INVESTOR UPDATE - Long Run Exploration

INVESTOR UPDATE
JANUARY 2015
1
LONG RUN PROFILE
Long Run Exploration is a Calgary‐based intermediate oil and natural gas company focused on light oil development and exploration in western Canada. Northern Gas
2,900 Boe/d
ALBERTA
BRITISH
COLUMBIA
Peace River Area
Montney
13,850 Boe/d
SASKATCHEWAN
Deep Basin Area
Cardium
11,150 Boe/d
• TSX: LRE
• Shares Outstanding: 193.5 million Redwater Area
Viking
8,200 Boe/d
• Dividend: $0.0175/ share/ month
• 2015 Production Guidance: 35,000 – 36,000 Boe/d (44% oil + NGLs) 2
CORPORATE STRATEGY
• Provide long‐term value to shareholders through a sustainable dividend model • Focus on operational efficiency and capital discipline
• Balance production between natural gas and oil
• Maintain balanced portfolio combining natural gas and oil; development, enhanced recovery and exploration
• Utilize horizontal drilling and completion techniques to improve pool recovery and enhance project economics
3
BUSINESS PLAN
Key inputs to a sustainable business model  Long‐term focus
 Extensive drilling inventory
 Target total payout ratio of 100% or less
 Enhanced oil recovery ~1,000 booked locations
 Low basic payout of 20% for 2015
SUSTAINABLE MODEL
STRONG ASSET BASE
Initiated in both Peace River and Redwater areas
 Corporate decline of 28%
Expected to further reduce over next 12 months
 Proactive hedging strategy ACTIVE FINANCIAL ~40% of oil & ~40% of natural gas production hedged for 2015
MANAGEMENT
 Focused capital discipline
Improve balance sheet through focused high‐grade development program and selective dispositions
BALANCED PORTFOLIO
 Balanced production mix
44% oil and NGLs for 2015
 Strong capital efficiencies
All‐in capital efficiency of $26,000/Boe
4
PRODUCTION PROFILE
Completed Deep Basin property acquisition (May 2014)
40,000
35,000
Completed Crocotta Energy Inc. acquisition (August 2014)
Production (Boe/d)
30,000
25,000
20,000
15,000
10,000
5,000
0
Q1 2014
Peace River Montney Property
Redwater
Viking Property
Q2 2014
Deep Basin
Cardium Property
Q3 2014
Northern Gas
Q4 2014 Estimate (1)
Minor Properties
Established new Deep Basin Cardium core area in 2014 through the Deep Basin property acquisition in May and the Crocotta Energy Inc. acquisition in August.
(1) Based on 2014 Guidance updated November 5, 2014
5
2015 CORPORATE GUIDANCE
2015 Guidance(1)
Production average (Boe/d)
% oil and NGLs
Funds flow from operations ($ million)(2)
• Based on WTI US$70/Bbl average for 2015, with an average of ~$60/Bbl in Q1 35,000 – 36,000
44
$200 ‐ $210
Net capital expenditures ($ million)(3)
$165
Dividends ($ million)(4)
$40
Dividend per share (annual)
$0.21
Basic payout ratio(2)(5)
20%
Total sustainability ratio(2)(5)
100%
• Funds flow includes average operating costs of $13.00/Boe and general and administrative costs of $2.75/Boe
• Target of 1,000 ‐ 4,000 Boe/d of divestitures to improve balance sheet (not included in Guidance)
• Dividend reinvestment plan (“DRIP”) participation excluded from forecasts
1) 2015 Guidance as released on December 15, 2014 is based on the following assumptions: WTI US$70.00/Bbl; AECO $3.50/GJ; FX USD/CDN 1.145. 2) See “Non‐GAAP Measures” section.
3) Net capital expenditures are calculated as capital expenditures net of acquisitions and divestitures. No acquisitions or divestitures are currently included in our budget. 4) Excluding impact of the DRIP.
5) Based on mid‐range of funds flow guidance, excluding impact of the DRIP.
6
DEVELOPMENT PLAN FOR 2015
Capital Expenditures (by area)
Capital Expenditures
≤15 wells
≤25 wells
Well Capital
$ Millions
$115
Plant & Facilities
$20
G&G, Land, HS&E
$30
TOTAL
$165
Deep Basin Cardium Property
Peace River Montney Property
Redwater Viking Property
G&G, Land, HS&E
7
DEVELOPMENT PLAN FOR 2015
Property Overview
Peace River Montney
Deep Basin
Pine Creek Cardium
$2.1
$3.0
$3.4
$1.2
$20,000
$17,200
$12,800
$34,300
IP 30 (Boe/d)(2)
190 334
413 72 % liquids
63
58
20
90
IP 365 (Boe/d) (2)
105
175
265 35 % liquids
63
40
20
90
190
(63% liquids)
225
(33% liquids) 365
(20% liquids)
40
(90% liquids)
On‐stream cost ($MM)(1)
12‐month capital efficiency (Boe/d)
Estimated ultimate recovery (MBoe)(2)
Deep Basin Kakwa Cardium
Redwater Viking
1) Estimated on‐stream costs are based on internal historical averages 2) Estimated initial well rates and ultimate recovery are based on internal type curve forecasts
8
DEVELOPMENT PLAN FOR 2015
By Property
$100
Capital Expenditures
Net operating income(1)
$ Million
$75
$50
$25
≤25
wells
≤15
wells
$0
Peace River Montney
Property
Deep Basin Cardium
Property
Redwater Viking
Property
Northern Gas
Minor Properties
1) Net operating income is calculated as revenues minus royalties, transportation costs and operating expenses
9
RISK MANAGEMENT
2015 Natural Gas Hedges
$100
60%
50%
60%
$4.00
50%
$3.80
$90
40%
30%
$80
$/Bbl
40%
$3.60
30%
$3.40
20%
20%
$70
10%
0%
$60
Q1
Q2
% of Production Hedged
Q3
Q4
Average Floor Price
10%
$3.20
0%
$3.00
Q1
Q2
% of Production Hedged
Q3
$/GJ
2015 Oil Hedges
Q4
Average Floor Price
• Long Run’s on‐going risk management philosophy is to hedge approximately 35% to 50% of our annual production volumes to mitigate commodity price volatility
• ~40% of oil and natural gas hedged for 2015
• Average hedge price floor of US$93.44/Bbl for oil, and $3.61/GJ for natural gas for 2015
10
2015 FORECAST SENSITIVITIES
Annual Base Assumption
+/‐ Impact ($ Million)
on 2015 Forecast
Sensitivity
WTI (USD/Bbl)
$70.00
+/‐
$1.00
=
$3.6
AECO (CAD/GJ)
$3.50
+/‐
$0.10
=
$3.0
Edmonton par (CAD)
$71.25
+/‐
$1.00
=
$3.6
USD/CDN FX
1.145
+/‐
$0.01
=
$3.0
Interest Rate
5.00%
+/‐
0.25%
=
$1.9
11
CAPITAL STRUCTURE
Share Capital:
• 193.5 million common shares outstanding
Debt Structure
(at September 30, 2014)
Credit Facility $632M
Unused Credit Capacity $63M
Convertible Debentures $75M
Credit Facilities:
• Long Run’s lending facilities total $695 million
• Financial requirements under the credit facilities relate to bank debt and total debt to trailing 12 month EBITDA and interest coverage(1)
Convertible Debentures:
• Issued $75 million of unsecured subordinated debentures in January 2014
• Bear interest of 6.40% annually
• Mature on January 31, 2019 and are convertible into common shares at a price of $7.40 per share
1) Further details on the calculations of the covenants can be found in the Company’s credit facility agreement filed on SEDAR at www.sedar.com on May 5, 2014, June 6, 2014 and August 25, 2014 under the Company’s profile.
12
DIVIDEND REINVESTMENT PLAN
• Long Run is implementing a Dividend Reinvestment Plan (“DRIP”)
• Proceeds from the DRIP will be used to support the capital program – No DRIP participation is currently included in our 2015 guidance
• Anticipate that the DRIP will be in place for the February 2015 dividend to be paid in March 2015
• Further information to be provided to shareholders at the end of January
13
PEACE RIVER MONTNEY
Normandville/Girouxville
• Montney horizontal oil development
• 950m vertical depth
• October 2014 estimated production of 11,100 Boe/d (60% oil and NGLs)
• Medium gravity oil (28o API)
• Significant owned and operated infrastructure in place
• Enhanced oil recovery commenced
Normandville
Normandville Oil Battery
• 5,000 bopd • 15 mmcf/d
12,000
Donnelly
Gas Plant
• 35 mmcf/d Girouxville
LRE Land
• 5,000 bopd • 15 mmcf/d
LRE HZ Montney Oil Wells
Average Production (Boe/d)
Girouxville Oil Battery
Production
10,000
8,000
6,000
4,000
61%
2,000
0
62%
57%
35%
2010
45%
2011
Oil
2012
2013
Natural Gas
2014
(8 months)
14
ENHANCED OIL RECOVERY (EOR)
Peace River Montney Property
• Good waterflood candidate for pressure support:
Normandville
• Large oil in place reservoir
• Good rock permeability of 10 ‐ 20 md
• EOR project at Normandville currently encompasses five sections
• Includes 16 horizontal producers, eight horizontal injection wells and one vertical injection well
• EOR project at Girouxville is planned to cover 1.5 sections • Includes six horizontal producers and four horizontal injection wells • Potential to improve recovery by an additional 5 ‐ 15% depending on waterflood pattern/success
Girouxville
LRE Land
Phase 1
LRE HZ Montney Oil Wells
Potential EOR Expansion
15
DEEP BASIN CARDIUM
Pine Creek/Edson
13‐09 LRE Battery/Compressor Station
• 6,500 boe/d (100%)
• Cardium horizontal light oil development
• 1,800m ‐ 1,900m vertical depth
• Bluesky horizontal liquids‐rich natural gas development
• 2,400m vertical depth
• October 2014 estimated production of 7,200 Boe/d (30% oil and NGLs)
• Significant owned and operated infrastructure in place
Pine Creek
13‐19 LRE Multiwell
Oil Battery
• 1,200 bbl/d
• 10.5 mmcf/d (97% WI)
Average Production (Boe/d)
10,000
01‐13 LRE Gas Plant
• 30 mmcf/d (97%)
16‐14 LRE Compressor Station • 20 mmcf/d (100%)
Edson
Talisman Gas Plant
• 400 mmcf/d (2.7% LRE WI)
LRE Land
Production
8,000
6,000
4,000
2,000
34%
32%
2012
2013
34%
LRE Wells
Recent LRE HZ Wells
0
30%
28%
2010
2011
Oil + NGLs
Natural Gas
2014
(8 months)
16
DEEP BASIN CARDIUM
Kakwa/Wapiti
• Cardium horizontal liquids‐rich natural gas
• 1,000m ‐ 1,600m vertical depth
• October 2014 estimated production of 3,950 Boe/d (30% liquids) • NGL content of 40‐50 Bbl/Mmcf
• First four wells have been successfully completed with initial results exceeding type curve expectations
Wapiti
Production
Kakwa
LRE Land
LRE Wells
Recent LRE HZ Wells
Average Production (Boe/d)
6,000
4,000
2,000
28%
29%
28%
28%
2011
2012
2013
2014
(8 months)
31%
0
2010
Oil + NGLs
Natural Gas
17
REDWATER VIKING
07‐21 Redwater North
Oil Battery
• 5,000 bbls/d • 4.0 mmcf/d
T58
Redwater
05‐17 Redwater North Compressor Station
• 4.5 mmcf/d
06‐11 Eastgate Gas Plant
• 1.0 mmcf/d
T56
05‐04 Redwater Central
Oil Battery
• 3,000 bbls/d • 1.0 mmcf/d
15‐07 Bruderheim North Oil Battery
• 2,000 bbls/d • 500 mcf/d
15‐24 Bruderheim South Oil Battery
• 3,000 bbls/d • 2.0 mmcf/d
6,000
Production
5,000
R21
LRE Land
R19W4
LRE Viking HZ Oil Wells
Average Production (Boe/d)
03‐31 Redwater Central
Oil Battery
• 2,000 bbls/d • 1.0 mmcf/d
• Viking horizontal oil development
• 700m vertical depth
• October 2014 estimated production of 4,700 Boe/d (85% liquids) • Light oil (38o API)
• Key infrastructure in place
• EOR commenced
4,000
3,000
89%
2,000
88%
86%
87%
1,000
79%
0
2010
2011
Oil
2012
Natural Gas
2013
2014
(8 months)
18
ENHANCED OIL RECOVERY
Redwater Viking Property
• Good waterflood candidate for pressure support:
• Large oil in place reservoir
• Good rock permeability of 10 ‐ 20 md
• Relatively uniform vertical and lateral rock properties
Redwater
• Initial pilot EOR project encompasses 0.5 sections in the north part of the field
• Includes three horizontal injection wells and five producer wells
• Second EOR pilot in the south part of the trend began in December 2014 and covers 0.625 sections
• Includes two horizontal injection wells, six horizontal producer wells and six vertical producers
LRE Land
LRE Viking HZ Oil Wells
Potential EOR Expansion
Phase 1
• Potential to improve recovery by an additional 10 ‐ 12% depending on waterflood pattern/success
19
NORTHERN GAS
Boyer
• Bluesky natural gas
• 200m ‐ 500m vertical depth
• October 2014 estimated production of 2,900 Boe/d (100% natural gas)
• Shallow decline (8%/year)
• 690,000 net acres
• Current drilling density less than 1.5 wells per section under vertical development. Potential exists for horizontal development
• 70 MMcf/d of additional operated processing capacity available
Average Production (Boe/d)
5,000
LRE Land
Production
4,000
3,000
2,000
1,000
LRE Wells
0
2010
2011
2012
Natural Gas
2013
2014
(8 months)
20
LONG RUN KEY VALUE DRIVERS
• Deliver a focused capital program targeting total corporate sustainability ratio of 100% or less
• Continue to exploit our balanced portfolio of properties through development, enhanced recovery and exploration • Provide long‐term value to shareholders through capital discipline and operational execution
21
SUPPLEMENTAL INFORMATION
22
ENHANCED OIL RECOVERY (EOR)
Waterflood
Current Waterflood Pilots
• Major oil projects under early stage waterflood
Area
Formation
Pilot Start Date
Expansion Start Date
# of Injectors
Normandville
Montney
May 1, 2013
December 8, 2014
9
This initial phase of EOR covers five sections
Girouxville
Montney
October 24, 2013
January 2015
4
This initial phase of EOR covers 1.5 sections
Redwater
Viking
December 9, 2013
December 8,
2014
5
Comments
Expansion consists of a second pilot in the southern portion of the Redwater field • Cost effective reserve additions
• Increases recovery
• Lowers finding & development costs
• Uses existing land base
• Moderates production declines
• Stabilizes production rates
• Source of free funds flow
23
Natural Gas
Crude Oil
RISK MANAGEMENT
Costless Collars
Volume Pricing
January 1, 2015 – December 31, 2015
2,500 Bbl/day
WTI US $95.00 ‐ $97.50/ Bbl
Fixed Price
Volume
Pricing
January 1, 2015 – April 30, 2015
1,000 Bbl/d
WTI US $85.00/Bbl
January 1, 2015 – April 30, 2015
1,000 Bbl/d
WTI US $90.00/Bbl
Calls
Volume
Pricing
January 1, 2015 – December 31, 2015
500 Bbl/d
WTI US $85.00/Bbl Costless Collars
Volume
Pricing
January 1, 2015– March 31, 2015
13,000 GJ/day
CDN $3.50‐$3.75/GJ
January 1, 2015 – December 31, 2015
5,000 GJ/day
CDN $4.00‐$4.50/GJ
January 1, 2015 – December 31, 2015 5,000 GJ/day
CDN $4.00‐$4.51/GJ
January 1, 2015 – December 31, 2015
20,000 GJ/day
CDN $3.50‐$4.00/GJ
January 1, 2015 – December 31, 2015
11,000 GJ/day
CDN $3.50‐$4.35/GJ
• Financial hedges mitigate risk associated with commodity price volatility
• Improves predictability of funds flow
• Current oil production hedges: • ~50% hedged for Q1 2015
• ~40% hedged for full year 2015
• Current natural gas production hedges: • ~45% hedged Q1 2015
• ~40% hedged for full year 2015
24
NETBACKS BY AREA
Peace River Area
Deep Basin Area
Redwater
Area
13,850
11,150
8,200
2,900
38,250
% Liquids
55%
30%
60%
‐
45%
Oil Quality
28° API
42° API
38° API
‐
32° API
October 2014 Estimated Production Northern Gas Total
(Boe/d)
September Field Netback ($/Boe)(1)
Price
($/Mcf)
$ 54.82
$ 34.18
$ 63.41
$ 23.00
$ 3.83
$49.81
(6.72)
(4.29)
(7.52)
(0.71)
(0.12)
(5.96)
Operating Costs
(15.44)
(6.68)
(12.16)
(7.36)
(1.23)
(12.83)
Transportation
(2.70)
(1.22)
(1.74)
(2.24)
(0.37)
(1.94)
$ 29.96
$ 21.99
$ 41.99
$ 12.69
$ 2.11
$ 29.08(1)(2)
Royalty
1) See “Netbacks” under the Advisories
2) Excluding realized financial hedging gains/losses
25
TAX POOLS
Tax Pools
Annual Deduction
$ Millions
Up to approximately 25%
$370
Canadian Oil & Gas Property Expense (COGPE)
Up to 10%
$440
Canadian Development Expense (CDE)
Up to 30%
$630
Up to 100%
$150
Deducted against taxable income
$250
Undepreciated Capital Cost (UCC)
Canadian Exploration Expense (CEE)
Non‐Capital Loss Carry Forward Estimated Total Corporate Tax Pools (at September 30, 2014)
$1,840
26
BANK SYNDICATE
Bank of Nova Scotia National Bank of Canada The Toronto‐Dominion Bank
HSBC Bank Canada
Wells Fargo Bank, N.A., Canadian Branch
Canadian Imperial Bank of Commerce
Alberta Treasury Branches Union Bank, Canada Branch
United Overseas Bank Limited
Bank of Montreal Business Development Bank of Canada
27
CORPORATE INFORMATION
TSX:LRE
Contacts
Bill Andrew
Chair & CEO
(403) 261‐6012
Dale Miller
President & COO
(403) 261‐6012
Corine Bushfield
Senior Vice President & CFO
(403) 261‐6012
Dale Orton
Senior Vice President, Development
(403) 261‐6012
Lauren Kimak
Investor Relations
(403) 716‐3222
1‐888‐598‐1330
Main: Toll‐Free Investor Line:
Email: Web:
403‐261‐6012
1‐888‐598‐1330
[email protected]
www.longrunexploration.com
28
ADVISORIES
Forward Looking Statements: This document contains forward‐looking statements and forward‐looking information (collectively "forward‐looking information") within the meaning of applicable securities laws relating to the Company's plans and other aspects of Long Run's anticipated future operations, management focus, objectives, corporate strategies and business plan, financial, operating and production results and opportunities including 2015 guidance including average production, commodity mix, funds flow from operations, total dividends and dividends per share (annual), basic payout ratio and total sustainability ratio; and assumptions relating to such guidance, including 2015 average operating costs and general and administrative costs; expectation that corporate decline rate will reduce during 2015; plans to divest up to 4,000 Boe/d; plans to institute a dividend reinvestment plan and the timing thereof; estimated results of development plan for 2015, including anticipated initial production rates, commodity mix, 12‐month capital efficiencies, and estimated ultimate recovery; 2015 forecast sensitivities; and timing of the commencement of various enhanced oil recovery operations and the anticipated impact on operations.
Forward‐looking information typically uses words such as "anticipate", "believe", "project", "expect", "goal", "plan", "intend" or similar words suggesting future outcomes, statements that actions, events or conditions "may", "would", "could" or "will" be taken or occur in the future. The forward‐looking information is based on certain key expectations and assumptions made by Long Run's management, including expectations and assumptions concerning prevailing commodity prices, exchange rates, interest rates, applicable royalty rates and tax laws; future production rates and estimates of operating costs; performance of existing and future wells; reserve and resource volumes; anticipated timing and results of capital expenditures; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the state of the economy and the exploration and production business; results of operations; performance; business prospects and opportunities; the availability and cost of financing, labor and services; the impact of increasing competition; ability to market oil and natural gas successfully; and Long Run's ability to access capital. Although the Company believes that the expectations and assumptions on which such forward‐looking information is based are reasonable, undue reliance should not be placed on the forward‐looking information because Long Run can give no assurance that they will prove to be correct. Since forward‐looking information addresses future events and conditions, by its very nature they involve inherent risks and uncertainties. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward‐looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward‐looking information will transpire or occur, or if any of them do so, what benefits that the Company will derive there from. Management has included the above summary of assumptions and risks related to forward‐looking information provided in this corporate presentation in order to provide shareholders and potential investors with a more complete perspective on Long Run's future operations and such information may not be appropriate for other purposes. Readers are cautioned that the foregoing lists of risks and factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).
Included herein are estimates of Long Run's 2015 funds flow from operations, total dividends and total dividends per share, basic payout ratio and total sustainability ratio based on assumptions provided herein and other assumptions utilized in arriving at Long Run's capital budget. To the extent such estimates constitute a financial outlook, they were approved by management on December 15, 2014 and are included herein to provide readers with an understanding of the effects of the anticipated funds available to Long Run to fund its capital expenditures, dividends and the effects thereof and readers are cautioned that the information may not be appropriate for other purposes.
29
ADVISORIES
Statements relating to "reserves" are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estimates provided herein. These forward‐looking statements are made as of the date of this document and Long Run disclaims any intent or obligation to update publicly any forward‐
looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. BOE:
"Boe" means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1 Bbl, utilizing a conversion ratio at 6 mcf: 1 Bbl may be misleading as an indication of value. Initial Production Rates and Type Curves:
Initial production rates disclosed herein may not necessarily be indicative of long‐term performance or ultimate recovery. Type curves presented herein are not necessarily reflective of the performance of future wells.
Dividends:
The payment and the amount of dividends declared in any month is subject to the discretion of the board of directors of the Company and will depend on the board of director's assessment of Long Run's outlook for growth, capital expenditure requirements, funds from operation, potential acquisition opportunities, debt position and other conditions that the board of directors may consider relevant at such future time. The amount of future cash dividends, if any, may also vary depending on a variety of factors, including fluctuations in commodity prices.
Non‐GAAP Measures:
This document contains terms commonly used in the oil and gas industry, such as funds flow from operations, basic payout ratio and total sustainability ratio. These terms are not defined by International Financial Reporting Standards (IFRS) and should not be considered an alternative to, or more meaningful than, cash provided by operating activities or net earnings as determined in accordance with IFRS as an indicator of Long Run's performance. These measures are commonly used in the oil and gas industry and by Long Run to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations. Long Run's determination of these measures may not be comparable to that reported by other companies. Funds flow from operations is calculated as cash flow from operating activities before changes in non‐
cash working capital and abandonment expenditures. Basic payout ratio is calculated by dividing dividends by funds flow from operations. Total sustainability ratio is defined as net capital expenditures plus dividends divided by funds flow from operations. Long Run has provided information on how these measures are calculated in the Management’s Discussion and Analysis for the three and nine months ended September 30, 2014 dated November 5, 2014, which is available under the Company’s SEDAR profile at www.sedar.com.
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