TIDMDGOC
RNS Number : 4573R
Diversified Gas & Oil PLC
08 March 2021
8 March 2021
DIVERSIFIED GAS & OIL PLC
("Diversified," "DGO" or the "Group")
Final Results for the Year Ended 31 December 2020
Diversified Gas & Oil PLC (LSE: DGOC) is pleased to announce
its annual results for the full-year ended 31 December 2020.
Key Highlights
-- December exit rate production of 103 MBoepd (617 MMcfepd), 8%
higher than 2019 exit (95 MBoepd)
Exceptionally low corporate annual decline rate of 7% including
both conventional and unconventional wells
DGO stands as the largest independent producer on the London
Stock Exchange ("LSE")
-- Hedged Adjusted EBITDA(1) of $301 million (up 10% over $273
million in 2019) bolstered by hedge cash settlements of $145
million that significantly offset low natural gas prices
Indicative of the improved natural gas pricing outlook that
creates a non-cash pre-tax mark-to-market hedge valuation loss of
$239 million, the Group reported a net loss of $23 million in 2020
(2019: $99 million net income inclusive of a pre-tax non-cash
mark-to-market hedge valuation gain of $20 million)
Adjusted Net Income of $175 million represents an 83% increase
over prior year (2019: $96 million) and excludes the mark-to-market
valuation change and other non-cash and non-recurring items
-- Adjusted Total Revenue (which includes $145 million of cash
hedge settlements) of $553 million was 8% higher in 2020 vs 2019
($512 million including $49 million of hedge cash settlements)
Total revenue (which excludes hedge settlements) of $409 million
in 2020 vs. $462 million in 2019 due to lower commodity prices in
2020 partially offset by higher production from our acquired
production (Carbon and EQT assets)
-- Cash Margin(1) of 54% driven by a 10% reduction in total cash
expenses(2) to $1.15/Mcfe ($6.92/Boe) and hedge cash
settlements
-- Dividend increased >14% with two consecutive quarterly raises during 2020
-- Recommending a final quarterly dividend of $0.04/share,
bringing the full-year 2020 dividend to $0.1525/share, 10% higher
than 2019 ($0.1392/share), supported by accretive growth of its
low-decline, long-life assets
Other Operational Highlights
-- Record full-year average daily net production of 100 MBoepd, up 18% vs 2019 (85 MBoepd)
Average daily production from conventional (Legacy(3) ) assets
consistent with 2019 at 69 MBoepd reflective of effective Smarter
Asset Management
-- Acquired and fully integrated $243 million (gross) of assets
which expand scale and reduce unit costs:
May 2020 conventional upstream and midstream assets from Carbon
($110 million) and primarily unconventional upstream assets from
EQT ($125 million)
4Q20 acquisition of five unconventional wells in Ohio for $8
million
-- ESG enhancements included broader leak detection and repair
programme and progress on further refining the Group's
comprehensive facilities inventory contributing to lower reported
emissions
-- Exceeded our 80-well annual well retirement commitment by
retiring 92 wells averaging $25K each
Proactively worked with regulators in Ohio to extend our
retirement agreement to 10-year term
Other Financial Highlights
-- Remain proactive and opportunistic to protect cash flows and
provide dividend stability through hedging:
90% of 2020 production protected by natural gas hedges, with
current forward hedge positions including:
-- 90% of 2021 natural gas hedged at a weighted average floor
price of $2.94/Mcfe ($2.67/MMBtu)
-- 65% of 1H2022 natural gas hedged at a weighted average floor
price of $2.84/Mcfe ($2.59/MMBtu)
-- Significant field operating efficiencies reduced total unit
cash costs inclusive of higher Adjusted G&A(1) . The additional
administrative expense supports the enlarged business, positions
the Group with a scalable corporate platform for additional growth
and reflects enhanced corporate governance following its transition
from AIM to the Premium Segment of the Main Market:
Base lease operating expense down 24%: $0.42/Mcfe ($2.53/Boe)
(2019: $0.55/Mcfe ($3.31/Boe)
Total operating expense down 15%: $0.93/Mcfe ($5.58/Boe) (2019:
$1.09/Mcfe ($6.54/Boe)
Adjusted G&A(1) expense up 14%: $0.22/Mcfe ($1.33/Boe)
(2019: $0.19/Mcfe ($1.17/Boe)
-- Distributions benefiting shareholders in 2020 totalled $115 million
Dividends paid in 2020: $99 million ($0.1425/share), up 5%
(2019: $0.1362/share)
Share repurchases: $16 million (13 million shares) (2019: $53
million)
-- Net Debt of $725 million resulting in Net Debt-to-Hedged
Adjusted EBITDA(1) of 2.2x at 31 December 2020
Debt reductions in 2020, adjusted for acquisitions, total $82
million, driven largely by repayments of scheduled amortising debt
structures
-- Year-end liquidity >$210 million
Full reaffirmation of $425 million borrowing base twice during
2020, despite volatile commodity price market, with no changes to
terms and full support of 17 lenders in the Credit Facility
Corporate Highlights
-- Successful move to the Main Market of the London Stock Exchange
-- Inclusion in FTSE250 Index
-- Established strategic partnership with Oaktree Capital
Management, L.P. who committed $1 billion to jointly identify and
fund future proved developed producing ("PDP") acquisition
opportunities as a non-operating working interest partner
For completed acquisitions, the Agreement compensates DGO
through an upfront promote and includes reversion interest
opportunities to the Group
-- Successful financings support growth platform: $200 million
(gross) asset securitisation to term out a portion of the Group's
revolving Credit Facility and the combination of an $85 million
(gross) share placing and $160 million (gross) 10-year amortising
secured term loan to primarily fund acquisitions during 2020
-- Significant ESG initiatives reflect stewardship emphasis and transparency:
Published inaugural year 2019 Sustainability Report with plans
to issue the Group's 2020 Sustainability Report in April 2021
Initiated comprehensive Enterprise Risk Management reviews
Initiated Task Force for Climate-related Disclosure reporting
practices
Adopted new corporate policies on human rights, environmental,
health and safety and corporate responsibility
1 This non-IFRS alternative performance measure referenced
throughout is defined and reconciled within the Group's Final
Results under the caption "Alternative Performance Measures".
2 Total cash expenses represent total operating expense plus
recurring general and administrative costs. Total operating expense
includes base lease operating expense, production taxes, midstream
operating expense and transportation expense. Recurring
administrative expenses is a non-IFRS financial measure defined as
total administrative expenses excluding non-recurring acquisition
& integration costs and non-cash equity compensation.
3 Legacy Assets owned as at 31 December 2018 and excluding the
Group's 2020 acquisitions of Carbon and EQT and 2019 acquisitions
of HG Energy and EdgeMarc.
Commenting on the results, CEO Rusty Hutson, Jr. said:
"I am exceptionally pleased with our results in 2020 as they
reflect the resilience of our business model and its proven ability
to consistently deliver shareholder value and returns, even in the
most challenging of markets. Our commitment to value-accretive
growth, operational excellence, cost discipline, and risk
mitigation drove the Group's solid performance through turbulent
times. Our long-standing strategy of focusing on low-risk assets
and reliable cash flows position DGO for further growth, and
enables us to maintain our firm commitment to shareholder returns,
evidenced by the increase in our per-share dividend, which we
raised twice, or 14%, during the year.
"With a business model grounded in asset and environmental
stewardship, we made significant strides in developing plans and
adopting disclosure frameworks aimed at improving our environmental
footprint. Additionally, we strengthened our track record of
accretive growth with the successful acquisitions of both upstream
and midstream assets, contributing to a consistent, strong cash
margin and enlarging our portfolio of Smarter Asset Management
opportunities on a base of assets with an exceptionally low
corporate decline rate of 7%. Our commitment to acquire low-decline
assets enables us to replace production declines with approximately
10% of our Adjusted EBITDA while meeting our operating and ESG
commitments, reducing our debt and making consistent quarterly
dividend payments to shareholders.
"Our move in May 2020 to the premium segment of the Main Market
and subsequent inclusion in FTSE250 reflects the evolution of our
business and enables us to solidify our position as the leading
independent producer on the LSE. Even so, with the shifting market
dynamics of the last few years, we are seeing a generational
opportunity to accelerate our accretive consolidation strategy, and
our strategic partnership with Oaktree Capital uniquely positions
us to capitalise on these opportunities, whether within or outside
the Appalachian Basin. The positive fundamentals and outlook for US
natural gas are creating a supportive tailwind, which gives us
confidence in our ability to sustain our dividend and create value
for our stakeholders."
Results Presentation and Audiocasts
DGO will host a conference call today at 2:00pm GMT (9:00am EST)
to discuss these results. The conference call details are as
follows:
US (toll-free) + 1 877 407 5976
UK (toll-free) + 44 (0)800 756 3429
Web Audio www.dgoc.com/news-events/events
Replay Information https://ir.dgoc.com/financial-info
Additionally, on 10 March 2021 at 6:00pm GMT (1:00pm EST), DGO
is pleased to host an investor webinar featuring CEO Rusty Hutson,
COO Brad Gray and CFO Eric Williams during which management will
discuss the full-year results. To register for the webinar, please
contact Yellowstone Advisory at info@yellowstoneadvisory.com, or
refer to the following link:
https://us02web.zoom.us/webinar/register/5816106105281/WN_u6UZAWCXTXaT_8uqF9rPEg
1 (205) 408
Diversified Gas & Oil PLC + 0909
Teresa Odom, Vice President, Investor Relations
www.dgoc.com
ir@dgoc.com
44 (0)20 7466
Buchanan + 5000
Financial Public Relations
Ben Romney
Chris Judd
Kelsey Traynor
James Husband
dgo@buchanan.uk.com
About Diversified Gas & Oil PLC
Diversified Gas & Oil PLC is an independent energy company
engaged in the production, marketing and transportation of
primarily natural gas related to its synergistic US onshore
upstream and midstream assets.
CHAIRMAN'S STATEMENT
I am delighted to report another year of tremendous progress for
the Group. Against both a challenging industry backdrop and the
extraordinary impact of the Covid-19 pandemic, our business model
has proven not only to be resilient and sustainable but also
extremely strong.
We have continued with the relentless focus on our strategy to
deliver consistent, profitable cash flow from our low-cost asset
base. During the year we made three accretive acquisitions which
have been successfully integrated. We also enhanced our borrowing
base with a securitised and fully-amortising financing, and entered
into an innovative joint arrangement with Oaktree Capital, which
positions us well for future acquisitions earning enhanced returns.
Our Smarter Asset Management programme has once again been
effective in maintaining steady production to offset natural
declines.
We successfully obtained admission of our shares to the Premium
Listing Segment of the Official List of the Financial Conduct
Authority and to trading on the Main Market of the LSE, and
subsequently entered the LSE FTSE 250 Index. In advance of this
move, and as reported last year, we appointed three new Independent
Non-Executive Directors to the Board. The current Board has seven
members, with four being independent. I am extremely pleased with
how the Board and Committees have functioned this year, in
particular given the difficulties of meeting in person. Each Board
member demonstrated a clear commitment to the Group and support for
its strategy while being willing to challenge each other as we
strive to continue building a business that benefits all
stakeholders. We appointed Leadership Advisor Group to conduct an
external Board Performance Review, and we will use their advice to
further examine our corporate governance and strategic thinking. At
present, two of our seven Board members (or approximately 30%) are
women. We are mindful of the recommendations of the
Hampton-Alexander Review and the Parker Review, and will be looking
to comply with them in the coming year as we strive to further
enhance our Board's diversity, experience, and knowledge base.
During the year we launched our inaugural Sustainability Report
which detailed the economic, environmental, social and governance
impacts of our activities. The report describes our firm commitment
to sustainability and to the communities in which we operate and
outlines our plans to remain fully engaged on these important
initiatives. We also embarked on a project with Critical Resource,
a global consultancy focused on climate strategies, to ensure that
our metrics and targets, as well as our governance, risk
management, and strategic planning align with the Task Force on
Climate Related Financial Disclosures ("TCFD") recommendations.
Additionally, we are examining investments in technology and
operational changes to help further reduce emissions, as well as
evaluating various offset measures with our target to achieve a net
zero carbon footprint by 2050. You can find additional details of
our ongoing sustainability efforts in our upcoming 2020
Sustainability Report.
We fully support the desire to reduce the world's carbon
emissions, and believe that our unique business model continues to
be well positioned to help us do so. Natural gas in the US has been
a major contributor to the substantial reductions in CO2 emissions
as energy supplies have switched from coal and oil. Future energy
demands must be met from multiple sources, including renewables,
nuclear, hydro, and our own low-carbon natural gas, which will
continue to be affordable and reliable. As such, we believe that
natural gas is an ideal partner to renewable energy sources like
wind and solar, thereby providing a solution to a more sustainable
world for future generations.
Our business model is based on sustainability. We are one of the
lowest cost operators in the industry, and we are well positioned
to perform in even the toughest of markets. We acquire undervalued
assets, that are non-core to other operators, and then focus on
optimising their productivity or usefulness until the end of their
natural lives. We are responsible operators with a commitment to
the safety of our employees and the public at large, the well-being
and vibrancy of the communities in which we live and work, and the
care of the natural world around us. This is what we do. As we
acquire more assets, we believe we can play a key role in improving
the environmental stewardship of them, as well as reducing the need
for further exploration and drilling elsewhere, with its resultant
impact on emissions and risk of stranded assets. We also continue
to embrace our responsibility to safely retire wells at the end of
their productive lives, and we've demonstrated this commitment to
the states in which we operate each year through our exceptional
well retirement programme.
Our extensive hedge portfolio and low-cost debt profile has
meant that our cash flow has remained stable and strong this year.
Combined with our accretive acquisitions, we increased our
quarterly dividend twice, and by 14% since the start of the year
from $0.0350 per share to $0.0400 per share. Accordingly, the Board
is recommending a final quarter dividend of $0.0400 per share,
making the total dividend attributable to the full-year $0.1525 per
share (2019: $0.1392 per share.) If approved, the final dividend
will be paid on 24 June 2021 to those shareholders on the register
on 28 May 2021.
This year was another very successful one for DGO, and I would
like to thank our executive team and all our employees for the hard
work and dedication that continues to drive our performance. They
represent the best in our industry and are a credit to the Group.
We understand the extraordinary impacts of the Covid-19 pandemic on
the personal lives of our employees and recognise that their
continued commitment has ensured we have not only delivered a
successful 2020 but are well positioned to continue to deliver the
long term sustainable success of our business. I also wish to thank
our shareholders, debt holders and other stakeholders for their
support. Looking ahead, the opportunities to continue our growth
are significant, and we are well placed to capitalise on them. We
along with the entire Diversified team will remain focused in 2021
and beyond on our strategy and continue to deliver sustainable
value to our shareholders.
David E. Johnson
Chairman of the Board
CHIEF EXECUTIVE'S STATEMENT
This past year was unlike any other in the history of our
company. In a year filled with global uncertainty, driven largely
by the Covid-19 pandemic, political unrest and economic disruption,
which led to the lowest NYMEX natural gas prices in 25 years, our
consistent performance and the strength of our business model
proved among the few certainties. From our founding nearly 20 years
ago, we've proactively and intentionally built our business to
reliably perform in any commodity price environment, and the result
of our strategic actions is demonstrated through our ability to
deliver significant financial results contrary to sector and
macro-economic headwinds. Deemed an essential business in the midst
of the pandemic, our company continues to successfully navigate the
new economic and social environment in which we now find ourselves.
Our success is reflective of a resilient, vertically integrated
business model and strategy executed by dedicated personnel, who
are focused on delivering strong operational and financial results,
resulting in significant shareholder value.
Our resilience demonstrates the solid foundations upon which DGO
is built. Our unwavering focus on opportunistic yet disciplined
acquisitive growth, portfolio optimisation and shareholder returns
differentiates us from our peers. The Board's commitment to
shareholder returns is resolved and represents a core principle of
our strategy and investment thesis. Currently, our dividend yield
is one of the most compelling amongst LSE listed companies,
evidenced by two dividend increases during a period when many of
our peers reduced or cancelled dividends, highlighting the strength
of our business model and the effectiveness of our execution.
A relentless focus on operational excellence across our
portfolio continues to serve as the bedrock of our stable
performance. During the year, our operations team delivered
impressive results through the successful application of our
Smarter Asset Management programme. Production remained steady
throughout the year as we effectively offset natural declines in
our portfolio through our operational techniques to optimise
production and to drive efficiency, and we achieved this result
while simultaneously reducing our emissions. These effective
operations continue to drive solid financial performance by
ensuring we remain a low-cost operator with clear visibility to
reliable cash flows. The capabilities of our midstream activities
continue to expand and were further bolstered by the acquisitions
in May, which increased opportunities for margin-enhancing
diversification, pricing optionality and third-party revenue
generation.
Even with the recovery and stabilisation of prices through the
fourth quarter of 2020 and into the start of 2021, the market
backdrop remains challenging for the natural gas industry. Despite
these headwinds, our business model gives us comfort, knowing that
we are uniquely positioned to make the most of the numerous
opportunities we see in the market today.
Positive momentum is building for natural gas pricing which
bodes well for our business. For many however, the positive
momentum may have come too late, and consolidation will be a
natural consequence. As a result, we continue to evaluate a robust
acquisition pipeline as we look to capitalise on market
opportunities, seeking value accretive growth.
With this backdrop, we established a major strategic partnership
through our agreement with Oaktree Capital. The agreement aligns us
with a strong partner with whom we can capitalise on the growing
pipeline of opportunities, both in the near-term and over the
long-term. The agreement validates our strategy, and helps to
expand our market intelligence and network through Oaktree's
unrivalled standing in the market. The partnership also strengthens
our acquisition bid credibility, and enables us to comfortably
pursue larger transactions that can deliver a measurable change in
accretive cash flow growth and shareholder returns. The deal
structure positions us to capture long-term value for our
shareholders as Oaktree's co-ownership of assets presents a
foreseeable inventory of acquisition opportunities whereby DGO, as
the operator of those assets, is the natural buyer when Oaktree
seeks to monetise its investment.
The strong position that we have established for ourself through
years of delivering results aligned with our stated commitments
leaves us well placed to maintain our growth trajectory. Financial
discipline at the corporate and operational levels remains a key
tenet to our strategy. We will seek to continue to maintain a
healthy balance sheet with appropriate liquidity to safeguard our
dividend, and reduce Leverage while working to capture prudent
growth opportunities.
I am very proud that we have been able to maintain our progress
through the economic and social challenges we faced during the last
year. The Board's focus on continuous improvement of all aspects of
governance has enabled us to take considerable strides forward and
provides a springboard for future growth. Our move to the Main
Market and subsequent inclusion in the FTSE 250 Index reflects our
evolution, maturity and growth into the largest independent
producer by volume on the London market, and I am excited for the
opportunities that lie ahead for our company.
Robert R. ("Rusty") Hutson Jr.
Chief Executive Officer
FINANCIAL REVIEW
A MESSAGE FROM OUR CHIEF FINANCIAL OFFICER
We have spoken to the challenges and opportunities that 2020
presented to companies across all sectors. I echo Rusty's pride in
our dedicated and talented employees who delivered exceptional
results. In a year marked by uncertainty and unprecedented
commodity demand and price volatility, we steadied ourselves,
remained focused on our strategic objectives and used the many
tools within our chest to advance our business while many companies
around us struggled. Ultimately, we achieved record production and
Hedged Adjusted EBITDA, closed three acquisitions, repaid
borrowings, and raised our dividend twice... all during a pandemic
and amidst the lowest natural gas commodity price environment we
have seen in the past two decades.
By design, we built Diversified to be resilient in even the most
challenging environments. Our strategy to acquire and nurture
mature producing assets not only affords us a stable positive Free
Cash Flow profile, but importantly it provides us with a highly
predictable and largely controllable cost structure that we can
comfortably hedge to secure healthy margins. If any series of
events were to reinforce the importance of responsible hedging, it
was those we witnessed during 2020, when we observed even the
largest, investment-grade established names within our industry
dramatically cut spending, reduce staffing, increase borrowings and
lower - or even eliminate - their dividends to shareholders. By
contrast, we not only expanded our team as we added additional
high-quality producing assets to our portfolio, but we also
responsibly managed our debt and increased our quarterly dividend
twice and by over 14% to $0.04 per share or $0.16 per share
annualised. In fact, since our IPO four years ago and demonstrating
the true accretive nature of our growth, we have increased our
per-share dividend nine times and grown it by nearly 70% compounded
annually.
The past few years, and 2020 in particular, have reinforced the
importance of hedging, which you have come to appreciate is part of
our strategic DNA. Our hedge portfolio extends more than a decade
to support each of our long-term, fixed rate and fully amortising
financing structures, which today comprise approximately 70% of our
total borrowings. We were rewarded handsomely for our decision to
hedge approximately 90% of our natural gas production this year,
receiving nearly $145 million in hedge proceeds that significantly
adds to our $409 million of total revenue. Not only were we able to
fund our growth, reduce our borrowings adjusting for acquisitions
and maintain a strong balance sheet, we also paid $99 million of
dividend distributions to our shareholders and repurchased $16
million of our outstanding shares.Recognising that acquiring
quality producing assets, rather than drilling and completing
wells, fuels our growth, we actively manage our balance sheet by
using a prudent mix of debt and equity financing to maintain
Leverage below our stated limit of 2.5x Net Debt-to-Hedged Adjusted
EBITDA. In fact, we ended 2020 and sit today at just 2.2x. During
2020, we were rewarded for our fiscal discipline with investors
willing to entrust additional debt and equity growth capital to DGO
when others had no access. We also enjoy a healthy and supportive
bank group and lenders like Munich Re and Nuveen, a TIAA company.
Not only did we term-out $200 million of borrowings on our Credit
Facility through a low-cost asset-backed securitisation, we
successfully raised $160 million of long-term financings and $85
million of equity proceeds to fund our acquisition of assets from
EQT Corporation, Carbon Energy Corporation and other sellers. We
also exited the year strong with a full re-affirmation of our $425
million Credit Facility borrowing base and more than $210 million
of liquidity.
Importantly, we enter 2021 with optimism underpinned by our past
success, lean operating costs, solid financial footing and an
enhanced platform following investments in people, processes and
technology to become a Premium Listed, Main Market company. We are
further encouraged to see higher commodity prices on the forward
curve as positive sentiment regarding natural gas' longer-term
outlook creates an improved price outlook. This optimism is
particularly impactful to us since natural gas comprises over 91%
of our production. In a higher price environment, not only will we
realise the full value of the hedged prices we locked as part of
our commitment to protect our cash flow, we'll also benefit from
higher market prices on our unhedged volumes.
As I turn to a discussion of our reported earnings, it is
important to link the positive price momentum I discussed to its
associated earnings impact. As we adjust our 10+ year derivative
portfolio to their fair values, we recognised a $239 million
non-cash charge that we report in our earnings, which represents
the change in the fair value of our entire unsettled hedge
portfolio from 31 December 2019 to 31 December 2020. This non-cash
valuation change primarily relates to higher prices on the forward
price curve for natural gas, and drives our $87 million gross
profit into a $137 million pre-tax loss. When excluding this
non-cash loss, just as we have excluded our valuation-related
non-cash gains in prior years, we report a $102 million pre-tax
gain compared to $131 million in 2019. Ultimately, while we report
a net loss in 2020 of $24 million compared to net income in 2019 of
$99 million, we grew Hedged Adjusted EBITDA by 10% to $301 million
compared to $273 million in 2019.
Protecting our cash flow and its payment of dividends and debt
will always be paramount. While hedging may, at times, cause us to
forgo upside to commodity prices, we believe our shareholders and
lenders value the high visibility into our distributions that
hedging affords us. Importantly and as I mentioned earlier, not
only do we stand to earn a healthy Cash Margin in 2021 from our
natural gas hedges' weighted average floor price of $2.93 per Mcf
compared to Total Cash Cost per Mcfe $1.15 ($6.92 per Boe), but
should prices settle higher than this value, the earnings and cash
flow on our unhedged volumes will increase. You will find the full
financial results of our operations in the following pages, which I
hope will be helpful as you review our performance.
In summary, 2021 is shaping up to be another exceptional year
for Diversified, and I look forward to serving alongside a team
eager to deliver the same excellence you have come to expect from
us.
Eric Williams
Chief Financial Officer
RESULTS OF OPERATIONS
Please refer to the APMs section for information on how these
metrics are calculated and reconciled to IFRS measures.
Year Ended
------------------------------------------
31 December 2020 31 December 2019 Change % Change
-------------------- -------------------- ---------- ----------
Net production
Natural gas (MMcf) 199,667 166,377 33,290 20%
NGLs (MBbls) 2,843 2,807 36 1%
Oil (MBbls) 417 407 10 2%
---------------- --------------- --- ---------- ------
Total production (MBoe) 36,538 30,944 5,594 18%
Average daily production (Boepd) 99,831 84,778 15,053 18%
% Natural gas (Boe basis) 91% 90%
Average realised sales price
(excluding impact of derivatives settled
in cash)
Natural gas (Mcf) $ 1.72 $ 2.31 $ (0.59) (26)%
NGLs (Bbls) 8.15 12.00 (3.85) (32)%
Oil (Bbls) 36.12 50.30 (14.18) (28)%
Total (Boe) $ 10.45 $ 14.16 $ (3.71) (26)%
Average realised sales price
(including impact of derivatives settled
in cash)
Natural gas (Mcf) $ 2.33 $ 2.47 $ (0.14) (6)%
NGLs (Bbls) 13.95 19.91 (5.96) (30)%
Oil (Bbls) 52.97 49.74 3.23 6%
Total (Boe) $ 14.40 $ 15.76 $ (1.36) (9)%
Revenue (in thousands)
Natural gas $ 343,425 $ 384,121 $ (40,696) (11)%
NGLs 23,173 33,685 (10,512) (31)%
Oil 15,064 20,474 (5,410) (26)%
---------------- --------------- --- ---------- ------
Total commodity revenue $ 381,662 $ 438,280 $ (56,618) (13)%
Midstream revenue 25,389 22,166 3,223 15%
Other revenue 1,642 1,810 (168) (9)%
---------------- --------------- --- ---------- ------
Total revenue $ 408,693 $ 462,256 $ (53,563) (12)%
============ =========== === ========= ======
Gain (loss) on derivative settlements
(in thousands)
Natural gas $ 121,077 $ 27,483 $ 93,594 341%
NGLs 16,498 22,214 (5,716) (26)%
Oil 7,025 (230) 7,255 (3154)%
---------------- --------------- --- ---------- ------
Net gain (loss) on derivative
settlements $ 144,600 $ 49,467 $ 95,133 192%
Adjusted Total Revenue $ 553,293 $ 511,723 $ 41,570 8.1%
============ =========== === ========= ======
Per Boe metrics
Average realised sales price
(including impact of derivatives
settled in cash) $ 14.40 $ 15.76 $ (1.36) (9)%
Other revenue 0.74 0.77 (0.03) (4)%
Base lease operating expense 2.53 3.31 (0.78) (24)%
Midstream operating expense 1.45 1.42 0.03 2%
Adjusted G&A 1.33 1.17 0.16 14%
Production taxes 0.38 0.53 (0.15) (28)%
Transportation expense 1.24 1.28 (0.04) (3)%
---------------- --------------- --- ---------- ------
Operating margin $ 8.21 $ 8.82 $ (0.61) (7)%
% Operating margin 54% 53%
Other financial metrics (in thousands)
Adjusted Net Income $ 174,786 $ 95,618 $ 79,168 82.8%
============ =========== === ========= ======
Operating profit (loss) $ (77,568) $ 180,507 $(258,075) (143)%
============ =========== === ========= ======
Income (loss) available to
shareholders after taxation $ (23,474) $ 99,400 $(122,874) (124)%
============ =========== === ========= ======
Production, Revenue and Hedging
Total revenue in the year ended 31 December 2020 of $409 million
decreased 12% from $462 million reported for the year ended 31
December 2019, primarily due to a 26% decrease in the average
realised sales price, partially offset by 18% higher production.
Including commodity hedge settlements of $145 million and $49
million in 2020 and 2019, respectively, Total Adjusted Revenue
increased by 8% to $553 million in 2020 from $512 million in
2019.
We sold approximately 36,538 MBoe in 2020 versus approximately
30,944 MBoe in 2019 with the increase driven by the full
integration of the previously acquired HG Energy and EdgeMarc
assets in 2019 and the Carbon and EQT assets we acquired in May
2020. Lower commodity prices drove our average realised sales
prices lower as reflected in the table below for the periods
presented:
(In thousands) Year Ended
----------------------------
31 December 31 December
2020 2019 $ Change % Change
------------- ------------- ---------- ----------
Henry Hub $ 2.08 $ 2.63 $ (0.55) (21)%
Belvieu 21.85 25.11 (3.26) (13)%
WTI 39.61 56.95 (17.34) (30)%
Refer to Note 5 in the Notes to the Group Financial Information
for additional information regarding our acquisitions.
Commodity Revenue
The following table reconciles the change in commodity revenue
(excluding the impact of hedges settled in cash) for the year ended
31 December 2020 by reflecting the effect of changes in volume and
in the underlying prices:
(In thousands) Natural
Gas NGLs Oil Total
----------- ---------- ------- -------------
Commodity revenue for the year
ended 31 December 2019 $ 384,121 $ 33,685 $20,474 $ 438,280
------- ------ ------ -------
Volume increase (decrease) 76,900 432 503 77,835
Price increase (decrease) (117,596) (10,944) (5,913) (134,453)
----------- ---------- ------- -----------
Net increase (decrease) (40,696) (10,512) (5,410) (56,618)
----------- ---------- ------- -----------
Commodity revenue for the year
ended 31 December 2020 $ 343,425 $ 23,173 $15,064 $ 381,662
======= ====== ====== =======
To manage our cash flows in a volatile commodity price
environment, we utilise derivative contracts which allow us to fix
the sales prices at a Boe level for approximately 90% of our
production to mitigate commodity risk. The tables below set forth
the commodity hedge impact on commodity revenue, excluding and
including cash received for commodity hedge settlements with
natural gas on a per Mcfe basis and NGLs and oil on a per Bbls
basis:
(In thousands,
except per unit
data) Year Ended 31 December 2020
--------------------------------------------------------------------------------------
Natural Gas NGLs Oil Total Commodity
-------------------- ------------------- ------------------- ----------------------
Realised Realised Realised Realised
Revenue $ Revenue $ Revenue $ Revenue $
-------- ---------- ------- ---------- ------- ---------- -------- ------------
Excluding hedge
impact $343,425 $ 1.72 $23,173 $ 8.15 $15,064 $ 36.12 $381,662 $ 10.45
Commodity
hedge
impact 121,077 0.61 16,498 5.80 7,025 16.85 144,600 3.95
-------- ---------- ------- ---------- ------- ---------- -------- ----------
Including hedge
impact $464,502 $ 2.33 $39,671 $ 13.95 $22,089 $ 52.97 $526,262 $ 14.40
======= ====== ====== ====== ====== ====== ======= ======
Year Ended 31 December 2019
--------------------------------------------------------------------------------------
Natural Gas NGLs Oil Total Commodity
-------------------- ------------------- ------------------- ----------------------
Realised Realised Realised Realised
Revenue $ Revenue $ Revenue $ Revenue $
-------- ---------- ------- ---------- ------- ---------- -------- ------------
Excluding hedge
impact $384,121 $ 2.31 $33,685 $ 12.00 $20,474 $ 50.30 $438,280 $ 14.16
Commodity
hedge
impact 27,483 0.16 22,214 7.91 (230) (0.56) 49,467 1.60
-------- ---------- ------- ---------- ------- ---------- -------- ----------
Including hedge
impact $411,604 $ 2.47 $55,899 $ 19.91 $20,244 $ 49.74 $487,747 $ 15.76
======= ====== ====== ====== ====== ====== ======= ======
Refer to Note 14 in the Notes to the Group Financial Information
for additional information regarding our hedging portfolio.
Expenses
(In thousands,
except
per unit data) Year Ended
--------------------------------------------------------------------------
Per Boe
Per Per Total Change Change
------------------- -----------------
31 31
December December
2020 Boe 2019 Boe $ % $ %
-------- ------ -------- ------ --------- -------- ------- --------
Base lease
operating
expense (a) $ 92,288 $ 2.53 $102,302 $ 3.31 $(10,014) (10)% $(0.78) (24)%
Production
taxes
(b) 13,705 0.38 16,427 0.53 (2,722) (17)% (0.15) (28)%
Midstream
operating
expense (c) 52,815 1.45 44,060 1.42 8,755 20% 0.03 2%
Transportation
expense
(d) 45,155 1.24 39,596 1.28 5,559 14% (0.04) (3)%
-------- ------ -------- ------ --------- ---- ------- ----
Total operating
expense $203,963 $ 5.58 $202,385 $ 6.54 $ 1,578 1% $(0.96) (15)%
Base G&A (e) 47,181 1.29 36,073 1.17 11,108 31% 0.12 10%
Non-recurring
and/or
non-cash G&A
(f) 30,053 0.82 19,816 0.64 10,237 52% 0.18 28%
-------- ------ -------- ------ --------- ---- ------- ----
Total operating
and
G&A expense $281,197 $ 7.70 $258,274 $ 8.35 $ 22,923 9% $(0.65) (8)%
Depreciation,
depletion
and
amortisation 117,290 3.21 98,139 3.17 19,151 20% 0.04 1%
Allowance for
credit
losses (g) 8,490 0.23 730 0.02 7,760 100% 0.21 100%
-------- ------ -------- ------ --------- ---- ------- ----
Total expenses $406,977 $11.14 $357,143 $11.54 $ 49,834 14% $(0.40) (3)%
======= ===== ======= ===== ======== ==== ====== ====
(a) Base lease operating expense is defined as the sum of
employee and benefit expenses, well operating expense (net),
automobile expense and insurance cost.
(b) Production taxes include severance and property taxes.
Severance taxes are generally paid on natural gas, NGLs and oil
production at fixed rates established by federal, state or local
taxing authorities. Property taxes are generally based on the
taxing jurisdictions' valuation of our natural gas and oil
properties and midstream assets.
(c) Midstream operating expenses are daily costs incurred to
operate our owned midstream assets inclusive of employee and
benefit expenses.
(d) Transportation expenses are daily costs incurred to third
parties to gather, process and transport the Group's natural gas,
NGLs and oil.
(e) Base G&A includes payroll and benefits for our
administrative and corporate staff, costs of maintaining
administrative and corporate offices, costs of managing our
production operations, franchise taxes, public company costs,
non-cash equity issuance, fees for audit and other professional
services, and legal compliance.
(f) Non-recurring and/or non-cash G&A includes costs related
to acquisitions, our up-list to the Main Market of the LSE, hedge
modifications, non-cash equity compensation and one-time
projects.
(g) Allowance for credit losses consists of expected credit
losses and a non-recurring increase in the reserve of joint
interest owner receivable.
Our value-focused growth and disciplined operating approach
reduced per unit expenses by 3%, or $0.40 per Boe, including:
-- Lower per Boe base lease operating expenses, which declined
24%, or $0.78 per Boe, through a mixture of disciplined cost
reductions and economies of scale, whereby fixed operating costs
were spread across a larger base of producing assets;
-- Lower per Boe production taxes, which declined 28%, or $0.15
per Boe, primarily due to a decrease in severance taxes as a result
of a decrease in revenue. Declines also resulted from taxes on our
midstream assets, that are generally fixed, being spread across a
larger base of producing assets; and
-- Lower per Boe transportation expense related to efficiencies
of scale gained on the fixed cost components associated with
transportation expense.
Partially offsetting the per Boe declines were increases due
to:
-- Higher per Boe midstream operating expense, which increased
2%, or $0.03 per Boe, primarily due to increases in the size of our
midstream workforce to meet the needs of the expanded midstream
capabilities gained in the Carbon and EQT acquisitions;
-- Higher Adjusted G&A as a result of investments made in
staff and systems to support our enlarged operation; and
-- Higher non-recurring and/or non-cash G&A due to costs
associated with our transition from listing on AIM to the Premium
Segment of the Main Market on the LSE, acquisition and integration
expenses related to Carbon and EQT, and costs to modify certain
derivative contracts.
Refer to Notes 5 and 14 in the Notes to the Group Financial
Information for additional information regarding our acquisitions
and derivative contracts, respectively.
Derivative Financial Instruments
We recorded the following gain (loss) on derivative financial
instruments in the Consolidated Statement of Comprehensive Income
for the periods presented:
(In thousands) Year Ended
----------------------------------------------------
31 December 31 December
2020 2019 $ Change % Change
------------- ------------- ---------- ----------
Net gain (loss) on commodity
derivatives (a) $ 144,600 $ 49,467 $ 95,133 192%
Net gain (loss) on interest
rate swap (202) - (202) (100)%
Gain on foreign currency hedge - 4,117 (4,117) (100)%
------------- ------------- ---------- ------
Total gain (loss) on settled
derivative instruments $ 144,398 $ 53,584 90,814 169%
Gain (loss) on fair value
adjustments of unsettled financial
instruments (b) (238,795) 20,270 (259,065) (1278)%
------------- ------------- ---------- ------
Total gain (loss) on derivative
financial instruments $ (94,397) $ 73,854 $(168,251) (228)%
========= ========= ========= ======
(a) Represents the cash settlement of hedges that settled during the period.
(b) Represents the change in fair value of financial instruments
net of removing the carrying value of hedges that settled during
the period.
For the year ended 31 December 2020, the total loss on
derivative financial instruments of $94 million decreased by $168
million compared to a gain of $74 million in 2019. Adjusting our
unsettled derivative contracts to their fair values drove a loss of
$239 million in 2020, a decrease of $259 million, as compared to a
gain of $20 million in 2019.
While the change in fair value is significant and reflective of
higher prices on the forward price curve, our derivative contracts
position us to not only fully realise the healthy cash flows we
hedged but also earn higher cash flow on our unhedged
production.
Additionally, a large portion of the unsettled hedge loss
relates to time option value of our long-dated portfolio.
Specifically, approximately $70 million of the $166 million net
liability reflected on our balance sheet relates to the time value
rather than their settlement value based on the current futures
price strip.
Offsetting the non-cash valuation loss was a cash gain of $144
million on settled derivative instruments for the year ended 31
December 2020, an increase of $91 million over 2019.
For the year ended 31 December 2020, the gain on settled
derivative instruments, representing 26% of Adjusted Total Revenue,
validates our hedge portfolio objective to provide downside
commodity risk protection. While year-end 2020 prices experienced
modest recovery, the rising forward price curve results in a shift
of our overall, long-dated derivative contract portfolio from an
asset to a liability. For 2021, we have significant downside
protection, including approximately 90% of our natural gas
production hedged at a weighted average floor price of $2.93 per
Mcfe, securing our cash flows, future dividend distributions and
debt repayments.
Refer to Note 14 in the Notes to the Group Financial Information
for additional information regarding our derivative financial
instruments.
Gain on Bargain Purchase
We recorded the following gains on bargain purchase in the
Consolidated Statement of Comprehensive Income for the periods
presented:
(In thousands) Year Ended
----------------------------------------------------
31 December 31 December
2020 2019 $ Change % Change
------------- ------------- ---------- ----------
Gain on bargain purchase $ 17,172 $ 1,540 $ 15,632 1,015%
========= ========= ====== ======
While gains on bargain purchases are uncommon, the E&P
segment of the broader energy sector has been in a period of
transition and rebalancing for the past few years, creating
opportunities for healthy companies like Diversified to acquire
high quality assets for less than their fair values. We have
established a track record of being disciplined in our bidding to
acquire assets that meet our strict asset profile and are accretive
to our overall corporate value.
Refer to Note 5 in the Notes to the Group Financial Information
for additional information regarding our acquisitions and bargain
purchase gains.
Finance Costs
(In thousands) Year Ended
31 December 31 December
2020 2019 $ Change % Change
------------- ------------- ---------- ----------
Interest expense, net of capitalised
and income amounts $ 34,391 $ 32,662 $ 1,729 5%
Amortisation of discount and
deferred finance costs 8,334 3,875 4,459 115%
Other 602 130 472 363%
------------- ------------- ---------- -----
Total finance costs $ 43,327 $ 36,667 $ 6,660 18%
========= ========= ====== =====
For the year ended 31 December 2020, interest expense on
borrowings of $34 million increased $2 million compared to $33
million in 2019, primarily due to the increase in borrowings used
to fund our previously mentioned acquisitions. As of 31 December
2020 and 2019, total borrowings were $746 million and $645 million,
respectively. For the year ended 31 December 2020, the weighted
average interest rate on borrowings was 4.70% as compared to 4.52%
in 2019, as a result of entering into additional fixed rate
financing structures as we sought to capitalise on depressed
markets and secure advantageous financing.
The increase in other finance costs was primarily due to an
increase in interest expense on leases. During the year ended 31
December 2020, we expanded our fleet and transitioned owned
vehicles to a fleet management lease programme.
Refer to Notes 5, 21, and 22 in the Notes to the Group Financial
Information for additional information regarding our acquisitions,
capital leases and borrowings, respectively.
Taxation
The effective tax rate is calculated on the face of the
Statement of Comprehensive Income by dividing income (loss) before
taxation by the amount of recorded income tax benefit (expense) as
follows:
(In thousands) Year Ended
-------------------------------------------------------
31 December 31 December
2020 2019 $ Change % Change
-------------- --------------- ---------- ----------
Income (loss) before
taxation $(136,740) $ 131,491 $(268,231) (204)%
Income tax benefit (expense) 113,266 (32,091) 145,357 (453)%
---------- -----------
Effective tax rate 82.8% 24.4%
========== ===========
The differences between the statutory US federal income tax rate
and the effective tax rates are summarised as follows:
Year Ended
----------------------------
31 December 31 December
2020 2019
------------- -------------
Expected tax at statutory US federal income
tax rate 21.0% 21.0%
State income taxes, net of federal tax benefit 5.4% 6.0%
Federal credits 58.8% (5.3)%
Other, net (2.4)% 2.7%
-------- --------
Effective tax rate 82.8% 24.4%
======== ========
For the year ended 31 December 2020, we reported a tax benefit
of $113 million, a change of $145 million, compared to an expense
of $32 million in 2019. The resulting effective tax rates for the
years ended 31 December 2020 and 2019 were 83% and 24%,
respectively. The effective tax rate is primarily impacted by
recognition of the federal well tax credit available to qualified
producers in 2020, who operate lower-volume wells during a low
commodity pricing environment. The federal government provides
these credits to encourage companies to continue producing
lower-volume wells during periods of low prices to maintain the
underlying jobs they create and the state and local tax revenues
they generate for communities to support schools, social
programmes, law enforcement and other similar public services.
Refer to Note 8 in the Notes to the Group Financial Information
for additional information regarding taxation.
Operating Profit, Net Income, EPS, Adjusted Net Income, Adjusted
EPS and Hedged Adjusted EBITDA
(In thousands, except per unit
amounts) Year Ended
31 December 31 December
2020 2019 $ Change % Change
------------- ------------- ---------- ----------
Operating profit (loss) $ (77,568) $ 180,507 $(258,075) (143)%
Income (loss) available to shareholders
after taxation (23,474) 99,400 (122,874) (124)%
Adjusted Net Income 174,786 95,618 79,168 83%
Hedged Adjusted EBITDA 300,590 273,266 27,324 10%
Earnings (loss) per share - diluted $ (0.03) $ 0.15 $ (0.18) (120)%
Adjusted EPS - diluted 0.25 0.15 0.10 67%
Hedged Adjusted EBITDA per Share
- diluted 0.44 0.42 0.02 5%
For the year ended 31 December 2020, we reported a net loss of
$23 million and a loss per share of $0.03 compared to income of $99
million and EPS of $0.15 in 2019, a decrease of 124% and 120%,
respectively. We also reported an operating loss of $78 million
compared with an operating profit of $181 million for the year
ended 31 December 2020 and 2019. This year-over-year decline in net
income was attributable to a mark-to-market loss of $239
million.
Excluding the mark-to-market loss as well as other non-cash and
non-recurring items, we reported Adjusted Net Income of $175
million and Adjusted EPS of $0.25 per share compared to Adjusted
Net Income of $96 million and Adjusted EPS of $0.15 per share in
2019, increases of 83% and 67%, respectively.
Additional adjustments for depletion, depreciation,
amortisation, interest, and taxes resulted in Hedged Adjusted
EBITDA of $301 million and Hedged Adjusted EBITDA per Share of
$0.44 compared to $273 million and $0.42 in 2019, representing
increases of 10% and 5%, respectively. The increases in Adjusted
Net Income and Hedged Adjusted EBITDA metrics year-over-year were
driven by a strong execution of our stated strategy, resulting in
consistent growth of earnings at the share level.
Refer to Note 9 in the Notes to the Group Financial Information
for information regarding Adjusted Net Income, Adjusted EPS, and
Hedged Adjusted EBITDA. Please refer to the APMs section for
information on how these metrics are calculated and reconciled to
IFRS measures.
LIQUIDITY AND CAPITAL RESOURCES
Our principal sources of liquidity have historically been cash
generated from operating activities. To minimise financing costs,
we apply our excess cash flow to reduce borrowings on our Credit
Facility. When we acquire assets to grow, we complement our Credit
Facility with long-term, fixed-rate, fully-amortising debt
structures that better match the long-life nature of our assets.
These structures not only afford us lower interest rates than more
traditional E&P financing like high-yield bonds, but also
provide a visible path for reducing leverage as we make scheduled
principal payments. For larger acquisitions, and to ensure we
maintain a leverage profile that we believe is appropriate for the
type of assets we acquire, we will also raise equity proceeds
through a secondary offering.
We monitor our working capital to ensure that the levels remain
adequate to operate the business with excess cash primarily being
utilised for the repayment of debt or shareholder distributions. In
addition to working capital management, we have a disciplined
approach to managing operating costs and allocating capital
resources, ensuring that we are generating return on our capital
investments to support the strategic initiatives in our business
operations.
(In thousands) Year Ended
---------------------------------------------------
31 December 31 December
2020 2019 $ Change % Change
------------- ------------- --------- ----------
Net cash provided by operating
activities $ 241,710 $ 279,156 $(37,446) (13)%
Net cash used in investing
activities (256,863) (466,887) 210,024 (45)%
Net cash provided by financing
activities 14,871 188,020 (173,149) (92)%
------------- ------------- --------- ------
Net change in cash and cash
equivalents $ (282) $ 289 $ (571) (198)%
=== ======== === ======== ======== ======
Net Cash Provided by Operating Activities
For the year ended 31 December 2020, net cash provided by
operating activities of $242 million decreased $37 million, or 13%,
as compared to $279 million in 2019. The reduction in net cash
provided by operating activities was predominantly attributable to
the following:
-- A decrease in revenue, largely offset by an increase in settlements of hedges;
-- An increase in Adjusted G&A for investments in staffing and systems to support our growth;
-- An increase in non-recurring and/or non-cash G&A
associated with a variety of items including (1) the costs to
transition from our AIM listing to a Premium Listing on the Main
Market of the LSE, (2) acquisition and integration expenses related
to Carbon and EQT, and (3) derivative commodity contract
modifications costs associated with our ABS II financing and with
similar portfolio optimisation initiatives; and
-- The timing of working capital payments and receipts.
Refer to Notes 5 and 14 in the Notes to the Group Financial
Information for additional information regarding our acquisitions
and derivative financial instruments, respectively.
Net Cash Used in Investing Activities
For the year ended 31 December 2020, net cash used in investing
activities of $257 million decreased $210 million, or 45%, from
$467 million in 2019. The change in net cash used in investing
activities was primarily attributable to the following:
-- For the year ended 31 December 2020, we paid cash purchase
consideration of approximately $100 million and $123 million for
business combinations (Carbon) and asset acquisitions (primarily
EQT), respectively. For the year ended 31 December 2019, we paid
purchase consideration of $439 million for business combinations
(primarily HG Energy & Edgemark). Refer to Note 5 in the Notes
to the Group Financial Information for additional information
regarding our acquisitions.
-- Capital expenditures were $22 million for the year ended 31
December 2020 compared to $32 million for the year ended 31
December 2019. Prior-year expenditures included "Project Delta,"
our system modernisation initiative whereby we planned, designed,
tested, and implemented a network of accounting, production, land
and measurement systems into a single data platform. Having
completed most of that work during 2019, we had less similar
expenditures in 2020.
-- Restricted cash increased by $7 million year-over-year as a
result of the interest expense reserve required by our long-term
financing agreements including ABS I, ABS II and Term Loan
financing. For more information refer to Note 3 in the Notes to the
Group Financial Information.
-- Investments were made in our marketing and operations groups
in 2020 as we looked to expand these to better manage our growth.
We invested in two service providers that had previously been
providing contracting services for us. These acquisitions resulted
in a cash outflow of $3 million. For more information refer to Note
13 in the Notes to the Group Financial Information.
Net Cash Provided by Financing Activities
For the year ended 31 December 2020, net cash provided by
financing activities of $15 million decreased $173 million, or 92%,
as compared to $188 million in FY19. The change in net cash
provided by financing activities was primarily attributable to the
following:
-- Our Credit Facility activity resulted in net repayments of
$223 million in 2020 versus net repayments of $59 million in 2019,
with much of the increase attributed to a $200 million refinancing
of Credit Facility borrowings through ABS II;
-- Proceeds from borrowings, net of repayments, on our new debt
facilities were $318 million in 2020, an increase of $112 million
as compared to 2019;
-- A decrease of $140 million in proceeds from equity issuances
that raised $81 million in 2020 as compared to $222 million raised
in 2019.
-- An increase of $16 million in dividends paid in 2020 as compared to 2019; and
-- A decrease of $37 million in the repurchase of shares in 2020 as compared to 2019.
Refer to Notes 17, 19 and 22 in the Notes to the Group Financial
Information for additional information regarding share capital,
dividends and borrowings, respectively.
GROUP FINANCIAL INFORMATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Amounts in thousands, except per share and per unit data)
Audited as at
------------------------------
Year Ended
------------------------------
31 December 31 December
Note 2020 2019
---- ------------- ---------------
Revenue 6 $ 408,693 $ 462,256
Operating expense 7 (203,963) (202,385)
Depreciation, depletion and amortisation 7 (117,290) (98,139)
------------- -------------
Gross profit 87,440 161,732
General and administrative expense 7 (77,234) (55,889)
Allowance for expected credit losses 15 (8,490) (730)
Gain (loss) on natural gas and oil programme
and equipment 12 (2,059) -
Gain (loss) on derivative financial instruments 14 (94,397) 73,854
Gain on bargain purchase 5 17,172 1,540
------------- -------------
Operating profit (loss) (77,568) 180,507
Finance costs 22 (43,327) (36,667)
Accretion of asset retirement obligation 20 (15,424) (12,349)
Other income (expense) (421) -
------------- -------------
Income (loss) before taxation (136,740) 131,491
Income tax benefit (expense) 8 113,266 (32,091)
------------- -------------
Income (loss) available to shareholders
after taxation (23,474) 99,400
Other comprehensive income (loss) (28) -
------------- -------------
Total comprehensive income (loss) for
the year $ (23,502) $ 99,400
========= === ========
Earnings (loss) per share - basic 10 $ (0.03) $ 0.15
Earnings (loss) per share - diluted 10 $ (0.03) $ 0.15
Weighted average shares outstanding -
basic 10 685,170 641,666
Weighted average shares outstanding -
diluted 10 688,348 644,782
The notes are an integral part of this Group Financial
Information.
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
(Amounts in thousands, except per share and per unit data)
Audited as at
------------------------------
31 December 31 December
Note 2020 2019
---- ------------- ---------------
ASSETS
Non-current assets:
Natural gas and oil properties, net 11 $ 1,755,085 $ 1,496,029
Property, plant and equipment, net 12 382,103 320,953
Intangible assets 13 19,213 15,981
Restricted cash 3 20,100 6,505
Derivative financial instruments 14 717 3,803
Deferred tax asset 8 14,777 -
Other non-current assets 16 4,213 2,309
------------- -------------
Total non-current assets $ 2,196,208 $ 1,845,580
--------- ---------
Current assets:
Trade receivables, net 15 $ 66,991 $ 73,924
Cash and cash equivalents 3 1,379 1,661
Restricted cash 3 250 1,207
Derivative financial instruments 14 17,858 73,705
Other current assets 16 7,996 9,863
------------- -------------
Total current assets $ 94,474 $ 160,360
--------- ---------
Total assets $ 2,290,682 $ 2,005,940
--------- ---------
EQUITY AND LIABILITIES
Shareholders' equity:
Share capital 17 $ 9,520 $ 8,800
Share premium 17 841,159 760,543
Merger reserve (478) (478)
Capital redemption reserve 592 518
Share-based payment reserve 8,683 3,907
Retained earnings 27,182 164,845
------------- -------------
Total equity $ 886,658 $ 938,135
--------- ---------
Non-current liabilities:
Asset retirement obligations 20 $ 344,242 $ 196,871
Leases 21 13,865 1,015
Borrowings 22 652,281 598,778
Deferred tax liability 8 15,746 124,112
Derivative financial instruments 14 168,524 15,706
Other non-current liabilities 24 12,860 4,468
------------- -------------
Total non-current liabilities $ 1,207,518 $ 940,950
--------- ---------
Current liabilities:
Trade and other payables 23 $ 19,366 $ 17,052
Leases 21 5,013 798
Borrowings 22 64,959 23,723
Derivative financial instruments 14 15,858 -
Other current liabilities 24 91,310 85,282
------------- -------------
Total current liabilities $ 196,506 $ 126,855
--------- ---------
Total liabilities $ 1,404,024 $ 1,067,805
--------- ---------
Total equity and liabilities $ 2,290,682 $ 2,005,940
========= =========
The notes are an integral part of this Group Financial
Information.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Amounts in thousands, except per share and per unit data)
Capital Share-Based
Share Share Merger Redemption Payment Retained Total
Note Capital Premium Reserve Reserve Reserve Earnings Equity
Balance at 31
December
2018 $ 7,346 $540,655 $ (478) $ - $ 842 $ 200,498 $748,863
===== ======= ===== ==== ====== === ======== ======= =======
Income (loss)
after
taxation - - - - - 99,400 99,400
Other
comprehensive
income (loss) - - - - - - -
--------- -------- --------- ------------ ------------- ----------- --------
Total
comprehensive
income (loss) - - - - - 99,400 99,400
--------- -------- --------- ------------ ------------- ----------- --------
Issuance of
share
capital 17 1,972 219,888 - - - - 221,860
Equity
compensation - - - - 3,065 - 3,065
Repurchase of
shares 17 (518) - - 518 - (52,902) (52,902)
Dividends 19 - - - - - (82,151) (82,151)
--------- -------- --------- ------------ ------------- ----------- --------
Transactions
with
shareholders 1,454 219,888 - 518 3,065 (135,053) 89,872
--------- -------- --------- ------------ ------------- ----------- --------
Balance at 31
December
2019 $ 8,800 $760,543 $ (478) $ 518 $ 3,907 $ 164,845 $938,135
===== ======= ===== ==== ====== === ======== ======= =======
Income (loss)
after
taxation - - - - - (23,474) (23,474)
Other
comprehensive
income (loss) - - - - - (28) (28)
--------- -------- --------- ------------ ------------- ----------- --------
Total
comprehensive
income (loss) - - - - - (23,502) (23,502)
--------- -------- --------- ------------ ------------- ----------- --------
Issuance of
share
capital 17 791 80,616 - - - - 81,407
Equity
compensation 3 - - - 4,776 - 4,779
Repurchase of
shares 17 (74) - - 74 - (15,634) (15,634)
Dividends 19 - - - - - (98,527) (98,527)
--------- -------- --------- ------------ ------------- ----------- --------
Transactions
with
shareholders 720 80,616 - 74 4,776 (114,161) (27,975)
--------- -------- --------- ------------ ------------- ----------- --------
Balance at 31
December
2020 $ 9,520 $841,159 $ (478) $ 592 $ 8,683 $ 27,182 $886,658
===== ======= ===== ==== ====== === ======== ======= =======
The notes are an integral part of this Group Financial
Information.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Amounts in thousands, except per share and per unit data)
Audited as at
------------------------------
Year Ended
------------------------------
31 December 31 December
Note 2020 2019
----- ------------- ---------------
Cash flows from operating activities:
Income (loss) after taxation $ (23,474) $ 99,400
Cash flows from operations reconciliation:
Depreciation, depletion and amortisation 7 117,290 98,139
Accretion of asset retirement obligations 20 15,424 12,349
Income tax (benefit) expense (113,266) 32,091
(Gain) loss on fair value adjustments
of unsettled financial instruments 14 238,795 (20,270)
Plugging costs of asset retirement obligations 20 (2,442) (2,541)
(Gain) loss on natural gas and oil programme
and equipment 1,356 -
(Gain) on bargain purchase 5 (17,172) (1,540)
Finance costs 22 43,327 36,667
Revaluation of contingent consideration 5 567 -
Hedge modifications 14 (7,723) -
Non-cash equity compensation 7 5,007 3,065
Working capital adjustments:
Change in trade receivables 2,390 4,528
Change in other current assets 1,958 2,606
Change in other assets (1,173) 409
Change in trade and other payables (4,772) 7,669
Change in other current and non-current
liabilities (8,532) 8,573
------------- -------------
Cash generated from operations 247,560 281,145
Cash paid for income taxes (5,850) (1,989)
------------- -------------
Net cash provided by operating activities 241,710 279,156
------------- -------------
Cash flows from investing activities:
Consideration for Business Acquisitions,
net of cash acquired 5 (100,138) (439,272)
Consideration for Acquisition of Assets 5 (122,953) -
Expenditures on natural gas and oil
properties and equipment 11,12 (21,947) (32,313)
(Increase) decrease in restricted cash (12,637) (5,302)
Proceeds on disposals of natural gas
and oil properties and equipment 12 3,712 10,000
Other acquired intangibles 13 (2,900) -
------------- -------------
Net cash used in investing activities (256,863) (466,887)
------------- -------------
Cash flows from financing activities:
Repayment of borrowings 22 (705,314) (618,010)
Proceeds from borrowings 22 799,650 765,236
Financing expense (34,335) (32,715)
Cost incurred to secure financing (7,799) (11,574)
Proceeds from equity issuance, net 81,407 221,860
Principal element of lease payments 20 (3,684) (1,724)
Contingent consideration payments 5 (893) -
Dividends to shareholders 19 (98,527) (82,151)
Repurchase of shares (15,634) (52,902)
------------- -------------
Net cash provided by financing activities 14,871 188,020
------------- -------------
Net change in cash and cash equivalents (282) 289
Cash and cash equivalents, beginning
of period 1,661 1,372
------------- -------------
Cash and cash equivalents, end of period $ 1,379 $ 1,661
========= === ========
The notes are an integral part of this Group Financial
Information.
NOTES TO THE GROUP FINANCIAL INFORMATION
(Amounts in thousands, except per share and per unit data)
INDEX TO THE NOTES TO THE GROUP FINANCIAL INFORMATION
--------------------------------------------------------
Note 1 - General Information
Note 2 - Basis of Preparation
Note 3 - Significant Accounting Policies
Note 4 - Significant Accounting Judgements and Estimates
Note 5 - Acquisitions
Note 6 - Revenue
Note 7 - Expenses by Nature
Note 8 - Taxation
Note 9 - Adjusted Net Income and Hedged Adjusted EBITDA
Note 10 - Earnings (Loss) Per Share
Note 11 - Natural Gas and Oil Properties
Note 12 - Property, Plant and Equipment
Note 13 - Intangible Assets
Note 14 - Derivative Financial Instruments
Note 15 - Trade and Other Receivables
Note 16 - Other Assets
Note 17 - Share Capital
Note 18 - Non-Cash Share-Based Compensation
Note 19 - Dividends
Note 20 - Asset Retirement Obligations
Note 21 - Leases
Note 22 - Borrowings
Note 23 - Trade and Other Payables
Note 24 - Other Liabilities
Note 25 - Fair Value and Financial Instruments
Note 26 - Financial Risk Management
Note 27 - Contingencies
Note 28 - Related Party Transactions
Note 29 - Subsequent Events
NOTE 1 - GENERAL INFORMATION
Diversified Gas & Oil PLC (the "Parent") and its wholly
owned subsidiaries (the "Group") is a natural gas, NGLs and oil
producer and midstream operator that is focused on acquiring and
operating mature producing wells with long-life low-decline
profiles. The Group's assets are exclusively located within the
Appalachian Basin of the US. The Group is domiciled in the UK and
headquartered in Birmingham, Alabama, US, with field offices
located in the states of Pennsylvania, Ohio, West Virginia,
Kentucky, Virginia and Tennessee.
The Parent was incorporated on 31 July 2014 in England and Wales
as a public limited company under company number 09156132. The
Group's registered office is located at 4th floor Reading Bridge
House, George Street, Reading, Berkshire, RG1 8LS, UK.
In February 2017, the Group's shares were admitted to trading on
AIM under the ticker "DGOC." In May 2020, the Group's shares were
admitted to trading on the LSE's Main Market for listed securities.
The shares trading on AIM were cancelled concurrent to their
admittance on the LSE.
NOTE 2 - BASIS OF PREPARATION
Basis of Preparation
The Group's consolidated financial statements (the "Group
Financial Information") has been prepared in accordance with both
international accounting standards in conformity with the
requirements of the Companies Act 2006 and IFRS adopted pursuant to
Registration (EC) No 1606/2002 as it applies in the EU. The
principal accounting policies are set out below and have been
applied consistently throughout the year
Unless otherwise stated, the Group Financial Information is
presented in US Dollars, which is the Group's subsidiaries'
functional currency and the currency of the primary economic
environment in which the Group operates, and all values are rounded
to the nearest thousand dollars except per share and per unit
amounts and where otherwise indicated.
Transactions in foreign currencies are translated into US
Dollars at the rate of exchange on the date of the transaction.
Monetary assets and liabilities denominated in foreign currencies
are translated at the exchange ruling at the date of the
Consolidated Statement of Financial Position. Where the Group has a
different functional currency, its results and financial position
are translated into the presentation currency as follows:
-- Assets and liabilities for each Consolidated Statement of
Financial Position presented are translated at the closing rate at
the date of that Consolidated Statement of Financial Position;
-- Income and expenses in the Consolidated Statement of
Comprehensive Income are translated at average exchange rates
(unless this is not a reasonable approximation of the cumulative
effect of the rates prevailing on the transaction dates, in which
case income and expenses are translated at the dates of the
transactions); and
-- All resulting exchange differences are reflected within other
comprehensive income in the Consolidated Statement of Comprehensive
Income.
The Group Financial Information has been prepared under the
historical cost convention, as modified by the revaluation of
financial assets and liabilities (including derivative instruments)
held at fair value through profit and loss or through other
comprehensive income.
Going concern
The Group Financial Information 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, taking into account
the Directors' assessment of the financial and trading effects of
the Covid-19 pandemic. The Directors have reviewed the Group's
overall position and outlook and are of the opinion that the Group
is sufficiently well funded to be able to operate as a going
concern for at least the next twelve months.
The Directors closely monitor and carefully manage the Group's
liquidity risk. Our financial outlook is assessed primarily through
the annual business planning process, however it is also carefully
monitored on a monthly basis. This process includes regular Board
discussions, led by the Senior Leadership Team, at which the
current performance of and outlook for the Group are assessed.
The outputs from the business planning process include a set of
key performance objectives, an assessment of the Group's primary
risks, the anticipated operational outlook and a set of financial
forecasts that consider the sources of funding available to the
Group (the "Base Plan").
Key assumptions, which underpin the annual business planning
process, include forecasted natural gas and oil prices, forecasted
operating cost and capital expenditure levels, production profiles,
and the availability of liquidity or additional financing. Cash
flow projections are regularly produced and sensitivities run for
different scenarios including, but not limited to, changes in
commodity prices and different production rates from our producing
assets. The Directors and Senior Leadership Team closely monitor
these forecast assumptions and projections and seek to mitigate the
Group's liquidity risk.
Based on our scenario planning process, the Directors and Senior
Leadership Team believe that stress testing forecast results over
the Base Plan, from January 2021 to December 2023, form a
reasonable expectation to the Group's viability. The Base Plan
forecast process is performed at least annually and covers our
three year medium-term strategic planning period. The Directors and
Senior Leadership Team are confident that operational risks are
being monitored and managed effectively within the Base Plan
period, and our scenario planning is focused primarily on plausible
changes in external factors, providing a reasonable degree of
confidence.
The principal risks and uncertainties that affect the Directors'
assessment of our viability in this period are:
-- The effect of volatile natural gas prices on the business;
-- Operational production performance of the producing assets; and
-- Operating cost levels and our ability to control costs.
The Base Plan incorporates assumptions that reflect these
principal risks as follows:
-- Projected operating cash flows are calculated using a
production profile which is consistent with current operating
results and decline rates;
-- Assumes commodity prices are in line with the current forward
curve which considers basis differentials;
-- Operating cost levels stay consistent with historical trends;
-- The financial impact of our current hedging contracts in
place, being approximately 90%, 65% and 45% of total production
volumes hedged for the years ending 31 December 2021, 2022 and 2023
respectively; and
-- The scenario also includes the scheduled principal and
interest payments on our current debt arrangements and the funding
of a dividend utilising approximately 40% of Free Cash Flow.
The Directors and Senior Leadership Team also consider further
scenarios around the Base Plan that primarily reflect a more
severe, but plausible, impact of the principal risks, both
individually and in the aggregate, as well as the additional
capital requirements that downside scenarios could place on us.
Scenario 1: A sharp and sustained decline in pricing resulting
in a 10% reduction to net realised prices.
Scenario 2: A operational stoppage or regulatory event occurs
which results in reduced production by approximately 5%.
Scenario 3: A market or regulatory event triggers an increase in
operating and midstream expenses by approximately 5%.
Scenario 4: The three scenarios above were then considered in aggregate.
The Directors and Senior Leadership Team consider the impact
that these principal risks could, in certain circumstances, have on
the Group's prospects within the assessment period, and accordingly
assess the opportunities to actively mitigate the risk these
downside scenarios create while still being able to meet our debt
obligations, and return cash flows to shareholders.
Under these downside sensitivity scenarios, the Group remains
cash flow positive. The Group meets its working capital
requirements through operating cash flow management and through the
utilisation of the Group's Credit Facility, when necessary. For the
purpose of the going concern assessment, the Directors have only
taken into account the capacity under the existing Credit Facility.
In November 2020 the Group reaffirmed its borrowing base on the
$1,500,000 Credit Facility at $425,000. The Group's available
borrowing under the Credit Facility totalled $211,600 as of 31
December 2020. The key covenants attached to the Group's Credit
Facility relate to the Group's EBITDAX leverage ratio and current
ratio. In the downside scenario modelled, the Group continues to
maintain sufficient liquidity and meets its covenants under the
Credit Facility as well as its other existing borrowing
instruments.
In addition to its modelled downside going concern scenarios,
the Board has reverse stress tested the model to determine the
extent of downturn which would result in a breach of covenants.
Assuming similar levels of cash conversion as seen in 2020, a
decline in production volume and pricing, well in excess of that
historically experienced by the Group, would need to persist
throughout the going concern period for a covenant breach to occur,
which is considered very unlikely. This stress test also does not
incorporate certain mitigating actions or cash preservation
responses, which the Group would implement in the event of a severe
and extended revenue decline.
The Directors also considered the risk of a temporary shutdown
resulting from the Covid-19 pandemic. Notwithstanding the modelling
of this scenario, the Group is considered an essential service as
the Group falls under the US Department of Homeland Security's
definition of essential criteria infrastructure workers as defined
on 19 March 2020. As a result of the announcement, the Group's
employees are exempt from any lockdown in the US.
The Directors have reviewed the Group's overall position and
outlook and are of the opinion that the Group is sufficiently well
funded to be able to operate as a going concern for at least the
next twelve months from the date of approval of the Group Financial
Information.
Prior period reclassifications
The Group has reclassified certain amounts in its prior year
Consolidated Statement of Financial Position to conform to its
current period presentation. These changes in classification do not
affect total comprehensive income previously reported in the
Consolidated Statement of Comprehensive Income or the Consolidated
Statement of Cash Flows. During the year ended 31 December 2019,
the Group reclassified $15,981 related to its Enterprise Resource
Planning ("ERP") software from "Property, plant and equipment" to
"Intangible assets" in the Consolidated Statement of Financial
Position.
Basis of Consolidation
During 2019, the Group underwent a restructuring in order to
simplify its organisation. Under this restructuring all production
entities were merged into Diversified Production, LLC and all
midstream entities were merged into Diversified Midstream, LLC.
Further, Diversified Energy Marketing, LLC was created to sell the
commodities produced by Diversified Production, LLC and certain
third parties. There is no financial information impact as a result
of the reorganisation.
The Group Financial Information for the year ended 31 December
2020 reflects the following corporate structure of the Group:
The Group, and its 100% wholly owned subsidiary:
-- Diversified Gas & Oil PLC ("DGOC") as well as its wholly owned subsidiaries
-- Diversified Gas & Oil Corporation
Diversified Production, LLC
-- Diversified ABS Holdings LLC
-- Diversified ABS LLC
-- Diversified ABS Phase II Holdings LLC
-- Diversified ABS Phase II LLC
-- DP Bluegrass Holdings LLC
-- DP Bluegrass LLC
Diversified Midstream LLC
-- Cranberry Pipeline Corporation
-- Coalfield Pipeline Company
Diversified Energy Marketing LLC
DGOC Holdings LLC
-- DGOC Holdings Sub III LLC
NOTE 3 - SIGNIFICANT ACCOUNTING POLICIES
The preparation of the Group Financial Information in compliance
with IFRS requires the Directors to make estimates and exercise
judgment in applying the Group's accounting policies. The areas
involving a higher degree of judgment or complexity, or areas where
assumptions and estimates are significant to the Group Financial
Information are disclosed in Note 4.
Business Combinations and Asset Acquisitions
The Group performs an assessment of each acquisition to
determine whether the acquisition should be accounted for as an
asset acquisition or business combination.
Accounting for business combinations under IFRS 3 is applied
once it is determined that a business has been acquired. Under IFRS
3, a business is defined as an integrated set of activities and
assets conducted and managed for the purpose of providing a return
to investors. A business generally consists of inputs, processes
applied to those inputs, and resulting outputs that are, or will
be, used to generate revenues.
For each transaction, the Group may elect to apply the
concentration test under the IFRS 3 amendment to determine if the
fair value of assets acquired is substantially concentrated in a
single asset (or a group of similar assets). If this concentration
test is met, the acquisition qualifies as an acquisition of a group
of assets and liabilities, not of a business. When the Group
determines a transaction is an acquisition of a group of assets
rather than a business combination, the Group capitalises the
transaction costs incurred as part of the acquisition. Additionally
in instances when the acquisition of a group of assets contains
contingent consideration, the Group records changes in the fair
value of the contingent consideration through the basis of the
asset acquired rather than through the statement of comprehensive
income.
More information regarding the judgements and conclusions
reached with respect to business combinations and asset
acquisitions is included in Note 4 and Note5.
Cash and Cash Equivalents
Cash on the balance sheet comprises cash at banks. Balances held
at banks, at times, exceed US federally insured amounts. The Group
has not experienced any losses in such accounts and the Directors
believe the Group is not exposed to any significant credit risk on
its cash. At 31 December 2020 and 2019, the Group's cash balance
was $1,379 and $1,661, respectively.
Trade Receivables
Trade receivables are stated at the historical carrying amount,
net of any provisions required. Trade receivables are due from
customers throughout the natural gas and oil industry. Although
diversified among several customers, collectability is dependent on
the financial condition of each individual customer as well as the
general economic conditions of the industry. The Directors review
the financial condition of customers prior to extending credit and
generally do not require collateral to support of the Group's trade
receivables. Any changes in the Directors' allowance for current
expected credit losses during the year are recognised in the
Consolidated Statement of Comprehensive Income. Trade receivables
also include certain receivables from third-party working interest
owners. The Group consistently assesses the collectability of these
receivables. At 31 December 2020 and 2019, the Group considered a
portion of these working interests receivables uncollectable and
recorded a allowance for credit losses in the amount of $11,082 and
$3,210, respectively. See Note 15 for additional information.
Impairment of Financial Assets
IFRS 9, Financial Instruments ("IFRS 9"), requires the
application of an expected credit loss model in considering the
impairment of financial assets. The expected credit loss model
requires the Group to account for expected credit losses and
changes in those expected credit losses at each reporting date to
reflect changes in credit risk since initial recognition of the
financial assets. The credit event does not have to occur before
credit losses are recognised. IFRS 9 allows for a simplified
approach for measuring the loss allowance at an amount equal to
lifetime expected credit losses for trade receivables and contract
assets.
The Group applies the simplified approach to the expected credit
loss model to trade receivables arising from:
-- Sales of natural gas, NGLs and oil ;
-- Sales of gathering and transportation of third-party natural gas; and
-- The provision of other services.
Borrowings
Borrowings are recognised initially at fair value, net of any
applicable transaction costs incurred. Borrowings are subsequently
carried at amortised cost. Any difference between the proceeds (net
of transaction costs) and the redemption value is recognised in the
Consolidated Statement of Comprehensive Income over the period of
the borrowings using the effective interest method (if
applicable).
Interest on borrowings is accrued as applicable to each class of
borrowing.
Derivative Financial Instruments
Derivatives are used as part of the Group's overall strategy to
mitigate risk associated with the unpredictability of cash flows
due to volatility in commodity prices. Further details of the
Group's exposure to these risks are detailed in Note 26. The Group
has entered into financial instruments which are considered
derivative contracts, such as swaps and collars which result in net
cash settlement each month and do not result in physical
deliveries. The derivative contracts are initially recognised at
fair value at the date the contract is entered into and remeasured
to fair value every balance sheet date. The resulting gain or loss
is recognised in the Consolidated Statement of Comprehensive Income
in the year incurred.
Restricted Cash
Cash held on deposit for bonding purposes is classified as
restricted cash and recorded within current and non-current assets.
The cash (1) is restricted in use by state governmental agencies to
be utilised and drawn upon if the operator should abandon any
wells, or (2) is being held as collateral by the Group's surety
bond providers. Additionally, the Group is required to maintain
certain reserves for interest payments related to its asset backed
securitisation discussed in Note 22. These reserves approximate
seven and a half months of interest and any associated fees. At 31
December 2020 and 2019, the Group's restricted cash balance was
$20,350 and $7,712, respectively. The Group classifies restricted
cash as current or non-current based on the classification of the
associated asset or liability to which the restriction relates.
Natural Gas and Oil properties
Development and acquisition costs
Expenditures related to the construction, installation or
completion of infrastructure facilities, such as platforms, and the
drilling of development wells, including delineation wells, are
capitalised within natural gas and oil properties. The initial cost
of an asset comprises its purchase price or construction cost, any
costs directly attributable to bringing the asset into operation,
and the initial estimate of the well asset retirement obligation.
The purchase price or construction cost is the aggregate amount
paid and the fair value of any other consideration given to acquire
the asset.
Depletion
Natural gas and oil properties are depleted on a
unit-of-production basis over the proved reserves of the field
concerned, except in the case of assets whose useful life is
shorter than the lifetime of the field, in which case the straight-
line method is applied. Rights and concessions are depleted on the
unit-of-production basis over the total proven reserves of the
relevant area. The unit-of-production rate for the depreciation of
field development costs considers expenditures incurred to date,
together with sanctioned future development expenditure.
Intangible Assets
Software development and acquisition costs
Development costs that are directly attributable to the design
and testing of identifiable and unique software products controlled
by the Group are recognised as intangible assets where the
following criteria are met:
-- It is technically feasible to complete the software so that it will be available for use;
-- The Directors intend to complete the software and use or sell it;
-- There is an ability to use the software;
-- It can be demonstrated how the software will generate probable future economic benefits;
-- Adequate technical, financial and other resources to complete
the development and to use the software are available; and
-- The expenditure attributable to the software during its
development can be reliably measured.
Directly attributable costs that are capitalised as part of the
software include employee costs and an appropriate portion of
relevant overheads.
Capitalised development costs are recorded as intangible assets
and amortised from the point at which the asset is ready for
use.
Costs associated with maintaining software programmes are
recognised as an expense as incurred.
Impairment of intangible assets
Intangible assets are tested for impairment whenever events or
changes in circumstances indicate that the carrying amount may not
be recoverable. An impairment loss is recognised for the amount by
which the asset's carrying amount exceeds its recoverable amount.
The recoverable amount is the higher of an asset's fair value less
costs of disposal and value in use. For the purposes of assessing
impairment, assets are grouped at the lowest levels for 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). Intangible assets that suffered an
impairment are reviewed for possible reversal of the impairment at
the end of each reporting period.
Amortisation
The Group amortises intangible assets with a limited useful
life, using the straight-line method over the following
periods:
Range in Years
--------------
Software 3
Other acquired intangibles 3
Property, Plant and Equipment
Property, plant and equipment are stated at cost less
accumulated depreciation and impairment losses, if any. The cost of
an item of property, plant and equipment initially recognised
includes its purchase price and any cost that is directly
attributable to bringing the asset to the location and condition
necessary for it to be capable of operating in the manner intended
by the Directors.
Property, plant and equipment are generally depreciated on a
straight-line basis over their estimated useful lives:
Range in Years
--------------
Buildings and leasehold improvements 40
Equipment 5 - 10
Motor vehicles 5
Midstream assets 7 - 15
Other property and equipment 5 - 10
Property, plant and equipment held under leases are depreciated
over the shorter of lease term and estimated useful life.
Impairment of Non-Financial Assets
At each reporting date, the Directors assess whether indications
exist that an asset may be impaired. If indications exist, or when
annual impairment testing for an asset is required, the Directors
estimate the asset's recoverable amount. An asset's recoverable
amount is the higher of an asset's or cash generating unit's fair
value less costs to sell and its value-in-use, and is determined
for an individual asset, unless the asset does not generate cash
inflows that are largely independent of those from other assets or
groups of assets. Where the carrying amount of an asset or
cash-generating unit exceeds its recoverable amount, the Directors
consider the asset impaired and write the subject asset down to its
recoverable amount. In assessing value-in-use, the Directors
discount the estimated future cash flows to their present value
using a pre-tax discount rate that reflects current market
assessments of the time value of money and the risks specific to
the asset. In determining fair value less costs to sell, the
Directors consider recent market transactions, if available. If no
such transactions can be identified, the Directors will utilise an
appropriate valuation model.
Leases
The Group recognises a right-of-use asset and a lease liability
at the commencement date of contracts (or separate components of a
contract) which convey to the Group the right to control the use of
an identified asset for a period of time in exchange for
consideration, when such contracts meet the definition of a lease
as determined by IFRS 16. The determination of whether an
arrangement is, or contains, a lease is based on the substance of
the arrangement at inception date.
The Group initially measures the lease liability at the present
value of the future lease payments. The lease payments are
discounted using the interest rate implicit in the lease. When this
rate can not be readily determined the Group uses its incremental
borrowing rate. After the commencement date, the lease liability is
reduced for payments made by the lessee and increased for interest
on the lease liability.
Right-of-use assets are initially measured at cost, which
comprises:
-- The amount of the initial measurement of the lease liability;
-- Any lease payments made at or before the commencement date,
less any lease incentives received, any initial direct costs
incurred by the lessee; and
-- An estimate of costs to be incurred by the lessee in
dismantling and removing the underlying asset, restoring the site
on which it is located or restoring the underlying asset to the
condition required by the terms and conditions of the lease unless
those costs are incurred to produce inventories.
Subsequent to the measurement date, the right-of-use asset is
depreciated on a straight line basis for a period of time that
reflects the life of the underlying asset, and also adjusted for
the remeasurement of any lease liability.
Asset Retirement Obligations
Where a material liability for the retirement of a well, removal
of production equipment and site restoration at the end of the
production life of a well exists, the Group recognises a liability
for well asset retirement. The amount recognised is the present
value of estimated future net expenditures determined in accordance
with local conditions and requirements. The unwinding of the
discount on the decommissioning liability is included as accretion
of the decommissioning provision. The cost of the relevant
property, plant and equipment asset is increased with an amount
equivalent to the liability and depreciated on a unit of production
basis. The Group recognises changes in estimates prospectively,
with corresponding adjustments to the liability and the associated
non-current asset.
At 31 December 2020 and 2019, the Group had no midstream asset
retirement obligations.
Taxation
Deferred taxation
Deferred tax is provided in full on temporary differences
arising between the tax bases of assets and liabilities and their
carrying amounts in the Group Financial Information. Deferred tax
is determined using tax rates (and laws) that have been enacted or
substantially enacted by the balance sheet date and are 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 utilised.
Income taxation
Current income tax assets and liabilities for the years ended 31
December 2020 and 2019 were measured at the amount to be recovered
from, or paid to, the taxation authorities. The tax rates and tax
laws used to compute the amount are those that are enacted or
substantively enacted at the reporting date in the jurisdictions
where the Group operates and generates taxable income.
Uncertain tax positions
Management periodically evaluates positions taken in tax returns
with respect to situations in which applicable tax regulation is
subject to interpretation and considers whether it is probable that
a taxation authority will accept an uncertain tax treatment. The
group measures its tax balances based on either the most likely
amount, or the expected value, depending on which method provides a
better prediction of the resolution of the uncertainty.
Revenue Recognition
Natural gas, NGLs and oil
Commodity revenue is derived from sales of natural gas, NGLs and
oil products and is recognised when the customer obtains control of
the commodity. This transfer generally occurs when product is
physically transferred into a vessel, pipe, sales meter or other
delivery mechanism. This also represents the point at which the
Group carries out its single performance obligation to its customer
under contracts for the sale of natural gas, NGLs and oil.
Commodity revenue in which the Group has an interest with other
producers is recognised proportionately based on the Group's
working interest and the terms of the relevant production sharing
contracts. The portion of revenue that is due to minority working
interest is included as a liability in Note 24.
Commodity revenue is recorded based on the volumes accepted each
day by customers at the delivery point and is measured using the
respective market price index for the applicable commodity plus or
minus the applicable basis differential based on the quality of the
product.
Third-party gathering revenue
Revenue from gathering and transportation of third-party natural
gas is recognised when the customer transfers its natural gas to
the entry point in the Group's midstream network and becomes
entitled to withdraw an equivalent volume of natural gas from the
exit point in the Group's midstream network under contracts for the
gathering and transportation of natural gas. This transfer
generally occurs when product is physically transferred into the
Group's vessel, pipe, or sales meter. The customer's entitlement to
withdraw an equivalent volume of natural gas is broadly coterminous
with the transfer of natural gas into the Group's midstream
network. Customers are invoiced and revenue is recognised each
month based on the volume of natural gas transported at a
contractually agreed upon price per unit.
Other revenue
Revenue from the operation of third-party wells is recognised as
earned in the month work is performed and consistent with the
Group's contractual obligations. The Group's contractual
obligations in this respect are considered to be its performance
obligations for the purposes of IFRS 15, Revenue from Contracts
with Customers ("IFRS 15").
Revenue from the sale of water disposal services to
third-parties into the Group's disposal wells is recognised as
earned in the month the water was physically disposed at a
contractually agreed upon price per unit. Disposal of the water is
considered to be the Group's performance obligation under these
contracts.
Revenue is stated after deducting sales taxes, excise duties and
similar levies.
Share-Based Payments
The Group accounts for share-based payments under IFRS 2,
Share-based Payment ("IFRS 2"). All of the Group's share-based
awards are equity settled. The fair value of the awards are
determined at the date of grant. At 31 December 2020 and 2019, the
Group had three types of share-based payment awards, restricted
stock units ("RSUs"), performance stock units ("PSUs") and Options.
The fair value of the grant of the Group's RSUs and PSUs is
determined using the stock price at the grant date and uniformly
expensed over the vesting period. The fair value of the Group's
Options are calculated using the Black-Scholes model as of the
grant date. The inputs to the Black-Scholes model included:
-- The share price at the date of grant;
-- Exercise price;
-- Expected volatility;
-- Expected dividends;
-- Risk-free rate of interest; and
-- Patterns of exercise of the plan participants.
The grant date fair value of share-based awards, adjusted for
market-based performance conditions, are expensed uniformly over
the vesting period.
Segment Reporting
The Group is an independent owner and operator of producing
natural gas and oil wells concentrated in the Appalachian Basin.
The Group's operations are located throughout the region and has
operations in the states of Tennessee, Kentucky, Virginia, West
Virginia, Ohio, and Pennsylvania. The Group's strategy is to
acquire long-life producing assets, efficiently operate those
assets to generate Free Cash Flow for shareholders and then to
retire assets safely and responsibly at the end of their useful
life. The Group's assets consist of approximately 67,000
geographically concentrated wells and approximately 17,000 miles of
natural gas gathering pipelines and a network of compression and
processing facilities which are complementary to the Company's
assets. The Director's acquire and manage these assets in a
complementary fashion to vertically integrate and improve margins
rather than as separate options. Accordingly when determining
operating segments under IFRS 8 the Group has identified one
reportable segment that produces and transports natural gas, NGLs
and oil in the Appalachian Basin of the US.
New Standards and Interpretations - Adopted
IFRS 3, Business Combinations ("IFRS 3")
In October 2018, the International Accounting Standards Board
issued amendments to IFRS 3. The amendments clarify the definition
of a business, with the objective of assisting entities to
determine whether a transaction should be accounted for as a
business combination or as an asset acquisition. The amended
standard states that to be considered a business, an acquired set
of activities and assets must include, at a minimum, an input and a
substantive process that together significantly contributes to the
ability to create outputs while removing the consideration of a
market participant's ability to replace any missing inputs or
processes and continuing to produce outputs. The standard also
establishes an optional asset concentration test allowing entities
to determine whether an acquired set of activities and assets is
not a business. The Group adopted the amendments to IFRS 3 on 1
January 2020 and applied the amendments to asset acquisitions and
business combinations that occurred subsequent to adoption.
New Standards and Interpretations - Not Yet Adopted
Certain new accounting standards and interpretations have been
published that are not mandatory for 31 December 2020 reporting
periods and have not been early adopted by the Group. None of these
new standards or interpretations are expected to have a material
impact on the consolidated financial statements of the Group.
NOTE 4 - SIGNIFICANT ACCOUNTING JUDGEMENTS AND ESTIMATES
In application of the Group's accounting policies, which are
described in note 3, the Directors have made the following
judgments and estimates which may have a significant effect on the
amounts recognised in the Group Financial Information:
SIGNIFICANT JUDGEMENTS
Business Combinations and Asset Acquisitions
The Group follows the guidance in IFRS 3 for determining the
appropriate accounting treatment for acquisitions. IFRS 3 permits
an initial fair value screen to determine if substantially all of
the fair value of the assets acquired is concentrated in a single
asset or group of similar assets. If the initial screening test is
not met, the set is considered a business based on whether there
are inputs and substantive processes in place. Based on the results
of this analysis and conclusion on an acquisition's classification
of a business combination or an asset acquisition, the accounting
treatment is derived.
If the acquisition is deemed to be a business, the acquisition
method of accounting is applied. Identifiable assets acquired and
liabilities assumed at the acquisition date are recorded at fair
value. When the fair value exceeds the consideration transferred a
bargain purchase gain is recognised, conversely when the
consideration transferred exceeds the fair value goodwill is
recorded.
If the transaction is deemed to be an asset purchase, the cost
accumulation and allocation model is used whereby the assets and
liabilities are recorded based on the purchase price and allocated
to the individual assets and liabilities based on relative fair
values. As a result bargain purchase gains are not recognised on
asset acquisitions. Additionally in instances when the acquisition
of a group of assets contains contingent consideration, the Group
records changes in the fair value of the contingent consideration
through the basis of the asset acquired rather than through the
Consolidated Statement of Comprehensive Income. More information
regarding conclusions reached with respect to this judgement is
included in Note 5.
The determination and allocation of fair values to the
identifiable assets acquired and liabilities assumed are based on
various assumptions and valuation methodologies requiring
considerable management judgment. The most significant variables in
these valuations are discount rates and other assumptions and
estimates used to determine the cash inflows and outflows.
Management determines discount rates based on the risk inherent in
the acquired assets, specific risks, industry beta and capital
structure of guideline companies. The valuation of an acquired
business is based on available information at the acquisition date
and assumptions that are believed to be reasonable. However, a
change in facts and circumstances as of the acquisition date can
result in subsequent adjustments during the measurement period, but
no later than one year from the acquisition date.
SIGNIFICANT ESTIMATES
Estimating the Fair Value of Natural Gas and Oil Properties
The Group determines the fair value of its natural gas and oil
properties upon acquisition using the income approach based on
expected discounted future cash flows from estimated reserve
quantities, costs to produce and develop reserves, and natural gas
and oil forward prices. The future net cash flows are discounted
using a weighted average cost of capital as well as any additional
risk factors. Proved reserves are estimated by reference to
available geological and engineering data and only include volumes
for which access to market is assured with reasonable certainty.
Estimates of proved reserves are inherently imprecise, require the
application of judgment and are subject to regular revision, either
upward or downward, based on new information such as from the
drilling of additional wells, observation of long-term reservoir
performance under producing conditions and changes in economic
factors, including product prices, contract terms or development
plans. Sensitivity analysis on the significant inputs to the fair
value is included in Note 5.
Impairment of Natural Gas and Oil Properties
In preparing the Group Financial Information the Directors
considered that a key judgment was whether there was any evidence
that the natural gas and oil properties were impaired. When making
this assessment producing assets are reviewed for indicators of
impairment at the balance sheet date. Indicators of impairment for
the Group's producing assets include:
-- A decrease in commodity pricing or other negative changes in market conditions;
-- Downward revisions of reserve estimates; or
-- Increases in operating costs.
The Group reviews the carrying value of its natural gas and oil
properties annually or when an indicator of impairment is
identified. The impairment test compares the carrying value of
natural gas and oil properties to their recoverable amount based on
the present value of estimated future net cash flows from the
proved natural gas and oil reserves. The future cash flows are
calculated using estimated reserve quantities, costs to produce and
develop reserves, and natural gas and oil forward prices. The fair
value of proved reserves is estimated by reference to available
geological and engineering data and only include volumes for which
access to market is assured with reasonable certainty. When the
carrying value is in excess of the fair value, the Group recognises
an impairment by writing down the value of its natural gas and oil
properties to their fair value. No such impairments were recorded
during 2020 and 2019.
Where there has been a charge for impairment in an earlier
period, that charge will be reversed in a later period where there
has been a change in circumstances to the extent that the
recoverable amount is higher than the net book value at the time.
In reversing impairment losses, the carrying amount of the asset
will be increased to the lower of its original carrying value or
the carrying value that would have been determined (net of
depletion) had no impairment loss been recognised in prior years.
No such recoveries were recorded during 2020 and 2019. Please refer
to Note 20 for additional information.
When applicable, the Group recognises impairment losses in the
Consolidated Statement of Comprehensive Income in those expense
categories consistent with the function of the impaired asset.
Reserve Estimates
Reserves are estimates of the amount of natural gas, NGLs and
oil product that can be economically and legally extracted from the
Group's properties. To calculate the reserves, significant
estimates and assumptions are required about a range of geological,
technical and economic factors, including quantities, production
techniques, recovery rates, production costs, transport costs,
commodity demand, commodity prices and exchange rates.
Estimating the quantity and/or grade of reserves requires the
size, shape and depth of fields to be determined by analysing
geological data, such as drilling samples. This process may require
complex and difficult geological judgments and calculations to
interpret the data.
Given the economics used to estimate reserve changes from year
to year and, because additional geological data is generated during
the course of operations, estimates of reserves may change from
time to time.
Asset Retirement Obligation Costs
The ultimate asset retirement obligation 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 and amount of expenditures can also change, for
example, in response to changes in reserves or changes in laws and
regulations or their interpretation. As a result, significant
estimates and assumptions are made in determining the provision for
asset retirement. These assumptions include cost to plug the wells,
the economic life of the wells and the discount rate. Changes in
assumptions related to the Group's asset retirement obligations
could result in a material change in the carrying value within the
next financial year. See Note 20 for more information and
sensitivity analysis.
NOTE 5 - ACQUISITIONS
The assets acquired in all acquisitions include the necessary
permits, rights to production, royalties, assignments, contracts
and agreements that support the production from wells and
operations of pipelines. The Group accounts for acquisitions under
IFRS 3.
As part of the Group's corporate strategy it actively seeks to
acquire assets complementary to its existing asset base when the
assets meet the acquisition criteria stated in the Acquire
Long-Life Stable Assets pillar of the corporate strategy.
2020 Acquisitions
Carbon Energy Corporation ("Carbon") business combination
On 26 May 2020, the Group acquired approximately 6,100
conventional wells in the states of Kentucky, West Virginia and
Tennessee from Carbon. When evaluating the transaction the Group
determined it acquired an identifiable set of inputs, processes and
outputs and concluded the transaction was a business combination.
The Group initially paid purchase consideration of $98,120,
excluding customary purchase price adjustments. Subsequent to the
initial closing price the companies settled on a final closing
statement and the Group paid another $3,370 in cash consideration
for a total cash consideration of $101,490. Transaction costs
associated with the acquisition were $1,118. The Group funded the
cash consideration for the purchase with proceeds from the $160,000
Term Loan I, discussed in Note 22.
Carbon may earn additional contingent consideration of up to
$15,000 in the aggregate. The contingent consideration will be
calculated based on fixed volumes and the average settled natural
gas pricing for 2020, 2021, and 2022 as compared to established
benchmark pricing. Any payments due will be paid yearly by 5
January of each of 2021, 2022 and 2023 based on the contingent
consideration calculation for the respective calendar years. Based
on forward NYMEX natural gas prices the fair value of the
contingent consideration as at the acquisition date was $5,463. As
of 31 December 2020 no contingent consideration payment had been
made.
In the period from its acquisition to 31 December 2020 the
acquisition of Carbon increased the Group's natural gas and oil
production by 10,279 MMcf and 45 MBbls, respectively. The
properties associated with the acquisition have been co-mingled
with the Group's existing properties and it is impractical to
provide stand-alone operational results related to these acquired
properties for the twelve month period ended 31 December 2020.
As stated in Note 4, changes in the Group's assumptions used as
inputs for acquisitions could result in a material change of the
fair value of the acquired reserves. The Group considers the
discount rate, commodity pricing, production and operating expense
assumptions to be the inputs most sensitive to the fair value of
the acquired reserves. The table below represents the impact a 100
basis point adjustment in the discount rate, commodity price,
production and operating expense would have on the fair value of
the acquired reserves provided this represents a reasonably
possible change in these assumptions.
Adjusted fair value of natural gas and oil +100 Basis -100 Basis
properties Points Points
---------- ------------
Discount rate 76,625 83,751
Pricing (a) 81,938 78,238
Production 81,938 78,238
Operating expense 79,238 80,938
(a) The Group used a projected base realised price of $1.86 for
natural gas and $30.84 f or oil.
As a result of the valuation, the fair value of the reserves
held in assets acquired was $80,138, which was derived using a
cumulative discount rate of 11%. The provisional fair value of the
assets acquired and liabilities assumed were as follows:
Consideration paid
Cash consideration $101,490
Contingent consideration 5,463
--------
Total consideration $106,953
=======
Net assets acquired
Natural gas and oil properties $ 80,138
Natural gas and oil properties (asset retirement obligation,
asset portion) 23,853
Property, plant and equipment 46,713
Other non-current assets 3,846
Derivative financial instruments, net 3,464
Trade receivables 110
Inventory 2,478
Other current assets 6
Cash and cash equivalents 1,352
Deferred tax asset 4,105
Leases, non-current (2,537)
Other non-current liabilities (441)
Asset retirement obligation, liability portion (23,853)
Trade and other payables (1,672)
Leases, current (963)
Other current liabilities (12,474)
--------
Net assets acquired 124,125
--------
Gain on bargain purchase (17,172)
--------
Purchase price $106,953
=======
Taking into account the requirements of IFRS 3 with respect to
the possibility of recognising a possible gain on a bargain
purchase, the Group reviewed the procedures used to identify and
measure all amounts affecting the calculation of the assets and
liabilities acquired in the transaction and considered the
recognition of the gain on the bargain purchase appropriate. The
review of these factors included the review of Carbon's public
filings when submitting the transaction to stockholders for
approval as required by Section 271 of the General Corporation Law
of the State of Delaware.
The bargain purchase was a result of a combination of factors
that coincided with the sustained period of low natural gas and oil
prices the market has experienced, significant market volatility
linked to the Covid-19 pandemic and strategic decisions by other
industry participants as they effect their own initiatives often
choosing to divest assets they consider non-core to their
business.
These external pressures created concerns about Carbon's ability
to comply with certain financial covenants if this lingering period
of low pricing were to persist, providing incentive for Carbon to
market the assets. These pressures coupled with Carbon's desire for
additional strategic pursuits in California-based assets
contributed to the Group's recognition of a $17,172 gain on bargain
purchase.
EQT Corporation ("EQT") asset acquisition
On 21 May 2020, the Group acquired 889 proved developed wells
and related gathering infrastructure in the states of Pennsylvania
and West Virginia from EQT. Given the concentration of assets this
transaction was considered a acquisition of assets rather than a
business combination. The Group initially paid purchase
consideration of $111,587, excluding customary purchase price
adjustments. Subsequent to the initial closing price the companies
settled on a final closing statement and the Group paid another
$3,215 in cash consideration for a total cash consideration of
$114,802. Transaction costs associated with the acquisition were
$1,069 and have been capitalised to natural gas and oil properties.
The Group funded the purchase with proceeds from the $160,000 Term
Loan I and a short-term draw from the Credit Facility, both
discussed in Note 22.
EQT may earn additional contingent consideration of up to
$20,000 in the aggregate. The contingent consideration will be
calculated based on the three-month average of the NYMEX Henry Hub
natural gas settlement price relative to stated floor and target
price thresholds beginning on 31 August 2020 and ending on 30
November 2022. Based on forward NYMEX natural gas prices the fair
value of the contingent consideration as at the acquisition date
was $7,082. As at 31 December 2020, the Group has made contingent
consideration payments of $893.
In the period from its acquisition to 31 December 2020 the
acquisition of EQT increased the Group's natural gas production by
12,971 MMcf. The properties associated with the acquisition have
been co-mingled with the Group's existing properties and it is
impractical to provide stand-alone operational results related to
these acquired properties for the twelve month period ended 31
December 2020.
As stated in Note 4, changes in the Group's assumptions used as
inputs for acquisitions could result in a material change of the
fair value of the acquired reserves. The Group considers the
discount rate, commodity pricing, production and operating expense
assumptions to be the inputs most sensitive to the fair value of
the acquired reserves. The table below represents the impact a 100
basis point adjustment in the discount rate, commodity price,
production and operating expense would have on the fair value of
the acquired reserves provided this represents a reasonably
possible change in these assumptions.
Adjusted fair value of natural gas and oil +100 Basis -100 Basis
properties Points Points
---------- ------------
Discount rate 114,909 115,808
Pricing (a) 115,447 115,258
Production 115,447 115,258
Operating expense 115,333 115,375
(a) The Group used a projected base realised price of $1.73
using Henry Hub strip prices adjusted for differentials.
As a result of the valuation, the fair value of the reserves
held in assets acquired was $114,007, which was derived using a
cumulative discount rate of 11%. The provisional fair value of the
assets and liabilities assumed were as follows:
Consideration paid:
Cash consideration $114,802
Contingent consideration 7,082
Acquisition costs 1,069
--------
Total consideration $122,953
=======
Natural gas and oil properties $114,007
Natural gas and oil properties (asset retirement obligation,
asset portion) 3,142
Property, plant and equipment 10,956
Asset retirement obligation, liability portion (3,142)
Other current liabilities (2,010)
--------
Net assets acquired $122,953
=======
Other asset acquisitions of natural gas properties
In December 2020, the Group acquired five gross unconventional
Utica Shale horizontal wells in the state of Ohio. The Group paid
purchase consideration of $7,083, excluding customary purchase
price adjustments. Transaction costs associated with the
acquisition were insignificant. The Group funded the cash
consideration for the purchase with a draw on its Credit Facility.
The group is still working to finalise the fair value estimates
associated with this acquisition.
2019 Acquisitions
HG Energy ("HG Energy") business combination
In April 2019, the Group acquired 107 unconventional wells in
the states of Pennsylvania and West Virginia from HG Energy. The
Group paid purchase consideration of $384,020, excluding customary
purchase price adjustments. Transaction costs associated with the
acquisition were $4,788. The Group funded the cash consideration
for the purchase with the proceeds from an equity placing of shares
in April 2019 and a draw from the Credit Facility, discussed in
Notes 17 and 22, respectively.
In the period from its acquisition to 31 December 2019, the
acquisition of HG Energy contributed revenue of approximately
$34,000 and increased the Group's natural total production by
90,940 Boepd. The properties associated with the acquisition have
been commingled with the Group's existing properties and it is
impractical to provide stand-alone operational results related to
these acquired properties.
As a result of the valuation, the fair value of the reserves
held in the assets acquired was $385,671, which was derived using a
cumulative discount rate of 8%. The fair values of the assets and
liabilities assumed were as follows:
Consideration paid
Cash consideration $384,020
-------
Total consideration $384,020
=======
Net assets acquired
Natural gas and oil properties $385,671
Natural gas and oil properties (asset retirement obligation,
asset portion) 236
Suspense (a) (1,651)
Asset retirement obligation, liability portion (236)
--------
Net assets acquired $384,020
=======
(a) Suspense represents the amounts payable to minority working interest owners.
EdgeMarc Energy ("EdgeMarc") business combination
In September 2019, the Group acquired 12 unconventional wells
and three drilled but uncompleted unconventional wells in Ohio from
EdgeMarc Energy. The Group paid purchase consideration of $48,107,
excluding customary purchase price adjustments. Transaction costs
associated with the acquisition were $747. The Group funded the
cash consideration for the purchase from a draw on the Credit
Facility, discussed in Note 22.
In the period from its acquisition to 31 December 2019, the
acquisition of EdgeMarc contributed revenue of approximately $6,600
and increased the Group's total production to 95,940 Boepd. The
properties associated with the acquisition have been commingled
with the Group's existing properties and it is impractical to
provide stand-alone operational results related to these acquired
properties.
As a result of the valuation, the fair value of the reserves
held in the assets acquired was $40,507, which was derived using a
cumulative discount rate of 8.5%. The fair values of the assets and
liabilities assumed were as follows:
Consideration paid
Cash consideration $48,107
------
Total consideration $48,107
======
Net assets acquired
Natural gas and oil properties $40,507
Natural gas and oil properties (asset retirement obligation,
asset portion) 15
Drilled but uncompleted 10,000
Derivative financial instruments, net 2,213
Suspense (a) (2,744)
Asset retirement obligation, liability portion (15)
Taxes payable (329)
-------
Net assets acquired 49,647
-------
Gain on bargain purchase (1,540)
-------
Purchase price $48,107
======
(a) Suspense represents the amounts payable to minority working interest owners.
The Group recorded a $1,540 gain on the acquisition of the
EdgeMarc assets which the Directors believe is reasonable given the
facts and circumstances of the acquisition. The Group entered into
a "stalking-horse" Asset Purchase Agreement with EdgeMarc,
debtors-in-possession under title 11 of the US Code, pursuant to
voluntary petitions for relief filed under Chapter 11 of the US
Bankruptcy Code. Given the circumstances of EdgeMarc, the Directors
believe that EdgeMarc was in a distressed position to sell the
assets under fair market value.
Acquisition of natural gas gathering systems
In September 2019, the Group acquired certain natural gas
gathering systems from Dominion and Equitrans, for total cash
consideration of $7,700, excluding customary purchase price
adjustments. The natural gas gathering systems associated with the
acquisitions have been commingled with the Group's existing natural
gas gathering systems and it is impractical to provide stand-alone
operational results related to these acquired assets. The Group
funded the cash consideration of the purchase from a draw on the
Credit Facility discussed in Note 22. The Group accounted for this
acquisition as an asset acquisition under IFRS 3. Transaction costs
associated with the Dominion and Equitrans acquisitions were $726
and $507, respectively.
NOTE 6 - REVENUE
The Group extracts and sells natural gas, NGLs and oil to
various customers in addition to operating a majority of these
natural gas and oil wells for customers and other working interest
owners. In addition, the Group provides gathering and
transportation services to third parties. All revenue was generated
in the US. The following table reconciles the Group's revenue for
the periods presented:
Year Ended
------------------------------
31 December 31 December
2020 2019
------------- ---------------
Natural gas $ 343,425 $ 384,121
NGLs 23,173 33,685
Oil 15,064 20,474
------------- -------------
Total commodity revenue 381,662 438,280
Midstream 25,389 22,166
Other 1,642 1,810
------------- -------------
Total revenue $ 408,693 $ 462,256
========= =========
A significant portion of the Group's trade receivables represent
receivables related to either sales of natural gas, NGLs and oil or
operational services, all of which are generally uncollateralised,
and are collected within 30 - 60 days depending on the commodity,
location and well type.
During the year ended 31 December 2020, two customers
individually totalled more than 10% of total revenues, totalling
11% each for a total of 22%. During the year ended 31 December
2019, one customer individually totalled more than 10% of total
revenues, totalling 13%.
NOTE 7 - EXPENSES BY NATURE
The following table provides a detail of the Group's expenses
for the periods presented:
Year Ended
------------------------------
31 December 31 December
2020 2019
------------- ---------------
Base lease operating expense (a) $ 92,288 $ 102,302
Production taxes (b) 13,705 16,427
Midstream operating expense (c) 52,815 44,060
Transportation expense (d) 45,155 39,596
------------- -------------
Total operating expense (e) 203,963 202,385
------------- -------------
Depreciation and amortisation 33,673 23,568
Depletion 83,617 74,571
------------- -------------
Total depreciation, depletion and amortisation 117,290 98,139
------------- -------------
Employees and benefits (administrative) 28,843 20,914
Other administrative (f) 8,820 7,384
Professional fees (g) 6,259 5,212
Auditors' remuneration (h) 2,429 1,667
Rent 830 896
------------- -------------
Base G&A (i) 47,181 36,073
------------- -------------
Non-recurring costs associated with acquisitions
(j) 10,465 9,210
Other non-recurring costs (k) 14,581 7,542
Non-cash equity compensation (l) 5,007 3,064
------------- -------------
Non-recurring and/or non-cash G&A (m) 30,053 19,816
------------- -------------
Total G&A 77,234 55,889
------------- -------------
Allowance for joint interest owner receivables 6,931 730
Recurring allowance for credit losses 1,559 -
------------- -------------
Total allowance for credit losses (n) 8,490 730
------------- -------------
Total expense $ 406,977 $ 357,143
========= =========
Aggregate remuneration (including Directors):
Wages and salaries 75,719 68,226
Payroll taxes 5,383 2,869
Benefits 14,926 5,766
------------- -------------
Total employees and benefits expense $ 96,028 $ 76,861
========= =========
(a) Base lease operating expense is defined as the sum of
employee and benefit expenses, well operating expense (net),
automobile expense and insurance cost.
(b) Production taxes include severance and property taxes.
Severance taxes are generally paid on produced natural gas, NGLs
and oil production at fixed rates established by federal, state or
local taxing authorities. Property taxes are generally based on the
taxing jurisdictions' valuation of the Group's natural gas and oil
properties and midstream assets.
(c) Midstream operating expenses are daily costs incurred to
operate the Group's owned midstream assets inclusive of employee
and benefit expenses.
(d) Transportation expenses are daily costs incurred from
third-party systems to gather, process and transport the Group's
natural gas, NGLs and oil.
(e) Total operating expense increased due to seven months of
operating expense related to the EQT and Carbon acquisitions, both
acquired in May 2020, as well as a full year of operating expenses
related to the HG Energy and EdgeMarc assets acquired in April 2019
and September 2019, respectively. See Note 5 for additional
information on acquisitions.
(f) Other administrative expense includes general liability
insurance, IT services, other office expenses and travel.
(g) Professional fees include legal, marketing, payroll, and
consultation fees and costs associated with being a public
company.
(h) Auditors' remuneration includes fees payable to the Group's
auditor for the audit of the Group and Company annual accounts,
accounts of subsidiaries and other assurance services. Please refer
to the table below for more information.
(i) Adjusted G&A includes payroll and benefits for our
management, directors and administrative staff, costs of
maintaining administrative offices, costs of managing our
production operations, franchise taxes, public company costs,
non-cash equity issuance, fees for audit and other professional
services, and legal compliance.
(j) Non-recurring costs associated with acquisitions primarily
relate to transition services, IT integration, legal and consulting
costs directly related to acquisitions.
(k) Other non-recurring costs for 2020 are associated with legal
and professional fees related to the up-list to the Premium Segment
of the Main Market of the LSE and expenses for a one-time hedge
portfolio modification. For 2019, other non-recurring costs are
associated with early buyouts of long-term firm transportation
agreements, severance packages, temporary service agreements for
onboarding of acquired assets and consolidation of the Group's
corporate structure.
(l) Non-cash equity issuances in 2020 and 2019, reflect the
expense recognition related to share-based compensation provided to
certain key managers.
(m) Non-recurring and/or non-cash G&A includes costs related
to acquisitions, the Group's up-list to the Main Market of the LSE,
and other one-time events.
(n) Allowance for credit losses consists of expected credit
losses and a non-recurring increase in the reserve for joint
interest owner receivables. Refer to Note 15 for additional
information.
The average monthly number of employees was as follows:
Year Ended
--------------------------
31 December 31 December
2020 2019
----------- -------------
Number of production support employees, including
Directors 183 156
Number of production employees 924 768
----------- -----------
Workforce 1,107 924
=========== ===========
The Directors consider that the Group's key management personnel
comprise the Directors. The Directors' remuneration was as follows
for the periods presented:
Year Ended
------------------------------
31 December 31 December
2020 2019
------------- ---------------
Executive Directors
Salary $ 1,090 $ 775
Taxable benefits (a) 16 11
Benefit plan (b) 32 22
Bonus 1,537 1,124
------------- -------------
Total Executive Directors' remuneration 2,675 1,932
------------- -------------
Non-Executive Directors
Salary 763 374
------------- -------------
Total Non-Executive Directors' remuneration 763 374
------------- -------------
Total remuneration $ 3,438 $ 2,306
========= =========
(a) Taxable benefits were comprised of Group paid life insurance
premiums and automobile reimbursements.
(b) Benefit plan amounts reflect matching contributions under the Group's 401(k) plan.
Auditors' remuneration for the Group was as follows for the
periods presented:
Year Ended
------------------------------
31 December 31 December
2020 2019
------------- ---------------
Auditors remuneration (PwC)
Fees payable to the Company's external auditors
and their associates for the audit of the
consolidated financial statements $ 1,196 $ -
Audit-related assurance services (a) 1,146 -
Other assurance services 87 -
------------- -------------
Total auditors' remuneration (PwC) 2,429 -
------------- -------------
Auditors' remuneration (Crowe)
Fees payable to the Company's external auditors
and their associates for the audit of the
consolidated financial statements - 350
Audit-related assurance services - 1,092
Other assurance services - 225
------------- -------------
Total auditors' remuneration (Crowe) - 1,667
------------- -------------
Total auditors' remuneration $ 2,429 $ 1,667
========= =========
(a) Fees incurred associated with the up-list to the Main Market of the LSE.
NOTE 8 - TAXATION
The Group files a consolidated US federal tax return, multiple
state tax returns, and a separate UK tax return for the Parent
entity. Income taxes are provided for the tax effects of
transactions reported in the Group Financial Information and
consist of taxes currently due plus deferred taxes related to
differences between the basis of assets and liabilities for
financial and income tax reporting.
For the taxable years ending 31 December 2020 and 2019, the
Group had a tax benefit of $113,266 and an expense of $32,091,
respectively. The Group's effective tax rate was 82.8% and 24.4%
for the same periods, respectively. The effective tax rate is
primarily impacted by the Group's recognition of the federal well
tax credit available to qualified producers in 2020 who operate
lower-volume wells during a low commodity pricing environment. The
federal government provides these credits to encourage companies to
continue producing lower-volume wells during periods of low prices
to maintain the underlying jobs they create and the state and local
tax revenues they generate for communities to support schools,
social programs, law enforcement and other similar public services.
The federal tax credit is prescribed by Internal Revenue Code
Section 45I and is available for certain natural gas production
from qualifying wells. In May 2020, the US Internal Revenue Service
released Notice 2020-34 which quantified the amount of credit per
Mcf of qualified natural gas production for tax years beginning in
2019 and also detailed the calculation methodology for future
years. The federal tax credit is intended to provide a benefit for
wells producing less than 90 Mcfe per day when market prices for
natural gas are relatively low. The Group benefits from this credit
given its portfolio of long-life, low-decline conventional wells.
Other impacts to the effective rate include changes in state tax
rates as a result of acquisitions and recurring permanent
differences, such as meals and entertainment.
The provision for income taxes in the Consolidated Statement of
Comprehensive Income is summarised below:
Year Ended
------------------------------
31 December 31 December
2020 2019
------------- ---------------
Current income tax expense
Federal $ 233 $ 654
State 4,923 2,217
Foreign - UK 616 142
------------- -------------
Total current income tax expense 5,772 3,013
============= =============
Deferred income tax (benefit) expense
Federal (108,627) 22,253
State (10,411) 6,825
------------- -------------
Total deferred income tax (benefit) expense (119,038) 29,078
============= =============
Total income tax (benefit) expense $ (113,266) $ 32,091
========= =========
The effective tax rates and differences between the statutory US
federal income tax rate and the effective tax rates are summarised
as follows:
Year Ended
-------------------------------
31 December 31 December
2020 2019
-------------- ---------------
Income (loss) before taxation $(136,740) $ 131,491
Income tax benefit (expense) 113,266 (32,091)
---------- -----------
Effective tax rate 82.8% 24.4%
========== ===========
Year Ended
---------------------------------------------
31 December 2020 31 December 2019
--------------------- ----------------------
Expected tax at statutory
US federal income tax rate $ (28,715) 21.0% $ 27,613 21.0%
State income taxes, net of
federal tax benefit (7,451) 5.4% 7,946 6.0%
Federal credits (80,380) 58.8% (7,000) (5.3)%
Other, net 3,280 (2.4)% 3,532 2.7%
---------- ----- ----------- -----
Effective tax rate $(113,266) 82.8% $ 32,091 24.4%
========= ===== ======= =====
The Group had a net deferred tax liability of $969 at 31
December 2020 compared to a net deferred tax liability of $124,112
at 31 December 2019. The deferred tax liability decreased by
$123,143, primarily due to unrealised losses for unsettled
derivatives not recognised for tax purposes, the recognition of
federal tax credits, and the utilisation of federal and state net
operating losses. The presentation in the balance sheet takes into
consideration the offsetting of deferred tax assets and deferred
tax liabilities within the same tax jurisdiction, where permitted.
The overall deferred tax position in a particular tax jurisdiction
determines if a deferred tax balance related to that jurisdiction
is presented within deferred tax assets or deferred tax
liabilities.
The following table presents the components of the net deferred
income tax asset included in non-current assets and net deferred
income tax liability included in non-current liabilities as at the
periods presented:
31 December 31 December
2020 2019
------------- ---------------
Deferred tax asset
Asset retirement obligations $ 90,949 $ 52,254
Derivative financial instruments 46,237 -
Allowance for doubtful accounts 2,968 841
Net operating loss carryover 474 43,262
Federal tax credits carryover 99,117 19,502
Other 4,160 2,344
------------- -------------
Total deferred tax asset 243,905 118,203
------------- -------------
Deferred tax liability
Amortisation and depreciation (244,874) (228,004)
Derivative financial instruments - (14,311)
------------- -------------
Total deferred tax liability (244,874) (242,315)
------------- -------------
Net deferred tax liability $ (969) $ (124,112)
=== ======== =========
Balance sheet presentation
Deferred tax asset $ 14,777 $ -
Deferred tax liability (15,746) (124,112)
------------- -------------
Net deferred tax liability $ (969) $ (124,112)
=== ======== =========
In assessing the realisability of deferred tax assets, the Group
considers whether it is probable that some or all the deferred tax
assets will not be realised. The ultimate realisation of deferred
tax assets is dependent upon the generation of future taxable
income during the periods in which those temporary differences
become deductible or before credits expire. The Group considers the
scheduled reversal of deferred tax liabilities, projected future
taxable income and tax planning strategies in making this
assessment. The Group has determined, at this time, to recognise
its deferred tax assets.
The Group reported the effects of deferred tax expense as at and
for the year ended 31 December 2020:
Consolidated
Statement
Opening of Comprehensive Closing
Balance Income Other (a) Balance
---------- ------------------- ----------- -------------
Asset retirement obligations $ 52,254 $ 38,695 $ - $ 90,949
Allowance for doubtful accounts 841 2,127 - 2,968
Net operating loss carryover 43,263 (43,181) 392 474
Federal tax credits carryover 19,503 79,614 - 99,117
Property, plant, and equipment
and natural gas and oil properties (228,005) (20,079) 3,210 (244,874)
Derivative financial instruments (14,311) 60,548 - 46,237
Other 2,343 1,314 503 4,160
---------- ------------------- ----------- -----------
Total deferred tax liability $(124,112) $ 119,038 $ 4,105 $ (969)
========= === ============== ======= =======
(a) Amounts primarily relate to deferred taxes acquired as part
of acquisition purchase accounting.
The Group reported the effects of deferred tax expense as at and
for the year ended 31 December 2019:
Consolidated
Statement
Opening of Comprehensive Closing
Balance Income Other (a) Balance
--------- ------------------- ----------- ------------
Asset retirement obligations $ 46,893 $ 5,361 $ - $ 52,254
Allowance for doubtful accounts 577 264 - 841
Net operating loss carryover 57,081 (13,818) - 43,263
Federal tax credits carryover 14,365 5,138 - 19,503
Property, plant, and equipment
and natural gas and oil properties (206,795) (21,210) - (228,005)
Derivative financial instruments (8,488) (5,823) - (14,311)
Other 1,334 1,009 - 2,343
--------- ------------------- ----------- ----------
Total deferred tax liability $(95,033) $ (29,079) $ - $(124,112)
======== =============== ===== ==== =========
(a) No acquisition purchase accounting deferred taxes were recorded in 2019.
The Group's deferred tax assets and liabilities all arise in the
US.
For US federal tax purposes, the Group is taxed as one
consolidated entity. The Group is subject to additional taxes in
its domiciled jurisdiction of the UK. For the years ended 31
December 2020 and 2019, the Group incurred $616 and $142 of income
tax liability in the UK, respectively.
The Group had an uncertain tax position liability of $1,837 at
31 December 2020 compared to a liability of $2,133 at 31 December
2019. At the date of acquisition, the Directors determined that
Alliance Petroleum had taken uncertain tax positions. The Group had
no other uncertain tax positions as at 31 December 2020.
For the year ended 31 December 2020, the Group utilised all of
its $196,200 federal net operating loss carryforwards ("NOLs")
reported as of 31 December 2019. With the acquisition of Carbon,
discussed in Note 5, the Group acquired $1,867 of NOLs, which are
subject to limitation. Additionally, the Group has US state NOLs of
approximately $2,025, which expire in 2038.
The Group had US federal well tax credit carryforwards of
approximately $99,117 at 31 December 2020 compared to $19,502 at 31
December 2019. As discussed earlier, the federal tax credit is
intended to provide a benefit for wells producing less than 90 Mcfe
per day when market prices for natural gas are relatively low. Due
to the low commodity price environment, the Group generated $80,380
of federal tax credits and utilised $765 for the year ended 31
December 2020. The tax credits expire in the years 2037 through
2040.
The Group had US federal capital loss carryforwards of $9,904 at
31 December 2020 compared to $17,600 at 31 December 2019. For the
year ended 31 December 2020, $7,700 of the capital loss
carryforwards expired, and the remaining amounts expire in 2023.
The Group does not expect to utilise these carryforwards, and
therefore, a deferred tax asset for these carryforwards has not
been recorded.
The Group completed a Section 382 study through 31 December 2020
in accordance with the Internal Revenue Code of 1986, as amended.
If the Group experiences an ownership change, tax credit
carryforwards can be utilised but are limited each year and could
expire before they are fully utilised. The study concluded that the
Group has not experienced an ownership change as defined by Section
382 since the last ownership change that occurred on 31 January
2018. The Directors expect its tax credit carryforwards, limited by
the 31 January 2018 ownership change, to be fully available for
utilisation by 2024. Based on the results of the study, it is
reasonably possible that a change in shareholder ownership could
occur in 2021.
NOTE 9 - ADJUSTED NET INCOME AND HEDGED ADJUSTED EBITDA
Adjusted Net Income and Hedged Adjusted EBITDA are defined as
operating profit (loss) plus or minus the items detailed in the
table below. These metrics are of particular interest to the
industry and the Group. Adjusted Net Income represents net income
when excluding non-cash and non-recurring amounts while Hedged
Adjusted EBITDA is essentially the cash generated from operations
that the Group has free for principal and interest payments,
capital investments and dividend payments. Adjusted Net Income and
Hedged Adjusted EBITDA should not be considered as an alternative
to operating profit (loss), comprehensive income, cash flow from
operating activities or any other financial performance or
liquidity measure presented in accordance with IFRS.
The Directors believe Adjusted Net Income and Hedged Adjusted
EBITDA are useful measures because they enable a more effective way
to evaluate operating performance and compare results of operations
from period-to-period and against their peers without regard to the
Group's financing methods or capital structure. The Directors
exclude the items listed in the table below from operating profit
(loss) in arriving at Adjusted Net income and Hedged Adjusted
EBITDA for the following reasons:
-- Certain amounts are non-recurring from the operation of the business such as;
Gains or losses on foreign currency hedges;
Costs associated with acquisitions or other one-time events;
or
Gains or losses on natural gas and oil programme and
equipment.
-- Certain amounts are non-cash such as;
Amortisation, depreciation and depletion;
Gains or losses on the valuation of unsettled financial
instruments; or
Equity compensation costs included in G&A.
The following table reconciles income (loss) available to
shareholders after taxation to Adjusted Net Income and Hedged
Adjusted EBITDA for the periods presented:
Year Ended
------------------------------
31 December 31 December
2020 2019
Income (loss) available to shareholders after
taxation $ (23,474) $ 99,400
Loss on joint and working interest owners
receivable 6,931 730
Gain on bargain purchase (17,172) (1,540)
(Gain) loss on fair value adjustments of
unsettled financial instruments 238,795 (20,270)
(Gain) loss on natural gas and oil programme
and equipment 2,059 -
Non-recurring costs 25,046 16,752
Non-cash equity compensation 5,007 3,065
(Gain) loss on foreign currency hedge - (4,117)
(Gain) loss on interest rate swap 202 -
Tax effect on adjusting items (a) (62,608) 1,598
------------- -------------
Adjusted Net Income 174,786 95,618
Less: Tax effect on adjusting items to Adjusted
Net Income 62,608 (1,598)
Depreciation, depletion and amortisation 117,290 98,139
Finance costs 43,327 36,667
Accretion of asset retirement obligations 15,424 12,349
Other (income) expense 421 -
Loss on debt cancellation - -
Income tax (benefit) expense (113,266) 32,091
------------- -------------
Hedged Adjusted EBITDA 300,590 273,266
Adjusted EPS - basic $ 0.26 $ 0.15
========= === ========
Adjusted EPS - diluted $ 0.25 $ 0.15
========= === ========
Hedged Adjusted EBITDA per Share - basic $ 0.44 $ 0.43
========= === ========
Hedged Adjusted EBITDA per Share - diluted $ 0.44 $ 0.42
========= === ========
(a) The tax effect on adjusting items to Adjusted Net Income is
calculated using the Group's expected federal and state statutory
rates for the periods ended 31 December 2020 and 2019. These
expected statutory rates are presented in Note 8.
NOTE 10 - EARNINGS (LOSS) PER SHARE
The calculation of basic earnings (loss) per share is based on
the income (loss) available to shareholders after taxation and on
the weighted average number of shares outstanding during the
period. The calculation of diluted earnings per share is based on
the income (loss) available to shareholders after taxation and the
weighted average number of shares outstanding plus the weighted
average number of shares that would be issued if dilutive Options
and warrants were converted into shares on the last day of the
reporting period. Basic and diluted earnings (loss) per share are
calculated as follows for the periods presented:
Year Ended
------------------------------
31 December 31 December
Calculation 2020 2019
------------ ------------- ---------------
Income (loss) available to shareholders
after taxation A $ (23,474) $ 99,400
Weighted average shares outstanding
- basic B 685,170 641,666
Weighted average shares outstanding
- diluted C 688,348 644,782
Earnings (loss) per share - basic = A/B $ (0.03) $ 0.15
========= =========
Earnings (loss) per share - diluted = A/C $ (0.03) $ 0.15
========= =========
Hedged Adjusted EBITDA per Share - Note
basic 9 $ 0.44 $ 0.43
========= =========
Hedged Adjusted EBITDA per Share -
diluted $ 0.44 $ 0.42
========= =========
NOTE 11 - NATURAL GAS AND OIL PROPERTIES
The following table summarises the Group's natural gas and oil
properties for the periods presented:
Year Ended
------------------------------
31 December 31 December
2020 2019
------------- ---------------
Costs:
Beginning balance $ 1,625,884 $ 1,148,235
Additions (a) 346,385 487,649
Disposals (b) (3,712) (10,000)
------------- -------------
Ending balance $ 1,968,557 $ 1,625,884
--------- ---------
Depletion and impairment:
Beginning balance $ (129,855) $ (55,284)
Period changes (83,617) (74,571)
Disposals - -
------------- -------------
Ending balance $ (213,472) $ (129,855)
--------- ---------
Net book value $ 1,755,085 $ 1,496,029
========= =========
(a) For the year ended 31 December 2020, $103,991, $117,149 and
$7,083 in additions were related to the acquisitions of Carbon, EQT
and the Utica wells, respectively. The remaining change is
primarily attributable to revisions in the Group's asset retirement
obligations as a result of changes in the discount rate, please
refer to Note 19 for additional information. For the year ended 31
December 2019, $385,907 and $40,522 were related to the
acquisitions of HG Energy and EdgeMarc, respectively. See Note 5
for additional information regarding these acquisitions.
(b) In September 2020 the Group sold 662 wells in McKean,
Forest, and Warren Counties, Pennsylvania. In November 2019, the
Group sold the three drilled but uncompleted unconventional wells
that were acquired in the EdgeMarc acquisition.
Impairment of Natural Gas and Oil Properties
Having identified an impairment indicator relating to a decline
of natural gas and oil prices and the macroeconomic impacts of the
Covid-19 pandemic in the half-year accounts, the Directors
undertook an impairment test in line with the Group's accounting
policy. Having performed this assessment, no impairment was
recognised. For the period ended 31 December 2020, the Directors
reassessed the indicators of impairment, noting a recovery in
pricing and the economic outlook to the Group. As part of this
assessment the Directors also evaluated the current and projected
impact of climate change on the Group. As a result of their
assessment no additional impairment indicators were identified.
For the period ended 31 December 2019, the Directors compared
the carrying value of the Group's natural gas and oil properties to
their fair values. Based on this review, the carrying value of
natural gas and oil properties was not impaired.
NOTE 12 - PROPERTY, PLANT AND EQUIPMENT
The following table summarises the Group's property, plant and
equipment for the periods presented:
Year Ended 31 December 2020
-----------------------------------------------------------------------------
Buildings Other
and Leasehold Motor Midstream Property
Improvements Equipment Vehicles Assets and Equipment Total
-------------- ----------- --------- --------- ------------- -----------
Costs:
Beginning
balance $ 22,654 $ 4,438 $ 19,099 $ 306,537 $ 2,205 $ 354,933
Additions
(a)(b) 5,536 2,415 19,127 60,794 3,395 91,267
Disposals
(c) - (85) (3,097) - - (3,182)
-------------- ----------- --------- --------- ------------- ---------
Ending
balance
(d) $ 28,190 $ 6,768 $ 35,129 $ 367,331 $ 5,600 $ 443,018
--- --------- ------- -------- -------- --------- --------
Depletion and
impairment:
Beginning
balance $ (559) $ (1,987) $ (7,251) $(23,455) $ (728) $(33,980)
Period
changes (448) (876) (5,770) (20,142) (314) (27,550)
Disposals - 3 612 - - 615
-------------- ----------- --------- --------- ------------- ---------
Ending balance $ (1,007) $ (2,860) $(12,409) $(43,597) $ (1,042) $(60,915)
--- --------- ------- -------- -------- --------- --------
Net book value $ 27,183 $ 3,908 $ 22,720 $ 323,734 $ 4,558 $ 382,103
=== ========= ======= ======== ======== ========= ========
Year Ended 31 December 2019
--------------------------------------------------------------------------------
Buildings Other
and Leasehold Motor Midstream Property
Improvements Equipment Vehicles Assets and Equipment Total
-------------- ----------- ----------- --------- -------------- -----------
Costs:
Beginning
balance $ 8,963 $ 2,750 $ 18,879 $ 292,619 $ 2,108 $ 325,319
Additions
(a)(b) 13,691 1,688 220 13,918 97 29,614
Disposals
(c) - - - - - -
-------------- ----------- ----------- --------- -------------- ---------
Ending
balance
(d) $ 22,654 $ 4,438 $ 19,099 $ 306,537 $ 2,205 $ 354,933
--- --------- ------- ------- -------- --- --------- --------
Depletion and
impairment:
Beginning
balance $ (84) $ (87) $ (1,065) $(11,166) $ (28) $(12,430)
Period
changes (475) (1,900) (6,186) (12,289) (700) (21,550)
Disposals - - - - - -
-------------- ----------- ----------- --------- -------------- ---------
Ending balance $ (559) $ (1,987) $ (7,251) $(23,455) $ (728) $(33,980)
--- --------- ------- ------- -------- --- --------- --------
Net book value $ 22,095 $ 2,451 $ 11,848 $ 283,082 $ 1,477 $ 320,953
=== ========= ======= ======= ======== === ========= ========
(a) Of the $91,356 in 2020 additions, $46,713 and $10,956 were
related to the acquisitions of Carbon and EQT, respectively, while
$19,820 was associated with right-of-use asset additions for new
and amended leases. Of the $17,315 in 2019 additions, $7,700
relates to equipment purchased through the Dominion and Equitrans
acquisition. See Note 5 for additional information regarding these
acquisitions.
(b) Additions are related to routine capital projects on the
Group's compressor and gathering systems, vehicle and equipment
additions.
(c) Disposals are primarily related to $1,945 of vehicles
acquired as part of the Carbon acquisition being transferred to the
Group's fleet management and lease programme.
(d) Buildings and Leasehold improvements and motor vehicles is
inclusive of right-of-use assets associated with the Group's
leases. Refer to Note 21 for additional information.
The Group continued to utilise certain fully depreciated assets
during the years ended 31 December 2020 and 2019 with an original
cost basis of $3,313 and $1,820, respectively.
NOTE 13 - INTANGIBLE ASSETS
Intangible assets consisted of the following for the periods
presented:
Year Ended 31 December 2020
--------------------------------------------
Other Acquired
Software Intangibles Total
------------- ---------------- -----------
Costs:
Beginning balance $ 17,822 $ - $ 17,822
Additions (a) 6,449 2,900 9,349
Disposals - - -
------------- ---------------- ---------
Ending balance $ 24,271 $ 2,900 $ 27,171
--------- ------------ --------
Accumulated amortisation:
Beginning balance $ (1,841) $ - $ (1,841)
Period changes (5,405) (712) (6,117)
Disposals - - -
------------- ---------------- ---------
Ending balance $ (7,246) $ (712) $ (7,958)
--------- ------------ --------
Net book value $ 17,025 $ 2,188 $ 19,213
========= ============ ========
Year Ended 31 December 2019
------------------------------------------------
Other Acquired
Software Intangibles Total
--------------- ---------------- -------------
Costs:
Beginning balance $ 2,775 $ - $ 2,775
Additions (a) 15,047 - 15,047
Disposals - - -
--------------- ---------------- -----------
Ending balance $ 17,822 $ - $ 17,822
----------- ---------- ---- ----------
Accumulated amortisation:
Beginning balance $ (212) $ - $ (212)
Period changes (1,629) - (1,629)
Disposals - - -
--------------- ---------------- -----------
Ending balance $ (1,841) $ - $ (1,841)
----------- ---------- ---- ----------
Net book value $ 15,981 $ - $ 15,981
=========== ========== ==== ==========
(a) For the year ended 31 December 2020 additions were related
to software enhancements and $2,900 in other acquired intangibles.
For the year ended 31 December 2019 additions were related to costs
associated with the Group's ERP project.
NOTE 14 - DERIVATIVE FINANCIAL INSTRUMENTS
The Group is exposed to volatility in market prices and basis
differentials for natural gas, NGLs and oil, which impacts the
predictability of its cash flows related to the sale of those
commodities. The Group is also exposed to volatility in interest
rate markets, which impacts the predictability of its cash flows
related to interest payments on the Group's variable rate debt
obligations. These risks are managed by the Group's use of certain
derivative financial instruments. As of 31 December 2020, the
Group's derivative financial instruments consisted of swaps,
collars, basis swaps, stand alone put and call options, and
swaptions. A description of the Group's derivative financial
instruments is provided below:
-- Swaps : If the Group sells a swap, it receives a fixed price
for the contract and pays a floating market price to the
counterparty.
-- Collars : Arrangements that contain a fixed floor price
(purchased put option) and a fixed ceiling price (sold call option)
based on an index price which, in aggregate, have no net costs. At
the contract settlement date, (1) if the index price is higher than
the ceiling price, the Group pays the counterparty the difference
between the index price and ceiling price, (2) if the index price
is between the floor and ceiling prices, no payments are due from
either party, and (3) if the index price is below the floor price,
the Group will receive the difference between the floor price and
the index price.
-- Basis swaps : Arrangements that guarantee a price
differential for commodities from a specified delivery point. If
the Group sells a basis swap, it receives a payment from the
counterparty if the price differential is greater than the stated
terms of the contract and pays the counterparty if the price
differential is less than the stated terms of the contract.
-- Put options : The Group purchases and sells put options in
exchange for a premium. If the Group purchases a put option, it
receives from the counterparty the excess (if any) of the market
price below the strike price of the put option at the time of
settlement, but if the market price is above the put's strike
price, no payment is due from either party.
-- Call options : The Group purchases and sells call options in
exchange for a premium. If the Group purchases a call option, it
receives from the counterparty the excess (if any) of the market
price over the strike price of the call option at the time of
settlement, but if the market price is below the call's strike
price, no payment is due from either party. If the Group sells a
call option, it pays the counterparty the excess (if any) of the
market price over the strike price of the call option at the time
of settlement, but if the market price is below the call's strike
price, no payment is due from either party.
-- Swaptions : If the Group sells a swaption, the counterparty
will receive the option to enter into a swap contract at a
specified date and receives a fixed price for the contract and pays
a floating market price to the counterparty.
The Group may elect to enter into offsetting transactions for
the above instruments for the purpose of cancelling or terminating
certain positions.
The following tables summarise the Group's calculated net fair
value of derivative financial instruments as of the reporting date
as follows:
NATURAL GAS Weighted Average Price per Mcfe
CONTRACTS (a)
--------------------------------------------------------------
Fair Value
Volume Sold Purchased Sold Purchased Basis at
31 December
(MMcf) Swaps Puts Puts Calls Calls Differential 2020
--------- ----- ------ ----------- ----- ----------- -------------- ------------
2021
Swaps 186,347 $2.93 $ - $ - $ - $ - $ - $ 2,447
Stand-Alone
Calls 7,300 - - - 2.86 - - (2,116)
Basis Swap 106,632 - - - - - (0.47) 12,126
--------- ----------
Total 2021 contracts 300,279 $ 12,457
--------- ---------
2022
Swaps 118,884 $2.81 $ - $ - $ - $ - $ - $ (6,817)
Stand-Alone
Calls 71,175 3.06 - - - - - (20,036)
Basis Swap 33,539 - - - - - (0.48) 2,855
--------- ----------
Total 2022 contracts 223,598 $ (23,998)
--------- ---------
2023
Swaps 88,957 $2.68 $ - $ - $ - $ - $ - $ (1,625)
Stand-Alone
Calls 85,392 3.04 - - - - - (19,028)
Basis Swap 900 - - - - - (0.51) 53
--------- ----------
Total 2023 contracts 175,249 $ (20,600)
--------- ---------
2024
Swaps 81,739 $2.66 $ - $ - $ - $ - $ - $ (4,845)
Stand-Alone
Calls 9,150 2.86 - - - - - (3,023)
Total 2024 contracts 90,889 $ (7,868)
--------- ---------
2025
Swaps 65,864 $2.63 $ - $ - $ - $ - $ - $ (8,928)
2026
Swaps 42,454 $2.61 $ - $ - $ - $ - $ - $ (8,888)
2027
Swaps 33,820 $2.60 $ - $ - $ - $ - $ - $ (7,343)
2028
Swaps 32,190 $2.57 $ - $ - $ - $ - $ - $ (8,218)
2029
Swaps 29,190 $2.57 $ - $ - $ - $ - $ - $ (8,410)
2030
Swaps 5,450 $2.50 $ - $ - $ - $ - $ - $ (2,557)
Swaptions
1/1/2022-1/12/2022
(b) 14,600 $ - $ - $ - $2.92 $ - $ - $ (1,693)
1/10/2024-1/9/2028
(c) 14,610 - - - 2.99 - - (3,837)
1/1/2025-1/12/2029
(d) 36,520 - - - 2.85 - - (7,827)
1/4/2026-1/3/2030
(e) 97,277 - - - 2.64 - - (34,024)
1/4/2030-1/3/2032
(f) 42,627 - - - 2.64 - - (21,453)
--------- ----------
Total 2025-2032
contracts 205,634 $ (68,834)
--------- ---------
Total natural
gas contracts 1,204,617 $(153,187)
========= =========
(a) Rates have been converted from Btu to Mcfe using a Btu conversion factor of 1.10.
(b) Option expires on 23 December 2021.
(c) Option expires on 6 September 2024.
(d) Option expires on 23 December 2024.
(e) Option expires on 23 March 2026.
(f) Option expires on 22 March 2030.
NGLs
CONTRACTS Weighted Average Price per Bbl
Fair Value
Volume Sold Purchased Sold Purchased Basis at
31 December
(MBbls) Swaps Puts Puts Calls Calls Differential 2020
------- --------- ------ ----------- ------- ----------- -------------- --------------
2021
Swaps
(a) 2,130 $ 20.73 $ - $ - $ - $ - $ - $ (14,983)
Total NGLs
contracts 2,130 $ (14,983)
======= ========
(a) Certain portions of NGL swaps include effects of purchased
oil swaps intended to provide a final NGL price as a percentage of
WTI.
OIL Weighted Average Price per Bbl
CONTRACTS
Volume Sold Purchased Sold Basis Fair Value
Purchased at
(MBbls) Swaps Puts Puts Calls Differential 31 December
Calls 2020
------- --------- ------ ----------- ------- ----------- -------------- ------------
2021
Sold
Swaps 139 $ 44.21 $ - $ - $ - $ - $ - $ (565)
Long
Swaps 306 32.63 - - - - - 4,770
Collars 121 - - 52.01 67.72 - - 809
------- ----------
Total 2021
contracts 566 $ 5,014
2022
Swaps 110 $ 43.06 $ - $ - $ - $ - $ - $ (409)
2023
Swaps 70 37.00 - - - $ - - (601)
2024
Swaps 64 37.00 - - - $ - - (511)
2025
Swaps 56 37.00 - - - $ - - (430)
2026
Swaps 13 37.00 - - - $ - - (102)
------- ----------
Total oil
contracts 879 $ 2,961
======= === =====
Fair Value
INTEREST at
Principal 31 December
Hedged Fixed Rate 2020
----------- ------------ ---------------
2022
LIBOR Interest Rate Swap $ 150,000 0.45% $ (598)
Net fair value of derivative financial
instruments $ (165,807)
=========
Netting the fair values of derivative assets and liabilities for
financial reporting purposes is permitted if such assets and
liabilities are with the same counterparty and a legal right of
set-off exists, subject to a master netting arrangement. The
Directors have elected to present derivative assets and liabilities
net when these conditions are met. The following table outlines the
Group's net derivatives as of the reporting date as follows:
Derivative Financial Consolidated Statement 31 December 31 December
Instruments of Financial Position 2020 2019
------------------------------- ------------------------- ------------- ---------------
Assets:
Derivative financial
Non-current assets instruments $ 717 $ 3,803
Derivative financial
Current assets instruments 17,858 73,705
------------- -------------
Total assets $ 18,575 $ 77,508
--------- ---------
Liabilities
Derivative financial
Non-current liabilities instruments $ (168,524) $ (15,706)
Derivative financial
Current liabilities instruments (15,858) -
------------- -------------
Total liabilities $ (184,382) $ (15,706)
--------- ---------
Net assets (liabilities):
Net assets (liabilities) Other non-current assets
- non-current (liabilities) $ (167,807) $ (11,903)
Net assets (liabilities) Other current assets
- current (liabilities) 2,000 73,705
------------- -------------
Total net assets (liabilities) $ (165,807) $ 61,802
========= =========
The Group's policy is to present the fair value of derivative
contracts on a net basis in the consolidated balance sheet. The
following presents the impact of this presentation to the Group's
recognised assets and liabilities for the periods indicated:
As at 31 December 2020
---------------------------------------------------
Presented As Presented
without Effects Effects of with Effects
of Netting Netting of Netting
------------------ ------------ -----------------
Non-current assets $ 25,159 $ (24,442) $ 717
Current assets 42,023 (24,165) 17,858
------------------ ------------ ---------------
Total assets 67,182 (48,607) 18,575
Non-current liabilities (192,967) 24,443 (168,524)
Current liabilities (40,022) 24,164 (15,858)
------------------ ------------ ---------------
Total liabilities (232,989) 48,607 (184,382)
Total net assets (liabilities) $ (165,807) $ - $ (165,807)
============== ======== ===========
As at 31 December 2019
---------------------------------------------------
Presented As Presented
without Effects Effects of with Effects
of Netting Netting of Netting
------------------ ------------ -----------------
Non-current assets $ 35,657 $ (31,854) $ 3,803
Current assets 93,548 (19,843) 73,705
------------------ ------------ ---------------
Total assets 129,205 (51,697) 77,508
Non-current liabilities (47,560) 31,854 (15,706)
Current liabilities (19,843) 19,843 -
------------------ ------------ ---------------
Total liabilities (67,403) 51,697 (15,706)
Total net assets (liabilities) $ 61,802 $ - $ 61,802
============== ======== ===========
The Group recorded the following gain (loss) on derivative
financial instruments in the Consolidated Statement of
Comprehensive Income for the periods presented:
Year Ended
------------------------------
31 December 31 December
2020 2019
------------- ---------------
Net gain (loss) on commodity derivatives
(a) $ 144,600 $ 49,467
Net gain (loss) on interest rate swap (202) -
Gain on foreign currency hedge - 4,117
------------- -------------
Total gain (loss) on settled derivative instruments 144,398 53,584
Gain (loss) on fair value adjustments of
unsettled financial instruments (b) (238,795) 20,270
------------- -------------
Total gain (loss) on derivative financial
instruments $ (94,397) $ 73,854
========= =========
(a) Represents the cash settlement of hedges that settled during the period.
(b) Represents the change in fair value of financial instruments
net of removing the carrying value of hedges that settled during
the period.
All derivatives are defined as Level 2 instruments as they are
valued using inputs and outputs other than quoted prices that are
observable for the assets and liabilities.
The Group enters into derivative contracts to reduce the effect
of commodity price volatility on its cash flows, and enters into
these contracts at the legal entity level that holds the Group's
borrowings. Accordingly, the Group maintains distinct, long-dated
derivative contract portfolios for its ABS financings and Term Loan
I. The Group also maintains a separate derivative contract
portfolio related to its Credit Facility. Infrequently, the Group
adjusts portions of its derivative contract portfolio across these
legal entities to ensure that it maintains the appropriate level
and composition at both the legal entity and full-Group level.
During the year ended 31 December 2020, the Group paid $10,963 to
modify certain derivative contracts, which it excluded from Hedged
Adjusted EBITDA due to their non-recurring nature. Modifications
include the quantum of production subject to contracts, the swap or
floor price of certain contracts and similar elements of it. Of the
$10,963, $3,240 related to the Group's ABS II financing
transaction, which refinanced a portion of its Credit Facility
borrowings. To facilitate the price protection for ABS II, the
Group initiated the necessary derivative contracts required by the
lender with a member of its existing Credit Facility. After closing
ABS II, the Group novated certain contracts to the legal entity
holding ABS II. The remaining payments of $7,723 related to
offsetting positions for derivative contracts on its Credit
Facility, which the Group recorded as new derivative financial
instruments on its Consolidated Statement of Financial Position.
For more information on the Group's financing arrangements see Note
22.
NOTE 15 - TRADE AND OTHER RECEIVABLES
Trade receivables include amounts due from customers, entities
that purchase the Group's natural gas, NGLs and oil production, and
also include amounts due from joint interest owners, entities that
own a working interest in the properties operated by the Group. The
majority of trade receivables are current and the Group believes
these receivables are collectible. At 31 December 2020 and 2019,
the Group recorded an allowance for current expected credit losses
of $11,082 and $3,210, respectively. The following table summarises
the Group's trade receivables. The fair value approximates the
carrying value as at the periods presented:
31 December 31 December
2020 2019
------------- ---------------
Commodity receivables $ 70,199 $ 64,522
Other receivables 7,874 12,612
------------- -------------
Total trade receivables 78,073 77,134
Allowance for credit losses (a) 11,082 3,210
------------- -------------
Total trade receivables, net $ 66,991 $ 73,924
========= =========
(a) For the period ended 31 December 2020 the Group recorded a
non-recurring increase in the reserve of joint interest owner
receivables of $6,931. Due to the historical low pricing
environment, the Group increased the allowance for credit losses
related to amounts due from joint interest owners.
NOTE 16 - OTHER ASSETS
The following table includes a detail of other assets as at the
periods presented:
31 December 31 December
2020 2019
------------- ---------------
Other non-current assets
Other non-current assets $ 2,376 $ 176
Indemnification receivable (a) 1,837 2,133
------------- -------------
Total other non-current assets $ 4,213 $ 2,309
========= =========
Other current assets
Prepaid expenses $ 1,681 $ 4,317
Other receivables - 383
Inventory 6,315 5,163
------------- -------------
Total other current assets $ 7,996 $ 9,863
========= =========
(a) At the date of acquisition, the Directors determined that
Alliance Petroleum had taken uncertain tax positions, and as a
result, an indemnification agreement was executed. The Group
recorded an indemnification receivable for the amount of $1,837 and
$2,133 as at 31 December 2020 and 2019, respectively. In accordance
with IFRS 3, the Group assigned acquisition date fair value to the
indemnification asset using the same valuation techniques used to
determine the acquisition date fair value of the related
liability.
NOTE 17 - SHARE CAPITAL
Share capital represents the nominal (par) value of shares
(GBP0.01) that have been issued. Share premium includes any
premiums received on issue of share capital above par. Any
transaction costs associated with the issuance of shares are
deducted from share premium, net of any related income tax
benefits. The components of share capital include:
Issuance of Share Capital
In May 2020, the Group placed 64,281 new shares at $1.33 per
share (GBP1.08) to raise gross proceeds of $85,415 (approximately
GBP69,423). Associated costs of the placing were $4,008. The Group
used the proceeds to partially fund the acquisition of certain
assets of Carbon and EQT, discussed in Note 5.
In April 2019, the Group placed 151,515 new shares at $1.52 per
share (GBP1.17) to raise gross proceeds of $230,676 (approximately
GBP177,278). Associated costs of the placing were $8,817.The Group
used the proceeds to fund the HG Energy acquisition, discussed in
Note 5.
Repurchase of Shares
During the year ended 31 December 2020, the Group repurchased
12,958 treasury shares at an average price of $1.21 totalling
$15,634.
During the year ended 31 December 2019, the Group repurchased
38,662 treasury shares at an average price of $1.36 totalling
$52,902. The Group has accounted for the repurchase of these shares
as a direct reduction to retained earnings.
All repurchased treasury shares have been cancelled.
The following tables summarise the Group's share capital, net of
customary transaction costs, for the periods presented:
Number of Total Share Total Share
Shares Capital Premium
--------- ------------- ---------------
Balance at 31 December 2018 542,654 $ 7,346 $ 540,655
========= ========= =========
Issuance of share capital 151,515 1,972 219,888
Repurchase of shares (38,662) (518) -
Other issues (a) 223 - -
--------- ------------- -------------
Balance at 31 December 2019 655,730 $ 8,800 $ 760,543
========= ========= =========
Issuance of share capital 64,281 791 80,616
Repurchase of shares (12,958) (74) -
Other issues (a) 324 3 -
--------- ------------- -------------
Balance at 31 December 2020 707,377 $ 9,520 $ 841,159
========= ========= =========
(a) During the years ended 31 December 2020 and 2019, the Group
issued 324 and 223 RSUs, respectively, to certain key managers. The
RSUs had no impact on share premium.
NOTE 18 - NON-CASH SHARE-BASED COMPENSATION
Equity Incentive Plan
The 2017 Equity Incentive Plan (the "Plan"), as amended through
11 May 2020, authorised and reserved for issuance 50,681 shares of
common stock, which may be issued upon exercise of vested Options,
RSUs and PSUs, that are granted under the Plan. As at 31 December
2020, 1,023 shares have vested and been made available to Plan
participants while 31,110 shares have been granted but remain
unvested.
Options Awards
The following table summarises Options award activity for the
years ended 31 December 2020 and 2019:
Weighted Average
Grant Date
Number of Fair Value
Shares per Share
--------- --------------------
Balance at 31 December 2018 15,450 $ 0.33
=========
Granted 8,520 0.59
Vested - -
Forfeited (300) 0.33
---------
Balance at 31 December 2019 23,670 $ 0.42
=========
Granted - -
Vested - -
Forfeited (650) 0.37
---------
Balance at 31 December 2020 23,020 $ 0.43
=========
The Group's Options ratably vest over a three-year period and
contain both performance and service metrics. The performance
metrics include Adjusted EPS as compared to pre-established
benchmarks and a calculation that compares the Group's TSR to
pre-established benchmarks. The number of units that will vest can
range between 0% and 100% of the award.
The fair value of the Group's Options are calculated using the
Black-Scholes model as of the grant date. The inputs to the
Black-Scholes model included the following for Options granted
during the years ended 31 December 2020 and 2019:
31 December 31 December
2020 (a) 2019
------------------ ---- ---------------
The share price at the date of grant GBP - GBP 1.25
Exercise price GBP - GBP 1.20
Expected volatility - % 31%
Expected dividends - % -%
Risk-free rate of interest - % 2.25%
Options life - 10 years
(a) No Options were awarded during the year ended 31 December 2020.
(b) Volatility was calculated utilising the historical volatility for the Group's share price.
The fair value of the grant of the Group's Options is uniformly
expensed over the vesting period.
RSU and PSU Awards
The following table summarises RSU equity award activity for the
years ended 31 December 2020 and 2019:
Weighted Average
Grant Date
Number of Fair Value
Shares per Share
--------- --------------------
Balance at 31 December 2018 672 $ 0.92
=========
Granted 900 1.30
Vested (320) 0.91
Forfeited - -
---------
Balance at 31 December 2019 1,251 $ 1.20
=========
Granted 7,309 1.18
Vested (470) 1.08
Forfeited - -
---------
Balance at 31 December 2020 8,090 $ 1.19
=========
RSUs cliff-vest based on service conditions, while PSUs
cliff-vest based on three performance criteria which include a
three-year average adjusted return on equity as compared to
pre-established benchmarks, a calculation that compares the Group's
TSR to pre-established benchmarks as well as the same calculated
return for a group of peer companies as selected by the Group. The
number of units that will vest can range between 0 % and 100% of
the award.
The fair value of the Group's RSUs and PSUs is determined using
the stock price at the grant date and uniformly expensed over the
vesting period.
Share-Based Compensation Expense
The following table presents share-based compensation expense
for the respective periods:
31 December 31 December
2020 2019
------------- ---------------
Options $ 2,553 $ 2,095
RSUs and PSUs 2,483 367
------------- -------------
Total share-based compensation expense $ 5,036 $ 2,462
========= =========
NOTE 19 - DIVIDS
The following table summarises the Group's dividends declared
and paid on the dates indicated:
Dividend
per Share
--------------------
Gross
Date Dividends Record Shares Dividends
Declared/Paid USD GBP Date Pay Date Outstanding Paid
------------------ ------- ----------- ----------- ------------ ------------ --------------
Declared on 14
December 8 March 29 March
2018 $0.0330 GBP 0.0253 2019 2019 542,654 17,908
Declared on 28
February 12 April 28 June
2019 $0.0340 GBP 0.0239 2019 2019 542,654 18,450
Declared on 13
June 6 September 27 September
2019 $0.0342 GBP 0.0278 2019 2019 663,636 22,696
Declared on 8
August 29 November 20 December
2019 $0.0350 GBP 0.0269 2019 2019 659,903 23,097
------------
Paid during the
year
ended 31 December
2019 $ 82,151
========
Declared on 10
December 6 March 27 March
2019 $0.0350 GBP 0.0276 2020 2020 642,805 22,498
Declared on 9
March 29 May 26 June
2020 $0.0350 GBP 0.0274 2020 2020 707,086 24,748
Declared on 4 May 4 September 25 September
2020 $0.0350 GBP 0.0269 2020 2020 707,274 24,755
Declared on 10
August 27 November 18 December
2020 $0.0375 GBP 0.0278 2020 2020 707,377 26,526
------------
Paid during the
year
ended 31 December
2020 $ 98,527
========
On 29 October 2020 the Group proposed a dividend of $0.0400 per
share. The dividend will be paid on 26 March 2021 to shareholders
on the register on 5 March 2021. This dividend was not approved by
shareholders, thereby qualifying it as an "interim" dividend. No
liability was recorded in the Group Financial Information in
respect of this interim dividend as at 31 December 2020.
Subsequent Events
On 8 March 2021 the Directors recommended a final quarter
dividend of $0.0400 per share. The dividend would be paid on 24
June 2021 to shareholders on the register on 28 May 2021, subject
to shareholder approval at the AGM. No liability has been recorded
in the Group Financial Information in respect of this dividend as
at 31 December 2020.
NOTE 20 - ASSET RETIREMENT OBLIGATIONS
The Group records a liability for the future cost of
decommissioning its natural gas and oil properties, which it
expects to incur over the long producing life of its wells (the
Group presently expects all of its existing wells to have reached
the end of their economic lives by approximately 2095).
The Group also records a liability for the future cost of
decommissioning its production facilities and pipelines if required
by contract or statute. The decommissioning liability represents
the present value of estimated future decommissioning costs. No
such contractual agreements or statutes were in place for the Group
for the periods ended 31 December 2020 and 2019.
In estimating the present value of future decommissioning costs
of natural gas and oil properties the Group takes into account the
number and state jurisdictions of wells, current costs to
decommission by state and the average well life across its
portfolio. The Directors' assumptions are based on the current
economic environment and represent what the Directors believe is a
reasonable basis upon which to estimate the future liability.
However, actual decommissioning costs will ultimately depend upon
future market prices at the time the decommissioning services are
performed. Furthermore, the timing of decommissioning will vary
depending on when the fields cease to produce economically, making
the determination dependent upon future natural gas and oil prices,
which are inherently uncertain.
The Group applies a contingency allowance for annual cost
increases and discounts the resulting cash flows using a credit
adjusted risk free discount rate. The Group considers the Bloomberg
15-year US Energy BB bond to most closely align with the underlying
long-term and unsecured liability and has derived its risk adjusted
rate by reference to that. The net discount rate used in the
calculation of the decommissioning liability in 2020 and 2019 was
3.7% and 5.0%, respectively.
The composition of the provision for asset retirement
obligations at the reporting date was as follows for the periods
presented:
Year Ended
------------------------------
31 December 31 December
2020 2019
------------- ---------------
Balance at beginning of period $ 199,521 $ 142,725
Additions (a) 26,995 252
Accretion 15,424 12,349
Plugging costs (2,442) (2,541)
Disposals (3,838) -
Revisions to estimate (b) (c) 110,464 46,736
------------- -------------
Balance at end of period 346,124 199,521
Less: Current asset retirement obligations 1,882 2,650
------------- -------------
Non-current asset retirement obligations $ 344,242 $ 196,871
========= =========
(a) See Note 5 for more information about the Group's acquisitions.
(b) At 31 December 2020, the Group performed normal revisions to
its asset retirement obligations which resulted in a $110,464
adjustment, of which $102,686 relates to macroeconomic factors
stemming largely from the Covid-19 pandemic that reduced bond
yields and resulted in a lower discount rate applied to our asset
retirement obligations liability. The remaining $7,778 relates to
pricing-related adjustments based on historical costs incurred to
plug and abandon wells.
(c) At 31 December 2019, the Group performed normal revisions to
its asset retirement obligations which resulted in a $46,736
adjustment, of which $42,650 relates to macroeconomic factors that
reduced bond yields and resulted in a lower discount rate applied
to our asset retirement obligations liability. The remaining $4,086
relates to pricing-related adjustments based on historical costs
incurred to plug and abandon
Changes to assumptions used as inputs for the estimation of the
Group's asset retirement obligations could result in a material
change in the carrying value of the liability. A reasonably
possible fifty basis point decline in the gross discount rate could
have an approximately $69,675 impact on the Group's asset
retirement obligations as at 31 December 2020.
NOTE 21 - LEASES
The Group leased automobiles, equipment and real estate for the
periods presented below. A reconciliation of leases arising from
financing activities and the balance sheet classification of future
minimum lease payments as at the reporting periods presented were
as follows:
Present Value of
Minimum Lease Payments
-----------------------------------
31 December 31 December
2020 2019
------------------ ---------------
Balance at beginning of period $ 1,813 $ 3,536
Additions (a) 19,820 1
Interest expense (b) 929 -
Cash outflows (3,684) (1,724)
------------------ -------------
Balance at end of period $ 18,878 $ 1,813
=== ============= =========
Classified as:
Current liability $ 5,013 $ 798
Non-current liability 13,865 1,015
------------------ -------------
Total $ 18,878 $ 1,813
=== ============= =========
(a) Of the $19,820 in lease additions, $3,500 was attributable
to the Carbon acquisition. The remainder is a result of fleet
expansion and the Group transitioning owned vehicles to a fleet
management lease programme.
(b) Included as a component of finance cost.
Set out below is the movement in the right-of-use assets:
Right-of-Use Assets
--------------------------------
31 December 31 December
2020 2019
--------------- ---------------
Balance at beginning of period $ 1,868 $ 3,454
Additions (a) 19,558 -
Depreciation (3,400) (1,586)
--------------- -------------
Balance at end of period $ 18,026 $ 1,868
=== ========== ==== =======
Classified as:
Motor vehicles $ 14,614 $ 1,655
Buildings and leasehold improvements 3,412 213
--------------- -------------
Total $ 18,026 $ 1,868
=== ========== ==== =======
The range of discount rates applied in calculating right-of-use
assets and related lease liabilities, depending on the lease term,
is presented below:
31 December 31 December
2020 2019
----------- -----------
Discount rates range 1.8% - 3.3% 3.1% - 4.3%
The undiscounted future cash outflows relating to leases are
disclosed in Note 26. Expenses related to short-term and low-value
lease exemptions applied under IFRS 16 are disclosed in Note 7.
NOTE 22 - BORROWINGS
The Group's borrowings consist of the following amounts as of
the reporting date as follows:
31 December 31 December
2020 2019
------------- ---------------
Credit Facility
Weighted average Interest rate of 2.96% (2020)
and 4.80% (2019) $ 213,400 $ 436,700
ABS I Note
Interest rate of 5.00% 180,426 200,000
ABS II Note
Interest rate of 5.25% 191,125 -
Term Loan I
Interest rate of 6.50% 156,805 -
Miscellaneous, primarily for real estate,
vehicles and equipment 4,730 8,219
------------- -------------
Total borrowings $ 746,486 $ 644,919
Less: Current portion of long-term debt (64,959) (23,510)
Less: Deferred financing costs (23,068) (22,631)
Less: Original issue discounts (6,178) -
------------- -------------
Total non-current borrowings, net $ 652,281 $ 598,778
========= =========
Credit Facility
In November 2020, the Group reaffirmed its borrowing base on the
$1,500,000 Credit Facility at $425,000, which maintains the
maturity date of the previous facility of July 2023. The Credit
Facility is secured by natural gas and oil properties and has an
interest rate of one-month LIBOR plus 2.50% and is subject to a
pricing grid that fluctuates from 2.00% to 3.00% plus LIBOR based
on utilisation. Interest and principal payments on the Credit
Facility are paid on a monthly basis. The next redetermination is
in May 2021. Available borrowings under the Group's Credit Facility
were $211,600 as at 31 December 2020.
The Credit Facility contains certain customary representations
and warranties and affirmative and negative covenants, including
covenants relating to: maintenance of books and records; financial
reporting and notification; compliance with laws; maintenance of
properties and insurance; and limitations on incurrence of
indebtedness, liens, fundamental changes, international operations,
asset sales, certain debt payments and amendments, restrictive
agreements, investments, restricted payments and hedging. It also
requires the Group to maintain a ratio of total debt to EBITDAX
(the "Leverage Ratio") of not more than 3.75 to 1.00 and a ratio of
current assets (with certain adjustments) to current liabilities
(the "Current Ratio") of not less than 1.00 to 1.00 as of the last
day of each fiscal quarter. As of 31 December 2020 the Group was in
compliance with all financial covenants. The fair value of the
Credit Facility approximates the carrying value as at 31 December
2020.
Term Loan I
In May 2020, the Group formed DP Bluegrass LLC ("Bluegrass"), a
limited-purpose, bankruptcy-remote, wholly owned subsidiary of the
Group to enter into a securitised financing agreement for $160,000,
which was structured as a secured term loan. The Group issued the
Term Loan I at a 1% discount, and used the proceeds of $158,400 to
fund the Carbon and EQT acquisitions, as discussed in Note 5.
The Term Loan I is secured by the Group's producing assets
acquired from Carbon and EQT discussed in Note 5.
The Term Loan I accrues interest at a stated 6.50% annual rate
and has a maturity date of May 2030. Interest and principal
payments on the Term Loan I are payable on a monthly basis
beginning May 2020 and November 2020, respectively. During the
period ended 31 December 2020, the Group incurred $6,371 in
interest related to the Term Loan I which is recognised under the
effective interest rate method. The fair value of the Term Loan I
approximates the carrying value as at 31 December 2020.
The Term Loan I is subject to a series of covenants and
restrictions customary for transactions of this type, including (i)
that the Issuer maintains specified reserve accounts to be used to
make required interest payments in respect of the Term Loan I, (ii)
provisions relating to optional and mandatory prepayments and the
related payment of specified amounts, including specified premium
payments in the case of an optional prepayment, (iii) certain
indemnification payments in the event, among other things, that the
assets pledged as collateral for the Term Loan I are used in stated
ways defective or ineffective, and (iv) covenants related to
recordkeeping, access to information and similar matters.
The Term Loan I is also subject to customary accelerated
amortisation events provided for in the indenture, including events
tied to failure to maintain stated debt service coverage ratios,
certain change of control and management termination events, and
event of default and the failure to repay or refinance the Term
Loan I on the applicable scheduled maturity date.
The Term Loan I is subject to certain customary events of
default, including events relating to non-payment of required
interest, principal or other amounts due on or with respect to the
Term Loan I, failure to comply with covenants within certain time
frames, certain bankruptcy events, breaches of specified
representations and warranties, failure of security interests to be
effective and certain judgments.
As of 31 December 2020 the Group was in compliance with all
financial covenants.
ABS II Note
In April 2020, the Group formed Diversified ABS Phase II LLC
("ABS II"), a limited-purpose, bankruptcy-remote, wholly owned
subsidiary of the Group to enter into a securitised financing
agreement for $200,000. The ABS II Note is BBB rated and was issued
at a 2.775% discount. The Group used the proceeds of $183,617, net
of discount, capital reserve requirement, and debt issuance costs,
to pay down its Credit Facility.
The ABS II Note is secured by 29.4% of the Group's producing
assets, excluding the Group's EdgeMarc assets acquired in September
2019. Natural gas production associated with the 29.4% working
interest was hedged at 85% at the close of the agreement with
long-term derivative contracts.
The ABS II Note accrues interest at a stated 5.25% rate and has
a maturity date of July 2037. Interest and principal payments on
the ABS II Note are payable on a monthly basis beginning July 2020
and August 2020, respectively. During the period ended 31 December
2020, the Group incurred $7,563 in interest related to the ABS II
Note which is recognised under the effective interest rate method.
In the event that ABS II has cash flow in excess of the required
payments, 25% to 100% of the excess cash, contingent on certain
performance metrics, is required to pay down additional principal
with the remaining proceeds remaining with the Group. The fair
value of the ABS II Note approximates the carrying value as at 31
December 2020.
The ABS II Note is subject to a series of covenants and
restrictions customary for transactions of this type, including (i)
that the Issuer maintains specified reserve accounts to be used to
make required interest payments in respect of the ABS II Note, (ii)
provisions relating to optional and mandatory prepayments and the
related payment of specified amounts, including specified premium
payments in the case of an optional prepayment, (iii) certain
indemnification payments in the event, among other things, that the
assets pledged as collateral for the ABS II Note are used in stated
ways defective or ineffective, and (iv) covenants related to
recordkeeping, access to information and similar matters.
The ABS II Note is also subject to customary early amortisation
events provided for in the indenture, including events tied to
failure to maintain stated debt service coverage ratios, failure to
maintain certain production metrics, certain change of control and
management termination events, and event of default and the failure
to repay or refinance the ABS II Note on the applicable scheduled
maturity date.
The ABS II Note is subject to certain customary events of
default, including events relating to non-payment of required
interest, principal or other amounts due on or with respect to the
ABS II Note, failure to comply with covenants within certain time
frames, certain bankruptcy events, breaches of specified
representations and warranties, failure of security interests to be
effective and certain judgments.
As of 31 December 2020 the Group was in compliance with all
financial covenants.
ABS I Note
In November 2019, the Group formed Diversified ABS, LLC ("ABS
I"), a limited-purpose, bankruptcy-remote, wholly-owned subsidiary
of the Group to enter into a securitised financing agreement for
$200,000 which was issued at par through a BBB- rated bond. The ABS
I Note is secured by 21.6% of the Group's producing assets,
excluding the acquired EdgeMarc assets discussed in Note 5. Natural
gas production associated with the 21.6% working interest was
hedged at 85% at the close of the agreement using a 10-year swap
and rolling 2-year basis hedge.
Interest and principal payments on the ABS I Note are payable on
a monthly basis beginning 28 February 2020. For the years ended 31
December 2020 and 2019, the Group incurred $9,661 and $1,305 of
interest related to the ABS I Note, respectively. The legal final
maturity date is January 2037 with an amortising maturity of
December 2029. The ABS I Note accrues interest at a stated 5% rate.
In the event that ABS I has cash flow in excess of the required
payments, 25% to 100% of the excess cash, contingent on certain
performance metrics, is required to pay down additional principal
with the remaining proceeds remaining with the Group. The fair
value of the ABS I Note approximates the carrying value as at 31
December 2020.
The ABS I Note is subject to a series of covenants and
restrictions customary for transactions of this type, including (i)
that the Issuer maintains specified reserve accounts to be used to
make required interest payments in respect of the ABS I Note, (ii)
provisions relating to optional and mandatory prepayments and the
related payment of specified amounts, including specified
make-whole payments in the case of the ABS I Note under certain
circumstances, (iii) certain indemnification payments in the event,
among other things, that the assets pledged as collateral for the
ABS I Note is used in stated ways defective or ineffective, and
(iv) covenants related to recordkeeping, access to information and
similar matters.
The ABS I Note is also subject to customary rapid amortisation
events provided for in the indenture, including events tied to
failure to maintain stated debt service coverage ratios, failure to
maintain certain production metrics, certain change of control and
management termination events, and event of default and the failure
to repay or refinance the ABS I Note on the applicable scheduled
maturity date.
The ABS I Note is subject to certain customary events of
default, including events relating to non-payment of required
interest, principal or other amounts due on or with respect to the
ABS I Note, failure to comply with covenants within certain time
frames, certain bankruptcy events, breaches of specified
representations and warranties, failure of security interests to be
effective and certain judgments.
As of 31 December 2020 the Group was in compliance with all
financial covenants.
In August 2020, in conjunction with Munich Re Reserve Risk
Financing, Inc. ("MRRF"), the Group requested to withdraw the
public ratings on the ABS I Note. Following MRRF's further
investment in the Group through the Term Loan I to fund a portion
of the Group's most recent acquisitions from EQT and Carbon, MRRF
dedicated internal resources to both the ABS I Note and the Term
Loan I, and given these resources, believed the rating agencies'
reviews and oversight were unnecessary. Both Fitch and Morningstar
affirmed the BBB- rating of the ABS I Note concurrent with the
ratings withdrawal, which was not the result of any disagreement
with the rating agencies or MRRF.
For clarity, the ABS II Note is unaffected by this reporting
change to the ABS I Note, and Fitch will continue to cover the ABS
II Note, which remains BBB rated at the time of this report.
The following table provides a reconciliation of the Group's
future maturities of its total borrowings as of the reporting date
as follows:
31 December 31 December
2020 2019
------------- ---------------
Not later than one year $ 64,959 $ 23,510
Later than one year and not later than five
years 450,503 515,620
Later than five years 231,024 105,789
------------- -------------
Total borrowings $ 746,486 $ 644,919
========= =========
The following table represents the Group's finance costs for
each of the periods presented:
Year Ended
------------------------------
31 December 31 December
2020 2019
------------- ---------------
Interest expense, net of capitalised and
income amounts $ 34,391 $ 32,662
Amortisation of discount and deferred finance
costs 8,334 3,875
Other 602 130
------------- -------------
Total finance costs $ 43,327 $ 36,667
========= =========
Loss on early retirement of debt $ - $ -
========= =========
Reconciliation of borrowings arising from financing
activities:
Year Ended
------------------------------
31 December 31 December
2020 2019
------------- ---------------
Balance at beginning of period $ 622,288 $ 482,814
Proceeds from borrowings 799,650 765,236
Repayments of borrowings (705,314) (618,010)
Costs incurred to secure financing (7,799) (11,574)
Amortisation of discount and deferred financing
costs 8,334 3,875
Interest paid in cash (34,335) (32,715)
Finance costs and other 34,416 32,662
------------- -------------
Balance at end of period $ 717,240 $ 622,288
=== ======== === ========
NOTE 23 - TRADE AND OTHER PAYABLES
The following table includes a detail of trade and other
payables. The fair value approximates the carrying value as at the
periods presented:
31 December 31 December
2020 2019
------------- ---------------
Trade payables $ 19,218 $ 16,700
Other payables 148 352
------------- -------------
Total trade and other payables $ 19,366 $ 17,052
========= =========
NOTE 24 - OTHER LIABILITIES
The following table includes details of other liabilities as at
the periods presented:
31 December 31 December
2020 2019
============= ===============
Other non-current liabilities
Uncertain tax position (a) $ 1,837 $ 2,133
Other non-current liabilities (b) 11,023 2,335
------------- -------------
Total other non-current liabilities $ 12,860 $ 4,468
========= =========
Other current liabilities
Accrued expenses $ 28,582 $ 23,645
Taxes payable 18,025 19,379
Net revenue clearing (c) 12,561 9,287
Asset retirement obligations - current 1,882 2,650
Revenue to be distributed (d) 30,260 30,321
Total other current liabilities $ 91,310 $ 85,282
========= =========
(a) At the date of acquisition, the Directors determined that
Alliance Petroleum had taken uncertain tax positions, and as a
result, an indemnification agreement was executed. The Group
recorded an indemnification receivable for the amount of $1,837 and
$2,133 as at 31 December 2020 and 2019, respectively. In accordance
with IFRS 3, the Group assigned acquisition date fair value to the
indemnification asset using the same valuation techniques used to
determine the acquisition date fair value of the related
liability.
(b) Other non-current liabilities includes the long-term portion
of the contingent consideration for the Carbon and EQT
acquisitions. For more information please refer to Note 5.
(c) Net revenue clearing is estimated revenue that is payable to
third-party working interest owners.
(d) Revenue to be distributed is revenue that is payable to
third-party working interest owners, but has yet to be paid due to
title, legal, ownership or other issues. The Group releases the
underlying liability as the aforementioned issues become resolved.
As the timing of resolution is unknown, the Group records the
balance as a current liability.
NOTE 25 - FAIR VALUE AND FINANCIAL INSTRUMENTS
Fair Value
The fair value of an asset or liability is the price that would
be received to sell that asset or paid to transfer that liability
in an orderly transaction occurring in the principal market (or
most advantageous market in the absence of a principal market) for
such asset or liability. In estimating fair value, the Group
utilises valuation techniques that are consistent with the market
approach, the income approach and/or the cost approach. Such
valuation techniques are consistently applied. Inputs to valuation
techniques include the assumptions that market participants would
use in pricing an asset or liability. IFRS 13, Fair Value
Measurement ("IFRS 13"), establishes a fair value hierarchy for
valuation inputs that gives the highest priority to quoted prices
in active markets for identical assets or liabilities and the
lowest priority to unobservable inputs. The fair value hierarchy is
defined as follows:
Level 1: Inputs are unadjusted, quoted prices in active markets
for identical assets at the measurement date.
Level 2: Inputs (other than quoted prices included in Level 1
can include the following):
(a) Observable prices in active markets for similar assets;
(b) Prices for identical assets in markets that are not active;
(c) Directly observable market inputs for substantially the full term of the asset; and
(d) Market inputs that are not directly observable but are
derived from or corroborated by observable market data.
Level 3: Unobservable inputs which reflect the Directors' best
estimates of what market participants would use in pricing the
asset at the measurement date.
The Group does not hold derivatives for speculative or trading
purposes and the derivative contracts held by the Group do not
contain any credit-risk related contingent features. The Directors
have elected not to apply hedge accounting to derivative
contracts.
Netting the fair values of derivative assets and liabilities for
financial reporting purposes is permitted if such assets and
liabilities are with the same counterparty and a legal right of
set-off exists, subject to a master netting arrangement. The
Directors have elected to present derivative assets and liabilities
net when these conditions are met. When derivative assets and
liabilities are presented net, the fair value of the right to
reclaim collateral assets (receivable) or the obligation to return
cash collateral (payable) is also offset against the net fair value
of the corresponding derivative. At 31 December 2020 and 2019,
there were no collateral assets or liabilities associated with
derivative assets and liabilities.
Derivatives expose the Group to counterparty credit risk. The
derivative contracts have been executed under master netting
arrangements which, in the event of default by its counterparties,
allows the Group to elect early termination. The Group monitors the
creditworthiness of its counterparties but is not able to predict
sudden changes and hence may be limited in its ability to mitigate
an increase in credit risk.
Possible actions would be to transfer the Group's positions to
another counterparty or request a voluntary termination of the
derivative contracts, resulting in a cash settlement in the event
of non-performance by the counterparty. For the periods ended 31
December 2020 and 2019, the counterparties for all the Group's
derivative financial instruments were lenders under formal credit
and debt agreements.
The derivative instruments consist of non-financial instruments
considered normal purchases and normal sales.
For recurring and non-recurring fair value measurements
categorised within Level 2 and Level 3 of the fair value hierarchy,
a description of the valuation technique(s) and the inputs used in
the fair value measurement. If there has been a change in valuation
technique (ex: changing from a market approach to an income
approach or the use of an additional valuation technique), the
entity shall disclose that change and the reason(s) for making
it.
All financial instruments measured at fair value use Level 2
valuation techniques for the periods ended 31 December 2020 and
2019.
Level 2 fair value measurements are those including inputs other
than quoted prices included within Level 1 that are observable for
the asset or liability directly or indirectly. The fair value of
the swap commodity derivatives is calculated using a discounted
cash flow model and the fair value of the option commodity
derivatives are calculated using a relevant option pricing model,
which are calculated from relevant market prices and yield curves
at the balance sheet date and are therefore based solely on
observable price information. These instruments are not directly
quoted in active markets and are accordingly classified as Level 2
in the fair value hierarchy.
There were no transfers between fair value levels for the
periods ended 31 December 2020 and 2019.
Financial Instruments
For trade receivables, the Group applies the simplified approach
permitted by IFRS 9, which requires expected lifetime losses to be
recognised from initial recognition of the receivables. Financial
liabilities are initially measured at fair value and subsequently
measured at amortised cost.
The Group is not a financial institution. The Group does not
apply hedge accounting and its customers are considered
creditworthy and pay consistently within agreed payments terms.
A classification of the Group's financial instruments for the
periods presented is included in the table below:
Year Ended
------------------------------
31 December 31 December
2020 2019
------------- ---------------
Cash and cash equivalents at amortised cost $ 1,379 $ 1,661
Trade receivables and accrued income at amortised
cost 66,991 73,924
Other non-current assets (a) 2,376 176
Other current assets (b) - 383
Other non-current liabilities (b) (11,023) (2,335)
Other current liabilities (c) (41,143) (32,932)
Derivative financial instruments at fair
value (165,807) 61,802
Leases (18,878) (1,813)
Borrowings (746,486) (644,919)
------------- -------------
Total $ (912,591) $ (544,053)
========= =========
(a) Excludes indemnification receivables.
(b) Excludes prepaid expenses and inventory.
(c) Excludes uncertain tax positions.
(d) Excludes taxes payable, asset retirement obligations and revenue to be distributed.
NOTE 26 - FINANCIAL RISK MANAGEMENT
The Group is exposed to a variety of financial risks such as
market risk, credit risk, liquidity risk, capital risk and
collateral risk. The Group manages these risks by monitoring the
unpredictability of financial markets and seeking to minimise
potential adverse effects on the Group's financial performance on a
continuous basis.
The Group's principal financial liabilities are comprised of
borrowings, leases and trade and other payables, used primarily to
finance and financially guarantee its operations. The Group's
principal financial assets include cash and cash equivalents and
trade and other receivables derived from its operations.
The Group also enters into derivative financial instruments
which, depending on market dynamics, are recorded as assets or
liabilities. To assist with its hedging programme design and
composition, the Group engages a specialist firm with the
appropriate skills and experience to manage its risk management
derivative-related activities.
Market Risk
Market risk is the possibility that the fair value of future
cash flows of a financial instrument will fluctuate due to changes
in market prices. Market risk is comprised of two types of risk:
interest rate risk and commodity price risk. Financial instruments
affected by market risk include borrowings and derivative financial
instruments. Derivative and non-derivative financial instruments
are used to manage market price risks resulting from changes in
commodity prices and foreign exchange rates, which could have a
negative effect on assets, liabilities or future expected cash
flows.
Interest rate risk
The Group is subject to market risk exposure related to changes
in interest rates on its variable-rate Credit Facility. The
remainder of the Group's financing is fixed-rate. At 31 December
2020 and 2019, the Group had $213,400 and $436,700, respectively,
outstanding under its Credit Facility with a weighted average
interest rate of 2.96% and 4.80%, respectively. Refer to Note 22
for additional information about the Credit Facility.
The table below represents the impact a 100 basis point
adjustment in the interest rate for the Credit Facility and the
corresponding impact on finance costs. This represents a reasonably
possible change in interest rate risk.
+100 Basis -100 Basis
Credit Facility Interest Rate Sensitivity Points Points
------------ --------------
Finance costs $ 2,134 $ (2,134)
The Group principally manages this risk by entering into fixed
rate borrowing obligations with amortising structures facilitating
an expedited repayment of principal. To mitigate residual interest
rate risk the Group enters into derivative financial instruments.
The total principal hedged through the use of derivative financial
instruments varies from period to period. See Note 14 for more
information on the Group's derivative financial instruments.
As of 31 December 2020, the Group had an interest rate swap ("IR
swap") that fixed $150,000 of variable LIBOR interest rate risk. As
of 31 December 2019 the Group had no IR swaps. Refer to Note 14 for
additional information about the Group's derivative financial
instruments.
Commodity price risk
The Group's revenues are primarily derived from the sale of its
natural gas, NGLs and oil production, and as such, the Group is
subject to commodity price risk. Commodity prices for natural gas,
NGLs and oil can be volatile and can experience fluctuations as a
result of relatively small changes in supply, weather conditions,
economic conditions and government actions. For the years ended 31
December 2020 and 2019, the Group's commodity revenue was $381,662
and $438,280, respectively.
The Group enters into derivative financial instruments to
mitigate the risk of fluctuations in commodity prices. The total
volumes hedged through the use of derivative financial instruments
varies from period to period, but generally the Group's objective
is to hedge approximately 40% to 90% of its anticipated production
volumes for the next 36 months. Refer to Note 14 for additional
information about the Group's derivative financial instruments.
Credit Risk
The Group is exposed to credit risk from the sale of its natural
gas, NGLs and oil. Trade receivables from customers are amounts due
for the purchase of natural gas, NGLs and oil. Collectability is
dependent on the financial condition of each customer. The Group
reviews the financial condition of customers prior to extending
credit and generally does not require collateral in support of
their trade receivables. At 31 December 2020 and 2019, the Group
had one and three customers, respectively, over 10% that made up
11% and 41%, respectively of the Group's total trade receivables
from customers. At 31 December 2020 and 2019, the Group's trade
receivables from customers were $66,908 and $68,393,
respectively.
The Group is exposed to credit risk from joint interest owners,
entities that own a working interest in the properties operated by
the Group. Joint interest receivables are classified in trade
receivables, net in the Consolidated Statement of Financial
Position. The Group has the ability to withhold future revenue
payments to recover any non-payment of joint interest receivables.
Given the historical low pricing environment in 2020, however, the
Group increased the allowance for credit losses related to amounts
due from joint interest owners by $6,931 . At 31 December 2020 and
2019, the Group's joint interest receivables were $83 and $5,531,
respectively.
The majority of trade receivables are current and the Group
believes these receivables are collectible.
Liquidity Risk
Liquidity risk is the possibility that the Group will not be
able to meet its financial obligations as they are due. The Group
manages this risk by 1) maintaining adequate cash reserves through
the use of cash from operations and bank borrowings, and 2)
continuously monitors its forecast and actual cash flows to ensure
it maintains an appropriate amount of liquidity. The amounts
disclosed in the table are the contractual undiscounted cash flows.
Balances due within 12 months equal their carrying balances,
because the impact of discounting is not significant.
Later Than
One Year
and
Not Later Not Later
Than Than Later Than
One Year Five Years Five Years Total
----------- ------------- ------------- ----------
31 December 2020
Trade and other payables $ 19,366 $ - $ - $ 19,366
Borrowings 64,959 450,503 231,024 746,486
Lease 5,013 13,865 - 18,878
Other liabilities (a) 41,143 11,023 - 52,166
----------- ------------- ------------- --------
Total $ 130,481 $ 475,391 $ 231,024 $836,896
======= ========= ========= =======
31 December 2019
Trade and other payables $ 17,052 $ - $ - $ 17,052
Borrowings 23,723 515,407 105,789 644,919
Lease 798 1,015 - 1,813
Other liabilities (a) 32,932 2,335 - 35,267
----------- ------------- ------------- --------
Total $ 74,505 $ 518,757 $ 105,789 $699,051
======= ========= ========= =======
(a) Excludes uncertain tax position, taxes payable, asset
retirement obligations and revenue to be distributed.
Capital Risk
The Group defines capital as the total of equity shareholders'
funds and long-term borrowings net of available cash balances. The
Group's objectives when managing capital are to provide returns for
shareholders and safeguard the ability to continue as a going
concern while pursuing opportunities for growth through identifying
and evaluating potential acquisitions and constructing new
infrastructure on existing proved leaseholds. The Directors do not
establish a quantitative return on capital criteria, but rather
promote year-over-year Hedged Adjusted EBITDA per Share growth. The
Group uses its Net Debt-to-Hedged Adjusted EBITDA to monitor
capital risk and maintain a target of below 2.5x. See Note 9 for
more information on Hedged Adjusted EBITDA.
Collateral Risk
The Group has pledged 51.0% of its natural gas and oil
properties, excluding the EdgeMarc acquisition, to fulfil the
collateral requirements for borrowings under asset-backed
securitisation with its senior secured lenders as part of the ABS I
and ABS II transactions. In addition the Carbon and EQT natural gas
and oil properties have been pledged to fulfil the collateral
obligations of the Term Loan I financing arrangement. The fair
value is based on a third-party engineering reserve calculation
using a 10% cumulative discount cash flow and a commodities futures
price schedule. See Notes 5 and 22 for additional information on
acquisitions and debt, respectively.
NOTE 27 - CONTINGENCIES
Litigation and Regulatory Proceedings
The Group is involved in various pending legal issues that have
arisen in the normal course of business. The Group accrues for
litigation, claims and proceedings when a liability is both
probable and the amount can be reasonably estimated. As of 31
December 2020 the Group does not currently have any material
amounts accrued related to litigation or regulatory matters. For
any matters not accrued for, it is not possible at this time to
estimate the amount of any additional loss, or range of loss that
is reasonably possible, but, based on the nature of the claims,
management believes that current litigation, claims and
proceedings, individually or in aggregate and after taking into
account insurance, are not likely to have a material adverse impact
on the Group's financial position, results of operations or cash
flows.
Previously the Group disclosed it was assessing the
interpretation of a US tax rule to determine if the Group would be
subject to a maximum withholding tax of $8,800 payable to the US
tax authorities in relation to its share buyback programme
discussed in Note 17. As of 31 December 2020. the Group completed
its review of this matter and concluded that it has no liability
for taxes, penalties or interest due related to the US Withholding
Tax rule.
The Group has no other contingent liabilities that would have a
material impact on the Group's financial position or results of
operations.
Environmental Matters
The Group's operations are subject to environmental regulation
in all the jurisdictions in which it operates and was in compliance
as of 31 December 2020. The Group is unable to predict the effect
of additional environmental laws and regulations which may be
adopted in the future, including whether any such laws or
regulations would adversely affect its operations. The Group can
offer no assurance regarding the significance or cost of compliance
associated with any such new environmental legislation once
implemented.
NOTE 28 - RELATED PARTY TRANSACTIONS
UK Legal Counsel
Martin K. Thomas is a partner at Wedlake Bell LLP, the UK legal
advisor to the Group.
Year Ended
------------------------------------------------
31 December 2020 31 December 2019
---------------------- ------------------------
Fees paid to related party
legal advisor $ 41 GBP 33 $ 195 GBP 150
Dividend Payments
In 2019, the Directors became aware that aggregate dividends
totalling $82,151 paid during this period had been made otherwise
than in accordance with the Companies Act 2006, as unaudited
interim accounts had not been filed at Companies House prior to the
dividend payments. At a General Meeting of Shareholders held on 15
April 2020, a resolution was passed which authorised the
appropriation of distributable profits to the payment of the
relevant dividends and removed any right for the Group to pursue
shareholders or Directors for repayment. This constituted a related
party transaction under IAS 24 "Related Party Disclosures". The
overall effect of the resolution being passed was to return all
parties, so far as possible, to the position they would have been
in had the relevant dividends been made in full compliance with the
Companies Act 2006.
NOTE 29 - SUBSEQUENT EVENTS
The Group determined the need to disclose the following material
transactions that occurred subsequent to 31 December 2020, which
have been described within each relevant footnote as follows:
Description Footnote
----------- --------
Dividends Note 19
ALTERNATIVE PERFORMANCE MEASURES (UNAUDITED)
(Amounts in thousands, except per share and per unit data)
DGO uses APMs to improve the comparability of information
between reporting periods and to more accurately evaluate cash
flows, either by adjusting for uncontrollable or non-recurring
factors, or by aggregating measures, to aid the users in
understanding the activity taking place across DGO. APMs are used
by the Directors for planning and reporting. The measures are also
used in discussions with the investment analyst community and
credit rating agencies.
Average Dividend Average Dividend per Share is reflective of the average
per Share of the dividends per share declared throughout the year
which gives consideration to changes in dividend rates
and changes in the amount of shares outstanding.
This is a key metric for the Directors as they seek
to provide a consistent and reliable dividend to shareholders.
2020 2019
------- ---------
Declared on first quarter results $0.0350 $0.0342
Declared on second quarter results 0.0375 0.0350
Declared on third quarter results 0.0400 0.0350
Recommended on the fourth quarter results 0.0400 0.0350
------- ---------
Average Dividend per Share $0.0381 $0.0348
------ ------
Total Dividends per Share $0.1525 $0.1392
====== ======
Adjusted Net As used herein, Adjusted Net Income and Adjusted EPS
Income and represent income (loss) available to shareholders after
Adjusted EPS taxation, but exclude mark-to-market adjustments related
to DGO's hedge portfolio.
The Directors believe these metrics are useful to investors
because they provide a meaningful measure of DGO's profitability
before recording certain items whose timing or amount
cannot be reasonably determined.
2020 2019
-------- ------------
Income (loss) available to shareholders after
taxation (23,474) 99,400
Loss on joint and working interest owners
receivable 6,931 730
Gain on bargain purchase (17,172) (1,540)
(Gain) loss on fair value adjustments of
unsettled financial instruments 238,795 (20,270)
(Gain) loss on natural gas and oil programme
and equipment 2,059 -
Non-recurring costs 25,046 16,752
Non-cash equity compensation 5,007 3,065
(Gain) loss on foreign currency hedge - (4,117)
(Gain) loss on interest rate swap 202 -
-------- ----------
Tax effect on adjusting items (62,608) 1,598
-------- ----------
Adjusted Net Income $174,786 $ 95,618
======= ======
Adjusted EPS - basic $ 0.26 $ 0.15
Adjusted EPS - diluted $ 0.25 $ 0.15
Hedged Adjusted As used herein, EBITDA represents earnings before interest,
EBITDA and taxes, depletion, depreciation and amortisation. Hedged
Unhedged Adjusted Adjusted EBITDA includes adjustments for non-recurring
EBITDA and non-cash items such as gain on the sale of assets,
acquisition related expenses and integration costs,
mark-to-market adjustments related to DGO's hedge portfolio,
non-cash equity compensation charges and items of a
similar nature, while Unhedged Adjusted EBITDA excludes
mark-to-market adjustments related to DGO's hedge portfolio
Hedged Adjusted EBITDA and Unhedged Adjusted EBITDA
should not be considered in isolation or as a substitute
for operating profit or loss, net income or loss, or
cash flows provided by operating, investing and financing
activities. However, the Directors believe it is useful
to an investor in evaluating DGO's financial performance
because this measure (1) is widely used by investors
in the natural gas and oil industry as an indicator
of underlying business performance; (2) helps investors
to more meaningfully evaluate and compare the results
of DGO's operations from period to period by removing
the often-volatile revenue impact of changes in the
fair value of derivative instruments prior to settlement;
(3) is used in the calculation of a key metric in one
of DGO's Credit Facility financial covenants; and (4)
is used by the Directors as a performance measure in
determining executive compensation.
2020 2019
Operating profit (loss) $(77,568) $180,507
Depreciation, depletion and amortisation 117,290 98,139
Loss on joint and working interest owners
receivable 6,931 730
Gain on bargain purchase (17,172) (1,540)
(Gain) loss on natural gas and oil programme
and equipment 238,795 (20,270)
(Gain) loss on fair value adjustments of
unsettled financial instruments 2,059 -
Non-recurring costs 25,046 16,752
Non-cash equity compensation 5,007 3,065
(Gain) loss on foreign currency hedge - (4,117)
(Gain) loss on interest rate swap 202 -
Total adjustments $ 378,158 $ 92,759
Hedged Adjusted EBITDA $ 300,590 $273,266
Less: Cash portion of settled commodity
hedges (144,600) (53,584)
Unhedged Adjusted EBITDA $ 155,990 $219,682
Net Debt, As used herein, Net Debt represents total debt as recognised
Net Debt-to-Hedged on the balance sheet less cash and restricted cash.
Adjusted EBITDA Total debt includes DGO's current portion of debt, Credit
Facility borrowings and term loan borrowings. Net Debt
is a useful indicator of DGO's leverage and capital
structure.
As used herein, Net Debt-to-Hedged Adjusted EBITDA,
or Leverage, is measured as Net Debt divided by Pro
Forma Hedged Adjusted EBITDA. The Directors believe
that this metric is a key measure of DGO's financial
liquidity and flexibility and is used in the calculation
of a key metric in one of DGO's Credit Facility financial
covenants.
2020 2019
Cash $ 1,379 $ 1,661
Restricted cash 20,350 7,712
Credit Facility (213,400) (436,700)
ABS I Note (180,426) (200,000)
ABS II Note (191,125) -
Bluegrass Note (156,805) -
Other (4,730) (8,219)
Net Debt $(724,757) $(635,546)
Hedged Adjusted EBITDA $ 300,590 $ 273,266
Pro forma Hedged Adjusted EBITDA (a) $ 333,940 $ 319,470
Net Debt-to-Hedged Adjusted EBITDA 2.2x 2.0x
(a) Pro forma Hedged Adjusted EBITDA includes adjustments in
2020 for the EQT, Carbon and Utica Shale acquisitions to pro forma
their results for a full year of operations. A similar adjustment
was made in 2019 to pro forma results for the HG and EdgeMarc
acquisitions.
Hedged Adjusted The Directors believe that Hedged Adjusted EBITDA per
EBITDA per Share provides direct line of sight into the Group's
Share ability to measure the accretive growth we seek to acquire
while providing shareholders with a depiction of cash
earnings at the share level.
In this calculation we utilise weighted average shares
as to not disproportionately weight the calculation
for equity issued for acquisitive growth at varying
periods throughout the year.
2020 2019
-------- ----------
Weighted average shares outstanding - diluted 688,348 644,782
Hedged Adjusted EBITDA $300,590 $273,266
------- -------
Hedged Adjusted EBITDA per Share $ 0.44 $ 0.42
======= =======
Adjusted Total As used herein, Adjusted Total Revenue includes the
Revenue impact of derivatives settled in cash. The Directors
believe that Adjusted Total Revenue is a useful measure
because it enables investors to discern DGO's realised
revenue after adjusting for the settlement of derivative
contracts.
Cash Operating As used herein, Cash Operating Margin is measured by
Margin reducing Adjusted Total Revenue for operating expenses.
The resulting margin on Cash Operating Income is considered
the Group's Cash Operating Margin. The Directors believe
that Cash Operating Margin is a useful measure of DGO's
profitability and efficiency as well as its earnings
quality.
Cash Margin As used herein, Cash Margin is measured as Hedged Adjusted
EBITDA, as a percentage of Adjusted Total Revenue. The
key distinction between Cash Operating Margin and Cash
Margin is the inclusion of Adjusted G&A. The Directors
believe that Cash Margin is a useful measure of DGO's
profitability and efficiency as well as its earnings
quality.
2020 2019
Total revenue $ 408,693 $ 462,256
Commodity hedge impact 144,600 49,467
Adjusted Total Revenue 553,293 511,723
LESS: Operating expense (203,963) (202,385)
Total Cash Operating Income 349,330 309,338
LESS: Adjusted G&A (47,181) (36,072)
LESS: Allowance for credit losses - recurring (1,559)
Hedged Adjusted EBITDA $ 300,590 $ 273,266
Cash Margin 54% 53%
Cash Operating Margin 63% 60%
Free Cash As used herein, Free Cash Flow represents Hedged Adjusted
Flow and EBITDA less recurring capital expenditures, asset retirement
Free Cash costs and cash interest expense. The Directors believe
Flow Yield that Free Cash Flow is a useful indicator of DGO's ability
to internally fund its activities and to service or
incur additional debt.
As used herein, Free Cash Flow Yield represents Free
Cash Flow as a percentage of DGO's total market capitalisation.
The Directors believe that, like Free Cash Flow, Free
Cash Flow Yield is an indicator of financial stability
and reflects DGO's operating strength relative to its
size as measured by market capitalisation.
2020 2019
Hedged Adjusted EBITDA $300,590 $273,266
LESS: Recurring capital expenditures (15,981) (17,255)
LESS: Plugging and abandonment costs (2,442) (2,541)
LESS: Cash interest expense (34,335) (32,715)
Free Cash Flow $247,832 $220,755
Pro forma Free Cash Flow (a) $281,182 $266,959
Average share price $ 1.21 $ 1.22
Weighted average shares outstanding - diluted 688,348 644,782
Free Cash Flow Yield 34% 34%
(a) Pro forma Free Cash Flow includes adjustments in 2020 for
the EQT, Carbon and Utica Shale acquisitions to pro forma their
results for a full year of operations. A similar adjustment was
made in 2019 to pro forma results for the HG and EdgeMarc
acquisitions.
Total Cash Total Cash Cost per Boe is a metric which allows us
Cost per Boe to measure the cumulative operating cost it takes to
produce each Boe. This metric includes operating expense
and Adjusted G&A, both of which include fixed and variable
cost components.
2020 2019
Total production (MBoe) 36,538 30,944
Total operating expense $203,963 $202,385
Adjusted G&A 48,740 36,073
Total Cash Cost $252,703 $238,458
Total Cash Cost per Boe $ 6.92 $ 7.71
Base G&A As used herein, Base G&A represents total administrative
expenses excluding non-recurring and/or non-cash acquisition
and integration costs. The Directors use Base G&A because
this measure excludes items that affect the comparability
of results or that are not indicative of trends in the
ongoing business.
Adjusted G&A As used herein, Adjusted G&A represents Base G&A plus
recurring allowances for expected credit losses. The
Directors use Adjusted G&A because this measure excludes
items that affect the comparability of results or that
are not indicative of trends in the ongoing business.
2020 2019
Total G&A $ 77,234 $ 55,889
LESS: Non-recurring and/or non-cash G&A
(a) (30,053) (19,816)
Base G&A (b) $ 47,181 $ 36,073
Recurring allowance for expected credit
losses 1,559 -
Adjusted G&A (c) $ 48,740 $ 36,073
(a) Non-recurring and/or non-cash G&A includes costs related
to acquisitions, DGO's up-list to the main market, and one-time
projects.
(b) Base G&A includes payroll and benefits for our corporate
and administrative staff, costs of maintaining corporate and
administrative offices, costs of managing our production
operations, franchise taxes, public company costs, non-cash equity
issuance, fees for audit and other professional services, and legal
compliance.
(c) Adjusted G&A includes all of the same items as Base
G&A then also include recurring allowance for expected credit
losses.
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
Authority to act as a Primary Information Provider in the United
Kingdom. Terms and conditions relating to the use and distribution
of this information may apply. For further information, please
contact rns@lseg.com or visit www.rns.com.
RNS may use your IP address to confirm compliance with the terms
and conditions, to analyse how you engage with the information
contained in this communication, and to share such analysis on an
anonymised basis with others as part of our commercial services.
For further information about how RNS and the London Stock Exchange
use the personal data you provide us, please see our Privacy
Policy.
END
FR EAKDPEDKFEEA
(END) Dow Jones Newswires
March 08, 2021 02:00 ET (07:00 GMT)
Diversified Energy (LSE:DEC)
Historical Stock Chart
From Mar 2024 to Apr 2024
Diversified Energy (LSE:DEC)
Historical Stock Chart
From Apr 2023 to Apr 2024
