GeoPark Reports Results For The Third Quarter 2016

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 1 reports its consolidated financial results for the three-month period ended September 30, 2016 ("Third Quarter" or 3Q2016").

A conference call to discuss 3Q2016 Financial Results and 2017 Work Program and Investment Guidelines will be held on November 15, 2016 at 10 a.m. 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.

THIRD QUARTER 2016 HIGHLIGHTS

Operational:
  • Oil and Gas Production Up 15% to 22,070 boepd
    • Oil production up 15% to 16,942 boepd
    • Gas production up 13% to 30.8 mmcfpd
    • 2016 targeted exit production of 23,500-24,500 boepd
  • Unfolding World-Class Oil Play in Colombia
    • Tigana/Jacana oil field complex producing 25,000+ bopd gross from 13 wells in Llanos 34 Block (GeoPark operated with a 45% WI)
    • Recent drilling results expanded field size, with expected significant reserve impact
    • Jacana 6 appraisal well drilled outside 2P reserve outline, expected to be tested during November
    • 2016 drilling program continuing with 2-3 additional wells

Financial:
  • Adjusted EBITDA up 7%
    • Adjusted EBITDA up 7% to $19.4 million
    • 9M2016 Adjusted EBITDA of $52 million, covering full 2016 capital expenditures
    • Cash cost per boe down 8% to $16.1
    • 9M2016 Cash costs down $20.1 million vs. 9M2015
    • Net loss for the period of $21.0 million, after $13.3 million non-cash write-offs
  • Hedging Secures $50/bbl Minimum Oil Price
    • Secured a minimum Brent price of $50 per barrel for 6,000 bopd (approximately 30-35% of expected total oil production) through June 30, 2017
  • $180 Million Cash and Available Facilities
    • Cash on hand of $63.6 million, $80.0 million in available committed facilities, and $36.0 million in uncommitted facilities

Strategic:
  • 2017 Work Program and Investment Guidelines Highlights
    • Focus on unfolding potential of the Tigana/Jacana oil field complex
    • Fully funded $80-90 million adaptable capital program, with 70-75% allocated to Colombia
    • Base case production growth of 20-25% to 26,500-27,500 boepd
    • Estimated 2017 exit production above 30,000 boepd
    • Drilling of approximately 30-35 wells

__________________________
1     Transaction executed with Petroperu on October 1, 2014 with final closing subject to Peru Government approval

For further detail, please refer to 2017 Work Program and Investment Guidelines released on November 14, 2016.

James F. Park, Chief Executive Officer of GeoPark, said: "Our third quarter financial results reflect our operating success through the year - and, despite market volatility in the beginning of the year, our growing cash flow has already fully-funded our total 2016 work program. Operating and financial growth is being driven by the successful production, development and appraisal of the Tigana/Jacana oil field complex in Colombia - where its attractive geology and low cost operating structure suggest big economic potential and a powerful engine of growth for GeoPark for the next 3-4 years. New results from testing and drilling this play are expected during the Fourth Quarter 2016."

CONSOLIDATED OPERATING PERFORMANCE

The table below sets forth key performance indicators for 3Q2016 compared to those of 3Q2015:

 
Key Indicators     3Q2016   3Q2015   % Chg.
Oil production a (bopd)     16,942   14,712   15%
Gas production (mcfpd) 30,774 27,188 13%
Average net production (boepd)     22,070   19,244   15%
Brent Oil Price ($ per bbl) 46.9 52.0 -10%
Combined price ($ per boe) 26.3 28.2 -7%
¿ Oil ($ per bbl) 26.9 30.1 -11%
¿ Gas ($ per mcf) 4.5 4.2 7%
Net Oil Revenues ($ million) 38.4 38.6 -1%
Net Gas Revenues ($ million) 11.5 9.3 24%
Net Revenues ($ million) 49.9 47.8 4%
Production & Operating Costs b ($ million) -19.6 -18.2 8%
G&G, G&A c and Selling Expenses ($ million) -11.3 -12.8 -12%
Adjusted EBITDA ($ million) 19.4 18.2 7%
Adjusted EBITDA per boe ($) 10.2 10.7 -5%
Operating Netback per boe ($) 15.8 17.6 -10%
Profit (loss) for the period ($ million)     -21.0   -37.7   -44%
Capital Expenditures during quarter ($ million)     10.1   26.3   -62%
Cash Position at period-end ($ million) 63.6 90.4 -30%
Short-Term Debt at period-end ($ million) 32.5 26.2 24%
Long-Term Debt at period-end ($ million)     320.4   338.2   -5%
a)     Includes government royalties paid in kind in Colombia for approximately 690 bopd in 3Q2016 and 726 bopd in 3Q2015. 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 $0.9 million and $1.0 million for 3Q2016 and 3Q2015, respectively, of (non-cash) share based payments that are excluded from the Adjusted EBITDA calculation.

Production: consolidated oil and gas production increased 15% to 22,070 boepd in 3Q2016 compared to 19,244 boepd in 3Q2015. The increase was mainly attributed to higher production in Colombia (production from Jacana Field - discovered in 3Q2015 - with three new wells put into production during 3Q2016) and Chile (increased gas production from the Ache Field - put into production in 3Q2015), partially offset by lower gas production in the Manati Field, due to lower gas consumption in northeastern Brazil.
  • Colombia: Average net oil production increased by 20% to 15,678 bopd in 3Q2016 compared to 13,033 bopd in 3Q2015
  • Chile: Average net oil and gas production increased by 17% to 3,756 boepd in 3Q2016 compared to 3,207 boepd in 3Q2015
  • Brazil: Average net oil and gas production decreased 12% to 2,636 boepd in 3Q2016 compared to 3,004 boepd in 3Q2015

For further detail, please refer to 3Q2016 Operational Update released on October 11, 2016.

Reference and Realized Oil Prices: Brent crude price averaged $46.9 per barrel during 3Q2016, while consolidated realized oil sales price averaged $26.9 per barrel in 3Q2016 resulting from commercial and transportation discounts, both in Colombia and Chile, and the Vasconia differential in Colombia.

The table below sets forth a breakdown of reference and net realized oil prices in Colombia and Chile in 3Q2016:
         
3Q2016 - Realized Oil Prices

($ per bbl)
  Colombia   Chile
Brent Oil Price   46.9   46.9
Vasconia Differential (5.7) -
Commercial and Transportation Discounts (15.2) (9.1)
Other a   (0.1)   -
Realized Oil Price   25.9   37.8
Weight on Oil Sales Mix   92%   8%
a)     Corresponds to a short-term agreement to fix the price of 4,000 bopd of the Company´s production at $45.1/bbl Brent price for a period of 3-months ended July 31, 2016.

In Colombia, commercial discounts are mainly related to oil transportation costs, which are deducted from the net price, following the terms of the Trafigura offtake agreement (announced in December 2015, with deliveries that began in March 2016).

The Company secured a minimum Brent price of $50 per barrel on production of 6,000 bopd (approximately 30-35% of GeoPark expected total oil production), through a zero-cost collar structure that includes a maximum price of $57 per barrel for the same volumes. This hedge is effective from November 1, 2016 to June 30, 2017.

Net Revenues: Consolidated net revenues increased by 4% to $49.9 million in 3Q2016, compared to $47.8 million in 3Q2015, mainly driven by higher gas revenues, partially offset by a slight decrease in oil revenues.

Oil Revenues: Consolidated oil revenues decreased by 1% to $38.4 million in 3Q2016, mainly due to a 11% decrease in realized oil prices, offset by increased production. Oil revenues represent 77% of total net revenues as compared to 81% in 3Q2015.
  • Colombia: In 3Q2016, oil revenues increased by 5% to $33.8 million mainly due to increased deliveries, partially offset by lower realized oil prices. Realized oil prices decreased by 10% to $25.9 per barrel, in line with decreased Brent prices. Oil deliveries increased by 15% to 14,734 bopdColombian earn-out payments (deducted from Colombian oil revenues) decreased by 14% to $1.3 million in 3Q2016, compared to $1.5 million in 3Q2015, in line with lower oil prices
  • Chile: In 3Q2016, oil revenues decreased by 28% to $4.4 million due to lower production and lower prices. Realized oil prices decreased 8% to $37.8 per barrel in line with decreased Brent prices. Deliveries decreased by 22% to 1,257 bopd due to lower production resulting from the natural decline of the fields and no new oil wells drilled since 4Q2014

Gas Revenues: Consolidated gas revenues increased by 24% to $11.5 million in 3Q2016 compared to $9.3 million in 3Q2015.
  • Chile: In 3Q2016, gas revenues increased by 45% to $4.2 million mainly due to increased production, resulting from new gas projects, partially offset by lower prices. Gas deliveries increased by 82% and amounted to 13,194 mcfpd (2,199 boepd) mainly resulting from the start-up of the Ache gas field (in 4Q2015) and the Pampa Larga 16 development well (in 1Q2016). Gas prices decreased by 20% to $3.5 per mcf ($20.8 per boe) in 3Q2016
  • Brazil: In 3Q2016, gas revenues increased by 9% to $6.9 million, mainly due to higher gas prices, partially offset by lower production. Gas prices, net of taxes, increased by 25% to $5.2 per mcf ($31.5 per boe) due to the appreciation of the local currency and the annual gas-price inflation adjustment of approximately 10% in 1Q2016. Gas deliveries decreased by 13% and amounted to 14,396 mcfpd (2,399 boepd) due to lower gas consumption. Manati field production capacity remained unaffected and it is expected to reach an annual average level of 18,000 mcfpd (3,000 boe) in 2016

Production and Operating Costs 2 : Consolidated production and operating costs increased by 8% to $19.6 million in 3Q2016, compared to $18.2 million in 3Q2015, due to increased production levels (15% increased production compared to 3Q2015) and one-time road maintenance and well facilities costs.

Operating Costs: Consolidated operating costs (excluding royalties) increased by 18% to $16.3 million in 3Q2016, due to increased production levels and, to a lesser extent, to the impact of the revaluation of local currencies against the US Dollar.
  • Colombia: Operating costs increased by 27% to $9.8 million in 3Q2016, mainly resulting from increased production levels (20% increased production compared to 3Q2015) and one-time charges for $2.3 million (or $1.7 per boe) associated with one-time road maintenance and well facilities costs in Llanos 34 BlockCompared to 2Q2016, Colombian operating costs increased by $4.8 million (or $3.1 per boe) in 3Q2016, mainly due to: (i) the reopening of La Cuerva and other marginal fields (with higher operating costs than the average in Colombia) that represented incremental costs of $1.2 million, and (ii) one-time charges for $2.3 million (or $1.7 per boe), associated with one-time road maintenance and well facilities costs in Llanos 34 Block.
  • Chile: Operating costs increased by 5% to $5.1 million in 3Q2016 due to increased production, partially offset by lower operating costs per boe. Operating costs per boe decreased by 14% to $15.9 per boe
  • Brazil: Operating costs remained stable at $1.5 million in 3Q2016. Operating costs per boe increased by 16% to $6.6 impacted by lower production levels affecting fixed cost absorption

Royalties: Consolidated royalties paid in cash (reported in Production and Operating Costs) decreased to $3.3 million in 3Q2016, compared to $4.4 million in 4Q2015, in line with the decline in oil prices.

Selling Expenses: Consolidated selling expenses increased to $0.5 million in 3Q2016 compared to $0.4 million in 3Q2015 in line with increased production and deliveries during the quarter.

Administrative Expenses and Geological & Geophysical Expenses (G&A, G&G): Consolidated G&A and G&G expenses decreased by 14% to $10.8 million in 3Q2016 compared to $12.4 million in 3Q2015 mainly due to continuing financial discipline and cost reduction initiatives.

Adjusted EBITDA: Consolidated Adjusted EBITDA 3 increased by 7% to $19.4 million, or $10.2 per boe, in 3Q2016 compared to $18.2 million, or $10.7 per boe, in 3Q2015, mainly caused by increased production levels and cash cost reductions, partially offset by lower realized prices.
  • Colombia: Adjusted EBITDA of $17.4 million in 3Q2016
  • Chile: Adjusted EBITDA of $1.0 million in 3Q2016
  • Brazil: Adjusted EBITDA of $4.4 million in 3Q2016
  • Corporate, Argentina and Peru: Adjusted EBITDA of negative $3.4 million

__________________________
2     Production and Operating Costs = Operating Costs plus Royalties

3

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 3Q2016 and 3Q2015, on a per country and on a per boe basis:
Adjusted EBITDA/boe     Colombia     Chile     Brazil     Total
      3Q16   3Q15     3Q16   3Q15     3Q16   3Q15     3Q16   3Q15
Production (boepd)     15,678   13,033     3,756   3,207     2,636   3,004     22,070   19,244
Stock variation /RIK a     (944)   (261)     (301)   (392)     (199)   (209)     (1,444)   (862)
Sales Volume (boepd) 14,734 12,772 3,455 2,815 2,437 2,795 20,626 18,382
% Oil     100%   100%     36%   57%     2%   2%     78%   78%
($ per boe)
Realized Oil Price 25.9 28.8 37.8 41.0 48.3 50.8 26.9 30.1
Realized Gas Price b - - 20.8 26.1 31.5 25.1 27.1 25.3
Earn-out     (0.9)   (1.3)     -   -     -   -     (0.6)   (1.0)
Combined Price     25.0   27.5     27.0   34.6     31.7   25.5     26.3   28.2
Operating Costs (7.1) (6.5) (15.9) (18.5) (6.6) (5.6) (8.5) (8.1)
Royalties in cash (1.7) (1.5) (1.1) (1.6) (3.1) (2.3) (1.7) (2.4)
Selling & Other Expenses     (0.1)   1.4     (0.7)   (0.7)     -   (0.1)     (0.3)   (0.1)
Operating Netback     16.3   19.6     9.4   13.8     22.1   17.5     15.8   17.6
G&A, G&G                                   (5.6)   (6.9)
Adjusted EBITDA/boe                                   10.2   10.7
a)     RIK (Royalties in Kind). Includes royalties paid in kind in Colombia for approximately 690 bopd in 3Q2016 and 726 bopd in 3Q2015. No royalties were paid in kind in Chile and Brazil.
b) Conversion rate of $mcf/$boe=1/6.

Write-off of Unsuccessful Efforts: Consolidated write-off of unsuccessful efforts amounted to $13.3 million in 3Q2016, compared to $3.7 million in 3Q2015. Amounts recorded in 3Q2016 correspond to non-cash charges from seismic and exploratory costs associated to the relinquishment of blocks with no production and no reserves in Colombia and Brazil plus unsuccessful exploratory efforts in Chile (incurred in prior years).

Depreciation: Consolidated depreciation charges decreased by 15% to $20.8 million in 3Q2016, compared to $24.5 million in 3Q2015, mainly due to lower depreciation costs per boe in Colombia and Chile and stable depreciation costs per boe in Brazil. In Colombia, the decrease in depreciation costs per boe is the result of drilling success and increased reserves, while in Chile, it is mostly related to impairment charges recognized in 4Q2015.

Other expenses: Other operating non-recurrent charges amounted to a $1.0 million gain in 3Q2016, compared to a $3.9 million loss in 3Q2015.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Financial Costs: Net financial costs decreased by 4% to $8.6 million in 3Q2016, mainly consisting of lower interest costs and bank charges.

Foreign Exchange: Net foreign exchange charges amounted to a $1.8 million loss in 3Q2016 compared to a $28.4 million loss in 3Q2015, mainly related to the impact of the devaluation of the Brazilian Real (1% in 3Q2016 vs. 27% in 3Q2015) over the US Dollar-denominated net debt incurred at the local subsidiary level, where the functional currency is the Brazilian Real.

Income Tax: Income tax gains amounted to $3.5 million in 3Q2016 as compared to $15.0 million in 3Q2015, in line with lower losses before taxes in 3Q2016 as compared to 3Q2015.

Net Income: Loss for the period amounted to $21.0 million in 3Q2016 compared to $37.7 million in 3Q2015.

BALANCE SHEET

Cash and Cash Equivalents: Cash and cash equivalents totaled $63.6 million as of September 30, 2016. Year-end 2015 cash and cash equivalents amounted to $82.7 million, the difference primarily being: (i) cash used in investing activities amounting to $24.2 million, (ii) cash used in financing activities of $49.4 million (made up of principal payments of $21.4 million primarily related to the Itau Loan plus interest payments of $25.5 million), and (iii) cash generated from operating activities that amounted to $54.9 million.

The table below shows a reconciliation of cash and cash equivalents as of June 30, 2016 and September 30, 2016.
         
($ million)        
Cash + Cash Equivalents - June 30, 2016       79.2
Cash from Operating activities       26.5
Cash used in Investing activities a (10.1)
Cash used in Financing activities b (31.2)
Currency translation effect       (0.8)
Cash + Cash Equivalents - September 30, 2016       63.6
a)     Including Capex in Colombia amounting to $8.2 million during 3Q2016.
b) Mainly related to principal payments ($11.3 million), interest payments ($12.8 million) and dividends to non-controlling interest ($6.4 million).

Prepayment Facility and Credit Lines Available: As of September 30, 2016, the Company has in place an offtake and prepayment agreement with Trafigura of up to $100 million (with $20 million drawn) and approximately $36 million in uncommitted credit lines.

Financial Debt: Total financial debt (net of debt issuance costs) amounted to $352.9 million, including principally the $300 million 2020 Bond and the Itau Loan (originally incurred for the acquisition of an interest in the Brazilian Manati Field) amounting to $48.9 million.

FINANCIAL RATIOS a
($ million)
At period-end    

Financial Debt
   

Cash Position
   

Gross Debt / LTM Adj. EBITDA
   

Net Debt b / LTM Adj. EBITDA
   

Interest

Coverage
                   
3Q2015 364.6 90.4 4.0x 3.0x 2.9x
FY2015 378.7 82.7 5.1x 4.0x 2.4x
1Q2016 363.0 71.6 5.3x 4.3x 2.2x
2Q2016 369.9 79.2 6.1x 4.8x 2.0x
3Q2016     352.9 c     63.6     5.7x     4.7x     2.0x
a)     Based on trailing 12 month financial results.
b) Included for informational purposes only. Not included in the 2020 Bond Indenture.
c) Decreased total financial debt in 3Q2016 vs. 2Q2016 corresponds to principal and interest payments, partially offset by interest costs accrued during the period.

GeoPark's consolidated financial incurrence test covenants included in the 2020 Bond Indenture are:
  • A leverage Ratio, defined as Gross Debt to Adjusted EBITDA, lower than 2.5x from 2015 onwards; and
  • An Interest Coverage Ratio, defined as Adjusted EBITDA divided by Interest Expenses, above 3.5x

As shown in the table above, as of September 30, 2016 the Company's Leverage Ratio was above the 2.5 times threshold included in the 2020 Bond Indenture and in addition, the Interest Coverage Ratio was below the 3.5 times threshold included in the 2020 Bond Indenture. These ratios were impacted by the current low oil price environment. Failure to comply with the incurrence test ratios does not trigger an event of default. However, this situation may limit the Company's capacity to incur additional indebtedness, other than permitted debt, as specified in the indenture governing the Notes. Incurrence covenants as opposed to maintenance covenants must be tested by the Company before incurring additional debt or performing other specific corporate actions including but not limited to dividend payments and restricted payments.

SELECTED INFORMATION BY BUSINESS SEGMENT

(unaudited)
             
Colombia     3Q2016     3Q2015

Net Oil Revenues ($ million)
   

33.8
    32.3

Production and Operating Costs a ($ million) 
-12.0 -11.0
Adjusted EBITDA ($ million) 17.4 17.6
Capital Expenditures b ($ million) 8.2 17.9
             
Chile     3Q2016     3Q2015
Net Oil Revenues ($ million)     4.4     6.1
Net Gas Revenues ($ million) 4.2 2.9
Net Revenues ($ million) 8.6 8.9
Production and Operating Costs a ($ million) -5.4 -5.2
Adjusted EBITDA ($ million) 1.0 0.0
Capital Expenditures b ($ million) 0.0 6.1
             
Brazil     3Q2016     3Q2015
Net Oil Revenues ($ million)     0.2     0.2
Net Gas Revenues ($ million) 6.9 6.4
Net Revenues ($ million) 7.1 6.6

Production and Operating Costs a ($ million) 
-2.2 -2.0
Adjusted EBITDA ($ million) 4.4 3.6
Capital Expenditures b ($ million) 0.6 2.3
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

CONSOLIDATED STATEMENT OF INCOME
(unaudited)            
 
(In millions of $) 3Q2016       3Q2015

NET REVENUES
Sale of crude oil 38.4 38.6
Sale of gas 11.5 9.3
TOTAL NET REVENUES 49.9 47.8
Production and operating costs -19.6 -18.2
Geological and Geophysical expenses (G&G) -2.3 -3.3
Administrative expenses (G&A) -8.5 -9.1
Selling expenses -0.5 -0.4
Depreciation -20.8 -24.5
Write-off of unsuccessful efforts -13.3 -3.7
Other operating 1.0 -3.9
OPERATING PROFIT (LOSS) -14.1 -15.2
 
Financial costs, net -8.6 -9.0
Foreign Exchange Gain (Loss) -1.8 -28.4
PROFIT (LOSS) BEFORE INCOME TAX -24.5 -52.6
 
Income tax 3.5 15.0
PROFIT (LOSS) FOR THE PERIOD -21.0 -37.7
Non-controlling interest -2.9 -1.5
ATTRIBUTABLE TO OWNERS OF GEOPARK -18.1 -36.2

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

(unaudited)
                     
3Q2016 Colombia     Chile     Brazil     Other     Total
Adjusted EBITDA 17.4 1.0 4.4 -3.4 19.4
Depreciation -10.2 -7.6 -2.9 -0.0 -20.8
Write-offs unsuccessful efforts -7.4 -1.3 -4.6 0.0 -13.3
Share Based Payments -0.2 -0.1 0.0 -0.8 -1.1
Others       0.5     0.5     1.1     -0.5     1.7
OPERATING PROFIT (LOSS)       0.0     -7.5     -2.0     -4.7     -14.1
Financial costs, net -8.6
Foreign Exchange charges, net                               -1.8
PROFIT (LOSS) BEFORE INCOME TAX -24.5
 
3Q2015 Colombia     Chile     Brazil     Other     Total
Adjusted EBITDA 17.6 0.0 3.6 -2.9 18.2
Depreciation -13.3 -8.0 -3.1 -0.0 -24.5
Write-offs unsuccessful efforts -3.7 0.0 0.0 0.0 -3.7
Share Based Payments 0.0 -0.2 0.0 -1.2 -1.4
Others       0.5     -3.2     0.0     -1.1     -3.8
OPERATING PROFIT (LOSS)       1.1     -11.5     0.4     -5.2     -15.2
Financial costs, net -9.0
Foreign Exchange charges, net                               -28.4
PROFIT (LOSS) BEFORE INCOME TAX -52.6

CONSOLIDATED SUMMARIZED STATEMENT OF FINANCIAL POSITION
      Sept '16       Dec '15
     
Non Current Assets
Property, Plant and Equipment 487.5 522.6
Other Non Current Assets 48.0 49.4
Total Non Current Assets 535.5 572.0
 
Current Assets
Inventories 3.6 4.3
Trade Receivables 11.9 13.5
Other Current Assets 29.7 31.3
Cash at bank and in hand 63.6 82.7
Total Current Assets 108.8 131.8
 
Total Assets 644.3 703.8
 
Equity
Equity attributable to owners of GeoPark 124.3 146.7
Non-controlling interest 41.3 53.5
Total Equity 165.6 200.2
 
Non Current Liabilities
Borrowings 320.4 343.2
Other Non Current Liabilities 84.5 79.0
Total Non Current Liabilities 404.9 422.2
 
Current Liabilities
Borrowings 32.5 35.4
Other Current Liabilities 41.3 46.0
Total Current Liabilities 73.8 81.4

Total Liabilities
478.7 503.6
Total Liabilities and Equity 644.3 703.8

CONFERENCE CALL INFORMATION

GeoPark will host its Third Quarter 2016 Financial Results and Work Program and Investment Guidelines 2017 conference call and webcast on Tuesday, November 15, 2016, at 10:00 a.m. Eastern Standard 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 3Q2016 and work program and investment guidelines for 2017, 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: 866-547-1509International Participants: +1 920-663-6208Passcode: 93708120

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 cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful efforts, accrual of share-based payment and other non-recurring events
 
Adjusted EBITDA per boe Adjusted EBITDA divided by total boe deliveries
 

Operating Netback per boe
Net revenues, less production costs (net of depreciation charges and accrual of stock options and stock awards) and selling expenses, divided by total boe deliveries. Operating Netback is equivalent to Adjusted EBITDA net of cash expenses included in Administrative, Geological and Geophysical and Other operating costs
 
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
 
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
 
Mm 3 /day Thousand cubic meters per day
 
PRMS Petroleum Resources Management System
 
SPE Society of Petroleum Engineers
 
WI Working interest
 
NPV10 Present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual rate of 10%
 
Sqkm Square kilometers

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.

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 2016 production growth and capital expenditures plan, and 2017 work program and investment guidelines. 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.

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 cost, 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, bargain purchase gain on acquisition of subsidiaries 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.

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