Pengrowth Second Quarter 2019 Adjusted Funds Flow Increased 188% Year-over-year to $29 Million

Source Press Release
Company Pengrowth Energy Corporation 
Tags Capital Spending, Strategy - Corporate, Financial & Operating Data
Date August 08, 2019

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 
           
PRODUCTION           
Average daily production (boe/d)  22,707  22,764  —   22,600  — 
FINANCIAL           
Oil and gas sales  $144.4  $128.3  13  $147.4  (2) 
Capital expenditures  $1.9  $11.4  (83)  $23.1  (92) 
Cash proceeds from dispositions  $(0.1)  $5.4  (102)  $3.5  (103) 
Interest and financing charges  $14.9  $14.6  $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  556,117 
Adjusted funds flow per share (1)  $0.05  $0.03  67  $0.02  150 
OPERATIONAL           
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 
DEBT           
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.

Co-Generation Project:
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 
Bitumen (bbl/d)  18,036  18,193  (1)  15,876  14 
Natural gas (Mcf/d)  25,294  23,988  34,064  (26) 
Light oil (bbl/d)  336  514  (35)  769  (56) 
Natural gas liquids (NGL) (bbl/d)  120  59  103  278  (57) 
Total boe/d  22,707  22,764  (0.3)  22,600  0.5 

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.

Financial Results
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)  (11.47)  (14) 
Bitumen revenue (2)  48.99  41.19  19  52.47  (7) 
Royalties  (4.39)  (3.19)  38  (4.57)  (4) 
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)  — 
Transportation expenses  (3.23)  (3.11)  (2.91)  11 
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 ($/boe) (1)  Jun 30, 2019  Mar 31, 2019  % Change  Jun 30, 2018  % Change 
Produced petroleum revenue (1)  41.52  36.27  14  42.59  (3) 
Royalties  (3.63)  (2.73)  33  (3.99)  (9) 
Adjusted operating expenses (1)  (9.24)  (10.54)  (12)  (10.11)  (9) 
Transportation expenses  (2.95)  (3.03)  (3)  (2.67)  10 
Operating netbacks before realized commodity risk management  (1)  25.70  19.97  29  25.82  — 
Realized commodity risk management  (3.44)  (2.49)  38  (9.82)  (65) 
Operating netbacks ($/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 
Add (deduct):           
Interest and financing charges  $(14.9)  $(14.6)  $(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 
Total  $(1.8)  $23.8  (108)  $(2.7)  (33) 
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.

Net Loss
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)

(000’s BBLs)
Reserves Category 
Proved Developed Producing  Proved  Proved and Probable 
Opening Balance (January 1, 2019)  19,609  159,153  311,395 
Technical additions  6,112  40,860  82,175 
Infill Drilling  16,384   
Production  3,279  3,279  3,279 
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 
Reserves Category  0%  5%  10%  15%  20% 
Proved Reserves           
Proved Developed Producing  549  521  490  461  434 
Proved Developed Non-Producing 
Proved Undeveloped  5,335  2,275  1,176  699  456 
Total Proved Reserves  5,885  2,796  1,666  1,160  890 
Change from Jan 1, 2019  46%  24%  16%  14%  14% 
Probable Reserves  4,799  1,865  899  492  287 
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 
2019    57.94  3%    59.05  24% 
2020    62.50  (1)%    57.79  (1)% 
2021    65.00  (3)%    60.76  (8)% 
2022    67.50  (4)%    64.38  (5)% 
2023    70.00  (3)%    67.50  (4)% 
2024    72.50  (3)%    70.63  (3)% 
2025    75.00  (3)%    73.75  (3)% 
2026    77.50  (4)%    76.88  (3)% 
2027    79.67  (3)%    79.59  (2)% 
2028    81.27  (3)%    81.59  (2)% 
2029+    +2.0%/yr      +2.0%/yr   

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:

WTI Swaps       
Reference point  Remaining term  Volume (bbl/d)  Price per bbl (U.S.$) 
WTI  Jul. 1, 2019 - Sep. 30, 2019  3,000  $59.62 
Costless Collars      Floor  Ceiling 
Reference point  Remaining term  Volume (bbl/d)  Price per bbl (U.S.$)  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:

Principal amount
(US$ millions) 
Swapped amount
(US$ millions) 
  % of principal swapped  Average fixed rate
(US$ per CA$) 
366.3  240.0  66%  0.75 

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.

Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd