GeoPark Reports Results for the Fourth Quarter and Full Year Ended December 31, 2016

Record Oil and Gas Production and Reserves /
$28MM Colombian Investment Program Generates $351MM Increase in Value

SANTIAGO, Chile--()--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 December 31, 2016 (“Fourth Quarter” or “4Q2016”), and its audited annual results for 2016.

A conference call to discuss 4Q2016 Financial Results will be held on March 8, 2017 at 10 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, investors should read this release in conjunction with GeoPark’s consolidated financial statements and the notes to those statements for the years ended December 31, 2016 and 2015 available on the Company’s website.

FOURTH QUARTER AND FULL YEAR 2016 HIGHLIGHTS

More Oil and Gas

  • Record Oil and Gas Production:
    • Consolidated production up 2% to 23,593 boepd
    • Colombia production up 13% to 17,535 bopd
    • Current production of 25,900 boepd
  • Record Oil and Gas Reserves:
    • Proven and Probable (2P) PRMS reserves up 14% to 142.8 mmboe
    • Colombia 2P PRMS reserves up 45% to 67.4 mmboe

More Efficiencies / Less Cost

  • Finding and Development Costs:
    • Consolidated 2P of $1.7/boe
    • Colombia 2P of $1.0/bbl
  • Operating Costs:
    • Consolidated operating costs down 19% to $8.1 per boe / full year down 31%
    • Colombia down 32% to $6.1 per bbl / full year down 39%

More Cash Generation

  • Adjusted EBITDA up 154% to $27.0 million / full year up 6% to $78.3 million
  • Operating Netback up 83% to $39.5 million / full year up 3% to $122.1 million
  • Cash Flow from Operating Activities up to $28.0 million / full year up 220% to $82.9 million
  • Net loss reduced to $26.0 million / full year net loss of $60.6 million (impacted by $25.7 million in non-cash write-offs and impairments)
  • Over $160 million in cash and available facilities ($73.6 million cash)

More Value

  • Independently-certified proven (1P) reserves NPV10 up 26% to $1.1 Billion (equivalent to net debt adjusted NPV10 of $12.3 per share)
  • Independently-certified 2P reserves NPV10:
    • Consolidated NPV10 up 15% to $1.9 Billion (equivalent to net debt adjusted NPV10 of $23.6 per share)
    • Colombia NPV10 up 54% to $1.0 Billion (equivalent to net debt adjusted NPV10 of $10.2 per share)
  • $28 million 2016 capital investment program produced $351 million increase in 2P NPV10 in Colombian assets (despite using lower oil price forecast)

More Opportunity

  • 2017 $80-90 million base case capital investment program, at a $45-50 per barrel oil price, targets 20-25% production growth and exit production of 30,000 boepd consisting of:
    • 15-20 gross well development, appraisal and exploration drilling program in Llanos 34 Block in Colombia
    • 8 gross well exploration drilling program in prolific Neuquen Basin in Argentina
    • 4 gross well exploration and development drilling program in mature Magallanes Basin in Chile
    • 3 gross well exploration drilling program in mature onshore Reconcavo and Potiguar Basins in Brazil
  • New acquisition opportunities in Colombia, Brazil, Argentina, Mexico and other operated countries

James F. Park, Chief Executive Officer of GeoPark, said: “Congratulations to the GeoPark team for doing an exceptional job through the 2016 industry turbulence and achieving important advances across all our business. We discovered and produced more oil and gas. We increased our efficiency and did more for less. We generated more cash and strengthened our balance sheet. We became a better and more capable organization. We grew total Company value and the underlying value of every share owned by our shareholders. We again extended our leading 10+ year growth track record. And, we positioned GeoPark for an even more exciting year to come in 2017. This already is being proved up by our early 2017 operational successes which are setting us on a path to leap-frog our strong 2016 performance.”

OIL AND GAS RESERVES

GeoPark consolidated 2P reserves increased by 14% in 2016 to 142.8 mmboe compared to 2015. The increase in reserves mainly results from new discoveries in the Llanos 34 Block (GeoPark operated with 45% WI) in Colombia.

  • PDP Reserves: Net proven developed producing (PDP) reserves increased by 13% (2.2 mmboe) to 19.5 mmboe, with a PDP reserve replacement index (RRI) of 127%. Total NPV10 of PDP reserves increased by 49% ($93.1 million) to $282.2 million
  • 1P Reserves: Net 1P reserves increased by 10% (7.1 mmboe) to 78.3 mmboe, with 1P reserve life index (RLI) of 9.5 years and a 1P RRI of 187%. Total NPV10 of 1P reserves increased by 26% ($228 million) to $1.1 billion
  • 2P Reserves: Net 2P reserves increased by 14% (17.5 mmboe) to 142.8 mmboe, with a 2P RLI of 17.4 years and a 2P RRI of 312%. Total NPV10 of 2P reserves increased by 15% ($241 million) to $1.9 billion
  • Colombia 2P Reserves: Net 2P reserves in Colombia increased by 45% (20.9 mmboe) to 67.4 mmboe with a 2P RLI of 11.8 years and a 2P RRI of 468%. Total NPV10 of 2P reserves in Colombia increased by 54% ($351 million) to $1.0 billion

For further detail, please refer to 2016 Reserves Release published on February 6, 2017.

CONSOLIDATED OPERATING PERFORMANCE

The table below sets forth key performance indicators for 4Q2016 and 2016 compared to 3Q2016, 4Q2015 and 2015:

                     
Key Indicators   4Q2016   3Q2016   4Q2015   FY2016   FY2015
Oil productiona (bopd)   18,798   16,942   17,123   16,955   15,119
Gas production (mcfpd) 28,770 30,774 35,636

32,634

31,488
Average net production (boepd)   23,593   22,070   23,062   22,394   20,367
Brent Oil Price ($ per bbl) 51.1 46.9 45.0 45.2 54.3
Combined price ($ per boe) 29.3 26.3 23.5 25.2 30.0
⁻ Oil ($ per bbl) 31.2 26.9 23.6 25.6 32.1
⁻ Gas ($ per mcf) 4.6 4.5 4.3 4.5 4.6
Net Oil Revenues ($ million) 49.3 38.4 33.1 145.2 162.6
Net Gas Revenues ($ million) 11.0 11.5 12.3 47.5 47.1
Net Revenues ($ million) 60.3 49.9 45.4 192.7 209.7
Commodity Risk Mngmt Contracts ($ million) -2.6 0.0 0.0 -2.6 0.0
Production & Operating Costsb ($ million) -20.8 -19.6 -22.2 -67.2 -86.7
G&G, G&Ac and Selling Expenses ($ million) -13.2 -11.3 -15.8 -48.7 -56.5
Adjusted EBITDA ($ million) 27.0 19.4 10.6 78.3 73.8
Adjusted EBITDA per boe ($) 13.1 10.2 5.5 10.2 10.5
Operating Netback per boe ($) 19.2 15.8 11.2 15.9 16.9
Profit (loss) ($ million)   -26.0   -21.0   -201.5   -60.6   -284.6
Capital Expenditures ($ million)   15.1   10.1   6.6   39.3   -48.8
Cash Position at year-end ($ million) 73.6 63.6 82.7 73.6 82.7
Short-Term Debt at year-end ($ million) 39.3 32.5 35.4 39.3 35.4
Long-Term Debt at year-end ($ million)   319.4   320.4   343.2   319.4   343.2
a)   Includes government royalties paid in kind in Colombia for approximately 718 bopd in 4Q2016 and 776 bopd in 4Q2015. 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 $0.5 million and $3.2 million for 4Q2016 and 4Q2015, respectively, of (non-cash) share based payments that are excluded from the Adjusted EBITDA calculation.

Production: Consolidated oil and gas production increased 2% to 23,593 boepd in 4Q2016 compared to 23,062 boepd in 4Q2015. The increase was mainly attributed to higher production in Colombia (with six new wells put into production in 2H2016), partially offset by lower production in Chile and Brazil.

  • Colombia: Average net oil production increased by 13% to 17,535 bopd in 4Q2016 compared to 15,510 bopd in 4Q2015 due to continuing successful exploration drilling and development in the Llanos 34 Block
  • Chile: Average net oil and gas production decreased by 12% to 3,523 boepd in 4Q2016 compared to 4,006 boepd in 4Q2015 due to the natural decline of the fields with limited drilling activity since 2014, and no drilling activity in Chile during 4Q2016
  • Brazil: Average net oil and gas production decreased 29% to 2,535 boepd in 4Q2016 compared to 3,546 boepd in 4Q2015, primarily attributed to lower gas consumption by Brazilian industrial users

Production mix showed an increase in oil to 80% of the total reported production in 4Q2016 (vs. 74% in 4Q2015) explained by the successful drilling campaign in the Llanos 34 Block (GeoPark operated with 45% WI).

For further detail on production activities please refer to 4Q2016 Operational Update released on January 9, 2017.

Reference and Realized Oil Prices: Brent crude price averaged $51.1 per barrel during 4Q2016, while consolidated realized oil sales price averaged $31.2 per barrel in 4Q2016, up 16% from $26.9 per barrel in 3Q2016 and up 32% from $23.6 per barrel in 4Q2015. Differences between reference and realized prices result from commercial and transportation discounts, both in Colombia and Chile, and from the Vasconia differential in Colombia.

The table below sets forth a breakdown of reference and net realized oil prices in Colombia and Chile in 4Q2016:

         
4Q2016 - Realized Oil Prices

($ per bbl)

  Colombia   Chile
Brent Oil Price   51.1   51.1

Vasconia Differential

(5.7)

-

Commercial and Transportation Discounts

 

(15.0)

  (9.7)
Realized Oil Price   30.4   41.4
Weight on Oil Sales Mix   93%   7%

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). Commercial and Transportation discounts declined even further in 4Q2016 as most of the Colombian oil was sold at wellhead under the Trafigura agreement as compared to 4Q2015 where the sale strategy was a combination of wellhead and pipeline.

Commodity Risk Management Contracts - Brent Oil Price: In 4Q2016 the Company recorded the following amounts related to Commodity Risk Management Contracts to mitigate the risk exposure to changes in the price of Brent Oil Price. Realized gains reflect cash settled transactions, while unrealized losses reflect non-cash changes between the contract values and the forward Brent oil curve since the contracts were executed.

     

4Q2016 – Commodity Risk
Management Contracts

  ($ million)

Realized Cash Gain

  0.5

Non-Cash Unrealized Loss

  (3.1)
Net Effect   (2.6)

The Company has the following risk management contracts in place as of the date of this release:

  • For the period November 2016 – June 2017, GeoPark guaranteed a minimum Brent price of $50 per barrel for 6,000 bopd through a zero-cost collar structure that includes a maximum price of $57 per barrel
  • For the period January 2017 – September 2017, GeoPark secured a minimum Brent price of $53 per barrel for 6,000 bopd through a zero-cost collar structure that includes a maximum price of $61 per barrel

Net Revenues: Consolidated net revenues increased by 33% to $60.3 million in 4Q2016, compared to $45.4 million in 4Q2015, mainly driven by higher oil revenues, partially offset by lower gas revenues.

Oil Revenues: Consolidated oil revenues increased by 49% to $49.3 million in 4Q2016, mainly due to a 32% increase in realized oil prices and a 10% increase in oil production (compared to 4Q2015). Oil revenues represented 82% of total net revenues as compared to 73% in 4Q2015.

  • Colombia: In 4Q2016, oil revenues increased by 60% to $44.2 million mainly due to higher realized prices and increased deliveries. Under the Trafigura agreement, sales occur at the wellhead, reducing revenues slightly but having a larger reduction on selling expenses compared to 4Q2015. Realized oil prices increased by 37% to $30.4 per barrel, in line with increased Brent prices. Oil deliveries increased by 18% to 16,657 bopd

    Colombian earn-out payments (deducted from Colombian oil revenues) increased to $2.3 million in 4Q2016, compared to $1.3 million in 4Q2015, in line with higher oil revenues
  • Chile: In 4Q2016, oil revenues decreased by 4% to $5.0 million due to lower production, partially offset by higher prices. Realized oil prices increased 24% to $41.4 per barrel in line with increased Brent prices but oil deliveries decreased by 22% to 1,300 bopd

Gas Revenues: Consolidated gas revenues decreased by 11% to $11.0 million in 4Q2016 compared to $12.3 million in 4Q2015.

  • Chile: In 4Q2016, gas revenues decreased by 17% to $4.2 million mainly due to lower gas prices, partially offset by higher gas deliveries. Gas prices decreased by 21% to $3.7 per mcf ($21.9 per boe) in 4Q2016. Gas deliveries increased by 5% to 12,434 mcfpd (2,072 boepd)
  • Brazil: In 4Q2016, gas revenues decreased by 9% to $6.6 million, mainly due to lower production partially offset by higher gas prices. Gas prices, net of taxes, increased by 27% to $5.2 per mcf ($31.4 per boe) due to the appreciation of the local currency (+16%) and the annual gas-price inflation adjustment of approximately 10% since 1Q2016. Gas deliveries decreased by 29% and amounted to 13,784 mcfpd (2,297 boepd) due to lower industrial demand

Production and Operating Costs1: Consolidated production and operating costs decreased by 6% to $20.8 million in 4Q2016, compared to $22.2 million in 4Q2015, due to cost reduction efforts and efficiencies, partially offset by increased volume sold (6% increased deliveries compared to 4Q2015). Driving Production and Operating Costs into their constituent parts:

Royalties: Consolidated royalties paid in cash (reported in Production and Operating Costs) increased to $3.9 million in 4Q2016, compared to $2.7 million in 4Q2015, in line with increased production levels and higher oil prices.

Operating Costs: Consolidated operating costs (excluding royalties) decreased by 13% to $16.9 million in 4Q2016, as follows:

  • Colombia: Operating costs decreased by 20% to $9.5 million in 4Q2016, mainly resulting from cost reduction efforts, partially offset by the costs associated with that production (13% increased oil production compared to 4Q2015). Operating costs per boe decreased by 32% to $6.1 per boe
  • Chile: Operating costs decreased by 5% to $5.6 million in 4Q2016 due to lower production (12% decreased oil and gas production compared to 4Q2015). Operating costs per boe increased by 3% to $18.0 per boe as lower production affected fixed cost absorption
  • Brazil: Operating costs remained stable at $1.7 million in 4Q2016 despite a 29% decrease in production, mainly resulting from the impact of fixed costs plus the appreciation of the local currency (+16%). Operating costs per boe increased by 42% to $8.0 per boe

1 Production and Operating Costs = Operating Costs plus Royalties

Selling Expenses: Consolidated selling expenses decreased to $0.6 million in 4Q2016 compared to $1.4 million in 4Q2015 mainly as a result of lower selling expenses in Colombia. In Colombia, selling expenses decreased by 87% to just $0.1 million due to the Trafigura offtake agreement as sales occur at the well-head. Chilean selling expenses remained flat at $0.3 million in line with higher oil prices, offset by lower oil and gas production.

Administrative Expenses: Consolidated Administrative Expenses decreased by 2% to $10.0 million in 4Q2016 compared to $10.2 million in 4Q2015 mainly due to continuing financial discipline.

Geological & Geophysical Expenses: Consolidated G&G expenses decreased by 38% to $2.7 million in 4Q2016 compared to $4.3 million in 4Q2015 mainly due to lower staff costs and higher amounts allocated to capitalized projects.

Adjusted EBITDA: Consolidated Adjusted EBITDA2 increased by 154% to $27.0 million, or $13.1 per boe, in 4Q2016 compared to $10.6 million, or $5.5 per boe, in 4Q2015, mainly caused by increased production levels, cash cost reductions and higher realized oil prices.

  • Colombia: Adjusted EBITDA of $26.5 million in 4Q2016
  • Chile: Adjusted EBITDA of $0.6 million in 4Q2016
  • Brazil: Adjusted EBITDA of $3.3 million in 4Q2016
  • Corporate, Argentina and Peru: Adjusted EBITDA of negative $3.5 million

2 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 4Q2016 and 4Q2015, on a per country and per boe basis:

                 
Adjusted EBITDA/boe   Colombia   Chile   Brazil   Total
    4Q16   4Q15   4Q16   4Q15   4Q16   4Q15   4Q16   4Q15
Production (boepd)   17,535   15,510   3,523   4,006   2,535   3,546   23,593   23,062
Stock variation /RIKa   (878)   (1,346)   (151)   (355)   (206)   (268)   (1,235)   (1,969)
Sales Volume (boepd)   16,657   14,164   3,372   3,651   2,329   3,278   22,358   21,093
% Oil   100%   100%   39%   46%   1%   1%   80%   75%
($ per boe)                                
Realized Oil Price   30.4   23.2   41.4   33.5   54.7   46.9   32.3   24.3
Realized Gas Priceb   -   -   21.9   27.6   31.4   24.6   27.3   25.8
Earn-out   (1.4)   (1.0)   -   -   -   -   (1.1)   (0.7)
Combined Price   29.0   22.2   29.4   30.3   31.7   25.0   29.3   23.5
Operating Costs   (6.1)   (9.0)   (18.0)   (17.5)   (8.0)   (5.7)   (8.1)   (9.9)
Royalties in cash   (1.9)   (1.2)   (1.2)   (1.2)   (2.6)   (2.5)   (1.9)   (1.4)
Selling & Other Expenses   0.2   (3.1)   (1.0)   (0.4)   -   0.2   (0.3)   (1.0)
Operating Netback   21.1   8.9   9.2   11.2   21.0   17.0   19.2   11.2
G&A, G&G                           (6.1)   (5.7)
Adjusted EBITDA/boe                           13.1   5.5
a)   RIK (Royalties in Kind). Includes royalties paid in kind in Colombia for approximately 718 bopd in 4Q2016 and 776 bopd in 4Q2015. No royalties were paid in kind in Chile and Brazil.
b) Conversion rate of $mcf/$boe=1/6.

Depreciation: Consolidated depreciation charges decreased by 46% to $16.9 million in 4Q2016, compared to $31.2 million in 4Q2015, mainly due to lower depreciation cost per boe, partially offset by increased production levels. Decreased depreciation cost per boe in Colombia results from drilling success and increased reserves, while in Chile, it is mostly related to impairment charges recognized in 4Q2015. Depreciation cost per boe decreased by 49% to $8.2 per boe.

Write-off of Unsuccessful Efforts: Consolidated write-off of unsuccessful efforts amounted to $17.7 million in 4Q2016, compared to $26.4 million in 4Q2015. Amounts recorded in 4Q2016 and 4Q2015 correspond to non-cash charges from seismic and exploratory costs previously capitalized in Tierra del Fuego Blocks in Chile (incurred in prior years).

Impairment of Non-Financial Assets: Consolidated non-cash impairment of non-financial assets amounted to $5.7 million gain in 4Q2016 ($5.7 million in Colombia) compared to $149.6 million loss in 4Q2015 ($104.5 million recorded in Chile and $45.1 million in Colombia). Gains recorded in 4Q2016 result from an improved oil price environment.

Other expenses: Other operating non-recurrent charges amounted to a $0.9 million loss in 4Q2016, compared to a $1.1 million loss in 4Q2015.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Financial Costs: Net financial costs decreased by 7% to $8.9 million in 4Q2016, compared to $9.6 in 4Q2015, mainly consisting of lower bank charges and higher interest received.

Foreign Exchange: Net foreign exchange charges amounted to a $1.4 million loss in 4Q2016 compared to a $10.9 million gain in 4Q2015. Exchange differences are mainly generated from net devaluation and appreciation in the Brazilian Real 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 losses amounted to $9.7 million in 4Q2016 as compared to $2.0 million in 4Q2015, in line with lower losses before taxes in 4Q2016 as compared to 4Q2015.

Net Income: Loss for the period amounted to $26.0 million in 4Q2016 compared to $201.5 million in 4Q2015.

BALANCE SHEET

Cash and Cash Equivalents: Cash and cash equivalents totaled $73.6 million as of December 31, 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 $39.3 million, (ii) cash used in financing activities of $51.1 million (made up of principal payments of $22.6 million primarily related to the Itau Loan plus interest payments), and (iii) cash generated from operating activities that amounted to $82.9 million.

The table below shows a reconciliation of cash and cash equivalents as of September 30, 2016 and December 31, 2016.

     
($ million)    
Cash + Cash Equivalents – September 30, 2016   63.6
Cash from Operating activities   28.0
Cash used in Investing activities (15.1)
Cash used in Financing activities (1.7)
Currency translation effect   (1.2)
Cash + Cash Equivalents – December 31, 2016   73.6

Prepayment Facility and Credit Lines Available: As of December 31, 2016, the Company has in place an offtake and prepayment agreement with Trafigura of $75 million (with $20 million drawn) and approximately $31 million in uncommitted credit lines.

Financial Debt: Total financial debt (net of debt issuance costs) amounted to $358.7 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 $49.8 million.

FINANCIAL RATIOSa

($ million)        
At period-end   Financial Debt   Cash Position  

Gross Debt /
LTM Adj.
EBITDA

 

Net Debtb/
LTM Adj.
EBITDA

  Interest

Coverage

         
3Q2015 364.6 90.4 4.0x 3.0x 2.9x
4Q2015 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 63.6 5.7x 4.7x 2.0x
4Q2016  

358.7

  73.6   4.6x   3.6x   2.7x
a)   Based on trailing 12 month financial results.
b) Included for informational purposes only. Not included in the 2020 Bond Indenture.

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 December 31, 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

         
Colombia   4Q2016   4Q2015

Net Revenues ($ million)

 

44.4

  27.7
Production and Operating Costsa ($ million) -12.5 -13.4
Adjusted EBITDA ($ million) 26.5 9.2
Capital Expendituresb ($ million) 11.5 2.6
         
Chile   4Q2016   4Q2015
Net Oil Revenues ($ million) 5.0 5.1
Net Gas Revenues ($ million) 4.2 5.0
Net Revenues ($ million) 9.1 10.2
Production and Operating Costsa ($ million) -6.0 -6.3
Adjusted EBITDA ($ million) 0.6 1.0
Capital Expendituresb ($ million) 1.0 3.3
         
Brazil   4Q2016   4Q2015
Net Oil Revenues ($ million) 0.2 0.2
Net Gas Revenues ($ million) 6.6 7.3
Net Revenues ($ million) 6.8 7.5
Production and Operating Costsa ($ million) -2.3 -2.5
Adjusted EBITDA ($ million) 3.3 4.1
Capital Expendituresb ($ million) 2.0 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
       

CONSOLIDATED STATEMENT OF INCOME

 
(In millions of $) 4Q2016   4Q2015   FY2016   FY2015

NET REVENUES

Sale of crude oil 49.3 33.1 145.2 162.6
Sale of gas 11.0 12.3 47.5 47.1
TOTAL NET REVENUES 60.3 45.4 192.7 209.7
Commodity Risk Management Contracts -2.6 0.0 -2.6 0.0
Production and operating costs -20.8 -22.2 -67.2 -86.7

Geological and Geophysical expenses (G&G)

-2.7

-4.3

-10.3 -13.8
Administrative expenses (G&A) -10.0 -10.2 -34.2 -37.5
Selling expenses -0.6 -1.4 -4.2 -5.2
Depreciation -16.9 -31.2 -75.8 -105.6
Write-off of unsuccessful efforts -17.7 -26.4 -31.4 -30.1

Impairment for non-financial assets

5.7 -149.6 5.7 -149.6
Other operating -0.9 -1.1 -1.3 -13.7
OPERATING PROFIT (LOSS) -6.1 -200.9 -24.6 -232.5
 
Financial costs, net -8.9 -9.6 -34.1 -35.7
Foreign Exchange Gain (Loss) -1.4 10.9 13.9 -33.5
PROFIT (LOSS) BEFORE INCOME TAX -16.3 -199.5 -48.8 -301.6
 
Income tax -9.7 -2.0 -11.8 17.1
PROFIT (LOSS) -26.0 -201.5 -60.6 -284.6
Non-controlling interest -5.6 -43.8 -11.6 -50.5
ATTRIBUTABLE TO OWNERS OF GEOPARK -20.4 -157.6 -49.1 -234.0
 

SUMMARIZED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

 
(In millions of $)   Dec '16   Dec '15
 
Non Current Assets
Property, Plant and Equipment 473.6 522.6
Other Non Current Assets 45.7 49.4
Total Non Current Assets 519.3 572.0
 
Current Assets
Inventories 3.5 4.3
Trade Receivables 18.4 13.5
Other Current Assets 25.7 31.3
Cash at bank and in hand 73.6 82.7
Total Current Assets 121.2 131.8
 
Total Assets 640.5 703.8
 
Equity
Equity attributable to owners of GeoPark 105.8 146.7
Non-controlling interest 35.8 53.5
Total Equity 141.6 200.2
 
Non Current Liabilities
Borrowings 319.4 343.2
Other Non Current Liabilities 80.0 79.0
Total Non Current Liabilities 399.4 422.2
 
Current Liabilities
Borrowings 39.3 35.4
Other Current Liabilities 60.2 46.0
Total Current Liabilities 99.5 81.4

Total Liabilities

498.9 503.6
Total Liabilities and Equity 640.5 703.8
 

SUMMARIZED CONSOLIDATED STATEMENT OF CASH FLOWS

 
(In millions of $)   Dec '16   Dec '15
 
Cash Flows from Operating Activities 82.9 25.9
Cash Flows used in Investing Activities -39.3 -48.8
Cash Flows used in Financing Activities -51.1 -18.0
Net Change -7.6 -41.0
 

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

 
2016 (In millions of $)   Colombia   Chile   Brazil   Other   Total
Adjusted EBITDA 66.9   5.1   17.5   -11.2   78.3
Depreciation -31.1 -31.3 -13.0 -0.3 -75.8
Write-offs unsuccessful efforts -7.4 -19.4 -4.6 - -31.4

Impairment

5.7 - - - 5.7
Commodity Risk Management Contracts -3.1 - - - -3.1
Share Based Payments and Other   0.5   0.6   -0.5   -3.0   -2.4
OPERATING PROFIT (LOSS)   31.5   -45   -0.6   -14.5   -28.6
Financial costs, net -34.1
Foreign Exchange charges, net                   13.9
PROFIT (LOSS) BEFORE INCOME TAX -48.8
 
2015 (In millions of $) Colombia   Chile   Brazil   Other   Total
Adjusted EBITDA 66.7 -0.2 20.5 -13.2 73.8
Depreciation -52.4 -39.2 -13.6 -0.3 -105.6
Write-offs unsuccessful efforts -4.3 -25.8 - - -30.1
Impairment -45.1 -104.5 - - -149.6
Share Based Payments and Other   -2.1   -10.6   -0.3   -8.1   -21.1
OPERATING PROFIT (LOSS)   -37.2   -180.3   6.6   -21.6   -232.5
Financial costs, net -35.7
Foreign Exchange charges, net                   -33.5
PROFIT (LOSS) BEFORE INCOME TAX -301.6


CONFERENCE CALL INFORMATION

GeoPark will host its Fourth Quarter 2016 Financial Results conference call and webcast on Wednesday, March 8 2017, 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 4Q2016, 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: 66557648

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, unrealized result on commodity risk management contracts 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
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
 
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
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.

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 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, unrealized result 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.

Contacts

INVESTORS:
GeoPark Limited
Santiago, Chile
Stacy Steimel, +56 (2) 2242-9600
Shareholder Value Director
ssteimel@geo-park.com
or
GeoPark Limited
Buenos Aires, Argentina
Dolores Santamarina, +54 (11) 4312-9400
Investor Manager
dsantamarina@geo-park.com
or
MEDIA:
Sard Verbinnen & Co
New York, USA
Jared Levy, +1 (212) 687-8080
jlevy@sardverb.com
or
Sard Verbinnen & Co
New York, USA
Kelsey Markovich, +1 (212) 687-8080
kmarkovich@sardverb.com

Contacts

INVESTORS:
GeoPark Limited
Santiago, Chile
Stacy Steimel, +56 (2) 2242-9600
Shareholder Value Director
ssteimel@geo-park.com
or
GeoPark Limited
Buenos Aires, Argentina
Dolores Santamarina, +54 (11) 4312-9400
Investor Manager
dsantamarina@geo-park.com
or
MEDIA:
Sard Verbinnen & Co
New York, USA
Jared Levy, +1 (212) 687-8080
jlevy@sardverb.com
or
Sard Verbinnen & Co
New York, USA
Kelsey Markovich, +1 (212) 687-8080
kmarkovich@sardverb.com