karen iampen, repsol november 3 final - northeast gasrepsol ypf, s.a. “repsol” is the exclusive...
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ALL RIGHTS ARE RESERVED© REPSOL YPF, S.A. 2012
Repsol YPF, S.A. “Repsol” is the exclusive owner of this document. No part of this document may be reproduced (including photocopying), stored, duplicated, copied, distributed or introduced into a retrieval system of any nature or transmitted in any form or by any means without the prior written permission of Repsol.
This document does not constitute an offer or invitation to purchase or subscribe shares, in accordance with the provisions of the Spanish Securities Market Law (Law 24/1988, of July 28, as amended and restated) and its implementing regulations. In addition, this document does not constitute an offer of purchase, sale or exchange, or a request for an offer of purchase, sale or exchange of securities in any other jurisdiction.
Some of the resources mentioned in this document do not constitute proved reserves and will be recognized as such when they comply with the formal conditions required by the U. S. Securities and Exchange Commission.
This document contains statements that Repsol believes constitute forward-looking statements within the meaning of the US Private Securities Litigation Reform Act of 1995. These forward-looking statements may include statements regarding the intent, belief, or current expectations of Repsol and its management, including statements with respect to trends affecting Repsol’s financial condition, financial ratios, results of operations, business, strategy, geographic concentration, production volume and reserves, as well as Repsol’s plans, expectations or objectives with respect to capital expenditures, business, strategy, geographic concentration, costs savings, investments and dividend payout policies. These forward-looking statements may also include assumptions regarding future economic and other conditions, such as future crude oil and other prices, refining and marketing margins and exchange rates. These statements are not guarantees of futureperformance, prices, margins, exchange rates or other events and are subject to material risks, uncertainties, changes and other factors which may be beyond Repsol’scontrol or may be difficult to predict.
Repsol’s future financial condition, financial ratios, results of operations, business, strategy, geographic concentration, production volumes, reserves, capital expenditures, costs savings, investments and dividend payout policies, as well as future economic and other conditions, such as future crude oil and other prices, refining margins and exchange rates, could differ materially from those expressed or implied in any such forward-looking statements. Important factors that could cause such differences include, but are not limited to, oil, gas and other price fluctuations, supply and demand levels, currency fluctuations, exploration, drilling and production results, changes in reserves estimates, success in partnering with third parties, loss of market share, industry competition, environmental risks, physical risks, the risks of doing business in developing countries, legislative, tax, legal and regulatory developments, economic and financial market conditions in variouscountries and regions, political risks, wars and acts of terrorism, natural disasters, project delays or advancements and lack of approvals, as well as those factors described in the filings made by Repsol and its affiliates with the Comisión Nacional del Mercado de Valores in Spain, the Comisión Nacional de Valores in Argentina, and the Securities and Exchange Commission in the United States and with all the supervisory authorities of the markets where the securities issued by Repsol and/or its affiliates are admitted to trading. In light of the foregoing, the forward-looking statements included in this document may not occur. Repsol does not undertake to publicly update or revise these forward-looking statements even if experience or future changes make it clear that the projected performance, conditions or events expressed or implied therein will not be realized.
The information contained in the document has not been verified nor revised by the External Accountant Auditors of Repsol.
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DISCLAIMERForward Looking Statements
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DISCUSSION TOPICS
Repsol’s Northeast Assets Overview Key Price Risks – Near and Mid Term Weather and Demand Outlook East to West - Swing Molecule LNG Market Outlook 12 – 24 months Winter Strategy
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Canaport LNG• 1.0 Bcfd capacity • ~10 Bcf storage
Producer ServicesEnCana – Deep Panuke(Summer 2013 start-up)
Producer ServicesCorridor Resources – McCully
Field
Producer ServicesExxonMobil – Sable Island
M&NP U.S.730 MDth/d of capacity
Brunswick Pipeline•850 MDth/d of capacity
Pipeline Capacity LNG Regasification Gas Supply
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REPSOL ENERGY NORTH AMERICANortheast U.S. / Maritimes Canada Natural Gas Assets
Marcellus Production~500,000 Dth/d
Gas Production
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North America GasKey Price Risks – Near and Medium Term
On the immediate horizon, we are closely monitoring economic conditions, along with weather forecasts. U.S. Electric Generation loads
Renewable penetration – policies (CO2 Standards) and subsidies Questions regarding the timing and costs of new pipelines – adds to uncertainty surrounding
the composition of gas supply in 2017 and beyond
Natural gas Demand Growth, expecting over 10 Bcf/d of growth, primarily from LNG, power and exports to Mexico
Timing of Gas Supply Response Gas drilling yet to recover
Laws, regulations, mandates, rules, guidelines, plus “surprises”
TGP Possible Winter Scheduling Process Implemented during winter
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Northeast Gas Plant Additions
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Marcellus/Utica shale expected to realize 4 Bcf/d of new gas demand from new and developing plants
<= 500 MW> 500 & <= 1000 MW
> 1000 MW
Shale FormationUtica
Marcellus
Utica underlying Marcellus
PhaseOnline
Under Construction
In Development
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North America GasKey Price Risks – Near and Medium Term
U.S. is set to become a net LNG exporter in 2017 for the first time since 1955. Globally, annual capacity of liquefaction plants is on track to increase some 40% to 60 BCF/d by
2021
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Historical LNG PricingWinter 2004/2005 to 2015/2016The following indices provide a good indication of global LNG prices over the last decade. Before Fukushima, the Atlantic Basin LNG price generally correlated to NBP and HH. Post Fukushima, Atlantic Basin prices increased in order to compete with increased Asian demand and pricing.
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$-
$2.000
$4.000
$6.000
$8.000
$10.000
$12.000
$14.000
$16.000
$18.000
$20.000
$22.000
04/05 05/06 06/07 07/08 08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16
US
$/M
MB
tu
Winter [November – March]
NBP HH 14% Brent Japan Spot
Post-FukushimaPre-Fukushima Oil Price and
New LNG Supply
Sources: IHS CERA, Platts & ICE
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$-
$2.000
$4.000
$6.000
$8.000
$10.000
$12.000
$14.000
$16.000
$18.000
$20.000
$22.000
04/05 05/06 06/07 07/08 08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16
US
$/M
MB
tu
Winter (November – March)
AGT GDA (Nov-Mar) Atlantic Basin - low range Atlantic Basin - high range
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Post-FukushimaPre-Fukushima Oil Price and
New LNG Supply
Historical LNG PricingAtlantic Basin LNG Pricing vs. AGT CGThe price bands below represent the approximate price of Atlantic Basin LNG (November –March) relative to the Algonquin CG Gas Daily Average (November –March).
Sources: Platts & ICE
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Weather & Demand OutlookHistorical Context
2012/2013 Winter• A relatively average winter
• A combination of less backfeed gas supply and fast consumption of peaking fuel options (CLNG & Oil) led to consistently high pricing from mid-Jan through Mar.
• NE-ISO oil program wasn’t active
2013/2014 Winter• A very cold season for the
Northeast and the Eastern two thirds of North America.
• Every month was significantly colder than 5-year normal with the strongest anomaly during March.
• With limited (and expensive) LNG and excessive demand in Mid-Con, New England, and New York, prices peaked at record levels.
2014/2015 Winter• A cold season for New
England though the East in general was not that cold.
• Additional LNG availability and sendout from other terminals significantly reduced price volatility during the cold storms.
• NE-ISO oil program: 2.7M barrels burned for peak power
• Peak Price: $34.75
• Avg Dec – Feb GD Price: $11.22
• Peak Price: $73.03
• Avg Dec – Feb GD Price: $19.68
• Peak Price: $29.85
• Avg Dec – Feb GD Price: $10.89
2015/2016 Winter• Winter was very warm in
most parts of the country
• Godzilla El Nino produced one of the warmest winters on record
• Several regions including the NE set new records
• Peak Price: $8.00
• Avg Dec – Feb GD Price: $3.39
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Weather & Demand Outlook 16/17
Moderate to Weak La Nina WinterInitial models indicate a high probability of a neutral to weak La Nina.
Colder temps for the north central US and warmer for the South.
Fuel CompetitionLow global oil prices will create more peak power competition.
16/17 NE-ISO Oil Program similar to last year
RGGI prices are lower enabling more oil based power
DemandAIM start up November 3
Sabine Pass starts up Train 2 and Train 1 returns from maintenance ‘
Normal winter will return 6/bcf per day of demand in the US
Latest NOAA Winter CFC Model
Weak La Nina Winter Strong La Nina Winter
The models have been trending colder in the central US and NE
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East to West – Swing Molecule
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-
10,000,000
20,000,000
30,000,000
40,000,000
50,000,000
60,000,000
70,000,000
80,000,000
90,000,000
100,000,000
11/12 12/13 13/14 14/15 15/16
TBtu
East to West Supply (Dec – Feb)
Canada Production PNGTS CLNG Excelerate Everett
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LNG Market Outlook (12 - 24 Months)A slow recovering oil market paired with the planned incremental supply leads to a bearish view
Supply : • Atlantic supply from US and Angola LNG restart could total 23.2 mtpa of new supply • Sabine Trains 1 and 2 will be producing, with the start-up of Trains 3 and 4 scheduled for the 2nd half of 2017 • Australian start-ups could total 24.5 mtpa of new Pacific volume end of the year: Gorgon T1, T2 estimated by
Chevron by end 2016, Gorgon T3 (Q2 2017), Wheatstone (mid-2017), Ichthys (Q3 2017) • That being said two traditional LNG supplies to the Atlantic Basin are experiencing production issues : Nigeria
offline due to feedgas supply issues; Trinidad’s LNG production is also being affected by declining feedgas supply.
Demand: • Hydrology in the Americas: less rainfall in Chile and Brazil could affect demand in 2017 • New, so-called “organic” importers are expected to add incremental but limited demand: Colombia, Malta,
Jamaica, Ghana• Asia demand relatively flat with new Pacific supply coming online. Upcoming liberalization of Japan’s electricity
sector could throw utilities’ demand in flux • New Chinese terminals should be supplied by long-term contracts; Middle East demand mainly fulfilled by Qatari
supply via trading companies to Egypt, Pakistan • In Europe, Rough outage through March/April 2017 affecting NBP, TTF curves, but pipeline and Qatari term
cargoes could mitigate
Pricing: • Arbitrage opportunities have long vanished, companies now managing portfolio optimization • Buyers and sellers will still have to manage oil price volatility • US Henry Hub prices will set floor on production cost of US LNG but DES price risk will be managed by offtaker• In the US, basis risk will have to be managed by Cheniere for LNG exports, as well as LDC and industrial gas
consumers, depending on ramp up of pipeline exports to Mexico Source : ICIS Heren, LNG Americas Editor
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NorthEast 2016/2017
Winter StrategyBusiness as Usual We currently have ~ tanks full . Strategy for Winter 2016/2017 is to have sales obligations matched with pre-arranged supply
Near term pricing of LNG NBP (Atlantic Basin Price) $6.80 Jan, $6.90 Feb, $7.00 Mar AGT Jan range bound $7.50 - $7.60
Marketing Monday-Friday Gas product to go with ON PEAK power product to regional generators Lots of interest – spark spreads not cooperating
Long term strategy of peaking solution for a peaking problem Customer and industry meetings – lobbyists that challenge the status quo
Given the recent decline in worldwide LNG prices coupled with the abundant new LNG supply sources that will come on line in the next few years, LNG will remain a competitive and reliable gas supply source for New England and Maritimes Canada for the foreseeable future.
• Repsol has successfully provided winter peak gas supply services to the New England market for several years now, and it is poised to provide multi-year peaking services in lieu of expensive long-term (15+ year) pipeline expansions.