CALGARY, ALBERTA-( March 23, 2017) – Chinook Energy Inc. (“our”, “we”, or “us”) (TSX:CKE) is pleased to announce its fourth quarter 2016 financial and operating results and provide an operations update, including in respect of its most recent three well Birley/Umbach drilling program.
Our operational and financial highlights for the three months and year ended December 31, 2016 are noted below and should be read in conjunction with our consolidated financial statements for the years ended December 31, 2016 and 2015 and our related management’s discussion and analysis which have been posted on the SEDAR website (www.sedar.com) and our website (www.chinookenergyinc.com).
Fourth Quarter 2016 Financial and Operating Highlights
|Three months ended||Year ended|
|December 31||December 31|
|Crude oil (bbl/d)||451||922||768||1,187|
|Natural gas liquids (boe/d)||613||364||637||510|
|Natural gas (mcf/d)||21,548||15,851||24,631||23,642|
|Average daily production (boe/d)||4,655||3,928||5,510||5,637|
|Average oil price ($/bbl)||$||71.98||$||47.93||$||52.01||$||53.08|
|Average natural gas liquids price ($/boe)||$||40.70||$||30.59||$||26.35||$||35.83|
|Average natural gas price ($/mcf)||$||3.31||$||2.09||$||2.06||$||2.50|
|Average commodity pricing ($/boe)||$||27.67||$||22.51||$||19.51||$||24.89|
|Net production expenses ($/boe) (1)||$||(11.88||)||$||(14.17||)||$||(13.61||)||$||(15.92||)|
|G&A expense ($/boe)||$||(5.80||)||$||(8.31||)||$||(4.58||)||$||(4.76||)|
|Netback ($/boe) (1)||$||7.15||$||2.42||$||0.13||$||3.48|
|Wells Drilled (net)|
|Total natural gas wells drilled (net)||2.63||–||2.63||2.75|
|Three months ended||Year ended|
|December 31||December 31|
|FINANCIAL ($ thousands, except per share amounts)|
|Petroleum & natural gas revenues, net of royalties||$||10,631||$||9,000||$||36,943||$||49,701|
|Funds (outflow) from operations (1)||$||1,713||$||1,516||$||(1,004||)||$||9,033|
|Per share – basic and diluted ($/share)||$||0.01||$||0.01||$||(0.00||)||$||0.04|
|Net income (loss)||$||6,427||$||(5,303||)||$||(54,773||)||$||(83,606||)|
|Per share – basic and diluted ($/share)||$||0.03||$||(0.02||)||$||(0.25||)||$||(0.39||)|
|Net surplus (1)||$||(15,138||)||$||(29,614||)||$||(15,138||)||$||(29,614||)|
|Common Shares (thousands)|
|Weighted average during period|
|Outstanding at period end||216,443||215,349||216,443||215,349|
|(1)||Funds (outflow) from operations, Funds (outflow) from operations per share, net debt (surplus), netback, and net production expense are non-GAAP measures. These terms do not have any standardized meanings as prescribed by IFRS and, therefore, may not be comparable with the calculations of similar measures presented by other companies. See headings entitled “Funds (outflow) from Operations”, “Net Debt (Surplus)”, “Netback” and “Net Production Expense” in the Reader Advisory below for further information on such terms.|
2016 Highlights (Exclusive of assets disposed to Craft Oil Ltd.)
- Through several strategic transactions, we completed our transformation to a well-financed company focussing on our large contiguous Montney liquids-rich natural gas position at Birley/Umbach in northeast British Columbia.
- Our total proved (“1P”) reserves, net of acquisition & divestiture increased by 33% from 2015 to 2016 with record low finding and development (“F&D”) costs of $6.65/Boe (1P additions replaced 330% of production).
- Our total proved plus probable (“2P”) reserves, net of acquisition & divestiture increased by 45% from 2015 to 2016 with record low F&D costs of $4.76/Boe (2P additions replaced 660% of production).
- The net present value (NPV 10%) of our 1P reserves was $65.8 million at the end of 2016, an increase of 216% compared to 2015.
- The net present value (NPV 10%) of our 2P reserves was $127.7 million at the end of 2016, an increase of 178% compared to 2015.
- Reserves have been booked over only 15% of our 38,802 gross acres (32,054 net acres) of Montney rights in the Birley/Umbach area, not including 13,593 gross acres (11,755 net acres) of offsetting Montney rights in the Martin Creek area.
- Our 2016 operating costs per boe related to the properties that we currently still own (exclusive of our 2016 dispositions, including Craft, and our 2017 disposition at Gold Creek), decreased by about 35% to approximately $15.00/boe compared to our 2015 operating costs for these same properties of approximately $23.00/boe.
- During the fourth quarter, we began to realize the benefits of a new gas handling agreement which has significantly improved our go-forward economics and reduced our operating costs by an additional $2.70/boe.
- During the fourth quarter, we drilled three wells (2.63 net) at Birley/Umbach at an average cost of $1.28 million per well, a decrease of 43% from our previous average cost of $2.25 million per well.
- Capital investment was $9.2 million during 2016 including $2.0 million to complete the construction of our new 25 mmcf/d Birley/Umbach compression facility. We ended 2016 with a strong balance sheet, including a net surplus of $15.1 million (including cash of $16.1 million).
- During the fourth quarter, we negotiated an $8.0 million demand revolving credit facility with a Canadian chartered bank, which was signed during the first quarter of 2017.
- We continue to layer in commodity price hedges and diversify our natural gas sales points with approximately 42% of forecast 2017 natural gas production currently hedged and 20% of forecast 2017 natural gas production sold at Alliance Chicago Pricing.
2017 Recent Operations Highlights
- We completed, equipped and tied-in three (2.63 net) horizontal Montney wells at Birley/Umbach at an average cost to drill and complete of $3.7 million per well, a 30% decrease from the previous six (5.0 net) wells which averaged $5.3 million per well.
- Including production from the following new Birley wells, our current production is approximately 5,350 boe/d.
- A-071-F/094-H-03 (0.75 net) tested at a final rate of 1,288 boe/d (approximately 96% gas, 4% free condensate).
- C-095-F/094-H-03 (0.90 net) tested at a final rate of 1,364 boe/d (approximately 88% gas, 12% free condensate).
- D-095-F/094-H-03 (0.98 net) tested at a final rate of 1,094 boe/d (approximately 94% gas, 6% free condensate).
- We have commenced construction of a new drilling pad to drill four (3.67 net) wells through spring break-up and will complete all four shortly after spring break-up.
Craft Oil Ltd.
On June 10, 2016, we completed the conveyance of the majority of our Alberta oil and natural gas assets, excluding our Montney assets, and the associated decommissioning obligations in addition to $0.9 million cash (collectively, the “Subject Assets”) to a predecessor of Craft Oil Ltd. (“Craft”), a private Calgary-based petroleum and natural gas production company, for 70% of its issued and outstanding common shares pursuant to an asset purchase and sale agreement dated and effective May 1, 2016. On December 12, 2016 we completed the distribution of all of the Craft shares held by us to our shareholders as at the close of business pursuant to a plan of arrangement under the Business Corporations Act (Alberta) (the “Craft Share Distribution”). Following the Craft Share Distribution, we no longer had any ownership in Craft and, as a result, for subsequent reporting periods, the results of Craft are no longer required to be consolidated into our results.
2017 Non-Core Asset Dispositions
Effective January 23, 2017, we completed the sale of certain of our non-core assets located in the Knopcik/Pipestone area of Alberta for net consideration of approximately $7.5 million, subject to customary closing adjustments.
Effective February 1, 2017, we completed the disposition of certain of our non-core assets located in the Gold Creek area of Alberta for net consideration of approximately $10.5 million, subject to customary closing adjustments.
The foregoing dispositions further strengthened our company to pursue a more aggressive drilling program on our core Birley/Umbach acreage.
2016 Financial Results
Our production in the fourth quarter of 2016 averaged 4,655 boe/d, up almost 19% from the same period in 2015. This increase is attributed to the completion of our Birley/Umbach compressor expansion during the first quarter of 2016, in addition to improved commodity pricing and a new gas handling agreement which enabled us to reactivate wells in the Martin Creek and Black Conroy areas of northeastern British Columbia, adding 1,100 boe/d of production during the fourth quarter. These increases were partially offset by Craft’s disposition of certain Alberta assets in October 2016 followed by our completion of the Craft Share Distribution in December 2016, in addition to natural declines, additional property dispositions and voluntary shut-ins. On an unconsolidated basis (excluding results from Craft), our fourth quarter 2016 production averaged 2,593 boe/d.
Our 2016 petroleum and natural gas revenues were down approximately 23% from 2015 primarily as a result of both decreased volumes and realized commodity prices. However, our fourth quarter petroleum and natural gas revenues increased almost 46% from the same period of 2015 primarily as a result of increased natural gas and natural gas liquids volumes and increased realized commodity prices. On an unconsolidated basis, our fourth quarter petroleum and natural gas revenues were down approximately 41% from the same period of 2015 primarily as a result of decreased crude oil production. On an unconsolidated basis, we had lower natural gas and natural gas liquids production during the fourth quarter; however, these production decreases were offset by higher commodity prices which led to an increase of approximately 11% and 23% in our natural gas and natural gas liquids revenues, respectively, during the fourth quarter compared to the same quarter of 2015, despite the decrease in volumes.
Our 2016 net production expense (operating costs net of processing income) decreased by approximately 16% to $27.4 million from $32.8 million in the same period of 2015. This decrease primarily resulted from disposing or shutting-in high operating cost/lower netback properties during the year. On an unconsolidated basis, our fourth quarter net production expense of $9.39/boe benefited from the disposition of higher operating cost assets and a new gas handling agreement which we entered into during the third quarter of 2016. For 2017 we forecast our operating costs to be approximately $10.00/boe ($9.50/boe net of processing income.)
We have focused on improving our G&A cost structure and implementing cost cutting initiatives. Our year over year G&A costs decreased by approximately 6% despite including $1.6 million of Craft G&A costs. Although personnel were transferred to Craft on conveyances of the Subject Assets, we will not report this significant G&A cost reduction until the first quarter of 2017. During 2016, $2.4 million of our total G&A costs related to rent expense incurred on our head office lease which expires June 30, 2019. Assuming current rental market conditions remain the same or similar, we expect a favourable rent adjustment commencing in 2019 upon our lease expiration, based on our anticipated office space requirements.
Our fourth quarter funds from operations were $1.7 million an increase of approximately 13% compared to the same quarter of 2015 as a result of increases in our production volumes and corporate netbacks. On an unconsolidated basis, our fourth quarter funds from operations were $0.2 million. For the year ended 2016, we reported an outflow from operations of $1.0 million compared to funds from operations of $9.0 million during the year ended 2015 as a result of lower production volumes and corporate netbacks. Our lower corporate netback was primarily due to lower realized commodity pricing.
We reported a net loss for the year ended 2016 of $54.8 million compared to a loss of $83.6 million for the year ended 2015. During 2016, we reported a lower impairment charge of $58.1 million related to development and production assets held by Craft, as well as a recovery of prior period impairments of $17.0 million related to our remaining assets at December 31, 2016, compared to an impairment charge of $75.0 million during the year ended 2015.
We have transformed into a pure play Montney focused company. Completing the foregoing non-core asset dispositions at Gold Creek and Knopcik/Pipestone during the first quarter of 2017 raised capital which we are actively deploying to develop and expand our Birley/Umbach property.
During mid-February 2016, we brought on-stream three (2.75 net) additional wells at Birley/Umbach upon the commissioning of our new compression facility. During the fourth quarter of 2016, we successfully completed a three well (2.63 net) drilling program at Birley/Umbach which was on schedule and under budget by approximately 26%, with average drilling costs of approximately $1.28 million per well ($1.12 million, net).
During the first quarter of 2017, we completed and tied-in the three wells (the a-71-F, d-95-F and c-95-F wells) drilled during the fourth quarter of 2016. The gross test results for the three wells, as compared to gross test rates for all our Birley/Umbach wells drilled to date, are as follows:
|Well||Working Interest (%)||Lateral Length (metres)||Frac’d Stages (gross)||Flow Time (hours)||24 Hour Test Rate End Date (MM/DD/YYYY)||Final 24 Hour Average Test Total Gas Rates (mcf/d)||Final 24 Hour Average Test Total FCGR (1)(bbl/mmcf)||IP30 (mcf/d)||IP60 (mcf/d)||IP90 (mcf/d)|
|(1)||Free condensate gas ratio.|
The a-71-F well has been on production for 8 days and is currently producing at a restricted gross rate of 3.9 mmcf/d and 77 bbls of free condensate per day (gross – 724 boe/d; net – 540 boe/d). The d-95-F well has been on production for 8 days and is currently producing at a restricted gross rate of 3.7 mmcf/d and 154 bbls of free condensate per day (gross – 774 boe/d; net – 761 boe/d). The c-95-F well has been on production for 4 days and is currently producing at a restricted gross rate of 3.5 mmcf/d and 111 bbls of free condensate per day (gross – 690 boe/d; net – 624 boe/d).
Our future growth potential at Birley/Umbach is significant with 52,395 acres (43,809 net) of Montney rights with an upper Montney drilling inventory of over 270 (227 net) management identified locations along with additional potential to reduce inter-well spacing in the upper Montney (from four to five or six horizontal wells per section) and also develop middle and lower Montney layers throughout a 250 meter thick Montney interval.
We use commodity price hedges to support our capital investment and growth by providing more certainty regarding our funds flow and balance sheet management. Our internal policy permits us to hedge up to a maximum period of 24 months, based on our total estimated oil and natural gas production volumes, consisting of no more than 50% for the first 12 months and 25% for the last 12 months. Our current hedges in place are as follows:
|Indexed Price||Notional Volumes||Company’s Received Price||Contractual Term|
|AECO||7,500 GJ/d||$3.205/GJ||January 1, 2017 to December 31, 2017|
|AECO||4,000 GJ/d||$2.50/GJ||April 1, 2017 to October 31, 2017|
On January 23, 2017, we announced a $40 million capital program for 2017 which included the expansion of our facility at Birley/Umbach to 50 mmcf/d and the drilling of six (4.5 net) wells which were anticipated to be 1,600 meters in length with frac spacing of 60 to 65 meters. We are optimizing our drilling and completion program which has been revised to now include the drilling of four (3.67 net) wells, two (2.0 net) of which will have lateral sections of 1,600 meters in length and two (1.67 net) will have 1,800 meter length laterals. All four wells will have tighter frac spacing of approximately 52 meters from the original 60 to 65 meters. The additional length of two of the wells is anticipated to add to the recoverability of hydrocarbons while increased frac density is anticipated to result in increased initial well rates. This change in our drilling program will result in 10% more net frac stages despite resulting in 0.83 fewer net wells. As a result of the longer length of two of the wells and the decreased frac spacing, the amount of our capital program will be maintained at $40 million. We are also marginally increasing our previously announced average and ending production for 2017 and marginally decreasing our working capital surplus at December 31, 2017 as follows:
|($ millions, except boe/d)||Original 2017 Guidance (1)||Revised 2017 Guidance(2)|
|Average production (boe/d)||4,070 – 4,170||4,200 – 4,300|
|Exit production (boe/d)||6,000 – 6,150||6,300 – 6,500|
|Net surplus as at December 31, 2017||$||3||$||2|
|(1)||Original 2017 guidance assumptions: AECO natural gas price $2.93/mmbtu, Station 2 natural gas price $2.26/mmbtu and Chicago Alliance natural gas price $3.20/mmbtu.|
|(2)||Revised 2017 guidance assumptions: AECO natural gas price $2.64/mmbtu, Station 2 natural gas price $2.11/mmbtu and Chicago Alliance natural gas price $2.92/mmbtu.|
|Original 2017 Guidance||Revised 2017 Guidance|
|Drilling program (wells)||6||4.5||4||3.67|
|Frac stages for drilling program||144||107.4||130||118.4|
About Chinook Energy Inc.
Chinook is a Calgary-based public oil and natural gas exploration and development company which is focused on realizing per share growth from its large contiguous Montney liquids-rich natural gas position at Birley/Umbach, British Columbia.
|Oil and Natural Gas Liquids||Natural Gas|
|bbl||barrel||mmcf/d||million cubic feet per day|
|bbls/d||barrels per day||GJ/d||gigajoules per day|
|mcf||thousand cubic feet||mmbtu||million British Thermal Units|
|mmcf||million cubic feet|
|boe||barrel of oil equivalent on the basis of 6 mcf/1 boe for natural gas and 1 bbl/1 boe for crude oil and natural gas liquids (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)|
|boe/d||barrel of oil equivalent per day|
In the interest of providing our shareholders and readers with information regarding our company, including management’s assessment of our future plans and operations, certain statements contained in this news release constitute forward-looking statements or information (collectively “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “may”, “will”, “project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”, “potential”, “target” and similar words suggesting future events or future performance. In particular, this news release contains, without limitation, forward-looking statements pertaining to: our expectation that the new gas handling agreement will significantly improve our go-forward drilling economics and reduce our operating costs, future G&A cost reductions and the realization thereof, our expected future production costs, our plans and operations including our intention to concentrate on our Montney assets, the amount and composition of our 2017 capital program, future exploration and development activities and the timing thereof and how we intend to manage our company as well our revised guidance regarding average and ending production for 2017, capital expenditures for 2017 and working capital surplus at December 31, 2017 set forth under the heading “Outlook”.
With respect to the forward-looking statements contained in this news release, we have made assumptions regarding, among other things: that we will continue to conduct our operations in a manner consistent with that expressed herein, future capital expenditure levels, future oil and natural gas prices, future oil and natural gas production levels, future currency, exchange and interest rates, our ability to obtain equipment in a timely manner to carry out exploration and development activities, the ability of the operator of the projects in which we have an interest in to operate in the field in a safe, efficient and effective manner, the impact of increasing competition, field production rates and decline rates, anticipated production volumes, our ability to replace and expand production and reserves through exploration and development activities, certain cost assumptions, that the budgeted 2017 capital program, which is subject to the discretion of our Board of Directors, will not be amended in the future, and the continued availability of adequate debt and cash flow to fund our planned expenditures. Although we believe that the expectations reflected in the forward-looking statements contained in this news release, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this news release, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur.
By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that predictions, forecasts, projections and other forward-looking statements will not occur, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices and currency fluctuations, our Board of Directors may amend the 2017 capital program based on its discretion; environmental risks, competition from other producers, inability to retain drilling rigs and other services, unanticipated increases in or unforeseen capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, delays in projects and/or operations resulting from surface conditions, wells not performing as expected, delays resulting from or inability to obtain the required regulatory approvals and inability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Readers are cautioned that the forgoing list of factors is not exhaustive. Additional information on these and other factors that could affect our operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) and at our website (www.chinookenergyinc.com). Furthermore, the forward-looking statements contained in this news release are made as at the date of this news release and we do not undertake any obligation to update publicly or to revise any of the forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
The reader is cautioned that this news release contains the term netback, which is not a recognized measure under IFRS and is calculated as a period’s sales of petroleum and natural gas, net of royalties less net production and operating expenses and G&A expense as divided by the period’s sales volumes. We use this measure to assist us in understanding our profitability relative to current commodity prices and it provides an analytical tool to benchmark changes in operational performance against prior periods. Readers are cautioned, however, that this measure should not be construed as an alternative to other terms such as net income determined in accordance with IFRS as a measure of performance. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies. We include G&A expense in our Netback calculation as it represents the administrative component of developing the associated production.
Net Production Expense
The reader is cautioned that this news release contains the term net production expense, which is not a recognized measure under IFRS and is calculated as production and operating expense less processing and gathering income. We use net production expense to determine the current periods’ cash cost of operating expenses and net production and operating expense per boe is used to measure operating efficiency on a comparative basis. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies.
Funds (Outflow) from Operations
The reader is cautioned that this news release contains the term funds (outflow) from operations, which is not a recognized measure under IFRS and is calculated from cash flow from operations adjusted for changes in non-cash working capital related to operations, exploration and evaluation expenses related to operations, decommissioning obligation expenditures related to operations and transaction costs. We believe that funds (outflow) from operations is a key measure to assess our ability to finance capital expenditures and when debt is drawn, debt repayments. Funds (outflow) from operations is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS and should not be construed as an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with IFRS as an indicator of our financial performance. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies. We adjust exploration and evaluation expense as we could otherwise capitalize these expenses.
Net Debt (Surplus)
The reader is cautioned that this news release contains the term net debt (surplus), which is not a recognized measure under IFRS and is calculated as bank debt adjusted for current assets less current liabilities as they appear on the balance sheets, both of which exclude mark-to-market derivative contracts and assets and liabilities held for sale and current liabilities excludes any current portion of debt and decommissioning obligation. We use net debt (surplus) to assist us in understanding our liquidity at specific points in time. We exclude the current portion of decommissioning obligation as it is not a financial instrument and only once it has been incurred and in turn cycled through accounts payable, accrued liabilities or a reduction in cash, do we view it as an adjustment to our net debt (surplus). Mark-to-market derivative contracts are excluded as they are unrealized.
Future Oriented Financial Information
This news release, in particular the information in respect of the anticipated capital expenditures and net surplus set out in the table under the heading “Outlook”, may contain Future Oriented Financial Information (“FOFI”) within the meaning of applicable securities laws. The FOFI has been prepared by our management to provide an outlook of our activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions including the assumptions discussed under the heading “Forward-Looking Statements” and assumptions with respect to production rates and commodity prices. The actual results of our operations and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. Our management believes that the FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments.
Barrels of Oil Equivalent
Barrels of oil equivalent (boe) is calculated using the conversion factor of 6 mcf (thousand cubic feet) of natural gas being equivalent to one barrel of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl (barrel) 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 from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
This news release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from our most recent independent reserves evaluation as prepared by McDaniel & Associates Consultants Ltd. as of December 31, 2016 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the over 270 gross (227 net) additional drilling locations identified herein, 16 gross (14.2 net) are proved locations, 10 gross (8.5 net) are probable locations and 244 gross (204.3 net) are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, 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.
Initial Production Rates
Any reference in this news release to initial, early and/or test or production/performance rates (including IP30, IP60 and IP90) are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Additionally, such rates may also include recovered “load oil” fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating our aggregate production. The initial production or test rates may be estimated based on other third party estimates or limited data available at this time . In all cases in this news release initial production or test rates are not necessarily indicative of long-term performance of the relevant well or fields or of ultimate recovery of hydrocarbons. Well-flow test result data should be considered to be preliminary until a pressure transient analysis and/or well-test interpretation has been carried out.