6-K 1 dp61099_6k.htm FORM 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER PURSUANT TO RULE 13a-16
OR 15d-16 UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of November 2015

Commission File Number: 001-36298

GeoPark Limited

(Exact name of registrant as specified in its charter)

Nuestra Señora de los Ángeles 179

Las Condes, Santiago, Chile

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F

Form 40-F

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Yes

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):

Yes

GEOPARK LIMITED

TABLE OF CONTENTS

ITEM
1.	Press Release dated November 10, 2015 titled “GeoPark Reports Results for the Third Quarter Ended September 30, 2015”

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

GeoPark Limited


By:	/s/ Andrés Ocampo
	Name:	Andrés Ocampo
	Title:	Chief Financial Officer

Date: November 10, 2015

FOR IMMEDIATE DISTRIBUTION

GEOPARK REPORTS RESULTS FOR THE THIRD QUARTER

ENDED SEPTEMBER 30, 2015

CASH PRESERVATION, PRODUCTION MAINTENANCE, NEW INVESTMENT & GROWTH

Santiago, Chile – November 10, 2015 - GeoPark Limited (“GeoPark” or the “Company”) (NYSE: “GPRK”), the Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Chile, Brazil, Argentina, and Peru¹reports its unaudited consolidated financial results for the three-month period ended September 30, 2015 (“Third Quarter” or “3Q2015”). A conference call to discuss 3Q2015 results will be held on November 11, 2015 at 10 am Eastern Standard Time.

All figures are expressed in US Dollars and growth comparisons refer to the same period of the prior year, except when specified.

THIRD QUARTER 2015 HIGHLIGHTS

Operational:

Consolidated oil and gas production totaled an average of 19,244 boepd from Colombia, Chile and Brazil. (Current 4Q consolidated production is approximately 23,000 boepd)

Continuing oil production growth in Llanos 34 Block (GeoPark operated with 45% WI) with average of 29,000 bopd gross

Drilling campaign resumed with five new wells drilled in Colombia of which four were successful

Two new Colombian oilfield discoveries: GeoPark began drilling again on the Llanos 34 Block (GeoPark operated with 45% WI) and discovered and put into production the new Chachalaca and Jacana oil fields

Two new Colombian appraisal wells: GeoPark drilled the Tilo 2 well with a successful 800 bopd oil test and the Jacana 2 well with a successful 1,000 bopd oil test, both in the Llanos 34 Block (GeoPark operated with 45% WI)

New Chile gas field on stream: Construction of Ache gas treatment facility in Fell Block (GeoPark operated with 100% WI) was completed and the field was put into production at a rate of approximately 6.7 mmcfpd

Brazil compression plant completed: Pressure maintenance facility to stabilize production and develop remaining Manati gas field reserves (non-operated with 10% WI) was completed and field production resumed at approximately 220 mmcfpd gross. (Temporary shut-in of gas field during the tie-in impacted 3Q2015 net production by approximately 500 boepd)

Financial:

Balance Sheet: Strong cash position of $90.4 million at the end of 3Q2015 through financial discipline and cost reductions. (Long term corporate debt profile: 80+% of financial obligations due in 2020. No principal payments due in 2015)

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

Base Performance: Adjusted EBITDA of $18.2 million. Quality of asset base, matched with cost reduction and restructuring efforts, have ensured that approximately 85% of production is cash flow positive at $25-$30 barrel oil prices

Cost Discipline: Aggressive cost management plan across the entire Company, supported by depreciation of local currencies, decreased production and operating costs by 56% to $18.2 million and decreased cash costs by 54% to $29.6 million

Capital Allocation: 2015 $55-60 million capital expenditure plan (reduction of 75% compared to 2014) on target and focused on higher return quickest cash flow producing projects. 9M2015 capital expenditures of $42.3 million represent a 75% decrease compared to 9M2014 (Nine-month period ended September 30, 2014)

Strategic/New Business:

New Brazil blocks: As part of its continuing long term growth strategy into proven low risk high potential hydrocarbon basins across Latin America, GeoPark was awarded four new attractive exploratory blocks in the Reconcavo and Potiguar basins – adjacent to existing GeoPark acreage – under favorable terms in the Brazilian Round 13 auction (October 2015)

James F. Park, Chief Executive Officer of GeoPark, said: "GeoPark moved decisively at the end of 2014 to adjust to a sustained period of low oil prices. This has enabled us to adapt quickly to the new industry environment, find ways to continue achieving both organic and inorganic growth, and continue pushing forward with our long term business plan. Defensively, our team restructured our operations to deliver important cost savings and both reduced and refocused our capital investments to the lower-risk higher-return quickest-cash flow projects. These actions, coupled with the quality and diversity of our asset base, have resulted in approximately 85% of our production being profitable at a $25-30 oil price. Consequently, our balance sheet has been kept strong and our cash safe — while still investing in projects that will ensure our long term growth. In the third quarter, we got back to finding oil with the drill bit with the discovery of two new oil fields — meaning we have been able to demonstrate continuous production and reserve growth in Colombia throughout 2015. And, considering all country business units, we are currently at record production levels. Offensively, we have also been able to continue building our portfolio of attractive assets in low risk proven hydrocarbon basins across Latin America — and in the latest bid round in Brazil were able to acquire four new attractive blocks complementary to other GeoPark assets. We salute the GeoPark team for again proving its experience, creativity, and agility — and look forward to the opportunities ahead."

THIRD QUARTER 2015

The table below sets forth key performance indicators for 3Q2015 compared to those of 3Q2014:

Key Indicators	3Q2015	3Q2014	% Chg.
Brent Oil Price ($ per bbl)	52.0	103.0		-50%
Oil production (bopd)	14,712	15,739		-7%
Gas production (mcfpd)	27,188	34,854		-22%
Average net production (boepd)	19,244	21,548		-11%
Combined price ($ per boe)	28.2	69.8		-60%
⁻ Oil ($ per bbl)	30.1	82.3		-64%
⁻ Gas ($ per mcf)	4.2	7.6		-44%
Net Oil Revenues ($ million)	38.6	111.6		-65%
Net Gas Revenues ($ million)	9.3	20.2		-54%
Net Revenues ($ million)	47.8	131.8		-64%
Production & Operating Costs* ($ million)	-18.2	-41.0		-56%
G&G, G&A and Selling Costs ($ million)	-12.8	-25.8		-50%
Adjusted EBITDA ($ million)	18.2	67.9		-73%
Adjusted EBITDA per boe ($)	10.7	36.0		-70%
Operating Netback per boe ($)	17.6	43.5		-60%
Profit (loss) for the period ($ million)	-37.7	11.9		-
Capital Expenditures ($ million)	26.3	51.1		-49%
Cash Position at period-end ($ million)	90.4	128.8		-30%
Short-Term Debt at period-end ($ million)	26.2	20.6		27%
Long-Term Debt at period-end ($ million)	338.3	342.3		-1%

* Production and Operating costs include operating costs and royalties paid in cash.

CONSOLIDATED OPERATING PERFORMANCE

Production: Consolidated production reached 19,244 boepd in 3Q2015, compared to 21,548 boepd in 3Q2014.

Colombia: Average net oil production in Colombia increased by 9% to 13,033 boepd in 3Q2015– mainly resulting from new field discoveries, development drilling and reengineering of well completions and operations

Chile: Average net oil and gas production in Chile decreased by 46% to 3,207 boepd in 3Q2015. The decrease consisted of 54% lower oil production and 33% lower gas production and was mainly the result of natural decline in base production and no drilling activity during 2015. The new Ache gas field was put into production at the end of 3Q2015 at a rate of approximately 6.7 mmcfpd and is expected to increase production during 4Q2015

Brazil: Average gas production decreased by 15% to 2,959 boepd in 3Q2015 compared to 3,480 boepd in 3Q2014 mainly as a consequence of the shut-in of the Manati gas field during the tie-in of the new compression plant that temporarily reduced 3Q2015 net production by approximately 500 boepd. The pressure maintenance facility was built to stabilize production and develop remaining Manati gas field reserves (non-operated with 10% WI). Manati gas field production resumed at approximately 220 mmcfpd gross

Due to new drilling and operational successes during 3Q2015, current consolidated production has grown to approximately 23,000 boepd, thereby already reversing the 3Q2015 decrease.

Reference and Realized Oil Prices: Average consolidated realized oil sales price averaged $30 per barrel in 3Q2015, representing a $22 discount from the average Brent crude prices of $52 per barrel. Continuous commercial efforts are underway in Colombia and Chile to improve realized oil prices.

Colombia: Realized oil price was $28.8 per barrel (representing a $23.2 per barrel discount from Brent or $17 per barrel discount to Vasconia). Discounts include commercial costs related to oil quality and marketing fees (approximately $8.0 per barrel) as well as transportation costs (approximately $9.0 per barrel) related to sales made at wellhead. Vasconia, the Company’s reference price in Colombia, averaged $46 per barrel during 3Q2015

Chile: Realized oil price was $41.0 per barrel in 3Q2015 (representing a $11.0 per barrel discount from Brent)

Net Revenues: Consolidated net revenues decreased by 64% to $47.8 million in 3Q2015, compared to $131.8 million in 3Q2014, mainly driven by lower oil and gas prices.

Consolidated Oil Revenues: Consolidated oil revenues decreased by 65% to $38.6 million in 3Q2015 mainly explained by a 64% decrease in realized oil prices. Oil revenues represent 81% of total net revenues as compared to 85% in 3Q2014.

Colombia: Oil revenues decreased by 60% to $33.8 million in 3Q2015 mainly due to lower oil prices. Realized oil prices decreased by 63% to $28.8 per barrel in 3Q2015. Oil deliveries increased by 8% to 1.2 million barrels in 3Q2015. The decrease in realized prices in 3Q2015 was higher than the decrease in reference prices due to more volumes sold at well-head. In 3Q2015, 98% of sales volumes were made at the well-head, compared to approximately 45% in 3Q2014. Well-head sales imply lower realized prices but also lower selling expenses, thereby increasing margins

Colombian earn-out payments decreased by 75% to $1.5 million in 3Q2015, compared to $7.6 million in 3Q2014, mainly due to the decline in oil prices

Chile: Oil revenues decreased by 81% to $6.1 million in 3Q2015 due to lower production and lower prices. Realized oil prices decreased 55% to $41.0 per barrel in 3Q2015 in line with decreased Brent prices. Deliveries decreased by 58% to 0.15 million barrels in 3Q2015 due to lower production resulting from the natural decline of the fields and no new wells drilled during 9M2015

Consolidated Gas Revenues: Consolidated gas revenues decreased by 54% to $9.3 million in 3Q2015 compared to $20.2 million in 3Q2014.

Chile: Gas revenues decreased by 47% to $2.9 million in 3Q2015 mainly due to decreased production and lower prices. Gas prices decreased by 32% to $4.3 per mcf ($25.8 per boe) in 3Q2015, resulting from lower international methanol prices that affected Fell Block gas prices. Gas deliveries decreased by 22% and amounted to 667 mmcf (0.11 mmboe) mainly resulting from the natural decline of the fields and no new wells drilled during 9M2015

Brazil: Gas revenues decreased by 57% to $6.4 million in 3Q2015 mainly due to decreased production and lower prices. Gas prices, net of taxes, decreased by 47% to $4.2 per mcf ($25.1 per boe) in 3Q2015, largely due to the depreciation of the local currency. Gas deliveries decreased by 14% and amounted to 1,500 mmcf (0.25 mmboe) mainly resulting from temporary shut-in of the Manati gas field during the tie-in of the new compression plant

Production and operating costs: Consolidated production and operating costs decreased by 56% to $18.2 million in 3Q2015, representing savings of $16.4 per barrel.

Consolidated operating costs: Consolidated operating costs (excluding royalties) decreased by 61% to $13.9 million in 3Q2015, compared to $35.5 million in 3Q2014, due to cost reduction initiatives and the impact of the depreciation of the local currencies against the US Dollar. These factors resulted in lower staff costs, well maintenance, consumables, transportation, equipment rental, field camp and other operating costs.

Colombia: Operating costs decreased by 66% to $7.7 million in 3Q2015. Operating costs per boe decreased by 69% to $6.5 per boe mainly due to improved fixed cost absorption, cost reduction initiatives, temporary shut-in of La Cuerva field and the impact of the depreciation of the Colombian Peso against the US Dollar

Chile: Operating costs decreased by 54% to $4.9 million in 3Q2015. Operating costs per boe decreased by 11% to $18.5 per boe due to cost reduction initiatives and the impact of the depreciation of the Chilean Peso against the US Dollar, partially offset by the impact on fixed costs from lower production

Brazil: Operating costs decreased by 11% to $1.5 million in 3Q2015 mainly due to the impact of the depreciation of the Brazilian Real against the US Dollar, partially offset by higher operating expenses resulting from the start-up of the compression plant. Operating costs per boe remained stable.

Consolidated Royalties: Consolidated royalties paid in cash (reported in production and operating costs) amounted to $4.4 million in 3Q2015, compared to $5.5 million in 3Q2014, representing 9% of total net revenues in 3Q2015 compared to 4% in 3Q2014. The increase in royalties, as a percentage of sales, is due to the Tua and Tigana fields in the Llanos 34 Block in Colombia becoming subject to higher royalties in 2015 after surpassing the production threshold of 5 million barrels of oil.

Geological and Geophysical Expenses (G&G): Consolidated geological and geophysical expenses amounted to $3.3 million in 3Q2015 compared to $3.4 million in 3Q2014.

Selling Expenses: Consolidated selling expenses decreased by 96% to $0.4 million in 3Q2015 compared to $9.3 million in 3Q2014, mainly as the result of lower selling expenses in Colombia.

Colombia: Selling expenses decreased by 85% to $0.1 million in 3Q2015 resulting from lower transportation costs per boe due to a change in the commercialization mix with 98% sales at well-head in 3Q2015, compared to 45% in 3Q2014

Administrative Costs (G&A): Consolidated administrative costs decreased by 30% to $9.1 million in 3Q2015 compared to $13.0 million in 3Q2014 mainly due to continuing financial discipline and cost reduction initiatives impacting consultant fees, office expenses, directors fees, share based payments and other G&A costs. The G&A cost reduction was achieved despite new start-up costs related to the Company’s operations in Peru and lower overhead collected from joint venture partners due to lower capital expenditures.

Adjusted EBITDA: Consolidated Adjusted EBITDA decreased by 73% to $18.2 million in 3Q2015 compared to $67.9 million in 3Q2014, mainly caused by the 64% decrease in revenues resulting from lower international oil prices, which was partially offset by a 54% reduction in cash costs (including production and operating costs, G&A and selling expenses).

Adjusted EBITDA per boe decreased by 70% to $10.7 per boe in 3Q2015 compared to $36.0 per boe in 3Q2014.

Colombia: Adjusted EBITDA decreased 58% to $17.6 million in 3Q2015 compared to $42.0 million in 3Q2014, mainly due to the decline in realized oil prices, partially offset by lower operating and selling costs. Adjusted EBITDA per boe decreased by 61% to $15.0 per boe in 3Q2015, mainly due to lower oil prices, partially offset by lower operating costs and selling expenses per boe resulting from increased efficiency and the depreciation of the Colombian Peso

Chile: Adjusted EBITDA was nil in 3Q2015, compared to $20.2 million in 3Q2014, mainly due to lower production and the impact of lower oil and gas prices, partially offset by lower operating and production costs and G&A expenses

Brazil: Adjusted EBITDA decreased 57% to $3.6 million in 3Q2015 compared to $8.3 million in 3Q2014, mainly due to lower revenues resulting from lower realized prices due to the depreciation of the Brazilian Real against the US Dollar. Adjusted EBITDA per boe decreased by 49% to $13.8 in 3Q2015 compared to $27.6 in 3Q2014

Other Operating Costs: Consolidated other operating costs amounted to negative $3.9 million in 3Q2015, related mainly due to Chilean contract termination costs, compared to $0.8 million gain in 3Q2014.

Depreciation: Consolidated depreciation charges decreased by 10% to $24.5 million in 3Q2015, compared to $27.1 million in 3Q2014, mainly due to lower production and lower per barrel depreciation costs in Colombia, partially offset by higher depreciation costs in Chile and stable depreciation costs in Brazil.

Write-off of Unsuccessful Efforts: Consolidated write-off of unsuccessful effort charges amounted to $3.7 million in 3Q2015, compared to nil in 3Q2014, mainly resulting from the impact of two wells plugged and abandoned in Colombia; one well in the CPO-4 Block and one well in the non-operated Llanos 32 Block.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Financial Costs: Net financial costs increased by 20% to $9.0 million in 3Q2015, compared to $7.5 million in 3Q2014 mainly from: (i) $0.6 million lower capitalized costs due to lower capital expenditures, and (ii) $0.5 million decrease in interest income due to lower average cash position.

Foreign Exchange Losses: Net foreign exchange losses increased to $28.4 million in 3Q2015 from $13.0 million in 3Q2015, mainly related to the impact of the depreciation of the Brazilian Real over US Dollar-denominated net debt incurred at the local subsidiary level, where the functional currency is the Brazilian Real. This effect may be partially offset in the following quarters due to fluctuations in the local currency.

Income Tax Expense: Income tax amounted to $15.0 million in 3Q2015, in line with consolidated losses before taxes in 3Q2015, compared to negative $6.2 million in 3Q2014.

Profit: Losses for the period amounted to $37.7 million in 3Q2015 compared to a profit of $11.9 million in 3Q2014, mainly due to lower revenues resulting from lower realized prices and foreign exchange losses, partially offset by lower Production and Operating costs, G&A costs, Selling expenses, Depreciation and Income tax charges.

BALANCE SHEET

Cash and Cash Equivalents: Cash and cash equivalents totaled $90.4 million as of September 30, 2015. Year-end 2014 cash and cash equivalents amounted to $127.7 million, the difference primarily being (i) cash used in investing activities during 9M2015 amounting to $42.3 million and (ii) $25.1 million of funds used in financing activities that are mainly explained by interest payments, and (iii) previous two components partially offset by cash generation from operating activities that amounted to $32.9 million.

Total Assets: Total assets amounted to $919.1 million as of September 30, 2015 compared to $1,039 million as of December 31, 2014. The decrease is mainly due to lower PP&E assets derived from depreciation charges during 9M2015 and lower cash and cash equivalents as explained in the paragraph above.

Capital Expenditures: Total investments in 9M2015 amounted to $42.3 million and mainly included: (i) $28.1 million invested in Colombia, (ii) $9.1 million invested in Chile, and (iii) $5.0 million invested in Brazil.

Financial Debt: Total financial debt (net of debt issuance costs) amounted to $364.6 million, including the $300 million 2020 Bond and the credit facility in Brazil for the acquisition of an interest in the Brazilian Manati Field amounting to $70.4 million.

Equity: Equity reached $397.8 million and included non-controlling interests of $97.0 million related to LG International’s participation in the Chilean and Colombian operations. (LG International Corp., the Korean conglomerate, holds a 20% equity interest in GeoPark’s Colombian operations, a 20% equity interest in the Fell Block and a 31% equity interest in the Tierra del Fuego blocks in Chile). Equity as of September 30, 2015 decreased by $81.3 million since December 31, 2014 mainly because of the $83.1 million loss in the nine-month period ended September 30, 2015, partially offset by share-based payment charges amounting to $4.5 million.

FINANCIAL RATIOS (*)

Amounts in $ million


Year / Period	Financial Debt	Cash Position	Gross Debt / LTM Adj EBITDA	Interest Coverage

2Q2014 (**)	368.6	125.3	1.8x	6.0x
3Q2014 (**)	362.9	128.8	1.6x	6.7x
FY2014 (**)	370.0	127.7	1.7x	7.5x
1Q2015	363.4	91.4	1.9x	6.3x
2Q2015	370.4	105.3	2.6x	4.7x
3Q2015	364.6	90.4	4.0x	2.9x

(*) Based on trailing 12 months financial results.

(**) Considers Adjusted EBITDA generated by the acquired interest in the Brazilian Manati Field only since 2Q2014.

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 stated in the table above, as of September 30, 2015 the Company’s Leverage Ratio was above the 2.5 times threshold included in the 2020 Bond Indenture and in addition, the Interest Coverage Ratio was below the 3.5 times threshold included in the 2020 Bond Indenture. These ratios were impacted by the current low oil price environment. Failure to comply with the incurrence test ratios does not trigger an event of default. However, this situation may limit the Company’s capacity to incur additional indebtedness, other than permitted debt, as specified in the indenture governing the Notes. Incurrence covenants as opposed to maintenance covenants must be tested by the Company before incurring additional debt or performing other specific corporate actions including but not limited to dividend payments, restricted payments, and others.

OTHER NEWS / RECENT EVENTS

New Oil Field Discoveries in Llanos 34 Block in Colombia

During 3Q2015, GeoPark announced two new oil field discoveries, following successful drilling of the Chachalaca and Jacana exploratory wells, both located on the Llanos 34 Block in Colombia.

Chachalaca Oil Field Discovery: The Chachalaca 1 exploration well was drilled to a depth of 12,270 feet. A test conducted in the Mirador formation resulted in a gross production rate of approximately 1,100 bopd. The well was put into production in October 2015

Jacana Oil Field Discovery: The Jacana 1 exploration well was drilled to a depth of 10,900 feet with hydrocarbon shows in both the Mirador and Guadalupe formations. A test conducted in the Guadalupe formation resulted in a gross production rate of approximately 1,880 bopd. The well was put into production in October 2015

New blocks awarded in the Brazilian Round 13 auction

In October 2015, GeoPark was awarded four new exploratory blocks (covering 30,200 acres) in the Brazilian Round 13 auction, complementing GeoPark’s existing exploration portfolio in the Reconcavo and Potiguar basins. GeoPark has committed to invest a minimum of approximately $3.50 million (including bonus and work program commitments) during the first exploratory period ending 2019.

The awarded blocks were:

Block (Basin)	Gross Acres	WI	Operator	Bonus	Investment Commitment
POT-T-747 (Potiguar)	6,900	70%*	GeoPark	$0.09 million	$1.10 million
POT-T-882 (Potiguar)	7,900	70%*	GeoPark	$0.05 million	$0.30 million
REC-T-93 (Reconcavo)	7,800	70%*	GeoPark	$0.04 million	$0.20 million
REC-T-128 (Reconcavo)	7,600	70%	GeoPark	$0.08 million	$1.60 million

* 30% WI of proposed partners is subject to ANP approval.

The bidding round was organized by the ANP and all proceedings and bids have been made public. The winning bids are subject to confirmation of qualification requirements.

CONFERENCE CALL INFORMATION

GeoPark will host its Third Quarter 2015 Financial Results conference call and webcast on Wednesday, November 11, 2015, at 10:00 a.m. Eastern Standard Time.

Chief Executive Officer, James F. Park, Chief Operating Officer, Augusto Zubillaga, and Director of Capital Markets, Pablo Ducci, will discuss GeoPark's financial results for 3Q2015, with a question and answer session immediately following.

Interested parties can access the conference call by dialing the following number from outside the United States: +1 201-689-8035. From within the United States, interested parties can access the call by dialing 1 877-407-8035 (Passcode: GeoPark). To listen to the webcast, please visit the Investor Support section of the Company’s website (www.geo-park.com).

For further information please contact:

Pablo Ducci – Director Capital Markets	pducci@geo-park.com
Santiago, Chile
T: +562 2242 9600

Dolores Santamarina – Investor Manager Buenos Aires, Argentina T: +5411 4312 9400	dsantamarina@geo-park.com

GeoPark can be visited online at www.geo-park.com

ANALYSIS INFORMATION BY BUSINESS SEGMENT

Colombia	3Q2015	3Q2014	% Chg.
Oil production (bopd)	12,967	11,892	9%
Gas production (mcfpd)	395	251	57%
Average net production (boepd)	13,033	11,934	9%
Oil price ($ per bbl)	28.8	79.0	-63%
Net oil Revenues ($ million)	32.3	78.3	-59%
Production and Operating Costs* ($ million)	-11.0	-25.5	-57%
Adjusted EBITDA ($ million)	17.6	42.0	-58%
Adjusted EBITDA per boe ($)	15.0	38.6	-61%
Operating Netback per boe ($)	19.6	43.5	-55%

Chile	3Q2015	3Q2014	% Chg.
Oil production (bopd)	1,700	3,721	-54%
Gas production (mcfpd)	9,039	13,637	-34%
Average net production (boepd)	3,207	5,994	-46%
Combined price ($ per boe)	34.6	76.3	-55%
⁻ Oil ($ per bbl)	41.0	90.0	-55%
⁻ Gas ($ per mcf)	4.3	6.4	-33%
Net Oil Revenues ($ million)	6.1	32.3	-81%
Net Gas Revenues ($ million)	2.9	5.4	-46%
Net Revenues ($ million)	9.0	37.7	-76%
Production and Operating Costs* ($ million)	-5.1	-12.1	-58%
Adjusted EBITDA ($ million)	-	20.2	-
Adjusted EBITDA per boe ($)	-	40.8	-
Operating Netback per boe ($)	13.8	50.2	-73%

Brazil	3Q2015	3Q2014	% Chg.
Oil production (bopd)	45	56	-20%
Gas production (mcfpd)	17,754	20,882	-15%
Average net production (boepd)	3,004	3,536	-15%
Gas Price ($ per mcf)	4.2	7.9	-47%
Net Revenues ($ million)	6.6	15.3	-57%
Production and Operating Costs* ($ million)	-2.0	-2.6	-23%
Adjusted EBITDA ($ million)	3.6	8.3	-57%
Adjusted EBITDA per boe ($)	13.8	27.6	-50%
Operating Netback per boe ($)	17.5	38.1	-46%

* Production and Operating costs include operating costs and royalties paid in cash.

FIRST NINE-MONTHS 2015

The table below sets forth some key performance indicators for 9M2015 compared with 9M2014. Figures corresponding to 9M2014 include information relating to the acquired interest in the Brazilian Manati Field completed on March 31, 2014. As from that date, GeoPark started consolidating line by line its results of operations for accounting purposes within its Brazilian operations.

Key Indicators	9M2015	9M2014	% Chg.
Oil production (bopd)	14,445	14,426		0%
Gas production (mcfpd)	30,132	30,645		-2%
Average net production (boepd)	19,467	19,533		0%
Combined price ($ per boe)	32.4	71.9		-55%
⁻ Oil ($ per bbl)	35.3	85.7		-59%
⁻ Gas ($ per mcf)	4.7	7.1		-34%
Net Oil Revenues ($ million)	129.6	298.8		-57%
Net Gas Revenues ($ million)	34.7	49.2		-29%
Net Revenues ($ million)	164.3	348.0		-53%
Production & Operating Costs* ($ million)	-64.6	-98.4		-34%
G&G, G&A, & Selling ($ million)	-40.7	-65.6		-38%
Adjusted EBITDA ($ million)	63.2	192.7		-67%
Adjusted EBITDA per boe ($)	12.5	39.8		-69%
Operating Netback per boe ($)	19.1	47.6		-60%
Profit (loss) for the period ($ million)	-83.1	49.6		-

* Production and Operating Costs include operating costs and royalties paid in cash.

CONSOLIDATED STATEMENT OF INCOME

(unaudited)

(In millions of $, except for %)	3Q2015	3Q2015	9M2015	9M2014

NET REVENUES
Sale of crude oil	38.6	111.6	129.6	298.8
Sale of gas	9.3	20.2	34.7	49.2
TOTAL NET REVENUES	47.8	131.8	164.3	348.0
Production and operating costs	-18.2	-41.0	-64.6	-98.4
Geological and Geophysical costs	-3.3	-3.4	-9.6	-9.0
Administrative expenses	-9.1	-13.0	-27.3	-34.9
Selling expenses	-0.4	-9.3	-3.8	-21.6
Depreciation	-24.5	-27.1	-74.3	-72.8
Write-off of unsuccessful efforts	-3.7	-0.0	-3.7	-8.6
Other operating	-3.9	0.8	-12.6	1.8
OPERATING PROFIT	-15.2	38.7	-31.7	104.3

Financial costs, net	-9.0	-7.5	-26.1	-20.0
Foreign Exchange Losses	-28.4	-13.0	-44.4	-11.7
PROFIT BEFORE INCOME TAX	-52.6	18.1	-102.2	72.6

Income tax	15.0	-6.2	19.1	-23.0
PROFIT (LOSS) FOR THE PERIOD	-37.7	11.9	-83.1	49.6
Non-controlling interest	-1.5	3.5	-6.7	12.7
ATTRIBUTABLE TO OWNERS OF GEOPARK	-36.2	8.5	-76.4	36.9

RECONCILIATION OF ADJUSTED EBITDA TO PROFIT BEFORE INCOME TAX

AND ADJUSTED EBITDA PER BOE

(unaudited)


	3Q2015	3Q2014	9M2015	9M2014
Adjusted EBITDA	18.2	67.9	63.2	192.7
Depreciation	-24.5	-27.1	-74.3	-72.8
Share Based Payments	-1.4	-2.4	-4.5	-8.0
Impairment and write-off	-3.7	-0.0	-3.7	-8.6
Others	-3.8	0.3	-12.3	1.1
OPERATING PROFIT	-15.2	38.7	-31.7	104.3
Financial costs, net	-9.0	-7.5	-26.1	-20.0
Foreign Exchange Losses, net	-28.4	-13.0	-44.4	-11.6
PROFIT BEFORE INCOME TAX	-52.6	18.1	-102.2	72.6

Adjusted EBITDA	18.2	67.9	63.2	192.7
Total deliveries (in millions of boe)	1.7	1.9	5.1	4.8
Adjusted EBITDA per boe	10.7	36.0	12.5	39.8

CONSOLIDATED SUMMARIZED BALANCE SHEET

(Quarterly information unaudited)

	Sept'15	Dec '14

Non Current Assets
Property, Plant and Equipment	725.4	790.8
Other Non Current Assets	60.6	47.8
Total Non Current Assets	786.0	838.5

Current Assets
Inventories	4.7	8.5
Trade Receivables	11.6	36.9
Other Current Assets	26.4	27.5
Cash at bank and in hand	90.4	127.7
Total Current Assets	133.1	200.6

Total Assets	919.1	1,039.1

Equity
Equity attributable to owners of GeoPark	300.8	375.6
Non-controlling interest	97.0	103.6
Total Equity	397.8	479.1

Non Current Liabilities
Borrowings	338.3	342.4
Other Non Current Liabilities	93.1	93.6
Total Non Current Liabilities	431.4	436.0

Current Liabilities
Borrowings	26.2	27.2
Other Current Liabilities	63.7	96.8
Total Current Liabilities	89.9	124.0

Total Liabilities and Equity	919.1	1,039.1

SELECTED HISTORICAL OPERATIONAL AND FINANCIAL DATA

		Year ended December 31,
	2014	2013	2012	2011	2010
Oil Reserves (2P PRMS) - mmboe	56.3	33.9	27.8	16.9	16.2
Gas Reserves (2P PRMS) - mmboe	35.8	27.7	29.1	32.6	33.4
Combined Reserves (2P PRMS) - mmboe	92.1	61.6	56.9	49.5	49.6
Peru*	30.2	-	-	-	-
Total including Peru	122.3	-	-	-	-


Oil Production (thousand boepd)	14.5	11.1	7.5	2.5	1.9
Gas Production (thousand boepd)	5.1	2.4	3.8	5.1	5.0
Production (thousand boepd)	19.6	13.5	11.3	7.6	6.9

Oil Revenues ($ million )	367	315	222	74	48
Gas Revenues ($ million)	62	23	29	38	31
Total Revenues ($ million)	429	338	250	112	80

Adjusted EBITDA ($ million)	220	167	121	63	41

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

GLOSSARY

Adjusted EBITDA	Adjusted EBITDA is defined as profit for the period before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful efforts, accrual of share-based payment and other non-recurring events
Adjusted EBITDA per boe	Adjusted EBITDA divided by total boe deliveries
Operating Netback per boe	Net revenues, less production costs (net of depreciation charges and accrual of stock options and stock awards) and selling expenses, divided by total boe deliveries. Operating Netback is equivalent to Adjusted EBITDA net of cash expenses included in Administrative, Geological and Geophysical and Other operating costs
ANP	Agência Nacional do Petróleo, Brazil’s National Agency of Petroleum

ANH	Agencia Nacional de Hidrocarburos de Colombia
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
EPS	Earnings per share
IPO	Initial Public Offering
mbbl	Thousand barrels of oil
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.

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 2015 production growth 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.

Information about oil and gas reserves: The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, 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.

Adjusted EBITDA: The Company defines Adjusted EBITDA as profit for the period before net finance cost, income tax, depreciation, amortization and certain non-cash items such as impairments and write-offs of unsuccessful exploration and evaluation assets, accrual of stock options stock awards, bargain purchase gain on acquisition of subsidiaries and other non-recurring events. Adjusted EBITDA is not a measure of profit or cash flows as determined by IFRS. The Company believes Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. The Company excludes the items listed above from profit for the period in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, profit for the period or cash flows from operating activities as determined in accordance with IFRS or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure and significant and/or recurring write-offs, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. The Company’s computation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. For a reconciliation of Adjusted EBITDA to

the IFRS financial measure of profit for the year or corresponding period, see the accompanying financial tables.

Operating netback per boe should not be considered as an alternative to, or more meaningful than, profit for the period or cash flows from operating activities as determined in accordance with IFRS or as an indicator of our operating performance or liquidity. Certain items excluded from Operating netback per boe are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure and significant and/or recurring write-offs, as well as the historic costs of depreciable assets, none of which are components of Operating Netback per boe. The Company’s computation of Operating Netback per boe may not be comparable to other similarly titled measures of other companies. For a reconciliation of Operating Netback per boe to the IFRS financial measure of profit for the year or corresponding period, see the accompanying financial tables.