Corporate Presentation January 2016

Transcription

1 Corporate Presentation January 2016

2 CAUTIONARY STATEMENTS Certain information regarding the Company contained in this presentation, including our liquidity position, our business strategies, plans and objectives; our guidance for 2015 including our capital budget, production targets and anticipated product type weighting; expectations regarding our realized oil and natural gas prices; proposed exploration and development activities (including the number of wells to be drilled, completed and put on production); our drilling inventory; the timing of certain projects; future finding and development costs; asset disposition strategy; sources of capital, anticipated interest savings, debt repayment and the sufficiency of our financial resources to fund our operations may constitute forward-looking statements under applicable securities laws. The forward looking statements are based on certain key expectations and assumptions made by the Company, including, without limitation: that Lightstream will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes, the accuracy of the estimates of Lightstream s reserves and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate financing and cash flow to fund its planned expenditures. Although the Company believes that the expectations and assumptions on which the forward looking statements are based are reasonable, undue reliance should not be placed on the forward looking statements because the Company can give no assurance that they will prove to be correct. Since forward looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to commodity price and exchange rate fluctuations, the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), changes in the regulatory regime applicable to the Company and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Certain of these risks are set out in more detail in the Company's Annual Information Form which has been filed on SEDAR and can be accessed at The forward looking statements contained in this presentation are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. This presentation contains financial terms that are not considered measures under International Financial Reporting Standards ( IFRS ), which are considered to be generally accepted accounting principles ( GAAP ), such as EBITDA, funds flow from operations, total debt and operating netback. These measures are commonly utilized in the oil and gas industry and are considered informative for management and stakeholders. Specifically, EBITDA is defined as earnings before interest, taxes, depletion and depreciation, and other non-cash items. This measure is used to evaluate compliance with certain financial covenants. Funds flow from operations reflects cash generated from operating activities before changes in non-cash working capital. Management considers funds flow from operations important as it helps evaluate performance and demonstrate the ability to generate sufficient cash to fund future growth opportunities, pay dividends and repay debt. Total debt includes credit facility outstanding plus accounts payable less accounts receivable and prepaid expense plus the full value outstanding on the senior unsecured notes and convertible debentures converted to Canadian dollars at the exchange rate on the period end date less the value of long-term investments and is used to evaluate Lightstream s financial leverage. Profitability relative to commodity prices per unit of production is demonstrated by an operating netback. Operating netback reflects revenues less royalties, transportation costs, and production expenses divided by production for the period. EDITDA, funds flow from operations, net debt and operating netbacks may not be comparable to those reported by other companies nor should they be viewed as an alternative to cash flow from operations or other measures of financial performance calculated in accordance with IFRS. 2

3 OUR ASSET BASE Business Units Q3 Production (boepd) First Nine Months Production (boepd) Drilling Inventory (locations) Bakken 11,173 12,225 >1,050 Cardium 16,089 17,062 >460 AB / BC 2,993 3,161 >295 Total 30,255 32,448 >1,865 3

4 2015 CORPORATE STRATEGY Retain long-term value and preserve financial flexibility in the current low commodity price environment Operational Plan Suspension of monthly dividend Capital program of $100 - $120 million, funded by internally generated cash flow First nine months spending was $95 million Two wells from inventory put on production in Q Annual average production of 30,500 32,500 boepd Funds flow from operations of $175 $195 million at WTI of US$50.00/bbl 1 $75 million surplus cash to be applied to debt Strategy to potentially sell our Bakken business unit Proceeds would be used to transform our balance sheet and shift LTS into an Albertafocused company with a growth platform 1. WTI oil pricing assumption of $50/bbl for Q

5 2015 CAPITAL & DRILLING PROGRAM We have an attenuated second half operated drilling program given low commodity prices and current capital costs 2015 Planned Capital Activity Business Unit Net Wells DCET (million) Facilities (million) Workovers, Optimization & Other (million) Bakken 7 $21 $10 $7 Cardium AB/BC TOTAL 17 $70 $19 $22 In Q4 we drilled 1 net well, completed and brought 2 net wells on-stream, leaving 1 well in inventory 5

6 Amount ($'000,000) CAPITAL & FUNDS FLOW We expect to generate funds flow well above our capital spending in 2015 $ % $ % $ % $200 50% $0 1H 2H 1H 2H 1H 2H 1H 2H 1H 2H (e) Funds Flow Capital Expenditures* Cash Dividend Annual Outflows/Inflows (%) *Does not include A&D 0% 6

7 DEBT CAPITAL COMPOSITION DEBT AND LIQUIDITY Our second lien debt transactions in Q3 reduced overall debt Term Secured Debt $550 million Credit Facility 1 ~$200 million of available liquidity ~$350 million drawn (Q3 2015) Term subject to further extensions Term Secured 2 nd Lien US$650 million Notes 2 Second Lien Secured Notes (9.875% interest) Term Unsecured Debt US$254 million High Yield Notes 3 Senior Unsecured Notes (8.625% interest) MATURITY DATE The borrowing base of the credit facility is subject to re-determination on a semi-annual basis and contains a single financial covenant as described in our May 21, 2015 press release 2. See slide 8 for second lien overview 3. Original high yield issue of US$900 million. Current balance reflects total repurchases of US$100 million and debt exchanges and cancellations of US$546 million 7

8 SECOND LIEN OVERVIEW In Q3 we issued US$650mm of second lien notes with a semi-annual coupon of 9.875% US$546 million of senior unsecured notes exchanged for US$450 million of second lien notes Immediate debt reduction of ~$125 million 1 and annual interest savings of ~$3.4 million 1 Maturity date of June 15, 2019 US$200 million of second lien notes were issued for cash which was applied to reduce outstanding borrowing under our secured credit facility Liquidity initially increased to ~$395 million with borrowing base of $750 million Current liquidity is ~$200 million post November 2015 borrowing base redetermination of $550 million 1. Based on US$/Cdn$ exchange rate assumption of $0.77 8

9 Amount ('000) DEBT POSITION We have decreased our overall debt positon since 2012, with continuous access to an appropriate level of liquidity $1,500 $1,000 Total Debt Outstanding Forecasted 2015 year end debt reduced by $900 million 3 since 2013 $500 $ Credit Facility Drawn Credit Facility Available Convertible Debenture 2 Second Lien 2 Unsecured 2 Working Capital Deficit 1. Based on our $550 million credit facility effective November, Stated in $USD 3. Debt reduction based on Q financial results including debt exchanges and surplus cash generated in (e) 1 9

10 GUIDANCE Although we continue to restrict the amount of capital invested into new operated wells, we expect to remain within our guidance range for annual average production and exit production rates 2015 Guidance 2015 Actual First 9 Months Average Production (boe/d) 30,500 32,500 32,448 Exit Production (boe/d) 26,500 28,500 Liquids Weighting 73% 73% EBITDA $295,000 $315,000 $251,221 Funds Flow 1 Funds Flow from Operations (000) $175,000 $195,000 $163,540 Funds Flow per share $0.89 $0.99 $0.83 Annual Dividend per share $0.00 $0.00 Capital Expenditures (000) 2 $100,000 - $120,000 $94,646 Economic Parameters WTI oil price US$50.00/bbl 3 US$51.00/bbl Light oil wellhead price differential 15% 14% AECO gas price $3.00/mcf $2.81/mcf Foreign exchange rate (US$/Cdn$) Funds Flow per share calculation based on 197 million weighted average shares outstanding 2. Projected capital expenditures exclude acquisitions and divestitures, which are evaluated separately 3. Oil pricing assumption is US$50/bbl WTI for the fourth quarter of

11 Q NETBACKS & HEDGING EFFECTS In Q3 2015, we realized a gain of ~$25 million on crude oil derivative contracts, resulting in a netback of $30.94/boe Q3 Operating Netback Plus Commodity Hedges $40 $35 $30 $25 $20 $15 $10 $5 $0 VET WCP LTS PGF TOG BNP BTE CR TET ERF PWT BXE Operating Netback Realized Commodity Contract Hedges *Data from peer Q3 financial reports and is calculated using operating netback and realized gain (loss) on commodity derivative contracts 11

12 FUNDS FLOW PROTECTION Our 2015 crude oil hedge position helped provide funds flow downside protection We continue to build our 2016 hedge portfolio Commodity Oct Dec 2015 Oct Dec H H 2016 Light oil: WTI (bbl/d) Ceiling ($US/bbl) Floor ($US/bbl) Fixed Price Swap ($US/bbl) Light oil diff: Edm Sweet (bbl/d) WTI Edm Sweet ($US/bbl) Natural gas: AECO (mcf/d) Fixed Price Swap ($Cdn/Mcf) 4,289 $103 $80 1,500 N/A N/A $56 ~950 $3.01 2,500 N/A N/A $51 1,500 $3.62 ~4,740 $3.08 1,000 N/A N/A $50 1,500 $3.82 ~4,740 $3.08 We aim to hedge 25% - 50% of net production ~35% of net liquids production 1,2 hedged for the Q Typically hedge months out depending on market conditions Cash proceeds on crude oil derivative contracts for Q3 were ~$25 million 3 Estimated Cash Proceeds from Hedging for Q WTI Prices US$40/bbl US$45/bbl US$50/bbl US$55/bbl US$60/bbl Hedge proceeds 3 $23MM $19MM $16MM $13MM $9MM 1. Net production (less royalties of 15%), 73% liquids weighting 2. Based on mid-point of annual average production guidance and US$/Cdn$ exchange rate of $ All hedge proceeds stated in Cdn$ 12

13 ECONOMIC SENSITIVITIES Sensitivities and assumptions on remaining three months of 2015 on funds flow from operations Parameter Assumption Change of: Funds Flow Impact ($ millions) WTI Oil 1,2 US$50.00/bbl +/- $1.00 $1.2 Production (Q4 2015) 28,556 boepd +/- 1,000 $2.2 Natural Gas (AECO) 1 $3.00/mcf +/- $0.10 $0.4 Exchange Rate (US$) 1 $0.77 +/- $0.01 $ Oil price, natural gas price and exchange rate sensitivities include the impact of commodity hedges 2. Q WTI oil price assumption is US$50/bbl Our 2015 plans are based on funds flow from operations exceeding capital expenditures 13

14 $/boe CASH COSTS In this low commodity price environment, we have generated positive funds flow from operations $120 Quarterly Cash Costs and Oil Prices $100 $80 $60 $40 $20 $0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q Production Expenses Royalties Transportation G&A Interest WTI (USD) Edmonton Light Sweet(CAD) 14

15 BAKKEN ASSETS Focus on optimization and EOR Our assets produce light oil from the Bakken and the conventional Mississippian formations with a relatively low decline rate. In 2015 we continued to focus on optimizing and expanding our natural gas EOR projects in the Bakken. We have an extensive network of facilities that allows us to control operating costs. Business Unit Bakken 1 Results Q M 2015 Average Production (boepd) 11,173 12,225 Oil/Liquids Weighting 92% 93% Operating Income ($ million) Capex ($ million) 5 32 Free Cash Flow ($ million) P Reserves (mmboe) 69 Upside Opportunities 1 Undeveloped Land (sections) 259 LTS Land LTS Gas Plant LTS Batteries Sales Gas Pipelines Sales Oil Pipelines LTS Operated Wells EOR Wells Drilling Inventory (net locations) > 1, Includes conventional Mississippian 15

16 Calendar Day Oil (bbls) Number of Wells IMPROVING TIGHT OIL RECOVERIES Future value generation through natural gas flooding With Bakken EOR projects we expect to: Bakken Creelman Attenuate declines and extend production life Increase DPIIP recovery factors from 15% to potentially >25% Improve economic returns with high production-to-injector well ratios 13 section Creelman EOR Unit has been finalized 1 section Midale EOR Unit has been finalized 2 additional injection wells were placed on injection in Q Total of 7 wells are on gas injection in the Bakken 1 well shut in for monitoring Original Pattern EOR Performance Original injection well drilled and placed on primary production Natural Gas Injection commenced Original Injector On Injection LTS Operated Feb-08 Feb-09 Feb-10 Feb-11 Feb-12 Feb-13 Feb-14 Feb-15 EOR Benefit Primary Prod. From Inj. Well Base Production Producing well count 0 16

17 CARDIUM ASSETS Generating positive operating cash flow Our extensive land base stretches from southwest of Calgary to northwest of Edmonton and our assets primarily produce light oil from the Cardium formation. We are continuously evolving our drilling and completion techniques and we initiated water injection for EOR in July This is an active area for industry, with multizone potential. Business Unit Cardium Results Q M 2015 Average Production (boepd) 16,089 17,062 Oil/Liquids Weighting 57% 61% Operating Income ($ million) Capex ($ million) 7 60 Free Cash Flow ($ million) P Reserves (mmboe) 79 Upside Opportunities Undeveloped Land (sections) 122 Drilling Inventory (net locations) > 460 West West Pembina Pembina Brazeau Lochend LTS Land LTS Batteries Sales Gas Pipelines Sales Oil Pipelines LTS Operated Wells 17

18 Production (boepd) Net Wells on Production CARDIUM GROWTH 25,000 Cardium Production and Cumulative Well Count , , , , Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q Production (boepd) On-Stream Well Count 1. Production is after Q asset dispositions of 1,200 boepd 18

19 AB / BC ASSETS The Swan Hills provides us with another growth platform Production has grown to >2,500 boepd Available capacity in our 3,500 bopd battery Reserve bookings confirm long-term prospectivity Implementation of EOR water flood in early 2016 Business Unit AB / BC 1 Swan Hills Results Q M 2015 Q M 2015 LTS Land LTS Batteries Sales Oil Pipelines LTS Operated Wells Average Production (boepd) 2,993 3,161 1,987 2,106 Oil/Liquids Weighting 65% 66% 91% 92% Operating Income ($ million) Capex ($ million) Free Cash Flow ($ million) P Reserves (mmboe) 13 8 Upside Opportunities Undeveloped Land (sections) Drilling Inventory (net locations) > AB/BC includes Swan Hills 2. Capital expenditures reduced due to accrual reversals on seismic, drilling and equipping activities 19

20 Production (boepd) Net Wells on Production SWAN HILLS PRODUCTION Swan Hills production has increased our liquids weighting for the Alberta/BC business unit Swan Hills Production and Cumulative Well Count 5, , , , , Q1 '13 Q2 '13 Q3 '13 Q4 '13 Q1'14 Q2'14 Q3'14 Q4'14 Q1'15 Q2'15 Q3'15 Swan Hills Production AB/BC Production Swan Hills On-Stream Well Count * 0 *Reduced production levels due to third party facility turnaround, increased downtime 20

21 LONG-TERM WELL ECONOMICS We focus on well economics that reinforce our business model with quick payouts and strong capital efficiencies < 2 year capital payout > 2 recycle ratio Business Unit Type Well Bakken Business Unit Cardium Alberta/BC Bakken Mississippian Brazeau W. Pembina Falher Swan Hills Drill, Complete, Equip, Tie-in ($ million) Netback ($/boe) EUR (Mboe) F&D ($/boe) Recycle Ratio Payout (years) Net Locations (included in reserve report) Net Locations (with no reserves assigned) Assumptions: US $60/bbl WTI for first year and US$70/bbl thereafter, AECO gas price $3.00/Mcf, foreign exchange rate of US$/Cdn$ $0.75, light-oil weighted differential of US$8/bbl, before tax, excludes land costs Well counts are based on formation locations and are high graded to what we would drill today 1. Estimated capital costs based on the commodity price forecast environment 2. Internal estimates 21

22 LONG-TERM OPPORTUNITY EXTENSIVE ASSETS SUSTAINABILITY PRESERVE LONG TERM VALUE Drilling inventory of 10+ years Undeveloped land of ~ 527,000 acres 161 million boe of P reserves 2015 capital funded by cash flow Credit capacity helps preserve long term investment opportunities during current low commodity price environment 2014 reserve value significantly exceeds enterprise value Defer drilling of inventory until economic conditions improve 22

23 Trading Symbol LTS: TSX Share Price (January 4, 2016) $0.27 Market Capitalization $54 million Shares Outstanding (Sep 30, 2015 Basic) 198 MM Total Debt (Q3 2015) $1.60 billion Options/Incentive shares (Sep 30, 2015) 9.9 MM Enterprise Value $1.65 billion Shares Traded Daily (Q3 2015) 839 M EIGHTH AVENUE PLACE 2800, 525-8TH AVENUE SW CALGARY, ALBERTA T2P 1G1 (403)