GeoPark Reports Third Quarter 2017 Results

GeoPark Limited (“GeoPark” or the “Company”) (NYSE:GPRK), a leading independent Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Chile, Brazil, Argentina, and Peru reports its consolidated financial results for the three-month period ended September 30, 2017 (“3Q2017”).

A conference call to discuss 3Q2017 Financial Results will be held on November 16, 2017 at 10:00 am Eastern Standard Time.

All figures are expressed in US Dollars and growth comparisons refer to the same period of the prior year, except when specified. Definitions and terms used herein are provided in the Glossary at the end of this document. This release does not contain all of the Company’s financial information. As a result, this release should be read in conjunction with GeoPark’s consolidated financial statements and the notes to those statements for the period ended September 30, 2017, available on the Company’s website.

THIRD QUARTER 2017 HIGHLIGHTS

Operational Results:

Oil and gas production up 28%

  • Consolidated oil and gas production up 28% to 28,325 boepd (up 8% compared to 2Q2017)
  • Current total production of 30,000+ boepd (exceeds year-end exit target)
  • Oil production increased by 37% to 23,237 bopd (up 6% compared to 2Q2017)
  • Colombian oil production increased by 43% to 22,301 bopd (up 6% compared to 2Q2017). Total gross Colombian production is over 51,000 bopd – making GeoPark the third largest Colombian oil and gas operator

Successful drilling results in Colombia

In Llanos 34 block (GeoPark operated, 45% WI)

  • Tigana Norte 2 appraisal well was drilled to delineate the northeastern boundary of the Tigana/Jacana complex and is currently producing 2,700 bopd
  • Tigana Norte 3 appraisal well recently drilled outside the 3P outline defined in the 2016 D&M reserves certification and approximately 50 feet down dip of the Tigana Norte 1 well and did not encounter the oil-water contact. The well is currently producing 1,700 bopd
  • Tigana Norte 4 appraisal well currently being drilled further down dip of Tigana Norte 3 well to continue delineating the northeastern boundaries of the Tigana/Jacana complex
  • Jacana 10 appraisal well was drilled to test the northern limits of the Jacana oil field and is currently producing 900 bopd
  • Jacana 12 appraisal well was drilled to test the southeastern boundary of Jacana and is currently producing 2,800 bopd
  • Curucucu 1 exploration well was drilled exploring a new fault trend to the east of Tigana/Jacana fault trend and is currently producing 1,100 bopd

Financial Results:

Adjusted EBITDA up by 131%

  • Revenues increased 64% to $81.9 million (up 9% compared to 2Q2017)
  • Operating netbacks increased by 47% ($7.4 per boe) to $23.2 per boe (up 5% compared to 2Q2017)
  • Consolidated operating expenses per boe down by 14% from $8.5 per boe to $7.3 per boe
  • Adjusted EBITDA increased by 131% to $44.6 million, last twelve months adjusted EBITDA reached $147.5 million
  • Adjusted EBITDA per boe increased by 76% to $18.0 per boe (up 13% compared to 2Q2017)
  • Net loss of $19.1 million impacted by one-time costs related to early cancellation of 2020 Notes of $17.6 million
  • Net debt to adjusted EBITDA ratio decreased from 4.7x to 1.9x (down by 14% from 2Q2017)
  • Cash and cash equivalents increased by $71.6 million to $135.2 million as of September 30, 2017

Successful 2024 Notes transaction

  • Successful placing of $425 million 2024 Notes, maturing in September 2024 with a 6.5% coupon, strengthened balance sheet by increasing funds, extending maturity and lowering debt cost
  • Proceeds used to repay substantially all existing financial debt, for capital expenditures and for general corporate purposes
  • Transaction oversubscribed by more than six times with top tier and high-quality investors

Strategic Results:

New high potential exploration acreage acquired adjacent to Llanos 34 block

  • 85% WI and operatorship of Tiple Exploration Acreage acquired in Colombia from CEPSA Colombia SA
  • One exploration well scheduled to be drilled in 1H2018, for a total investment of $7-8 million

Brazil low cost high potential acreage added

  • Awarded new block in the proven mature onshore Potiguar Basin, nearby other GeoPark blocks
  • Total commitment (bonus plus work program) of less than $500,000

James F. Park, Chief Executive Officer of GeoPark, said: “It was another powerful quarter – with important operational, financial and strategic wins – that continue building momentum for a successful completion of 2017 and an exciting outlook for 2018. Our team did its job by growing every component of our business plan. Production continues to increase as our drilling keeps finding oil and pushing out the boundaries of our key oil fields. Our cost reduction efforts and innovations continue to decrease operating and capital costs. Our cash flow more than doubled and key financial metrics showed improvement. We added new highly-prospective acreage to our expanding project portfolio by acquisitions in Colombia and Brazil and successfully closed a new bond transaction providing more funds, longer maturities, more flexibility and lower costs.”

CONSOLIDATED OPERATING PERFORMANCE

Key performance indicators:

                     
Key Indicators   3Q2017   2Q2017   3Q2016   9M2017   9M2016
Oil productiona (bopd)   23,237   21,930   16,942   21,895   16,277
Gas production (mcfpd) 30,528 25,158 30,774 27,954 33,810
Average net production (boepd)   28,325   26,123   22,070   26,554   21,913
Brent oil price ($ per bbl) 52.1 51.0 46.9 52.6 43.1
Combined price ($ per boe) 33.0 32.2 26.3 32.6 23.6
⁻ Oil ($ per bbl) 34.6 33.4 26.9 34.1 23.3
⁻ Gas ($ per mcf) 5.3 5.5 4.5 5.3 4.5
Sale of crude oil ($ million) 68.4 64.1 38.4 187.0 95.9
Sale of gas ($ million) 13.6 11.1 11.5 36.9 36.5
Revenue ($ million) 81.9 75.2 49.9 223.8 132.3
Commodity Risk Management Contracts ($ million) -8.3 5.9 - 3.0 -
Production & Operating Costsb ($ million) -25.7 -25.3 -19.6 -68.5 -46.4
G&G, G&Ac and Selling Expenses ($ million) -12.0 -13.9 -11.3 -36.1 -35.5
Adjusted EBITDA ($ million) 44.6 37.1 19.4 120.5 51.4
Adjusted EBITDA ($ per boe) 18.0 15.9 10.2 17.6 9.2
Operating Netback ($ per boe) 23.2 22.2 15.8 23.1 14.7
Profit (loss) ($ million)   -19.1   -1.1   -21.0   -14.4   -34.7
Capital Expenditures ($ million)   30.9   25.9   10.1   80.3   24.2
Cash and cash equivalents ($ million) 135.2 77.0 63.6 135.2 63.6
Short-term financial debt ($ million) 1.9 31.7 32.5 1.9 32.5
Long-term financial debt ($ million) 418.5 314.6 320.4 418.5 320.4
Net debt ($ million)   285.2   269.3   289.3   285.2   289.3
a)   Includes government royalties paid in-kind in Colombia for approximately 774, 781 and 690 bopd in 3Q2017, 2Q2017 and 3Q2016 respectively. No royalties were paid in kind in Chile and Brazil.
b) Production and Operating costs include operating costs and royalties paid in cash.
c) G&A expenses include $0.8, $0.8 and $0.9 million for 3Q2017, 2Q2017 and 3Q2016, respectively, of (non-cash) share-based payments that are excluded from the adjusted EBITDA calculation.
 

Production: Consolidated oil and gas production grew by 28% to a record 28,325 boepd in 3Q2017 compared to 22,070 boepd in 3Q2016. The increase was mainly attributed to new production from the Tigana/Jacana oil fields with four new wells put into production during the quarter.

  • Colombia: Average net oil and gas production increased by 43% to 22,367 boepd in 3Q2017 compared to 15,678 boepd in 3Q2016 due to continued successful exploration and development drilling in the Llanos 34 block.
  • Chile: Average net oil and gas production decreased by 25% to 2,817 boepd in 3Q2017 compared to 3,756 boepd in 3Q2016, due to natural decline of the fields.
  • Brazil: Average net gas production increased by 19% to 3,141 boepd in 3Q2017 compared to 2,636 boepd in 3Q2016. Industrial demand for gas in Brazil recovered in the third quarter.

The weight of crude oil in the production mix represented 82% in 3Q2017 (vs. 77% in 3Q2016) due to the successful drilling campaign in Llanos 34 block.

Recent Activity:

Colombia

  • Acquired 85% WI and operatorship of Tiple Exploration Acreage (adjacent to Llanos 34 block) from CEPSA Colombia SA

In Llanos 34 block:

  • Tigana Norte 3 appraisal well successfully drilled outside the 3P outline defined in the 2016 D&M reserves certification and approximately 50 feet down dip of the Tigana Norte 1 well (previous lowest known oil) and did not encounter the oil-water contact. The well is currently producing 1,700 bopd.
  • Tigana Norte 4 appraisal well currently being drilled to continue delineating the northeastern boundaries of the Tigana/Jacana complex. The Tigana Norte 4 well is being drilled outside the 3P outline defined in the 2016 D&M reserves certification and further down dip of the recent Tigana Norte 3 well (now the lowest known oil). Currently testing 3 wells, including Tigana Sur Oeste 7, Jacana 13 and 17.

Brazil

  • Awarded new block in the proven mature onshore Potiguar Basin, nearby other GeoPark blocks

Catalysts in 4Q2017

Colombia

  • Continued delineation of Tigana/Jacana complex, drilling six wells in 4Q that focus on northern Tigana, the area between Tigana and Jacana in Llanos 34 block and the southernmost part of Jacana

Argentina

  • Production start-up with long-term testing in Rio Grande Oeste oil field in CN-V block (GeoPark operated, 50% WI)
  • Exploration drilling start-up in Sierra del Nevado block (GeoPark non-operated, 18% WI) in Neuquen Basin

Brazil

  • Exploration drilling in POT-T-747 block (GeoPark operated, 70% WI) in the Potiguar Basin

Reference and Realized Oil Prices: Brent crude oil price averaged $52.1 per bbl during 3Q2017, and the consolidated realized oil sales price averaged $34.6 per bbl in 3Q2017, representing a 4% increase from $33.4 per bbl in 2Q2017 and a 29% increase from $26.9 per bbl in 3Q2016. Differences between reference and realized prices are a result of commercial and transportation discounts as well as the Vasconia price differential in Colombia, which narrowed to $2.8 per bbl in 3Q2017 from $5.7 per bbl in 3Q2016.

The following table provides a breakdown of reference and net realized oil prices in Colombia and Chile in 3Q2017:

         
3Q2017 - Realized Oil Prices

($ per bbl)

  Colombia   Chile
Brent oil price   52.1   52.1
Vasconia differential (2.8) -
Commercial and transportation discounts   (15.2)   (7.8)
Realized oil price   34.1   44.3
Weight on Oil Sales Mix   96%   4%
 

Commodity Risk Management Contracts - Brent Oil Price: In 3Q2017 the Company recorded the following amounts related to commodity hedges to mitigate the risk exposure to changes in the Brent oil price. Realized gains reflect cash settled transactions and unrealized gains/losses reflect non-cash changes between the contract values and the forward Brent oil curve.

     
3Q2017 – Commodity Risk Management Contracts   ($ million)
Realized cash gain   1.5
Non-cash unrealized losses   -9.8
Net effect   -8.3
 

The Company has the following commodity risk management contracts (reference ICE Brent), in place as of the date of this release:

             
Period Hedged   Type   Volume bopd   Contract details ($ per bbl)
      Purchased Put   Sold Put   Sold Call
4Q2017   Zero premium collar   12,000  

50.0-51.0

  -  

54.9-57.5

1Q2018 Zero premium collar
Zero premium 3 way
9,000
2,000
2,000

50.0-52.0
42.0
43.0

 

-
52.0
53.0

 

54.9-60.0
59.5-59.6
59.5-59.6

      Total: 13,000            
2Q2018 Zero premium collar
Zero premium 3 way
Zero premium 3 way
4,000
4,000
2,000

52.0
42.0
43.0

-
52.0
53.0

58.3-60.0
58.4-64.6
58.4-64.6

      Total: 10,000            
 

For further details, please refer to Note 4 of GeoPark’s consolidated financial statements for the period ended September 30, 2017, available on the Company’s website.

Revenue: Consolidated revenues increased by 64% to $81.9 million in 3Q2017, compared to $49.9 million in 3Q2016, mainly driven by higher oil and gas revenues.

Sales of crude oil: Consolidated oil revenues increased by 78% to $68.4 million in 3Q2017, driven by a 39% increase in oil sales volumes and a 28% increase in realized oil prices. Oil revenues represented 83% of total revenues compared to 77% in 3Q2016.

  • Colombia: In 3Q2017, oil revenues increased by 90% to $64.3 million mainly due to increased sales volumes and higher realized prices. Oil sales volumes increased by 45% to 21,378 bopd. Realized oil prices increased by 31% to $34.1 per bbl, in line with higher Brent prices and a lower Vasconia discount. Colombia earn-out payments (deducted from Colombia oil revenues) increased to $2.8 million in 3Q2017, compared to $1.3 million in 3Q2016, in line with increased production and higher oil revenues.
  • Chile: In 3Q2017, oil revenues decreased by 14% to $3.8 million due to lower sales volumes partially offset by higher realized prices. Oil sales volumes decreased by 26% to 928 bopd and realized oil prices increased by 17% to $44.3 per barrel, in line with higher Brent prices.

Sales of gas: Consolidated gas revenues increased by 18% to $13.6 million in 3Q2017 compared to $11.5 million in 3Q2016 due to 17% higher realized gas prices and 1% higher gas sales volumes.

  • Chile: In 3Q2017, gas revenues decreased by 1% to $4.2 million mainly due to lower gas sales volumes, partially offset by higher realized gas prices. Gas sales volumes decreased by 21% to 10,383 mcfpd (1,730 boepd). Gas prices increased by 25% to $4.35 per mcf ($26.1 per boe) in 3Q2017, due to increased methanol prices.
  • Brazil: In 3Q2017, gas revenues increased by 33% to $9.2 million, due to both higher realized prices and sales volumes. Gas prices, net of taxes, increased by 12% to $5.9 per mcf ($35.2 per boe) due to the annual gas price inflation adjustment of approximately 7%, effective January 2017, and a slight 3% appreciation of the local currency. Gas sales volumes increased by 18% to 17,056 mcfpd (2,842 boepd), primarily due to higher gas consumption by Brazilian industrial users.

Production and operating costs[1]: Consolidated production and operating costs increased by 31% to $25.7 million in 3Q2017, compared to $19.6 million in 3Q2016, mainly due to high price royalties that increased the total by $4.1 million, and to a lesser extent, higher operating costs of $2.0 million, due to a 39% increase in oil sales volumes. The Jacana oil field in Llanos 34 block in Colombia accumulated more than five million barrels of production which triggered Colombia’s “high price” royalty scheme beginning in mid-2Q2017. Thus, cash royalties as a percentage of revenues were 9% compared to 7% in 3Q2016.

Adjusting for increased production, consolidated operating costs per barrel actually decreased to $7.3 per boe in 3Q2017 from $8.5 per boe a year earlier. Apart from lower road maintenance and well-intervention costs, the improvement reflects the company´s continuous efforts to reduce operating costs.

By country, production and operating costs were as follows:

  • Colombia: Operating costs increased by 11% to $10.8 million in 3Q2017 from $9.8 million in 3Q2016, mainly resulting from a 45% increase in sales volumes. Compared to 3Q2016, there were lower road maintenance works, pulling and other well intervention activities. Operating costs per boe decreased to $5.5 per boe in 3Q2017 from $7.1 per boe in 3Q2016.
  • Chile: Operating costs increased by 4% to $5.3 million in 3Q2017 from $5.0 million in 3Q2016 mainly due to higher pulling, well intervention activities and consumables, and to a lesser extent to the appreciation of the Chilean peso (+3%). Operating costs per boe increased by 36% to $21.5 per boe due to the impact of lower absorption of fixed costs from lower sales volumes.
  • Brazil: Operating costs increased to $2.2 million in 3Q2017 from $1.5 million in 3Q2016, mainly due to increased volumes (+18%) and higher maintenance costs in Manati ($0.7 million higher in 3Q2017 vs 3Q2016) and, to a lesser extent, the appreciation of the Brazilian real (+3%). Operating costs per boe increased to $8.2 per boe from $6.6 in 3Q2016.

Royalties: Consolidated royalties paid in cash (reported in Production and Operating Costs) increased by $4.1 million to $7.4 million in 3Q2017, compared to $3.3 million in 3Q2016, mainly resulting from increased production, higher oil prices and the “high price” royalty for the Jacana oil field in Llanos 34 block beginning in 3Q2017. Thus, consolidated royalties increased to 9% of revenue versus 7% in 3Q2016.

Selling expenses: Consolidated selling expenses decreased to $0.3 million in 3Q2017 compared to $0.5 million in 3Q2016.

Administrative, Geological and Geophysical expenses: Consolidated G&A and G&G expenses increased by 7% to $11.6 million in 3Q2017 compared to $10.8 million in 3Q2016. Consolidated G&A and G&G costs per boe decreased by 7% to $5.2 per boe in 3Q2017 (vs. $5.6 per boe in 3Q2016).

Adjusted EBITDA: Consolidated adjusted EBITDA1 strongly grew by 131% to $44.6 million or $18.0 per boe in 3Q2017 compared to $19.4 million or $10.2 per boe in 3Q2016, mainly driven by the combination of increased production levels and higher realized oil and gas prices.

  • Colombia: Adjusted EBITDA of $41.6 million in 3Q2017
  • Chile: Adjusted EBITDA of $0.8 million in 3Q2017
  • Brazil: Adjusted EBITDA of $5.4 million in 3Q2017
  • Corporate, Argentina and Peru: Adjusted EBITDA of negative $3.2 million in 3Q2017

_______________

[1]   Production and Operating Costs = Operating Costs plus Royalties
1 See “Reconciliation of adjusted EBITDA to Profit (Loss) before income tax and adjusted EBITDA per boe” included in this press release.
 

The table below shows production, volumes sold and breakdown of the most significant components of adjusted EBITDA for 3Q2017 and 3Q2016, on a per country and per barrel basis:

                 
Adjusted EBITDA/boe   Colombia   Chile   Brazil   Total
    3Q17   3Q16   3Q17   3Q16   3Q17   3Q16   3Q17   3Q16
Production (boepd)   22,367   15,678   2,817   3,756   3,141   2,636   28,325   22,070
Stock variation /RIKa   (935)   (944)   (158)   (301)   (254)   (199)   (1,347)   (1,444)
Sales volume (boepd) 21,432 14,734 2,659 3,455 2,887 2,437 26,978 20,626
% Oil   100%   100%   35%   36%   2%   2%   83%   78%
($ per boe)
Realized oil price 34.1 25.9 44.3 37.8 59.4 48.3 34.6 26.9
Realized gas priceb - - 26.1 20.8 35.2 31.5 31.8 27.1
Earn-out   (1.3)   (0.9)   -   -   -   -   (0.9)   (0.6)
Combined Price   32.7   25.0   32.4   27.0   35.6   31.7   33.0   26.3
Commodity Risk Management Contracts   0.8   -   -   -   -   -   0.6   -
Operating costs (5.5) (7.1) (21.5) (15.9) (8.2) (6.6) (7.3) (8.5)
Royalties in cash (3.1) (1.7) (1.3) (1.1) (3.4) (3.1) (3.0) (1.7)
Selling & other expenses   0.0   (0.1)   (0.6)   (0.7)   -   -   (0.1)   (0.3)
Operating Netback/boe   24.9   16.3   9.0   9.4   24.0   22.1   23.2   15.8
G&A, G&G                           (5.2)   (5.6)
Adjusted EBITDA/boe                           18.0   10.2
a)   RIK (Royalties in Kind). Includes royalties paid in kind in Colombia for approximately 774 and 690 bopd in 3Q2017 and 3Q2016, respectively. No royalties were paid in kind in Chile and Brazil.
b) Conversion rate of mcf/boe=1/6
 

Depreciation: Consolidated depreciation decreased by 6% to $19.4 million in 3Q2017, compared to $20.8 million in 3Q2016, due to lower depreciation costs per boe as a consequence of drilling successes and increased reserves, partially offset by higher volumes sold. Depreciation costs per boe declined by 28% to $7.8 per boe.

Write-off of unsuccessful exploration efforts: Consolidated write-off of unsuccessful exploration efforts amounted to $0.2 million in 3Q2017, compared to $13.3 million in 3Q2016. Amounts recorded in 3Q2016 correspond to non-cash charges from seismic and exploration activities associated to the relinquishment of blocks with no production and no reserves in Colombia and Brazil, plus unsuccessful exploratory efforts in Chile.

Other expenses: Other operating expenses amounted to $0.4 million in 3Q2017, compared to $1.0 million gain in 3Q2016.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Net financial expenses: Net financial costs increased to $26.6 million in 3Q2017, compared to $8.6 million in 3Q2016. Amounts recorded in 3Q2017 include $17.6 million related to one-time costs on the cancellation of 2020 Notes (see “Financial Ratios” section below for further details). Excluding these costs, net financial expenses amounted to $9.0 million in 3Q2017.

Foreign exchange: Net foreign exchange charges amounted to a $3.2 million gain in 3Q2017 compared to a $1.8 million loss in 3Q2016, mainly due to the appreciation of the Brazilian real in 3Q2017 versus the depreciation in 3Q2016. Foreign exchange differences resulted from differences in the US Dollar-denominated debt incurred at the local subsidiary level and the underlying functional currency, the Brazilian real.

Income tax: Income taxes amounted to an $11.6 million loss in 3Q2017, as compared to a $3.5 million gain in 3Q2016, in line with operating profits recorded in 3Q2017 versus operating losses recorded in 3Q2016.

Net income: Net losses amounted to $19.1 million in 3Q2017 compared to $21.0 million in 3Q2016. The net loss in 3Q2017 mainly relates to one-time costs from the cancellation of 2020 Notes.

BALANCE SHEET

Cash and cash equivalents: Cash and cash equivalents totaled $135.2 million as of September 30, 2017. Year-end 2016 cash and cash equivalents amounted to $73.6 million. The difference reflects cash generated from operating activities of $117.4 million and cash from financing activities of $26.4 million, partially offset by cash used in investing activities of $80.3 million.

Cash from financing activities of $26.4 million includes net proceeds from the issuance of 2024 Notes of $420.8 million, offset by: (i) principal paid of $353.9 million related to the payment of 2020 Notes and the prepayment of the Itau loan, (ii) cancellation costs of $17.6, and (iii) interest payments of $22.4 million.

Prepayment facility and credit lines available: As of September 30, 2017, the Company had in place an offtake and prepayment agreement with Trafigura of up to $100 million ($12.5 million outstanding as of September 30, 2017) and approximately $28 million in uncommitted credit lines.

Financial debt: Total financial debt (net of issuance costs) amounted to $420.4 million, including the $425 million 2024 Notes issued in September 2017. Short-term debt amounted to $1.9 million as of September 30, 2017.

FINANCIAL RATIOSa

($ million)    

At period-
end

 

Financial
Debt

 

Cash and Cash
Equivalents

 

Net Debt

 

Net Debt/ LTM
Adj. EBITDA

 

LTM Interest
Coverage

         
3Q2016 352.9 63.6 289.3 4.7x 2.0x
4Q2016 358.7 73.6 285.1 3.6x 2.7x
1Q2017 341.7 70.3 271.4 2.6x 3.4x
2Q2017 346.3 77.0 269.3 2.2x 4.1x
3Q2017   420.4   135.2   285.2   1.9x   5.3x
a)   Based on trailing 12-month financial results.
 

Issuance of 2024 Notes: During September 2017, the Company successfully placed $425 million notes (“2024 Notes”) in accordance with Rule 144A under the United States Securities Act, and outside the United States to non-U.S. persons in accordance with Regulation S under the United States Securities Act. The 2024 Notes carry a coupon of 6.50% per annum. Funds were used to repay financial debt, to provide financial flexibility and for general corporate purposes.

The indenture governing the 2024 Notes includes incurrence test covenants that provides among other things, that, during the first two years from the issuance date, the net Debt to adjusted EBITDA ratio should not exceed 3.5 times and the adjusted EBITDA to interest ratio should exceed 2 times. Failure to comply with the incurrence test covenants would not trigger an event of default. As of the date of this release the Company is in compliance with all provisions and covenants.

IN MEMORIAM

GeoPark deeply laments the passing of Michael Dingman on October 3, 2017, a special friend, valued colleague, and a giant in international industry and finance, who served on GeoPark's Board of Directors and passionately supported and advised GeoPark’s management team. Michael´s extensive Board knowledge and experience on the boards of major listed companies greatly benefited the GeoPark Board of Directors.

 

   

SELECTED INFORMATION BY BUSINESS SEGMENT

(UNAUDITED)

 
Colombia   3Q2017   3Q2016
Revenue ($ million) 64.5 34.2
Production and Operating Costsa ($ million) -17.0 -12.0
Adjusted EBITDA ($ million) 41.6 17.4
Capital Expendituresb ($ million) 22.5 8.2
         
Chile   3Q2017   3Q2016
Sale of crude oil ($ million)   3.8   4.4
Sale of gas ($ million) 4.2 4.2
Revenue ($ million) 7.9 8.6
Production and Operating Costsa ($ million) -5.6 -5.4
Adjusted EBITDA ($ million) 0.8 1.0
Capital Expendituresb ($ million) 4.6 0.0
 
         
Brazil   3Q2017   3Q2016
Sale of crude oil ($ million)   0.2   0.2
Sale of gas ($ million) 9.2 6.9
Revenue ($ million) 9.4 7.1
Production and Operating Costsa ($ million) -3.1 -2.2
Adjusted EBITDA ($ million) 5.4 4.4
Capital Expendituresb ($ million) 0.0 0.6
a)   Production and Operating = Operating Costs + Royalties.
b) The difference with the reported figure in Key Indicators table corresponds mainly to capital expenditures in Argentina and to a lesser extent in Peru.
 
       

CONSOLIDATED STATEMENT OF INCOME

(UNAUDITED)

 
(In millions of $) 3Q2017   3Q2016   9M2017   9M2016

REVENUE

Sale of crude oil 68.4 38.4 187.0 95.9
Sale of gas 13.6 11.5 36.9 36.5
TOTAL REVENUE 81.9 49.9 223.8 132.3
Commodity risk management contracts -8.3 - 3.0 -
Production and operating costs -25.7 -19.6 -68.5 -46.4
Geological and geophysical expenses (G&G) -0.7 -2.3 -3.8 -7.6
Administrative expenses (G&A) -10.9 -8.5 -31.4 -24.2
Selling expenses -0.3 -0.5 -0.9 -3.6
Depreciation -19.4 -20.8 -55.1 -58.9
Write-off of unsuccessful exploration efforts -0.2 -13.3 -4.8 -13.7
Impairment for non-financial assets - - - -
Other operating -0.4 1.0 -2.4 -0.4
OPERATING PROFIT (LOSS) 15.9 -14.1 59.9 -22.6
 
Financial costs, net -26.6 -8.6 -43.3 -25.2
Foreign exchange gain (loss) 3.2 -1.8 1.4 15.3
PROFIT (LOSS) BEFORE INCOME TAX -7.5 -24.5 18.0 -32.5
 
Income tax -11.6 3.5 -32.4 -2.1
PROFIT (LOSS) FOR THE PERIOD -19.1 -21.0 -14.4 -34.7
Non-controlling interest 0.8 -2.9 5.4 -6.0
ATTRIBUTABLE TO OWNERS OF GEOPARK -19.9 -18.1 -19.8 -28.7
 
   

SUMMARIZED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

 
(In millions of $) Sep '17   Dec '16
(Unaudited) (Audited)
Non-Current Assets
Property, plant and equipment 497.9 473.6
Other non-current assets 46.9 45.7
Total Non-Current Assets 544.8 519.3
 
Current Assets
Inventories 4.7 3.5
Trade receivables 14.4 18.4
Other current assets 34.0 25.7
Cash at bank and in hand 135.2 73.6
Total Current Assets 188.3 121.2
 
Total Assets 733.1 640.5
 
Equity
Equity attributable to owners of GeoPark 90.0 105.8
Non-controlling interest 40.9 35.8
Total Equity 130.9 141.6
 
Non-Current Liabilities
Borrowings 418.5 319.4
Other non-current liabilities 78.8 80.0
Total Non-Current Liabilities 497.3 399.4
 
Current Liabilities
Borrowings 1.9 39.3
Other current liabilities 103.0 60.2
Total Current Liabilities 104.9 99.5

Total Liabilities

602.2 498.9
Total Liabilities and Equity 733.1 640.5
 
       

SUMMARIZED CONSOLIDATED STATEMENT OF CASH FLOWS

(UNAUDITED)

 
(In millions of $) 3Q2017   3Q2016   9M2017   9M2016
 
Cash flows from operating activities 38.2 26.4 117.4 54.9
Cash flows used in investing activities -30.9 -10.1 -80.3 -24.2
Cash flows from (used) in financing activities 51.4 -31.3 26.4 -49.4
 
 
RECONCILIATION OF ADJUSTED EBITDA TO PROFIT (LOSS) BEFORE INCOME TAX
(UNAUDITED)
         
9M2017 (In millions of $) Colombia   Chile   Brazil   Other   Total
Adjusted EBITDA 116.7 2.9

13.0

-12.0

120.5
Depreciation -29.2

-18.0

-7.7 -0.2 -55.1
Commodity Risk Management Contracts -0.7 - - - -0.7
Write-offs unsuccessful exploration efforts -1.6 -

-3.0

-0.2 -4.8
Share Based Payments -0.4 -0.3 -0.1 -2.3 -3.1
Others   4.1   0.6   -0.5   -1.1   3.1
OPERATING PROFIT (LOSS)   88.8   -14.7   1.7   -15.9   59.9
Financial costs, net -43.3
Foreign Exchange charges, net                   1.4
PROFIT (LOSS) BEFORE INCOME TAX

18.0

 
 
9M2016 (In millions of $)

 

Colombia

 

Chile

 

Brazil

 

Other

 

Total

Adjusted EBITDA

 

40.5

4.5

14.1

-7.7

51.4

Depreciation

 

-24.5

-24.1

-10.1

-0.2

-58.9

Commodity Risk Management Contracts

 

- - -

-

-

Write-offs unsuccessful exploration efforts

 

-7.4

-1.7

-4.6

-

-13.7

Share Based Payments

 

-0.5

-0.3

0.0

-1.1

-1.9

Others

 

0.3

 

0.9

 

1.0

 

-1.6

 

0.6

OPERATING PROFIT (LOSS)

 

8.3

 

-20.6

 

0.4

 

-10.7

 

-22.6

Financial costs, net

 

-25.2

Foreign Exchange charges, net              

 

 

15.3

PROFIT (LOSS) BEFORE INCOME TAX

 

-32.5

 
 

RECONCILIATION OF LAST TWELVE MONTHS ADJUSTED EBITDA TO PROFIT (LOSS) BEFORE INCOME TAX

(UNAUDITED)

Last Twelve Months - LTM (In millions of $)   Total
Adjusted EBITDA 147.5
Depreciation -72.0
Commodity Risk Management Contracts -3.8
Write-offs unsuccessful exploration efforts/impairment -16.8
Share Based Payments/Other -1.2

OPERATING PROFIT

  53.7
Financial costs, net -52.2
Foreign Exchange charges, net   0.1

PROFIT BEFORE INCOME TAX

1.6
 

CONFERENCE CALL INFORMATION

GeoPark will host its Third Quarter 2017 Financial Results conference call and webcast on Thursday, November 16, 2017, at 10:00 a.m. Eastern Daylight Time.

Chief Executive Officer, James F. Park, Chief Financial Officer, Andres Ocampo, and Chief Operating Officer, Augusto Zubillaga will discuss GeoPark's financial results for 3Q2017 and work program and investment guidelines for 2018, with a question and answer session immediately following.

Interested parties may participate in the conference call by dialing the numbers provided below:

United States Participants: 866-547-1509
International Participants: +1 920-663-6208
Passcode: 99494005

Please allow extra time prior to the call to visit the website and download any streaming media software that might be required to listen to the webcast.

An archive of the webcast replay will be made available in the Investor Support section of the Company’s website at www.geo-park.com after the conclusion of the live call.

GeoPark can be visited online at www.geo-park.com.

 

GLOSSARY

 
Adjusted EBITDA Adjusted EBITDA is defined as profit for the period before net finance costs, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful exploration efforts, accrual of share-based payments, unrealized results on commodity risk management contracts and other non-recurring events
 
Adjusted EBITDA per boe Adjusted EBITDA divided by total boe sales volumes
 
Bbl Barrel
 
Boe Barrels of oil equivalent
 
Boepd Barrels of oil equivalent per day
 
Bopd Barrels of oil per day
 
CEOP Contrato Especial de Operacion Petrolera (Special Petroleum Operations Contract)
 
D&M DeGolyer and MacNaughton
 
F&D costs Finding and development costs, calculated as capital expenditures in 2016 divided by the applicable net reserves additions before changes in Future Development Capital
 
“High price” royalty An additional royalty incurred in Colombia when each oil field exceeds 5 mmbbl of cumulative production and is determined by a combination of API gravity and WTI oil prices
 
Mboe Thousand barrels of oil equivalent
 
Mmbo Million barrels of oil
 
Mmboe Million barrels of oil equivalent
 
Mcfpd Thousand cubic feet per day
 
Mmcfpd Million cubic feet per day
 
Mm3/day Thousand cubic meters per day
 
NPV10 Present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual rate of 10%
 
Operating netback per boe Revenue, less production and operating costs (net of depreciation charges and accrual of stock options and stock awards) and selling expenses, divided by total boe sales volumes. Operating netback is equivalent to adjusted EBITDA net of cash expenses included in Administrative, Geological and Geophysical and Other operating costs
 
PRMS Petroleum Resources Management System
 
SPE Society of Petroleum Engineers
 
SQ KM Square kilometers
 
WI Working interest
 

NOTICE

Additional information about GeoPark can be found in the “Investor Support” section on the website at www.geo-park.com.

Rounding amounts and percentages: Certain amounts and percentages included in this press release have been rounded for ease of presentation. Percentage figures included in this press release have not in all cases been calculated on the basis of such rounded figures, but on the basis of such amounts prior to rounding. For this reason, certain percentage amounts in this press release may vary from those obtained by performing the same calculations using the figures in the financial statements. In addition, certain other amounts that appear in this press release may not sum due to rounding.

This press release contains certain oil and gas metrics, including information per share, operating netback, reserve life index, and others, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.

CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

This press release contains statements that constitute forward-looking statements. Many of the forward-looking statements contained in this press release can be identified by the use of forward-looking words such as ‘‘anticipate,’’ ‘‘believe,’’ ‘‘could,’’ ‘‘expect,’’ ‘‘should,’’ ‘‘plan,’’ ‘‘intend,’’ ‘‘will,’’ ‘‘estimate’’ and ‘‘potential,’’ among others.

Forward-looking statements that appear in a number of places in this press release include, but are not limited to, statements regarding the intent, belief or current expectations, regarding various matters, including expected 2017 production growth and performance, operating netback per boe and capital expenditures plan. Forward-looking statements are based on management’s beliefs and assumptions, and on information currently available to the management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors.

Forward-looking statements speak only as of the date they are made, and the Company does not undertake any obligation to update them in light of new information or future developments or to release publicly any revisions to these statements in order to reflect later events or circumstances, or to reflect the occurrence of unanticipated events. For a discussion of the risks facing the Company which could affect whether these forward-looking statements are realized, see filings with the U.S. Securities and Exchange Commission.

Oil and gas production figures included in this release are stated before the effect of royalties paid in kind, consumption and losses. Annual production per day is obtained by dividing total production for 365 days.

Information about oil and gas reserves: The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proven, probable and possible reserves that meet the SEC's definitions for such terms. GeoPark uses certain terms in this press release, such as "PRMS Reserves" that the SEC's guidelines do not permit GeoPark from including in filings with the SEC. As a result, the information in the Company’s SEC filings with respect to reserves will differ significantly from the information in this press release.

NPV10 for PRMS 1P, 2P and 3P reserves is not a substitute for the standardized measure of discounted future net cash flows for SEC proved reserves.

The reserve estimates provided in this release are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual reserves may eventually prove to be greater than, or less than, the estimates provided herein. Statements relating to reserves are by their nature forward-looking statements.

Adjusted EBITDA: The Company defines adjusted EBITDA as profit for the period before net finance costs, income tax, depreciation, amortization and certain non-cash items such as impairments and write-offs of unsuccessful exploration and evaluation assets, accrual of stock options stock awards, unrealized results on commodity risk management contracts and other non-recurring events. Adjusted EBITDA is not a measure of profit or cash flows as determined by IFRS. The Company believes adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. The Company excludes the items listed above from profit for the period in arriving at adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, profit for the period or cash flows from operating activities as determined in accordance with IFRS or as an indicator of our operating performance or liquidity. Certain items excluded from adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure and significant and/or recurring write-offs, as well as the historic costs of depreciable assets, none of which are components of adjusted EBITDA. The Company’s computation of adjusted EBITDA may not be comparable to other similarly titled measures of other companies. For a reconciliation of adjusted EBITDA to the IFRS financial measure of profit for the year or corresponding period, see the accompanying financial tables.

Operating netback per boe should not be considered as an alternative to, or more meaningful than, profit for the period or cash flows from operating activities as determined in accordance with IFRS or as an indicator of our operating performance or liquidity. Certain items excluded from Operating Netback per boe are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure and significant and/or recurring write-offs, as well as the historic costs of depreciable assets, none of which are components of Operating Netback per boe. The Company’s computation of Operating Netback per boe may not be comparable to other similarly titled measures of other companies. For a reconciliation of Operating Netback per boe to the IFRS financial measure of profit for the year or corresponding period, see the accompanying financial tables.