Petrus Resources Ltd. (“Petrus” or the “Company”) (TSX:PRQ) is pleased to report financial and operating results for the three and twelve month periods ended December 31, 2017 and to provide summary 2017 year end reserves information as evaluated by Sproule Associates Limited (“Sproule”). The Company’s Management’s Discussion and Analysis (“MD&A”) and audited consolidated financial statements dated as at and for the year ended December 31, 2017 are available on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.
- Petrus generated funds flow of $45.0 million for the year ended December 31, 2017 which is 62% higher than the $27.8 million generated in the prior year. For the fourth quarter of 2017, Petrus generated funds flow of $13.1 million ($1.04 per share annualized), a 33% increase relative to the $9.8 million generated in the fourth quarter of 2016. The increases in funds flow are attributed to production growth and stronger oil and liquids pricing realized in 2017.
- Fourth quarter average production was 10,711 boe/d in 2017 compared to 8,595 boe/d in 2016. The 24% increase is attributable to the Company’s drilling program at Ferrier, where production grew 54% during the same period. Since the third quarter of 2016, when the Company’s quarterly average production was 7,100 boe/d, Petrus has grown its production 51%. Annual average production also increased 24% from 8,236 boe/d in 2016 to 10,217 boe/d in 2017. The production growth is a result of the Company’s strategic shift to focus on developmental drilling and facility ownership and control in the Ferrier area.
- Operating expenses have decreased 22% from $6.48 per boe in the year ended December 31, 2016 to $5.08 per boe in the year ended December 31, 2017. The average annual expenses on a per boe basis have decreased due to the ownership, control and expansion of the Company’s Ferrier gas plant, 2017 production growth, as well as the 2016 disposition of higher cost assets. The Company’s operating expenses were $4.81 per boe in the fourth quarter of 2017.
- In 2017 Petrus’ development program generated Proved Developed Producing (“PDP”) reserve volume additions of 6.0 mmboe, or 43% of its December 31, 2016 PDP reserve volume of 13.8 mmboe. The Company produced 3.7 mmboe during 2017 and ended the year with 16.1 mmboe of PDP reserve volume.
- Petrus ended 2017 with $214.4 million and $485.1 million of PDP and Proved plus Probable (“P+P”), respectively, reserve value before-tax, discounted at 10%, based on the independent reserve report prepared by Sproule, dated March 7, 2018, for the year ended December 31, 2017 (“2017 Sproule Report”). The reserve values have increased 19% and 15%, respectively, from the December 31, 2016 Sproule Report. In 2017, the Company realized Finding and Development (“F&D”) costs(3) of $11.57/boe and $12.03/boe for PDP and Total Proved (“TP”) reserves, respectively, and during the year ended December 31, 2017 the Company’s undeveloped net acreage in Ferrier grew 31%.
- During the fourth quarter of 2017, Petrus participated in 3 gross (1.4 net) Cardium wells in the Ferrier area, two of which were Cardium light oil wells and the third a Cardium gas well. The Ferrier gas plant expansion, doubling the plant’s capacity from 30 mmcf/d to 60 mmcf/d, was completed in early October.
- Petrus utilizes financial derivative contracts to mitigate commodity price risk. The Company realized a gain on financial derivatives in the year ended December 31, 2017, which increased the Company’s corporate netback(2) by $1.00 per boe. Petrus has derivative contracts in place for 58% (average floor price of $2.54 per mcf), and 68% (average floor price of $65.46 per bbl), of its natural gas and total liquids production, respectively, for the 2018 fiscal year (as a percentage of fourth quarter 2017 average production).
(1) Refer to “Advisories – Forward-Looking Statements.”
(2) Refer to “Non-GAAP Financial Measures.”
(3) Refer to “Oil and Gas Disclosures.”
|SELECTED FINANCIAL INFORMATION|
|Dec. 31, 2017||Dec. 31, 2016||Dec. 31, 2017||Sept. 30, 2017||Jun. 30, 2017||Mar. 31, 2017|
|Natural gas (mcf/d)||43,747||33,964||46,625||45,550||42,392||40,332|
|Natural gas sales weighting||71||%||69||%||73||%||72||%||69||%||72||%|
|Natural gas ($/mcf)||2.39||2.39||1.90||1.66||3.29||2.85|
|Total realized price ($/boe)||24.26||21.40||23.56||18.82||28.69||26.48|
|Net oil and natural gas revenue ($/boe)||20.72||18.54||20.55||16.10||24.10||22.59|
|Operating netback (1)(2) ($/boe)||14.33||10.58||14.49||9.39||17.25||16.71|
|Realized gain on derivatives ($/boe)||1.00||4.98||1.23||1.88||0.23||0.57|
|General & administrative expense||(0.87||)||(2.56||)||(0.27||)||(1.09||)||(1.12||)||(1.05||)|
|Cash finance expense||(1.88||)||(3.53||)||(1.54||)||(1.99||)||(1.94||)||(2.07||)|
|Decommissioning expenditures (3)||(0.52||)||(0.96||)||(0.62||)||(0.23||)||(1.03||)||(0.19||)|
|Corporate netback (1)(2) ($/boe)||12.06||8.51||13.29||7.96||13.39||13.97|
|FINANCIAL (000s except per share)||Twelve months
|Dec. 31, 2017||Dec. 31, 2016||Dec. 31, 2017||Sept. 30, 2017||Jun. 30, 2017||Mar. 31, 2017|
|Oil and natural gas revenue||90,569||64,840||23,243||18,299||26,753||22,274|
|Net income (loss)||(111,261||)||(66,988||)||(67,095||)||(50,696||)||(781||)||7,311|
|Net income (loss) per share|
|Funds flow (3)||45,003||27,811||13,084||7,727||12,458||11,732|
|Funds flow per share (3)|
|Net acquisitions (dispositions)||4,741||(29,718||)||789||(4,866||)||—||8,818|
|Weighted average shares outstanding|
|As at period end|
|Common shares outstanding|
|Net debt (1)||148,066||124,915||148,066||137,531||137,069||130,624|
(1) Refer to “Non-GAAP Financial Measures.”
(2) In prior periods Petrus included realized gain on derivatives (hedging gain (loss)) in the calculation of operating netback. The amount is included in the calculation of corporate netback. The comparative information has been re-classified to conform to current presentation.
(3) In prior periods Petrus excluded decommissioning expenditures from the calculation of funds flow. The comparative information has been re-classified to conform to current presentation.
Average fourth quarter production by area was as follows:
For the three months ended December 31, 2017
|Natural gas (mcf/d)||30,857||8,515||7,253||46,625|
|Natural gas sales weighting||71||%||85||%||68||%||73||%|
Fourth quarter average production was 10,711 boe/d (73% natural gas) in 2017 compared to 8,595 boe/d (72% natural gas) in the fourth quarter of 2016. The 24% increase is attributable to the Company’s drilling program in its core operating area, Ferrier, where production has grown 54% since the fourth quarter of 2016.
Petrus’ 2017 drilling program has been focused exclusively in the Ferrier area targeting light oil and liquids rich natural gas in the Cardium formation. Throughout 2017, the Company drilled or participated in 19 gross (13.2 net) wells. This included two Extended Reach Horizontal (“ERH”) liquids rich natural gas wells related to the previously announced Ferrier farm-in agreement (“Farm-In”), each with approximately 100 stages of fracture stimulations. One of these ERH wells came on production in November 2017, while the second ERH well was fracture stimulated and brought on production in December 2017. The Company estimates the Farm-in contributed 16 gross (5.2 net) Cardium locations to its drilling inventory(1). During the fourth quarter of 2017, the Ferrier gas plant expansion was completed which doubled the plant’s capacity from 30 mmcf/d to 60 mmcf/d. Also during the fourth quarter, Petrus participated in 3 gross (1.4 net) Cardium wells in the Ferrier area, two of which were light oil wells and the third a liquids rich natural gas well. The most recent Cardium oil well was fracture stimulated with 82 stages over a one mile lateral. This well flow tested over 1,200 bbl/d of oil over its 10 day test period.
From 2015 to 2017 the Company has lowered its capital cost to add a producing barrel (which Petrus defines as the total capital investment per boe per day using the average initial production rate for the first 60 days) by 52%. This efficiency has dramatically improved as a result of increasing the frac density for the completion operations, using pad drilling to reduce capital costs, experiencing more efficient drilling times, implementing monobore wellbore design, and more efficient water management.
During the third quarter of 2017, as a result of weakness and volatility in the Alberta natural gas commodity price market, Petrus realized high volatility in the market price for its natural gas. In particular, there was high volatility in the daily average natural gas spot price (AECO 5A index) which is the index on which Petrus previously sold all of its natural gas. Beginning in November 2017, Petrus elected for approximately half of its natural gas production to be paid on the forward monthly natural gas price (AECO 7A index) in an attempt to reduce the Company’s exposure to daily natural gas price volatility.
During the fourth quarter of 2017, a lower portion of Petrus’ natural gas production was sold on the daily average natural gas spot price (AECO 5A index). Furthermore, the AECO 5A index averaged $1.60 per GJ in the fourth quarter of 2017 which was 16% higher than the $1.38 per GJ average market price for the third quarter of 2017. Petrus’ average realized natural gas price in the fourth quarter of 2017 of $1.80 per GJ was 12% higher than the AECO 5A index which averaged $1.60 per GJ in the fourth quarter of 2017.
Petrus has derivative contracts in place for 58% (average floor price of $2.54 per mcf), and 68% (average floor price of $65.46 per bbl), of its natural gas and total liquids production, respectively, for the 2018 fiscal year (as a percentage of fourth quarter 2017 average production).
In October 2017 Petrus completed the semi-annual review of its reserve based revolving credit facility (“RCF”). The RCF syndicate of lenders increased the borrowing base from $120 million to $130 million. In addition, the Company’s total debt borrowing limit was increased from $141 million to
$155 million. Petrus’ Term Loan has $35 million outstanding therefore lender consent, from both the RCF syndicate and Petrus’ Term Loan lender, is required for total borrowings against the RCF that exceed $105 million. The Company’s annual review of its RCF is scheduled to take place in May 2018.
Early in 2017 Petrus set out to grow its Ferrier production and as a result, set a 2017 capital budget of $50 to $60 million which was subsequently increased by $10 million to participate in additional capital opportunities identified. Petrus achieved year over year annual average production growth of 24% from 2016 to 2017. In response to the current commodity price outlook for natural gas, the Company has shifted its focus for 2018 to prioritize its light oil drilling opportunities and to moderate its growth in order to direct excess funds flow towards debt repayment. Petrus’ Board of Directors has approved a 2018 capital budget of $25 to $30 million, with excess funds flow to be directed toward debt repayment. Petrus estimates debt repayment between $10 and $15 million in 2018, based on a current forecast for commodity futures pricing, anticipated service costs and current activity levels. Assuming capital investment of $25 million and a current forecast for commodity futures pricing, Petrus estimates the 2018 capital program will increase production year over year by 2% to an average annual 2018 production of approximately 10,350 boe/d. The 2018 capital is expected to be directed primarily to the development of the Company’s Ferrier Cardium asset which is comprised of light oil and liquids rich natural gas opportunities. The program is expected to include the drilling of nine gross (4.4 net) Cardium wells and Petrus is focusing on the areas within the reservoir that are expected to be concentrated with light oil and condensate rich natural gas. The 2018 capital program is expected to be funded through funds flow and working capital.
ANNUAL GENERAL MEETING
The Company’s Annual General Meeting will be held at the Jamieson Place Conference Centre (3rd floor) 308, 4th Ave SW Calgary, Alberta, on Tuesday May 8, 2018 at 9:00 a.m. (Calgary time).
(1)Refer to “Advisories – Forward-Looking Statements”.
Petrus’ 2017 year end reserves were evaluated by independent reserves evaluator Sproule Associates Limited (“Sproule”) in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) as of December 31, 2017 (“2017 Sproule Report”). Additional reserve information as required under NI 51-101 will be included in our Annual Information Form, for the year ended December 31, 2017, which will be filed on SEDAR.
Petrus has a reserves committee, comprised of independent board members, that reviews the qualifications and appointment of the independent reserve evaluators. The committee also reviews the procedures for providing information to the evaluators. All booked reserves are based upon annual evaluations by the independent qualified reserve evaluators conducted in accordance with the COGE Handbook and NI 51-101. The evaluations are conducted using all available geological and engineering data. The reserves committee has reviewed the reserves information and approved the reserve report.
The following table provides a summary of the Company’s before tax reserves as evaluated by Sproule:
|As at December 31, 2017||Total Company Interest (1)(3)
|Proved + Probable Producing||88,692||2,181||3,667||20,630||429,640||317,865||257,025|
|Total Proved Plus Probable||199,522||6,332||8,879||48,464||898,573||637,694||485,132|
(1) Tables may not add due to rounding.
(2) NPV 0%, NPV 5% and NPV 10% refer to the risked net present value of the future net revenue of the Company’s reserves, discounted by Nil, 5% and 10%, respectively and is presented before tax and based on Sproule’s pricing assumptions.
(3) Total company interest reserve volumes presented above and in the remainder of this annual report are presented as the Company’s total working interest before the deduction of royalties (but after including any royalty interests of Petrus).
In 2017 Petrus’ development program generated Proved Developed Producing (“PDP”) reserve volume additions of 6.0 mmboe, or 43% of its December 31, 2016 PDP reserve volume of 13.8 mmboe. The Company produced 3.7 mmboe during 2017 and ended the year with 16.1 mmboe of PDP reserve volume.
Petrus ended 2017 with $214.4 million and $485.1 million of PDP and Proved plus Probable (“P+P”), respectively, reserve value before-tax, discounted at 10%, based on the 2017 Sproule Report. The reserve values have increased 19% and 15%, respectively, from the independent reserve report prepared by Sproule for the year ended December 31, 2016. In 2017, the Company realized Finding and Development (“F&D”) costs(3) of $11.57/boe and $12.03/ boe for PDP and Total Proved (“TP”) reserves, respectively, and during the year ended December 31, 2017 the Company’s undeveloped net acreage in Ferrier grew 31%.
Based on the 2017 Sproule Report, the Company’s PDP reserve value before-tax, discounted at 10% is $4.33 per share. On the same basis, the P+P reserve value is $9.80 per share.
FUTURE DEVELOPMENT COST
Future Development Cost (“FDC”) reflects Sproule’s best estimate of what it will cost to bring the P+P undeveloped reserves on production. FDC associated with Petrus’ total P+P reserves at December 31, 2017, based on the 2017 Sproule Report, is $283.0 million (undiscounted) and includes 225 gross (122.4 net) booked P+P locations.
The following table provides a summary of the Company’s FDC as set forth in the 2017 Sproule Report:
|Future Development Cost ($000s)||Total Proved||Total Proved + Probable|
|Total FDC, Undiscounted||182,086||283,030|
|Total FDC, Discounted at 10%||155,723||241,235|
The following table highlights annual performance ratios for the Company from 2014 to 2017:
|December 31, 2017||December 31, 2016||December 31, 2015||December 31, 2014|
|FD&A ($/boe) (1)(2)||13.05||(0.43||)||23.18||35.35|
|Reserve Life Index (yr) (1)||4.1||4.4||5.2||4.6|
|Reserve Replacement Ratio (1)||1.6||0.4||0.7||5.9|
|FD&A ($/boe) (1)(2)||14.33||(15.77||)||16.77||27.44|
|Reserve Life Index (yr) (1)||8.0||9.8||10.9||7.3|
|Reserve Replacement Ratio (1)||1.1||0.5||2.9||9.1|
|Future Development Cost ($000s)||182,086||201,556||223,409||122,326|
|Total Proved + Probable|
|FD&A ($/boe) (1)(2)||14.87||350.08||15.4||21.49|
|Reserve Life Index (yr) (1)||12.3||14.6||16.4||11.2|
|Reserve Replacement Ratio (1)||1.7||(0.1||)||3.7||12.7|
|Future Development Cost ($000s)||283,030||269,144||325,325||199,410|
(1) Refer to “Oil and Gas Disclosures in the Management’s Discussion & Analysis attached hereto.”
(2) Certain changes in FD&A produce non-meaningful figures as discussed in “Oil and Gas Disclosures” in the Management’s Discussion & Analysis attached hereto. While FD&A costs, reserve life index, reserve replacement ratio and finding and development costs are commonly used in the oil and nature gas industry and have been prepared by management, these terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons. FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the exploration and development costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total FD&A costs related to reserves additions for that year.
In 2017, the Company realized F&D costs of $11.57/boe and $12.03/boe for PDP and TP reserves, respectively, as outlined in the following table.
|Finding & Development Costs ($/boe) (1)||2017||2016|
|Proved Developed Producing (1)||11.57||9.89|
|Total Proved (1)||12.03||2.46|
|Proved Plus Probable (1)||17.28||(8.06||)|
(1) Refer to “Oil and Gas Disclosures” in the Management’s Discussion & Analysis attached hereto.
NET ASSET VALUE
The following table shows the Company’s Net Asset Value (“NAV”), calculated using the price forecast from Sproule Associates Limited, the Company’s independent reserves evaluator:
|As at December 31, 2017 ($000s except per share)||Proved Developed
|Total Proved||Proved and Probable|
|Present Value Reserves, before tax (discounted at 10%) (1)||214,420||314,296||485,132|
|Undeveloped Land Value (2)||43,197||43,197||43,197|
|Net Debt (3)||(148,066||)||(148,066||)||(148,066||)|
|Net Asset Value||109,551||209,427||380,263|
|Fully Diluted Shares Outstanding (4)||49,492||49,492||49,492|
|Estimated Net Asset Value per Share||$2.21||$4.23||$7.68|
(1) Based on the 2017 Sproule Report, using the forecast future prices and costs.
(2) Based on the exploration and evaluation assets as per the Company’s December 31, 2017 audited consolidated financial statements.
(3) See Non-GAAP Financial Measures in the Management’s Discussion & Analysis attached hereto.
(4) There were no “in-the-money” options or warrants based on the Company’s December 31, 2017 closing share price of $1.95 therefore the calculation uses the common shares outstanding at December 31, 2017.
An updated corporate presentation can be found on the Company’s website at www.petrusresources.com.
For further information, please contact:
Neil Korchinski, P.Eng.
President and Chief Executive Officer T: 403-930-0889
NON-GAAP FINANCIAL MEASURES
This press release makes reference to the terms “operating netback”, “corporate netback,” “net debt” and “net debt to funds flow.” These indicators are not recognized measures under the Generally Accepted Accounting Principals (“GAAP”) and do not have a standardized meaning prescribed by GAAP. Accordingly, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. Management uses these terms for the reasons set forth below.
Operating netback is a common non-GAAP financial measure used in the oil and gas industry which is a useful supplemental measure to evaluate the specific operating performance by product at the oil and gas lease level. The most directly comparable GAAP measure to operating netback is funds flow. Operating netback is calculated as oil and natural gas revenue less royalties, operating and transportation expenses. It is presented on an absolute value and per unit basis.
Corporate netback is also a common non-GAAP financial measure used in the oil and gas industry which evaluates the Company’s profitability at the corporate level. Management believes corporate netback provides information to assist a reader in understanding the Company’s profitability relative to current commodity prices. It is calculated as the operating netback less general and administrative expense, finance expense, decommissioning expenditures, plus the net realized gain (loss) on financial derivatives. It is presented on an absolute value and per unit basis. The most directly comparable GAAP measure to corporate netback is funds flow.
Net debt is a non-GAAP financial measure and is calculated as current assets (excluding unrealized financial derivative assets) less current liabilities (excluding unrealized financial derivative liabilities and deferred share unit liabilities) and long term debt. Petrus uses net debt as a key indicator of its leverage and strength of its balance sheet. There is no GAAP measure that is reasonably comparable to net debt.
Net Debt to Funds Flow
Net debt to funds flow is calculated as the period ending net debt divided by the trailing quarter funds flow (annualized).
OIL AND GAS DISCLOSURES
Our oil and gas reserves statement for the year ended December 31, 2017, which includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, is contained within our Annual Information Form (“AIF”) which will be available on our SEDAR profile at www.sedar.com. The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered.
This press release contains metrics commonly used in the oil and natural gas industry, such as “finding and development costs” or “F&D”, “finding, development and acquisition costs” or “FD&A”, “future development cost” or “FDC”, “reserve life index” and “reserve replacement ratio.” These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included herein to provide readers with additional information to evaluate the Company’s performance, however such metrics should not be unduly relied upon.
F&D and FD&A Costs
FD&A cost is defined as capital costs for the time period including change in FDC divided by change in reserves including revisions and production for that same time period. F&D cost is defined as capital costs for the time period including change in FDC divided by change in reserves including revisions and production for that same time period, excluding acquisitions and dispositions. Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis. The methodology used to calculate F&D costs includes disclosure required to bring the proved undeveloped and probable reserves to production. Annually, changes in forecast FDC occur as a result of Petrus’ development, acquisition and disposition activities, undeveloped reserve revision and capital cost estimates. These values reflect the independent evaluator’s best estimate of the cost to bring the proved and probable undeveloped reserves to production. In 2016, the P+P F&D costs including changes in FDC can generate non meaningful information because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs.
Reserve Life Index
Reserve life index is defined as total reserves by category divided by the annualized fourth quarter production.
Reserve Replacement Ratio
The reserve replacement ratio is calculated by dividing the yearly change in reserves net of production by the actual annual production for the year.
Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Petrus’ operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment
Basis of Presentation
Financial data presented above has largely been derived from the Company’s financial statements, prepared in accordance with GAAP which require publicly accountable enterprises to prepare their financial statements using IFRS. Accounting policies adopted by the Company are set out in the notes to the audited consolidated financial statements as at and for the twelve months ended December 31, 2017. The reporting and the measurement currency is the Canadian dollar. All financial information is expressed in Canadian dollars, unless otherwise stated.
Certain information regarding Petrus set forth in this press release contains forward-looking statements within the meaning of applicable securities law, that involve substantial known and unknown risks and uncertainties. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. Such statements represent Petrus’ internal projections, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital investment, anticipated future debt, production, revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. These statements are only predictions and actual events or results may differ materially. Although Petrus believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Petrus’ actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Petrus.
In particular, forward-looking statements included in this press release include, but are not limited to, statements with respect to: the availability of cash flows from operating activities; expected 2018 debt repayment; expected year over year production; sources of financing and the requirement therefor; the growth of Petrus and the availability of the full amount of the revolving credit facility; the treatment of the revolving credit facility following the end of the revolving period; Petrus’ ability to fund its financial liabilities; the size of, and future net revenues from, crude oil, NGL (natural gas liquids) and natural gas reserves; future prospects; the focus of and timing of capital expenditures; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; access to debt and equity markets; projections of market prices and costs; the performance characteristics of the Company’s crude oil, NGL and natural gas properties including estimated production; crude oil, NGL and natural gas production levels and product mix; Petrus’ future operating and financial results; capital investment programs; supply and demand for crude oil, NGL and natural gas; future royalty rates; drilling, development and completion plans and the results therefrom; and treatment under governmental regulatory regimes and tax laws. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
This press release discloses drilling locations, which are unbooked locations based on Petrus’ prospective acreage and internal estimates as to the number of wells that can be drilled per section. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information.
There is no certainty that the Company will drill any unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company’s control, including the impact of general economic conditions; volatility in market prices for crude oil, NGL and natural gas; industry conditions; currency fluctuation; imprecision of reserve estimates; liabilities inherent in crude oil and natural gas operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources; completion of the financing on the timing planned and the receipt of applicable approvals; and the other risks. With respect to forward-looking statements contained in this press release, Petrus has made assumptions regarding: future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment and services; effects of regulation by governmental agencies; and future operating costs. Management has included the above summary of assumptions and risks related to forward-looking information provided in this press release in order to provide shareholders with a more complete perspective on Petrus’ future operations and such information may not be appropriate for other purposes. Petrus’ actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that the Company will derive therefrom. Readers are cautioned that the foregoing lists of factors are not exhaustive.
These forward-looking statements are made as of the date of this press release and the Company disclaims any intent or obligation to update any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.
The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent (“boe”) basis 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 measurement of results and comparisons with other industry participants. Petrus uses the 6:1 boe measure which is the approximate energy equivalence of the two commodities at the burner tip. Boe’s do not represent an economic value equivalence at the wellhead and therefore may be a misleading measure if used in isolation.
|$/bbl||dollars per barrel|
|$/boe||dollars per barrel of oil equivalent|
|$/GJ||dollars per gigajoule|
|$/mcf||dollars per thousand cubic feet|
|bbl/d||barrels per day|
|boe||barrel of oil equivalent|
|mboe||thousand barrel of oil equivalent|
|mmboe||million barrel of oil equivalent|
|boe/d||barrel of oil equivalent per day|
|GJ/d||gigajoules per day|
|mcf||thousand cubic feet|
|mcf/d||thousand cubic feet per day|
|mmcf/d||million cubic feet per day|
|NGLs||natural gas liquids|
|WTI||West Texas Intermediate|