Obsidian Energy Announces First Quarter 2018 Financial and Operational Results
CALGARY, May 11, 2018 /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 three months ended March 31, 2018. All figures are in Canadian dollars unless otherwise stated.
David French, President and CEO commented, "Obsidian Energy had another solid quarter of drilling success, especially with momentum building in Willesden Green where our results continue to exceed expectations. Recent results and the short cycle inventory we see in the units and along the halo of the play demand more investment. The vast majority of future development capital will flow to Willesden Green primary drilling and will be the key growth driver over the quarters and years to come. Our Harmon Valley South program in Peace River yielded excellent results, partially offsetting lower than expected gas rates from our last Mannville test and frac delays in Pembina.
The Company's first quarter production and operating cost results were hampered by cold weather downtime, third party maintenance and operational delays. Relative to last quarter, our financials were challenged due to hedging losses and wide differentials. The impact of our hedging program does not represent our long term ability to generate cash flow, nor does it represent the underlying quality of our operations. With the business freeing up from one-time costs in 2018 and potential dispositions impacting both debt and production levels next year, we do not expect to add incremental 2019 hedges at this time.
Despite the temporary production and cash flow impacts in the quarter, we continue to expect full year production and operating costs within guidance ranges. Production levels increased in April with recent success within our optimization budget and new wells coming on-stream and cleaning up through the month. We are well positioned for a strong second half with corporate volumes averaging over 30,000 boe per day the last two weeks, and are ready to expand our capital program in Willesden Green pending results from our business development activities."
Challenges in the first quarter, but strong underlying operations reinforce full year guidance
First quarter production averaged 29,443 boe per day, a decrease of six percent relative to fourth quarter 2017. Our previously disclosed sale of legacy assets, cold weather related downtime, third party maintenance and lower than expected Mannville gas rates resulted in lower production volumes for the quarter. This was mitigated by strong underlying base operations, specifically development within our Willesden Green Cardium acreage. Corporate production volumes have been over 30,000 boe per day for the last two weeks.
First quarter operating costs were $14.86 per boe, a six percent decrease relative to the first quarter of 2017 and a three percent increase relative to fourth quarter 2017. Operating costs were impacted by cold weather, higher power costs and one-off spill related expenses.
Willesden Green rates meaningfully exceeding type curve, approximately $50 million in Cardium drill ready inventory on standby
Six Willesden Green Cardium wells were brought on production in the quarter and are some of industry's best wells drilled to date in the area. Our four well pad brought on in January averaged over 400 boe per day per well over the first 90 days of production, and our two well pad in the halo drilling window has averaged approximately 375 boe per day per well over its first 60 days of production. In addition, we demonstrated the readiness of our Willesden Green program and delivered an incremental well on budget and ahead of schedule. This well came on at the end of April flowing over 900 boe per day per well (72 percent liquids) while choked, over the first 15 days of production. Five of these new wells will receive pressure support from new injectors also drilled in Q1. We are excited by results seen to date in the halo acreage and the significant running room we have in this play.
Top decile results for the Peace River Oil Partnership
Three of our four Peace River Oil Partnership ("PROP") wells came on line in the first quarter, with average peak rates above 500 bbl per day per well, and 90-day initial production rates forecasted to be in the best 10 percent of wells drilled across our acreage. The fourth well came on production in late April and has already reached first oil, producing over 500 bbl per day in early May. These production rates coupled with recent uptick in crude oil pricing drives strong rates of returns on these wells.
Optimization program partially delayed due to weather, with debottlenecking projects and multi-zone tests now yielding highly capital efficient results
Our optimization budget has yielded highly capital efficient results as work accelerated at the end of the first quarter. We have added new production from existing wellbores at a 90-day initial production capital efficiency of approximately $8,000 per boe per day. We brought 23 projects on line in the first quarter on approximately $5 million of capital spend, with an additional $1 million spent on projects benefitting second quarter production. We continue to see success targeting the Blue Ridge, Nisku, and Bakken formations by stimulating and reactivating existing wellbores.
Improved pricing outlook and ongoing business development initiatives set up exciting second half of the year and beyond
We see meaningful cash flow improvement in 2019 as the business rolls beyond the 2018 hedge book, regulatory capital requirements in Peace River and the third quarter Pound Sterling hedge commitment. The unshackling of our business in 2019 will provide a marked increase in capital allocated for development, focused in Willesden Green. Our operational teams are ready to execute on a robust inventory of projects to further capitalize our considerable land base.
Financial and Operating Highlights
| Three months ended March 31 |
|||||||||
| 2018 |
2017 |
% change |
|||||||
| Financial |
|||||||||
| Funds flow from operations (1) |
$ |
35 |
$ |
57 |
(39) |
||||
| Basic and Diluted per share (1) |
0.07 |
0.11 |
(36) |
||||||
| Net income (loss) |
(65) |
27 |
>(100) |
||||||
| Basic and Diluted per share |
(0.13) |
0.05 |
>(100) |
||||||
| Capital expenditures (2) |
60 |
26 |
>100 |
||||||
| Net Debt |
$ |
407 |
$ |
405 |
- |
||||
| Operations |
|||||||||
| Daily production |
|||||||||
| Light oil and NGL (bbls/d) |
14,412 |
15,962 |
(10) |
||||||
| Heavy oil (bbls/d) |
4,751 |
5,206 |
(9) |
||||||
| Natural gas (mmcf/d) |
62 |
82 |
(24) |
||||||
| Total production (boe/d) (3) |
29,443 |
34,900 |
(16) |
||||||
| Average sales price |
|||||||||
| Light oil and NGL (per bbl) |
$ |
64.25 |
$ |
57.00 |
13 |
||||
| Heavy oil (per bbl) |
31.34 |
33.21 |
(6) |
||||||
| Natural gas (per mcf) |
$ |
2.87 |
$ |
3.22 |
(11) |
||||
| Netback per boe (3) |
|||||||||
| Sales price |
$ |
42.52 |
$ |
38.63 |
10 |
||||
| Risk management gain (loss) |
(4.20) |
3.52 |
>(100) |
||||||
| Net sales price |
38.32 |
42.15 |
(9) |
||||||
| Royalties |
(2.73) |
(2.68) |
2 |
||||||
| Operating expenses (4) |
(14.86) |
(15.78) |
(6) |
||||||
| Transportation |
(3.16) |
(2.31) |
37 |
||||||
| Netback (1) |
$ |
17.57 |
$ |
21.38 |
(18) |
||||
| (1) |
The terms "funds flow from operations" and their applicable per share amounts, and "netback" are non-GAAP measures. Please refer to the "Non-GAAP Measures" advisory section below for further details. |
| (2) |
Includes the effect of capital carried from its partner under PROP in 2017. The benefit of carried capital expenditures from the Company's partner under PROP was fully utilized in December 2017. |
| (3) |
Please refer to the "Oil and Gas Information Advisory" section below for information regarding the term "boe". |
| (4) |
Operating costs per boe is presented excluding the impact of carried operating expenses. The benefit of carried operating expenses from the Company's partner under PROP was fully utilized in December 2017. |
- Funds Flow from Operations ("FFO") for the first quarter was $35 million, a decrease of 33 percent from the fourth quarter of 2017. The decrease in FFO was primarily due to the conclusion of the PROP operating cost carry, realized risk management losses and lower production volumes, partially offset by higher commodity prices. Realized risk management losses for the quarter totaled $4.20 per boe compared to nil in the fourth quarter of 2017. The realized loss increased as crude oil prices strengthened in 2018.
- Average liquids sales prices in the first quarter were $56.09 per boe and average natural gas sales prices were $2.87 per mcf, excluding the impact of hedging activities. Relative to the fourth quarter of 2017, liquids pricing was similar as crude oil price increases were offset by lower heavy oil price realizations due to widening differentials. Realized gas pricing was higher as a result of increasing AECO benchmark pricing and the Company continued to benefit from its Ventura marketing arrangement.
- First quarter operating costs were $14.86 per boe, a six percent decrease relative to the first quarter of 2017 and a three percent increase relative to fourth quarter 2017. Operating costs were impacted by cold weather, higher power costs and one-off spill related expenses. We expect second quarter absolute operating costs to be in-line with the first quarter due to higher scheduled turnaround activity, before trending lower in the second half of the year.
- Invested $60 million of development capital expenditures across the business, mainly in the Cardium, and $2 million of decommissioning expenditures.
- Net Debt was $407 million at March 31, 2018 and increased relative to the fourth quarter of 2017 due to higher capital expenditure activities. Net debt includes $258 million drawn on our revolving credit facility and $109 million of Senior Notes. Subsequent to the quarter, the Company extended its reserve based Syndicated Credit Facility (the "Facility") to May 31, 2019 as part of its semi-annual redetermination. The underlying borrowing base continues to be $550 million with $410 million available under the Facility. Availability under the Facility will increase to $440 million on May 29, 2018 in connection with the payment of a senior note maturity on that date.
- Closed our legacy asset disposition on January 31, reducing our decommissioning liabilities, improving netbacks and increasing our corporate liquids weighting. Refer to our press release titled "Obsidian Energy Announces Legacy Asset Disposition" dated January 31, 2018 for further details.
The table below outlines select metrics in our key development and legacy areas for the three months ended March 31, 2018 and excludes the impact of hedging:
| Area |
Select Metrics – Three Months Ended March 31, 2018 |
|||
| Production |
Liquids |
Operating |
Netback |
|
| Cardium |
19,081 boe/d |
66% |
$14/boe |
$28/boe |
| Deep Basin |
1,292 boe/d |
22% |
$1/boe |
$22/boe |
| Alberta Viking |
1,916 boe/d |
54% |
$11/boe |
$28/boe |
| Peace River |
4,963 boe/d |
99% |
$12/boe |
$12/boe |
| Key Development Areas |
27,252 boe/d |
69% |
$13/boe |
$25/boe |
| Legacy Areas(1) |
2,191 boe/d |
25% |
$38/boe |
$(19)/boe |
| Key Development & Legacy Areas |
29,443 boe/d |
65% |
$15/boe |
$22/boe |
| (1) |
A portion of Legacy Areas includes assets sold in the first quarter. Refer to January 31, 2018 press release for more details. |
The table below provides a summary of our operated activity in the first quarter.
| Number of Wells Q1 2018 |
||||||||
| Drilled |
Completed |
On-stream |
||||||
| Gross |
Net |
Gross |
Net |
Gross |
Net |
|||
| Cardium |
||||||||
| Producer |
6 |
4.7 |
7 |
6.0 |
6 |
5.6 |
||
| Injector |
6 |
6.0 |
3 |
3.0 |
0 |
0.0 |
||
| Deep Basin |
1 |
1.0 |
1 |
1.0 |
1 |
1.0 |
||
| Alberta Viking |
0 |
0.0 |
0 |
0.0 |
0 |
0.0 |
||
| Peace River |
3 |
1.7 |
3 |
1.7 |
3 |
1.7 |
||
| Total |
16 |
13.3 |
14 |
11.7 |
10 |
8.3 |
||
Operational Update
Extreme cold weather in Western Canada impacted the first quarter results; we dealt with frozen casing, pumping equipment and pipelines. In total, we estimate cold weather impacted the quarter by approximately 500 boe per day. Production has now been fully restored and we are back to normal operations with average production over 30,000 boe per day over the last two weeks. Scheduled turnaround activity is expected to impact the second quarter by approximately 900 boe per day.
Our four well pad in Willesden Green Cardium came on-stream in January averaging nearly 650 boe per day per well (87 percent liquids) for the first 30 days of production, and over 400 boe per day per well for the first 90 days of production. We expect injection support to mitigate decline rates and meaningfully enhance the ultimate recovery from the wells. Our two well pad just east of this pad was brought on-stream in February and averaged 375 boe per day per well (87 percent liquids) for both the first 30 and 60 days of production.
As outlined in our year-end results press release, we elected to add an additional Willesden Green well to our program. This well came on at the end of April and was flowing over 900 boe per day per well (72 percent liquids) while choked, over the first 15 days of production. We will drill two more wells in the third quarter within close proximity to this well and have an additional 15 wells ready to execute should additional capital become available through our business development activities.
In Pembina, we have drilled and completed all six of our planned wells, which are accompanied by low cost injector conversions for waterflood support. Infrastructure constraints and weather delays impacting frac crew availability limited our ability to bring these wells on-line in the first quarter. Our four well pad in PCU#9 encountered high initial pressures, proving the benefits of the waterflood work to pre-pressurize the reservoir in advance of drilling the pad. The first three wells came on production March 31, showing high total fluid rates and are currently being optimized. Our two well pad in PCU#11 came on production at the end of April and also had encouraging initial tests while being optimized.
Despite positive initial pressure results, our first quarter Deep Basin Mannville Falher well did not meet rate expectations and is tracking approximately 1,000 boe per day behind our forecast. The well was drilled in the Falher formation within the Mannville group, and the underperformance is mostly made up of natural gas. Liquids yields came in as expected at 64 bbl per mmcf, or 210 bbl per day. The well was placed in channel throughout the entire length of the well; however, the reservoir had less permeability than anticipated. This well is still economic due to our owned infrastructure processing advantage and liquids content. We have one Deep Basin well provisionally planned for the third quarter directly offsetting the best well from our 2017 program, in a more extensive channel in the over pressured regime. We maintain significant running room in the Deep Basin amongst multiple formations, and will continue to prove up the acreage as our capital plan allows.
In Peace River, we delivered a strong four well program significantly above type curve initial production rates as we moved back to the heart of Harmon Valley South. Three of our four PROP wells came on line in the first quarter, with average peak rates above 500 bbl per day and 90-day initial production forecasts in the best 10 percent of wells drilled across our acreage. The fourth well came on production late April and has already reached first oil, producing over 500 bbl per day in early May. The joint industry gas gathering system and gas plant is proceeding on schedule, and we expect to have the system on-stream well in advance of the AER Directive-84 regulatory deadline.
Our four well second half Alberta Viking program is highly economic, targeting structural lows to maximize light oil productivity. Pending the results from the ongoing dispositions process, the program may be drilled in the third quarter.
Current Hedging Position
No hedges were added recently as we were already at approved levels for the next 12 months. With the business freeing up from one-time costs in 2018 and potential dispositions impacting both debt and production levels next year, we do not expect to add incremental 2019 hedges at this time. Currently, the Company has the following crude oil hedges in place:
| Q2 2018 |
Q3 2018 |
Q4 2018 |
Q1 2019 |
Q2 2019 |
Q3 2019 |
||
| WTI $USD |
$50.00 |
$50.05 |
$49.78 |
$50.02 |
$56.53 |
$57.00 |
|
| bbl/day |
7,000 |
8,000 |
8,000 |
3,000 |
2,000 |
1,000 |
|
| WTI $CAD |
$71.03 |
$71.04 |
$71.04 |
$67.88 |
$68.58 |
- |
|
| bbl/day |
5,000 |
4,000 |
4,000 |
6,000 |
4,000 |
- |
|
| Total |
|||||||
| bbl/day |
12,000 |
12,000 |
12,000 |
9,000 |
6,000 |
1,000 |
|
Additionally, the Company has the following foreign exchange contracts in place:
- 2018 foreign exchange revenue swaps at an average of 1.268 on notional US$9 million per month
- 2018 foreign exchange revenue collars at an average of 1.210 – 1.272 on notional US$2 million per month
- Q1 2019 foreign exchange revenue swaps at an average of 1.300 on notional US$2 million per month
- Foreign exchange swaps on May 2018 debt maturities at an average of 1.233 on US$15 million
Currently, the Company has the following natural gas hedges in place:
| Q2 2018 |
Q3 2018 |
Q4 2018 |
||
| AECO $CAD |
$2.72 |
$2.67 |
$2.67 |
|
| mcf/day |
22,700 |
17,100 |
15,200 |
|
| Ventura $USD (1) |
$2.79 |
$2.79 |
$2.79 |
|
| mcf/day |
7,500 |
7,500 |
7,500 |
|
| Total |
||||
| mcf/day |
30,200 |
24,600 |
22,700 |
|
| (1) |
Through the third quarter of 2020, the Company has an agreement in place to sell 15 mmcf per day of natural gas 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. |
AGM Details
There will be no conference call accompanying these results, as the Company's Annual and Special Meeting (the "Meeting") is scheduled later at 10:00 a.m. MDT (12:00 p.m. EDT). The Meeting will be held in the Acadia Ballroom of the Marriott Downtown Hotel, located at 110 - 9th Avenue SE Calgary, Alberta.
At approximately 10:10 a.m. MDT, and following the formal portion of the Meeting, Mr. David French, President and CEO, will address shareholders and discuss the Company's 2018 first quarter financial and operational results. The Company will host a question and answer period subsequent to the presentation.
To listen to a live broadcast of the presentation and the question and answer period, please access the following URL:
https://event.on24.com/wcc/r/1652072/0971A412DE063422C87144C72F6938B1
A replay of the audio webcast and a link to the Annual and Special Meeting presentation will be available two hours afterwards on our website at www.obsidianenergy.com.
Electronic copies of our Management Information Circular, Proxy Statement, financial statements, news releases, and other public information are available on our website at www.obsidianenergy.com, on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov.
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.
Abbreviations
| Oil |
Natural Gas |
||
| bbl |
barrel or barrels |
Mcf |
thousand cubic feet |
| bbl/d |
barrels per day |
MMcf |
million cubic feet |
| Mbbl |
thousand barrels |
Bcf |
billion cubic feet |
| MMbbl |
million barrels |
Mcf/d |
thousand cubic feet per day |
| boe/d |
barrels of oil equivalent per day |
MMcf/d |
million cubic feet per day |
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, netback 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. 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 "Financial and Operational Highlights" above for a calculation of the Company's netbacks. 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
| Three months ended March 31 |
|||||
| (millions, except per share amounts) |
2018 |
2017 |
|||
| Cash flow from operating activities |
$ |
57 |
$ |
38 |
|
| Change in non-cash working capital |
(32) |
2 |
|||
| Decommissioning expenditures |
2 |
4 |
|||
| Office lease settlements |
5 |
4 |
|||
| Realized foreign exchange loss – debt maturities |
- |
3 |
|||
| Carried operating expenses (1) |
- |
4 |
|||
| Restructuring charges |
1 |
2 |
|||
| Other expenses |
2 |
- |
|||
| Funds flow from operations |
$ |
35 |
$ |
57 |
|
| Per share |
|||||
| Basic per share |
$ |
0.07 |
$ |
0.11 |
|
| Diluted per share |
$ |
0.07 |
$ |
0.11 |
|
| (1) The benefit of carried operating expenses from the Company's partner under PROP was fully utilized in December 2017. |
Forward-Looking Statements
Certain statements contained in this document constitute forward-looking statements or information (collectively "forward-looking statements"). 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: that the vast majority of future development capital will flow to Willesden Green primary drilling and will be the key growth driver over the quarters and years to come; that we do not expect to add incremental 2019 hedges at this time; our expectations for full year production and operating costs guidance; that we are well positioned for a strong second half and that we are ready to expand our capital program in Willesden Green with more wells and significant running room in the play pending results from our business development activities; that we continue to see success targeting the Blue Ridge, Nisku and Bakken formations by stimulating and reactivating existing wellbores; that we see meaningful cash flow improvement in 2019 as the business rolls beyond the 2018 hedge book, regulatory capital requirements in Peace River and the third quarter Pound Sterling hedge commitment; that the unshackling of our business in 2019 will provide a marked increase in capital allocated for development focused in Willesden Green; that our operational teams are ready to execute on a robust pipeline of projects to further capitalize our considerable land base; that we expect second quarter absolute operating costs in-line with the first quarter due to higher scheduled turnaround activity, before trending lower in the second half of the year; that availability under the Facility will increase to $440 million on May 29, 2018 to recognize the payment of a senior note maturity; the impact to second quarter production of scheduled turnaround activity; that we expect injection support to mitigate decline rates and meaningfully enhance the ultimate recovery from the four well pad in Willesden Green; the expectation for drilling and timing at various locations; that we maintain significant running room in the Deep Basin amongst multiple groups and formations, and will continue to prove up the acreage as our capital plan allows; that we expect to have the joint industry gas gathering system on-stream well in advance of the AER Directive-84 regulatory deadline; and pending the results of our disposition process, the highly economic Viking program may be drilled.
With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things that we do not dispose of any material producing properties other than stated herein; 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 securityholders 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.
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]
Share this article