CALGARY, March 7, 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 year ended December 31, 2017. All figures are in Canadian dollars unless otherwise stated. Obsidian Energy’s Management Discussion and Analysis (“MD&A”) dated March 6, 2018 and audited financial statements for year end 2017 can be found on our website at www.obsidianenergy.com. The documents will also be filed on SEDAR and EDGAR in due course.
“We are pleased to report an excellent fourth quarter and full year results,” commented David French, President & CEO. “2017 was a breakthrough year for the Company. Notwithstanding a challenging external environment, we consistently delivered on our operational objectives, beat our production guidance, and underpinned the shallow decline cash flows of the business. We grew our A&D adjusted production base in 2017 by approximately 10 percent, kick-starting a disciplined growth story, even while spending less capital and maintaining our focus on balance sheet strength.
We continue to deliver strong results across our field operations, specifically within our Cardium acreage. Off the back of these results, we have found ways to put additional dollars to work in the highly economic Willesden Green fairway. The success of our 2017 program sets us up well for 2018 and beyond. We see many reasons to be excited for the future of Obsidian Energy.”
Delivered Year over Year Production Growth of 10 Percent and Full Year 2017 Production above Guidance
Full year 2017 production was 31,723 boe per day, above the high end of our guidance range of 30,500 – 31,500 boe per day. Ongoing waterflood and our shallow base decline, combined with solid execution of our second half development program drove the outperformance.
Fourth quarter 2017 production was 31,447 boe per day, 10 percent higher than the previous year, adjusted for A&D. Relative to the third quarter, we grew total production and liquids production by four percent. This marks another quarter of consistent production delivery and advances our operational momentum into the first quarter of 2018.
Total 2017 Capital Expenditures Beat Guidance, Including Cardium Drilling Acceleration
Full year 2017 capital was $157 million, including decommissioning expenditures, below our guidance of $160 million. Fourth quarter capital was $44 million, including decommissioning expenditures, highlighted by our first foray into the Deep Basin and bringing on seven Cardium producing wells. We also executed a December start-up of five of our 2018 Cardium wells, while delaying some minor Cardium injector capital into 2018.
Operating Expenses were Comfortably Within Guidance Range
Full year and fourth quarter 2017 operating expenses were $13.40 per boe and $12.50 per boe, respectively, net of carried expenses. Growing production volumes offset higher maintenance and turnaround activity, driving a full year number that was comfortably within our guidance range of $13.00 – $13.50 per boe.
As expected, our Peace River operating cost carry was fully utilized in December. The Company is well positioned for continuous operating cost improvement driven by a dedicated push for efficiency and our recent disposition of high cost legacy assets. As a result, we expect our cost basis, excluding any carry impact, to decrease year over year.
Five Percent Higher Funds Flow from Operations versus 2016, Despite 42 Percent Less Production
Full year Funds Flow from Operations was $192 million, up from $182 million in 2016. Despite meaningful disposition activity in 2016 that reduced production by 42 percent, the increase in FFO was supported by higher crude oil prices and more than $100 million less of gross operating expenses.
Fourth quarter Funds Flow from Operations was $52 million, up from $40 million in the third quarter. Higher benchmark commodity prices, robust field realizations and strong production volumes drove the cash flow performance. Our light oil realizations were in line with benchmark expectations, while heavy oil and natural gas realizations were higher than benchmark pricing.
Heavy oil realized pricing increased by 26 percent relative to the third quarter, compared to a 15 percent increase in Canadian Dollar heavy oil benchmark pricing. Our rail transportation and alternative price basis sales points reinforced the strong realized pricing in the quarter.
A portion of our natural gas volumes are sold relative to a US Midwest market at Ventura. In the fourth quarter of 2017, Obsidian Energy had the benefit of selling approximately 30 mmcf per day into this market. The premium we received at Ventura contributed nearly $5 million additional to Funds Flow from Operations and was mainly due to a short term price spike, where our gas realizations averaged approximately $5.00 per mcf above AECO pricing in December. While a portion of our pricing arrangement ended in 2017, we retain 15 mmcf per day of Ventura marketing commitments through the third quarter of 2020.
Demonstrating Cardium Drilling Consistency; Well Results Command Additional Investment
Following on our recent four well pad in Willesden Green, initial rates from our two 2018 locations are exceeding expectations. The two well pad came on stream February 20 and has averaged approximately 900 boe per day through March 4, implying an average of 450 boe per day per well (88 percent liquids) over that timeframe. These strong initial results demonstrate the regular success we have had optimizing wellbore placement in the bioturbated interval and proven completion design.
We plan to add three wells to our 2018 Willesden Green Cardium program. We expect one of those wells to come on stream in the second quarter, and the next two wells to come on stream early in the fourth quarter. We will fund these wells by reducing our Alberta Viking, Deep Basin and standalone waterflood capital outlays by a total of $9 million.
Second Half Optionality Remains to Increase Returns and Enhance 2019 Outlook
We have the operational flexibility to adjust our capital program as Alberta commodity prices allow. We will continue to be prudent with respect to balance sheet management, and will not call on debt to fund additional development. As next quarter’s pricing plays out and we get further certainty on our full year cash flow profile, we will fine tune our capital program for the second half of the year.
Financial and Operating Highlights
Three months ended December 31 |
Year ended December 31 |
||||||||||
2017 |
2016 |
% change |
2017 |
2016 |
% change |
||||||
Financial (millions, except per share amounts) |
|||||||||||
Funds Flow from Operations (1) |
$ |
52 |
$ |
48 |
8 |
$ |
192 |
$ |
182 |
5 |
|
Basic per share (1) |
0.10 |
0.10 |
– |
0.38 |
0.36 |
6 |
|||||
Diluted per share (1) |
0.10 |
0.10 |
– |
0.38 |
0.36 |
6 |
|||||
Net loss |
(58) |
(232) |
(75) |
(84) |
(696) |
(88) |
|||||
Basic per share |
(0.12) |
(0.46) |
(74) |
(0.17) |
(1.39) |
(88) |
|||||
Diluted per share |
(0.12) |
(0.46) |
(74) |
(0.17) |
(1.39) |
(88) |
|||||
Capital expenditures (2) |
37 |
50 |
(26) |
141 |
82 |
72 |
|||||
Net Debt |
$ |
383 |
$ |
502 |
(24) |
$ |
383 |
$ |
502 |
(24) |
|
Operations |
|||||||||||
Daily production |
|||||||||||
Light oil and NGL (bbls/d) |
14,288 |
15,803 |
(10) |
14,236 |
26,059 |
(45) |
|||||
Heavy oil (bbls/d) |
5,247 |
5,493 |
(4) |
5,387 |
8,750 |
(38) |
|||||
Natural gas (mmcf/d) |
71 |
103 |
(31) |
73 |
121 |
(40) |
|||||
Total production (boe/d) (3) |
31,447 |
38,481 |
(18) |
31,723 |
54,990 |
(42) |
|||||
Average sales price |
|||||||||||
Light oil and NGL (per bbl) |
$ |
62.70 |
$ |
52.34 |
20 |
$ |
56.84 |
$ |
43.74 |
30 |
|
Heavy oil (per bbl) |
38.12 |
27.09 |
41 |
33.27 |
21.22 |
57 |
|||||
Natural gas (per mcf) |
$ |
2.51 |
$ |
2.98 |
(16) |
$ |
2.81 |
$ |
2.14 |
31 |
|
Netback per boe (3) |
|||||||||||
Sales price |
$ |
40.55 |
$ |
33.33 |
22 |
$ |
37.58 |
$ |
28.83 |
30 |
|
Risk management gain |
– |
4.27 |
(100) |
2.02 |
5.03 |
(60) |
|||||
Net sales price |
40.55 |
37.60 |
8 |
39.60 |
33.86 |
17 |
|||||
Royalties |
(2.64) |
(1.26) |
>100 |
(2.57) |
(1.08) |
>100 |
|||||
Operating expenses (4) |
(12.50) |
(14.05) |
(11) |
(13.40) |
(13.18) |
2 |
|||||
Transportation |
(2.41) |
(1.62) |
49 |
(2.48) |
(1.72) |
44 |
|||||
Netback (1) |
$ |
23.00 |
$ |
20.67 |
11 |
$ |
21.15 |
$ |
17.88 |
18 |
(1) |
The terms “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. |
|
(2) |
Includes the benefit of capital carried by partners. |
|
(3) |
Please refer to the “Oil and Gas Information Advisory” section below for information regarding the term “boe”. |
|
(4) |
Includes the benefit of carried operating expenses from its partner under the Peace River Oil Partnership of $6 million or $1.89 per boe (2016 – $5 million or $1.30 per boe) for the three months ended and $21 million or $1.78 per boe (2016 – $15 million or $0.75 per boe) for the year ended on a combined basis. |
- Funds Flow from Operations for the fourth quarter was $52 million, reflecting stronger realized pricing primarily due to an increase in US$ WTI and Ventura pricing. Full year Funds Flow from Operations was $192 million, a five percent increase relative to 2016.
- Average liquids sales prices in the fourth quarter were $56.10 per boe and average natural gas sales prices were $2.51 per mcf. Strong realized pricing in the quarter is a result of our value adding marketing activities, specifically on heavy oil and natural gas.
- Fourth quarter operating costs were $12.50 per boe, net of carried expenses. As expected, operating costs were consistent with the third quarter and around $2 per boe below first half 2017, which had higher maintenance and turnaround activity.
- Invested $37 million of development capital expenditures across our key development areas and $7 million of decommission expenditures in the fourth quarter. Full year development capital and decommission expenditures were $141 million and $16 million, respectively.
- Total Net Debt was $383 million at December 31, 2017, $119 million lower than the prior year. Net debt includes $253 million drawn on our revolving credit facility and $106 million of Senior Notes.
The table below outlines select metrics in our key development and legacy areas for the three months ended December 31, 2017 and excludes the impact of hedging:
Area |
Select Metrics – Three Months Ended December 31, 2017 |
||||
Production |
Liquids |
Operating |
Netback |
||
Cardium |
18,190 boe/d |
64% |
$13/boe |
$28/boe |
|
Deep Basin |
1,356 boe/d |
31% |
$1/boe |
$28/boe |
|
Alberta Viking |
2,508 boe/d |
54% |
$11/boe |
$23/boe |
|
Peace River(1) |
4,963 boe/d |
99% |
$3/boe |
$30/boe |
|
Key Development Areas |
27,018 boe/d |
68% |
$12/boe |
$28/boe |
|
Legacy Areas(2) |
4,429 boe/d |
25% |
$28/boe |
$(6)/boe |
|
Key Development & Legacy Areas |
31,447 boe/d |
62% |
$13/boe |
$23/boe |
(1) |
Net of carried operating costs. |
(2) |
A portion of Legacy Areas are classified as Assets Held for Sale. Refer to January 31, 2018 press release for more details |
The table below provides a summary of our operated activity in the fourth quarter.
Number of Wells Q4 2017 |
||||||||
Drilled |
Completed |
On stream |
||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
|||
Cardium |
||||||||
Producer |
6 |
5.8 |
4 |
4.0 |
7 |
6.7 |
||
Injector |
0 |
0.0 |
5 |
4.5 |
5 |
4.5 |
||
Deep Basin |
0 |
0.0 |
0 |
0.0 |
2 |
1.7 |
||
Alberta Viking |
0 |
0.0 |
0 |
0.0 |
4 |
4.0 |
||
Peace River |
4 |
2.2 |
5 |
2.8 |
5 |
2.8 |
||
Total |
10 |
8.0 |
14 |
11.3 |
23 |
19.7 |
In the Cardium, we brought on production three PCU #9 wells and five associated injectors. In Willesden Green, we brought on our four well pad late in December but due to extreme cold weather and third party pipeline curtailment, all four wells were not running at the same time until January 3, 2018.
We brought on the final two wells of our three well Mannville program, our first foray into the Deep Basin. These three wells contributed approximately 1,300 boe per day to the quarter (net to OBE) with strong liquids yields averaging 55 bbl/mmcf (135 bbl/d per well).
The second half 2017 Peace River program is currently producing approximately 2,100 boe per day gross production (1,200 boe per day net working interest). All 12 wells were on production by mid-December 2017. Per well results are consistent with expectations and reconfirm the upside we see within the heart of our acreage.
Our second half 2017 Alberta Viking program is fully optimized and all 10 wells were on production early in the fourth quarter. The wells displayed initial rates above expectations, and the total program reached a peak rate of approximately 1,900 boe per day in the quarter. The wells averaged approximately 1,200 boe per day over the quarter.
Operational Update
Our four well pad in Willesden Green Cardium was on-stream as of January 3, 2018. IP30 for the wells averaged nearly 650 boe per day (87 percent liquids). The pad is currently producing approximately 1,200 boe per day. We expect injection support to mitigate decline rates and meaningfully enhance the ultimate recovery from the wells. Our two well pad in Willesden Green, approximately 20 kilometers east, was on stream February 20, 2018. The pad has averaged approximately 900 boe per day since the wells came on production, implying an average of 450 boe per day per well over that timeframe. We have elected to add three additional Willesden Green Cardium wells to our 2018 development plans, within close proximity to our recent program. The wells will be funded from other areas of our development program.
We have drilled six and completed four wells in Pembina, which are accompanied by six low cost injector conversions for waterflood support. We expect these wells to be on production early in the second quarter.
We recently finished drilling a two-mile Mannville (Falher) well which is expected to be on stream at the end of March. Initial pressure metrics and production tests look encouraging, and we expect the well to be highly economic due to our owned infrastructure processing advantage and high liquids content. We plan to drill another Deep Basin opportunity in the second half of 2018.
Total 2018 capital expectations for Peace River are down slightly, and we shifted to a four well program from five wells. We believe four wells with varying lateral legs and lengths can deliver the same production wedge as originally anticipated. We are currently on the third of four wells and preliminary drilling and production test results are consistent with expectations.
Our second half Alberta Viking program is highly economic, targeting structural lows to maximize light oil productivity. The program will be drilled in the third quarter.
Updated Hedging Position
We continued our active hedging program and extended our hedge book into 2019. Currently, the Company has the following crude oil hedges in place:
Q1 2018 |
Q2 2018 |
Q3 2018 |
Q4 2018 |
Q1 2019 |
Q2 2019 |
Q3 2019 |
||
WTI $USD |
$50.82 |
$50.00 |
$50.05 |
$49.78 |
$50.02 |
$56.53 |
$57.00 |
|
bbl/day |
7,000 |
7,000 |
8,000 |
8,000 |
3,000 |
2,000 |
1,000 |
|
WTI $CAD |
$71.03 |
$71.03 |
$71.04 |
$71.04 |
$67.88 |
$68.58 |
– |
|
bbl/day |
5,000 |
5,000 |
4,000 |
4,000 |
6,000 |
4,000 |
– |
|
Total |
||||||||
bbl/day |
12,000 |
12,000 |
12,000 |
12,000 |
9,000 |
6,000 |
1,000 |
Additionally, the Company has the following foreign exchange contracts in place for 2018:
- Foreign exchange swaps on revenues at an average of 1.268 on notional US$9 million per month
- Foreign exchange collar on revenues at an average of 1.210 – 1.272 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:
Q1 2018 |
Q2 2018 |
Q3 2018 |
Q4 2018 |
|||
AECO $CAD |
$2.83 |
$2.72 |
$2.67 |
$2.67 |
||
mcf/day |
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 |
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. Ventura pricing in the fourth quarter averaged approximately $4.00 per mcf. Recent transportation deductions for the Company to bring product to the Ventura market have been approximately $0.55 per mcf. |
2018 Guidance Summary
Our total 2018 guidance remains unchanged:
2018 Annual Guidance |
|
Production |
29,000 to 30,000 boe per day |
Production Growth Rate (1) |
5% |
Operating Costs |
$13.00 – $13.50 per boe |
General & Administrative |
$2.00 – $2.50 per boe |
(1) |
Relative to full year 2017 production, adjusted for all 2017 & 2018 A&D, of 28,000 boe per day |
Our Total Capital Expenditure Guidance remains the same, but accounts for the reallocation as noted below:
Capital Category |
# of Operated Wells |
Net Capital |
Cardium |
11 Producers |
$51 million |
Deep Basin |
2 Producers |
$7 million |
Peace River |
4 Producers |
$8 million |
Alberta Viking |
4 Producers |
$6 million |
Existing Wellbore Optimization |
>50 Projects |
$14 million |
Total Development |
21 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 |
Proposed Share Consolidation
Obsidian Energy will propose a consolidation of the Company’s outstanding common shares at the upcoming Annual and General Meeting. Obsidian believes that a share consolidation will reduce its outstanding equity float to a level more suitable to the current size of the Company, appeal to a broader universe of investors and reinforce compliance with the New York Stock Exchange’s minimum share price listing requirement. The proposed 3:1 ratio balances improved marketability for the shares, reduced transaction costs for lot trading and sufficient liquidity going forward.
Shareholders will be asked to pass a special resolution that will authorize the Board of Directors to direct the Company to amend our articles, in order to consolidate (or reverse split) the Company’s issued common shares into a lesser number of issued common shares on the basis of three (3) old common shares for one (1) new common share. The Board of Directors will retain the discretion to revoke the share consolidation resolution and elect not to proceed with the filing of the articles of amendment and the implementation of the share consolidation.
A share consolidation will be subject to approval of the Toronto Stock Exchange and the New York Stock Exchange. Further information regarding the potential share consolidation and timing of the Annual and General Meeting will be included in the Company’s Management Information Circular to be disseminated later this spring.
Year-End 2017 Financial Results 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 March 7, 2018.
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:
http://event.on24.com/wcc/r/1602755-1/F3B454234B7BA6D9E327EEC65E28F03E
A digital recording will be available for replay two hours after the call’s completion, and will remain available until March 21, 2018, 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 1898936, followed by the pound (#) key.