Frontera Announces Second Quarter 2017 Results

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

For further information: Richard Oyelowo, Manager, Investor Relations, +1 (416) 362-7735, ir@fronteraenergy.ca, www.fronteraenergy.ca

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