CALGARY, Alberta – InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) is pleased to announce its financial and operating results for the three and twelve months ended December 31, 2019, and the results of its independent oil and gas reserves evaluation effective December 31, 2019 (the “Sproule Report”) prepared by Sproule Associates Limited (“Sproule”). InPlay’s audited annual financial statements and notes, as well as Management’s Discussion and Analysis (“MD&A”) for the year ended December 31, 2019 will be available at “www.sedar.com” and our website at “www.inplayoil.com”.
Message to Shareholders:
InPlay’s strategy has always been to operate a smart, prudent, and well run junior light oil focused Company that has the ability to provide growth through its strong technical expertise and generate top tier efficiencies in finding reserves and adding production. This has been done while being flexible in executing our capital program and in operations where we have continually been reacting to the extremely volatile commodity price environment that our industry has endured over the last six plus years.
The Company continued to deliver exceptional operational and financial results, delivering 7% production per share growth in 2019 over 2018, achieving our annual average production guidance of 5,000 – 5,200 boe/d, notwithstanding the sale of 250 boe/d in the fourth quarter of 2018. This average production was achieved while reducing our planned capital expenditures by 11% in the fourth quarter of 2019 which resulted in spending less than adjusted funds flow (“AFF”)(1) for 2019, adhering to our approach of being adaptable and maintaining financial flexibility. A 10% reduction in operating costs per boe and an increased operating income profit margin(1) of 6% in 2019 over 2018 was achieved, generating a 20% increase in AFF for the year over 2018 to $32.5 million in 2019. These results were achieved within a reduced pricing environment resulting in a corporate realized price of $41.11/boe in 2019 compared to $45.00/boe in 2018, due to lower West Texas Intermediate (“WTI”) and natural gas liquids (“NGL”) pricing in the year.
InPlay continued to leverage our proven track record of drilling efficiency and operational expertise, setting industry pacesetting drilling times for horizontal wells in our Willesden Green and Pembina core areas. Production results and costs continued to be better than our expectations. The Company is focused on project economics where we drill, complete and equip wells, and build adaptable, fit for purpose, modular infrastructure for the full development of a specific area. The results of our project based economics combined with our technical expertise and focused execution of our capital projects provided expected top tier efficiencies including finding and development costs of $13.98, $7.92 and $7.82 in proved developed producing (“PDP”), total proved (“TP”) and total proved plus probable (“TPP”) reserve categories respectively. This equates to recycle ratios of 1.6, 2.9 and 2.9 in all three respective categories and achieves capital efficiencies in adding producing barrels of $18,387 per boe/d in 2019 which matches our three year average of $18,390 per boe/d. These are all expected to be competitive with top tier efficiencies amongst our light oil peers.
The beginning of 2020 was looking very promising for the energy industry with stability in world oil prices and several industry agencies predicting that demand would outpace supply at some point during the upcoming year. These are unprecedented times and conditions have changed quickly with concerns of demand destruction due to the COVID – 19 outbreak. In addition, a crude oil price war was initiated between certain OPEC+ members resulting in a quick and severe drop in world oil prices. InPlay’s response to these events will be to continue its approach of maintaining prudence and financial flexibility with a focus on preserving value and the balance sheet. Refer to the Outlook section for further details of our reaction and plans, to address the current economic situation.
InPlay is a nimble, focused Company that has always reacted quickly to volatility in challenging environments. The current situation we are facing is no exception. The Company will be diligent and responsive to react quickly and resume our capital program once the pricing environment improves. As we face these difficult circumstances we would especially like to thank our many dedicated shareholders, our dedicated staff and our strong and vested Board of Directors for their guidance and support.
- Generated AFF(1) of $32.5 million ($0.48 per basic and diluted share) during 2019, an increase of 20% compared to $27.0 million ($0.40 per basic and diluted share) in 2018.
- InPlay has always been focused on the prudent and efficient deployment of capital. This is evident in the exceptional finding and development costs incurred, and associated recycle ratios, in developing new reserves, and the strong capital efficiencies in adding new producing barrels. These metrics are expected to be top tier amongst our light oil peers:
° Finding and development (“F&D”)(2) and finding, development and acquisition (“FD&A”)(2) costs of $13.98/boe, $7.92/boe, and $7.82/boe for PDP, TP and TPP reserve categories respectively.
° Strong recycle ratios(2) of 1.6 (PDP), 2.9 (TP) and 2.9 (TPP)
° Generated capital efficiency(2) of $18,387 per boe/d in 2019 which substantially equals our average of $18,390 over the last three years.
- Averaged annual 2019 production of 5,000 boe/d, an increase of 7% compared to 4,653 boe/d in 2018, achieving our annual production guidance of 5,000 – 5,200 boe/d which was increased in August 2019 due to the excellent drilling results during the year which exceeded our expectations.
- Production growth was achieved notwithstanding the sale of approximately 250 boe/d of non-core producing assets late in 2018 and an 11% reduction to originally forecasted 2019 capital spending.
- Continued focus on efficiencies resulted in operating cost rates decreasing 10% to $14.36/boe in 2019 compared to $16.02/boe in 2018.
- Operating income profit margin(1) of 55% was generated in 2019 compared to 52% in 2018, an increase of 6% which was achieved even with a 9% decrease in our overall realized prices per boe received over the same respective periods.
- Achieved PDP reserve growth of 4% and TPP reserve growth of 1% resulting in 120% and 113% replacement of production respectively.
- Returns on the reduced capital program resulted in 15% reduction in the Company’s annual Net Debt / AFF(2) ratio of to 1.7 times for 2019 compared to 2.0 times in 2018.
- “Adjusted funds flow”,”operating income profit margin” and “net debt / adjusted funds flow” do not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP Financial Measures” and “BOE equivalent” at the end of this news release and to the section entitled “Non-GAAP Measures” in our MD&A for details of calculations, rationale for use and applicable reconciliation to the nearest IFRS measure.
- Refer to section “Performance Measures” for the determination of these measures’ calculations
Financial and Operating Results:
|(CDN) ($000’s)||Three months ended
|Oil and natural gas sales||18,425||12,716||75,025||76,419|
|Per share – basic and diluted||0.11||0.02||0.45||0.38|
|Adjusted funds flow(1)||7,846||1,721||32,541||27,040|
|Per share – basic and diluted(1)||0.11||0.03||0.48||0.40|
|Comprehensive income (loss)||(18,892||)||(7,887||)||(26,842||)||(8,598||)|
|Per share – basic and diluted||(0.28||)||(0.12||)||(0.39||)||(0.13||)|
|Exploration and development capital expenditures||4,574||6,954||32,106||50,206|
|Basic & diluted weighted-average shares||68,256,616||67,987,162||68,256,616||67,911,962|
|Daily production volumes|
|Light and medium crude oil (bbls/d)||2,466||2,937||2,626||2,756|
|Natural gas liquids (boe/d)||869||573||697||492|
|Natural gas (Mcf/d)||9,978||9,065||10,058||8,431|
|Light and medium crude oil & NGLs ($/bbls)||52.54||35.09||56.59||60.49|
|Natural gas ($/Mcf)||2.51||1.66||1.74||1.53|
|Operating netbacks ($/boe)(1)|
|Oil and natural gas sales||40.07||27.53||41.11||45.00|
|Realized gain (loss) on derivative contracts||0.00||(0.66||)||0.01||(2.42||)|
|Operating netback (including realized derivative contracts)||21.70||8.18||22.76||21.01|
|(1) “Adjusted funds flow”, “adjusted funds flow per share, basic and diluted”, “adjusted funds flow per boe”, “operating income”, “operating netback per boe” and “operating income profit margin” do not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. “Adjusted funds flow” adjusts for decommissioning expenditures from funds flow. Please refer to “Non-GAAP Financial Measures” and “BOE equivalent” at the end of this news release and to the section entitled “Non-GAAP Measures” in our MD&A for details of calculations, rationale for use and applicable reconciliation to the nearest IFRS measure.|
2019 Financial & Operations Overview
InPlay delivered another year of exceptional operational results while successfully responding to commodity price challenges facing the industry. InPlay achieved organic drill bit production growth of 7% over 2018 despite an 11% reduction in originally planned capital spending to accommodate lower commodity prices than originally forecasted. The Company continues to focus on operational efficiencies which resulted in a 10% reduction to operating costs to $14.36/boe in 2019 from $16.02/boe in 2018 and a 6% increase in operating income profit margin to 55% in 2019 from 52% in 2018 (which had higher realized prices). Prudent decision making on the timing of capital expenditures, continued drilling proficiency in our Willesden Green and Pembina core areas and a strong focus on operational efficiencies allowed InPlay to generate AFF in excess of capital spending and increased AFF by 20% to $32.5 million in 2019 from $27.0 million in 2018. This growth in the year was achieved without any share dilution and positioned the Company with a solid net debt / adjusted funds flow ratio of 1.7 for 2019 compared to 2.0 in 2018.
InPlay’s 2019 capital program consisted of $32.1 million of development capital, focused on drilling wells in our Willesden Green and Pembina Cardium areas, and was less than AFF for the year. The Company drilled 10 (5.2 net) extended reach horizontal (“ERH”) wells and three (3.0 net) one-mile horizontal wells during the year ended December 31, 2019, amounting to an equivalent of 22 gross horizontal miles (11.8 net horizontal miles) and completed two (2.0 net) ERH wells that were drilled in the fourth quarter of 2018. Eight (4.8 net) ERH wells were drilled in Willesden Green and three (3.0 net) horizontal wells were drilled in Pembina.
The results noted above were achieved in light of negative market factors that affected Natural Gas Liquids (“NGLs”) prices during 2019. Revenues were impacted by multi-year lows in NGL prices beginning at the start of the second quarter of 2019 which caused a 50% reduction in realized NGL prices to $19.02/boe in 2019 from $38.27/boe in 2018, following continued propane and butane price reductions. These lower NGL prices in addition to lower WTI prices resulted in a 9% reduction in total realized prices in 2019 compared to 2018. InPlay prudently reacted to these deteriorating prices by reducing 2019 capital expenditures by 11% compared to our initial forecast in order to generate AFF that was in line with total capital expenditures.
2019 Reserve Highlights:
The strong performance of the Company’s assets, specifically in the Willesden Green and Pembina areas is highlighted by increased PDP year-end reserves by 4% to 8,718 mboe. Following are the 2019 year-end reserve highlights derived from the Sproule Report:
- PDP increased 4% to 8,718 mboe (63% light crude oil & NGLs)
- TP decreased 2% to 18,573 mboe (69% light crude oil & NGLs)
- TPP increased 1% to 27,295 mboe (71% light crude oil & NGLs)
F&D and FD&A Costs per boe(1):
- PDP F&D and FD&A costs were $13.98
- TP F&D and FD&A costs were $7.92
- TPP F&D and FD&A costs were $7.82
- PDP was 1.6 times
- TP was 2.9 times
- TPP was 2.9 times
- PDP replacement was 120%
- TP replacement was 84%
- TPP replacement was 113%
- PDP reserve life index of 4.8 years
- TP reserve life index of 10.2 years
- TPP reserve life index of 15.0 years
Growth was achieved in year-end reserves, however decreases in WTI, natural gas and NGL pricing combined with additional Abandonment, Decommissioning and Reclamation (“ADR”) costs recognized as a result of changes to the Canadian Oil and Gas Evaluation Handbook (“COGEH”) resulted in reductions to 2019 year-end reserve net present values (“NPV”) of future net revenues and year-end net asset values (“NAV”)(2):
NAV based on NPV before tax discounted at 10% (“NPV 10 BT”)(3):
- PDP NAV of $116 mm equating to $1.70 per basic share
- TP NAV of $196 mm equating to $2.87 per basic share
- TPP NAV of $311 mm equating to $4.56 per basic share
These results were accomplished despite the following changes in Sproule’s year over year price assumptions:
- WTI prices dropping 9%, and 7% in years 1 and 2 respectively and 6% for the remaining years.
- Propane prices dropping 27% and 17% in years 1 and 2 respectively and 18% for the remaining years.
- Butane prices dropping 25% and 23% in years 1 and 2 respectively and 18% for the remaining years.
- AECO spot gas prices dropping 16% and 24% in years 1 and 2 respectively and 12% for the remaining years.
- NPV 10 BT in all reserve categories includes approximately $4.3 million ($0.06 per share) of additional future ARO compared to 2018 as recommended in COGEH’s 2019 industry guidelines.
- Refer to section “Performance Measures” for the determination of these measures’ calculations
- Refer to section “Net Asset Value” for the determination of these values.
- It should not be assumed that the net present value of estimated future net revenue (“NPV”) presented above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of InPlay’s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
Corporate Reserves Information:
The following summarizes certain information contained in the Sproule Report. The Sproule Report was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form (“AIF”) which will be filed on SEDAR by the end of March 2020.
|December 31, 2019
|Light and Medium||Conventional||Oil||BTAX NPV||Future Development||Net
|Reserves Category(1)(2)(3)(4)(5)||Crude Oil||NGLs||Natural Gas||Equivalent||10%||Capital||Wells|
|Proved developed producing||4,002.8||1,486.7||19,370||8,717.8||108,937||–||–|
|Proved developed non-producing||165.9||16.8||289||230.9||3,743||560||–|
|Probable developed producing||1,041.1||370.6||4,839||2,218.4||21,159||–||–|
|Probable developed non-producing||157.6||26.2||410||252.1||5,142||102||–|
|Total proved plus probable(6)||15,684.9||3,564.7||48,273||27,295.1||304,289||225,034||108.3|
- Reserves have been presented on a gross basis which are the Company’s total working interest (operating and non-operating) share before the deduction of any royalties and without including any royalty interests of the Company.
- Based on Sproule’s December 31, 2019, escalated price forecast as outlined in the table herein entitled “Pricing Assumptions”.
- It should not be assumed that the net present value of estimated future net revenue (“NPV”) presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of InPlay’s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
- All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis.
- In 2018, the InPlay reserve report included abandonment and reclamation costs for active wells and locations only. As recommended in the October 2019 COGEH updated guidance, the Company has now also included abandonment, decommissioning and reclamation costs for all inactive assets including non-producing and suspended wells, facilities and pipelines. The impact on the Sproule Report from these additional burdens on total Proved plus Probable reserves is estimated at $4.3 million of value discounted at 10%, which will differ from the discounted values carried in our financial reporting, due to differences in abandonment activity timing and different inflation and discount values
- Totals may not add due to rounding.
Net Asset Value:
|December 31, 2019|
|BTAX NPV 5%||BTAX NPV 10%|
|Net Asset Value (basic)||117,220||1.72||115,922||1.70|
|December 31, 2019|
|BTAX NPV 5%||BTAX NPV 10%|
|Net Asset Value (basic)||233,358||3.42||196,093||2.87|
|December 31, 2019|
|BTAX NPV 5%||BTAX NPV 10%|
|Net Asset Value (basic)||392,809||5.75||311,274||4.56|
- Evaluated by Sproule as at December 31, 2019. The estimated net present value of future net revenue (“NPV”) does not represent fair market value of the reserves.
- Based on Sproule’s forecast prices and costs as of December 31, 2019.
- Duvernay land holdings evaluated by independent third party firm Seaton-Jordan Partners effective December 31, 2018 attributed a value of $49.6 mm ($1,627/acre) for 30,480 net acres. The remaining undeveloped acreage is based on an internal valuation totaling $12.6 mm ($344/acre) for 36,550 net acres.
- Net debt as at December 31, 2019.
- Based upon 68,256,616 common shares outstanding as at December 31, 2019.
Future Development Costs (“FDCs”):
FDCs decreased by $18.5 million on a Total Proved basis and $14.6 million on a Proved plus Probable basis.
|Future Development Capital Costs (amounts in $000,000’s)|
|Total Proved||Total Proved + Probable|
|Total undiscounted FDC||167.2||255.0|
|Total discounted FDC at 10% per year||139.1||182.8|
Note: FDC as per Sproule Report based on Sproule forecast pricing as at December 31, 2019
|2017||2018||2019||3 Year Avg|
|Average crude oil price WTI US$/bbl||50.95||64.76||57.02||57.58|
|E&D Capital ($000’s)(1)||40,679||20,251||30,689||–|
|Production boe/day – Full Year||3,972||4,653||5,000||4,542|
|Production boe/day – Q4||4,185||5,021||4,998||4,735|
|Operating netback $/boe – FY(2)||21.89||23.43||22.75||22.69|
|Proved Developed Producing|
|Total Reserves mboe||7,911||8,348||8,718||8,326|
|Reserves additions mboe||2,057||2,135||2,195||2,129|
|FD&A (including FDCs) $/boe(2)||19.77||9.49||13.98||14.34|
|FD&A (excluding FDCs) $/boe(2)||19.77||9.49||13.98||14.34|
|Total Reserves mboe||17,473||18,859||18,573||18,302|
|Reserves additions mboe||2,345||3,084||1,540||2,323|
|FD&A (including FDCs) $/boe(2)||27.88||16.94||7.92||18.63|
|FD&A (excluding FDCs) $/boe(2)||17.35||6.57||19.93||13.15|
|Proved Plus Probable|
|Total Reserves mboe||26,084||27,063||27,295||26,814|
|Reserves additions mboe||3,048||2,678||2,057||2,594|
|FD&A (including FDCs) $/boe(2)||26.17||15.96||7.82||17.81|
|FD&A (excluding FDCs) $/boe(2)||13.35||7.56||14.92||11.77|
In 2019, InPlay’s successful exploration, development and acquisition/disposition capital program achieved a capital efficiency of $18,387 per boe/d and a three year average of $18,390 per boe/d.(6)
- Finding, Development & Acquisition (“FD&A”) costs are used as a measure of capital efficiency. The calculation includes the period’s capital expenditures, including Exploration and Development (“E&D”) and Acquisition and Disposition (“A&D”) expended in the year, less capitalized G&A expenses and undeveloped land expenditures acquired with no reserves. This total of capital expenditures, including the change in the FDC over the period, is then divided by the change in reserves, other than from production, for the period incorporating additions/reductions from extensions, infill drilling, technical revisions, acquisitions/dispositions and economic factors. For example: 2019 TPP = ($32.2 mm E&D – $1.5 mm capitalized G&A – $nil mm of land acquisitions – $nil mm net acquisition/disposition capital – $14.6 mm FDC) / (27,295 mboe – 27,063 mboe + 1,825 mboe) = $7.82 per boe. Finding and Development Costs (“F&D”) are calculated the same as FD&A costs, however adjusted to exclude the capital expenditures and reserve additions/reductions from acquisition/disposition activity. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information section.
- “Operating netback per boe” does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP Financial Measures” and “BOE equivalent” at the end of this news release and to the section entitled “Non-GAAP Measures” in our MD&A for details of calculations, rationale for use and applicable reconciliation to the nearest IFRS measure.
- Recycle Ratio is calculated by dividing the year’s operating netback per boe by the FD&A costs for that period. For example: 2019 TPP = ($22.75/$7.82) = 2.9. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information section.
- The reserves replacement ratio is calculated by dividing the yearly change in reserves before production by the actual annual production for that year. For example: 2019 TPP = (27,295 mboe – 27,063 mboe + 1,825 mboe) / 1,825 mboe = 113%, which reflects the extent to which the Company was able to replace production and add reserves throughout the year. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information section.
- RLI is calculated by dividing the reserves in each category by the 2019 average annual production. For example 2019 TPP = (27,295 mboe) / (5,000 boeday) = 15.0 years. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information section.
- Capital Efficiency is calculated as the total annual exploration & development and acquisition and disposition capital expended in the year, less capitalized G&A and land acquisition costs divided by production additions comparing the fourth quarter of the previous year using a decline rate of 34% over the course of the year, calculated as follows: ($32.2 mm E&D capital – $nil mm acquisition/disposition capital – $1.5mm capitalized G&A – $nil mm land acquisitions) / (Q4/2019 production of 4,998 boe/d – Q4/2018 production of 5,021 boe/d + 2019 declined production at 34% of 1,692 boe/d). See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information section.
The following tables set forth the benchmark reference prices, as at December 31, 2019, reflected in the Sproule Report. These price assumptions were provided to InPlay by Sproule and were Sproule’s then current forecast at the effective date of the Sproule Report.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS (1)
as of December 31, 2019
FORECAST PRICES AND COSTS
|Natural Gas AECO-C Spot
|NGLs Edmonton Butanes
|Operating Cost Inflation Rates
|Capital Cost Inflation Rates
|Exchange Rate (2)
|Thereafter Escalation rate of 2.0%|
- This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
- The exchange rate used to generate the benchmark reference prices in this table.
- As at December 31, 2019.
InPlay began the 2020 capital program drilling one (1.0 net) ERH horizontal Willesden Green well and three (3.0 net) horizontal Pembina wells in the first quarter of 2020. The Company also recompleted and commissioned a water disposal well in Pembina which is expected to provide long term savings in the area. All wells drilled in the first quarter have been completed and placed on production albeit at lower ramp up rates than would normally occur, as a result of the current low oil price.
In January of 2020, the Company’s Board of Directors had approved a 2020 capital program of $35 million which was less than projected AFF on WTI futures pricing of $57 USD/bbl. With the significant drop and volatility in world crude oil prices as a result of the COVID – 19 outbreak and the corresponding oil price war, consistent with past practices the Company will manage its spending and adjust the capital program accordingly throughout 2020 and no longer has plans for capital spending of $35 million. InPlay has completed its first quarter capital program and only minimal capital spending is expected over the second quarter during spring break-up. As such, no major capital spending decisions are being made at this time. Capital planning decisions for the second half of 2020 and any updated forecasts will be made in due course in consideration of forecasted AFF reflecting the prevailing commodity prices at that time.
The Company’s low decline rate, strong operating netbacks, top-tier capital efficiencies, lack of drilling commitments and primarily operated capital program provide flexibility in this volatile market. Efforts have been initiated to optimize operations in order to minimize costs and preserve value for the Company. All operations will be thoroughly vetted to optimize corporate cash flows which may include shutting in any wells that that will not generate positive cash flow under current prices (net of fixed cost considerations). Further operating and corporate cost efficiencies will also be pursued in consideration of the current pricing environment.