Lindbergh Proved Reserves Increased 34% While Proved and Probable Reserves Increased 25%
CALGARY, Alberta, Aug. 08, 2019 (GLOBE NEWSWIRE) — Pengrowth Energy Corporation (“Pengrowth” or the “Company“) (TSX:PGF, OTCQX:PGHEF), today reported its results for the three and six months ended June 30, 2019. The Company also announced that GLJ Petroleum Consultants Ltd. (“GLJ“) has provided an updated report (Dated: August 7, 2019) of Pengrowth’s bitumen reserves estimate based on the performance of the Lindbergh thermal oil project effective June 30, 2019. Unless otherwise indicated, financial figures are expressed in Canadian Dollars.
“I want to thank our teams who continued to demonstrate operational excellence and discipline by delivering an exceptional second quarter,” said Pete Sametz, President and Chief Executive Officer of Pengrowth. “As of mid-year 2019, Pengrowth has reduced operating costs, reduced general and administrative costs, and paid down debt with adjusted funds flow generated in excess of capital requirements. The overhaul of the corporate and cultural model that started last year has yielded results and we are performing well on the things we can control. What we cannot control is the deterioration in forecast commodity pricing for natural gas which has led to a non-cash impairment of $95 million on our Groundbirch asset. Without this non-cash accounting impairment, we would have reported positive net income this quarter.”
“The strong performance of the Lindbergh thermal oil project has led to a 34% increase in Lindbergh’s proved reserves, and a 25% increase in proved and probable reserves which extends Lindbergh’s reserve life index to 30 years and 54 years from 24 years and 48 years respectively. The independent report further increases the size and value of our core asset to the benefit of all of our stakeholders. As we continue to generate positive adjusted funds flow, pay off debt and grow our reserve base, Pengrowth’s capacity to generate value from our long-life low-decline Lindbergh project at current prices should become increasingly clear to our banks, note holders, and equity investors alike.”
Second Quarter 2019 Summary:
- Delivered strongest quarterly adjusted funds flow in two years with a 188% year-over-year increase to $29.1 million through:
• Pengrowth’s leaner cost structure which resulted in a 42% decrease in Cash G&A expenses per boe and a 9% decrease in adjusted operating expenses per boe year-over-year;
• A $13 million decrease in realized losses on commodity risk management;
• A 14% year-over-year increase in Lindbergh SAGD bitumen production to 18,036 barrels per day (“bbl/d“) at a steam-oil ratio (“SOR“) of 2.80 in the second quarter compared with 15,876 bbl/d at an SOR of 3.12 for the same period in the prior year;
- Increased Lindbergh’s proved reserves by 34% and proved and probable reserves by 25% at June 30, 2019 compared with January 1, 2019.
- Debt decreased $19.3 million to $702.2 million at June 30, 2019 compared with $721.5 million at March 31, 2019 partly due to repayment of $9.0 million with cash flow from operations and a $10.3 million advantageous swing in foreign exchange rates.
- The decrease in forecast gas prices led to a $95.0 million non-cash impairment of Groundbirch.
- For every US$1.00/bbl change in the price of West Texas Intermediate crude oil, the estimated impact on 12-month Adjusted Funds Flow is CA$7.9 million (Please refer to this quarter’s MD&A for more information).
- The Company continues to advance the Strategic Review process announced March 6, 2019 with a view to strengthening the Company’s balance sheet, addressing upcoming debt maturities, and maximizing overall value for the benefit of its stakeholders.
Summary of Financial & Operating Results
|Three months ended|
|(monetary amounts in millions except per boe and per share amounts)||Jun 30, 2019||Mar 31, 2019||% Change||Jun 30, 2018||% Change|
|Average daily production (boe/d)||22,707||22,764||—||22,600||—|
|Oil and gas sales||$144.4||$128.3||13||$147.4||(2)|
|Cash proceeds from dispositions||$(0.1)||$5.4||(102)||$3.5||(103)|
|Interest and financing charges||$14.9||$14.6||2||$12.6||18|
|Cash flow from operating activities||$30.9||$(7.8)||(496)||$12.8||141|
|Adjusted funds flow (1)||$29.1||$16.0||82||$10.1||188|
|Weighted average number of shares outstanding (000’s)||560,022||556,594||1||556,117||1|
|Adjusted funds flow per share (1)||$0.05||$0.03||67||$0.02||150|
|Produced petroleum revenue per boe (1)||$41.52||$36.27||14||$42.59||(3)|
|Operating expenses per boe||$8.32||$8.93||(7)||$9.34||(11)|
|Adjusted operating expenses per boe (1)||$9.24||$10.54||(12)||$10.11||(9)|
|Royalty expenses per boe||$3.63||$2.73||33||$3.99||(9)|
|Operating netback before realized commodity risk management per boe (1)||$25.70||$19.97||29||$25.82||—|
|Cash G&A expenses per boe (1)||$2.47||$3.22||(23)||$4.28||(42)|
|STATEMENT OF INCOME (LOSS)|
|Net income (loss)||$(76.5)||$(31.6)||142||$(27.5)||178|
|Net income (loss) per share||$(0.14)||$(0.06)||133||$(0.05)||180|
|Total debt before working capital (2)||$702.2||$721.5||(3)||$701.5||—|
(1) See definition in our MD&A under section “Non-GAAP Financial Measures“.
(2) Includes Credit Facility, current and long term portions of term notes, as applicable, and bank indebtedness. Excludes letters of credit and finance leases.
Alberta Production Curtailment Program
As one of the top 20 oil producers in Alberta, Pengrowth is subject to the Government of Alberta’s production curtailment program which took effect on January 1, 2019. Even though Lindbergh is subject to mandatory curtailments, the asset produced 18,036 bbl/d in the second quarter of 2019 and 18,193 in the first quarter of 2019 while remaining in compliance.
Year-to-Date 2019 Actual Results vs. 2019 Guidance
The following table provides a summary of Pengrowth’s actual results for the six months ended June 30, 2019 compared with full year guidance:
|Actual YTD June 30, 2019||2019 Guidance (1)|
|Average oil equivalent production (boe/d)||22,736||22,500 – 23,500|
|Lindbergh average bitumen production (bbl/d)||18,114||17,750 – 18,250|
|Capital expenditures ($ millions)||13.3||45|
|Royalty expenses (% of produced petroleum revenue) (2) (3)||8.2||7.0 – 8.0|
|Adjusted operating expenses ($/boe) (2)||9.89||9.25 – 10.00|
|Cash G&A expenses ($/boe) (2)||2.84||2.50 – 2.75|
(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 22,736 boe/d was within 2019 Guidance despite low capital spending and the Alberta Government’s mandatory production curtailment program. Total corporate oil-equivalent volumes are expected to be between 22,500 boe/d to 23,500 boe/d.
Year to date 2019 actual royalty expenses as a percent of produced petroleum revenue were slightly above full year Guidance; however Pengrowth anticipates royalty expense as a percent of produced petroleum revenue to fall within 2019 Guidance by the end of the year.
Year to date 2019 Cash G&A expenses per boe were above full year 2019 Guidance due to compensation related expenses. Cash G&A expenses per boe decreased from $3.22/boe in the first quarter of 2019 to $2.47/boe in the second quarter of 2019. Pengrowth anticipates full year 2019 cash G&A expenses to reach 2019 Guidance as expenses in the second quarter of 2019 are more representative of future cost expectations.
As previously disclosed, Pengrowth is working with a third party Co-Generation provider to build a cogeneration facility at Lindbergh. The addition of this cogeneration facility is expected to provide the steam required to incrementally grow production at Lindbergh to 35,000 bbl/d by the end of 2023. Subsequent to the end of the quarter, working alongside our partner, Pengrowth has submitted an application to amend Lindbergh’s current approvals in support of the new co-generation facility (D78 and EPEA). In addition, we are continuing to progress the Alberta Electric System Operator (AESO) interconnection process and accompanying Alberta Utilities Commission applications.
Second Quarter Operational Review
Average daily production for the second quarter decreased 0.3% to 22,707 boe/d compared with 22,764 boe/d in the first quarter of 2019 primarily as a result of Alberta’s production curtailment program, the disposition of Fenn Big Valley, offset by a 5% increase in production at Groundbirch compared to the prior quarter. Production increased 0.5% in the second quarter compared with the same period in the prior year due to a 14% increase in production from Lindbergh offset by the absence of natural gas production from the Sable Offshore Energy Project (“SOEP“), decreased natural gas production from Groundbirch, and the disposition of Fenn Big Valley.
|Three months ended|
|PRODUCTION||Jun 30, 2019||Mar 31, 2019||% Change||Jun 30, 2018||% Change|
|Natural gas (Mcf/d)||25,294||23,988||5||34,064||(26)|
|Light oil (bbl/d)||336||514||(35)||769||(56)|
|Natural gas liquids (NGL) (bbl/d)||120||59||103||278||(57)|
Despite lower year-over-year capital spending, Lindbergh average daily bitumen production only decreased 1% to 18,036 bbl/d in the second quarter compared with 18,193 bbl/d in the prior quarter. Lindbergh contributed 79% of Pengrowth’s total production in the second quarter. The SOR for the second quarter decreased nominally to 2.80 compared with 2.83 in the prior quarter, partly due to the relaxing of production curtailments. We expect the SOR to drop further if production curtailments ease further. The cumulative SOR as at June 30, 2019 was 2.69.
Lindbergh’s second quarter operating netbacks increased 30% to $32.57/bbl compared with $25.00/bbl in the prior quarter due to a 16% increase in realized diluted bitumen prices, an 18% decrease in energy related operating expenses, a 6% decrease in non-energy operating expenses partially offset by a 38% increase in royalties due to higher commodity prices and a 4% increase in diluent costs.
|Three months ended|
|Lindbergh Operating Netbacks ($/bbl) (1)||Jun 30, 2019||Mar 31, 2019||% Change||Jun 30, 2018||% Change|
|Diluted Bitumen Revenue (2)||58.87||50.65||16||63.94||(8)|
|Diluent Costs (Inc. transportation)||(9.88)||(9.46)||4||(11.47)||(14)|
|Bitumen revenue (2)||48.99||41.19||19||52.47||(7)|
|Adjusted Operating expenses – Non-energy(1)||(5.54)||(5.92)||(6)||(7.54)||(27)|
|Adjusted Operating expenses – Energy(1)||(3.26)||(3.97)||(18)||(3.25)||—|
|Operating netbacks before realized commodity risk management||32.57||25.00||30||34.20||(5)|
(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 before realized commodity risk management in the second quarter increased 29% to $25.70/boe compared with $19.97/boe in the first quarter of 2019 due to increased realized commodity prices, lower operating expenses, lower transportation expenses, partially offset by a 33% increase in royalties. Corporate operating netbacks after realized commodity risk management in the second quarter increased 27% to $22.26/boe compared with $17.48/boe in the first quarter of 2019 despite a 38% increase in realized commodity risk management losses.
Corporate operating netbacks before realized commodity risk management were relatively flat year-over-year. However, corporate operating netbacks after realized commodity risk management increased 39% year-over-year to $22.26/boe compared with $16.00/boe during the same period of last year due to lower realized commodity risk management losses.
|Three months ended|
|Corporate Operating Netbacks ($/boe) (1)||Jun 30, 2019||Mar 31, 2019||% Change||Jun 30, 2018||% Change|
|Produced petroleum revenue (1)||41.52||36.27||14||42.59||(3)|
|Adjusted operating expenses (1)||(9.24)||(10.54)||(12)||(10.11)||(9)|
|Operating netbacks before realized commodity risk management (1)||25.70||19.97||29||25.82||—|
|Realized commodity risk management||(3.44)||(2.49)||38||(9.82)||(65)|
|Operating netbacks ($/boe)||22.26||17.48||27||16.00||39|
(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 second quarter of 2019 was $30.9 million compared with $7.8 million of cash used in operating activities in the prior quarter due to a $11.5 million increase in oil and gas sales, a $4.0 million decrease in operating and cash G&A expenses, a $6.4 million decrease in remediation expenditures, partially offset by a $2.0 million increase in realized losses on commodity risk management and $1.9 million increase in royalties.
Year-over-year, cash flow from operating activities in the second quarter increased 141% to $30.9 million compared with $12.8 million in the same period last year primarily due to lower realized losses on commodity risk management, increased bitumen production and lower cash G&A expenses partially offset by lower realized bitumen prices and higher spending on remediation.
Adjusted Funds Flow
The following table provides a reconciliation of cash flow from operating activities to adjusted funds flow:
|Three months ended|
|($ millions)||Jun 30, 2019||Mar 31, 2019||% Change||Jun 30, 2018||% Change|
|Cash flow from operating activities||$30.9||$(7.8)||(496)||$12.8||141|
|Interest and financing charges||$(14.9)||$(14.6)||2||$(12.6)||18|
|Expenditures on remediation||$7.5||$13.9||(46)||$6.3||19|
|Change in non-cash operating working capital||$5.6||$24.5||(77)||$3.6||56|
|Adjusted funds flow||$29.1||$16.0||82||$10.1||188|
Adjusted Funds Flow increased 82% to $29.1 million in the second quarter compared with $16.0 million in the prior quarter due to a $38.7 million increase in cash flow from operating activities partially offset by a $0.3 million increase in interest and financing charges.
Adjusted Funds Flow increased 188% or $19.0 million year-over-year to $29.1 million compared with $10.1 million in the same period of last year primarily due to the impact of lower realized losses on commodity risk management, higher bitumen production and lower cash G&A expenses.
These favorable contributions to adjusted funds flow in the second quarter of 2019 were partially offset by lower realized bitumen prices due to the unfavourable impact of the WCS physical delivery fixed price differential contracts entered into in 2018, lower natural gas sales due to the absence of natural gas production from the Sable Offshore Energy Project and higher interest and financing charges.
Pengrowth reported a net loss of $76.5 million in the second quarter of 2019 compared to a net loss of $27.5 million in the same period last year. The net loss increased primarily due to a $95.0 million impairment charge in the current quarter as a result of a significant decline in the forward natural gas benchmark prices. This was partially offset by the impact of lower realized losses on commodity risk management, higher bitumen production, lower cash G&A expenses and change in fair value of commodity risk management.
Increased Proved and Probable Bitumen Reserves by 25%
Based on continued strong operational performance at Lindbergh, including the new infill wells, and to support the advancement of the Co-Generation project and Strategic Review process, GLJ was asked to provide a June 30, 2019 update of estimated Lindbergh reserves and reserves values. Pengrowth’s bitumen (Lindbergh) reserve values effective June 30, 2019 are based on an independent engineering evaluation conducted by GLJ using the GLJ Petroleum Consultants Crude Oil Commodity Price Forecast at July 1, 2019 and prepared in accordance with National Instrument 51-101 (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGEH”).
All evaluations and summaries of future net revenue are stated prior to provision for interest, debt service charges or general and administrative expenses and after deduction of royalties, operating costs, estimated abandonment and reclamation costs and estimated future capital expenditures.
Bitumen Reserves Key Highlights
- Long-term well performance and the performance of our infill wells at Lindbergh has led to a:
• 14% increase in proved developed producing reserves net of 3.3 million bbls produced in the first half of the year;
• 34% increase in proved reserves (“1P“); and
• 25% increase in proved and probable reserves (“2P“).
- Net present value (“NPV“) before income taxes discounted at 10% of 1P and 2P reserves was $1.7 billion and $2.6 billion, respectively.
- Lindbergh reserve life index (“RLI“) increased as follows:
• 1P RLI increased 25% to 30 years at June 30, 2019 from 24 years at December 31, 2018;
• 2P RLI increased 12% to 54 years at June 30, 2019 from 48 years at December 31, 2018.
Pengrowth Mid-Year 2019 Bitumen Reserve Additions (Company Interest)
|Proved Developed Producing||Proved||Proved and Probable|
|Opening Balance (January 1, 2019)||19,609||159,153||311,395|
|Closing Balance (July 1, 2019)||22,441||213,118||390,291|
|% Reserve Additions||14%||34%||25%|
Pengrowth Bitumen: Net Present Value of Future Net Revenue as at June 30, 2019 Before Income Taxes(1)
(Forecast Prices and Costs)
|Before Income Taxes Discounted at (%/year) – $MM|
|Proved Developed Producing||549||521||490||461||434|
|Proved Developed Non-Producing||1||0||0||0||0|
|Total Proved Reserves||5,885||2,796||1,666||1,160||890|
|Change from Jan 1, 2019||46%||24%||16%||14%||14%|
|Total Proved Plus Probable Reserves||10,684||4,661||2,565||1,652||1,177|
|Change from Jan 1, 2019||31%||12%||6%||5%||5%|
(1) The information included in this table represents the net present values of future net revenue before Income Taxes at the discount rates noted in this table, and based on the commodity pricing set forth below under the heading “GLJ Petroleum Consultants Crude Oil Commodity Price Forecast at July 1, 2019. It should not be assumed that the estimates of future net revenues presented in this table represent the fair market value of the reserves.
GLJ Petroleum Consultants Crude Oil Commodity Price Forecast at July 1, 2019
|NYMEX WTI||WCS Oil|
|Year||(USD/bbl)||% Change to Jan 1, 2019||(CAD/bbl)||% Change to Jan 1, 2019|
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates and may be subclassified based on development and production status.
Market Access and Commodity Risk Management
As the Company pursues greater cash flow certainty, for the third quarter of 2019 Pengrowth entered into WTI swaps and costless collars totaling 5,000 bbl/d for an average realized price of US$57.77/bbl using the following instruments:
|Reference point||Remaining term||Volume (bbl/d)||Price per bbl (U.S.$)|
|WTI||Jul. 1, 2019 – Sep. 30, 2019||3,000||$59.62|
|Reference point||Remaining term||Volume (bbl/d)||Price per bbl (U.S.$)||Price per bbl (U.S.$)|
|WTI||Jul. 1, 2019 – Sep. 30, 2019||2,000||$55.00||$61.05|
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 June 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$20.68/bbl including the apportionment protection fee for the second quarter of 2019.
Balance Sheet and Liquidity
Pengrowth’s total debt before working capital (excluding letters of credit) at June 30, 2019 decreased 3% to $702.2 million compared with $721.5 million as at March 31, 2019 partly due to $9.0 million in repayments and a $10.3 million advantageous swing in foreign exchange rates.
Upcoming Debt Maturities
On March 25, 2019 Pengrowth announced that it had reached arrangements for the extension of the March 31, 2019 maturity date under its $330 million secured revolving credit facility (the “Credit Facility”) through September 30, 2019, subject to certain terms. The Credit Facility is provided by a broad syndicate of domestic and international banks. The Company executed an extension agreement to the Credit Facility, supported by 100% of the lenders in the syndicate, providing for the extension of the maturity date under the Credit Facility to September 30, 2019, by way of an initial extension to July 29, 2019 and two subsequent extensions to August 29, 2019 and to September 30, 2019, respectively, each of which will automatically become effective unless lenders with at least two thirds of the total commitments under the Credit Facility provide notice to the Company that such automatic extension will not apply in advance of the automatic extension dates.
The extension of the Credit Facility provides support to Pengrowth while it undertakes the previously-announced Strategic Review to explore and develop strategic alternatives with a view to strengthening the Company’s balance sheet, addressing upcoming debt maturities, and maximizing enterprise value.
As at June 30, 2019, Pengrowth had drawings of $182.0 million on its Credit Facility (December 31, 2018 – $173.5 million), and $63.3 million of outstanding letters of credit (December 31, 2018 – $75.6 million).
In addition to the maturity of the Credit Facility in 2019, certain of the Company’s term notes in the aggregate principal amount of $56.9 million mature on October 18, 2019 and $123 million mature on May 11, 2020. As part of the Strategic Review, Pengrowth is exploring and advancing strategic alternatives to address the upcoming maturities of the October 2019 term notes.
Pengrowth’s total debt before working capital was 71% denominated in foreign currencies at June 30, 2019. To manage foreign exchange risk, Pengrowth holds a series of swap contracts that fix the foreign exchange rate on 66% of the principal for Pengrowth’s U.S. dollar denominated term debt. At June 30, 2019, Pengrowth held a total of US$240 million in foreign exchange swap contracts at a weighted average rate of US$0.75 per CA$1.00 as follows:
|% of principal swapped||Average fixed rate
(US$ per CA$)
Multi-year Development Plan
In June 2018, Pengrowth released its multi-year development plan to incrementally increase bitumen production at Lindbergh in bite sized steps rather than in one large phase.
Expansion at Lindbergh is expected to be achieved in incremental steps aligning capital spending with Pengrowth’s expected cash flow, shifting the development methodology away from the previously contemplated large single phase approach. Development capital is expected to be focused on drilling new well pairs, additional infill wells, as well as, adding incremental facilities to debottleneck fluid handling capacity. The Company expects to implement co-injection of steam and Non-Condensible Gas (“NCG“) to further enhance production by freeing-up steam for new wells while maintaining reservoir pressure which is expected to lower SORs. Regulatory approval for the application of NCG injection at Lindbergh was received in June of 2018. As previously announced, Pengrowth has signed a non-binding letter of intent with a third party to fund the development of additional co-generation capacity options at Lindbergh to provide Pengrowth with steam and power (under a fee structure) sufficient enough to support further efficient production expansions to reach approximately 35,000 bbl/d of bitumen. Capital to be committed to Lindbergh in 2020 and onwards will be dependent on the outcome of the current Strategic Review process and the prevailing commodity prices.
Groundbirch has a low cost structure which supports growth in production and cash flow under a stronger natural gas pricing environment.
2019 Capital Plan
Pending the completion of the Strategic Review, 2019 capital spending is not expected to exceed $21 million. Pengrowth’s 2019 Budget called for a capital spending plan of $45 million, with 76 percent or $34 million of this capital allocated to Lindbergh for continued production sustaining and maintenance activities, including drilling of three well pairs to utilize existing steam capacity. Pengrowth will continue to assess timing for commencement of the development program. The remaining $11 million of capital is related to maintenance and integrity activities to support the existing operations and for general corporate purposes.
Quarterly Presentation :
Pengrowth has posted a listen-only audio webcast presentation reviewing the second quarter 2019 results to the link below:
Please reach out to our investor relations department through the contact information below should you have any questions regarding the quarter.
FREQUENTLY RECURRING TERMS
Pengrowth uses the following frequently recurring industry terms and abbreviations in this press release:
|Units of Measurement|
|“bbl/d”||barrels per day|
|“boe“||barrel of oil equivalent|
|“boe/d“||barrels of oil equivalent per day|
|“Mcf/d“||thousand cubic feet per day|
|“MMcf/d“||million cubic feet per day|
|“SOR“||steam oil ratio|
|“CSOR“||cumulative steam oil ratio|
|Commodities and Currencies|
|“AECO“||Alberta natural gas price point|
|“WTI“||West Texas Intermediate crude oil price|
|“WCS“||Western Canadian Select crude oil price|
|“US$”||United States Currency|
|“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|
Disclosure of Oil and Gas Information:
When used herein, the term “boe” means barrels of oil equivalent on the basis of one boe being equal to one barrel of oil or NGLs or 6,000 cubic feet of natural gas (6 mcf: 1 bbl). Barrels of oil equivalent may be misleading, particularly if used in isolation. A conversion ratio of six mcf of natural gas to one boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All production figures stated are based on Company Interest before the deduction of royalties.
The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
Caution Regarding Forward Looking Information:
This press release contains forward-looking statements within the meaning of securities laws, including the “safe harbour” provisions of the Canadian securities legislation and applicable U.S. securities legislation including the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project”, “guidance”, “may”, “will”, “should”, “could”, “estimate”, “predict” or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this press release include, but are not limited to, statements with respect to the Company’s Strategic Review, including the potential for the Company to complete any financing arrangements, corporate merger, sale, recapitalization or other transaction or strategic alternative; the anticipated arrangements for the extension of the Company’s Credit Facility through September 2019 and the terms of any such extension; the ability of the Company to refinance or repay its existing indebtedness, including the term notes maturing in October 2019 and May 2020; the Company’s expectations that it will conclude definitive agreements for third party development of a co-generation facility at Lindbergh; expected production in 2019; the anticipated impact on adjusted funds flow of changes in the price of WTI crude; anticipated $45 million of capital expenditures in 2019; expected production at Lindbergh to the end of the year and up to 2023; the Company’s anticipated reserves life; anticipated royalty expenses, adjusted operating expenses; cash G&A expenses, production volumes, royalty expenses, cash G&A expenses, and the ability of Pengrowth to remain a going concern. Forward-looking statements and information are based on current beliefs as well as assumptions made by and information currently available to Pengrowth concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.
Forward-looking statements and information are based on Pengrowth’s current beliefs as well as assumptions made by, and information currently available to, Pengrowth concerning the Company’s ability to remain a going concern, general economic and financial market conditions, anticipated financial performance, business prospects, strategies, regulatory developments, including in respect of taxation, royalty rates and environmental protection, future capital expenditures and the timing thereof, future oil and natural gas commodity prices and differentials between light oil and bitumen prices, future oil and natural gas production levels, future exchange rates and interest rates, the amount of future cash dividends paid by Pengrowth or the lack thereof, the cost of expanding our property holdings, our ability to obtain labour and equipment in a timely manner to carry out development activities, our ability to market our oil and natural gas successfully to current and new customers including transportation availability, the impact of increasing competition, our ability to obtain financing on acceptable terms and meet financial covenants, our ability to add production and reserves through our development, exploitation and exploration activities, our ability to pay our current and future debt obligations and stay in compliance with our current and future debt covenants, our ability to obtain alternative debt financing and amend our financial covenants, and our ability to remain a going concern. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.
By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the risks associated with the oil and gas industry in general; volatility of oil and gas prices; Canadian light oil and bitumen differentials; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth’s ability to replace and expand oil and gas reserves, ability to produce those reserves; production may be impacted by unforeseen events such as equipment and transportation failures and weather related issues; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; counterparty risk; compliance with environmental laws and regulations; actions by government authorities, including the imposition or reassessment of taxes including changes in income taxes and royalty laws; Pengrowth’s ability to access external sources of debt and equity capital; Pengrowth’s inability to refinance secured term notes and /or existing Credit Facility; Pengrowth’s inability to successfully complete a transaction or recapitalization under the Strategic Review process; new IFRS and the impact on Pengrowth’s financial statements; the implementation of greenhouse gas emissions legislation and the impact of carbon taxes; and Pengrowth’s ability to remain a going concern. Further information regarding these factors may be found under the heading “Business Risks” herein and under “Risk Factors” in Pengrowth’s most recent AIF, and in Pengrowth’s most recent audited annual Consolidated Financial Statements, management information circular, quarterly reports, material change reports and news releases. Copies of Pengrowth’s public filings are available on SEDAR at www.sedar.com and EDGAR at www.sec.gov.
The foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this press release are made as of the date of this press release, and Pengrowth does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable laws. The forward-looking statements contained in this press release are expressly qualified by this cautionary statement.
The forward-looking statements contained in this news release are expressly qualified by this cautionary statement.
In addition to providing measures prepared in accordance with International Financial Reporting Standards (IFRS), Pengrowth presents non-GAAP measures including total debt before working capital, total debt including working capital, adjusted funds flow, adjusted funds flow per share, free funds flow, produced petroleum revenue per boe, adjusted operating expenses per boe, royalty expenses (% of produced petroleum revenue), Lindbergh operating netbacks, corporate operating netbacks, adjusted operating expenses, cash G&A expenses and cash G&A expenses per boe. These measures do not have any standardized meaning prescribed by GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. These measures are provided, in part, to assist readers in determining Pengrowth’s ability to generate cash from operations. Pengrowth believes these measures are useful in assessing operating performance and liquidity of Pengrowth’s ongoing business on an overall basis. These measures should be considered in addition to, and not as a substitute for, net income (loss), cash provided by operations and other measures of financial performance and liquidity reported in accordance with IFRS. Further information including reconciliation to the applicable GAAP measure with respect to these non-GAAP measures can be found in the MD&A.
Note to US Readers
We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51- 101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.
Current SEC reporting requirements permit, but do not require United States oil and gas companies, in their filings with the SEC, to disclose probable and possible reserves, in addition to the required disclosure of proved reserves. The SEC does not permit the inclusion of estimates of contingent resources in reports filed with it by United States companies. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. Because we are permitted to prepare our reserves information in accordance with Canadian disclosure requirements, we have included contingent resources, disclosed reserves before the deduction of royalties and interests of others and determined and disclosed our reserves and the estimated future net cash therefrom using forecast prices and costs. See “Presentation of our Reserve Information” in our most recent Annual Information Form or Form 40-F for more information.
We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves. The SEC permits, but does not require, the disclosure of reserves based on forecast prices and costs.
About Pengrowth Energy Corporation (TSX:PGF):
Pengrowth Energy Corporation is a Canadian energy company focused on the sustainable development and production of oil and natural gas in Western Canada from its Lindbergh thermal oil property and its Groundbirch Montney gas property. The Company is headquartered in Calgary, Alberta, Canada and has been operating in the Western Canadian basin for more than 30 years. The Company’s shares trade on both the Toronto Stock Exchange under the symbol “PGF” and on the OTCQX under the symbol “PGHEF”.
Additional information about Pengrowth is available at www.pengrowth.com and on SEDAR at www.sedar.com.
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