SANTIAGO, Chile--(BUSINESS WIRE)--GeoPark Limited (“GeoPark” or the “Company”) (NYSE: GPRK), a leading independent Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Chile, Brazil, Argentina, and Peru reports its consolidated financial results for the three-month period ended June 30, 2017 (“Second Quarter” or “2Q2017”).
A conference call to discuss 2Q2017 Financial Results will be held on August 17, 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 June 30, 2017, available on the Company’s website.
SECOND QUARTER 2017 HIGHLIGHTS
Record consolidated oil and gas production
- Consolidated oil and gas production increased by 24% to a record 26,123 boepd
- Oil production increased by 41% to 21,930 bopd, representing 84% of total production
- Colombian oil production continued climbing by 49% to 20,951 bopd
- Gas production decreased by 25% to 25.2 mmcfpd
- Current consolidated production of over 28,000 boepd
- 2017 exit production targeted to exceed 30,000 boepd
GeoPark Colombia surpasses 40 million barrel gross production milestone
At Llanos 34 block (GeoPark operated with a 45% WI):
- Exploration: Jacamar 1 well discovered a new oil field, currently producing 300 bopd gross, and Curucucu 1 well drilled and currently being completed for testing
- Appraisal: Jacana Sur 2 and Jacana 8 wells drilled, completed and currently producing 1,800 bopd gross. Jacana 9 appraisal well drilled and under testing. Jacana 10 appraisal well drilled and producing over 800 bopd
- Development: Jacana 7, Jacana Sur 1 and Tigana Sur 5 wells drilled, completed and currently producing 2,800 bopd gross
- Gross GeoPark operated production exceeds 51,000 barrels per day
New oil field discovery in Argentina
- Discovery of the Rio Grande Oeste oil field in CN-V block (GeoPark 50% WI) in the Neuquen Basin. Rio Grande Oeste 1 exploration well showed potential net pay of 400 feet and successfully tested 300 bopd gross
Adjusted EBITDA margin increased to 49%
- Revenues increased 64% to $75.2 million
- Operating netbacks of $22.2 per boe, a $4.5 per boe or a 25% increase
- Second quarter Adjusted EBITDA increased by 81% to $37.1 million and last twelve months Adjusted EBITDA reached $122.2 million
- Adjusted EBITDA per boe increased by 39% to $15.9 per boe
- Cash flow from operations of $33.9 million, exceeded capital expenditures by 1.3x
- Net loss of $1.1 million impacted by write-offs of $4.6 million
Continued balance sheet improvement
- Gross debt to Adjusted EBITDA decreased from 3.2x to 2.8x
- Net debt to Adjusted EBITDA decreased from 2.6x to 2.2x
- Interest coverage ratio at 4.1x now above 2020 Bond incurrence test ratio of 3.5x
- 40-50% of oil production hedged in 2H2017 with Brent price floor of $50-$54/bbl
- Increased cash and cash equivalents to $77.0 million
Intense exploration and appraisal drilling program in 3Q2017
- Four drilling rigs operating, targeting 12-13 oil and gas wells in Colombia, Chile and Argentina
- In Colombia, drilling seven wells, mostly appraisal, to further delineate the southern Jacana and northern Tigana oil fields in the Llanos 34 block
- In Chile, targeting one new shallow gas prospect in Fell block (GeoPark operated with a 100% WI)
- In Argentina, targeting four oil wells in the Sierra del Nevado and Puelen blocks (GeoPark non-operated with a 18% WI)
Improved market visibility
- Increased stock trading volume to approximately $1 million per day during the last twelve months and over $1.7 million during the last three months
James F. Park, Chief Executive Officer of GeoPark, said: “Our team’s repeated operational success on the ground continues to lead our successful financial performance. Our risk-managed high potential asset portfolio consistently delivers results. Colombia is driving us forward with a proven, low-cost, big-scale project. Argentina represents an exciting new country entry with room to grow. Brazil and Chile provide stability and new opportunity. Peru is targeted as the next big leg of growth. And, all built to work in today's low oil price world. GeoPark has the team, the assets, the capital, the position and the plan to endure, grow and prosper for the long-term in the evolving energy markets. All underpinned by a unique fifteen-year established platform across Latin America – the most dynamic and promising hydrocarbon region today.”
CONSOLIDATED OPERATING PERFORMANCE
Key performance indicators:
|Oil productiona (bopd)||21,930||20,487||15,530||21,213||15,939|
|Gas production (mcfpd)||25,158||28,152||33,678||26,646||35,357|
|Average net production (boepd)||26,123||25,180||21,143||25,654||21,831|
|Brent oil price ($ per bbl)||51.0||54.7||47.0||52.8||41.1|
|Combined price ($ per boe)||32.2||32.6||25.6||32.4||22.3|
|⁻ Oil ($ per bbl)||33.4||34.3||26.4||33.8||21.4|
|⁻ Gas ($ per mcf)||5.5||5.2||4.3||5.3||4.4|
|Sale of crude oil ($ million)||64.1||54.5||34.3||118.6||57.5|
|Sale of gas ($ million)||11.1||12.2||11.6||23.3||25.0|
|Revenue ($ million)||75.2||66.7||45.9||141.9||82.5|
|Commodity Risk Management Contracts ($ million)||5.9||5.4||-||11.3||-|
|Production & Operating Costsb ($ million)||-25.3||-17.6||-13.8||-42.9||-26.8|
|G&G, G&Ac and Selling Expenses ($ million)||-13.9||-10.2||-11.6||-24.1||-24.2|
|Adjusted EBITDA ($ million)||37.1||38.8||20.5||75.9||32.0|
|Adjusted EBITDA ($ per boe)||15.9||19.0||11.4||17.3||8.6|
|Operating Netback ($ per boe)||22.2||24.0||17.7||23.0||14.2|
|Profit (loss) ($ million)||-1.1||5.8||-1.6||4.7||-13.7|
|Capital Expenditures ($ million)||25.9||23.5||5.7||49.4||14.1|
|Cash and cash equivalents ($ million)||77.0||70.3||79.2||77.0||79.2|
|Short-term financial debt ($ million)||31.7||32.2||38.5||31.7||38.5|
|Long-term financial debt ($ million)||314.6||309.5||331.4||314.6||331.4|
|a)||Includes government royalties paid in-kind in Colombia for approximately 781, 608 and 729 bopd in 2Q2017, 1Q2017 and 2Q2016 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, $0.8 and $0.1 million for 2Q2017, 1Q2017 and 2Q2016, respectively, of (non-cash) share-based payments that are excluded from the Adjusted EBITDA calculation.|
Production: Consolidated oil and gas production grew by 24% to a record 26,123 boepd in 2Q2017 compared to 21,143 boepd in 2Q2016. The increase was driven by Colombian oil production, partially offset by lower gas production in Chile and Brazil.
- Colombia: Average net oil and gas production increased by 49% to 21,015 bopd in 2Q2017 compared to 14,084 bopd in 2Q2016 due to continued successful exploration and development drilling in the Llanos 34 block.
- Chile: Average net oil and gas production decreased by 41% to 2,450 boepd in 2Q2017 compared to 4,118 boepd in 2Q2016, mainly due to a temporary interruption in gas purchases during May and June of 2017. As of the date of this release, gas sales have been restored and current Chilean production is approximately 2,900 boepd.
- Brazil: Average net oil and gas production decreased by 10% to 2,658 boepd in 2Q2017 compared to 2,941 boepd in 2Q2016, due to lower gas consumption by Brazilian industrial users. As of the date of this release, gas demand has rebounded and current production is approximately 3,200 boepd.
The weight of crude oil in the production mix increased to 84% in 2Q2017 (vs. 73% in 2Q2016) due to the successful drilling campaign in Llanos 34 block and lower gas production in Chile and Brazil.
Recent Operational Activity:
- Jacana 9 appraisal well was drilled and completed to a total depth of 11,545 feet, approximately 75 feet down dip of Jacana 5. Preliminary logging information indicated the presence of hydrocarbons in the lower, middle and upper levels of the Guadalupe formation. A test conducted with an electric submersible pump in the lower section of the formation resulted in a production rate of approximately 80 barrels of oil per day (bopd) with a 90% water cut. Testing of the middle and upper Guadalupe zones will be performed over the course of the next few weeks. Formation depths and preliminary results from the Jacana 9 and 10 wells, taken together, could indicate that Jacana 9 is in a separate reservoir compartment with a shallower oil water transition zone than elsewhere in this large oil accumulation. As a result, following completion of Jacana 10, a workover rig will be moved to Jacana 9 well to test the middle and upper sections of the Guadalupe formation.
- Jacana 10 appraisal well, located between Jacana 9 and Tigana Sur 1 wells, was drilled to a total depth of 11,847 feet and completed during July to test the northern limits of the Jacana oil field and how it may relate to the Tigana oil field. A production test conducted with an electric submersible pump in the Guadalupe formation resulted in a production rate of approximately 1,000 bopd of 16.0 degrees API, with less than 1% water cut, through a choke of 38/64 mm and wellhead pressure of 37 pounds per square inch. Additional production history is required to determine stabilized flow rates of the well. Surface facilities are in place and the well is already in production.
- Drilling activity during 3Q2017 will continue with four appraisal and one development wells to further delineate the southern Jacana and northern Tigana oil fields in the Llanos 34 block and to define field boundaries and geography.
Reference and Realized Oil Prices: Brent crude oil price averaged $51.0 per bbl during 2Q2017, and the consolidated realized oil sales price averaged $33.4 per bbl in 2Q2017, representing a 3% decrease from $34.3 per bbl in 1Q2017 and a 27% increase from $26.4 per bbl in 2Q2016. Differences between reference and realized prices are a result of commercial and transportation discounts as well as the Vasconia price differential in Colombia, which narrowed to $3.6 per bbl in 2Q2017 versus $6.0 per bbl in 2Q2016.
The following table provides a breakdown of reference and net realized oil prices in Colombia and Chile in 2Q2017:
2Q2017 - Realized Oil Prices
($ per bbl)
|Brent oil price||51.0||51.0|
|Commercial and transportation discounts||(15.1)||(8.0)|
|Realized oil price||32.3||43.0|
|Weight on Oil Sales Mix||91%||9%|
Commodity Risk Management Contracts - Brent Oil Price: In 2Q2017 the Company recorded the following amounts related to commodity hedges to mitigate the risk exposure to changes in the Brent oil price. Realized gains reflect cash settled transactions and unrealized gains reflect non-cash changes between the contract values and the forward Brent oil curve.
|2Q2017 – Commodity Risk Management Contracts||($ million)|
|Realized cash gain||2.0|
|Non-cash unrealized gain||3.9|
The Company has the following commodity risk management contracts in place as of the date of this release:
- For the three-month period ending September 30, 2017, GeoPark guaranteed a minimum Brent price of $51.0 per bbl for 12,000 bopd through a zero-cost collar structure that includes a maximum price of $61.1 per bbl.
- For the three-month period ending December 31, 2017, GeoPark secured a minimum Brent price of $50.0 per bbl for 12,000 bopd through a zero-cost collar structure that includes a maximum price of $57.5 per bbl.
- For the three-month period ending March 31, 2018, GeoPark secured a minimum Brent price of $50.0 per bbl for 6,000 bopd through a zero-cost collar structure that includes a maximum price of $55 per bbl.
Revenue: Consolidated revenues increased by 64% to $75.2 million in 2Q2017, compared to $45.9 million in 2Q2016, mainly driven by higher oil revenues.
Sales of crude oil: Consolidated oil revenues increased by 87% to $64.1 million in 2Q2017, driven mainly by a 48% increase in oil sales volumes and a 27% increase in realized oil prices. Oil revenues represented 85% of total revenues compared to 75% in 2Q2016.
- Colombia: In 2Q2017, oil revenues increased by 97% to $58.7 million mainly due to increased sales volumes and higher realized prices. Oil sales volumes increased by 51% to 19,917 bopd. Realized oil prices increased by 30% to $32.3 per bbl, in line with higher Brent prices and a lower differential to the Vasconia marker. Colombian earn-out payments (deducted from Colombian oil revenues) increased to $2.5 million in 2Q2017, compared to $1.2 million in 2Q2016, in line with higher oil revenues and increased production.
- Chile: In 2Q2017, oil revenues increased by 40% to $7.7 million due to higher realized prices and increased sales volumes. (Oil production for the period January-March 2017 was recorded as Inventories at 1Q2017 period end, and delivered during 2Q2017, as the Company was negotiating a new sales agreement with ENAP that was signed in May 2017.) Oil sales volumes increased by 28% to 1,956 bopd. Realized oil prices increased by 9% to $43.0 per bbl, in line with higher Brent prices.
Sale of gas: Consolidated gas revenues decreased by 4% to $11.1 million in 2Q2017 compared to $11.6 million in 2Q2016 due to lower gas sales volumes, partially offset by higher realized gas prices.
- Chile: In 2Q2017, gas revenues decreased by 20% to $3.4 million mainly due to lower gas sales volumes resulting from a temporary interruption in gas purchases during May and June of 2017, partially offset by higher realized gas prices. Gas sales volumes decreased by 43% to 7,651 mcfpd (1,275 boepd). Gas prices increased by 41% to $5.0 per mcf ($29.7 per boe) in 2Q2017.
- Brazil: In 2Q2017, gas revenues slightly increased by 3% to $7.5 million, mainly due to higher realized prices, partially offset by lower gas sales volumes. Gas prices, net of taxes, increased by 14% to $5.7 per mcf ($34.3 per boe) due to a 9% appreciation of the local currency and the annual gas price inflation adjustment that this time was of approximately 7%, effective January 2017. Gas sales volumes decreased by 10% to 14,459 mcfpd (2,410 boepd), primarily due to lower gas consumption by Brazilian industrial users.
Production and operating costs: Consolidated operating costs per barrel increased to $8.3 per boe in 2Q2017 from $6.2 per boe a year earlier mainly as a result of more production from previously shut in fields, road maintenance and well intervention costs. Following the 48% increase in oil sales, total production and operating costs increased to $25.3 million in 2Q2017, compared to $13.8 million in 2Q2016. The Jacana oil field accumulated more than 5 mmbbl which triggered Colombia’s “high price” royalty scheme. Thus, cash royalties as a percentage of revenues were 7.8% compared to 5.6% in 2Q2016.
By country, production and operating costs were as follows:
Colombia: Operating costs per boe increased to $5.9 per boe in 2Q2017
from $4.0 per boe in 2Q2016 due to:
- Significantly higher volumes sold, 51% compared to a year earlier, increased overall operating costs to $10.7 million in 2Q2017 from $4.8 million in 2Q2016;
- Incremental costs related to the reopening of La Cuerva and Yamu mature oil fields also impacted operating costs since these fields had been temporarily closed in 2Q2016 and have significantly higher operating costs per barrel compared to Llanos 34 block; and
- $1.7 million (or $0.9 per bbl) related to road maintenance works, pulling and other well intervention activities in Jacana, Tigana, Tua and Tarotaro oil fields in Llanos 34 block.
- Chile: Operating costs increased by 25% to $6.4 million in 2Q2017, mainly due to a higher share of oil in the sales mix (61% vs 40% in 2Q2016), which had been deferred from the first quarter. The deferred oil sales have higher operating costs than gas. Operating costs per boe increased by 47% to $21.7 per boe.
- Brazil: Operating costs increased to $2.3 million in 2Q2017 from $1.3 million in 2Q2016, mainly resulting from non-recurring maintenance costs in Manati ($1.1 million during 2Q2017) and, to a lesser extent, the appreciation of the Brazilian real (+9%). Operating costs per boe increased to $10.1 per boe from $5.1 in 2Q2016.
Royalties: Consolidated royalties paid in cash (reported in Production and Operating Costs) increased to $5.9 million in 2Q2017, compared to $2.6 million in 2Q2016, mainly resulting from increased production, higher oil prices and the “higher price” royalty for the Jacana oil field in Llanos 34 block beginning in 2Q2017. Thus, consolidated royalties increased to 7.8% of revenue vs. 5.6% in 2Q2016.
Selling expenses: Consolidated selling expenses decreased to $0.1 million in 2Q2017 compared to $0.5 million in 2Q2016 mainly as a result of lower selling expenses in Colombia and Chile.
Administrative, Geological and Geophysical expenses: Consolidated G&A and G&G costs per boe remained flat at $6.3 per boe in 2Q2017 (vs. 2Q2016). Consolidated G&A and G&G expenses increased by 24% to $13.8 million in 2Q2017 compared to $11.1 million in 2Q2016. The Company expects that full year 2017 G&G and G&A expenses will be lower than figures reported in 2Q2017, at approximately $5-5.5 per boe.
Adjusted EBITDA: Consolidated Adjusted EBITDA1 continued growing by 81% to $37.1 million or $15.9 per boe in 2Q2017 compared to $20.5 million or $11.4 per boe in 2Q2016, mainly driven by the combination of increased production levels and higher realized oil and gas prices.
- Colombia: Adjusted EBITDA of $37.0 million in 2Q2017
- Chile: Adjusted EBITDA of $1.9 million in 2Q2017
- Brazil: Adjusted EBITDA of $3.7 million in 2Q2017
- Corporate, Argentina and Peru: Adjusted EBITDA of negative $5.5 million in 2Q2017
Production and Operating Costs = Operating Costs plus Royalties
|1||See “Reconciliation of Adjusted EBITDA to Profit (Loss) Before Income Tax and Adjusted EBITDA per Boe” included in this press release.|
The table below shows production, volumes sold and breakdown of the most significant components of Adjusted EBITDA for 2Q2017 and 2Q2016, on a per country and per barrel basis:
|Stock variation /RIKa||(1,047)||(876)||782||(338)||(209)||(227)||(474)||(1,441)|
|Sales volume (boepd)||19,968||13,208||3,232||3,780||2,449||2,714||25,649||19,702|
|($ per boe)|
|Realized oil price||32.3||24.8||43.0||39.5||54.9||48.0||33.4||26.4|
|Realized gas priceb||-||-||29.7||21.1||34.3||30.0||32.8||25.9|
|Commodity Risk Management Contracts||1.1||-||-||-||-||-||0.8||-|
|Royalties in cash||(2.6)||(1.1)||(1.7)||(1.2)||(3.1)||(2.8)||(2.5)||(1.4)|
|Selling & other expenses||0.0||(0.1)||(0.5)||(0.7)||-||-||(0.0)||(0.3)|
|a)||RIK (Royalties in Kind). Includes royalties paid in kind in Colombia for approximately 781 and 729 bopd in 2Q2017 and 2Q2016 respectively. No royalties were paid in kind in Chile and Brazil.|
|b)||Conversion rate of $mcf/$boe=1/6.|
Depreciation: Consolidated depreciation charges increased by 20% to $20.0 million in 2Q2017, compared to $16.6 million in 2Q2016, mainly due to increased sales volumes, partially offset by lower consolidated depreciation costs per boe. Depreciation costs per boe declined by 8% to $8.6 per boe.
Write-off of unsuccessful exploration efforts: Consolidated write-off of unsuccessful efforts amounted to $4.6 million in 2Q2017, compared to $0.4 million in 2Q2016. Amounts recorded in 2Q2017 mainly correspond to unsuccessful exploration efforts in Brazil and Colombia with two exploration wells, Praia do Espelho and Sinsonte, expensed during 2Q2017.
Other expenses: Other operating expenses amounted to $1.5 million in 2Q2017, compared to $0.6 million in 2Q2016.
CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD
Net financial expenses: Net financial costs slightly decreased to $7.4 million in 2Q2017, compared to $7.6 million in 2Q2016.
Foreign exchange: Net foreign exchange charges amounted to a $4.7 million loss in 2Q2017 compared to a $9.6 million gain in 2Q2016, mainly due to the depreciation and appreciation of the Brazilian Real in 2Q2017 and 2Q2016, respectively. Foreign exchange differences are mainly generated from changes in the value 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 expenses amounted to $4.8 million in 2Q2017, as compared to $6.3 million in 2Q2016, in line with lower profits before income tax in 2Q2017.
Net income: Net loss amounted to $1.1 million in 2Q2017 compared to a $1.6 million loss in 2Q2016.
Cash and cash equivalents: Cash and cash equivalents totaled $77.0 million as of June 30, 2017. Year-end 2016 cash and cash equivalents amounted to $73.6 million. The difference reflects cash used in investing activities of $49.4 million, cash used in financing activities of $25.0 million (made up of principal payments of $12.4 million primarily related to the Itau loan plus interest payments), and cash generated from operating activities of $79.1 million.
Prepayment facility and credit lines available: As of June 30, 2017, the Company had in place an offtake and prepayment agreement with Trafigura of up to $100 million (with $20.0 million drawn in 2016, of which $5.0 million were cancelled in 1H2017) and approximately $40 million in uncommitted credit lines.
Financial debt: Total financial debt (net of issuance costs) amounted to $346.3 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 $39.9 million.
|At period-end||Financial Debt||Cash and Cash Equivalents||Gross Debt / LTM Adj. EBITDA||Net Debtb/ LTM Adj. EBITDA||
|a)||Based on trailing 12-month financial results.|
|b)||Included for informational purposes only. Not included in the 2020 Bond Indenture.|
GeoPark’s consolidated financial incurrence test covenants included in the 2020 Bond Indenture are:
- A leverage ratio, defined as gross debt to Adjusted EBITDA, lower than 2.5x from 2015 onwards; and
- An interest coverage ratio, defined as Adjusted EBITDA divided by interest expenses, above 3.5x
As shown in the table above, as of June 30, 2017 the Company’s leverage ratio was above the 2.5x threshold included in the 2020 Bond Indenture, though the interest coverage ratio was above the 3.5x threshold included in the 2020 Bond Indenture. These ratios were impacted by lower oil prices since 2H2014. Failure to comply with the incurrence test ratios does not trigger an event of default. However, this situation may limit the Company’s capacity to incur additional indebtedness, other than permitted debt, as specified in the indenture governing the Notes. As opposed to maintenance covenants, incurrence covenants must be tested by the Company before incurring additional debt or performing other specific corporate actions including but not limited to dividend payments and restricted payments.
GeoPark deeply laments the passing of Peter Ryalls on July 25, 2017, a valued colleague and friend, who served on GeoPark's Board of Directors since 2006. Peter was a huge contributor to building the operational capabilities and strengths of GeoPark - and to making 'health and safety' a fundamental pillar of our long-term success. The GeoPark team is immensely thankful for Peter's very significant contributions.
SELECTED INFORMATION BY BUSINESS SEGMENT
|Revenue ($ million)||56.4||28.6|
|Production and Operating Costsa ($ million)||-15.4||-6.3|
|Adjusted EBITDA ($ million)||37.0||16.4|
|Capital Expendituresb ($ million)||18.9||4.9|
|Sale of crude oil ($ million)||7.7||5.5|
|Sale of gas ($ million)||3.4||4.3|
|Revenue ($ million)||11.1||9.8|
|Production and Operating Costsa ($ million)||-6.9||-5.5|
|Adjusted EBITDA ($ million)||1.9||2.2|
|Capital Expendituresb ($ million)||2.7||0.3|
|Sale of crude oil ($ million)||0.2||0.2|
|Sale of gas ($ million)||7.5||7.3|
|Revenue ($ million)||7.7||7.5|
|Production and Operating Costsa ($ million)||-2.9||-2.0|
|Adjusted EBITDA ($ million)||3.7||4.4|
|Capital Expendituresb ($ million)||1.0||0.9|
|a)||Production and Operating = Operating Costs + Royalties.|
|b)||The difference with the reported figure in Key Indicators table corresponds mainly to capital expenditures in Argentina.|
CONSOLIDATED STATEMENT OF INCOME
|(In millions of $)||2Q2017||2Q2016||1H2017||1H2016|
|Sale of crude oil||64.1||34.3||118.6||57.5|
|Sale of gas||11.1||11.6||23.3||25.0|
|Commodity risk management contracts||5.9||-||11.3||-|
|Production and operating costs||-25.3||-13.8||-42.9||-26.8|
|Geological and geophysical expenses (G&G)||-1.9||-2.9||-3.1||-5.3|
|Administrative expenses (G&A)||-12.0||-8.2||-20.5||-15.7|
|Write-off of unsuccessful efforts||-4.6||-0.4||-4.6||-0.4|
|Impairment for non-financial assets||-||-||-||-|
|OPERATING PROFIT (LOSS)||15.8||2.8||44.0||-8.4|
|Financial costs, net||-7.4||-7.6||-16.7||-16.6|
|Foreign exchange gain (loss)||-4.7||9.6||-1.8||17.0|
|PROFIT (LOSS) BEFORE INCOME TAX||3.7||4.7||25.5||-8.0|
|PROFIT (LOSS) FOR THE PERIOD||-1.1||-1.6||4.7||-13.7|
|ATTRIBUTABLE TO OWNERS OF GEOPARK||-3.4||-1.3||0.2||-10.6|
SUMMARIZED CONSOLIDATED STATEMENT OF FINANCIAL POSITION
|(In millions of $)||Jun '17||Dec '16|
|Property, plant and equipment||487.8||473.6|
|Other non-current assets||45.0||45.7|
|Total Non-Current Assets||532.8||519.3|
|Other current assets||37.3||25.7|
|Cash at bank and in hand||77.0||73.6|
|Total Current Assets||129.3||121.2|
|Equity attributable to owners of GeoPark||107.7||105.8|
|Other non-current liabilities||80.5||80.0|
|Total Non-Current Liabilities||395.1||399.4|
|Other current liabilities||87.1||60.2|
|Total Current Liabilities||118.9||99.5|
|Total Liabilities and Equity||662.0||640.5|
SUMMARIZED CONSOLIDATED STATEMENT OF CASH FLOWS
|(In millions of $)||2Q2017||2Q2016||1H2017||1H2016|
|Cash flows from operating activities||33.9||8.5||79.1||28.4|
|Cash flows used in investing activities||-25.9||-5.7||-49.4||-14.1|
|Cash flows (used) from in financing activities||-1.2||4.5||-25.0||-18.2|
RECONCILIATION OF ADJUSTED EBITDA TO PROFIT (LOSS) BEFORE INCOME TAX
|1H2017 (In millions of $)||Colombia||Chile||Brazil||Other||Total|
|Commodity Risk Management Contracts||9.1||-||-||-||9.1|
|Write-offs unsuccessful efforts||-1.6||-||-3.0||-||-4.6|
|Share Based Payments||-0.3||-0.2||-0.1||-1.5||-2.0|
|OPERATING PROFIT (LOSS)||65.2||-9.7||-0.7||-10.8||44.0|
|Financial costs, net||-16.7|
|Foreign Exchange charges, net||-1.8|
|PROFIT (LOSS) BEFORE INCOME TAX||25.5|
|1H2016 (In millions of $)||Colombia||Chile||Brazil||Other||Total|
|Commodity Risk Management Contracts||-||-||-||-||-|
|Write-offs unsuccessful efforts||-||-0.4||-||-||-0.4|
|Share Based Payments||-0.3||-0.2||-0.0||-0.3||-0.7|
|OPERATING PROFIT (LOSS)||8.2||-13.2||2.4||-5.9||-8.4|
|Financial costs, net||-16.6|
|Foreign Exchange charges, net||17.0|
|PROFIT (LOSS) BEFORE INCOME TAX||-8.0|
RECONCILIATION OF ADJUSTED LTM EBITDA TO PROFIT (LOSS) BEFORE INCOME TAX
|Last 12 Months - LTM (In millions of $)||Total|
|Commodity Risk Management Contracts||6.0|
|Write-offs unsuccessful efforts||-35.6|
|Share Based Payments/Other||-1.2|
|OPERATING PROFIT (LOSS)||23.8|
|Financial costs, net||-34.2|
|Foreign Exchange charges, net||-4.9|
|PROFIT (LOSS) BEFORE INCOME TAX||-15.3|
CONFERENCE CALL INFORMATION
GeoPark will host its Second Quarter 2017 Financial Results conference call and webcast on Thursday, August 17, 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 2Q2017, 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
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.
|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 sales volumes|
|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|
|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|
|PRMS||Petroleum Resources Management System|
|SPE||Society of Petroleum Engineers|
|NPV10||Present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual rate of 10%|
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.