GeoPark Reports Third Quarter 2017 Results

Higher Production Doubles EBITDA, New Funding Raised and New Assets
Acquired

BOGOTA, Colombia–(BUSINESS WIRE)–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:

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:

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.

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

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

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:

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

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.

Contacts

INVESTORS:
GeoPark Limited
Santiago, Chile
Stacy
Steimel
Shareholder Value Director
ssteimel@geo-park.com
or
MEDIA:
Sard
Verbinnen & Co
New York, USA
Jared Levy, +1 212-687-8080
jlevy@sardverb.com
or
Kelsey
Markovich, +1 212-687-8080
kmarkovich@sardverb.com

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