November 10, 2017 - 6:30 AM EST
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Obsidian Energy Announces Strong Third Quarter Results and 2018 Budget

Canada NewsWire

CALGARY, Nov. 10, 2017 /CNW/ - OBSIDIAN ENERGY LTD. (TSX/NYSE – OBE) ("Obsidian Energy", the "Company", "we", "us" or "our") is pleased to announce its financial and operational results for the third quarter ended September 30, 2017 and 2018 Budget. All figures are in Canadian dollars unless otherwise stated.

David French, President & CEO commented, "I am quite proud of the Obsidian Energy team in the third quarter, successfully executing our busiest drilling campaign in years and generating quality results across our key development areas. We are excited about the outlook for the Company and determined to continue operational delivery into 2018.

Deep Basin results are liquids rich and wells are flowing strong while choked back

We are encouraged with the results of our first foray into the Deep Basin. Our three Mannville wells are producing a combined 2,000 boe per day with average liquids rates of approximately 60 bbl per mmcf. These liquid yields are substantially above expectations and improve the already attractive play economics. We look forward to further 2018 development.

The Q3 program is beating forecast and reaffirms production guidance

Second half projects in the Cardium, Alberta Viking, and Peace River are delivering strong rates and reinforcing the value of our disciplined project funding and execution. As a result of production management and new well delivery, we are forecasting full year 2017 production at the high end of our 30,500 – 31,500 boe per day guidance range.

Waterflood performance is impressive

Waterflood investment is starting to bear fruit with meaningful decline mitigation across our Cardium assets. The base decline in our total Cardium business is only five percent year to date resulting from waterflood and base optimization projects initiated in 2016.

2018 delivers five percent growth at 80 percent reinvestment

We anticipate five percent production growth in 2018 while investing only 80 percent of Funds Flow from Operations. We have the operational flexibility and drill ready prospects to deliver north of five percent by adjusting our second half program as commodity prices allow. We have clear downside protection and growth confidence through our robust hedge book. Our Board has approved a $135 million 2018 budget which leverages the primary drilling opportunity set within our portfolio. We have targeted our capital to be short cycle focused while maintaining our base decline rate through efficient, low cost waterflood management.

Our 2018 plan offers a solid and scalable liquids weighted growth profile, and the third quarter and 2018 outlook are great signs for what is ahead of us as a Company."

Financial and Operating Highlights





Three months ended September 30

Nine months ended September 30


2017

2016

% change

2017

2016

% change

Financial (millions, except per share amounts)









Gross revenues (1,2)

$

98

$

136

(28)

$

341

$

576

(41)

Funds flow from operations (2)


40


32

25


140


134

4


Basic per share (2)


0.08


0.06

33


0.28


0.27

4


Diluted per share (2)


0.08


0.06

33


0.28


0.27

4

Net loss


(44)


(232)

(81)


(26)


(464)

(94)


Basic per share


(0.09)


(0.46)

(80)


(0.05)


(0.92)

(95)


Diluted per share


(0.09)


(0.46)

(80)


(0.05)


(0.92)

(95)

Capital expenditures (3)


55


13

  >100


105


32

>100

Net Debt (2,4)

$

410

$

484

(15)

$

410

$

484

(15)












Operations











Daily production












Light oil and NGL (bbls/d)


13,324


17,644

(24)


14,218


29,502

(52)


Heavy oil (bbls/d)


5,456


5,711

(4)


5,434


9,844

(45)


Natural gas (mmcf/d)


68


107

(36)


73


127

(43)

Total production (boe/d) (5)


30,166


41,233

(27)


31,816


60,533

(47)

Average sales price












Light oil and NGL (per bbl)

$

51.06

$

47.01

9

$

54.85

$

42.20

30


Heavy oil (per bbl)


30.36


21.67

40


31.69


20.12

58


Natural gas (per mcf)

$

2.35

$

2.46

(4)

$

2.91

$

1.92

52

Netback per boe (5)












Sales price

$

33.37

$

29.50

13

$

36.60

$

27.86

31


Risk management gain


2.24


5.58

(60)


2.69


5.19

(48)


Net sales price


35.61


35.08

2


39.29


33.05

19


Royalties


(2.27)


(1.63)

39


(2.54)


(1.04)

>100


Operating expenses (6)


(12.26)


(13.40)

(9)


(13.70)


(12.99)

5


Transportation


(2.38)


(1.71)

39


(2.50)


(1.74)

44


Netback (2)

$

18.70

$

18.34

2

$

20.55

$

17.28

19



(1)

Includes realized gains and losses on commodity contracts.

(2)

The terms "gross revenues", "funds flow from operations" and their applicable per share amounts, "netback", and "net debt" are non-GAAP measures. Please refer to the "Non-GAAP Measures" advisory section below for further details.

(3)

Includes the benefit of capital carried by partners.

(4)

Net debt includes long-term debt and includes the effects of working capital and all cash held on hand.

(5)

Please refer to the "Oil and Gas Information Advisory" section below for information regarding the term "boe".

(6)

Includes the benefit of carried operating expenses from its partner under the Peace River Oil Partnership of $5 million or $1.79 per boe (2016 – $4 million or $1.04 per boe) for the three months ended and $15 million or $1.75 per boe (2016 – $11 million or $0.66 per boe) for the nine months ended on a combined basis.

  • Funds Flow from Operations for the third quarter was $40 million, reflecting lower realized pricing due to a decrease in the CAD/USD exchange rate, which was partially offset by lower operating costs.

  • Average liquids sales prices were $45.05 per boe and average natural gas sales prices were $2.35 per mcf. Realized natural gas prices were at a premium to AECO in the quarter, resulting from a portion of our volumes marketed at alternative sales points. We expect our gas realizations to maintain a slight premium to AECO through 2018.

  • Third quarter operating costs were $12.26 per boe, net of carried expenses. As expected, operating costs were lower than the second quarter of 2017 due to lower maintenance and turnaround activity. We continue to target annual 2017 operating costs of approximately $13.00 to $13.50 per boe, net of carried expenses.

  • Invested $55 million of capital expenditures across our key development areas and remain on track to meet full year 2017 capital guidance.

  • Total Net Debt was approximately $410 million at the end of the third quarter, including $251 million drawn on our $410 million revolving credit facility and $113 million of Senior Notes.

  • Realized $2.24 per boe of realized commodity gains in the quarter, driven by our strong crude oil and natural gas swap positions.

Production Update

Average corporate production for the third quarter was 30,166 boe per day, consistent with the second quarter of 2017.

Base production continues to exceed expectations, driven by continued waterflood response across our Cardium acreage and reliability of our base infrastructure and gathering systems. We ran a successful campaign this year to optimize existing wellbores, which has contributed nearly 800 boe per day to our base production. The Company did not encounter any meaningful production impact resulting from the third-party service restrictions in the quarter.

The table below outlines select metrics in our key development and legacy areas for the three months ended September 30, 2017 and excludes the impact of hedging:



Area

Select Metrics – Three Months Ended September 30, 2017

Production

Liquids
Weighting

Operating
Cost

Netback

Cardium

18,876 boe/d

64%

$13/boe

$20/boe

Alberta Viking

1,766 boe/d

49%

$7/boe

$22/boe

Peace River(1)

4,823 boe/d

99%

$2/boe

$23/boe

Key Development Areas(2)

25,465 boe/d

69%

$10/boe

$21/boe

Legacy Areas

4,701 boe/d

23%

$22/boe

($3)/boe

Key Development & Legacy Area

30,166 boe/d

62%

$12/boe

$19/boe


(1)  Net of carried operating costs.

(2)  Deep Basin results for the quarter were negligible, and therefore included within the Cardium metrics.

Cardium Drilling Update

Our three well horizontal pad in PCU #9 came on production in October, and early rate indications are above type curve, currently producing nearly 200 boe per day, per well. We are currently drilling our four horizontal producers in Willesden Green and expect the pad to turn over to production prior to year-end.

We continue to see positive indications of Gas Oil Ratio ("GOR") suppression and decline mitigation in our Cardium development area. Our decline rate has shallowed to approximately five percent this year, from approximately 20 percent in 2016. The observed oil rate decline shallowing is driven by our low-cost waterflood optimization and base management projects that began in the third quarter of 2016.

Alberta Viking Drilling Update

Our 10 well Alberta Viking program continues to exceed expectations, with initial production results confirming early flowback rates. All 10 wells are on production, including the 100/2-18 well with a peak IP of 704 boe per day and producing day IP30 of 295 boe per day. We continue to evolve our development strategy in the area to enhance overall economics; including trucking clean oil through design change at our multi-well batteries and optimizing stage count to maximize capital efficiency.

Peace River Drilling Update

Our second half 2017 Peace River program returned to the heart of the Harmon Valley South field, and preliminary results of the program are encouraging. Daily total production from the first nine wells of our second half 2017 program is currently averaging approximately 190 boe per day, per well. At present, 10 of 12 second half wells are on production, and two under facility construction. Obsidian Energy set another record in the third quarter for meters drilled with a single bit and bottom hole assembly, whereby we drilled 17,278 meters of open hole for an overall cost of $76 per meter drilled.

Deep Basin Drilling Update

We successfully drilled our three well Mannville program in the third quarter, with one well on production as of September 30, 2017 and the remaining two wells by the end of October. This is the Company's first foray into our significant Deep Basin position and we designed a program that tests different Upper Mannville targets. The overall program is delivering value meaningfully ahead of expectations, driven by significant initial liquids rates and high pressure from the second and third wells in the program. While the first well encountered lower permeability and pressure than expected, our second and third wells moved to a high-pressure portion of the reservoir and have significant initial liquids rates. These wells are showing free condensate rates of 35 bbl per mmcf and overall liquids rates of 60 bbl per mmcf, more than double type curve expectations. We estimate the value uptick from the strong liquids rates will increase rates of return by approximately 20 percent. We are maximizing the liquids potential of these wells by utilizing a down-hole choke mechanism to stabilize gas rates at approximately 4,000 mcf per day. Our average working interest on these wells is 80 percent.

The table below provides a summary of our operated activity in the third quarter.



Number of Wells Q3 2017


Drilled

Completed

On production


Gross

Net

Gross

Net

Gross

Net

Cardium








Producer

4

3.7

3

2.7

0

0.0


Injector

5

4.5

0

0.0

5

5.0

Mannville

3

2.4

3

2.4

1

0.7

Alberta Viking

6

6.0

10

10.0

6

6.0

Peace River

8

4.4

7

3.9

7

3.9

Total

26

21.0

23

19.0

19

15.6

Updated Hedging Position

We continued our active hedging program and began to extend our hedge book into the second quarter of 2019. We also took advantage of the October decline in the CAD relative to the USD and hedged approximately two thirds of our foreign exchange exposure on our 2018 USD WTI hedges.

Our liquids exposure, net of royalties, is hedged approximately 65 percent through 2018 and our natural gas exposure, net of royalties, is hedged approximately 40 percent through the end of 2018. We have expanded our 2018 hedge volumes to capitalize on recent price improvements that support a fully funded 2018 capital program.

Currently, the Company has the following crude oil hedges in place:


Q4 2017

Q1 2018

Q2 2018

Q3 2018

Q4 2018

Q1 2019

Q2 2019


WTI $USD

-

$50.82

$50.00

$50.05

$49.78

$50.02

-



bbl/day

-

7,000

7,000

8,000

8,000

3,000

-


WTI $CAD

$67.70

$71.03

$71.03

$71.04

$71.04

$66.90

$67.30



bbl/day

7,900

5,000

5,000

4,000

4,000

4,000

2,000


Total










bbl/day

7,900

12,000

12,000

12,000

12,000

7,000

2,000

Additionally, the Company has the following foreign exchange contracts in place for 2018:

  • Foreign exchange swaps at an average of 1.261 on notional US$6 million per month 
  • Foreign exchange collar at an average of 1.210 – 1.272 on notional US$2 million per month

Currently, the Company has the following natural gas hedges in place:


Q4 2017

Q1 2018

Q2 2018

Q3 2018

Q4 2018


AECO $CAD

$3.00

$2.83

$2.72

$2.67

$2.67



mcf/day

20,900

28,400

22,700

17,100

15,200


Ventura $USD (1)

-

$2.79

$2.79

$2.79

$2.79



mcf/day

-

7,500

7,500

7,500

7,500


Total








mcf/day

20,900

35,900

30,200

24,600

22,700

(1)

Until the third quarter of 2020, the Company has an agreement in place to sell 15 mmcf per day at the Ventura index price less the cost of transportation from AECO.
Recent transportation deductions for the Company to bring product to the Ventura market have been approximately $0.55 per mcf. 

Disposition Highlights Subsequent to the Third Quarter

The Company entered into an agreement in late October for the sale of our royalty interests in Eastern Alberta for $40 million. The transaction capitalizes on the premium valuation associated with royalty assets and puts us in a solid liquidity position heading into 2018. Proceeds from the transaction will be used to reduce borrowings on our syndicated credit facility and therefore has a neutral effect on 2018 Funds Flow from Operations. Key metrics associated with the assets are as follows (1):

Production

181 boe per day

Implied Production Multiple

$221,000 per boe per day

Net Operating Income (NOI)

$2.7 million

Implied NOI Multiple

15x

(1)

Based on lease operating statements for the twelve months prior to the effective date

This royalty interest transaction is expected to close prior to the end of 2017 and is subject to closing adjustments customary in transactions of this nature.

2017 Guidance

We remain confident in our ability to demonstrate self-funded double-digit percent growth from the fourth quarter of 2016 to the fourth quarter of 2017, adjusted for A&D, and believe production will be near the high end of our full year 2017 guidance of 30,500 – 31,500 boe per day.


2017 Annual Guidance

Production

30,500 to 31,500 boe per day

Operating Costs, net of carried expenses(1)

$13.00 to $13.50 per boe



E&D Capital Expenditures

$145 million

Decommissioning Expenditures

$15 million

Total Capital Expenditures

$160 million

(1)

Net of carried operating expenses from the Company's partner under the Peace River Oil Partnership.

2018 Outlook

We are excited about the outlook for the Company, which combines a predictable, low decline asset base with a robust development opportunity set. Our extensive portfolio optionality allows us to shift capital allocation in response to various commodity price scenarios and deliver a returns focused capital program entirely supported by Funds Flow from Operations.

We plan to deliver approximately five percent production growth relative to full year 2017, adjusted for 2017 A&D activity. This will be accomplished by continuing our second half 2017 momentum, drilling producing wells through the first quarter of 2018. Our 2018 program is approximately 60 percent weighted to first half of 2018 and we maintain the operational flexibility to accelerate spending based on the commodity price outlook within the year. Furthermore, our hedge position provides certainty to our cash flow outlook whereby our capital program can withstand more than a 10 percent decline in Canadian dollar realized oil and gas pricing relative to current strip prices before exceeding our Funds Flow from Operations.

Our 2018 capital investment of $135 million includes $86 million associated with development and existing wellbore optimization, $25 million of infrastructure and corporate capital, $10 million of decommissioning expenditures and $14 million of capital associated with meeting the AER Directive 84 requirements for Hydrocarbon Emission Controls and Gas Conservation in the Peace River area. We are on track to meet the AER requirements and the Company will gather, process, and sell natural gas from its Peace River operations beginning in September 2018. We do not expect a material cash flow stream from natural gas in this area.

Our 2018 plans have an increased focus on shorter cycle opportunities within our portfolio. Our development capital program is approximately 50 percent weighted to the Cardium, employing a quicker payout program that balances primary drilling with targeted low capital integrated waterflood opportunities. The remainder of our development capital program has allocations of 10-15 percent each between our Deep Basin, Alberta Viking and Peace River Assets, and an additional 15 percent to capital efficient volume optimization of existing wellbores throughout our key development areas. The projected capital efficiency of our 2018 Development capital is approximately $15,000 per boe per day, based on the 12 month forward production associated with each project.

Cardium Development

We plan to spend approximately $44 million to develop our high netback, low decline Cardium asset, drilling eight horizontal producers (gross operated wells) amongst our Pembina and Willesden Green assets. Continuing our approach from the last several years, we place our horizontal wells in the bioturbated rock just below the upper good quality reservoir to ensure we access both reserves in the cleaner intervals, as well as tapping into undrained reservoir in the lower bioturbated interval. Six of our horizontal wells are in Pembina and two are in Willesden Green.

Additionally, we expect to spend approximately $5 million on integrated waterflood and optimization opportunities. This includes supporting our Pembina drills with inexpensive conversions of low producing vertical wells to injection, rather than new drills, employing a hybrid approach between our Type I & Type IV waterflood inventory. Our Cardium budget will also allocate approximately $12 million to Non-Operated primary drilling by our working interest partners in the area, and $4 million to land consolidation opportunities and seismic data. This shorter cycle focused Cardium program limits spending on new injection while still optimizing our waterflood fields and mitigating decline on horizontal wells.

Deep Basin Development

We plan to spend approximately $11 million to continue development of our Deep Basin position in 2018. Using the learnings from our 2017 development program and targeting high pressure areas of the reservoir with strategic positions close to our operated processing facilities, we plan to drill three wells through the year. Given the negative outlook for natural gas pricing in Alberta, we have high-graded our 2018 inventory to target liquids rich locations that generate robust rates of return.

Peace River Development

The Peace River area continues to be a key development area for the Company. Designing simpler wells to mitigate risk and increasing the length of individual legs to drill faster has driven cost savings that attract capital, despite the expected JV operating and capital cost carry expiry by year-end 2017. We plan to invest approximately $8 million to drill five (2.75 net) primary cold flow wells in 2018.

Alberta Viking Development

The Company plans to invest approximately $9 million to drill six wells in our Alberta Viking development area. All six wells are close to our 10 well program from 2017, and we expect similar production results. We expect slightly enhanced economics on our 2018 program using multi well pads close to existing infrastructure and by continuing to truck clean oil which enhance netbacks by approximately $1.50/bbl.

Optimization of Existing Wellbores

We plan to spend approximately $14 million on the optimization of existing well bores within our portfolio. This capital consists of over 50 individual projects to enhance field production by reactivating or re-fracking existing wells, debottlenecking, consolidating batteries, and testing additional zone potential in old vertical wells. This is some of the most capital efficient spend in our 2018 budget, projected at less than $10,000 per boe, per day. Our 2017 optimization projects contributed volumes at approximately $6,500 per boe, per day. We do not expect the same quantum of capital to be allocated to optimization past 2018.

Summary of 2018 Guidance


2018 Annual Guidance

Production

31,000 to 32,000 boe per day

Production Growth Rate (1)

5%

Operating Costs

$13.50 to $14.00 per boe

General & Administrative

$2.00 to $2.50 per boe

(1) Relative to full year 2017 production, adjusted for A&D, of between 29,000 – 30,000 boe per day

Our 2018 plans are based on full year 2018 pricing of US$55 WTI, $1.28 CAD/USD & C$2.25 AECO.




Capital Category

# of Operated Wells

Net Capital

Cardium

8 Producers

$44 million

Deep Basin

3 Producers

$11 million

Peace River

5 Producers

$8 million

Alberta Viking

6 Producers

$9 million

Existing Wellbore Optimization

>50 Projects

$14 million

Total Development

22 Producers

$86 million

Regulatory Directive 84 Requirements


$14 million

Infrastructure & Corporate Capital


$25 million

Total E&D Capital Expenditures


$125 million

Decommissioning Expenditures


$10 million

Total Capital Expenditures


$135 million

Conference Call Details

A conference call will be held to discuss the results at 6:30 a.m. MST (8:30 a.m. EST) on Friday, November 10, 2017.

To listen to the conference call, please call 647-427-7450 or 1-888-231-8191 (toll-free). This call will be broadcast live on the Internet and may be accessed directly at the following URL:

https://event.on24.com/wcc/r/1535576/E0A4361CC5204AE7C0052F290A83ABE9

A digital recording will be available for replay two hours after the call's completion, and will remain available until November 24, 2017 21:59 Mountain Time (23:59 Eastern Time). To listen to the replay, please dial 416-849-0833 or 1-855-859-2056 (toll-free) and enter Conference ID 4299386, followed by the pound (#) key.

An updated corporate presentation, the third quarter management's discussion and analysis and the unaudited consolidated financial statements will be available on the Company's website at www.obsidianenergy.com, on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov on the same date.

Additional Reader Advisories

Oil and Gas Information Advisory

Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil 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 that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value. 

Non-GAAP Measures

Certain financial measures including funds flow from operations, funds flow from operations per share-basic, funds flow from operations per share-diluted, EBITDA, netback, gross revenues and net debt included in this press release do not have a standardized meaning prescribed by IFRS and therefore are considered non-GAAP measures; accordingly, they may not be comparable to similar measures provided by other issuers. Funds flow from Operations is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and office lease settlements which also excludes the effects of financing related transactions from foreign exchange contracts and debt repayments/ pre-payments and is representative of cash related to continuing operations. Funds flow from operations is used to assess the Company's ability to fund its planned capital programs. EBITDA is cash flow from operations excluding the impact of changes in non-cash working capital, decommissioning expenditures, financing expenses, realized gains and losses on foreign exchange hedges on prepayments, realized foreign exchange gains and losses on debt prepayments and restructuring expenses. Additionally, under the syndicated credit facility, realized foreign exchange gains or losses related to debt maturities are excluded from the calculation. EBITDA as defined by Obsidian Energy's debt agreements excludes the EBITDA contribution from assets sold in the prior 12 months and is used within Obsidian Energy's covenant calculations related to its syndicated credit facility and senior notes.  See "Calculation of Funds Flow from Operations" below for a reconciliation of funds flow from operations to its nearest measure prescribed by IFRS. Netback is the per unit of production amount of revenue less royalties, operating expenses, transportation and realized risk management gains and losses, and is used in capital allocation decisions and to economically rank projects. See "Results of Operations – Netbacks" above for a calculation of the Company's netbacks. Gross revenue is total revenues including realized risk management gains and losses on commodity contracts and is used to assess the cash realizations on commodity sales. Net debt includes long-term debt and includes the effects of working capital and all cash held on hand.

Calculation of Funds Flow from Operations

 

(millions, except per share amounts)

Three months ended

September 30

Nine months ended

September 30

2017

2016

2017

2016

Cash flow from operating activities

$

61

$

(98)

$

118

$

(93)

Change in non-cash working capital


(34)


16


(18)


103

Decommissioning expenditures


2


1


9


5

Office lease settlements


3


-


11


-

Monetization of foreign exchange contracts


-


-


-


(32)

Settlements of normal course foreign exchange contracts


-


(9)


(8)


(3)

Monetization of transportation commitment


-


-


-


(20)

Realized foreign exchange loss – debt prepayments


-


113


-


113

Realized foreign exchange loss – debt maturities


-


-


4


36

Carried operating expenses (1)


5


4


15


11

Restructuring charges


3


5


9


14

Funds flow from operations

$

40

$

32

$

140

$

134










Per share










Basic per share

$

0.08

$

0.06

$

0.28

$

0.27


Diluted per share                                             

$

0.08

$

0.06

$

0.28

$

0.27

(1)

The benefit of carried operating expenses from the Company's partner under the Peace River Oil Partnership.

 

Forward-Looking Statements

Certain statements contained in this document constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "budget", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "objective", "aim", "potential", "target" and similar words suggesting future events or future performance. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: our excitement about the Company outlook and our determination to continue operational delivery into 2018; our forecasted full year 2017 production at the high end of our guidance; our expected 2018 production, percentage production growth rate for 2018 and associated investment level of Funds Flow from Operations, operating and general and administration cost ranges for 2018; that we have the operational flexibility and drilling prospects to deliver greater production growth by adjusting our second half program as commodity prices allow; that we have clear downside protection and confidence in growth through our hedging program; our capital spending plans in 2018; the expectation that our gas realizations will maintain a slight premium to AECO through 2018; our expectations for 2017 operating costs and the associated target range for those costs per boe (net of carried expenses); that we remain on track to meet full year 2017 capital guidance; our expected approach to development including the area-specific asset development plans described herein; the timing of development and operational activities; the expectations for timing for certain wells to be on production; the estimated value uptick in the Deep Basin from strong liquid rates; the expected closing date of the royalty interest transaction; our confidence in our ability to demonstrate self-funded double digit percentage growth from the fourth quarter of 2016 to the fourth quarter of 2017, adjusted for A&D; that we can accomplish our production growth estimates by continuing our second half 2017 momentum, by drilling producing wells through the first quarter of 2018; our ability to meet the AER requirements for Directive 84 in the Peace River Area and the Company will gather, process, and sell natural gas from its Peace River operations beginning in September 2018; the projected capital efficiency of our 2018 development capital, based on the 12 month forward production associated with each project; our intention to high-grade our 2018 inventory to target liquids rich locations that generate robust rates of return; that we expect slightly enhanced economics on our 2018 programs using multi well pads close to existing infrastructure and by continuing to truck clean oil which enhance netbacks; and that we do not expect the same quantum of capital to be allocated to existing wellbore optimization past 2018.

The key metrics for the Company set forth in this presentation may be considered to be future-oriented financial information or a financial outlook for the purposes of applicable Canadian securities laws. Financial outlook and future-oriented financial information contained in this presentation are based on assumptions about future events based on management's assessment of the relevant information currently available. In particular, this presentation contains projected operational and financial information for end of 2017, 2018 and beyond for the Company. The future-oriented financial information and financial outlooks contained in this presentation have been approved by management as of the date of this presentation. Readers are cautioned that any such financial outlook and future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein.

With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: 2018 prices of US$55.00 per barrel of West Texas Intermediate light sweet oil and C$2.25 per mcf AECO gas, and a C$/US$ foreign exchange rate of $1.28; that we do not dispose of any material producing properties; our ability to execute our long-term plan as described herein and in our other disclosure documents and the impact that the successful execution of such plan will have on our Company and our shareholders; that the current commodity price and foreign exchange environment will continue or improve; future capital expenditure levels; future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future crude oil, natural gas liquids and natural gas production levels; future exchange rates and interest rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including weather, infrastructure access and delays in obtaining regulatory approvals and third party consents; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability to renew or replace our syndicated bank facility and our ability to finance the repayment of our senior notes on maturity; and our ability to add production and reserves through our development and exploitation activities.

Although we believe that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the possibility that we will not be able to continue to successfully execute our long-term plan in part or in full, and the possibility that some or all of the benefits that we anticipate will accrue to our Company and our security holders as a result of the successful execution of such plans do not materialize; the possibility that we are unable to execute some or all of our ongoing asset disposition program on favourable terms or at all; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of crude oil, natural gas liquids and natural gas, price differentials for crude oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange or interest rates; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months, wild fires and flooding); and the other factors described under "Risk Factors" in our Annual Information Form and described in our public filings, available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

The forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update any forward-looking statements. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.

SOURCE Obsidian Energy Ltd.

View original content: http://www.newswire.ca/en/releases/archive/November2017/10/c5550.html

OBSIDIAN ENERGY: Suite 200, 207 - 9th Avenue SW, Calgary, Alberta T2P 1K3, Phone: 403-777-2500, Fax: 403-777-2699, Toll Free: 1-866-693-2707, Website: www.obsidianenergy.com; Investor Relations: Toll Free: 1-888-770-2633, E-mail: [email protected] CNW Group 2017


Source: Canada Newswire (November 10, 2017 - 6:30 AM EST)

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