Ovintiv Reports Second Quarter Financial and Operating Resul

|Jul 28|magazine53 min read

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) 
 ($ millions, except as indicated)

2Q 2020

2Q 2019

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)

($ millions, except as indicated)

2Q 2020

2Q 2019

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,
Restructuring Costs and Current Expected Credit Losses

1.38

1.48

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
Swap Price

882 MMcf/d
$2.57

165 MMcf/d
$2.51


WTI Swaps
Swap Price

125 Mbbls/d
$47.58

7 Mbbls/d
$43.02

NYMEX 3-Way Options
Short Call
Long Put
Short Put

330 MMcf/d
$2.72
$2.60
$2.25

170 MMcf/d
$3.22
$2.75
$2.50


WTI 3-Way Options
Short Call
Long Put
Short Put

38 Mbbls/d
$61.46
$53.36
$43.36

15 Mbbls/d
$50.00
$35.23
$24.64

NYMEX Costless Collars
Short Call
Long Put

55 MMcf/d
$2.88
$2.50



WTI Costless Collars
Short Call
Long Put

15 Mbbls/d
$68.71
$50.00

15 Mbbls/d
$45.84
$35.00

Basis Hedges ($/Mcf)



Basis Hedges ($/bbl)


AECO Basis Swaps
Swap Price

238 MMcf/d
($0.88)

75 MMcf/d
($1.01)


WTI / Midland Swaps
Swap Price

3.5 Mbbls/d
($1.20)


WAHA Basis Swaps
Swap Price

105 MMcf/d
($0.91)

86 MMcf/d
($0.80)


(1) Table exclude 2021 WTI swaption 10 Mbbls/d @ $58.00

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:

(888) 525-0304 


Media contact:

(281) 210-5253

 

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