GeoPark Reports Results for the Fourth Quarter and Full Year Ended December 31, 2017

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, Peru,
Argentina, Brazil, and Chile reports its consolidated financial results
for the three-month period ended December 31, 2017 (“Fourth Quarter” or
“4Q2017”), and its audited annual results for 2017.

A conference call to discuss 4Q2017 Financial Results will be held on
March 8, 2018 at 10:00 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. 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, 2017 and 2016
available on the Company’s website.

FOURTH QUARTER AND FULL YEAR 2017 HIGHLIGHTS

Record Oil and Gas Production

• Consolidated production up 30% to 30,654 boepd with current production
  of 33,000 boepd
• Colombia production up 39% to 24,378 boepd
• Annual average production up 23% to 27,586 boepd

Record Oil and Gas Reserves

• Certified consolidated proven (1P) reserves of 97 million boe
• Certified consolidated proven and probable (2P) reserves of 159.2
  million boe

Record Oil and Gas Asset Valuation – Total and Per Share

• Certified 1P NPV10 up 38% to $1.5 billion (equivalent to net debt
  adjusted NPV10 of $18.3 per share)
• Certified 2P NPV10 up 21% to $2.3 billion (equivalent to net debt
  adjusted NPV10 of $29.2 per share)
• Colombia 2P NPV10 up 38% to $1.4 billion (equivalent to net debt
  adjusted NPV10 of $15.8 per share)

Record Capital Investment and Cost Efficiencies

• Finding and development costs: Consolidated 2P of $4.0/boe / Colombia
  2P of $2.8/boe
• Full year 2017 operating costs of $7.3 per boe / Colombia $5.6 per boe
  / Llanos 34 $4.3 per boe
• Full year 2017 operating netback/capital expenditure ratio of 2.2x
• Capital investment program of $105.6 million in 2017 generated $404
  million in 2P NPV10

Record Cash Flow/Adjusted EBITDA Growth

• Adjusted EBITDA more than doubled - up 105% to $55.2 million / full
  year up 124% to $175.8 million
• Operating netback up 77% to $69.8 million / full year up 87% to $228.3
  million
• Full year cash flow from operating activities up 72% to $142.2 million
• Net loss reduced to $3.4 million / full year net loss of $17.8 million

Strengthened Balance Sheet and Credit Rating

• Cash in hand of $134.8 million
• Net debt to Adjusted EBITDA ratio decreased from 3.6x to 1.7x in 4Q2017
• 2024 new bond issued ($425 million at 6.5%), with longer maturities
  and lower cost, oversubscribed by four times by high-quality investors
• S&P upgraded GeoPark’s long-term corporate credit rating to B+ with a
  stable outlook

New Acreage/Projects Acquired and New Strategic Acquisition
Partnership Announced

• Colombia: Tiple and Zamuro high-impact exploration acreage acquired
  adjacent to Llanos 34 block
• Argentina: low-cost, cash flow-producing acquisition in the prolific
  Neuquen basin with production, development, exploration and
  unconventional opportunities
• ONGC Videsh + GeoPark strategic Latin American acquisition partnership

James F. Park, Chief Executive Officer of GeoPark, said: “Our team has
GeoPark firing on all cylinders. Through good science and engineering,
we found and produced more oil and gas. Through innovation and
efficiencies, we reduced our capital and operating costs. Through
organic cash flows, we self-funded our work and investment program.
Through effective capital allocation, every dollar of new investment
created multiples of net present value. Through engagement with our
neighbors and conscientious operations, we operated safely, cleanly and
without interruption. Through regional knowledge and scouting, we
acquired new high-impact acreage and projects. Through a rewarding and
motivating workplace, we were able to train and attract talented people
to continue to build our capabilities for the future. Through efforts to
more widely share our performance story, we were the number one
performing E&P stock on the NYSE. Our team now has a proven 15-year
track record of continuous growth, but we feel we are just getting
warmed up for the big opportunities coming our way.”

CONSOLIDATED OPERATING PERFORMANCE
Key performance indicators:
Key Indicators		4Q2017		3Q2017		4Q2016		FY2017		FY2016
Oil productiona (bopd)		25,341		23,237		18,798		22,761		16,955
Gas production (mcfpd)		31,876		30,528		28,770		28,950		32,634
Average net production (boepd)		30,654		28,325		23,593		27,586		22,394
Brent oil price ($ per bbl)		61.5		52.1		51.1		54.8		45.2
Combined price ($ per boe)		39.7		33.0		29.3		34.6		25.2
⁻ Oil ($ per bbl)		43.0		34.6		32.3		36.6		25.6
⁻ Gas ($ per mcf)		5.2		5.3		4.6		5.3		4.5
Sale of crude oil ($ million)		92.2		68.4		49.3		279.1		145.2
Sale of gas ($ million)		14.1		13.6		11.0		51.0		47.5
Revenue ($ million)		106.3		81.9		60.3		330.1		192.7
Commodity Risk Management Contracts ($ million)		-18.4		-8.3		-2.6		-15.4		-2.6
Production & Operating Costsb ($ million)		-30.5		-25.7		-20.8		-99.0		-67.2
G&G, G&Ac and Selling Expenses ($ million)		-14.8		-12.0		-13.2		-50.9		-48.7
Adjusted EBITDA ($ million)		55.2		44.6		27.0		175.8		78.3
Adjusted EBITDA ($ per boe)		20.6		18.0		13.1		18.4		10.2
Operating Netback ($ per boe)		26.1		23.2		19.2		23.9		15.9
Profit (loss) ($ million)		-3.4		-19.1		-26.0		-17.8		-60.6
Capital Expenditures ($ million)		25.3		30.9		15.1		105.6		39.3
Cash and cash equivalents ($ million)		134.8		135.2		73.6		134.8		73.6
Short-term financial debt ($ million)		7.7		1.9		39.3		7.7		39.3
Long-term financial debt ($ million)		418.5		418.5		319.4		418.5		319.4
Net debt ($ million)		291.4		285.2		285.1		291.4		285.1

a)		Includes government royalties paid in-kind in Colombia for approximately 881, 774 and 718 bopd in 4Q2017, 3Q2017 and 4Q2016 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 $0.7, $0.8, $0.5, $3.1 and $1.8 million for 4Q2017, 3Q2017, 4Q2016, FY2017 and FY2016, respectively, of (non-cash) share-based payments that are excluded from the adjusted EBITDA calculation.

Production: Significant oil production growth of 39% in Colombia
increased average consolidated oil and gas production to 30,654 boepd in
4Q2017 from 23,593 boepd in 4Q2016. The increase was mainly attributed
to new oil production from the Tigana/Jacana oil fields in Llanos 34
block in Colombia. On a consolidated basis, gas production increased by
11% compared to 4Q2016, primarily attributed to increased industrial
demand in Brazil.

For further detail, please refer to 4Q2017 Operational Update published
on January 10, 2018.

Reference and Realized Oil Prices: Brent crude oil price averaged
$61.5 per bbl during 4Q2017, and the consolidated realized oil sales
price averaged $43.0 per bbl in 4Q2017, representing a 24% increase from
$34.6 per bbl in 3Q2017 and a 38% increase from $31.2 per bbl in 4Q2016.
Differences between reference and realized prices are a result of
commercial and transportation discounts as well as the Vasconia price
differential in Colombia, which averaged $4.0 per bbl in 4Q2017 from
$2.8 per bbl in 3Q2017 and $5.7 per bbl in 4Q2016. Commercial and
transportation discounts in Colombia were reduced to $14.9 per bbl in
4Q2017 from $15.2 per bbl in 3Q2017 and $15.0 per bbl in 4Q2016.

Company efforts are currently underway to continue improving realized
oil prices, including negotiation of existing conditions with off-takers
plus construction of a flowline and related facilities in Llanos 34
block, expected to continue improving current commercial and
transportation discounts.

The following table provides a breakdown of reference and net realized
oil prices in Colombia and Chile in 4Q2017:

4Q2017 - Realized Oil Prices ($ per bbl)		Colombia		Chile
Brent oil price		61.5		61.5
Vasconia differential		(4.0)		-
Commercial and transportation discounts		(14.9)		(8.4)
Realized oil price		42.6		53.1
Weight on Oil Sales Mix		96%		4%

Revenue: Higher oil and gas production and pricing drove total
consolidated revenues up by 76% to $106.3 million in 4Q2017, compared to
$60.3 million in 4Q2016.

Sales of crude oil: Consolidated oil
revenues increased by 87% to $92.2 million in 4Q2017, driven by a 35%
increase in oil sales volumes and a 38% increase in realized oil prices.
Oil revenues represented 87% of total revenues compared to 82% in 4Q2016.

• Colombia: In 4Q2017, oil revenues increased by 98% to $87.5 million
  mainly due to increased sales volumes and higher realized prices. Oil
  sales volumes increased by 40% to 23,283 bopd. Realized oil prices
  also increased by 40% to $42.6 per bbl, in line with higher Brent
  prices and a lower Vasconia discount. Colombia earn-out payments
  (deducted from Colombia oil revenues) increased to $3.7 million in
  4Q2017, compared to $2.3 million in 4Q2016, in line with increased
  production and higher oil revenues.
• Chile: In 4Q2017, oil revenues decreased by 11% to $4.4 million due to
  lower sales volumes partially offset by higher realized prices. Oil
  sales volumes decreased by 31% to 902 bopd and realized oil prices
  increased by 28% to $53.1 per barrel, in line with higher Brent prices.

Sales of gas: Consolidated gas revenues
increased by 28% to $14.1 million in 4Q2017 compared to $11.0 million in
4Q2016 due to 15% higher realized gas prices and 11% higher gas sales
volumes.

• Chile: In 4Q2017, gas revenues increased by 6% to $4.4 million mainly
  due to higher gas prices, partially offset by lower sales volumes. Gas
  prices increased by 24% to $4.5 per mcf ($27.1 per boe) in 4Q2017, due
  to increased methanol prices. Gas sales volumes decreased by 15% to
  10,630 mcfpd (1,772 boepd).
• Brazil: In 4Q2017, gas revenues increased by 42% to $9.4 million, due
  to both higher realized prices and sales volumes. Gas prices, net of
  taxes, increased by 8% to $5.7 per mcf ($34.0 per boe) due to the
  annual gas price inflation adjustment of approximately 7%, effective
  January 2017. Gas sales volumes increased by 31% to 18,000 mcfpd
  (3,000 boepd), primarily due to higher gas consumption by Brazilian
  industrial users.

Commodity risk management contracts: Consolidated commodity risk
management contracts registered a realized loss of $5.8 million in
4Q2017, totaling realized losses of $2.1 million in full year 2017 ($3.8
million cash gains were recorded and cashed-in during the first nine
months of 2017). Unrealized cash losses amounted to $12.6 million in
4Q2017 compared to $3.1 million loss in 4Q2016 resulting from the
significant increase in forward Brent oil price curve. The company uses
risk management contracts to minimize the impact of oil price
fluctuations on the Company´s self-funded work program.

Production and operating costs^[1]:
Consolidated operating costs per barrel decreased by 9% to $7.3 per boe
in 4Q2017 from $8.1 per boe in 4Q2016. Following the 30% increase in oil
and gas sales volumes, total operating costs increased by $3.0 million
to $19.6 million. Consolidated royalties increased by $6.8 million to
$10.7 million in 4Q2017, mainly as the Jacana oil field in the Llanos 34
block accumulated more than five million barrels of production that
triggered Colombia’s “high price” royalty scheme beginning in 2Q2017,
and to a lesser extent due to increased volumes and higher realized
prices.

Below is a breakdown of production and operating costs by country:

• Colombia: Operating costs per boe remained flat at $6.1 per boe in
  both 4Q2017 and 4Q2016, due to:
  • Significant increase in volumes sold, 40% compared to a year
    earlier, that increased overall operating costs by 40% to $13.1
    million in 4Q2017 from $9.3 million in 4Q2016,
  • Incremental costs related to the reopening of mature oil fields
    temporarily closed in 4Q2016 which have higher operating costs per
    barrel compared to Llanos 34 block.
• Chile: Operating costs decreased by 6% to $5.2 million in 4Q2017 from
  $5.6 million in 4Q2016 mainly due to lower volumes sold (-21%). As a
  result of the lower volumes, operating costs per boe increased by 18%
  to $21.3.
• Brazil: Operating costs decreased by 45% to $1.0 million in 4Q2017
  from $1.7 million in 4Q2016, mainly due to a one-time recovery of
  maintenance costs in Manati that were incurred in previous quarters.
  Operating costs per boe decreased to $3.4 per boe from $8.0 in 4Q2016.

Selling expenses: Consolidated selling expenses decreased to $0.3
million in 4Q2017 compared to $0.6 million in 4Q2016.

Administrative, Geological and Geophysical expenses: Consolidated
G&A and G&G expenses increased by 15% to $14.5 million in 4Q2017
compared to $12.6 million in 4Q2016 mainly due to higher staff costs
resulting from an increased scale of operations. Consolidated G&A and
G&G costs per boe decreased by 13% to $5.5 per boe in 4Q2017 (vs. $6.1
per boe in 4Q2016).

Adjusted EBITDA: Consolidated adjusted EBITDA of $55.2 million
was more than two times higher than the $27.0 million in 4Q2016. That is
the equivalent of $20.6 per barrel and was driven by the combination of
increased production and higher realized oil and gas prices.

• Colombia: Adjusted EBITDA of $51.6 million in 4Q2017 (+95% vs. 4Q2016)
• Chile: Adjusted EBITDA of $1.1 million in 4Q2017 (+75% vs. 4Q2016)
• Brazil: Adjusted EBITDA of $7.2 million in 4Q2017 (+116% vs. 4Q2016)
• Corporate, Argentina and Peru: Adjusted EBITDA of negative $4.7
  million in 4Q2017

The table below shows production, volumes sold and breakdown of the most
significant components of adjusted EBITDA for 4Q2017 and 4Q2016, on a
per country and per barrel basis:

Adjusted EBITDA/boe		Colombia				Chile				Brazil				Total
		4Q17		4Q16		4Q17		4Q16		4Q17		4Q16		4Q17c		4Q16
Production (boepd)		24,378		17,535		2,932		3,523		3,328		2,535		30,654		23,593
Stock variation /RIKa		(1,004)		(878)		(258)		(151)		(285)		(206)		(1,593)		(1,235)
Sales volume (boepd)		23,374		16,657		2,674		3,372		3,043		2,329		29,091		22,358
% Oil		99.6%		100%		34%		39%		1%		1%		83%		80%
($ per boe)
Realized oil price		42.6		30.4		53.1		41.4		68.0		54.7		43.0		32.3
Realized gas priceb		30.8		-		27.1		21.9		34.0		31.4		31.4		27.3
Earn-out		(1.8)		(1.4)		-		-		-		-		(1.4)		(1.1)
Combined Price		40.8		29.0		35.9		29.4		34.5		31.7		39.7		29.3
Realized Commodity Risk Management Contracts		(2.7)		-		-		-		-		-		(2.2)		-
Operating costs		(6.1)		(6.1)		(21.3)		(18.0)		(3.4)		(8.0)		(7.3)		(8.1)
Royalties in cash		(4.4)		(1.9)		(1.4)		(1.2)		(3.3)		(2.6)		(4.0)		(1.9)
Selling & other expenses		0.0		0.2		(0.7)		(1.0)		-		-		(0.1)		(0.3)
Operating Netback/boe		27.6		21.1		12.4		9.2		27.8		21.0		26.1		19.2
G&A, G&G														(5.5)		(6.1)
Adjusted EBITDA/boe														20.6		13.1

a)		RIK (Royalties in Kind). Includes royalties paid in kind in Colombia for approximately 881 and 718 bopd in 4Q2017 and 4Q2016, respectively. No royalties were paid in kind in Chile and Brazil
b)		Conversion rate of mcf/boe=1/6
c)		Total amount includes 16 bopd of oil production from CN-V block in Argentina

Depreciation: Consolidated depreciation increased by 17% to $19.8
million in 4Q2017, compared to $16.9 million in 4Q2016, due to higher
volumes sold. On a per barrel basis, however, depreciation costs were
lower given drilling successes and increased reserves. Depreciation
costs per boe decreased by 10% to $7.4 per boe.

Write-off of unsuccessful exploration efforts: Consolidated
write-off of unsuccessful exploration efforts was $1.1 million in
4Q2017, compared to $17.7 million in 4Q2016. Amounts recorded in 4Q2017
mainly correspond to unsuccessful exploration efforts in non-operated
Sierra del Nevado and Puelen blocks in Argentina.

Impairment of Non-Financial Assets: Consolidated non-cash
impairment of non-financial assets was zero in 4Q2017 compared to a $5.7
million gain in 4Q2016 ($5.7 million non-cash recovery in Colombia).

Other expenses: Other operating expenses were $2.7 million in
4Q2017, compared to $0.9 million in 4Q2016.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Net financial expenses: Net financial costs decreased by 7% to
$8.2 million in 4Q2017, compared to $8.9 million in 4Q2016, mainly
resulting from lower bank charges and other financial results.

Foreign exchange: Net foreign exchange charges were a $3.6
million loss in 4Q2017 and $1.4 million loss in 4Q2016, mainly due to
the devaluation of the Brazilian Real over the US Dollar-denominated net
debt incurred at the local subsidiary level, where the Real is the
functional currency.

Income tax: Income taxes amounted to a $10.7 million in 4Q2017,
as compared to a $9.7 million in 4Q2016, in line with higher taxable
profits in 4Q2017.

Net income: Net losses amounted to $3.4 million in 4Q2017
compared to $26.0 million in 4Q2016. The net loss in 4Q2017 resulted
from unrealized hedge charges.

BALANCE SHEET

Cash and cash equivalents: Cash and cash equivalents totaled
$134.8 million as of December 31, 2017 compared to $73.6 million a year
earlier. The difference reflects cash generated from operating
activities of $142.2 million and cash from financing activities of $24.0
million, partially offset by cash used in investing activities of $105.6
million.

Cash generated from operating activities of $142.2 million is net of a
$15.6 million advance payment paid in December 2017 to Pluspetrol, as a
security deposit related to the recently announced acquisition of Aguada
Baguales, El Porvenir and Puesto Touquet blocks in Neuquen basin in
Argentina, which is expected to close in March 2018.

Cash from financing activities of $24.0 million includes net proceeds
from the issuance of 2024 Notes of $418.3 million, offset by: (i)
principal paid of $355.0 million related to the payment of 2020 Notes
and the prepayment of the Itau loan, (ii) cancellation costs of $12.3,
and (iii) interest payments of $27.7 million.

Cash used in investing activities of $105.6 million (76% allocated to
Colombia) includes capital expenditures related to development,
appraisal and exploration activities carried out in 2017 that allowed
GeoPark to increase its reserves with low finding and development costs
of $3.6/boe for 1P and $4.0/boe for 2P reserves (or $2.4/boe and
$2.8/boe for 1P and 2P, respectively in Colombia).

Financial debt: Total financial debt (net of issuance costs)
amounted to $426.2 million, including the $425 million 2024 Notes issued
in September 2017. Short-term debt amounted to $7.7 million as of
December 31, 2017.

FINANCIAL RATIOS^a

($ million)
At period-end		Financial Debt		Cash and Cash Equivalents		Net Debt		Net Debt/ LTM Adj. EBITDA		LTM Interest Coverage
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
4Q2017		426.2		134.8		291.4		1.7x		6.3x

a)		Based on trailing 12-month financial results.

Issuance of 2024 Notes: During September 2017, the Company
successfully placed $425 million notes (“2024 Notes”). 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 require the net debt to adjusted EBITDA ratio be lower
than 3.5 times and the adjusted EBITDA to interest ratio higher than 2
times until September 2019. 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.

COMMODITY RISK OIL MANAGEMENT CONTRACTS

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

Period		Type		Volume (bopd)		Contract terms ($ per bbl)
						Purchased Put		Sold Put		Sold Call
1Q2018		Zero cost collar		9,000		50.0-52.0		-		54.9-60.0
		Zero cost 3-way		2,000		52.0		42.0		59.5-59.6
		Zero cost 3-way		2,000		53.0		43.0		64.6
				Total: 13,000
2Q2018		Zero cost collar		5,000		52.0		-		58.3-60.0
		Zero cost 3-way		3,000		52.0		42.0		59.5-59.6
		Zero cost 3-way		2,000		53.0		43.0		64.6
				Total: 10,000
3Q2018		Zero cost 3-way		5,000		53.0		43.0		69.0
				Total: 5,000

For further details, please refer to Note 8 of GeoPark’s consolidated
financial statements for the year ended December 31, 2017, available on
the Company’s website.

SELECTED INFORMATION BY BUSINESS SEGMENT
(UNAUDITED)
Colombia		4Q2017		4Q2016
Sale of crude oil ($ million)		87.5		44.2
Sale of gas ($ million)		0.2		0.2
Revenue ($ million)		87.7		44.4
Production and Operating Costsa ($ million)		-22.6		-12.5
Adjusted EBITDA ($ million)		51.6		26.5
Capital Expendituresb ($ million)		19.4		11.5
Chile		4Q2017		4Q2016
Sale of crude oil ($ million)		4.4		5.0
Sale of gas ($ million)		4.4		4.2
Revenue ($ million)		8.8		9.1
Production and Operating Costsa ($ million)		-5.6		-6.0
Adjusted EBITDA ($ million)		1.1		0.6
Capital Expendituresb ($ million)		1.4		1.0
Brazil		4Q2017		4Q2016
Sale of crude oil ($ million)		0.3		0.2
Sale of gas ($ million)		9.4		6.6
Revenue ($ million)		9.7		6.8
Production and Operating Costsa ($ million)		-1.9		-2.3
Adjusted EBITDA ($ million)		7.2		3.3
Capital Expendituresb ($ million)		0.5		2.0

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
(QUARTERLY INFORMATION UNAUDITED)
(In millions of $)		4Q2017		4Q2016		FY2017		FY2016
REVENUE
Sale of crude oil		92.2		49.3		279.1		145.2
Sale of gas		14.1		11.0		51.0		47.5
TOTAL REVENUE		106.3		60.3		330.1		192.7
Commodity risk management contracts		-18.4		-2.6		-15.4		-2.6
Production and operating costs		-30.5		-20.8		-99.0		-67.2
Geological and geophysical expenses (G&G)		-3.9		-2.7		-7.7		-10.3
Administrative expenses (G&A)		-10.6		-10.0		-42.1		-34.2
Selling expenses		-0.3		-0.6		-1.1		-4.2
Depreciation		-19.8		-16.9		-74.9		-75.8
Write-off of unsuccessful exploration efforts		-1.1		-17.7		-5.8		-31.4
Impairment for non-financial assets		-		5.7		-		5.7
Other operating		-2.7		-0.9		-5.1		-1.3
OPERATING PROFIT (LOSS)		19.1		-6.1		79.0		-28.6
Financial costs, net		-8.2		-8.9		-51.5		-34.1
Foreign exchange gain (loss)		-3.6		-1.4		-2.2		13.9
PROFIT (LOSS) BEFORE INCOME TAX		7.3		-16.3		25.3		-48.8
Income tax		-10.7		-9.7		-43.1		-11.8
PROFIT (LOSS) FOR THE PERIOD		-3.4		-26.0		-17.8		-60.6
Non-controlling interest		1.1		-5.6		6.4		-11.6
ATTRIBUTABLE TO OWNERS OF GEOPARK		-4.5		-20.4		-24.2		-49.1

SUMMARIZED CONSOLIDATED STATEMENT OF FINANCIAL POSITION
(In millions of $)		Dec '17		Dec '16
		(Audited)		(Audited)
Non-Current Assets
Property, plant and equipment		517.4		473.6
Other non-current assets		53.8		45.7
Total Non-Current Assets		571.2		519.3
Current Assets
Inventories		5.7		3.5
Trade receivables		19.5		18.4
Other current assets		54.9		25.7
Cash at bank and in hand		134.8		73.6
Total Current Assets		215.0		121.2
Total Assets		786.2		640.5
Equity
Equity attributable to owners of GeoPark		84.9		105.8
Non-controlling interest		41.9		35.8
Total Equity		126.8		141.6
Non-Current Liabilities
Borrowings		418.5		319.4
Other non-current liabilities		74.5		80.0
Total Non-Current Liabilities		493.0		399.4
Current Liabilities
Borrowings		7.7		39.3
Other current liabilities		158.6		60.2
Total Current Liabilities		166.3		99.5
Total Liabilities		659.3		498.9
Total Liabilities and Equity		786.2		640.5

SUMMARIZED CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions of $)		Dec '17		Dec '16
Cash flows from operating activities		142.2		82.9
Cash flows used in investing activities		-105.6		-39.3
Cash flows from (used) in financing activities		24.0		-51.1

RECONCILIATION OF ADJUSTED EBITDA TO PROFIT (LOSS) BEFORE INCOME TAX
2017 (In millions of $)		Colombia		Chile		Brazil		Other		Total
Adjusted EBITDA		168.3		4.1		20.2		-16.8		175.8
Depreciation		-40.0		-23.7		-10.8		-0.4		-74.9
Unrealized Commodity Risk Management Contracts		-13.3		-		-		-		-13.3
Impairment		-		-		-		-		-
Write-offs unsuccessful exploration efforts		-1.6		-0.5		-3.0		-0.7		-5.8
Share Based Payments/Other		2.9		0.4		-2.0		-4.1		-2.8
OPERATING PROFIT (LOSS)		116.3		-19.7		4.4		-22.0		79.0
Financial costs, net										-51.5
Foreign Exchange charges, net										-2.2
PROFIT (LOSS) BEFORE INCOME TAX										25.3
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
Unrealized Commodity Risk Management Contracts		-3.1		-		-		-		-3.1
Impairment		5.7		-		-		-		5.7
Write-offs unsuccessful exploration efforts		-7.4		-19.4		-4.6		-		-31.4
Share Based Payments/Other		0.5		0.6		-0.5		-3.0		-2.4
OPERATING PROFIT (LOSS)		31.5		-45.0		-0.6		-14.5		-28.6
Financial costs, net										-34.1
Foreign Exchange charges, net										13.9
PROFIT (LOSS) BEFORE INCOME TAX										-48.8

OTHER NEWS / RECENT EVENTS

2017 YEAR-END RESERVES SUMMARY

GeoPark engaged DeGolyer & MacNaughton (“D&M”) to carry out an
independent appraisal of reserves as of December 31, 2017, covering 100%
of the current assets in Colombia, Chile, Brazil, Peru and Argentina.

Following oil and gas production of 10.2 mmboe in 2017, D&M certified 2P
reserves of 159.2 mmboe at 2017 year-end, following a 261% Reserve
Replacement, with an NPV valuation of $2.3 billion.

• PDP Reserves: Net proven developed producing (PDP) reserves increased
  by 47% to 28.5 mmboe, with a PDP reserve replacement index (RRI) of
  189%. PDP NPV10 increased by 74% to $491 million.
• 1P Reserves: Net 1P reserves increased by 24% to 97.0 mmboe, with 1P
  reserve life index (RLI) of 9.5 years and a 1P RRI of 284%. 1P NPV10
  increased by 39% ($430 million) to $1.5 billion.
• 2P Reserves: Net 2P reserves increased by 11% to 159.2 mmboe, with a
  2P RLI of 15.6 years and a 2P RRI of 261%. 2P NPV10 increased by 21%
  ($404 million) to $2.3 billion.
• Finding and Development (F&D) costs for 2017 were $3.6 per boe for 1P
  reserves and $4.0 per boe for 2P reserves.
• Colombia: Net PDP reserves increased 89% to 21.6 mmboe, Net 1P
  reserves increased 64% to 66.1 mmboe and net 2P reserves increased 31%
  to 88.2 mmboe. F&D Costs were $2.4 per boe for 1P reserves and $2.8
  per boe for 2P reserves.

For further detail, please refer to 2017 Reserves Release published on
February 5, 2018.

CONFERENCE CALL INFORMATION

GeoPark will host its Fourth Quarter 2017 Financial Results conference
call and webcast on Thursday, March 8, 2018, at 10:00 a.m. Eastern
Standard Time.

Chief Executive Officer, James F. Park and Chief Financial Officer,
Andres Ocampo will discuss GeoPark's financial results for 4Q2017, 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: 6197567

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 2018 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.

^[1] Production and Operating Costs = Operating Costs plus
Royalties

View source version on businesswire.com: http://www.businesswire.com/news/home/20180307006454/en/

Source: Business Wire
(March 7, 2018 - 6:49 PM EST)

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