysis from drilling and testing activities
resulted in material increases to Company estimates for both Oil in Place and
recoverable resource. The Company has sufficient working capital to continue
operations to the end of 2023, however as previously reported, intends to
complete either a farmout and/or other funding arrangement in the first half
of 2023 to have sufficient resources for the 2023/24 drilling and testing
campaign, the additional acreage purchases and ongoing working capital. The
Company's data room is anticipated to open shortly to formally commence the
process of seeking an appropriate farmout partner.
Supporting farmout efforts, the Company has commissioned Netherland Sewell
& Associates to undertake an independent expert report over the Company's
Theta West and Alkaid projects. Additionally, SLB is updating the dynamic
reservoir models across Pantheon's portfolio as part of the second phase of
their work. These reports will run in parallel to the farmout process as well
as providing investors and financiers an independent assessment of the
resources.
In 2021 the Company issued $55 million senior unsecured convertible bonds (the
"Convertible Bonds"). The Convertible Bonds carry a coupon of 4.0% per annum
and are repayable in equal quarterly instalments (the "Amortisations") over
the 5 year term of the Convertible Bond. Such Amortisations are payable in
cash or shares at the Company's option. As at 31 December, 2022 the
principal outstanding on the bond was $39.2m ($36.75m as of the date of
publication of this report). A summary of the key terms of the Convertible
Bond can be found at Note 5.
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE PERIOD ENDED 31 DECEMBER 2022
___________________________________________________________________________________
Notes 6 months ended 31 December 2022 (unaudited) 6 months ended 31 December 2021 (unaudited) Year ended 30 June 2022
(audited)
$ $ $
Continuing operations
Revenue 455,309 - -
Production royalties (57,101) - -
Facilities commissioning and operations (837,503) - -
Cost of sales (183,296) - -
Gross loss (622,590) - -
Administration expenses (3,699,831) (3,150,888) (7,430,653)
Share Based payment expense (2,935,897) (2,013,966) (8,256,575)
Operating loss (7,258,318) (5,174,854) (15,687,228)
Convertible Bond - Interest expense (3,151,102) (570,295) (4,640,537)
Convertible Bond - Revaluation of derivative 7,937,855 (200,531) 4,310,773
Interest receivable 152,492 143 42,674
Loss before taxation (2,319,073) (5,945,537) (15,974,318)
Taxation 743,097 1,497,945 2,022,334
Loss for the period (1,575,796) (4,447,592) (13,951,984)
Other comprehensive income for the period
Exchange differences from translating foreign operations (97,473) 844,484 (741,484)
Total comprehensive profit/(loss) for the period (1,673,449) (3,603,108) (14,693,468)
Loss per share from continuing operations:
Basic and diluted Loss per share 2 (0.21)¢ (0.66)¢ (1.93)¢
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE PERIOD ENDED 31 DECEMBER 2022
_______________________________________________________________________________________
Share Share Retained Currency Share Total
capital premium losses reserve based payment equity
$ $ $ $ $ $
Group
At 1 July 2022 10,720,459 264,879,196 (48,466,591) 493,078 11,776,246 239,402,388
Loss for the period - - (1,575,976) - - (1,575,976)
Other comprehensive income: Foreign currency translation - - - (97,473) - (97,473)
Total comprehensive income for the period - - (1,575,976) (97,473) - (1,673,449)
Exercise of Share Options
Issue of shares 54,759 1,701,259 - - - 1,756,018
- - 395,238 - (395,238) -
Transfer of previously expensed share based payment on exercise of options
Convertible Bond - Amortisation and Redemption
Issue of shares 73,543 5,683,957 - - - 5,757,500
Shares Issued in Lieu of Payment
Share based payments expense - - - - 2,935,897 2,935,897
Balance at 31 December 2022 10,848,761 272,264,411 (49,647,328) 395,605 14,316,906 248,178,354
Share Share Retained Currency Share Total
capital premium losses reserve based payment equity
$ $ $ $ $ $
Group
At 1 July 2021 9,739,203 208,683,936 (36,331,398) 1,234,562 5,336,462 188,662,765
Net loss for the period - - (4,447,592) - - (4,447,592)
Other comprehensive income: Foreign currency translation - - - 844,484 - 844,484
Total comprehensive income for the period - - (4,447,592) 844,484 - (3,603,108)
Capital Raising
Issue of shares 638,462 40,904,076 - - - 41,542,538
Issue costs - (1,489,248) - - - (1,489,248)
Exercised options - 230,958 - - (230,958) -
Share option expense - - - - 2,013,966 2,013,966
Exercised share options 40,716 1,099,881 - - - 1,140,597
Balance at 31 December 2021 10,418,381 249,429,603 (40,778,990) 2,079,046 7,119,470 228,267,510
Share Share Retained Currency Share Total
capital premium losses reserve based payment equity
$ $ $ $ $ $
Group
At 1 July 2021 9,739,203 208,683,936 (36,331,398) 1,234,562 5,336,462 188,662,765
Loss for the year - - (13,951,984) - - (13,951,984)
Other comprehensive income: Foreign currency translation - - - (741,484) - (741,484)
Total comprehensive income for the year - - (13,951,984) (741,484) - (14,693,468)
Capital Raising
Issue of shares 630,769 40,369,230 - - - 40,999,999
Issue of shares in lieu of fees 7,692 492,308 - - - 500,000
Issue costs - (1,494,693) - - - (1,494,693)
Exercise of Share Options
Issue of shares 196,238 5,543,559 - - - 5,739,796
- - 1,816,791 - (1,816,791) -
Transfer of previously expensed share based payment on exercise of options
Convertible Bond - Amortisation and Redemption
Issue of shares 146,557 11,284,856 - - - 11,431,413
Shares Issued in Lieu of Payment
Share based payments expense - - - - 8,256,575 8,256,575
Balance at 30 June 2022 10,720,459 264,879,196 (48,466,591) 493,078 11,776,246 239,402,388
CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION
AS AT 31 DECEMBER 2022
_______________________________________________________________________________________
Notes 6 months ended 6 months ended Year ended
31 December 31 December 30 June
2022 2021 2022
(unaudited) (unaudited) (audited)
ASSETS $ $ $
Non-Current Assets
Exploration and evaluation assets 3 274,321,398 195,662,187 237,722,294
Property, plant & equipment 3 66,199 4,245 91,691
274,387,597 195,666,432 237,813,985
Current Assets
Trade and other receivables 2,823,089 275,315 2,498,447
Cash and cash equivalents 16,335,676 92,667,269 57,784,121
19,158,765 92,942,584 60,282,568
293,546,363 288,609,016
Total assets 298,096,553
LIABILITIES
Current liabilities
Convertible Bond - Debt 9,929,027 - 10,001,704
Trade and other payables 6,336,999 1,120,647 6,377,986
Provisions 5,282,866 1,250,000 5,285,440
60
Lease Liabilities 60,007 4,702 60,297
Other Liabilities - - 1,964,441
Deferred tax liability 940,306 2,207,792 1,683,403
22,549,205 4,583,141 25,373,271
Non-current liabilities
Lease Liabilities 2,956 - 30,004
Trade and other payables
Convertible Bond - Debt 6 19,228,219 39,734,584 20,474,664
Convertible Bond - Derivative 6 3,587,629 16,023,781 12,816,226
22,818,804 55,758,365 33,320,894
45,368,009 60,341,506 58,694,166
Total liabilities
248,178,354 228,267,510 239,402,388
Net assets
EQUITY
Capital and reserves
Share capital 10,848,761 10,418,381 10,720,459
Share premium 272,264,411 249,429,603 264,879,196
Retained losses (49,647,328) (40,778,990) (48,466,591)
Currency reserve 395,605 2,079,046 493,078
Share based payment reserve 14,316,906 7,119,470 11,776,246
Shareholders' equity 248,178,354 228,267,510 239,402,388
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE PERIOD ENDED 31 DECEMBER 2022
_______________________________________________________________________________________
6 months ended 6 months ended
31 December 31 December Year ended
2022 2021 30 June
(unaudited) (unaudited) 2022
(audited)
$ $ $
Net outflow from operating activities (6,722,549) (2,446,588) (941,506)
Cash flows from investing activities
Interest received 152,492 143 42,674
Funds used for drilling, exploration and leases (36,601,678) (6,707,468) (45,267,175)
Advance for performance bond - - (2,400,000)
Interest paid - (7,961) -
Property, plant and equipment (3,033) - (3,368)
Net cash outflow from investing activities (36,452,218) (6,715,286) (47,627,869)
Cash flows from financing activities
Proceeds from share issues 1,756,018 42,140,595 46,739,796
Issue costs paid in cash - (946,710) (994,694)
Convertible Bond - 55,000,000 55,000,000
Repayment of borrowing and leasing liabilities (29,696) (28,218) (55,083)
Net cash inflow from financing activities 1,726,323 96,165,667 100,690,020
(Decrease) / Increase in cash & cash equivalents (41,448,445) 87,003,793 52,120,645
Cash and cash equivalents at the beginning of the period 57,784,121 5,663,476 5,663,476
Cash and cash equivalents at the end of the period 16,335,677 92,667,269 57,784,121
RECONCILIATION OF OPERATING LOSS TO NET CASH OUTFLOW FROM OPERATING ACTIVITIES
6 months ended 6 months ended Year ended
31 December 31 December 30 June
2022 2021 2022
(unaudited) (unaudited) (audited)
$ $ $
Loss for the period (1,575,976) (4,447,592) (13,951,984)
Net interest received (152,492) (143) (42,674)
Impairment of intangible assets - E&E - - -
Share Based Payments non-cash expense 2,935,897 2,013,966 8,256,575
Interest Expense - 570,295 -
Derivative mark to market charge - 200,531 -
Depreciation of office equipment 245 - 303
Depreciation of right of use assets 27,154 25,647 54,472
Interest Expense 3,151,102 - 4,640,537
Convertible Bond - Revaluation of derivative liability (7,937,855) - (4,310,773)
Other provisions - - 535,040
Decrease in other liabilities (1,964,731) - -
(Increase)/Decrease in trade and other receivables (324,642) (165,439) 11,430
(Decrease)/Increase in trade and other payables (40,987) 13,557 7,235,337
Effect of translation differences (97,165) 840,535 (1,347,435)
Taxation (743,097) (1,497,945) (2,022,334)
Net cash outflow from operating activities (6,722,549) (2,446,588) (941,506)
NOTES TO THE FINANCIAL INFORMATION
FOR THE PERIOD ENDED 31 DECEMBER 2022
_______________________________________________________________________________________
1. Accounting policies
A summary of the principal accounting policies, all of which have been applied
consistently throughout the period, is set out below.
1.1. Basis of preparation
This financial information has been prepared on a going concern basis using
the historical cost convention and in accordance with the International
Financial Reporting Standards as adopted by the European Union ("EU")
("IFRS"), including IFRS 6 'Exploration for and Evaluation of Mineral
Resources', and in accordance with the provisions of the Companies Act 2006.
This interim report has been prepared on a basis consistent with the Group's
expected accounting policies for the year ending 30 June 2023. These
accounting policies are the same as those set out in the Group's Annual Report
and Financial Statements for the year ended 30 June 2022, which are available
from the registered office or the company's website
(www.pantheonresources.com).
The Group financial information is presented in US Dollars and is unaudited.
The interim financial information does not constitute statutory accounts
within the meaning of section 434 of the Companies Act 2006. The comparative
figures for the year ended 30 June 2022 have been taken from the Group's
statutory accounts for that financial year, which have been reported on by the
Group's auditors and delivered to the Registrar of Companies.
1.2. Basis of consolidation
Subsidiaries are fully consolidated from the date on which control is
transferred to the Group. They are de-consolidated from the date that control
ceases. The purchase method of accounting is used to account for the
acquisition of subsidiaries by the Group. The cost of an acquisition is
measured as the fair value of the assets given, equity instruments issued, and
liabilities incurred or assumed at the date of exchange. Identifiable assets
acquired and liabilities and contingent liabilities assumed in a business
combination are measured initially at their fair values at the acquisition
date, irrespective of the extent of any minority interest. The excess of the
cost of acquisition over the fair value of the Group's share of the
identifiable net assets acquired is recorded as goodwill. Goodwill arising on
acquisitions is capitalised and subject to impairment review, both annually
and when there are indications that the carrying value may not be recoverable.
Inter-company transactions, balances and unrealised gains on transactions
between group companies are eliminated. All the companies over which the
Company has control apply, where appropriate, the same accounting policies as
the Company.
1.3. Foreign currency translation
(i) Functional and presentational currency
The financial statements are presented in US Dollars ("$"), which is the
functional currency of the Company and is the Group's presentation currency.
(ii) Transactions and balances
Transactions in foreign currencies are translated into US dollars at the
average exchange rate for the year. Monetary assets and liabilities
denominated in foreign currencies are translated at the rate of exchange
ruling at the balance sheet date. The resulting exchange gain or loss is dealt
with in the income statement.
The assets, liabilities and the results of the foreign subsidiary undertakings
are translated into US dollars at the rates of exchange ruling at the year
end. Exchange differences resulting from the retranslation of net investments
in subsidiary undertakings are treated as movements on reserves.
1.4. Cash and cash equivalents
The company considers all highly liquid investments, with a maturity of 90
days or less to be cash equivalents, carried at the lower of cost or market
value.
1.5. Going concern
The interim report has been prepared on the going concern basis, which
contemplates the continuity of normal business activity and the realisation of
assets and the settlement of liabilities in the normal course of business.
At 31 December 2022, cash and cash equivalents amounted to $16.3m
(2021: $92.7m). As previously announced, the Company had a successful
operational campaign since 1 July 2021, encountering oil in all three wells
drilled and/or tested/testing by the Group including Theta West #1, Talitha #A
and Alkaid #2. The data and analysis from drilling and testing activities
resulted in material increases to Company estimates for both Oil in Place and
recoverable resource. The Company has sufficient working capital to continue
operations to the end of 2023 however as previously disclosed, the Company
intends to complete either a farmout and/or other funding arrangements in the
first half of 2023 to have sufficient resources for the anticipated 2023/24
drilling and testing campaign, the additional acreage purchases, and ongoing
working capital. The Company is confident of achieving one or both of these
objectives. The Company's data room is expected to open in the near term to
formally commence the process of seeking an appropriate farmout partner.
Supporting farmout efforts, the Company has commissioned Netherland Sewell
& Associates to undertake an independent expert report over the Company's
Theta West and Alkaid projects. Additionally, SLB is updating the dynamic
reservoir models across Pantheon's portfolio as part of the second phase of
their work. These reports will run in parallel to the farmout process as well
as providing investors and financiers an independent assessment of the
resources.
1.6. Revenue
The Group is engaged in the business of extracting oil and gas. Revenue from
contracts with customers is recognised in accordance with IFRS15 Revenue from
Contacts with Customers, at an amount that reflects the consideration to which
the Group expects to be entitled in exchange for those goods.
Contract balances
A contract asset is the right to consideration in exchange for goods
transferred to the customer. If the Group performs by transferring goods to a
customer before the customer pays consideration or before payment is due, a
contract asset is recognised for the earned consideration that is conditional.
The Group does not have any contract assets as performance and a right to
consideration occurs within a short period of time and all rights to
consideration are unconditional.
Interest revenue is recognised on a proportional basis taking into account the
interest rates applicable to the financial assets.
1.7. Deferred taxation
Deferred 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 financial statements. Deferred tax is determined using
tax rates (and laws) that have been enacted or substantially enacted by the
balance sheet date and expected to apply when the related deferred tax is
realised, or the deferred liability is settled.
Deferred tax assets are recognised to the extent that it is probable that the
future taxable profit will be available against which the temporary
differences can be utilized.
1.8. Exploration and evaluation costs and developed oil and gas properties
The Group follows the 'successful efforts' method of accounting for
exploration and evaluation costs. At the point of production, all costs
associated with oil, gas and mineral exploration and investments are
classified into and capitalised on a 'cash generating unit' ("CGU") basis, in
accordance with IAS 36. Costs incurred include appropriate technical and
administrative expenses but not general corporate overheads. If an exploration
project is successful, the related expenditures will be transferred to
Developed Oil and Gas Properties and amortised over the estimated life of the
commercial reserves on a 'unit of production' basis.
The recoverability of all exploration and evaluation costs is dependent upon
the discovery of economically recoverable reserves, the ability of the Group
to obtain necessary financing to complete the development of the reserves and
future profitable production or proceeds from the disposition thereof. All
balance sheet carrying values are reviewed for indicators of impairment at
least twice yearly. The prospect acreage is classified into discrete
"prospects" or CGU's. When production commences the accumulated costs for the
specific CGU is transferred from intangible fixed assets to tangible fixed
assets i.e., 'Developed Oil & Gas Properties' or 'Production Facilities
and Equipment', as appropriate. Amounts recorded for these assets represent
historical costs and are not intended to reflect present or future values.
1.9 Impairment of exploration costs and developed oil and gas properties,
depreciation of assets, plug & abandonment and goodwill
In accordance with IFRS 6 'Exploration for and Evaluation of Mineral
Resources' (IFRS 6), exploration and evaluation assets are reviewed for
indicators of impairment. Should indicators of impairment be identified an
impairment test is performed.
In accordance with IAS 36, the Group is required to perform an "impairment
test" on assets when an assessment of specific facts and circumstances
indicate there may be an indication of impairment, specifically to ensure that
the assets are carried at no more than their recoverable amount. Where an
impairment test is required, any impairment loss is measured, presented and
disclosed in accordance with IAS 36.
Exploration and evaluation costs
All exploration and evaluation assets relate to the Group's Alaskan
operations. The Alaskan leasehold assets were fair valued as at the date of
acquisition of Great Bear and the carrying value at 31 December 2022
represents the cost of acquisition (plus the fair value adjustment, in
accordance with IFRS) and any capitalised costs incurred subsequent to the
acquisition.
Decommissioning Charges
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 expenditure may also change - for
example, in response to changes in reserves or changes in laws and regulations
or their interpretation. 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.
For all wells the Group has adopted a Decommissioning Policy in which all
decommissioning costs are recognise immediately when a well is either
completed, abandoned, suspended or a decision taken that the well will likely
be plugged and abandoned in due course. For completed or suspended wells, the
decommissioning charge is recorded against the capitalised amount and
subsequently depleted over the useful life of well using unit of production
method.
1.10 Financial instruments
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, if/where applicable, 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 liability is derecognised when it is extinguished, discharged,
cancelled or expires.
Classification and measurement of financial liabilities
The Group's financial liabilities include borrowings (convertible bond debt),
trade and other payables and embedded derivative financial instruments.
Financial liabilities are initially measured at fair value, and, where
applicable, adjusted for transaction costs unless the Group designated a
financial liability at fair value through profit or loss.
Subsequently, financial liabilities are measured at amortised cost using the
effective interest method except for derivatives and financial liabilities
designated which are carried subsequently at fair value with gains or losses
recognised in profit or loss.
All interest-related charges and, if applicable, changes in an instrument's
fair value that are reported in profit or loss are included within finance
costs or fair value gains/(losses) on derivative financial instruments.
Embedded derivative financial instruments
A borrowing arrangement structured as a convertible bond repayable in stock
over 20 quarterly instalments, in addition to the right of the lender to
voluntarily convert part or all of the outstanding principal prior to the
maturity date of the bond, has embedded in it a derivative. This is considered
to be a separable embedded derivative of a loan instrument.
At the date of issue, the fair value of the embedded derivative is estimated
using Monte Carlo analysis, by considering the derivative as a series of
individual components with modelling of the fixed and floating legs to
determine a repayment schedule and derive a net present value.
This amount is recognised separately as a financial liability or financial
asset and measured at fair value through the income statement. The residual
amount of the loan is then recorded as a liability on an amortised cost basis
using the effective interest method until extinguished upon conversion or at
the instrument's maturity date.
2. Loss per share
6 months 6 months Year ended
ended 31 December ended 31 30 June
2022 December 2022
2021
(unaudited) (unaudited) (audited)
Loss per share from continuing operations:
Basic and diluted loss per share (0.21)c (0.66)c (1.93)c
The calculation above for the loss per share has been calculated by dividing
the loss for the period from continuing operations, by the weighted average
number of ordinary shares in issue of 764,186,409 (December 2021: 676,479,991;
June 2022: 724,563,153). As the Group recorded a loss for the period, the
diluted loss per share has been made to equal the basic loss per share.
3. Non-current assets
Exploration and evaluation assets Exploration & evaluation
Group assets
At 30 June 2021 237,707,325
Additions 6,707,468
At 31 December 2021 244,414,793
Additions 38,559,707
Asset Retirement Obligations 3,500,400
At 30 June 2022 286,474,900
Additions 36,599,104
At 31 December 2022 323,074,004
Impairment:
At 30 June 2021 48,752,606
At 31 December 2021 48,752,606
At 30 June 2022 48,752,606
At 31 December 2022 48,752,606
Net book value:
At 31 December 2022 274,321,398
At 30 June 2022 237,722,294
In January 2019, the Group acquired 100% of the share capital of Great Bear
Petroleum Ventures I LLC and Great Bear Petroleum Ventures II LLC companies
(collectively, "Great Bear"). The principal assets of Great Bear are leases
with the rights to explore for hydrocarbons in the State of Alaska. At the
period end the exploration and evaluation assets all relate to the Alaskan
operation; Alaskan assets $274.3m (December 2021: $195.7m).
Exploration and evaluation assets are constantly reviewed for indicators of
impairment. If an indicator of impairment is found an impairment test is
required, where the carrying value of the asset is compared with its
recoverable amount. The recoverable amount is the higher of the assets fair
value less costs to sell and value in use. The directors are satisfied that no
impairments are required for the current period end.
Property, plant and equipment
Group Office Equipment Right of Use Assets Total
$ $ $
Cost
At 30 June 2021 16,099 103,913 120,012
At 31 December 2021 16,099 103,913 120,012
Additions 3,368 111,949 115,317
At 30 June 2022 19,467 215,862 235,329
Additions 3,053 - 3,053
Exchange difference - (13,371) (13,371)
At 31 December 2022 22,520 202,491 225,011
Depreciation
At 30 June 2021 16,099 73,605 89,704
Depreciation for the period - 25,647 25,647
Exchange difference - (1,619) (1,619)
At 31 December 2021 16,099 97,633 113,732
Depreciation for the period 303 28,825 29,128
Exchange difference 2 777 779
At 30 June 2022 16,403 127,235 143,638
Depreciation for the period 245 27,154 27,399
Exchange difference 20 (12,245) (12,225)
At 31 December 2022 16,668 142,144 158,812
Net book value
At 31 December 2022 5,852 60,347 66,199
At 30 June 2022 3,064 88,627 91,691
4. Share Capital
During the period, in September and December 2022, the company elected to meet
its quarterly Convertible Bond amortisation obligations by issuing a total of
6,077,187 ordinary shares.
In September 2022 the Company received instructions to exercise a total of
4,525,000 share options. The new ordinary shares have a nominal value of
£0.01. Total proceeds to the Company for the exercised options was
$1,756,018.
As at 31 December, 2022 the company had on issue 778,307,724 shares.
As at 31 December, 2022 the Company also has the following options and
warrants:
· 4,825,000 share options and 4,803,921 warrants; all with a £0.30
exercise price and all expiring September 2024. The warrants are identical to
the share options except are convertible into non-voting shares on a 1:1
basis.
· 7,000,000 share options with an exercise price of £0.27, expiring
July 2030.
· 12,430,000 share options with an exercise price of £0.33, expiring
January 2031.
· 21,380,000 share options with an exercise price of £0.67, expiring
January 2032.
5. Unsecured Convertible Bond
In December 2021, the Company issued $55 million face value of senior
unsecured convertible bonds to a fund advised by Heights Capital Ireland LLC,
a global equity and equity-linked focused investor. At the date of publication
of this report the remaining principal outstanding was $36.75m.
The Convertible Bonds have a maturity of 5 years, a coupon of 4.0% per annum
and are repayable in 20 quarterly repayments ("amortisations") of principal
and interest over the 5 year term of the convertible bond. Such quarterly
amortisations are repayable at the Company's option, in either cash at face
value, or in ordinary shares ("stock") at the lower of the conversion price
(presently USD$1.032 per share) or a 10% discount to volume weighted average
price ("VWAP") in the 10 or 3 day trading period prior to election date.
Additionally, the bondholder has the option to partially convert the
convertible bond at their discretion. A full summary of the terms of
Convertible Bonds is detailed in the Company's RNS dated 7 December, 2021.
The bond agreement contains embedded derivatives in conjunction with an
ordinary bond. As a result, and in accordance with the accounting standards,
the convertible bonds are shown in the Consolidated Statement of Financial
Position, in two separate components, namely Convertible Bond - Debt and
Convertible Bond - Derivative. At the time of initial recognition (Dec 2021)
the $55m bonds were split, $39,175,363 for the Debt Component and $15,824,637
for the Derivative Component.
In order to value the derivative component, Pantheon engages an independent
third party expert valuation specialist group to perform the valuations
bi-annually, who determined that the valuation of the instrument required a
Monte-Carlo simulation of share price outcomes over the 5 year life to
determine the ultimate value of the conversion option. This produced a
calculated Effective Interest Rate ("EIR") of 20.41%. For the 6 month period
ended 31 December 2022, the third party expert valuation group performed their
Monte-Carlo simulation and valuation calculations to determine the new value
for the equity component to be $3,587,629. The resulting movement was posted
to the consolidated statement of comprehensive income to the account
"Revaluation of derivative liability". These amounts will be revalued every
balance date with the differences being accounted for on a mark to market
basis.
For the 6 month interim period to 31 December 2022, two quarterly repayments
(amortisations) were made, and in both cases ordinary shares were issued in
full settlement. Subsequent to year end, in March 2023, an additional
quarterly repayment (amortisation) was made, and in all cases ordinary shares
were issued in full settlement.
At 31 December 2022 the Unsecured Convertible Bond is shown in the
Consolidated Statement of Financial Position in the following categories;
Convertible Bond - Debt Component (Current liability) $ 9,929,027
Convertible Bond - Debt Component (Non-current liability) $19,228,219
Convertible Bond - Derivate Component (Non-current liability) $ 3,587,629
Total $32,744,875
6. Approval by Directors
The interim report for the six months ended 31 December 2022 was approved by
the Directors on the 30th of March 2023.
7. Availability of Interim Report
The interim report will be made available shortly on the Company's website
(www.pantheonresources.com), with further copies available on request from the
Company's registered office.
8. Contingent liability
Pursuant to IAS37, a contingent liability is either: (1) a possible obligation
arising from past events whose existence will be confirmed only by the
occurrence or non-occurrence of some uncertain future event not wholly within
the entity's control, or (2) a present obligation that arises from a past
event but is not recognized because either: (i) it is not probable that an
outflow of resources embodying economic benefits will be required to settle
the obligation, or (ii) the amount of the obligation cannot be measured with
sufficient reliability.
Kinder Morgan Treating L.P. ("Kinder Morgan") initiated a dispute over an East
Texas gas treating agreement between Kinder Morgan and Vision Operating
Company, LLC ("VOC"). VOC ceased making payments to the service provider in
July 2019. The service provider subsequently issued a demand to VOC and, in
February 2021, served Pantheon Resources plc with a petition, seeking to
recover not less than $3.35m in respect of this VOC contract. Pantheon held
ownership of less than 0.1% of VOC via a 66.6% interest in Vision Resources
LLC. Both Vision Resources LLC and VOC filed for Chapter 7 Bankruptcy in the
United States Bankruptcy Court for the Southern District of Texas Houston
Division in April 2020
No Pantheon entity is a signatory to the gas treating agreement and none are
named in the agreement. Pantheon has taken legal advice on the matter and
believes it has no liability to the service provider. Accordingly, Pantheon
does not consider a provision should be included with the final statements and
will contest any claim made.
In, July 2021, the court dismissed Kinder Morgan's claims against Pantheon
Resources plc. Kinder Morgan has also asserted the same claims against two
subsidiaries, Pantheon Oil & Gas, LP and Pantheon East Texas, LLC.
Pantheon Oil & Gas, LP and Pantheon East Texas, LLC are contesting these
claims.
9. Subsequent events
Alkaid #2 production test well - operations
In January 2023 Pantheon confirmed that the Nordic Calista #2 rig would
mobilize to the Alkaid #2 location to undertake a cleanout of the estimated
c.1,000ft sand blockage in the horizontal wellbore. The commencement of these
operations was repeatedly delayed due to poor weather and a number of
electrical and hydraulic issues with the rig, which were subsequently
resolved. The cleanout of the wellbore was successfully completed, however
post cleanout the flow rates were only marginally higher than pre-cleanout
flow rates suggesting that the sand blockage affected final 1,000ft of the
wellbore had likely already been connected and contributing to the main
wellbore, probably through the fractures having been connected and in
communication with each other. The IP30 (average flow over 30 days)
production rate was calculated at c.505 barrels per day ("BPD") of liquid
hydrocarbons consisting of c.180 BOPD oil, c.325 BPD of condensate and natural
gas liquids ("NGLs"), along with c.2,300 mcfpd natural gas, after shrinkage.
Very importantly, this quantum of liquid and gas production was flowing
without artificial lift demonstrating better than expected reservoir
deliverability, which is positive and considered a significant de-risking
event for future Alkaid development.
It is believed that the Alkaid #2 well most likely fracked into a gas cap
which resulted in a much higher gas oil ratio ("GOR") than encountered at the
nearby Alkaid #1 well in the same reservoir. Analysis suggests that future
wells should be drilled a little deeper to avoid the gas cap and thus should
have the potential to produce a much improved GOR with a superior outcome.
Alkaid #2 was always designed as a production test well whose primary
objective was to gather information to assist in understanding the productive
capability of the reservoir and to assist in modelling and engineering future
development scenarios and commerciality. The decline rate at Alkaid #2 has
provided sufficient data to accurately model well performance and given the
significantly greater than expected gas production at Alkaid #2, likely as a
result of the intercepted gas cap, Pantheon has elected to not apply to the
State of Alaska for an extension of its gas flaring permit and thus has
concluded its flow testing operations of the zone of interest at Alkaid #2.
The wellbore will now be prepared for the future testing of the shallower
shelf margin deltaic ("SMD") in the vertical section of the wellbore.
During drilling to target depth, Alkaid #2 penetrated the shallower SMD
reservoir, which management estimates contains over 400 million barrels of oil
("mmbo") recoverable resource, over five times larger than the Alkaid
reservoir and with superior reservoir quality. The addition of these resources
to any potential Alkaid development will significantly boost economic
returns. Testing of oil and gas wells is always sequenced from deepest to
shallowest horizons, hence why SMD testing would always follow Alkaid testing.
Appointment of Independent non executive director
Pantheon announced the appointment of David Hobbs as an Independent
Non-Executive Director, effective 22 March 2023. Mr Hobbs is a Petroleum
Engineer with over 20 years experience in upstream oil and gas and 20 years
experience in strategy and energy policy.
Payment of quarterly amortization of convertible loan
In March 2023, Pantheon announced that it elected to pay (i) the quarterly
principal repayment of US$2.45 million and (ii) the interest payment
of US$0.392 million (collectively, the "Quarterly Repayment") in respect of
its senior unsecured convertible bonds due 2026 (the "Convertible Bonds"),
through the issuance of 9,257,328 new shares.
Issuance of 290,000 ordinary shares
In February 2023, Phillip Gobe, non-executive Chairman and a person
discharging managerial responsibility (PDMR) in the Company, was issued and
allotted 290,000 Ordinary Shares as a result of the conversion of 100% of his
previously granted 290,000 Restricted Stock Units ("RSUs"). Following the
completion of this allotment.
Other key appointments
Pantheon has appointed Tony Beilman, a petroleun engineer with over 40 years
experience in drilling, production and completions to the team. Tony's
appointment significantly strengthens Pantheon's operational capability.
Other key events
Pantheon as contracted SLB (nee Schlumberger ) to continue work on Phase 2 of
the reservoir dynamic model across the entire acreage and four reservoirs
within Pantheon's portfolio, and to manage the data room present for
prospective farminees.
Commissioning of Independent Expert Reports on Theta West and Alkaid
Pantheon has formally appointed Netherland Sewell & Associates, an
independent and highly reputable resource reporting firm, for the preparation
of Independent Experts Reports over its Theta West and Alkaid projects.
GLOSSARY
bbl barrel of oil mcfd thousand cubic feet per day
bopd barrels of oil per day Mmboe million barrels of oil equivalent
boepd barrels of oil equivalent per day NPV net present value
mcf thousand cubic feet $ United States dollar
bwpd barrels water per day
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