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Pengrowth Recorded Positive Adjusted Funds Flow in the Third Quarter of 2019 of $10.7 million Despite Lower Commodity Prices and Restructuring Costs


CALGARY, Alberta, Nov. 06, 2019 (GLOBE NEWSWIRE) — Pengrowth Energy Corporation (“Pengrowth” or the “Company“) (TSX:PGF, OTCQX:PGHEF), today reported its results for the three and nine months ended September 30, 2019. Unless otherwise indicated, financial figures are expressed in Canadian dollars.

“Negotiations with our lenders on an amendment and extension of our notes and credit facility as discussed in our September 30th press release broke down in October,” said Pete Sametz, President and Chief Executive Officer of Pengrowth. “While we are disappointed in the impact this has had on our shareholders, the transaction with Cona Resources Ltd. announced on November 1st represents the best value for our stakeholders after a comprehensive strategic review process, and the only available path to provide any value to our shareholders.”

Third Quarter 2019 Summary:

  • Pengrowth third quarter 2019 adjusted funds flow of $10.7 million decreased 31% year-over-year and included $8.9 million in restructuring costs related to legal and advisory fees for the strategic review and lender negotiations.
  • Lindbergh SAGD bitumen production increased 7% year-over-year to 17,603 barrels per day (“bbl/d“) compared with 16,408 bbl/d. Compared with the second quarter of 2019, production decreased due to multiple lightning strikes at the end of July that temporarily disabled Lindbergh’s electrical grid resulting in reduced production.
  • Cash G&A expenses per barrel of oil equivalent (“/boe“) decreased 19% to $3.24/boe compared with $3.99/boe in the prior year.
  • Adjusted operating expenses per boe increased 2% to $10.89/boe compared with $10.72/boe in the prior year as a result of pump replacements related to the disruption of the electrical grid at the end of July.
  • Debt increased $3.0 million to $705.2 million at September 30, 2019 compared with $702.2 million at June 30, 2019 due to the impact of a weaker Canadian dollar at the end of the period which increased the Canadian dollar equivalent value of foreign denominated debt, partially offset by lower Credit Facility drawings.
  • Pengrowth recorded a $100.0 million non-cash impairment in the quarter which included $39.0 million related to the change in future development plans for the Groundbirch natural gas property, and $61 million related to certain non-core assets.

Cona Resources Ltd. Transaction
On November 1, 2019 Pengrowth announced that it entered into a definitive arrangement agreement (the “Arrangement Agreement”) with Cona Resources Ltd. (the “Purchaser”) pursuant to which the Purchaser has agreed to repay the outstanding principal amount and accrued interest to the date of the Arrangement Agreement owing under the Company’s credit facility and secured notes (collectively the “Secured Debt”) and acquire all of the outstanding common shares for cash consideration of CDN $0.05 per share and a potential Contingent Value Payment for each Pengrowth Share. The proposed transaction (the “Transaction”) is to be completed by way of plan of arrangement under the Business Corporations Act (Alberta).

The aggregate value of the Transaction, including the repayment of the Secured Debt and the assumption of the Transaction costs by the Purchaser, is approximately $740 million. The total consideration being offered to lenders and noteholders (collectively the “Secured Debtholders”) represents a discount on the aggregate amount owing to the Secured Debtholders. The consideration paid to Secured Debtholders will be allocated pro rata amongst individual holders pursuant to the intercreditor agreement between the Secured Debtholders.

In the event that Secured Debtholders representing a majority in number of Secured Debtholders holding at least 66 2/3% of the Secured Debt have not executed and delivered support agreements on or before November 15, 2019, the Purchaser may terminate the Arrangement Agreement. There is no certainty support agreements will be obtained in that time frame. In such circumstance, the Purchaser may seek within ten days of the termination of the Arrangement Agreement, to negotiate with Pengrowth an Alternative Transaction where Pengrowth shareholders may not receive any consideration in exchange for their shares.

Summary of Financial & Operating Results

Three months ended
(monetary amounts in millions except per boe and per share
amounts)
Sept 30, 2019 June 30, 2019 % Change Sept 30, 2018 % Change
PRODUCTION
Average daily production (boe/d) 21,460 22,707 (5) 21,807 (2)
FINANCIAL
Oil and gas sales $118.2 $144.4 (18) $147.2 (20)
Capital expenditures $2.7 $1.9 42 $6.8 (60)
Cash proceeds from dispositions $0.4 $(0.1) (500) $9.6 (96)
Interest and financing charges $14.2 $14.9 (5) $12.3 15
Cash flow from operating activities (1) $9.2 $30.9 (70) $21.8 (58)
Adjusted funds flow (1, 2) $10.7 $29.1 (63) $15.6 (31)
Weighted average number of shares outstanding (000’s) 560,114 560,022 556,117 1
Adjusted funds flow per share (2) $0.02 $0.05 (60) $0.03 (33)
OPERATIONAL
Produced petroleum revenue per boe (2) $38.14 $41.52 (8) $47.10 (19)
Operating expenses per boe $9.98 $8.32 20 $10.17 (2)
Adjusted operating expenses per boe (2) $10.89 $9.24 18 $10.72 2
Royalty expenses per boe $3.04 $3.63 (16) $3.69 (18)
Operating netback before realized commodity risk
management per boe (2)
$21.47 $25.70 (16) $29.85 (28)
Cash G&A expenses per boe (2) $3.24 $2.47 31 $3.99 (19)
STATEMENT OF INCOME (LOSS)
Net income (loss) $(119.9) $(76.5) 57 $(1.6) 7,394
Net income (loss) per share $(0.21) $(0.14) 50 $—
DEBT
Total debt before working capital (3) $705.2 $702.2 $672.2 5

(1) Includes $8.9 million in restructuring costs related to legal and advisory fees for the strategic review and lender negotiations.
(2) See definition in our MD&A under section “Non-GAAP Financial Measures“.
(3) Includes Credit Facility, current and long term portions of term notes, as applicable, and bank indebtedness. Excludes letters of credit and finance leases.

Alberta Production Curtailment Program
As one of the top 20 oil producers in Alberta, Pengrowth was subject to the Government of Alberta’s production curtailment program, which took effect on January 1, 2019. As of September 30, 2019, companies like Pengrowth with less than 20,000 bbl/d of production are exempted from the curtailment program. Even though Lindbergh was subject to mandatory curtailments, the asset produced 17,603 bbl/d in the third quarter of 2019 while remaining in compliance.

Year-to-Date 2019 Actual Results vs. 2019 Guidance
The following table provides a summary of Pengrowth’s actual results for the nine months ended September 30, 2019 compared with full year guidance:

Actual YTD
September 30, 2019
Original 2019
Guidance (1)
Revised 2019
Guidance (1)
Average oil equivalent production (boe/d) 22,306 22,500 – 23,500 21,750 – 22,250
Lindbergh average bitumen production (bbl/d) 17,942 17,750 – 18,250 17,750 – 18,250
Capital expenditures ($ millions) 16.0 45 21
Royalty expenses (% of produced petroleum revenue) (2) (3) 8.1 7.0 – 8.0 7.5 – 8.0
Adjusted operating expenses ($/boe) (2) 10.21 9.25 – 10.00 10.00 – 10.50
Cash G&A expenses ($/boe) (2) 2.97 2.50 – 2.75 3.00 – 3.25

(1) Per boe estimates based on high and low ends of production Guidance.
(2) See definition under section “Non-GAAP Financial Measures“.
(3) Excludes financial commodity risk management activities.

Year to date 2019 daily production of 22,306 boe/d was below 2019 Guidance primarily due to shut in natural gas production at Fenn Big Valley as a result of third party facility restrictions and a temporary drop in production at Lindbergh at the end of July due to an electrical storm that tripped the electrical grid. Total corporate oil-equivalent volumes guidance has been revised accordingly.

2019 Guidance for cash G&A expenses per boe also increased as a result of higher legal and severance costs combined with lower production. Pengrowth is providing an update to its 2019 adjusted operating expense Guidance driven by increased costs and lower production.

Capital spending for 2019 is not expected to exceed $21 million as we continue to work within capital restrictions imposed by the banks and we expect those conditions to carry though until the close of the Cona Transaction. Pengrowth is therefore revising its 2019 Capital expenditures Guidance from $45 million to $21 million.

Third Quarter Operational Review
Average daily production for the third quarter decreased 5% to 21,460 boe/d compared with 22,707 boe/d in the second quarter of 2019 primarily due to shut in natural gas production at Fenn Big Valley as a result of third party facility restrictions and a temporary drop in production at Lindbergh at the end of July due to an electrical storm that tripped the electrical grid and damaged several production pumps.

Production decreased 2% in the third quarter compared with the same period in the prior year due to shut in natural gas production at Fenn Big Valley as a result of third party facility restrictions, the absence of natural gas production from the Sable Offshore Energy Project (“SOEP“), and the disposition of Fenn Big Valley properties, partially offset by a 7% and 9% increase in production from Lindbergh and Groundbirch respectively.

Three months ended
PRODUCTION Sept 30, 2019 June 30, 2019 % Change Sept 30, 2018 % Change
Bitumen (bbl/d) 17,603 18,036 (2) 16,408 7
Natural gas (Mcf/d) 20,948 25,294 (17) 27,604 (24)
Light oil (bbl/d) 303 336 (10) 663 (54)
Natural gas liquids (NGL) (bbl/d) 63 120 (48) 135 (53)
Total boe/d 21,460 22,707 (5.5) 21,807 (1.6)

Lindbergh average daily bitumen production decreased 2% to 17,603 bbl/d in the third quarter compared with 18,036 bbl/d in the prior quarter due to a temporary drop in production at the end of July for the aforementioned reasons. Lindbergh contributed 82% of Pengrowth’s total production in the third quarter. The SOR for the third quarter was 2.90 compared with 2.80 in the prior quarter. The increase over the second quarter of 2019 was due to lower production coupled with record steam production. The cumulative SOR as at September 30, 2019 was 2.70.

Lindbergh Operating Netbacks Before Realized Commodity Risk Management
Lindbergh’s third quarter operating netbacks decreased 14% to $27.97/bbl compared with $32.57/bbl in the prior quarter primarily due to a 12% decrease in realized diluted bitumen revenue and a 21% increase in non-energy related adjusted operating costs largely related to lower production and electric submersible pump replacements following the July electrical outage. These were partially offset by lower diluent costs, royalties, energy related adjusted operating expenses (natural gas costs), and transportation expenses.

Compared to the same period in the prior year, Lindbergh operating netbacks decreased 28% primarily due to a 22% decrease in realized diluted bitumen prices and a 30% increase in energy related adjusted operating expenses (natural gas costs) partially offset by lower diluent costs, royalties, non-energy related adjusted operating expenses and transportation expenses.

Three months ended
Lindbergh Operating Netbacks ($/bbl) (1) Sept 30, 2019 June 30, 2019 % Change Sept 30, 2018 % Change
Diluted Bitumen Revenue (2) 51.99 58.87 (12) 66.23 (22)
Diluent Costs (Inc. transportation) (7.90) (9.88) (20) (9.59) (18)
Bitumen revenue (2) 44.09 48.99 (10) 56.64 (22)
Royalties (3.52) (4.39) (20) (4.84) (27)
Adjusted Operating expenses – Non-energy(1) (6.73) (5.54) 21 (7.49) (10)
Adjusted Operating expenses – Energy(1) (3.09) (3.26) (5) (2.38) 30
Transportation expenses (2.78) (3.23) (14) (3.05) (9)
Operating netbacks before realized commodity risk management 27.97 32.57 (14) 38.88 (28)

(1) See definition in our MD&A under section “Non-GAAP Financial Measures“.
(2) Net of Fixed Price Differential Physical Delivery Contracts.

Corporate Operating Netbacks
Corporate operating netbacks before realized commodity risk management in the third quarter decreased 16% to $21.47/boe compared with $25.70/boe in the second quarter of 2019 due to an 8% decrease in produced petroleum revenue and an 18% increase in adjusted operating expenses, partially offset by lower royalties and transportation expenses. Corporate operating netbacks after realized commodity risk management in the third quarter decreased 13% to $19.39/boe compared with $22.26/boe in the second quarter of 2019 for the same reasons described above, partially offset by a 40% decrease in realized commodity risk management loss on a per boe basis.

Corporate operating netbacks before realized commodity risk management decreased 28% year-over-year from $29.85/boe primarily due to a 19.0% decrease in produced petroleum revenue. However, corporate operating netbacks after realized commodity risk management increased 5% year-over-year to $19.39/boe compared with $18.44/boe during the same period of last year due to lower realized commodity risk management losses.

Three months ended
Corporate Operating Netbacks ($/boe) (1) Sept 30, 2019 June 30, 2019 % Change Sept 30, 2018 % Change
Produced petroleum revenue (1) 38.14 41.52 (8) 47.10 (19)
Royalties (3.04) (3.63) (16) (3.69) (18)
Adjusted operating expenses (1) (10.89) (9.24) 18 (10.72) 2
Transportation expenses (2.74) (2.95) (7) (2.84) (4)
Operating netbacks before realized commodity risk management (1) 21.47 25.70 (16) 29.85 (28)
Realized commodity risk management (2.08) (3.44) (40) (11.41) (82)
Operating netbacks ($/boe) 19.39 22.26 (13) 18.44 5

(1) See definition in our MD&A under section “Non-GAAP Financial Measures“.

Cash Flow from Operating Activities

Cash flow from operating activities in the third quarter of 2019 decreased $21.7 million to $9.2 million compared with $30.9 million in the prior quarter primarily due to a $26.2 million decrease in oil and gas sales resulting from decreased realized pricing and lower production, $8.9 million in restructuring and legal costs related to the strategic review, changes in working capital, and a $2.4 million increase in adjusted operating expenses. These were partially offset by lower realized losses on commodity risk management combined with lower royalty expenses.

Third quarter of 2019 cash flow from operating activities decreased $12.6 million compared to the same period last year primarily due to lower realized bitumen pricing primarily as a result of the unfavourable impact of WCS physical delivery fixed price differential contracts entered into in 2018, lower benchmark prices for oil, $8.9 million in restructuring and legal costs related to the strategic review, changes in working capital and higher spending on remediation. These were partially offset by lower realized losses on commodity risk management, increased bitumen production and the recording of a royalty credit carry-back related to the abandonment and decommissioning expenditures at SOEP.

Adjusted Funds Flow

The following table provides a reconciliation of cash flow from operating activities to adjusted funds flow:

Three months ended
($ millions) Sept 30, 2019 June 30, 2019 % Change Sept 30, 2018 % Change
Cash flow from operating activities $9.2 $30.9 (70) $21.8 (58)
Add (deduct):
Interest and financing charges $(14.2) $(14.9) (5) $(12.3) 16
Expenditures on remediation $7.7 $7.5 2 $3.8 102
Change in non-cash operating working capital $8.0 $5.6 43 $2.3 248
Total $1.5 $(1.8) (183) $(6.2) (124)
Adjusted funds flow $10.7 $29.1 (63) $15.6 (31)

Adjusted Funds Flow decreased 63% to $10.7 million in the third quarter compared with $29.1 million in the prior quarter due to lower realized bitumen prices and bitumen production, $8.9 million in restructuring costs and higher adjusted operating expenses partially offset by lower realized losses on commodity risk management.

Adjusted Funds Flow decreased 31% or $4.9 million year-over-year to $10.7 million compared with $15.6 million in the same period of last year primarily due to lower realized bitumen prices and restructuring costs partially offset by the impact of lower realized losses on commodity risk management and higher bitumen production.

Net Loss
Pengrowth reported a net loss of $119.9 million in the third quarter of 2019 compared to a net loss of $1.6 million in the same period last year. The net loss increased primarily due to a $100.0 impairment charge in the current quarter, lower realized bitumen prices and change in fair value of commodity risk management. These were partially offset by the impact of lower realized losses on commodity risk management, lower depletion and recording of a royalty credit carry-back for SOEP.

Market Access and Commodity Risk Management
As the Company pursues greater cash flow certainty for the fourth quarter of 2019 Pengrowth entered into WTI swaps as follows:

WTI Swaps
Reference point Remaining term Volume (bbl/d) Price per bbl (U.S.$)
WTI Oct. 1, 2019 – Dec. 31, 2019 3,000 $59.92

Subsequent to September 30, 2019, Pengrowth has entered into the following financial contracts:

WTI Swaps
Reference point Remaining term Volume (bbl/d) Price per bbl (U.S.$)
WTI Nov. 1, 2019 – Dec. 31, 2019 6,000 $56.05

Pengrowth uses physical delivery contracts to ensure access to markets, protect against pipeline apportionment, and limit credit risk and exposure to widening benchmark differentials between Western Canadian Select (“WCS“) and West Texas Intermediate (“WTI“) crude oil prices. As at September 30, 2019, Pengrowth had apportionment protected physical contracts in place that ensure market access for 17,500 bbl/d of diluted bitumen for 2019. Using a combination of physical and financial contracts, the average realized price on these volumes was WTI minus US$19.86/bbl including the apportionment protection fee for the third quarter of 2019.

Balance Sheet and Liquidity
Pengrowth’s total debt before working capital (excluding letters of credit) at September 30, 2019 increased to $705.2 million compared with $702.2 million as at June 30, 2019 due to the impact of a weaker Canadian dollar at the end of the period which increased the Canadian dollar equivalent value of foreign denominated debt, partially offset by lower Credit Facility drawings.

FREQUENTLY RECURRING TERMS
Pengrowth uses the following frequently recurring industry terms and abbreviations in this press release:

Units of Measurement
bbl barrel
“bbl/d” barrels per day
boe barrel of oil equivalent
boe/d barrels of oil equivalent per day
Mcf/d thousand cubic feet per day
MMboe million boe
MMcf/d million cubic feet per day
SOR steam oil ratio
CSOR cumulative steam oil ratio
Commodities and Currencies
AECO Alberta natural gas price point
WTI West Texas Intermediate crude oil price
WCS Western Canadian Select crude oil price
“US$” United States Currency
“CA$” Canadian Currency
Other Terms
“1P” Proved reserves
“2P” Proved and probable reserves
“dilbit” or “diluted bitumen bitumen blended with diluent
G&A general and administrative expenses
IFRS International Financial Reporting Standards
“NPV” Net present value
“RLI” Reserve Life Index
“SOEP” Sable Offshore Energy Project


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