Ovintiv Reports Second Quarter Financial and Operating Results
Strong capital efficiency drives lower planned 2020 capital spending, higher expected fourth quarter production
Highlights:
-- 2020 planned capital investments reduced to $1.8 billion, the low end of
previous expected range of $1.8 - $1.9 billion.
-- Second quarter capital investments were $252 million (compared to
guidance of $250 - $300 million).
-- Fourth quarter 2020 average crude and condensate((1) )production
outlook was increased to 200 thousand barrels per day (Mbbls/d)
(previously forecast as a year-end exit rate).
-- Increased estimated 2020 cash cost savings to more than $200 million;
approximately half of the savings have been achieved year-to-date and
the majority are expected to be durable in future years.
-- Second quarter average drilled and completed (D&C) well costs were
approximately 15% lower than 2019 average results, and three-quarters of
the way to the Company's estimated 20% reduction in 2021.
-- Recent strong results increase confidence in 2021 "stay-flat" crude and
condensate scenario with $1.4 - $1.6 billion in capital investments.
-- The Company stated that all excess cash flows would be allocated to debt
reduction over the next six quarters.
DENVER, July 28, 2020 /PRNewswire/ - Ovintiv Inc. (NYSE: OVV) (TSX: OVV) today announced its second quarter 2020 financial and operating results and will hold a conference call and webcast at 9 a.m. MT (11 a.m. ET) on July 29, 2020. Please see dial-in details within this release, as well as additional details on the Company's website at www.ovintiv.com.
"During a very challenging period, we took advantage of the tremendous flexibility we have built into our business and performed exceptionally well through the first half of 2020--maintaining a sharp focus on driving efficiencies in every part of the Company and positioning Ovintiv to thrive in 2020 and beyond," said Doug Suttles, Ovintiv President and CEO. "Our culture of innovation is allowing us to drive down drilling and completion costs, enhance margins through durable cost savings and strengthen our capital efficiency outlook. We are even more confident in our ability to deliver the 2021 scenario we discussed last quarter which maintains scale and our strong capital structure while generating free cash flow at modest commodity prices. We have a demonstrated track record of generating free cash flow--$52 million this quarter and about $290 million over the last four quarters. For the next six quarters, all excess cash flows will go towards reducing our debt."
Second Quarter 2020 Financial and Operating Results
The Company recorded a net loss in the second quarter of $4.4 billion, or $16.87 per share of common stock. Results were impacted by the following items:
-- A non-cash ceiling test impairment of $3,250 million, before-tax,
primarily related to the decline in 12-month average trailing commodity
prices which reduced SEC proved reserves.
-- A non-cash charge of $568 million related to a deferred tax asset
valuation allowance.
-- A non-cash unrealized loss on risk management of $679 million,
before-tax, related to the mark-to-market value of derivative positions.
-- A restructuring charge of $81 million, before-tax, related to a 25%
reduction in Ovintiv's workforce as staffing levels were balanced with
planned activity levels.
Excluding these and other items, the Company reported a non-GAAP operating loss of $111 million. Cash from operating activities was $117 million and non-GAAP cash flow was $304 million. Cash flow was impacted by the $81 million restructuring charge mentioned above.
1. Throughout this document,
crude and condensate refers to
tight oil including medium and
light crude oil volumes and
plant condensate.
Ovintiv delivered higher than expected production during the quarter and continued to show significant reductions in costs. Capital investment levels were below the mid-point of the Company's previous guidance.
-- Total average production for the second quarter was nearly 537 thousand
barrels of oil equivalent per day (MBOE/d). Crude and condensate
production averaged 198 Mbbls/d. In response to low oil prices, the
Company voluntarily shut-in, delayed or curtailed approximately 32
MBOE/d, or 18 Mbbls/d of crude and condensate during the quarter.
Substantially all shut-in volumes are now back on-line.
-- Total Costs of $11.23 per BOE were nearly 8% lower when compared to the
first quarter of 2020.
-- Second quarter capital investments were $252 million and nearly 70%
below first quarter 2020 investment levels. The Company moved rapidly
from its March 2020 operated rig count of 23 rigs to seven rigs by
mid-May. Completion activities were halted across the business during
the quarter.
2020 and 2021 Scenario
Recent operating results have helped confirm key financial and operating assumptions behind the future "scenarios" the Company outlined in May 2020.
-- 2020--the Company today reduced its outlook for 2020 investments to
approximately $1.8 billion (previously $1.8 - $1.9 billion).
Expectations for fourth quarter crude and condensate production were
raised with the Company changing its previous 200 Mbbls/d 2020 "exit
rate" to a fourth quarter 2020 average. During the second quarter,
Ovintiv increased its original full-year cash cost savings estimate to
more than $200 million, of which approximately half has been achieved
through mid-year. Ovintiv plans to resume well completions in the third
quarter on more than 100 drilled but uncompleted wells (DUCs). As a
result of the second quarter completion holiday, third quarter crude and
condensate production is expected to be the trough for the year and
average approximately 180 Mbbls/d. The majority of the DUCs are expected
to commence production by year-end 2020 and a typical level of DUCs will
be carried into 2021.
-- 2021--the 2020 cost reductions are durable into 2021 and an additional
$100 million of reduced legacy costs will enhance cash flow. Assuming
benchmark prices of $35 per barrel WTI and $2.75 per MMBtu NYMEX natural
gas, Ovintiv could invest approximately $1.4 - $1.6 billion and balance
capital expenditures with non-GAAP free cash flow and fund its annual
dividend to shareholders. This level of investment would hold crude and
condensate volumes flat throughout the year at approximately 200
Mbbls/d.
Strong Hedge Position Protects Cash Flow
Ovintiv is substantially hedged on near-term, benchmark oil price risk. For the third quarter, 175 Mbbls/d are hedged at an average price of $45.06 per barrel. Of these positions, 160 Mbbls/d are in fixed price swaps at $44.60 per barrel and 15 Mbbls/d are covered by costless collars between $50.00 and $68.71 per barrel. "Benchmark" refers to NYMEX WTI. Natural gas hedges are also in place on approximately 1.4 billion cubic feet per day of production hedged at an average price of $2.53 per thousand cubic feet (Mcf).
-- Second quarter 2020 average realized prices including hedge of $39.70
per barrel for oil, $17.78 per barrel for NGLs and $2.09 per thousand
cubic feet (Mcf) for natural gas, resulted in a total equivalent price
of $21.21 per BOE. Ovintiv realized second quarter total hedging gains
of $365 million, before-tax.
-- Second quarter 2020 average realized prices excluding hedge of $22.91
per barrel for oil, $12.30 per barrel for NGLs and $1.57 per Mcf for
natural gas resulted in a total equivalent price of $13.80 per BOE.
Based on the forward strip as of June 30, third quarter realized risk management gains on benchmark oil and natural gas are expected to total approximately $180 million, and total $406 million for the balance-of-year-2020. Settlements for various other oil differential and natural gas basis positions in 2020 serve to further reduce risk. See the Hedge Volume and Hedging Price Sensitivity tables below.
Balance Sheet and Liquidity
Current liquidity is approximately $3.0 billion, which represents the Company's $4 billion committed, unsecured credit facilities, available capacity on uncommitted demand lines and cash-on-hand, less the amount drawn on the credit facilities.
During the first half of the year, Ovintiv repurchased approximately $137 million in principal amount of its senior notes in the open market for an aggregate cash payment of approximately $115 million, plus accrued interest. The Company has significant flexibility to manage the late 2021 and 2022 maturities, including the use of its credit facilities.
Approximately 80% of the Company's total fixed-rate long-term debt is due in 2024 or later and has an aggregate weighted average bond maturity of approximately nine years.
Refer to Note 1 Non-GAAP measures and the tables in this release for reconciliation to comparable GAAP financial measures.
Asset Highlights
The Company set new, record-low well drilling and completion costs in each of its Core 3 asset areas during the second quarter. A chart comparing previous well costs by area to current estimates is included in today's accompanying presentation on the website.
Permian
Permian production averaged 111 MBOE/d (81% liquids) in the quarter. The Company averaged four rigs, down from five in the first quarter of 2020. During the quarter, 23 net wells were drilled, and 13 net wells were turned in line (TIL). Ovintiv is currently running three rigs in the play.
The Company continues to advance Simul-Frac learnings in the Permian, leading to increased completion rates and lower cycle times over the quarter. These increased efficiencies resulted in a 19% improvement in the second quarter D&C well costs compared to 2019 average well costs.
Anadarko
Anadarko production averaged 144 MBOE/d (61% liquids) in the quarter. The Company averaged three rigs, down from six in the first quarter of 2020. During the second quarter, 13 net wells were drilled, and 17 net wells were TIL. Ovintiv is currently running two rigs in the play.
14 STACK wells in 2020 have been drilled and completed for less than $5 million. The pacesetter D&C well cost is now $4.4 million representing a 30% reduction from 2019 average results.
Montney
Second quarter Montney liquids production averaged 49 Mbbls/d. Total production in the play averaged 203 MBOE/d (24% liquids). During the quarter, the Company averaged two rigs, down from five in the first quarter of 2020. During the quarter, 12 net wells were drilled, and eight net wells were TIL. Ovintiv is currently running two rigs in the play.
The Company achieved a record completion rate on a recent four-well pad in Pipestone of 3,450 feet per day, a 45% improvement compared to the 2019 average. First half 2020 D&C well costs averaged $480 per foot in Pipestone, representing a 14% improvement over 2019 average costs.
Base Assets
Base assets in the portfolio include the Eagle Ford, Bakken, Uinta and Duvernay. There were no wells TIL in these areas during the second quarter.
For additional information, please refer to the 2Q 2020 Results Presentation at https://investor.ovintiv.com/presentations-events.
Dividend Declared
On July 28, 2020, Ovintiv's Board declared a dividend of $0.09375 per share of common stock payable on September 30, 2020 to common stockholders of record as of September 15, 2020.
Conference Call Information
A conference call and webcast to discuss the Company's second quarter results will be held at 9 a.m. MT (11 a.m. ET) on July 29, 2020. To participate in the call, please dial 888-664-6383 (toll-free in North America) or 416-764-8650 (international) approximately 15 minutes prior to the conference call. The live audio webcast of the conference call, including slides and financial statements, will be available on Ovintiv's website, www.ovintiv.com under Investors/Presentations and Events. The webcast will be archived for approximately 90 days.
Capital Investment and Production
(for the three months ended June 30) 2Q 2020 2Q 2019
---
Capital Expenditures (1) ($ millions) 252 750
===
Oil (Mbbls/d) (2) 146.5 179.3
NGLs - Plant Condensate (Mbbls/d) 51.8 55.3
NGLs - Other (Mbbls/d) 80.1 89.4
---
Total NGLs (Mbbls/d) 131.9 144.7
---
Total Liquids (Mbbls/d) 278.4 324.0
---
Natural gas (MMcf/d) (3) 1,550 1,607
===
Total production (MBOE/d) 536.6 591.8
---
(1) Including capitalized overhead
costs.
(2) Primarily tight oil, including
minimal medium and light crude
oil volumes.
(3) Primarily shale gas, including
minimal conventional natural
gas.
Second Quarter Summary
(for the three months ended June 30) 2Q 2020
2Q 2019
($ millions, except as indicated)
---
Cash from (used in) operating activities 117 906
Deduct (add back):
Net change in other assets and liabilities (68) (15)
Net change in non-cash working capital (119) 44
Current tax on sale of assets
---
Non-GAAP cash flow (1) 304 877
---
Non-GAAP cash flow margin (1) ($/BOE) 6.23 16.27
===
Non-GAAP cash flow
(1) 304 877
---
Less: Capital Expenditures 252 750
---
Non-GAAP free cash flow
(1) 52 127
===
Net earnings (loss) (4,383) 336
Before-tax (addition) deduction:
Unrealized gain (loss) on risk management (679) 83
Impairments (3,250)
Restructuring charges (81) (17)
Non-operating foreign exchange gain (loss) 50 46
Gain (loss) on divestitures
Gain on debt retirement 11
---
Income tax (3,949) 112
(323) (66)
After-tax (addition) deduction (4,272) 46
---
Non-GAAP operating earnings (loss) (1) (111) 290
---
(1) Non-GAAP cash flow,
non-GAAP cash flow
margin, non-GAAP free
cash flow and non-GAAP
operating earnings are
non-GAAP measures as
defined in Note 1.
Realized Pricing Summary
(for the three months ended June 30) 2Q 2020 2Q 2019
---
Liquids ($/bbl)
---
WTI 27.85 59.82
---
Realized liquids prices
(1)
---
Oil 39.70 60.14
---
NGLs - Plant Condensate 31.37 53.57
---
NGLs - Other 9.01 14.75
---
Total NGLs 17.78 29.57
===
Natural gas
---
NYMEX ($/MMBtu) 1.72 2.64
---
Realized natural gas price
(1)
($/Mcf) 2.09 2.22
===
(1) Prices include the impact of
realized gain (loss) on risk
management.
Total Costs Summary
(for the three months ended June 30) 2Q 2020
2Q 2019
($ millions, except as indicated)
===
Total Operating Expenses 4,785 1,517
Deduct (add back):
Market optimization operating expenses 382 286
Corporate & other operating expenses (1)
Depreciation, depletion and amortization 493 532
Impairments 3,250
Accretion of asset retirement obligation 9 10
Long-term incentive costs 25 (15)
Restructuring costs 81 17
Current expected credit losses (3)
---
Total Costs
(1) 548 688
---
Divided by:
Production Volumes (MMBOE) 48.8 53.9
---
Total Costs
(1)
($/BOE) 11.23 12.78
---
Drivers included in Total Costs ($/BOE)
Production, mineral and other taxes 0.55 1.36
Upstream Transportation and Processing 6.44 6.54
Upstream Operating, Excluding Long Term Incentive Costs 2.86 3.40
Administrative, Excluding Long-Term Incentive Costs, 1.38 1.48
Restructuring Costs and Current Expected Credit Losses
---
Total Costs $/BOE 11.23 12.78
===
(1) Calculated using whole
dollars and volumes. Total
Cost is a non-GAAP measure
as defined in Note 1.
Debt to Adjusted Capitalization
($ millions, except
as indicated) June 30, 2020 December 31, 2019
===
Long-Term Debt,
including current
portion 7,366 6,974
Total Shareholders'
Equity 5,873 9,930
Equity Adjustment
for Impairments at
December 31, 2011 7,746 7,746
---
Adjusted
Capitalization 20,985 24,650
---
Debt to Adjusted
Capitalization (1) 35% 28%
===
(1) Debt to Adjusted
Capitalization is a non-GAAP
measure as defined in Note 1.
Hedge Volumes as of June 27, 2020
Natural Gas Hedges
3Q/4Q 2020 2021
Oil & Condensate Hedges (1) 3Q/4Q 2020 2021
--- ---
Total Hedges 1,267 MMcf/d 335 MMcf/d
Total Hedges 178 Mbbls/d 37 Mbbls/d
---
Hedges ($/Mcf)
Hedges ($/bbl)
---
NYMEX Swaps
882 MMcf/d 165 MMcf/d
WTI Swaps 125 Mbbls/d 7 Mbbls/d
Swap Price $2.57 $2.51
Swap Price $47.58 $43.02
---
NYMEX 3-Way Options
330 MMcf/d 170 MMcf/d
WTI 3-Way Options 38 Mbbls/d 15 Mbbls/d
Short Call $2.72 $3.22 Short Call $61.46 $50.00
Long Put $2.60 $2.75
Long Put $53.36 $35.23
Short Put $2.25 $2.50
Short Put $43.36 $24.64
---
NYMEX Costless Collars
55 MMcf/d
WTI Costless Collars 15 Mbbls/d 15 Mbbls/d
Short Call $2.88 Short Call $68.71 $45.84
Long Put $2.50
Long Put $50.00 $35.00
---
Basis Hedges ($/Mcf) Basis Hedges ($/bbl)
---
AECO Basis Swaps
238 MMcf/d 75 MMcf/d
WTI / Midland Swaps 3.5 Mbbls/d
Swap Price ($0.88) ($1.01)
Swap Price ($1.20)
---
WAHA Basis Swaps
105 MMcf/d 86 MMcf/d (1) Table exclude 2021 WTI swaption 10 Mbbls/d @
$58.00
Swap Price ($0.91) ($0.80)
---
Price Sensitivities for WTI Oil Hedge Gains/Losses by Quarter for 2020 ($ MM):
Period $10 $20 $30 $40 $50
---
3Q 2020 565 404 243 82 (79)
---
4Q 2020 477 381 285 190 48
---
3Q-4Q Total 1,042 785 528 272 (31)
---
Price Sensitivities for NYMEX Natural Gas Hedge Gains/Losses by Quarter for 2020 ($ MM)
Period $1.00 $1.25 $1.50 $1.75 $2.00 $2.25
---
3Q 2020 155 131 108 84 60 37
---
4Q 2020 141 121 102 82 63 43
---
3Q-4Q Total 296 252 210 166 123 80
---
Note: Sensitivities do not include
gains or losses related to
differential hedges.
Note: Company has additional hedges
on Butane and Propane not
included.
Important information
Ovintiv reports in U.S. dollars unless otherwise noted. Production, sales and reserves estimates are reported on an after-royalties basis, unless otherwise noted. The term liquids is used to represent oil and NGLs. The term liquids-rich is used to represent natural gas streams with associated liquids volumes. Unless otherwise specified or the context otherwise requires, references to Ovintiv or to the Company includes reference to subsidiaries of and partnership interests held by Ovintiv Inc. and its subsidiaries.
NOTE 1: Non-GAAP measures
Certain measures in this news release do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. These measures may not be comparable to similar measures presented by other companies and should not be viewed as a substitute for measures reported under U.S. GAAP. These measures are commonly used in the oil and gas industry and/or by Ovintiv to provide shareholders and potential investors with additional information regarding the Company's liquidity and its ability to generate funds to finance its operations. For additional information regarding non-GAAP measures, see the Company's website. This news release contains references to non-GAAP measures as follows:
-- Non-GAAP Cash Flow is a non-GAAP measure defined as cash from (used in)
operating activities excluding net change in other assets and
liabilities, net change in non-cash working capital and current tax on
sale of assets. Non-GAAP Cash Flow Margin is a non-GAAP measure defined
as Non-GAAP Cash Flow per BOE of production. Non-GAAP Free Cash Flow is
a non-GAAP measure defined as Non-GAAP Cash Flow in excess of capital
investment, excluding net acquisitions and divestitures.
-- Non-GAAP Operating Earnings (Loss) is a non-GAAP measure defined as net
earnings (loss) excluding non-recurring or non-cash items that
management believes reduces the comparability of the company's financial
performance between periods. These items may include, but are not
limited to, unrealized gains/losses on risk management, impairments,
restructuring charges, non-operating foreign exchange gains/losses,
gains/losses on divestitures and gains on debt retirement. Income taxes
may include valuation allowances and the provision related to the
pre-tax items listed, as well as income taxes related to divestitures
and U.S. tax reform, and adjustments to normalize the effect of income
taxes calculated using the estimated annual effective income tax rate.
-- Total Costs is a non-GAAP measure which includes the summation of
production, mineral and other taxes, upstream transportation and
processing expense, upstream operating expense and administrative
expense, excluding the impact of long-term incentive costs,
restructuring costs and current expected credit losses. It is calculated
as total operating expenses excluding non-upstream operating costs and
non-cash items which include operating expenses from the Market
Optimization and Corporate and Other segments, depreciation, depletion
and amortization, impairments, accretion of asset retirement obligation,
long-term incentive costs, restructuring costs and current expected
credit losses. When presented on a per BOE basis, Total Costs is divided
by production volumes. Management believes this measure is useful to the
Company and its investors as a measure of operational efficiency across
periods.
-- Debt to Adjusted Capitalization is a non-GAAP measure which adjusts
capitalization for historical ceiling test impairments that were
recorded as at December 31, 2011. Management monitors Debt to Adjusted
Capitalization as a proxy for the Company's financial covenant under the
Credit Facilities which require debt to adjusted capitalization to be
less than 60 percent. Adjusted Capitalization incudes debt, total
shareholders' equity and an equity adjustment for cumulative historical
ceiling test impairments recorded as at December 31, 2011 in conjunction
with the Company's January 1, 2012 adoption of U.S. GAAP.
ADVISORY REGARDING OIL AND GAS INFORMATION - The conversion of natural gas volumes to barrels of oil equivalent (BOE) is on the basis of six thousand cubic feet to one barrel. BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. Readers are cautioned that BOE may be misleading, particularly if used in isolation.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS - This news release contains certain forward-looking statements or information (collectively, "FLS") within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of 1995. FLS include: anticipated cost savings, capital efficiency and sustainability thereof; estimated hedging revenue and sensitivity to commodity prices; shut-in strategy; production, total cash costs and capital investments versus expectations; capital investment scenarios and associated production; anticipated cash flow; statements regarding the Company's application of excess cash flow to reduce debt; operational flexibility, legacy costs, future well costs, service cost savings and efficiency gains; anticipated success of and benefits from technology and innovation; expected rigs and locations thereof; expected activity and investment levels; expected drilling and completions activity and the timing thereof; fourth quarter production outlook and ability to make adjustments as conditions dictate; use of the Company's credit facilities and ability to manage near-term maturities; financial flexibility and ability to respond to evolving market conditions; and pacesetting metrics being indicative of future well performance. FLS involve assumptions, risks and uncertainties that may cause such statements not to occur or results to differ materially. These assumptions include: future commodity prices and differentials; assumptions contained herein; data contained in key modeling statistics; availability of attractive hedges and enforceability of risk management program; and expectations and projections made in light of the Company's historical experience. Risks and uncertainties include: suspension of or changes to guidance, and associated impact to production; ability to generate sufficient cash flow to meet obligations; commodity price volatility and impact to the Company's stock price and cash flows; ability to secure adequate transportation and potential curtailments of refinery operations, including resulting storage constraints or widening price differentials; discretion to declare and pay dividends, if any; business interruption, property and casualty losses or unexpected technical difficulties; impact of COVID-19 to the Company's operations, including maintaining ordinary staffing levels, securing operational inputs, executing on portions of its business and cyber-security risks associated with remote work; counterparty and credit risk; impact of changes in credit rating and access to liquidity, including costs thereof; risks in marketing operations; risks associated with technology; risks associated with decommissioning activities, including timing and costs thereof; and other risks and uncertainties as described in the Company's Annual Report on Form 10- K, Quarterly Report on Form 10-Q and as described from time to time in its other periodic filings as filed on EDGAR and SEDAR. Although the Company believes such FLS are reasonable, there can be no assurance they will prove to be correct. The above assumptions, risks and uncertainties are not exhaustive. FLS are made as of the date hereof and, except as required by law, the Company undertakes no obligation to update or revise any FLS.
Further information on Ovintiv Inc. is available on the Company's website, www.ovintiv.com, or by contacting:
Investor contact: Media contact:
(888) 525-0304 (281) 210-5253
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