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Prairie Provident Resources Announces Third Quarter 2019 Financial and Operating Results


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Source: Prairie Provident Resources Inc.

CALGARY, Alberta, Nov. 13, 2019 (GLOBE NEWSWIRE) — Prairie Provident Resources Inc. (“Prairie Provident”, “PPR” or the “Company”) is pleased to announce its operating and financial results for the three and nine months ended September 30, 2019. PPR’s consolidated financial statements (“Financial Statements”) and related Management’s Discussion and Analysis (“MD&A”) for the three and nine months ended September 30, 2019 are available on our website at www.ppr.ca and filed on SEDAR.

Prairie Provident continued to successfully execute its strategic plan during the third quarter of 2019, delivering strong operational performance and responsibly maintaining stable production volumes while generating positive adjusted funds flow1 and solid operating netbacksdespite continued uncertain market conditions. Subsequent to quarter end, the Company’s lenders confirmed continuation of the borrowing base under PPR’s senior secured revolving note facility (the “Revolving Facility”) at US$60 million and extended the maturity date to April 30, 2021, which preserve the Company’s financial flexibility. Financial covenants are unchanged.

HIGHLIGHTS

  • Production averaged 6,214 boe/d (68% liquids) in the third quarter and 6,188 boe/d (68% liquids) for the first nine months of 2019, an increase of 8% and 19%, respectively, compared to the corresponding periods in 2018 and in line with guidance. The production increase was driven by a successful development program which contributed 593 boe/d and 400 boe/d of production in the third quarter and the first nine months of 2019, respectively, and incremental production volumes from the Marquee Energy Ltd. acquisition completed in Q4 2018.
  • PPR generated $11.0 million ($19.24/boe) of operating netback1 before the impact of derivatives in the third quarter of 2019. After the realized loss on derivatives, PPR generated $10.8 million ($18.95/boe) of operating netback, representing a 15% total increase (7% on a per unit basis) from the third quarter of 2018, as higher production, lower royalties and lower realized derivative losses outweighed the impact from lower realized oil prices.
  • Operating expense was $18.92/boe for the third quarter, at the low end of our guidance.  Compared to the first and second quarters of 2019, operating expense improved by $4.55/boe and $1.44/boe, respectively. While the first quarter 2019 operating expense was negatively impacted by extreme weather, the third quarter operating expense level was more reflective of PPR’s expected run-rate.
  • Positive adjusted funds flow1, excluding $0.4 million of decommissioning settlements, totaled $6.6 million ($0.04 per basic share and diluted share) in the third quarter, an increase of 7% from the same period last year due to higher production and an improved operating netback. Strong adjusted funds flow realized during the third quarter contributed to a strengthened balance sheet, positioning PPR to internally fund our planned 2019 capital program.
  • Net loss totaled $2.3 million in the third quarter of 2019 compared to a net loss of $2.6 million in the same period last year, primarily driven by non-cash items.

1  Non-IFRS measure – see below under “Non-IFRS Measures”

  • Overall net debt1 was reduced during the third quarter primarily due to adjusted funds flow1 exceeding net capital expenditures1, partially offset by weakening of the Canadian dollar against the US dollar. As at September 30, 2019, net debt totaled $112.1 million, a decrease of $1.3 million and $5.2 million from June 30, 2019 and December 31, 2018, respectively, as PRR continues to prioritize debt reduction and strengthening its balance sheet. PPR’s 2019 budget forecast for capital expenditures is expected to under-spend projected adjusted funds flow at current strip pricing, preserving the Company’s financial flexibility to pursue future growth opportunities organically or through acquisition.
  • Net capital expenditures1 during the third quarter and first nine months of 2019 were in line with guidance and totaled $1.9 and $8.8 million, respectively. Third quarter 2019 expenditures were primarily directed to recompleting one well in the Provost area, facility work at Evi and a 3D seismic program in the Princess area. With the volatility in both West Texas Intermediate and Canadian oil price differentials late in 2018, PPR elected to take a conservative approach in the first nine months of 2019 by reducing capital spending relative to the prior year with a focus on strengthening the balance sheet.
  • At Evi, an independent reserves evaluation as of May 31, 2019 assigned an incremental 2.1 MMboe of proved plus probable (“P+P”) undeveloped reserves (97% oil and liquids) to future waterflood expansions, comprised of approximately 1.6 MMboe of proved undeveloped reserves and approximately 0.5 MMboe of probable undeveloped reserves, with a total estimated net present value of future net revenue (before tax and discounted at 10%) on a P+P basis of $30 million. 2 The incremental reserves assignments increased PPR’s total estimated corporate reserves volumes by 7.1% on a proved basis and by 6.1% on a P+P basis, relative to year-end estimates.
  • Subsequent to September 30, 2019, PPR’s lenders confirmed continuation of the borrowing base under the Revolving Facility at US$60 million, extended the maturity date of the Company’s senior secured revolving note facility (“Revolving Facility”) from October 31, 2020 to April 30, 2021, and removed the “term-out” feature so as to keep the facility as a revolving facility for the remainder of the term. Financial covenants are unchanged. The next borrowing base re-determination for the Revolving Facility will be on or about March 31, 2020.
  • As of September 30, 2019, PPR had US$58.0 million of borrowings drawn against the US$60.0 million Revolving Facility, comprised of US$30.0 (CAD$40.5 million equivalent using exchange rate at the time of borrowing) of CAD-denominated borrowing and US$28.0 million of USD-denominated borrowing (CAD$37.1 million equivalent using the September 30, 2019 exchange rate of $1.00 USD to $1.32 CAD). There were also US$30.6 million (CAD$40.6 million equivalent using the September 30, 2019 exchange rate) of senior subordinated notes due October 31, 2021 outstanding at the quarter-end, for total borrowings of US$88.6 million or CAD$117.4 million at September 30, 2019 exchange rate.
  • PPR satisfied its remaining $1.8 million of Canadian Exploration Expense expenditure commitment related to its October 2018 flow-through share financing.

1  Non-IFRS measure – see below under “Non-IFRS Measures”
2  The incremental reserves assignments are based on an independent reserves evaluation of the Company’s interests in respect of specific reserve entities within three future undeveloped waterflood expansion areas in Evi. The evaluation was conducted by Sproule Associates Limited (“Sproule”), independent qualified reserves evaluators, with an effective date of May 31, 2019, and supplements Sproule’s year-end evaluation of the Company’s total corporate reserves as at December 31, 2018. For additional details, please refer to the Company’s news release dated September 18, 2019 (available at www.ppr.ca) and related material change report dated September 18, 2019 (filed on SEDAR and available under PPR’s issuer profile at www.sedar.com).

FINANCIAL AND OPERATING SUMMARY

Three Months Ended September 30, Nine Months Ended September 30,
($000s except per unit amounts) 2019 2018 2019 2018
Production Volumes
Crude oil (bbls/d) 4,029 4,044 4,051 3,552
Natural gas (Mcf/d) 12,092 9,607 11,792 9,056
Natural gas liquids (bbls/d) 169 131 172 120
Total (boe/d) 6,214 5,776 6,188 5,181
% Liquids 68 % 72 % 68 % 71 %
Average Realized Prices
Crude oil ($/bbl) 61.83 69.83 61.81 67.84
Natural gas ($/Mcf) 1.14 1.35 1.57 1.53
Natural gas liquids ($/bbl) 25.53 52.61 30.26 52.66
Total ($/boe) 43.01 52.33 44.29 50.40
Operating Netback ($/boe)1
Realized price 43.01 52.33 44.29 50.40
Royalties (4.85 ) (9.04 ) (4.57 ) (7.89 )
Operating costs (18.92 ) (18.81 ) (20.86 ) (19.47 )
Operating netback 19.24 24.48 18.86 23.04
Realized losses on derivative instruments (0.29 ) (6.77 ) (1.02 ) (5.48 )
Operating netback, after realized losses on derivative instruments 18.95 17.71 17.84 17.56

Notes:
1 Operating netback is a Non-IFRS measure (see “Non-IFRS Measures” below).

Capital Structure
($000s)
As at
September 30, 2019
As at
December 31, 2018
Working capital (deficit)1 2.7 (16.1 )
Long-term debt (114.8 ) (101.1 )
Total net debt2 (112.1 ) (117.3 )
Debt capacity3 2.7 21.8
Common shares outstanding (in millions) 171.3 171.9

Notes:
1 Working capital (deficit) is a non-IFRS measure (see “Non-IFRS Measures” below) calculated as current assets less current portion of derivative instruments, minus accounts payable and accrued liabilities.
2 Net debt is a non-IFRS measure (see “Non-IFRS Measures” below), calculated by adding working capital (deficit) and long-term debt.
3 Debt capacity reflects the undrawn capacity of the Company’s revolving facility of USD$60 million at September 30, 2019 and USD$65 million at December 31, 2018, converted at an exchange rate of $1.0000 USD to $1.3243 CAD on September 30, 2019 and $1.0000 USD to $1.3642 CAD on December 31, 2018.

Three Months Ended September 30, Nine Months Ended September 30,
Drilling Activity 2019 2018 2019 2018
Gross wells 1.0 8.0
Net (working interest) wells 1.0 8.0
Success rate, net wells (%) N/A N/A 100 % 100 %

OPERATIONS REVIEW

Princess, AB

PPR’s most recent well in the southern portion of our high-value, low decline light oil play in the Princess area was completed and brought on production in June 2019, averaging production of 386 boe/d (37% liquids) in the third quarter of 2019. With a total capital cost of approximately $1.6 million to drill, complete, equip and tie-in, the well is expected to pay out after ten months under current commodity price assumptions. PPR is currently drilling one development well and one stratigraphic well. Current production from the Princess area is approximately 1,300 boe/d (70% liquids).

Michichi, AB

During the first half of 2019, PPR acquired leases on 4.25 sections of undeveloped lands in the Michichi/Wayne area as part of the elimination of PPR’s capital commitment and purchased natural gas rights in areas where PPR currently holds petroleum leases. The Michichi area continues to contribute approximately 2,450 boe/d (45% liquids) to overall production with a significant inventory of high-quality future drilling locations to support longer-term growth.

Evi, AB

Total current production from the Evi area is approximately 1,850 boe/d (97% liquids) and includes incremental production from the two gross (2.0 net) light oil Slave Point wells completed and brought on production in February 2019.

2019 OUTLOOK AND GUIDANCE

With a continued focus on its balance sheet and enhancing per share metrics, PPR’s capital allocation decisions will be regularly assessed as the Company continues to responsibly manage its inventory of high-quality future drilling locations. Supported by a successful 2019 development program and strong adjusted funds flow generated year-to-date, Prairie Provident’s disciplined 2019 capital budget of $14.2 million is expected to be funded with internally-generated adjusted funds flow. Due to recent widening of WCS differentials, the Company has decided to defer the drilling of one well to the first quarter of 2020 to preserve liquidity and development economics. As such, the Company expects its average full-year production to be at the low end of its 2019 guidance.

ABOUT PRAIRIE PROVIDENT

Prairie Provident is a Calgary-based company engaged in the exploration and development of oil and natural gas properties in Alberta. The Company’s strategy is to grow organically in combination with accretive acquisitions of conventional oil prospects, which can be efficiently developed. Prairie Provident’s operations are primarily focused at the Michichi and Princess areas in Southern Alberta targeting the Banff, the Ellerslie and the Lithic Glauconite formations, along with an established and proven waterflood project at our Evi area in the Peace River Arch. Prairie Provident protects its balance sheet through an active hedging program and manages risk by allocating capital to opportunities offering maximum shareholder returns.

For further information, please contact:

Prairie Provident Resources Inc.
Tim Granger President and Chief Executive Officer
Tel: (403) 292-8110
Email: tgranger@ppr.ca

Forward-Looking Statements

This news release contains certain statements (“forward-looking statements”) that constitute forward-looking information within the meaning of applicable Canadian securities laws. Forward-looking statements relate to future performance, events or circumstances, are based upon internal assumptions, plans, intentions, expectations and beliefs, and are subject to risks and uncertainties that may cause actual results or events to differ materially from those indicated or suggested therein.  All statements other than statements of current or historical fact constitute forward-looking statements. Forward-looking statements are typically, but not always, identified by words such as “anticipate”, “believe”, “expect”, “intend”, “plan”, “budget”, “forecast”, “target”, “estimate”, “propose”, “potential”, “project”, “continue”, “may”, “will”, “should” or similar words suggesting future outcomes or events or statements regarding an outlook.

Without limiting the foregoing, this news release contains forward-looking statements pertaining to: the Company’s budgeted capital expenditure amounts for 2019 and its expectation that such amounts will be less than forecast 2019 adjusted funds flow at current strip pricing (see also “Non-IFRS Measures” below); the ability to pursue future growth opportunities; the Revolving Facility’s continued status as a revolving facility for the remainder of its term; and drilling plans at Princess for the fourth quarter of 2019.

Forward-looking statements are based on a number of material factors, expectations or assumptions of Prairie Provident which have been used to develop such statements but which may prove to be incorrect. Although the Company believes that the expectations and assumptions reflected in such forward-looking statements are reasonable, undue reliance should not be placed on forward-looking statements, which are inherently uncertain and depend upon the accuracy of such expectations and assumptions.  Prairie Provident can give no assurance that the forward-looking statements contained herein will prove to be correct or that the expectations and assumptions upon which they are based will occur or be realized.  Actual results or events will differ, and the differences may be material and adverse to the Company. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: that Prairie Provident will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities, and their consistency with past operations; the quality of the reservoirs in which Prairie Provident operates and continued performance from existing wells; the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Prairie Provident’s reserves volumes; commodity price and cost assumptions; continued availability of debt and equity financing and cash flow to fund Prairie Provident’s current and future plans and expenditures, with external financing on acceptable terms; the impact of competition; the general stability of the economic and political environment in which Prairie Provident operates; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of Prairie Provident to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Prairie Provident has an interest in to operate the field in a safe, efficient and effective manner; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Prairie Provident to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Prairie Provident operates; and the ability of Prairie Provident to successfully market its oil and natural gas products.

The forward-looking statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements including, without limitation: changes in realized commodity prices; changes in the demand for or supply of Prairie Provident’s products; the early stage of development of some of the evaluated areas and zones; the potential for variation in the quality of the geologic formations targeted by Prairie Provident’s operations; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Prairie Provident or by third party operators; increased debt levels or debt service requirements; inaccurate estimation of Prairie Provident’s oil and gas reserves volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and such other risks as may be detailed from time-to-time in Prairie Provident’s public disclosure documents, (including, without limitation, those risks identified in this news release and Prairie Provident’s current Annual Information Form).

The forward-looking statements contained in this news release speak only as of the date of this news release, and Prairie Provident assumes no obligation to publicly update or revise them to reflect new events or circumstances, or otherwise, except as may be required pursuant to applicable laws. All forward-looking statements contained in this news release are expressly qualified by this cautionary statement.

Barrels of Oil Equivalent

The oil and gas industry commonly expresses production volumes and reserves on a “barrel of oil equivalent” basis (“boe”) whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants.  A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead nor at the plant gate, which is where Prairie Provident sells its production volumes.  Boes may therefore be a misleading measure, particularly if used in isolation. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency ratio of 6:1, utilizing a 6:1 conversion ratio may be misleading as an indication of value.

Non-IFRS Measures

The Company uses certain terms in this news release and within the MD&A that do not have a standardized or prescribed meaning under International Financial Reporting Standards (IFRS), and, accordingly these measurements may not be comparable with the calculation of similar measurements used by other companies. For a reconciliation of each non-IFRS measure to its nearest IFRS measure, please refer to the “Non-IFRS Measures” section in the MD&A.  Non-IFRS measures are provided as supplementary information by which readers may wish to consider the Company’s performance but should not be relied upon for comparative or investment purposes.  The non-IFRS measures used in this news release are summarized as follows:

Working Capital – Working capital (deficit) is calculated as current assets excluding the current portion of derivative instruments, less accounts payable and accrued liabilities. This measure is used to assist management and investors in understanding liquidity at a specific point in time.  The current portion of derivatives instruments is excluded as management intends to hold derivative contracts through to maturity rather than realizing the value at a point in time through liquidation. The current portion of decommissioning expenditures is excluded as these costs are discretionary and the current portion of flow-through share premium and warrant liabilities are excluded as it is a non-monetary liability.  Lease liabilities have historically been excluded as they were not recorded on the balance sheet until the adoption of IFRS 16 – Leases on January 1, 2019.

Net Debt – Net debt is defined as long-term debt plus working capital surplus or deficit.  Net debt is commonly used in the oil and gas industry for assessing the liquidity of a company.

Operating Netback – Operating netback is a non-IFRS measure commonly used in the oil and gas industry. This measurement assists management and investors to evaluate the specific operating performance at the oil and gas lease level. Operating netbacks included in this news release were determined by taking (oil and gas revenues less royalties less operating costs).  Operating netback may be expressed in absolute dollar basis or per unit basis.  Per unit amounts are determined by dividing the absolute value by gross working interest production. Operating netback, including realized commodity (loss) and gain, adjusts the operating netback for only realized gains and losses on derivative instruments.

Adjusted Funds Flow – Adjusted funds flow is calculated based on cash flow from operating activities before changes in non-cash working capital, transaction costs, restructuring costs, and other non-recurring items. Management believes that such a measure provides an insightful assessment of PPR’s operational performance on a continuing basis by eliminating certain non-cash charges and charges that are non-recurring or discretionary and utilizes the measure to assess its ability to finance capital expenditures and debt repayments. Adjusted funds flow as presented is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS.  Adjusted funds flow per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of earnings per share.

Net Capital Expenditures – Net capital expenditures is a non-IFRS measure commonly used in the oil and gas industry. The measurement assists management and investors to measure PPR’s investment in the Company’s existing asset base. Net capital expenditures is calculated by taking total capital expenditures, which is the sum of property and equipment and exploration and evaluation expenditures from the consolidated statement of cash flows, plus capitalized stock-based compensation, plus acquisitions from business combinations, which is the outflow cash consideration paid to acquire oil and gas properties, less asset dispositions (net of acquisitions), which is the cash proceeds from the disposition of producing properties and undeveloped lands.



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