Operational Focus and Discipline Drive Financial Outperformance
Increased Operating EBITDA Guidance and Returns Focused Portfolio Optimization
TORONTO, Aug. 9, 2017 /CNW/ - Frontera Energy Corporation
(TSX: FEC) ("Frontera" or the "Company") announced today the release of its interim condensed consolidated
financial statements for the second quarter of 2017, together with its management discussion and analysis ("MD&A").
These documents will be posted on the Company's website at www.fronteraenergy.ca and SEDAR at www.sedar.com. The financial information contained herein is reported in United
States dollars and is in accordance with International Financial Reporting Standards ("IFRS") as issued by the
International Accounting Standards Board, unless otherwise noted.
Barry Larson, Chief Executive Officer of the Company, commented:
"Our new progressive and disciplined approach is focused on generating and delivering value. Recent reservoir optimization of
the Company's producing assets has strengthened the Company's focus on value creation to ensure that capital expenditures are
deployed efficiently to produce the highest netback barrels. Importantly, as a result of our strong first half results driven by
successful cost control and portfolio optimization, Frontera is increasing its 2017 Operating EBITDA guidance (in a flat
$50/bbl Brent oil environment) by 10% to $275 to $300 million (from
$250 to $275 million EBITDA on a consolidated basis). We have kept production flat on a quarterly
basis as we focus on costs and on delivering exceptional financial performance. The results of the asset review, combined with
our focus on returns and cash flow generation, means we are reducing our 2017 capex guidance by 21% to $250 to $300 million (from $325 to $375 million), and our 2017 production exit
guidance by 12% to 70,000 to 75,000 boe/d (from 80,000 to 85,000 boe/d). The Company generated operating cash flow in
excess of capital expenditures in the first half of 2017 and our revised guidance places Frontera's capital spending within the
Operating EBITDA metric for 2017.
"The remainder of 2017 will focus on continued Operating EBITDA expansion, cash flow generation, portfolio optimization, and
balance sheet protection. Potential positive catalysts to unlock shareholder value include contract renegotiations, non-core
asset dispositions, exploration drilling success, continued cost control, and improved financial and covenant flexibility via
debt refinancing or amendments. We are also excited to implement exploration and strategic activities designed to drive
growth in 2018. Our balance sheet remains extremely strong with over $450 million of cash on hand
and only $250 million of long term debt. We also have a strong oil hedge book with over 50% of our
2017 production hedged at a floor of approximately $50 per barrel."
Second Quarter 2017 Results
Operational Highlights:
- Net production after royalties and internal consumption for the second quarter of 2017 totalled 72,370 boe/d, in line with
that achieved in the first quarter of 2017 of 72,524 boe/d. The trucking operation that the Company developed in Peru to move production from Block 192 while the Norperuano pipeline was under repair was successful, with
an average of 2,506 bbl/d transported in the quarter.
- During the six months ended June 30, 2017, the Company completed 43 development wells (of
which 34 were drilled in 2017), serviced 29 wells, and completed five workovers, mainly in Colombian Blocks. The wells were
focused on maintenance to keep production flat during the first half of 2017 with modest capex investment.
Financial Highlights:
- During the second quarter of 2017, revenue totalled $299.5 million compared with $316.6 million in the prior quarter, due to the lower volumes sold. Revenue decreased by $76.9 million in comparison with the second quarter of 2016 mainly due to the expiry of the Rubialies-Piriri
contract in June 2016.
- Although Brent prices decreased by $3.78/bbl to $50.79/bbl in
the second quarter from the first quarter, Frontera offset this with a positive hedge effect and commercial differential of
$2.97/bbl. The Company's average sales price per barrel of crude oil and natural gas was
$46.28/boe, up from $45.95/boe in the first quarter of 2017.
- Total operating costs, including production, transportation, and diluent costs, were within the range of the Company's
guidance, increasing from $25.91/boe in the first quarter of 2017 to $26.53/boe in the second quarter of 2017. The increase was mainly attributable to the reactivation of Block
192 in Peru.
- Combined oil and gas Operating Netback for the second quarter of 2017 was $19.75/boe, 1.4%
lower than the $20.04/boe in the first quarter of 2017, mainly attributable to higher operating
costs related to the ramp-up of operations at Block 192.
- Consolidated Netback in the second quarter of 2017 was $18.55/boe, higher than $17.89/boe in the first quarter of 2017 and $17.01/boe in the second quarter of
2016, mainly due to cost reimbursement from the Bicentenario pipeline when third parties use the bidirectional pipeline. When
the Bicentenario system is not operational the pipeline can be reversed for third party use, and the Company obtains a benefit
by crediting its take-or-pay commitments.
- Operating EBITDA was $86.9 million for the second quarter of 2017, lower by 6% compared with
the $92.4 million achieved in the first quarter of 2017, mainly due to lower volumes sold. In
comparison with the second quarter of 2016, Operating EBITDA was lower by $33.6 million,
primarily due to the expiry of the Rubiales-Piriri contract in June 2016.
- G&A costs decreased to $26.1 million in the second quarter of 2017 from $27.7 million in the first quarter of 2017, and from $35.6 million in the
second quarter of 2016. The Company continues to reduce G&A costs and all non-essential spending activities. The Company
will continue to look for additional opportunities to eliminate unnecessary costs.
- During the second quarter of 2017, net loss attributable to equity holders of the parent was $51.5
million, compared with a net income of $8.5 million in the first quarter of 2017, mainly
due to a $23 million impairment charge, lower sales, lower unrealized risk management gain, lower
gain from the equity accounted investees, and a loss on foreign exchange.
- Balance sheet remains strong as per the first quarter of 2017, underpinned by positive working capital, high liquidity and
stable cash position at $541.0 million (total cash including short and long term restricted
cash).
- Total capital expenditures decreased to $35.9 million in the second quarter of 2017, compared
with $37.6 million in the first quarter of 2017.
Restructuring and Cost Saving Initiatives:
- The Company continues to execute a hedging program designed to protect against downward oil price movements and mitigate
volatility in cash flow. As of August 8, 2017, the Company has hedges in place for 1.44 MMbbl per
month for the remainder of 2017 with average floor and ceiling prices of $50.65/bbl and
$58.80/bbl Brent. In addition, the Company has hedged a total of 1.6 MMbbl of production in the
first quarter of 2018 with average floor and ceiling prices ranging from $48.73/bbl and
$55.73/bbl Brent.
- During the quarter, the Company prevented an estimated diluent cost increase of $1.3 million
through collaborative agreements with third parties. Additionally, through a processing deal with a local refinery, the Company
prevented a fuel cost increase of approximately $3.7 million.
- On April 3, 2017, the Company requested that the Agencia Nacional de Hidrocarburos
("ANH") approved the transfer of $6.0 million in commitment investment from the CPO-12
Block to two exploratory wells in the CPE-6 Block ($3.0 million for each well); the transfer is
subject to approval by the ANH. The Company continues to renegotiate field commitments to focus on high-impact development
drilling.
- On April 25, 2017, the Company and CNE Oil & Gas S.A.S., a subsidiary of Canacol Energy
Ltd. ("CNE Oil"), entered into a farm-out agreement whereby CNE Oil agreed to acquire the Company's participating
interest in the San Jacinto 7 Block, in consideration for assuming all contractual exploration obligations of the Company
totalling $7.8 million. The agreement is subject to approval by the ANH.
- On June 1, 2017, the Company executed an assignment agreement with Petrosouth Energy
Corporation pursuant to which the Company agreed to transfer its participating interest and the operatorship under the Cerrito
Association Contract for $0.1 million. The Company holds an undivided 70% participating interest
in the Cerrito Contract and Ecopetrol S.A. holds 30%; the assignment is subject to approval by the ANH.
- On June 2, 2017, the Agencia Nacional do Petróleo Gás Natural e Biocombustíveis
("ANP") approved the transfer of the Company's interest in the Queiroz Blocks in Brazil
to Queiroz Galvão Exploração e Produção S.A. ("QGEP"). However, the transfer is subject to the replacement of standby
letters of credit that the Company issued to ANP with guarantees from QGEP. Once finalized, the Company will release the
outstanding $10 million owed to QGEP.
Asset Sales (Executed/Closing) Summary:
During the second quarter of 2017, the Company continued to monetize non-core assets and received $17.1
million on closing of the Block 131 transaction. During the first half of 2017, the Company received a total of
$38.7 million from assets held for sale or sold in Peru (Blocks
126 and 131), Brazil (Karoon) and Colombia (Putumayo and
Casanare Este). In addition to assets held for sale, the Company finalized an agreement with Interoil Corporation (now ExxonMobil
Canada Holdings ULC) on the transfer of operating rights in Papua New Guinea for total cash
consideration of $57.0 million, net of outstanding liabilities. The Company expects to receive this
amount in the second half of 2017 upon receipt of regulatory approval. Below is a summary of all the non-core asset sales of
exploration and production blocks executed to date; many are pending final government approvals:
Block
|
Country
|
Buyer
|
Cash proceeds
|
Exploratory Commitments1
|
SBLC2 / Collateral
|
($ millions)
|
|
|
|
|
|
Santos Basin
|
Brazil
|
Karoon Gas
|
15.5
|
50.8
|
0.0
|
North Basins
|
Brazil
|
Queiroz Galvao
|
(10.0)
|
25.6
|
42.5
|
Lote 131
|
Peru
|
CEPSA
|
17.1
|
8.8
|
0.0
|
PUT-9
|
Colombia
|
Amerisur
|
0.7
|
9.1
|
0.9
|
Mecaya
|
Colombia
|
Amerisur
|
0.6
|
5.2
|
0.8
|
Terecay
|
Colombia
|
Amerisur
|
0.1
|
8.1
|
0.8
|
Tacacho
|
Colombia
|
Amerisur
|
3.5
|
4.1
|
0.4
|
Casanare Este
|
Colombia
|
Gold Oil
|
2.0
|
12.0
|
0.8
|
SSJN-7
|
Colombia
|
Canacol
|
0.0
|
7.8
|
2.5
|
Lote 126
|
Peru
|
Maple Gas
|
0.2
|
13.9
|
2.8
|
Cerrito
|
Colombia
|
PetroSouth
|
0.1
|
0.9
|
0.0
|
PNG Blocks
|
Papua - NG
|
Exxon Mobil
|
57.0
|
0.0
|
0.0
|
Total
|
|
|
86.8
|
146.3
|
51.5
|
1
|
IncludesAbandonment/Environmental Costs
|
2
|
Standby Letter of Credit
|
Financial Results:
|
Financial Summary
|
|
|
|
|
2017
|
2016
|
|
Q2
|
Q1
|
Q2
|
Total Sales ($ millions)
|
299.4
|
316.6
|
376.4
|
Operating EBITDA ($ millions)1
|
86.9
|
92.4
|
120.5
|
Operating EBITDA Margin (Operating EBITDA/Revenues) 1
|
29%
|
29%
|
32%
|
Consolidated EBITDA ($ millions)1
|
87.4
|
115.1
|
126.1
|
Consolidated EBITDA Margin (Consolidated EBITDA/Revenues)
1
|
29%
|
36%
|
33%
|
Net (loss) income2
|
(51.5)
|
8.5
|
(118.7)
|
Per share – basic ($)3
|
(1.03)
|
0.17
|
(37,665.40)
|
Net Production (boe/d)
|
72,370
|
72,524
|
127,951
|
Net Production (boe/d) (excluding Rubiales Field)
|
72,370
|
72,524
|
81,468
|
Sales Volumes (boe/d)
|
71,232
|
76,256
|
110,024
|
Average Shares Outstanding – basic (thousands)
|
50,006
|
50,026
|
3
|
1
|
These metrics are Non-IFRS financial measures. See Advisories - "Non-IFRS
Financial Measures" - below and "Non-IFRS Measures" on page 16 of the MD&A.
|
2
|
Net (loss) income attributable to equity holders of the parent.
|
3
|
The basic and diluted weighted average numbers of common shares for the
three months ended June 30, 2017 and 2016 were 50,005,832 and 3,150, respectively.
|
Production:
|
|
|
|
Net Production Summary
|
|
|
|
|
2017
|
2016
|
|
Q2
|
Q1
|
Q2
|
Oil and Liquids (bbl/d)
|
|
|
|
Colombia
|
61,535
|
62,180
|
116,425
|
Peru
|
4,913
|
3,855
|
2,101
|
Total Oil and Liquids (bbl/d)
|
66,448
|
66,035
|
118,526
|
|
|
|
|
Natural Gas (boe/d)1
|
|
|
|
Colombia
|
5,922
|
6,489
|
9,425
|
Total Natural Gas (boe/d)
|
5,922
|
6,489
|
9,425
|
|
|
|
|
Total Equivalent Production (boe/d)
|
72,370
|
72,524
|
127,951
|
1
|
Colombian standard natural gas conversion ratio of 5.7 Mcf/bbl.
|
|
Additional production details are available in the MD&A.
|
During the second quarter of 2017, net production after royalties, PAP, and internal consumption was 72,370 boe/d, in line
with that of the previous quarter. Total production for the first half 2017 was 72,446 boe/d from 135,144 boe/d in the same
period of 2017, mainly due to the expiry of the Rubiales-Piriri contract. During the six months ended June
30, 2017, the Company completed 43 development wells (of which 34 were drilled in 2017), executed 29 well services and
five workovers, mainly in our Colombian blocks. The wells were focused on maintenance to keep production flat during the first
half of 2017 with discrete capex investment.
Light and medium net oil production in Colombia was 34,174 bbl/d, compared with 34,177 bbl/d
in the previous quarter despite only one development well being drilled in each of the Guatiquia and Mapache Blocks.
Heavy oil production from Quifa SW field and other fields maintained production levels, in comparison with the previous
quarter. During the second quarter of 2017, 15 development wells were drilled in the Quifa SW field, while no wells were drilled
in the other heavy oil fields.
Natural gas production declined in the second quarter compared to the previous quarter reflecting the lack of capital
investment as the Company evaluates future activity on the Block.
In Peru, second quarter net production after royalties was 4,913 bbl/d (8,385 bbl/d average
gross production), a 27% increase from 3,855 bbl/d (7,805 bbl/d average gross production), in the first quarter of 2017, due to
Block 192's production ramp-up after the reactivation of the Norperuano pipeline on January 31,
2017.
2017 Operational Update:
During the second quarter of 2017, consistent with the new progressive and disciplined approach, the Company made the
strategic decision to slow down production volumes at certain blocks and focus its resources on conducting reservoir studies to
facilitate optimization of certain blocks over the long term. The following producing blocks were impacted:
- Quifa SW and Cajua – Reservoir studies were commenced to facilitate optimization and the placement of future development
wells and evaluate the potential for more efficient well designs (multi-laterals). Now that these studies are near completion
the Company will be accelerating the development program in the third quarter of 2017;
- Guatiquia – Development drilling was reduced due to reservoir studies that are required to ensure prudent reservoir
management and preparations for the drilling of injector wells for reservoir pressure maintenance. The first injector well in
the Ardilla Field will be drilled in the fourth quarter of 2017 in conjunction with the acceleration of the development
drilling;
- CPI Blocks (Orito and Neiva) – The Company has also been re-evaluating the forward development program and is currently
awaiting the results from a pilot water injection program in Neiva to enhance recovery and the completion of reservoir studies
to assess the production potential of the "A" Limestone in the Orito Field. The Company expects to accelerate the development
of these fields as a result of these studies; and
- Copa Field – Reservoir injectivity tests have been successfully completed, indicating that future injector wells will be
able to effectively provide reservoir pressure maintenance support and immediately facilitate increased production from the
Copa Field.
As a result of this comprehensive asset review, the Company is reducing its 2017 Capex guidance by 21% to $250 to $300 million (from $325 to $375 million), and our 2017 production
exit guidance by 12% to 70,000 to 75,000 boe/d (from 80,000 to 85,000 boe/d). Importantly, despite the revised flat production
profile, due to successful cost control and portfolio optimization, Frontera is increasing its 2017 operating EBITDA
guidance by 10% to $275 to $300 million (from $250 to $275
million EBITDA on a consolidated basis). Our revised guidance includes placing Frontera's capital spending within the
Operating EBITDA metric for 2017. Recent reservoir optimization of the Company's producing assets has strengthened the
Company's focus on value creation to ensure that capital expenditures are not only deployed efficiently to produce the highest
netback barrels, but also position the Company for cost efficient, sustainable future growth.
The Company's assumptions described above are dependent on a base case average Brent oil price assumption for 2017 of
$50/bbl and benchmark combined price differential in the range of $7.00/bbl to $7.50/bbl.
Third Quarter 2017 Outlook
During the third quarter, from an operations perspective, the Company plans to drill between 25 and 30 development wells and
continue with an active workover and recompletion program. The bulk of the development drilling activity is expected to take
place at Quifa while additional development wells will target light and medium oil locations. The Company will also drill its
first exploration well in 2017. The Alligator 1x well is expected to spud in September and take 35-40 days to drill, targeting
management's estimate of five million barrels of resources.
From a financial perspective, the Company's strong balance sheet provides financial flexibility to unlock value for
shareholders as we continue to focus on Operating EBITDA expansion. Some of the initiatives being considered include: contract
renegotiations, non-core asset dispositions, continued cost control, and improved financial and covenant flexibility via debt
refinancing or amendments.
Second Quarter 2017 Conference Call Details:
As previously disclosed, a conference call for investors and analysts is scheduled for Thursday, August
10, 2017 at 10:30 a.m. (Toronto time), 9:30 a.m. (Bogotá time), and 8:30 a.m. (Calgary
time). Participants will include Gabriel de Alba, Chairman of the Board of Directors, Barry Larson, Chief Executive Officer, Camilo McAllister, Chief Financial
Officer and select members of the senior management team.
A presentation will be available on the Company's website prior to the call, which can be accessed at www.fronteraenergy.ca.
Analysts and investors are invited to participate using the following dial-in numbers:
Participant Number (International/Local):
|
(647) 427-7450
|
Participant Number (Toll free Colombia):
|
01-800-518-0661
|
Participant Number (Toll free North America):
|
(888) 231-8191
|
Conference ID:
|
60148223
|
Webcast: www.fronteraenergy.ca
A replay of the conference call will be available until 10:59 p.m. (Bogotá time) and
11:59 p.m. (Toronto time), Thursday, August
24, 2017 and can be accessed using the following dial-in numbers:
|
|
Encore Toll Free Dial-in Number:
|
1-855-859-2056
|
Local Dial-in-Number:
|
(416)-849-0833
|
Encore ID:
|
60148223
|
About Frontera:
Frontera is a Canadian public company and a leading explorer and producer of crude oil and natural gas, with operations
focused in Latin America. The Company has a diversified portfolio of assets with interests in
more than 25 exploration and production blocks in Colombia and Peru. The Company's strategy is focused on sustainable growth in production and reserves and cash
generation. Frontera is committed to conducting business safely, in a socially and environmentally responsible manner.
The Company's common shares trade on the Toronto Stock Exchange under the ticker symbol "FEC".
If you would like to receive News Releases via e-mail as soon as they are published, please subscribe here: http://fronteraenergy.mediaroom.com/subscribe
Advisories:
Cautionary Note Concerning Forward-Looking Statements
This news release contains forward-looking statements. All statements, other than statements of historical fact, that
address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future
(including, without limitation, statements regarding estimates and/or assumptions in respect of production, revenue, cash flow
and costs, reserve and resource estimates, potential resources and reserves and the Company's exploration and development plans
and objectives) are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of
the Company based on information currently available to the Company. Forward-looking statements are subject to a number of risks
and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the
forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance
that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events
to differ materially from current expectations include, among other things: uncertainty of estimates of capital and operating
costs, production estimates and estimated economic return; uncertainties associated with estimating oil and natural gas
reserves ; failure to establish estimated resources or reserves; volatility in market prices for oil and natural
gas ; fluctuation in currency exchange rates; inflation; changes in equity markets; perceptions of the Company's
prospects and the prospects of the oil and gas industry in Colombia and the other countries
where the Company operates or has investments as the result of the completion of the Company's comprehensive restructuring
transaction or otherwise ; uncertainties relating to the availability and costs of financing needed in the future; the
uncertainties involved in interpreting drilling results and other geological data; and the other risks disclosed under the
heading "Risk Factors" and elsewhere in the Company's annual information form dated March 14, 2017
filed on SEDAR at www.sedar.com. Any forward-looking statement speaks only as
of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or
obligation to update any forward-looking statement, whether as a result of new information, future events or results or
otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable,
forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such
statements due to the inherent uncertainty therein.
This news release contains future oriented financial information and financial outlook information (collectively,
"FOFI") (including, without limitation, statements regarding expected capital expenditures, G&A, and operating and
consolidated EBITDA for the Company in 2017), and are subject to the same assumptions, risk factors, limitations and
qualifications as set forth in the above paragraph. The FOFI has been prepared by management to provide an outlook of the
Company's activities and results, and such information may not be appropriate for other purposes. The Company and management
believe that the FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments, however,
actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein. Any
FOFI speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company
disclaims any intent or obligation to update any FOFI, whether as a result of new information, future events or results or
otherwise.
In addition, reported production levels may not be reflective of sustainable production rates and future production rates
may differ materially from the production rates reflected in this news release due to, among other factors, difficulties or
interruptions encountered during the production of hydrocarbons.
Non-IFRS Financial Measures
This news release contains financial terms that are not considered in IFRS. These non-IFRS measures do not have any
standardized meaning, and therefore are unlikely to be comparable to similar measures presented by other companies. These
non-IFRS measures should not be considered in isolation or as a substitute for measures of performance prepared in accordance
with IFRS. These financial measures are included because management uses this information to analyze operating performance and
liquidity. They are different from those measures disclosed in prior periods, reflecting the Company's new strategic focus on
operational efficiency and capital discipline.
Management believes that Netback is a useful measure to assess the net profit after all the costs associated with bringing
one barrel of oil to the market. It is also commonly used by the oil and gas industry to analyze financial and operating
performances expressed as profit per barrel.
- Operating Netback represents realized price per barrel plus realized gain or loss on financial derivatives, less
production costs, transportation cost and diluent cost, and shows how efficient the Company is at extracting and selling its
product.
- Consolidated Netback represents Operating Netback plus the results from corporate investments such as our pipeline
investments that are in addition to oil and gas production and the take-or-pay tariffs paid on disrupted pipelines.
Management believes that EBITDA is a common measure used to assess profitability before the impact of different financing
methods, income taxes, depreciation and impairment of capital assets and amortization of intangible assets.
- Operating EBITDA represents the operating results of the Company's primary business, excluding the effects of capital
structure, other investments (infrastructure assets), non-cash items that depend on accounting policy choices, and one-time
items that are not expected to recur.
- Consolidated EBITDA excludes items of a non-recurring nature (one-time items), or that could make the period-over-period
comparison of results from operations less meaningful, but includes results from the Company's other investments
(infrastructure assets).
A reconciliation of Operating and Consolidated EBITDA to net earnings is as follows:
|
Three Months Ended
June 30
|
Six Months Ended
June 30
|
(in thousands of US$ )
|
2017
|
2016
|
2017
|
2016
|
|
|
|
|
|
Net (loss) income (1)
|
$
|
(51,542)
|
$
|
(118,654)
|
$
|
(43,044)
|
$
|
(1,019,603)
|
|
|
|
|
|
Adjustments
|
|
|
|
|
|
Income tax expense
|
3,535
|
8,624
|
13,569
|
18,572
|
|
Depletion, depreciation and amortization
|
97,588
|
145,891
|
199,382
|
376,483
|
|
Impairment and exploration expenses
|
23,159
|
22,788
|
12,712
|
689,686
|
|
Finance costs
|
6,586
|
32,891
|
11,483
|
101,805
|
|
Restructuring and severance costs
|
1,842
|
49,978
|
7,788
|
67,719
|
|
Equity tax
|
-
|
-
|
11,694
|
26,901
|
|
Other income
|
(5,350)
|
(2,210)
|
(7,848)
|
(44,420)
|
|
Foreign exchange unrealized loss (gain)
|
11,571
|
(13,225)
|
(3,289)
|
754
|
Consolidated EBITDA
|
87,389
|
126,083
|
202,447
|
217,897
|
|
(Gain) loss valuation of unrealized hedge contracts
|
(12,434)
|
(6,073)
|
(52,579)
|
107,472
|
|
Share of gain in equity-accounted investees
|
(9,937)
|
(29,526)
|
(33,925)
|
(56,373)
|
|
Gain attributable to non-controlling interest
|
1,469
|
12,500
|
9,314
|
12,507
|
|
Share based compensation loss (gain)
|
233
|
(5,297)
|
253
|
(8,503)
|
|
Foreign exchange realized loss (gain)
|
838
|
4,707
|
4,453
|
(5,933)
|
|
Fees paid on suspended pipeline capacity
|
22,237
|
18,058
|
49,337
|
43,449
|
Operating EBITDA
|
$
|
86,857
|
$
|
120,452
|
$
|
179,300
|
$
|
310,516
|
1
|
Net income (loss) attributable to equity holders of the parent.
|
|
|
|
|
2017
|
2016
|
(in thousands of US$ )
|
Q2
|
Q1
|
Q4
|
Q3
|
Q2
|
Q1
|
|
|
|
|
|
|
|
Financial and Operational results:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating EBITDA
|
86,857
|
92,442
|
44,275
|
89,846
|
120,452
|
190,064
|
|
|
|
|
|
|
|
Consolidated EBITDA
|
87,389
|
115,057
|
(1,967)
|
37,689
|
126,083
|
91,814
|
Please see the Company's most recent Management's Discussion and Analysis, which is available at www.sedar.com for additional information about these financial measures.
Boe Conversion
The term "boe" is used in this news release. Boe may be misleading, particularly if used in isolation. A boe conversion
ratio of 5.7 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
Definitions
Bcf
|
Billion cubic feet.
|
Bcfe
|
Billion cubic feet of natural gas equivalent.
|
bbl
|
Barrel of oil.
|
bbl/d
|
Barrel of oil per day.
|
boe
|
Barrel of oil equivalent. Boe's may be misleading, particularly if used in
isolation. The Colombian standard is a boe conversion ratio of 5.7 Mcf:1 bbl and is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not represent a value equivalency at the
wellhead.
|
boe/d
|
Barrel of oil equivalent per day.
|
Mbbl
|
Thousand barrels.
|
Mboe
|
Thousand barrels of oil equivalent.
|
MMbbl
|
Million barrels.
|
MMboe
|
Million barrels of oil equivalent.
|
Mcf
|
Thousand cubic feet.
|
Million Tons LNG
|
One million tons of LNG (Liquefied Natural Gas) is equivalent to 48 Bcf or
1.36 billion m3 of natural gas.
|
Net Production
|
Company working interest production after deduction of
royalties.
|
Total Field Production
|
100% of total field production before accounting for working interest and
royalty deductions.
|
Gross Production
|
Company working interest production before deduction of
royalties.
|
SOURCE Frontera Energy Corporation
View original content: http://www.newswire.ca/en/releases/archive/August2017/09/c5547.html