GeoPark Reports First Quarter 2017 Results

GeoPark Limited (“GeoPark” or the “Company”) (NYSE: GPRK), a leading independent Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Chile, Brazil, Argentina, and Peru reports its consolidated financial results for the three-month period ended March 31, 2017 (“First Quarter” or “1Q2017”).

A conference call to discuss 1Q2017 Financial Results will be held on May 11, 2017 at 10:00 am Eastern Daylight 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 March 31, 2017, available on the Company’s website.

FIRST QUARTER 2017 HIGHLIGHTS

Operational:

Record oil and gas production

• Consolidated oil and gas production rose by 12% to a record 25,180 boepd
• Oil production increased by 25% to 20,487 bopd, representing 81% of total production
• Gas production declined by 24% to 28.2 mmcfpd
• Current production of 26,500 boepd

Exploration, appraisal and development drilling success

In Colombia, Llanos 34 Block (GeoPark operated with a 45% WI):

• Exploration: Chiricoca 1 well discovered in a new oil field and currently producing 950 bopd gross. Sinsonte 1 well testing western fault trend was unsuccessful and was plugged and abandoned. Jacamar 1 well currently being drilled
• Appraisal: Jacana 11 well completed, testing and currently producing 3,200 bopd and Jacana Sur 2 appraisal well waiting for completion and testing in the coming weeks
• Development: Tigana Sur 6 well completed, tested and currently producing 1,700 bopd gross. Jacana Sur 1 well drilled, completed and currently testing 900 bopd gross from Guadalupe formation and Jacana 7 well drilled, completed and currently testing at 1,175 bopd gross from Guadalupe formation. Jacana 8 well drilled and completed with testing planned during May

Financial:

Self-funding program drives financial performance

• Revenue increased 82% to $66.7 million
• Operating netbacks more than doubled to $24.0 per boe
• Adjusted EBITDA jumped over three times to $38.8 million or $19.0 per boe
• Cash flow from operations of $45.2 million almost doubled capex of $23.5 million
• Net income of $5.8 million

Balance sheet deleveraging and strengthening

• Financial debt repayment of $11.3 million during the quarter
• Gross debt to Adjusted EBITDA declined sharply from 5.3x to 3.2x
• Net debt to Adjusted EBITDA decreased from 4.3x to 2.6x
• Hedged 55-60% of 2Q2017 oil production at a Brent price floor of $50-$54/bbl
• Ended the quarter with $70.3 million in cash and cash equivalents

Strategic:

Four rigs currently drilling for oil and gas

• 8-10 new wells in Colombia, Chile and Argentina expected in 2Q2017
• In Colombia, further delineation and development of the Tigana/Jacana oil fields and new exploration prospects in Llanos 34 Block (Jacamar and Curucucu)
• In Chile, new gas prospects in Fell Block (GeoPark operated with 100% WI)
• In Argentina, new oil prospects in Neuquen Basin CN-V Block (GeoPark operated with 50% WI)
• 2017 production guidance of 26,500–27,500 boepd, on track with 4Q2017 exit production of 30,000+ boepd

New commercial agreements signed

• Long-term gas supply agreement in Chile extended to December 2026
• New Chilean crude oil sales agreement with ENAP

James F. Park, Chief Executive Officer of GeoPark, said: “Great people create great results. Our first quarter this year shows how our consistent oil and gas finding success and operational efficiencies are leading to tangible financial breakthrough. It demonstrates the growing prosperity underlying GeoPark’s performance and coming opportunities – and the proven quality of our team, assets and approach.”

CONSOLIDATED OPERATING PERFORMANCE

The table below sets forth key performance indicators for 1Q2017 compared to 4Q2016 and 1Q2016:

Key Indicators		1Q2017		4Q2016		1Q2016
Oil productiona (bopd)		20,487		18,798		16,347
Gas production (mcfpd)		28,152		28,770		37,009
Average net production (boepd)		25,180		23,593		22,518
Brent oil price ($ per bbl)		54.7		51.1		35.4
Combined price ($ per boe)		32.6		29.3		19.1
⁻ Oil ($ per bbl)		34.3		31.2		16.7
⁻ Gas ($ per mcf)		5.2		4.6		4.5
Sale of crude oil ($ million)		54.5		49.3		23.2
Sale of gas ($ million)		12.2		11.0		13.4
Revenue ($ million)		66.7		60.3		36.6
Commodity Risk Management Contracts ($ million)		5.4		-2.6		0.0
Production & Operating Costsb ($ million)		-17.6		-20.8		-13.0
G&G, G&Ac and Selling Expenses ($ million)		-10.2		-13.2		-12.5
Adjusted EBITDA ($ million)		38.8		27.0		11.6
Adjusted EBITDA ($ per boe)		19.0		13.1		6.0
Operating Netback ($ per boe)		24.0		19.2		11.0
Profit (loss) ($ million)		5.8		-26.0		-12.0
Capital Expenditures ($ million)		23.5		15.1		8.3
Cash and cash equivalents ($ million)		70.3		73.6		71.6
Short-term financial debt ($ million)		32.2		39.3		30.7
Long-term financial debt ($ million)		309.5		319.4		332.4

a)		Includes government royalties paid in kind in Colombia for approximately 608, 718 and 769 bopd in 1Q2017, 4Q2016 and 1Q2016 respectively. No royalties were paid in kind in Chile and Brazil.
b)		Production and Operating costs include operating costs and royalties paid in cash.
c)		G&A expenses include $0.8, $0.5 and $0.4 million for 1Q2017, 4Q2016 and 1Q2016, respectively, of (non-cash) share-based payments that are excluded from the Adjusted EBITDA calculation.

Production: Consolidated oil and gas production grew by 12% to a record 25,180 boepd in 1Q2017 compared to 22,518 boepd in 1Q2016. The increase was driven by Colombian oil production, partially offset by lower gas production in Chile and Brazil.

• Colombia: Average net oil production rose by 30% to 19,330 bopd in 1Q2017 compared to 14,871 bopd in 1Q2016 due to continued successful exploration drilling and development in the Llanos 34 Block.
• Chile: Average net oil and gas production decreased by 18% to 3,351 boepd in 1Q2017 compared to 4,061 boepd in 1Q2016 due to the natural decline of the fields with limited drilling activity since 2014, and no drilling activity during 1Q2017.
• Brazil: Average net oil and gas production declined by 30% to 2,499 boepd in 1Q2017 compared to 3,586 boepd in 1Q2016, primarily attributed to lower gas consumption by Brazilian industrial users.

The participation of oil in the production mix increased to 81% of total reported production in 1Q2017 (vs. 73% in 1Q2016) due to the successful drilling campaign in the Llanos 34 Block.

Recent Operational Activity: After the latest events announced in the 1Q2017 Operational Update, released on April 10, 2017, GeoPark continued its activities in the Llanos 34 Block in Colombia, as follows:

• Jacana Sur 1 development well, located approximately 1.7 km southwest of Jacana 6, was drilled to a total depth of 10,686 feet (approximately 135 feet up dip of the Jacana 6 well) and completed during the second week of May. A test conducted with an electric submersible pump in the Guadalupe formation resulted in a production rate of approximately 900 bopd of 16.3 degrees API, with a 1% water cut, through a choke of 32/64 mm and wellhead pressure of 78 pounds per square inch. Additional production history will be required to determine stabilized flow rates of the well. Surface facilities are in place and the well is already in production.
• Jacana 7 development well, located approximately 0.9 km northeast of Jacana 6, was drilled to a total depth of 11,519 feet (approximately 26 feet down dip of the Jacana 6 well) and completed during the second week of May. A test conducted with an electric submersible pump in the Guadalupe formation resulted in a production rate of approximately 1,175 bopd of 15.2 degrees API, with a 6% water cut, through a choke of 32/64 mm and wellhead pressure of 68 pounds per square inch. Additional production history will be required to determine stabilized flow rates of the well. Surface facilities are in place and the well is already in production.
• Jacana 8 development well, located approximately 0.8 km south of Jacana 1, was drilled to a total depth of 10,882 feet, with completion and testing expected during May. According to petrophysical logging information, the well encountered oil in both the Mirador and Guadalupe formations.
• Sinsonte 1 exploration well, located on a new fault trend to the west of Tigana/Jacana fault trend in Llanos 34 Block, was drilled to a total depth of 11,903 feet. According to petrophysical logging information, the well encountered reservoirs in both Guadalupe and Mirador formations, with no evidence of hydrocarbons/both reservoirs being water-bearing. Following these results: (i) the well was plugged and abandoned, and (ii) a decision was made to defer the drilling of Guaco 1 exploration well, replacing it with Tigana Sur 5 development well.
• Jacamar 1 exploration well, located on a new fault trend to the east of Tigana/Jacana fault trend in Llanos 34 Block, is currently being drilled.
• Jacana Sur 2 appraisal well waiting for completion and testing in the coming weeks.

Reference and Realized Oil Prices: Brent crude price averaged $54.7 per bbl during 1Q2017, while the consolidated realized oil sales price averaged $34.3 per bbl in 1Q2017, up 10% from $31.2 per bbl in 4Q2016 and an increase of 105% from $16.7 per bbl in 1Q2016. Differences between reference and realized prices are a result of commercial and transportation discounts and from the Vasconia differential in Colombia.

The table below provides a breakdown of reference and net realized oil prices in Colombia in 1Q2017:

1Q2017 - Realized Oil Prices ($ per bbl)		Colombia
Brent oil price		54.7
Vasconia differential		(5.2)
Commercial and transportation discounts		(15.2)
Realized oil price		34.3

Commercial discounts in Colombia 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).

Commodity Risk Management Contracts - Brent Oil Price: In 1Q2017 the Company recorded the following amounts related to Commodity Risk Management Contracts to mitigate the risk exposure to changes in the Brent oil price. Realized gains reflect cash settled transactions, while unrealized gains reflect non-cash changes between the contract values and the forward Brent oil curve.

1Q2017 – Commodity Risk Management Contracts		($ million)
Realized cash gain		0.2
Non-cash unrealized gain		5.2
Net gain		5.4

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

• For the period ending June 30, 2017, GeoPark guaranteed a minimum Brent price of $50 per bbl for 6,000 bopd through a zero-cost collar structure that includes a maximum price of $57 per bbl.
• For the period ending September 30, 2017, GeoPark secured a minimum Brent price of $53 per bbl for 6,000 bopd through a zero-cost collar structure that includes a maximum price of $61 per bbl.

Revenue: Consolidated revenues increased by 82% to $66.7 million in 1Q2017, compared to $36.6 million in 1Q2016, mainly driven by higher oil revenues partially offset by lower gas revenues.

Sale of crude oil: Consolidated oil revenues rose by 135% to $54.5 million in 1Q2017, driven mainly by a 105% increase in realized oil prices and a 17% increase in oil deliveries (compared to 1Q2016). Oil revenues represented 82% of total revenues compared to 63% in 1Q2016.

• Colombia: In 1Q2017, oil revenues increased by 189% to $56.6 million mainly due to higher realized prices and increased deliveries. Under the Trafigura agreement, sales occur at the wellhead, slightly reducing revenues with a corollary benefit on selling expenses compared to 1Q2016. Realized oil prices increased by 124% to $34.3 per bbl, in line with higher Brent prices and a lower differential to the Vasconia marker. Oil deliveries increased by 30% to 18,375 bopd.
  Colombian earn-out payments (deducted from Colombian oil revenues) increased to $2.4 million in 1Q2017, compared to $0.6 million in 1Q2016, in line with higher oil revenues and increased production.
• Chile: In 1Q2017, no oil revenues were recorded as the Company was negotiating a new sales agreement with ENAP that was signed in May 2017. As a result, Chilean oil production was recorded as Inventories at March 31, 2017, and subsequently delivered to ENAP in May 2017 at a realized price of $43.5 per bbl. Revenue recorded in May 2017 from the sale of crude oil inventories to ENAP amounted to $5.7 million. In 1Q2016, oil revenue amounted to $4.0 million, with realized oil prices of $29.8 per bbl and deliveries of 1,462 bopd.

Sale of gas: Consolidated gas revenues decreased by 9% to $12.2 million in 1Q2017 compared to $13.4 million in 1Q2016 due to lower gas deliveries in both Chile and Brazil.

• Chile: In 1Q2017, gas revenues decreased by 8% to $4.8 million mainly due to lower gas deliveries resulting from the natural decline of gas fields and limited drilling activity in 2016 and 2017. Gas prices remained flat at $4.4 per mcf ($26.5 per boe) in 1Q2017. Gas deliveries decreased by 8% to 12,182 mcfpd (2,030 boepd).
• Brazil: In 1Q2017, gas revenues decreased by 12% to $7.2 million, mainly due to lower gas deliveries partially offset by higher gas prices. Gas prices, net of taxes, increased by 29% to $5.9 per mcf ($35.4 per boe) due to the 20% appreciation of the local currency and the annual gas price inflation adjustment of 7% effective during 2017. Gas deliveries decreased by 31% and amounted to 13,545 mcfpd (2,258 boepd) due to lower industrial demand in the northeast of the country.

Production and Operating Costs¹: Consolidated production and operating costs increased by 35% to $17.6 million in 1Q2017, compared to $13.0 million in 1Q2016, due to higher royalties paid in cash ($2.9 million higher than 1Q2016) and increased operating costs ($1.6 million higher than 1Q2016), mainly due to higher sales volumes (up 7% compared to 1Q2016), and the appreciation of local currencies in Colombia and Brazil.

Breaking down production and operating costs into their constituent parts:

Royalties: Consolidated royalties paid in cash (reported in Production and Operating Costs) increased to $4.7 million in 1Q2017, compared to $1.8 million in 1Q2016, in line with increased production and higher oil prices.

Operating Costs: Consolidated operating costs (excluding royalties) increased by 14% to $12.8 million 1Q2017. Consolidated operating costs per boe slightly increased to $6.2 per boe in 1Q2017 from $5.8 per boe in 1Q2016:

• Colombia: Operating costs increased by 53% to $8.0 million in 1Q2017, mainly as a result of increased costs associated with higher production (oil deliveries rose by 30% compared to 1Q2016), the reopening of La Cuerva, a mature oil field, and the revaluation of local currency (approximately 10% compared to 1Q2016). La Cuerva oil field, with higher operating costs than Llanos 34 Block, was temporarily shut down in early 1Q2016 and reopened in 3Q2016, increasing average operating cost levels in Colombia. Operating costs per boe increased by 19% to $4.8 per boe.
• Chile: Operating costs decreased by 45% to $2.7 million in 1Q2017 due to lower oil deliveries (oil and gas deliveries declined by 45% compared to 1Q2016) as a result of increased oil inventory levels. Operating costs per boe decreased by 2% to $14.3 per boe.
• Brazil: Operating costs increased to $2.2 million in 1Q2017 from $1.2 million in 1Q2016, mainly resulting from the appreciation of the local currency (+20%) and non-recurrent maintenance costs in Manati, partially offset by lower deliveries. Operating costs per boe increased to $10.5 per boe.

Selling Expenses: Consolidated selling expenses decreased to $0.4 million in 1Q2017 compared to $2.7 million in 1Q2016 mainly as a result of lower selling expenses in Colombia. Selling expenses in Colombia declined by 96% to only $0.1 million due to the Trafigura offtake agreement as sales occur at the wellhead, and are recorded as a discount to the oil price. Chilean selling expenses remained steady at $0.2 million.

Administrative Expenses: Consolidated administrative expenses increased by 14% to $8.5 million in 1Q2017 compared to $7.5 million in 1Q2016.

Geological & Geophysical Expenses: Consolidated G&G expenses decreased by 49% to $1.2 million in 1Q2017, compared to $2.4 million in 1Q2016, mainly due to the allocation of higher amounts of these expenses to capitalized projects due to increased drilling activity levels.

Adjusted EBITDA: Consolidated Adjusted EBITDA² surged by 236% to $38.8 million, or $19.0 per boe, in 1Q2017 compared to $11.6 million, or $6.0 per boe, in 1Q2016, mainly driven by the combination of increased production levels and higher realized oil prices.

• Colombia: Adjusted EBITDA of $38.1 million in 1Q2017
• Chile: Adjusted EBITDA of $0.3 million in 1Q2017
• Brazil: Adjusted EBITDA of $3.8 million in 1Q2017
• Corporate, Argentina and Peru: Adjusted EBITDA of negative $3.3 million in 1Q2017

________________________
1		Production and Operating Costs = Operating Costs plus Royalties
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 1Q2017 and 1Q2016, on a per country and per boe basis:

Adjusted EBITDA/boe		Colombia				Chile				Brazil				Total
		1Q17		1Q16		1Q17		1Q16		1Q17		1Q16		1Q17		1Q16
Production (boepd)		19,330		14,871		3,351		4,061		2,499		3,586		25,180		22,518
Stock variation /RIKa		(955)		(783)		(1,314)		(424)		(204)		(289)		(2,473)		(1,496)
Sales volume (boepd)		18,375		14,088		2,037		3,637		2,295		3,297		22,707		21,022
% Oil		100%		100%		0%		40%		2%		1%		81%		74%
($ per boe)
Realized oil price		34.3		15.3		-		29.8		59.5		43.0		34.3		16.7
Realized gas priceb		-		-		26.5		26.5		35.4		27.5		31.6		27.1
Earn-out		(1.4)		(0.4)		-		-		-		-		(1.1)		(0.3)
Combined Price		32.9		14.9		26.5		27.8		35.8		27.8		32.6		19.1
Operating costs		(4.8)		(4.0)		(14.3)		(14.6)		(10.5)		(4.0)		(6.2)		(5.8)
Royalties in cash		(2.4)		(0.5)		(0.8)		(1.1)		(3.1)		(2.5)		(2.3)		(0.9)
Selling & other expenses		0.1		(2.1)		(1.1)		(0.6)		-		(0.1)		(0.1)		(1.4)
Operating Netback/boe		25.8		8.3		10.4		11.5		22.2		21.2		24.0		11.0
G&A, G&G														(5.0)		(5.0)
Adjusted EBITDA/boe														19.0		6.0

a)		RIK (Royalties in Kind). Includes royalties paid in kind in Colombia for approximately 608, 718 and 769 bopd in 1Q2017, 4Q2016 and 1Q2016 respectively. No royalties were paid in kind in Chile and Brazil.
b)		Conversion rate of $mcf/$boe=1/6.

Depreciation: Consolidated depreciation charges decreased by 27% to $15.7 million in 1Q2017, compared to $21.5 million in 1Q2016, mainly due to lower depreciation costs per boe in Colombia as a result of the combination of drilling success and increased reserves, partially offset by increased production. Depreciation costs per boe declined by 32% to $7.7 per boe.

Other Expenses: Other operating expenses decreased 30% to $0.5 million in 1Q2017, compared to $0.7 million in 1Q2016.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Financial Expenses: Net financial costs slightly increased to $9.2 million in 1Q2017, compared to $9.0 million in 1Q2016.

Foreign Exchange: Net foreign exchange charges amounted to a $2.9 million gain in 1Q2017 compared to a $7.5 million gain in 1Q2016, mainly due to the lower appreciation of the Brazilian Real. Exchange differences are mainly generated from the appreciation of the Brazilian Real over the US Dollar-denominated debt incurred at the local subsidiary level, where the functional currency is the Brazilian Real.

Income Tax: Income tax expense amounted to $16.0 million in 1Q2017, due to higher profits in Colombia, as compared to a $0.7 million recovery in 1Q2016.

Net Income: The Company recorded net income for the first time in nine quarters. Net income for the period amounted to $5.8 million in 1Q2017 compared to a $12.0 million loss in 1Q2016, mainly resulting from higher revenue and lower G&G, selling and depreciation expenses, partially offset by higher income taxes.

BALANCE SHEET

Cash and Cash Equivalents: Cash and cash equivalents totaled $70.3 million as of March 31, 2017. Year-end 2016 cash and cash equivalents amounted to $73.6 million. The difference reflects cash used in investing activities of $23.5 million, cash used in financing activities of $23.8 million (made up of principal payments of $11.3 million primarily related to the Itau loan plus interest payments), and cash generated from operating activities of $45.2 million.

Prepayment Facility and Credit Lines Available: As of March 31, 2017, the Company has in place an offtake and prepayment agreement with Trafigura of up to $100 million (with $20.0 million drawn, of which $2.5 million were cancelled in 1Q2017) and approximately $31 million in uncommitted credit lines.

Financial Debt: Total financial debt (net of issuance costs) amounted to $341.7 million, including the $300 million 2020 bond and the Itau loan (originally incurred for the acquisition of an interest in the Brazilian Manati Field) of $39.2 million.

FINANCIAL RATIOS^a

($ million)

At period- end

Financial Debt

Cash and Cash Equivalents

Gross Debt / LTM Adj. EBITDA

Net Debtb/ LTM Adj. EBITDA

Interest Coverage

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

1Q2017

341.7

70.3

3.2x

2.6x

3.4x

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 March 31, 2017 the Company’s Leverage Ratio was above the 2.5x threshold included in the 2020 Bond Indenture and, in addition, the Interest Coverage Ratio was below the 3.5x threshold included in the 2020 Bond Indenture. These ratios have been impacted by pricing conditions since 2H2014. Failure to comply with the incurrence test ratios does not trigger an event of default. However, this situation may limit the Company’s capacity to incur additional indebtedness, other than permitted debt, as specified in the indenture governing the Notes. Incurrence covenants as opposed to maintenance covenants must be tested by the Company before incurring additional debt or performing other specific corporate actions including but not limited to dividend payments and restricted payments.

SELECTED INFORMATION BY BUSINESS SEGMENT (UNAUDITED)
Colombia			1Q2017		1Q2016
Revenue ($ million)	54.4				19.0
Production and Operating Costsa ($ million)			-11.9		-5.8
Adjusted EBITDA ($ million)			38.1		6.6
Capital Expendituresb ($ million)			19.2		1.6

Chile		1Q2017		1Q2016
Sale of crude oil ($ million)		0.0		4.0
Sale of gas ($ million)		4.8		5.2
Revenue ($ million)		4.9		9.2
Production and Operating Costsa ($ million)		-2.8		-5.2
Adjusted EBITDA ($ million)		0.3		1.3
Capital Expendituresb ($ million)		1.5		6.7

Brazil		1Q2017		1Q2016
Sale of crude oil ($ million)		0.2		0.2
Sale of gas ($ million)		7.2		8.2
Revenue ($ million)		7.4		8.3
Production and Operating Costsa ($ million)		-2.8		-2.0
Adjusted EBITDA ($ million)		3.8		5.4
Capital Expendituresb ($ million)		2.1		0.1

a)		Production and Operating = Operating Costs + Royalties.
b)		The difference with the reported figure in Key Indicators table corresponds mainly to capital expenditures in Argentina.

CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
(In millions of $)		1Q2017		1Q2016
REVENUE
Sale of crude oil		54.5		23.2
Sale of gas		12.2		13.4
TOTAL REVENUE		66.7		36.6
Commodity risk management contracts		5.4		0.0
Production and operating costs		-17.6		-13.0
Geological and geophysical expenses (G&G)		-1.2		-2.4
Administrative expenses (G&A)		-8.5		-7.5
Selling expenses		-0.4		-2.7
Depreciation		-15.7		-21.5
Write-off of unsuccessful efforts		-		-
Impairment for non-financial assets		-		-
Other operating		-0.5		-0.7
OPERATING PROFIT (LOSS)		28.1		-11.2
Financial costs, net		-9.2		-9.0
Foreign exchange gain (loss)		2.9		7.5
PROFIT (LOSS) BEFORE INCOME TAX		21.8		-12.7
Income tax		-16.0		0.7
PROFIT (LOSS) FOR THE PERIOD		5.8		-12.0
Non-controlling interest		2.2		-2.8
ATTRIBUTABLE TO OWNERS OF GEOPARK		3.6		-9.3

SUMMARIZED CONSOLIDATED STATEMENT OF FINANCIAL POSITION
(In millions of $)	Mar '17	Dec '16
	(Unaudited)	(Audited)
Non Current Assets
Property, plant and equipment	480.4	473.6
Other non current assets	43.8	45.7
Total Non Current Assets	524.2	519.3
Current Assets
Inventories	8.2	3.5
Trade receivables	13.4	18.4
Other current assets	33.1	25.7
Cash at bank and in hand	70.3	73.6
Total Current Assets	125.0	121.2
Total Assets	649.2	640.5
Equity
Equity attributable to owners of GeoPark	110.9	105.8
Non-controlling interest	38.0	35.8
Total Equity	148.9	141.6
Non Current Liabilities
Borrowings	309.5	319.4
Other non current liabilities	78.4	80.0
Total Non Current Liabilities	387.9	399.4
Current Liabilities
Borrowings	32.2	39.3
Other current liabilities	80.1	60.2
Total Current Liabilities	112.3	99.5
Total Liabilities	500.2	498.9
Total Liabilities and Equity	649.2	640.5

SUMMARIZED CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)
(In millions of $)	1Q2017	1Q2016
Cash flows from operating activities	45.2	19.9
Cash flows used in investing activities	-23.5	-8.4
Cash flows used in financing activities	-23.8	-22.7
Net Change	-2.1	-11.1

RECONCILIATION OF ADJUSTED EBITDA TO PROFIT (LOSS) BEFORE INCOME TAX (UNAUDITED)
1Q2017 (In millions of $)		Colombia		Chile		Brazil		Other		Total
Adjusted EBITDA		38.1		0.3		3.8		-3.3		38.8
Depreciation		-8.6		-4.7		-2.3		-0.1		-15.7
Commodity risk management Contracts		5.2		-		-		-		5.2
Share based payments and other		1.2		-0.1		-0.5		-0.8		-0.2
OPERATING PROFIT		35.9		-4.5		1.0		-4.2		28.1
Financial costs, net										-9.2
Foreign exchange charges, net										2.9
PROFIT (LOSS) BEFORE INCOME TAX										21.8
1Q2016 (In millions of $)		Colombia		Chile		Brazil		Other		Total
Adjusted EBITDA		6.6		1.3		5.4		-1.7		11.6
Depreciation		-8.5		-9.1		-3.9		-0.1		-21.5
Share based payments and other		-0.1		0.0		-0.1		-1.0		-1.3
OPERATING PROFIT (LOSS)		-1.9		-7.8		1.3		-2.8		-11.2
Financial costs, net										-9.0
Foreign exchange charges, net										7.5
PROFIT (LOSS) BEFORE INCOME TAX										-12.7

CONFERENCE CALL INFORMATION

GeoPark will host its First Quarter 2017 Financial Results conference call and webcast on Thursday, May 11 2017, at 10:00 a.m. Eastern Daylight Time.

Chief Executive Officer, James F. Park, Chief Financial Officer, Andres Ocampo, and Chief Operating Officer, Augusto Zubillaga will discuss GeoPark's financial results for 1Q2017, 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: 13704676

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 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 deliveries
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 deliveries. Operating netback is equivalent to Adjusted EBITDA net of cash expenses included in Administrative, Geological and Geophysical and Other operating costs
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
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 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.

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