Obsidian Energy Announces Third Quarter 2018 Financial and Operational Results
CALGARY, Nov. 8, 2018 /PRNewswire/ - OBSIDIAN ENERGY LTD. (TSX - OBE, NYSE - OBE.BC) ("Obsidian Energy", the "Company", "we", "us" or "our") is pleased to announce its financial and operational results for the three and nine months ended September 30, 2018. All figures are in Canadian dollars unless otherwise stated.
David French, President and CEO commented, "The third quarter results are a combination of excitement over the initial results from the second half of 2018 ("2H18") development program, set against the backdrop of lower than expected base performance from the first half of 2018 ("1H18") Pembina and Mannville programs and a challenging outlook for light and heavy oil differentials.
We expect full year 2018 production to be slightly below our guidance range due to the continued higher water cuts of our early 2018 injector development in PCU #9, lower than anticipated volumes from our 1H18 Mannville well, and deliberate choices on fourth quarter production due to recent differentials. This is partially offset by ahead of schedule delivery of our 15 well 2H18 Cardium development.
The success of the seven well 1H18 Willesden Green drilling program continues to bear fruit. The initial flowback tests in our 2H18 Willesden Green 8-9 and 14-1 pads are comparable with the offset producers drilled in the first half of the year. We expect to have eight of the 15 wells ready to produce this year, and anticipate an available early 2019 production wedge of 3,700 boe per day (2,900 bbl per day of oil) from all 15 wells. Our 2H18 Mannville well 02/14-03 was a strong volume contributor with an average initial production for the first 60 days ("IP60") of 1,355 boe per day (250 bbl per day are condensate).
In reaction to the recent swing in differential pricing for both heavy and light oil, the Company has prioritized its assessment of margin contribution across the Company:
-- Our four well 2H18 Peace River program was delivered on time and
on-budget; however, we are delaying sustained on-stream production for
those wells (peak rate of 300 bbl per day of gross oil expected per
well) until 2019;
-- We are announcing a disciplined effort to reduce exposure to the costs
of our legacy portfolio through participation in the Alberta Energy
Regulator's ("AER") Area Based Closure ("ABC") program. We are moving
forward with the shut-in of approximately 1,300 boe per day (2019
forecast contribution, 89 percent natural gas) and staggered abandonment
of cash flow negative assets within our legacy portfolio. This is
expected to improve 2019 Funds Flow from Operations ("FFO") by $4
million and reduce our undiscounted Asset Retirement Obligation for
these assets by 20-30 percent. This shut-in represents less than 2% of
reserves and Net Asset Value ("NAV") for our portfolio while
representing nearly one quarter of our active well count and installed
pipelines; and
-- We are closely monitoring the on-stream timing of our 2H18 light oil
Cardium program, which still delivers rates of return of greater than 60
percent with current outlook for pricing.
We expect a challenging fourth quarter with light sweet oil differentials recently exceeding US$30 per barrel and heavy oil differentials exceeding US$45 per barrel. However, it is our view that the current situation will improve by the second quarter of 2019. Given the unprecedented volatility in the Canadian crude oil market, we are deferring our 2019 outlook to Investor Day next week. I look forward to the opportunity to highlight the potential of our Cardium asset base and long-term strategy at that time."
Financial and Operating Highlights
Three months ended September 30
Nine months ended September 30
2018 2017
% 2018 2017
%
change change
---
Financial (millions, except per share
amounts)
Funds flow from operations (1) $
26 $
40 (35) $
93 $
140 (34)
Basic per share (1) 0.05 0.08 (38) 0.18 0.28 (36)
Diluted per share (1) 0.05 0.08 (38) 0.18 0.28 (36)
Net loss (31) (44) (30) (192) (26)
>100
Basic per share (0.06) (0.09) (33) (0.38) (0.05)
>100
Diluted per share (0.06) (0.09) (33) (0.38) (0.05)
>100
Capital expenditures (2) 41 55 (25) 127 105 21
Net Debt (1) $
446 $
410 9 $
446 $
410 9
Operations
Daily production
Light oil and NGL (bbls/d) 13,012 13,324 (2) 13,473 14,218 (5)
Heavy oil (bbls/d) 4,833 5,456 (11) 5,042 5,434 (7)
Natural gas (mmcf/d) 60 68 (12) 61 73 (16)
---
Total production (boe/d) (3) 27,777 30,166 (8) 28,633 31,816 (10)
---
Average sales price
Light oil and NGL (per $
75.49 $
51.06 48 $
71.27 $
54.85 30
bbl)
Heavy oil (per bbl) 45.30 30.36 49 40.11 31.69 27
Natural gas (per mcf) $
1.87 $
2.35 (20) $
2.12 $
2.91 (27)
Netback per boe (3)
Sales price $
47.26 $
33.37 42 $
45.09 $
36.60 23
Risk management gain (9.28) 2.24
>(100) (6.89) 2.69
>(100)
(loss)
Net sales price 37.98 35.61 7 38.20 39.29 (3)
Royalties (4.56) (2.27)
>100 (3.80) (2.54) 50
Operating expenses (4) (14.53) (14.05) 3 (14.62) (15.45) (5)
Transportation (3.71) (2.38) 56 (3.37) (2.50) 35
---
Netback (1) $
15.18 $
16.91 (10) $
16.41 $
18.80 (13)
---
(1) The terms "funds flow from
operations" and their
applicable per share amounts,
"Net Debt", 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
Peace River Oil Partnership
("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 third quarter of 2018 was $26
million. Increases in FFO from higher oil prices were offset by realized
risk management losses, crude oil differentials and lower production
volumes. Realized risk management losses for the quarter totaled $9.28
per boe compared to $7.28 per boe in the second quarter of 2018.
-- Invested $41 million of development capital expenditures, which focused
on accelerated development within the Cardium, drill and tie-in of one
Mannville well and spending on our gas gathering infrastructure to
satisfy the requirements under AER Directive 84 in Peace River. The gas
gathering system was commissioned in September on schedule.
-- Third quarter production averaged 27,777 boe per day, a decrease of
three percent relative to second quarter 2018. The Company's Mannville
well came on production in the third quarter with liquid rates higher
than expected. Overall, production was slightly behind estimates due to
lower rates from our first quarter Mannville and PCU #9 programs.
-- Average liquids sales prices in the third quarter were $67.31 per boe,
excluding the impact of hedging activities. Realized heavy oil pricing
in the quarter was $45.30 per bbl, a $1.51 per bbl decrease relative to
the second quarter which trended similar to benchmark Western Canadian
Select ("WCS") pricing which decreased by $1.06 per bbl. The Company has
a flexible marketing strategy in the Peace River area whereby we sell
into 10 different sales points with various benchmark prices independent
of WCS.
-- Average natural gas sales prices were $1.87 per mcf, with hedges
contributing an additional $0.40 per mcf. Realized gas pricing exceeded
AECO benchmark pricing as the Company continued to benefit from its
Ventura marketing arrangement.
-- Third quarter operating costs totaled $14.53 per boe, relatively
unchanged from the second quarter. Higher power prices continued to
impact operating costs, partially offset by decreases in trucking costs.
-- Third quarter G&A per boe totaled $2.19 compared to $2.49 per boe in the
second quarter of 2018. The reductions are the result of the Company's
focus on several cost saving initiatives.
-- Net Debt of $446 million at September 30, 2018 increased from $408
million at June 30, 2018, mainly due the settlement of the outstanding
GBP currency swap and our accelerated Cardium development program. Net
debt includes $316 million drawn on our revolving credit facility and
$78 million of senior notes.
-- The Company has proactively entered into an agreement to temporarily
amend its financial covenants in response to volatile crude oil
differentials. This allows the Company the financial flexibility to
maintain its Cardium development program as planned. The maximum Senior
debt to EBITDA ratio will be less than or equal to 3.75:1 for the period
of October 1, 2018 through and including March 31, 2019, decreasing to
less than or equal to 3.25:1 for the quarter ending June 30, 2019, and
then reverting back to 3:1 from July 1, 2019 and beyond. The Company
expects sufficient headroom in the second half of 2019 due to the
increase in Cardium production and expiry of out of the money crude oil
hedges resulting in higher cash flow.
The table below outlines select metrics in our key development and legacy areas for the three months ended September 30, 2018 and excludes the impact of hedging:
Area Select Metrics - Three Months Ended September 30,
2018
---
Production
Liquids Operating Netback
Weighting Cost
---
Cardium
17,863 boe/d 64%
$13/boe
$31/boe
Deep Basin
1,641 boe/d 25%
$2/boe
$18/boe
Alberta Viking
1,585 boe/d 48%
$13/boe
$21/boe
Peace River
4,724 boe/d 96%
$16/boe
$21/boe
---
Key Development
Areas
25,813 boe/d 67%
$13/boe
$28/boe
Legacy Areas
1,964 boe/d 20%
$24/boe
$(6)/boe
---
Key Development &
Legacy Areas
27,777 boe/d 64%
$15/boe
$24/boe
---
Operational Update
The third quarter has been a busy development focused period for Obsidian Energy, and we are pleased with performance in the field.
In our 2H18 Cardium program, nine of the program's 15 wells have been rig released since early July and costs have been below budget assumptions. Our drilling performance has been strong, with new Corporate pacesetters for both intermediate-casing (13.4 drilling days at 00/16-15-043-08W5, 4,820 meters) well designs and monobore-casing (12.1 drilling days at 02/05-35-042-08W5, 4,691 meters) well designs, despite their considerable length.
Stimulation and flowback of the first pad in the program (08-09 pad site) is complete and the wells will be tied-in mid-November. Early results have been positive, with post-fracture oil rates consistent with the strong 11-03 and 09-04 pads (five total wells) immediately to the South which averaged approximately 515 boe per day for the first 60 days of production (81 percent oil). Inclusive of the 08-09 pad, we expect eight of the fifteen wells will be ready to produce by year-end. Likewise, the 14-01 pad site wells are showing similar post-fracture oil rates to wells drilled on that pad in early 2018.
Our single, second half 2018 Deep Basin well has performed well. Drilling and completion costs came in on budget and the well averaged 1,355 boe per day over the first 60 days of production, with field condensate rates better than expected at approximately 246 bbl per day. The well produces directly into Company-owned and operated infrastructure.
In the Peace River area, the Company has successfully completed our four-well drilling program in this quarter. The project was completed on time and on budget, and the first pad (2 wells) was brought on production in early October. In response to the current heavy-oil differential environment and our expectations that differentials will improve considerably in 2019, the Company has elected to defer the peak rates from all four new wells until pricing improves. Detailed productivity of the wells will be confirmed at that time, but peak rates of 300 bbl per day per well are expected.
Shut-in of Legacy Production
The Company has determined that the shut-in of select legacy dry gas producing properties will positively affect our cash flows, total operating costs, and Corporate unit operating costs. This action will reduce the Company's production by approximately 1,300 boe per day (2019 forecast contribution, 89 percent natural gas), however, increase cash flow by approximately $4 million and reduce unit operating costs by approximately $0.40 per boe. Furthermore, the Company expects liquids weighting to rise approximately two percent and producing netbacks to improve by approximately $1.00 per boe.
The staggered abandonment of cash flow negative assets, where divestment options have been exhausted, is enabled by our commitment to the AER's recently-announced Area-Based Closure initiative. ABC participation enables a clear path to manage annual liability spend in a regulated and staged approach, yielding a more efficient and moderated spend profile.
The table below provides a summary of our operated activity in the third quarter.
Number of Wells Q3 2018
Drilled Completed On-stream
Gross Net
Gross Net
Gross Net
Cardium
Producer 4 4 0 0.0 0 0.0
Injector 0 0.0 0 0.0 0 0.0
Deep Basin 1 0.7 1 0.7 1 0.7
Alberta Viking 0 0.0 0 0.0 0 0.0
Peace River 3 1.7 2 1.1 0 0.0
---
Total 8 6.4 3 1.8 1 0.7
---
Current Hedging Position
No hedges were added recently as we are within approved levels. 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:
Q4 2018
Q1 2019
Q2 2019
Q3 2019
WTI $49.78 $50.02 $56.53 $57.00
$USD
bbl/day 8,000 3,000 2,000 1,000
WTI $71.04 $67.88 $68.58
$CAD
bbl/day 4,000 6,000 4,000
---
Total
bbl/day 12,000 9,000 6,000 1,000
---
Additionally, the Company has the following foreign exchange contracts in place:
-- In 2018, foreign exchange swaps at an average of 1.268 on notional US$9
million per month and a foreign exchange collar at an average of 1.210 -
1.272 on notional US$2 million per month.
-- In the first quarter of 2019, foreign exchange swaps at an average of
1.300 on notional US$2 million per month.
Currently, the Company has the following natural gas hedges in place:
Q4 2018
AECO $CAD $2.67
mcf/day 15,200
Ventura $USD (1) $2.79
mcf/day 7,500
---
Total
mcf/day 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.
Full Year 2018 Guidance Update
We are adjusting full year 2018 guidance due to the continued higher water cuts of our early 2018 injector development in PCU #9, lower than anticipated volumes from our 1H18 Mannville well, and deliberate choices on fourth quarter production due to differentials. This is partially offset by ahead of schedule delivery of our 15 well 2H18 Cardium development. This has a follow-on impact on Operating Costs per boe due to the lower volume assumptions. There is no change to our Total Capital Expenditure Guidance.
Metric
Previous 2018 Guidance Range
Updated Guidance Range
---
Production
29,000 to 30,000 boe per day
28,500 to 29,000 boe per day
Production Growth Rate (1) 5% 3%
Operating Costs
$13.00 - $13.50 per boe
$13.75 - $14.00 per boe
General & Administrative
$2.00 - $2.50 per boe
No change
---
(1) Relative to full year 2017
production, adjusted for all
2017 & 2018 A&D, of 28,000
boe per day
Investor Day Presentation to be held Thursday, November 15, 2018
There will be no conference call accompanying the quarterly release as Management will be hosting a comprehensive presentation via webcast at the Investor Day on Thursday, November 15, beginning at 9:00 am Mountain Time (11:00 am Eastern Time).
This presentation will offer the investment community a comprehensive technical overview of our current operations, long term development potential and corporate strategy. The event will be held in Calgary for analysts and sales representatives and simultaneously webcast for the broader investment community. To access the webcast please use the following URL:
https://event.on24.com/wcc/r/1850864/107BFCA7194ADB4B52B1FE66B4967F4E
Investors will be invited to ask questions through the online webcast portal throughout the presentation, or to submit questions ahead of time by emailing investor_relations@ObsidianEnergy.com. A recording of the Investor Day presentation will be available for replay after the conclusion of the presentation on our website www.obsidianenergy.com, or directly at the above URL.
Supporting Financial Documents
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 in due course.
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 Nine months ended
(millions, except per share amounts)
September 30 September 30
---
2018 2017 2018 2017
---
Cash flow from operating activities $
43 $
61 $
80 $
118
Change in non-cash working capital (40) (34) (46) (18)
Decommissioning expenditures 2 2 5 9
Office lease settlements 1 3 10 11
Settlements of normal course foreign exchange (8)
contracts
Realized foreign exchange loss - debt maturities 8 4
Realized foreign exchange loss - hedging repayment 18 18
Carried operating expenses (1) 5 15
Restructuring charges - cash portion (2) 3 8 9
Other expenses 2 10
---
Funds flow from operations $
26 $
40 $
93 $
140
--- ---
Per share
Basic per share $
0.05 $
0.08 $
0.18 $
0.28
Diluted per share $
0.05 $
0.08 $
0.18 $
0.28
--- ---
(1) The benefit of carried operating
expenses from the Company's
partner under PROP was fully
utilized in December 2017.
(2) Excludes the non-cash portion
of restructuring totaling $8
million, on payments due in
2019 and 2020.
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: our expectations for full year 2018 production guidance to be slightly below estimates and the reasons for the expectation change; our expectation for when certain wells will be on production and the resulting production wedge that could occur based on that timing; the expectation that the Company's participation in the ABC program will have on the 2019 FFO and reduction to our undiscounted Asset Retirement Obligations on those assets; that participation in the ABC program enables a clear path to manage annual liability spend in a regulated and staged approach, yielding a more efficient and moderated spend profile; our expectations for fourth quarter differential on light sweet and heavy oil and that those differentials will improve in the second quarter of 2019; that we will defer our 2019 outlook to Investor Day; that we will have an Investor Day with presentation webcast; that the amendment to the Company's financial covenants on Senior Debt allows it the financial flexibility to maintain its Cardium development program as planned; the expectation of sufficient headroom in the second half of 2019 due to the increase in Cardium production and expiry of our out of the money crude oil hedges resulting in higher cash flow; that we will defer the peak rates on certain wells in Peace River until pricing improves and the expectation of the initial productivity and peak rates of those wells; the positive impact that the shutting-in of select legacy dry gas producing properties will have on the Company, its production, cash flow, operating costs, netbacks and liquids weighting; that we do not expect to add incremental 2019 hedges at this time; and the updated guidance for production, operating costs, G&A and production growth.
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; 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.
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SOURCE Obsidian Energy Ltd.
