CALGARY, Alberta, Nov. 12, 2018 (GLOBE NEWSWIRE) -- InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) announces its financial and operating results for the three and nine months ended September 30, 2018.  InPlay’s condensed unaudited interim financial statements and notes, as well as management’s discussion and analysis (“MD&A”) for the three and nine months ended September 30, 2018 will be available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) and our website (“”).

We are pleased to present InPlay’s financial and operating results for the three and nine months ended September 30, 2018 with results in excess of forecast and record quarterly production, revenue and cashflow.

Q3 2018 Financial & Operating Highlights

  • Successfully closed the non-core asset disposition on October 1, 2018 (announced September 13, 2018) disposing approximately 250 boe/d (72% oil and liquids) for cash consideration of $16.7 million prior to adjustments.  This rationalization of assets at premium valuation metrics allows us to redeploy the proceeds towards our high rate of return Willesden Green Cardium drilling inventory.
  • Achieved record quarterly production of 4,773 boe/d, a 17% increase compared to the third quarter of 2017, resulting in average production of 4,529 boe/d for the first nine months of 2018, a 16% increase compared to the first nine months of 2017.  Total oil and liquids weighting also increased to 70% entirely attributable to light oil growth over the same respective periods.
  • Light oil production averaged 2,695 bbl/day for the nine months ended September 30, 2018, a 20% increase compared to the first nine months of 2017 and light oil and liquids production averaged 3,160 bbl/day for the nine months ended September 30, 2018, a 22% increase over the same respective period of 2017 reflecting the focused development of our light oil weighted Cardium assets.
  • Generated revenues of $22.8 million, an increase of 57% from the third quarter of 2017 (96% derived from light oil and liquids).  Light oil revenues in the third quarter increased 64% over the third quarter of 2017 to $19.7 million.
  • Operating costs per boe of $15.62 decreased 11% compared to the third quarter of 2017 and 10% compared to the second quarter of 2018.
  • Operating income of $13.0 million, represents a 110% increase over the third quarter of 2017 with a corresponding 80% increase in operating netback to $29.51 per boe over the same respective period.
  • Generated adjusted funds flow from operations of $10.0 million or $0.15 per basic share which includes $0.8 million in realized losses on commodity derivative contracts, representing a 115% increase over the third quarter of 2017 and a 36% increase over the second quarter of 2018. 
  • Net Debt/Annualized Adjusted funds flow from operations improved to 1.6 times from 2.3 times for the third quarter of 2017 and 2.0 times for the second quarter of 2018.

Financial and Operating Results

(CDN) ($000’s) (except per share figures) Three months ended
September 30
 Nine months ended
September 30
 2018 2017 2018 2017 
Financial (CDN$)    
Oil and natural gas sales22,801 14,489 63,703 44,222 
Adjusted funds flow from operations(1)10,006 4,662 25,320 16,930 
Per share – basic and diluted0.15 0.08 0.37 0.27 
Per boe22.79 12.40 20.48 15.90 
Net (Loss)(1,775)(2,228)(710)(761)
Per share – basic and diluted(0.03)(0.04)(0.01)(0.01)
Exploration and Development Capital expenditures17,376 8,292 43,252 22,231 
Net Property Acquisitions (Dispositions)(26)- (4,164)1,220 
(Net Debt)(1)(66,005)(41,950)(66,005)(41,950)
Shares outstanding67,886,619 62,053,569 67,886,619 62,053,569 
Basic weighted-average shares67,886,619 62,084,852 67,886,619 62,288,164 
Diluted weighted-average shares67,886,619 62,084,852 67,886,619 62,288,164 
Daily production volumes    
Crude oil (bbls/d)2,775 2,403 2,695 2,245 
Natural gas liquids (bbls/d)541 381 465 346 
Natural gas (Mcf/d)8,738 7,820 8,218 7,854 
Total (boe/d)4,773 4,087 4,529 3,900 
Realized prices    
Crude Oil & NGLs ($/bbls)71.48 51.31 70.00 54.86 
Natural gas ($/Mcf)1.23 1.87 1.48 2.52 
Total ($/boe)51.93 38.53 51.52 41.53 
Operating netbacks ($ per boe)(1)    
Oil and Gas sales51.93 38.53 51.52 41.53 
Transportation expense(0.77)(0.55)(0.77)(0.66)
Operating costs(15.62)(17.60)(16.30)(16.36)
Operating Netback (prior to realized derivative contracts)29.51 16.37 28.88 20.28 
Realized gain (loss) on derivative contracts(1.75)1.10 (3.08)0.90 
Operating Netback (including realized derivative contracts)27.76 17.47 25.80 21.18 

(1) “Adjusted funds flow from operations”, “Net Debt”, “Operating netback per boe” and “Operating netback” 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 from operations” adjusts for decommissioning obligation expenditures and net change in operating non-cash working capital from net cash flow provided by operating activities.  Please refer to Non-GAAP Financial Measures and Oil and Gas Metrics and BOE equivalent at the end of this news release and the Company’s MD&A. 

Third Quarter 2018 Capital & Operational Program

InPlay’s capital program over the third quarter of 2018 saw a continued focus on our Willesden Green bioturbated Cardium assets where we have delivered exceptional results with wells consistently exceeding internal type curves and delivering some of the best Cardium production results in the area.  Our continuous drilling program is delivering peer leading capital efficiencies as we have achieved some of the shortest spud to rig release drilling days for extended reach horizontal (“ERH”) wells seen to date.  Our most recent six 1.5 mile ERH wells have averaged 9.7 drilling days with the last two wells averaging nine drilling days which to date are pacesetters in the area.  Of equal importance is the consistency in our drilling performance where the maximum deviation from average drilling time of the six 1.5 mile ERH wells has been +/- 0.7 days.   The 1.5 mile extended reach horizontal Cardium wells have allowed us to access approximately 60% more reservoir while incurring approximately only 20% more in additional capital expenditures compared to a one mile horizontal well.

InPlay’s capital program of $17.4 million for the third quarter of 2018 continued to focus on the development of the Willesden Green bioturbated Cardium where we completed two (2.0 net) ERH wells that were drilled in the second quarter and we drilled an additional five (3.3 net) ERH wells of which three (1.3 net) were completed in the third quarter and two (2.0 net) were completed early in the fourth quarter. Over the first nine months of 2018, InPlay has drilled an equivalent of 18.5 gross horizontal miles (13.3 net horizontal miles) in Willesden Green. The two recent ERH wells completed and brought on production early October have been flowing to date at an average choked rate of 520 boe/d (87% light oil and liquids) per well  and have continued to clean up with current average production per well of 652 boe/d (82% light oil and liquids).  We expect the production from these wells to remain fairly stable flowing at choked rates for 2-3 months.


Results to date from our drilling program continue to exceed our internally forecasted type curves and, even with the non-core asset disposition on October 1, 2018 of approximately 250 boe/day, we remain on track to exceed our recently increased production guidance delivering top tier production growth amongst light oil peers.

Forward West Texas Intermediate (“WTI”) pricing for the remainder of the year is in the $60 - $65 per bbl range.  Light Sweet Edmonton pricing, however, started to experience weakness beginning in September with higher differentials than normal to WTI.  These increased differentials occurred as a result of extended refinery turnarounds in the Midwest USA, increased oil supplies and transportation infrastructure restrictions.  We expect these higher differentials to persist throughout the fourth quarter of 2018.  Although this negative pricing environment could continue into 2019 we do see this as a temporary situation which is anticipated to return to more normalized levels in the New Year.

The Willesden Green area is where InPlay will deploy the majority of the remaining budgeted development capital in the fourth quarter of 2018 on the completions of the two (2.0 net) wells that were drilled at the end of the third quarter and on drilling an additional three (2.2 net) ERH wells.  InPlay has elected to defer the completion of two (2.0 net) ERH wells, originally scheduled to be on production in mid-November, until the first quarter of 2019 when improved light oil differentials are anticipated.  Despite the delay of production from these two (2.0 net) deferred wells, we still expect to exceed our average annual production guidance of 4,600 boe/day (71% oil and liquids). Field production estimates are currently over 5,350 boe/d (72% oil and liquids) exceeding our year end exit forecast of 5,100 to 5,200 boe/day (72% oil and liquids) as our recent new drills are significantly exceeding forecasted production.  To further assist in managing the current higher light oil differentials we plan to manage light oil inventory levels at our facilities over the next few months in order to sell this oil in what we believe should be an improved differential pricing environment in 2019.

We also plan to drill one vertical stratigraphic well on our northern East Basin Duvernay lands to continue the surrounding Crown lands for an additional five years and satisfy the Company’s remaining flow-through share obligations. Our plans are still to develop our Huxley Duvernay lands at a measured pace as we continue to closely monitor the significant amount of offsetting competitor activity that is in proximity to InPlay’s lands.

Our Willesden Green Cardium and East Basin Duvernay assets have InPlay established in one of the most economic horizontal development light oil plays as well as one of the most exciting emerging light oil plays in the Western Canadian Sedimentary Basin. The Company is positioned to be one of the highest growth junior light oil focused companies which currently has 70% of production and 96% of total revenues derived from oil and liquids.  We are excited about InPlay’s near-term growth and development potential given these high quality assets in the Cardium and East Basin Duvernay plays. Plans are to continue to deploy capital towards our high rate of return assets and given our financial flexibility, we expect to be able to deliver sustainable light oil production per-share growth for our shareholders.

We thank our employees and directors for their ongoing commitment and dedication and we thank all of our shareholders for their continued interest and support.  We are excited about the strong operational results we have achieved to date and we look forward to reporting upcoming results from our ongoing development program.

For further information please contact:

Doug Bartole
President and Chief Executive Officer
InPlay Oil Corp.
Telephone: (587) 955-0632
 Darren Dittmer
Chief Financial Officer
InPlay Oil Corp.
Telephone: (587) 955-0634

Reader Advisories

Non-GAAP Financial Measures and Oil and Gas Metrics
InPlay uses certain terms within this news release that do not have a standardized prescribed meaning under IFRS and GAAP and therefore these measurements may not be comparable with the calculation of similar measurements of other entities.  The terms “Adjusted funds flow from operations”, “Adjusted funds flow from operations per share”, “Adjusted funds flow from operations per boe”, “operating netbacks” , “and operating netback per boe”, “operating income”, “net debt” and “working capital (deficit)” used in this news release are not recognized measures under GAAP. Management believes that in addition to net earnings (loss) and cash flow provided by operating activities as defined by GAAP, these terms are useful supplemental measures to evaluate operating performance as it demonstrates the Company’s field level of profitability relative to current commodity prices and to assess leverage. “Adjusted funds flow from operations” should not be considered as an alternative to or more meaningful than cashflow provided by operating activities as determined in accordance with GAAP as an indicator of the Company’s performance.  InPlay’s determination of adjusted funds flow from operations may not be comparable to that reported by other companies. Adjusted funds flow from operations is calculated by adjusting for changes in operating non-cash working capital and decommissioning expenditures from cash flow provided by operating activities.  These items are adjusted from cash flow provided by operating activities as these expenditures are primarily incurred on previous operating assets and there is uncertainty with the timing and payment of these items and they are incurred on a discretionary basis making them less useful in the evaluation of InPlay’s operating performance.  Adjusted funds flow from operations per share is calculated using the same weighted average number of shares outstanding used in calculating earnings per share.  Users are cautioned, however, that these measures should not be construed as an alternative to net earnings or cash flow provided by operating activities determined in accordance with GAAP as an indication of InPlay’s performance.  For a detailed description of InPlay’s method of the calculation of adjusted funds flow from operations and its reconciliation to GAAP terms, see “Non-GAAP Measures” in the Company’s MD&A filed on Sedar.  The term “net debt” is not recognized under GAAP and is calculated as bank debt plus working capital deficit.  Working Capital (deficit) is calculated as current assets less current liabilities adjusted for risk management derivative contract fair values, deferred lease credits, flow-through share premiums and current portion of decommissioning obligation.  Net debt is used by management to analyze the financial position and leverage of InPlay. InPlay monitors working capital and net debt as part of its capital structure.  Such terms do not have a standardized meaning prescribed by GAAP and, therefore, may not be comparable with the calculation of similar measures for other entities. InPlay also uses “operating netback” and “operating netback per boe” as a key performance indicator. Operating netback per boe is utilized by InPlay to evaluate the operating performance of its petroleum and natural gas assets, and is determined by deducting royalties and operating and transportation expenses from petroleum and natural gas revenue (all on a per boe basis).  Operating Income provides the total income provided by operating activities over the period and is determined by deducting royalties and operating and transportation expenses from petroleum and natural gas revenue

Management uses oil and gas metrics for its own internal planning and performance measurements and to provide shareholders with measures to compare InPlay's 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 or other purposes. Test results and initial or short term production rates disclosed in this news release may not necessarily be indicative of long term performance of wells or ultimate recoveries.

Forward-Looking Information and Statements
This news release contains certain forward–looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "project", "should", "believe", "plans", "intends" “forecast” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the volume and product mix of InPlay's oil and gas production; production estimates including third quarter 2018, 2018 average and exit forecasts, targeted production growth; future oil and natural gas prices and InPlay's commodity risk management programs;  future liquidity and financial capacity; future results from operations and operating metrics including forecasts of operating netbacks, adjusted funds flow, cash flow and net debt ratios; future costs, expenses and royalty rates; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration, acquisition, development and infrastructure activities and related capital expenditures, including our 2018 capital budget and the timing thereof; the number of wells to be drilled, completed and tied-in and the timing thereof; the amount and timing of capital projects; the potential for improved differential pricing in 2019; the resource potential of our Duvernay play; and methods of funding our capital program. Forward-looking statements or information are based on a number of material factors, expectations or assumptions of InPlay which have been used to develop such statements and information but which may prove to be incorrect. Although InPlay believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because InPlay can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which InPlay operates; the timely receipt of any required regulatory approvals; the ability of InPlay 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 InPlay has an interest in to operate the field in a safe, efficient and effective manner; the ability of InPlay to obtain financing on acceptable terms; 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 the ability of InPlay 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 InPlay operates; the ability of InPlay to successfully market its oil and natural gas products.   

The forward-looking information and statements included herein are not guarantees of future performance and should not be unduly relied upon. Such information and 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 defer materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices and differentials; the potential for variation in the quality of the reservoirs in which we operate; changes in the demand for or supply of our products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of InPlay or by third party operators of our properties, increased debt levels or debt service requirements; inaccurate estimation of our oil and gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in InPlay's  disclosure documents. The forward-looking information and statements contained in this news release speak only as of the date hereof and InPlay does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

BOE equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.