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Frontera Delivers Strong Fourth Quarter and 2018 Results and Replaces 103% of 2018 Produced Reserves

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Met or Exceeded all 2018 Guidance Metrics, 8% Quarterly Production Growth

Dividends of C$0.495 Paid in the First Half of 2019

TORONTO, March 14, 2019 – Frontera Energy Corporation (TSX: FEC) (“Frontera” or the “Company“) announced today the release of its consolidated financial statements, management discussion and analysis (“MD&A“), Annual Information Form (“AIF“) and Form 51-101 F1 – Statement of Reserves Data and Other Oil and Gas Information for the Company (the “F1 Report“) for the year ended December 31, 2018. These documents, among others, will be posted on the Company’s website at www.fronteraenergy.ca and SEDAR at www.sedar.com. All values in this news release and the Company’s financial disclosures are in United States dollars unless otherwise stated. All production numbers in this news release are before royalties unless otherwise stated.

FOURTH QUARTER AND FULL YEAR 2018 HIGHLIGHTS

Strong Fourth Quarter Operational and Financial Results

  • Production averaged 71,924 boe/d, an increase of 8% compared to the third quarter of 2018 and a 3% increase compared to the fourth quarter of 2017.
  • Oil production represented over 95% of total company production in the fourth quarter of 2018, compared to 94% in the third quarter of 2018 and 92% in the fourth quarter of 2017.
  • Net loss of $116.6 million ($1.17/share) in the fourth quarter of 2018 includes $143.9 million of non-recurring charges relating to payments under terminated pipeline contracts, impairments on infrastructure investments, oil and gas assets and on the carrying values of investments in associates offset by the benefit of the reversal of provisions related to high-price clause. This compares to a net loss of $32.5 million ($0.33/share) in the fourth quarter of 2017 which included a net benefit $63.8 million from the reversal of a provision related to high-price clause, offset by impairments on oil and gas assets and transmission line assets. Refer to notes 7 and 26 of the consolidated financial statements for more detail.
  • Operating EBITDA of $118.4 million was 27% higher than the prior quarter and 13% higher than the prior year quarter.
  • General and administrative expenses (“G&A“) of $21.8 million in the fourth quarter of 2018 declined 5% from the third quarter of 2018 and 11% from the fourth quarter of 2017, reflecting the benefit of the Company’s ongoing focus on efficiency and cost reduction projects throughout the organization.
  • Capital expenditures of $156.4 million were 26% higher than in the third quarter of 2018 and 41% higher than the fourth quarter of 2017, as anticipated, reflecting the completion of the Quifa SW water handling expansion project which has added over 3,000 bbl/d to Company production so far in 2019.
  • Cash used by operating activities of $3.5 million in the fourth quarter of 2018 reflected the normalization of timing of accounts receivable and payable through the cash management process.
  • The Company repurchased for cancellation 1.3 million shares at a cost of $13.3 million (C$13.87/share) under its normal course issuer bid during the fourth quarter of 2018. To date the Company has repurchased for cancellation 2.4 million shares at a cost of $24.9 million (C$13.96/share), representing 47% of the authorized buyback under the normal course issuer bid.
  • Total cash, including restricted cash, was $588.4 million as at December 31, 2018, down 25% from the third quarter of 2018 and down 9% compared to December 31, 2017.
  • Hedged on approximately 27% of expected 2019 production after royalties using put options with a Brent price of $55.00/bbl.

2018 Operational and Financial Results

  • Frontera’s 2P Reserves as at December 31, 2018, were 154.9 MMboe after royalties, which was 0.4% higher than at the end of 2017.
  • The Company achieved a 2P Reserves Replacement Ratio of 103% based on 2018 production after royalties of 23.6 MMboe.
  • The Company’s 2P Reserve Life Index increased to 6.8 years in 2018 from 6.1 years in 2017.
  • Net present value of 2P reserves discounted at 10%, before taxes, was $2.2 billion at the end of 2018, a decrease of 13% compared to 2017. The decrease reflects lower heavy oil price assumptions of $3.00/bbl over the first 10 years, partially offset by an increase of $0.80/bbl in light oil price assumptions. Heavy oil represents 62% of proved plus probable reserves, light oil 36% and natural gas 2%.
  • Net present value of proved plus probable reserves discounted at 10%, after taxes, was $1.9 billion, a decrease of 1% compared to 2017.
  • 2018 production averaged 71,032 boe/d before royalties (63,187 boe/d after royalties) within the annual guidance range of 70,000 to 72,000 boe/d before royalties (63,000 to 65,000 boe/d after royalties).
  • Net loss of $259.1 million ($2.59/share) in 2018 includes $327.0 million of non-recurring charges relating to payments under terminated pipeline contracts, impairments on infrastructure investments, oil and gas assets and on the carrying values of investments in associates offset by the benefit of the reversal of provisions related to high-price clause. This compares to a net loss of $216.7 million ($2.17/share) in 2017 which included $27.2 million of non-recurring charges relating to impairments offset by the reversal of a provision related to high-price clause. Please refer to notes 7 and 26 of the consolidated financial statements for more detail.
  • Operating EBITDA in 2018 increased by $28.7 million, or 7%, to $422.5 million compared to the prior year.
  • Oil and gas sales and other revenue of $1.4 billion in 2018 were 15% higher compared to the prior year. Net sales for the year (including the impact of realized losses on risk management contracts, royalties, and diluent costs) decreased by 2% compared to 2017.
  • Operating netback for 2018 was $25.98/boe, 14% higher than $22.79/boe in 2017.
  • The Company generated $312.0 million in cash provided by operating activities in the year compared to $314.4 million in the prior year, contributing to a strong balance sheet with a total cash position, including restricted cash, of $588.4 million as at December 31, 2018.
  • Capital expenditures during 2018 were $446.1 million compared to $236.4 million in the prior year.

Dividends

  • On December 5, 2018, the Company’s Board of Directors declared a idend, payable on January 17, 2019 of C$0.33 per share (approximately $25 million in aggregate), to common shareholders of record on January 3, 2019.
  • On March 13, 2019, the Company’s Board of Directors declared a idend, payable on or about April 16, 2019 of C$0.165 (approximately $12.5 million in aggregate), to common shareholders of record on April 2, 2019.

2018 Guidance

The Company achieved or exceeded its original 2018 guidance targets, with the exception of production guidance where it achieved revised guidance. Average production before royalties of 71,032 boe/d (within guidance range of 70,000 to 72,000 boe/d), operating EBITDA of $422.5 million (within guidance range of $400 to $450 million), capital expenditures of $446.1 million (within revised guidance range of $440 to $460 million, below original guidance of $450 to $500 million) and G&A expenses of $93.0 million (below revised guidance range of $95 to $105 million).

Richard Herbert, Chief Executive Officer of Frontera, commented:

“Frontera stabilized its core production base in 2018 as the Company began enhancing the portfolio to deliver growth. As planned, we replaced over 100% of produced reserves in 2018, which was enabled by the completion of the Quifa water handling expansion project, as well as exploration successes at Alligator and Coralillo in the Guatiquia block and Jaspe in the Quifa North area. Significant investment in Colombia in 2018 has contributed to a strong start in 2019, particularly in the Quifa SW field with new water handling facilities in operation. In addition, after last year’s interruptions, production from Block 192 in Peru has recently restarted. As it returns to peak levels, total company production is the strongest it has been in over a year. With solid production and cash flow generation, we are executing a number of initiatives to drive production and reserves growth including; successfully being awarded two highly prospective blocks in an exploration bid round in Ecuador, and testing the deliverability of natural gas production from our Z-1 block, offshore Peru. We are also very excited by upcoming drilling on the VIM-1 block in Colombia and on the Corentyne block offshore Guyana later this year.”

Gabriel de Alba, Chairman of the Board of Directors of the Company, commented:

“Thanks to substantial progress by the Frontera team in 2018, the Company is better positioned than ever to deliver returns to shareholders. With improved capital allocation and a plan to sustain production and reserves from our existing production base at current levels for the next five years – both of which we’re already delivering on – Frontera can generate sufficient cash flow to drive growth initiatives in the upstream business, as well as take steps to further enhance shareholder returns, as oil prices permit. Continuing on our progress in reducing G&A in 2018, we are pursuing additional opportunities to improve the efficiency and cost structure of the business, especially in the field, and to monetize non-core assets.  These actions will generate additional cash flow and capital for growth and enhanced equity returns. Frontera is off to a positive start in 2019. Production is strong, Brent oil prices are averaging close to $63.00/bbl, in line with our guidance, and the Company is currently benefiting from narrow oil price differentials.”

Financial Results

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2018


2017



Q4

Full Year


Q4

Full Year

Revenue

($MM)

265

1,320


345

1,254

Net loss (1)

($MM)

(117)

(259)


(33)

(217)

Per share – basic (2)

($)

(1.17)

(2.59)


(0.33)

(2.17)

Net sales (3)

($MM)

228

1,083


307

1,111

Cash (used) provided by operating activities

($M)

(3)

312


115

314

Operating EBITDA (3)

($MM)

118

423


104

394

Operating EBITDA margin (Operating EBITDA/Net sales)(3)

(%)

52%

39%


34%

35%

General and administrative (G&A)

($MM)

22

93


24

105

Total cash, including restricted cash(4)

($MM)

588

588


644

644

Working capital

($MM)

216

216


310

310

Average shares outstanding – basic

(MM)

99,417

99,842


100,012

100,008




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1

Net loss attributable to equity holders of the Company.

2

Basic and diluted weighted average numbers of common shares for the year ended December 31, 2018 were 99,841,652 (December 31, 2017: 100,007,826 ).

3

These metrics are Non-IFRS financial measures. See Advisories – “Non-IFRS Financial Measures” – below and “Non-IFRS Measures” on page 17 of the MD&A.

4

Includes $446 million of cash and cash equivalents, $40 million of short term restricted cash and $103 million of long term restricted cash.



The average Brent oil benchmark price decreased in the fourth quarter of 2018 to an average of $68.60/bbl, down 9.5% from $75.84/bbl in the third quarter of 2018. Brent oil benchmark price averaged $61.46/bbl in the fourth quarter of 2017. The Company’s realized oil price of $62.15/bbl in the fourth quarter of 2018 excludes the impact of $5.55/bbl of realized losses on risk management contracts.

During the fourth quarter of 2018, net loss attributable to equity holders of the Company was $116.6 million ($1.17 /share), compared with net income of $45.1 million ($0.45/share) in the third quarter of 2018. The net loss primarily reflects several one-time items, including impairments on investments in associates, exploration expenses and payments under terminated pipeline contracts offset by the reversal of provisions related to high-price clause which in aggregate amounted to $143.9 million in the fourth quarter of 2018. Please refer to notes 7 and 26 of the consolidated financial statements for more detail.

For the fourth quarter of 2018, net sales of $228.4 million were 23.7% lower than the third quarter of 2018 reflecting lower sales price and volumes, and 25.5% lower than the fourth quarter of 2017 as a result of losses on risk management contracts and lower sales volumes partially offset by higher oil prices.

Cash used by operating activities was $3.5 million in the fourth quarter compared to cash provided by operating activities of $177.6 million in the third quarter of 2018, reflecting lower sales volumes and oil prices as well as one-time cash payments associated with the termination of pipeline contracts.

Operating EBITDA of $118.4 million in the fourth quarter of 2018 increased 26.7% in comparison with the third quarter of 2018, and was 13.5% higher than in the fourth quarter of 2017 as a result of a reversal of the overlift accumulated in the second and third quarters of 2018.

Frontera continued taking actions to improve its cost structure in the fourth quarter by completing a project to increase organizational efficiency and reduce costs. These efforts helped the Company deliver lower G&A expenses of $21.8 million in the fourth quarter of 2018, a decrease of 4.9% from the third quarter of 2018, and a decrease of 10.7% from the fourth quarter of 2017. Going forward, the Company will look to further improve operational efficiency to drive additional cost savings.

Production and Development Summary(1)

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Production, before royalties

2018


2017


Q4

Q3

Q2

Q1

Full Year


Q4

Full Year

Oil and liquids (bbl/d)









Colombia

59,687

57,655

59,108

58,246

58,675


61,719

65,142

Peru

8,974

4,616

8,414

10,737

8,171


2,840

5,122

Total oil and liquids (bbl/d)

68,661

62,271

67,522

68,983

66,846


64,559

70,264










Natural gas (boe/d)(2)









Colombia

3,263

4,122

4,504

4,875

4,186


5,315

5,784

Total natural gas (boe/d)

3,263

4,122

4,504

4,875

4,186


5,315

5,784










Total equivalent production (boe/d)

71,924

66,393

72,026

73,858

71,032


69,874

76,048




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1

Additional production details are available in the MD&A “Financial and operational results” section, page 6.

2

Colombian standard natural gas conversion ratio of 5.7 Mcf per bbl as required by the Colombian Ministry of Mines and Energy.



Current production before royalties is over 67,500 boe/d (over 63,000 boe/d after royalties), as production from Block 192 continues to ramp up following the repair of the NorPeruano pipeline. Production, before royalties in the fourth quarter of 2018 averaged 71,924 boe/d (63,898 boe/d after royalties), an increase of 8.3% compared with the third quarter of 2018. The increase in quarterly production was a result of increased production from Peru while the NorPeruano pipeline was in service during October and November, as well as increases from light, medium and heavy oil in Colombia. Production from Colombia increased 1.9% during the fourth quarter of 2018 compared with the previous quarter, as a result of increased production at the Quifa block following the completion of the water handling expansion project, as well as production from the Coralillo discovery on the Guatiquia block.

Sales volumes for the three months ended December 31, 2018, were 50,298 boe/d, 17.6% lower than the previous quarter, reflecting the settlement of an overlift of 809 Mbbl built up in the second and third quarters of 2018 and an increase in inventory in Colombia, resulting in lower volumes available for sale.

During the fourth quarter of 2018, total capital expenditures were $156.4 million, up 26.1% than the previous quarter and 40.6% from the fourth quarter of 2017. The increase during the fourth quarter relates to the construction of additional water handling facilities in the Quifa SW field and the testing costs associated with the Acorazado-1 exploration well on the Llanos 25 block in Colombia. Additionally, Colombian exploration wells were drilled at Jaspe and Sabanero as well as two development wells at Zopilote Sur on the Cravo Viejo block.

A total of 29 wells were drilled in the fourth quarter of 2018, slightly lower than the 31 wells planned, as the Cocodrilo exploration well was deferred with the new acreage awarded at the Coralillo field on the Guatiquia block. Twenty-two heavy oil development wells and two water injection wells were drilled in the Quifa SW area in connection with the increased fluid handling capacity that was initiated during the fourth quarter. Three light oil development wells were drilled with two on the Candelilla field on the Guatiquia block and one at the Zopilote Sur field on the Cravo Viejo block. The Company also completed the drilling of two exploration wells, Jaspe 7D in the Quifa North area and the Chaman well on the Sabanero block. Additionally, four of five planned water injection wells were converted from producing wells on the Neiva and Orito blocks.

During the first quarter of 2019, the Company plans to drill 28 wells including 23 development wells in the Quifa SW area, two development wells in its light and medium oil areas, two exploration wells, and a conversion of an existing well to a water injection well at Orito. The Company is targeting to keep seven rigs active throughout the first quarter of 2019.

2018 Reserves:

For the year ended December 31, 2018, the Company’s reserves were independently evaluated by DeGolyer and MacNaughton (“D&M”), in accordance with  the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter) (“COGEH”) and – National Instrument 51-101 Standards for Disclosure of Oil and Gas Activities (“NI 51-101”) and are based on the Company’s 2018 year-end estimated reserves as evaluated by D&M in their reserves report dated February 25, 2019 with an effective date of December 31, 2018 (the “Reserves Report”). See Advisory Note regarding Oil and Gas Information.

The Company’s proved plus probable reserves before royalties of 170.5 MMboe (154.9 MMboe after royalties) for the year ended December 31, 2018. This compares with 172.7 MMboe of proved plus probable reserves before royalties (154.3 MMboe after royalties) for the year ended December 31, 2017. Proved reserves of 104.8 MMboe for the year ended December 31, 2018 represent 68% of the total proved plus probable reserves compared with 74% of the total proved plus probable reserves for the year ended December 31, 2017.

The following table provides a summary of the Company’s oil and natural gas reserves based on forecast prices and costs effective December 31, 2018 as applied in the Reserves Report. The Company’s net reserves after royalties incorporate all applicable royalties under Colombia and Peru fiscal legislation based on forecast pricing and production rates evaluated in the Reserves Report, including any additional participation interest related to the price of oil applicable to certain Colombian blocks, as at year-end 2018.

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Reserves at December 31, 2018 (MMboe)(1)(6)

Country

Field

Proved (1P)

Probable

Proved Plus

Probable (2P)

Hydrocarbon Type

Gross

Net

Gross

Net

Gross

Net

Colombia

Quifa SW block


45.0


38.6


11.8


9.7


56.8


48.4

Heavy oil

Other heavy oil blocks(2)


35.8


34.2


15.0


14.2


50.8


48.4

Heavy oil

Light/medium oil blocks(3)


29.9


27.5


23.1


21.2


52.9


48.7

Light and medium oil and

associated natural gas

Natural gas blocks(4)


1.6


1.6


1.1


1.1


2.7


2.7

Natural gas

Sub-total


112.3


101.9


51.0


46.2


163.2


148.2

Oil and natural gas

Peru

Light/medium oil and

natural gas blocks (5)


3.5


2.9


3.8


3.8


7.3


6.7

Light and medium oil and

associated natural gas


Total at Dec. 31, 2018


115.8


104.8


54.8


50.0


170.5


154.9

Oil and natural gas

Total at Dec. 31, 2017


128.7


114.1


44.0


40.2


172.7


154.3


Difference


(12.9)


(9.3)


10.8


9.8


(2.2)


0.6

2018 Production


25.8


22.9

Total Reserves

Incorporated


23.7


23.6




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1

See “Boe Conversion” section in the “Advisories” at the end of this press release.

2

Includes Cajua, Jaspe, Quifa North, Sabanero, and CPE-6 blocks.

3

Includes Cubiro, Cravo Viejo, Canaguaro, Guatiquia, Casimena, Corcel, Neiva, Cachicamo, and other producing blocks.

4

Includes La Creciente field and Guaduas block.

5

Includes onshore Block 192 and offshore Block Z1.

6

“Gross” refers to WI before royalties, “Net” refers to WI after royalties.


Note: Numbers in the table may not add due to rounding differences.




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2018 2P Reserves Reconciliation (1)


Oil Equivalent Gross 2P

Reserves (MMboe)

Oil Equivalent Net 2P

Reserves (MMboe)

December 31, 2017

172.7

154.3

Net Additions

8.7

8.0

Economic and Technical Revisions

15.0

15.6

Production(2)

(25.8)

(22.9)

December 31, 2018

170.5

154.9

Related Posts
1 of 60,797




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1

Numbers in the table may not add due to rounding differences.

2

Production represents the production for the twelve month period ended December 31, 2018.



Fourth Quarter and Year End 2018 Conference Call Details:

As previously disclosed, a conference call for investors and analysts will be held on Thursday, March 14, 2019 at 8:00 a.m. (MDT), 9:00 a.m. (GMT-5) and 10:00 a.m. (EDT). Participants will include Gabriel de Alba, Chairman of the Board of Directors, Richard Herbert, Chief Executive Officer, David Dyck, Chief Financial Officer and select members of the senior management team.

Analysts and investors are invited to participate using the following dial-in numbers:

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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:

7391259

Webcast Audio:

www.fronteraenergy.ca



A replay of the conference call will be available until 10:59 p.m. (GMT-5) and 11:59 p.m. (EDT) Thursday, March 28, 2019 and can be accessed using the following dial-in numbers:

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Encore Toll Free Dial-in Number:

1-855-859-2056

Local Dial-in Number:

(416)-849-0833

Encore ID:

7391259



About Frontera:

Frontera Energy Corporation is a Canadian public company and a leading explorer and producer of crude oil and natural gas, with operations focused in South America. The Company has a ersified portfolio of assets with interests in more than 30 exploration and production blocks. The Company’s strategy is focused on sustainable growth in production and reserves. Frontera is committed to conducting business safely, in a socially and environmentally responsible manner. Frontera’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, drilling plans and timing thereof, the Company’s exploration and development plans and objectives, the timing of payment of idends and implementation of cost saving initiatives) are forward-looking statements. Any statements relating to reserves and resource estimates including, without limitation, potential resources and reserves, are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. 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; 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 AIF dated March 13, 2019 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.

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 the following financial terms that do not have standardized definitions in the International Financial Reporting Standards (“IFRS”): “operating EBITDA”, “operating netback”, and “net sales”. These financial measures, together with measures prepared in accordance with IFRS, provide useful information to investors and shareholders, as management uses them to evaluate the operating performance of the Company. The Company’s determination of these non-IFRS measures may differ from other reporting issuers, and therefore are unlikely to be comparable to similar measures presented by other companies. Further, these non-IFRS measures should not be considered in isolation or as a substitute for measures of performance or cash flows prepared in accordance with IFRS. These financial measures are included because management uses this information to analyze operating performance and liquidity.

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.

EBITDA is a commonly used measure that adjusts net income (loss) as reported under IFRS to exclude the effects of income tax expense, net finance costs and Depletion, depreciation and amortization expense.

Operating EBITDA represents the operating results of the Company’s primary business, excluding the items noted above, including fees paid on suspended pipeline capacity, other investments (such as infrastructure assets), certain non-cash items (such as impairments, foreign exchange and unrealized risk management contracts, and share based compensation) and gains or losses arising form the disposal of capital assets. In addition, other unusual or non-recurring items are excluded from operating EBITDA as they are not indicative of the underlying core operating performance of the Company.

The following table provides a complete reconciliation of net loss to Operating EBITDA:

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Three months ended

December 31


Year ended

December 31

($M)

2018

2017


2018

2017







Net loss (1)

(116,631)

(32,544)


(259,083)

(216,703)







Fees paid on suspended pipeline capacity

24,656


82,372

108,831

Payments under terminated pipeline contracts

59,040


74,618

Share-based compensation

166

2,119


4,042

2,605

Depletion, depreciation and amortization

80,461

95,526


316,751

382,246

Impairment and exploration expenses and other

125,944

35,774


315,292

126,844

Reversal of provision related to PAP

(41,079)

(99,622)


(62,911)

(99,622)

Restructuring, severance and other costs

8,092

2,436


14,592

12,617

Share of income from associates

(8,952)

(14,809)


(83,601)

(76,186)

Equity tax


11,694

Foreign exchange loss (gain)

13,087

3,472


3,375

(1,876)

Finance income

(7,581)

(4,620)


(25,832)

(17,646)

Finance expense

14,668

10,098


52,724

41,814

Unrealized (gain) loss on risk management contracts

(31,392)

80,774


(107,337)

71,762

Other income (loss), net

832

4,322


4,741

5,425

Reclassification of currency translation adjustments

(2,753)


48,094

Loss on extinguishment of debt


25,628

Income tax expense (recovery)

16,067

(10,438)


18,721

15,265

Non-controlling interests

8,429

7,172


322

26,788

Operating EBITDA

118,398

104,316


422,508

393,858




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1

Net loss attributable to equity holders of the Company.




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2018

2017

($M)

Q4

Q3

Q2

Q1

Q4

Q3

Q2

Q1

Financial and Operational results:









Operating EBITDA

118,398

93,455

124,667

85,988

104,316

110,243

86,857

92,442



Netbacks

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 performance expressed as profit per barrel. Operating Netback represents realized price per barrel plus realized gain or loss on financial derivatives, less production costs, high price royalties and royalties paid in cash, and transportation and diluent costs, and shows how efficient the Company is at extracting and selling its product. Refer to the “Operating Netback” section on page 9 of the MD&A.

Net Sales

Net sales is a non-IFRS subtotal that adjusts revenue to include realized gains and losses from risk management contracts while removing the cost of dilution activities. This is a useful indicator for management as the Company hedges a portion of its oil production using derivative instruments to manage exposure to oil price volatility. This metric allows the Company to report its realized net sales after factoring in these risk management activities. The exclusion of diluent cost is helpful to understand the Company’s sales performance based on the net realized proceeds from production net of dilution, the cost of which is partially recovered when the blended product is sold. Net sales does not include the sales and purchases of oil and gas for trading as the gross margins from these activities are not considered significant or material to the Company’s operations.  Refer to the reconciliation in the “Sales” section on page 10 of the MD&A.

Advisory Note Regarding Oil and Gas Information

The reserves information contained in this press release has been prepared in accordance with NI 51-101.  Complete reserves disclosure required in accordance with NI 51-101 is contained in the F1 Report filed on SEDAR.  Actual oil and natural gas reserves and future production may be greater than or less than the estimates provided in this news release. There is no assurance that forecast prices and costs assumed in the Reserves Report, and presented in this this news release, will be attained and variances from such forecast prices and costs could be material. The estimated future net revenue from the production of the disclosed oil and natural gas reserves in this news release does not represent the fair market value of these reserves.

The estimates of reserves for inidual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

The term reserves replacement ratio is used in this news release. This term is consistent with disclosure by other oil and gas companies. Reserves replacement ratio is calculated by iding proved plus probable boe reserves added during the year by the total boe production during the year.

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 cubic feet to barrels is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In this news release, boe has been expressed using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy. 

Definitions:

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1P

Proved reserves.

2P

Proved plus probable reserves.

bbl(s)

Barrel(s) of oil.

bbl/d

Barrel of oil per day.

Boe

Refer to “Boe Conversion” disclosure above.

boe/d

Barrel of oil equivalent per day.

Mbbl

Thousand barrels of oil.

Mboe

Thousand barrels of oil equivalent.

MMboe

Million barrels of oil equivalent.

Mcf

Thousand cubic feet.

Net Production

Net production after royalties represents the Company’s working interest volumes, net of royalties and internal consumption.

WI

Working interest.



SOURCE Frontera Energy Corporation

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