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Chinook Energy Inc. Announces Third Quarter 2017 Results and Increased Credit Facility

CALGARY, AB, Nov 09, 2017 (GLOBE NEWSWIRE via COMTEX) --

Chinook Energy Inc. ("our", "we", or "us") (TSX:CKE) is pleased to announce its third quarter 2017 financial and operating results.

Our operational and financial highlights for the three and nine months ended September 30, 2017 are noted below and should be read in conjunction with our condensed consolidated financial statements for the three and nine months ended September 30, 2017 and 2016 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).

Third Quarter 2017 Financial and Operating Highlights

                                               Three months ended              Nine months ended
                                                              September 30     September 30
                                                   2017            2016           2017         2016
OPERATIONS
Production Volumes
Natural gas liquids (boe/d)                        405             599            442          645
Natural gas (mcf/d)                                14,109          28,972         17,051       25,666
Crude oil (bbl/d)                                  19              1,036          22           874
Average daily production (boe/d)                   2,776           6,464          3,306        5,798
Sales Prices
Average natural gas liquids price ($/boe)      $   42.07      $    10.67       $  46.22     $  21.78
Average natural gas price ($/mcf)              $   1.20       $    2.22        $  2.31      $  1.71
Average oil price ($/bbl)                      $   51.49      $    57.31       $  57.52     $  48.55
Netback
Average commodity pricing ($/boe)              $   12.61      $    20.14       $  18.49     $  17.31
Royalty recovery (expense) ($/boe)             $   0.52       $    (0.77  )    $  0.09      $  (0.74  )
Realized gains on derivative contracts ($/boe) $   6.54       $    1.84        $  2.70      $  0.72
Net production expense ($/boe)                 $   (12.32 )   $    (12.61 )    $  (11.77 )  $  (14.07 )
Operating Netback ($/boe)                      $   7.35       $    8.60        $  9.51      $  3.22
Wells Drilled (net)
Total natural gas wells drilled (net)              -               -              3.63         -
                                                  Three months ended                Nine months ended
                                                                  September 30      September 30
                                                      2017             2016             2017        2016
FINANCIAL ($ thousands, except per share amounts)
Petroleum & natural gas revenues, net of royalties$   3,351       $    11,518       $   16,772  $   26,312
Adjusted funds (outflow) from operations          $   647         $    1,894        $   3,878   $   (2,717  )
Per share - basic and diluted ($/share)           $   -           $    0.01         $   0.02    $   (0.01   )
Net (loss) income                                 $   (3,923  )   $    (35,905 )    $   4,246   $   (61,200 )
Per share - basic and diluted ($/share)           $   (0.02   )   $    (0.17   )    $   0.02    $   (0.28   )
Capital expenditures                              $   14,733      $    661          $   31,791  $   5,034
Net surplus                                       $   3,616       $    7,217        $   3,616   $   7,217
Total assets                                      $   155,799     $    274,674      $   155,799 $   274,674
Common Shares (thousands)
Weighted average during period
- basic                                               217,115          216,287          216,721     215,666
- diluted                                             217,115          216,287          217,144     215,666
Outstanding at period end                             217,115          216,443          217,115     216,443

-- Adjusted funds (outflow) from operations, adjusted funds (outflow) from operations per share, net surplus (debt), operating 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 "Adjusted Funds (outflow) from Operations", "Net Surplus (Debt)", "Operational Netback" and "Net Production Expense" in the Reader Advisory below for further information on such terms.

Highlights for the three months ended September 30, 2017

-- We ended the third quarter of 2017 with a net surplus of $3.6 million.

-- Subsequent to quarter end, we secured an increased credit facility to $18.0 million from the previous $8.0 million which provides us with further financial flexibility. We remain undrawn on this facility.

-- We incurred $14.7 million of capital expenditures during the third quarter which included the completion and tie-in of our four (3.63 net) horizontal wells at Birley/Umbach that were drilled in the second quarter of 2017 as well as $2.5 million related to our Birley/Umbach facility expansion.

-- Upon completion of the four new Birley/Umbach wells, the final 24 hour test rates per well averaged 1,800 boe/d including 300 bbl/d of condensate. Two of these wells (1.63 net) came on-stream at the beginning of October 2017; however, due to our existing 25 mmcf/d raw natural gas Birley/Umbach facility being full, these new wells are currently flowing at restricted rates.

-- Our Birley/Umbach facility expansion is ongoing and is expected to be on-stream late in the fourth quarter. Upon the completion of this facility's expansion to 50 mmcf/d, we plan on releasing the flow restrictions on our two newly producing Birley/Umbach wells and bringing the other two (2.00 net) wells on-stream. At that point we expect to have production from all 13 (11.27 net) Birley/Umbach wells.

-- A longer than expected third-party plant turnaround and other third party restrictions coupled with a decrease in our realized price driven by significantly lower BC natural gas benchmark pricing, has resulted in an update to our 2017 guidance which is outlined in the "Outlook" section of this news release. Our current production is approximately 4,700 boe/d.

Third Quarter 2017 Financial Results

Our production during the third quarter of 2017 averaged 2,776 boe/d, a decrease of 24% from the previous quarter primarily due to a longer than scheduled turnaround at the Enbridge McMahon gas plant (the "McMahon Plant") that restricted our July volumes. This turnaround, which began in June, resulted in July's production being 3,160 boe/d lower than May. Our Montney production was back on-stream in mid-July immediately following the completion of the McMahon Plant turnaround. We averaged 4,850 boe/d from July 18 - 24, 2017 but these volumes were subsequently impacted by further McMahon Plant and other third party restrictions.

Our production in the third quarter of 2017 decreased 57% from the same quarter of 2016 primarily due to the absence of the legacy assets of a subsidiary that we acquired late in the second quarter of 2016, in addition to the majority of our Alberta assets that we conveyed to that subsidiary, as a result of the distribution of that subsidiary's shares to our shareholders late 2016 (the "Share Distribution") and various other property dispositions.

For the third quarter of 2017, our operating netback decreased 15% to $7.35/boe compared to the same quarter of 2016. This decrease was driven by decreases in our realized commodity pricing despite improvements in each of the other components of the operating netback. Our realized commodity price decreases generally trended with the decreases in benchmark pricing resulting in a realized price of $12.61/boe for the third quarter. We realized a record low third quarter Station 2 benchmark price not observed in over two decades as attributable to temporary third party pipeline restrictions which are causing an increase in the overall pressure on the BC system and a surplus of natural gas at Station 2. During the third quarter of 2017, we sold over 70% of our natural gas production at Station 2; and approximately 28% at the comparably higher Chicago City Gate benchmark. We realized a recovery of royalties during the third quarter of $0.52/boe due to BC Government royalty grants and a gas cost allowance adjustment. Our net production expense of $12.32/boe during the third quarter decreased from the same period of 2016, despite significantly lower volumes, primarily due to the divestiture of higher cost properties and the signing of a new BC gas handling agreement late in the third quarter of 2016. However, our net production expense was higher than our expectations due in part to lower production volumes relative to our fixed operating costs. We expect our on-going operations to incur production costs under $10/boe once production volumes from our most recent 2017 four well drilling campaign are brought on-stream at full capacity and subject to our ability to maintain our production volumes.

Our adjusted funds from operations for third quarter of 2017 of $0.6 million decreased from $1.9 million during the third quarter of 2016, as realized gains on commodity price contracts and a lower cash-based cost structure for our Montney focused operations were more than offset by lower realized natural gas pricing and restricted production volumes. Despite historically low Station 2 benchmark pricing and restricted production volumes, our third quarter adjusted funds from operations is the fifth consecutive quarter we have reported positive adjusted funds flow which corresponds to when we started our transition to a pure Montney play.

We reported a net loss for the third quarter of 2017 of $3.9 million compared to a net loss of $35.9 million during the same quarter of 2016. This improvement reflects a lower cost structure associated with our transition to a pure Montney play in addition to a $1.7 million gain on commodity price contracts. The comparative quarter of 2016 was also impacted by net losses from our previous subsidiary's operations whose shares were included in the Share Distribution. These net losses included $52.0 million of impairment charged against the subsidiary's assets but as partially offset by $14.2 million of net losses attributable to the non-controlling interest.

Third Quarter 2017 Operational Results

During the third quarter, we successfully completed and tied-in our four (3.63 net) horizontal Montney gas wells at Birley/Umbach (the a-81-F, b-90-G, 02/d-5-K and b-14-K wells). These wells were drilled during the second quarter of 2017 with various downhole locations on our D-93-F pad. On average, each well cost $4.24 million gross to drill and complete. The higher average total cost per well incurred on our most recent drilling program, compared to the previous 2016 three (2.64 net) well program, resulted from each well, on average, having 200 metre longer lateral lengths and eight additional completion stages. These four (3.63 net) new wells had comparable drilling costs per metre of lateral and a 19% reduction in completion costs per stage.

Also included in our year to date capital expenditures is $4.7 million for the expansion of our Birley/Umbach facility to 50 mmcf/d. We budgeted $10 million net for the total cost of this expansion in our capital program. Two (1.63 net) of the four (3.63 net) most recently drilled, completed and equipped Birley/Umbach wells are currently on restricted production as our existing 25 mmcf/d facility is producing at maximum capacity. On commissioning of this facility's expanded capacity to 50 mmcf/d (net 41.76 mmcf/d) expected during the fourth quarter of 2017, these restrictions will be released and our remaining two (2.00 net) standing wells are expected to be brought on-stream bringing our exit production to our 2017 revised guidance of 6,300 - 6,500 boe/d.

Gross test result and production from our Birley/Umbach property is as follows:

 Well                Working      Lateral         Frac'd         Flow         24 Hour Test               Final 24 Hour   Final 24 Hour          Final 24 Hour          IP30 (mcf/d) IP60 (mcf/d) IP90 (mcf/d)
                     Interest (%) Length (metres) Stages (gross) Time (hours) Rate End Date (MM/DD/YYYY) Average Test    Average Test           Average Test
                                                                                                         Total Gas Rates Total Condensate Rates Total Production Rates
                                                                                                         (mcf/d)         (bbl/d)                (boe/d)
 00/A-060 K/094-H-03 74.55        1,204           18             154          3/9/2014                   5,276           284                    1,163                  3,726        3,754        3,923
 00/B-071-F/094-H-03 74.55        1,539           23             211          10/4/2014                  8,870           57                     1,536                  4,489        4,375        4,348
 00/A-073-L/094-H-03 74.55        1,192           18             252          2/16/2015                  3,827           87                     725                    3,712        3,417        3,459
 00/C-037-K/094-H-03 100.00       1,210           18             145          9/23/2015                  5,281           260                    1,140                  4,228        4,094        3,851
 00/B-072-F/094-H-03 74.55        1,228           18             69           9/24/2015                  3,908           118                    770                    3,991        4,104        4,227
 00/B-004-K/094-H-03 100.00       1,197           16             119          9/24/2015                  4,127           71                     759                    3,364        3,082        2,921
 00/A-071-F/094-H-03 74.55        1,457           24             113          2/8/2017                   7,319           60                     1,280                  3,271        3,433        3,344
 00/D-095-F/094-H-03 98.20        1,430           24             197          2/14/2017                  6,756           75                     1,201                  3,404        3,554        3,454
 00/C-095-F/094-H-03 89.20        1,437           24             98           2/15/2017                  8,202           201                    1,568                  2,957        2,665        2,494
 00/A-081-F/094-H-03 82.44        1,795           35             165          9/4/2017                   8,719           343                    1,796                  3,819        N/A          N/A
 00/B-090-G/094-H-03 80.54        1,798           35             83           9/14/2017                  11,150          401                    2,259                  3,841        N/A          N/A
 02/D-005-K/094-H-03 100.00       1,541           30             77           9/13/2017                  7,663           275                    1,552                  N/A          N/A          N/A
 00/B-014-K/094-H-03 100.00       1,537           30             138          9/7/2017                   7,461           197                    1,441                  N/A          N/A          N/A

-- 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. Please see "Initial Productions Rates" under the Reader Advisory section of this news release

-- IP30 production for well a-81-F is for 28 days.

Increased Credit Facility

Subsequent to September 30, 2017, our credit facility was amended to increase the availability to $18.0 million from its previous $8.0 million, with the next semi-annual review scheduled for May 31, 2018. This availability increase was secured upon submitting to the lender the test results from our recently drilled and completed wells. We remain undrawn on this facility and exited the third quarter of 2017 with a net surplus of $3.6 million.

This amended credit facility provides us with financial flexibility as we assess our capital program for the coming year. We continue to be well positioned to advance the development of our existing core assets at Birley/Umbach at a practical pace given the current economic environment.

Financial Commodity Price Contracts

We use financial commodity price contracts to support our capital investment and growth by providing more certainty regarding our adjusted funds from operations and balance sheet management and also when required to comply with our credit facility covenants. Our current financial commodity price contracts in place are as follows:

Indexed Price  Notional Volumes Company's Received Price Remaining Contractual Term
AECO           7,500 GJ/d       $3.205/GJ                October 1, 2017 to December 31, 2017
AECO           4,000 GJ/d       $2.50/GJ                 October 1, 2017 to October 31, 2017

Outlook

We continue to execute on our $40 million 2017 capital program and remain excited about the growth it will provide. As we implement this capital program we will continue to closely monitor our balance sheet and commodity prices.

We have made great strides over the past 12 months to improve our cost structure, including completing the Share Distribution and executing a new gas handling agreement in BC. On a per boe basis, for fourth quarter of 2017, our net production expense is expected to approximate $10/boe. As we begin to increase our production at Birley/Umbach, our cost structure and profitability should significantly improve.

We forecasted the McMahon Plant outages during the second quarter of 2017, resulting in us achieving production guidance for the quarter. However, the McMahon Plant turnaround unexpectedly continued in July. Additionally, high pipeline pressure and further third party restrictions caused restricted flow rates in our August production. As a result of this lower than expected production, in addition to historically low natural gas benchmark prices during the third quarter, we are issuing the following 2017 revised guidance:

($ millions, except boe/d)                  Previous 2017 2017 Revised
                                            Guidance      Guidance
Average production (boe/d)                  4,200 - 4,300 3,600 - 3,700
Exit production (boe/d)                     6,300 - 6,500 6,300 - 6,500
Capital expenditures                        $      40     $    40
Net surplus (debt) as at December 31, 2017  $      2      $    (2.7)

-- Previous 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.

-- Revised 2017 guidance assumptions: AECO natural gas price $2.15/mmbtu, Station 2 natural gas price $1.79/mmbtu and Chicago Alliance natural gas price $2.59/mmbtu.

-- Exit production may be negatively impacted should we choose to voluntarily shut-in production in the event of low commodity prices.

-- Includes decommissioning obligation expenditures and capitalized general and administrative costs.

We are currently assessing our 2018 capital program in order to remain prudent in how we deploy our capital. We anticipate releasing our 2018 capital budget around mid-January 2018.

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.

For further information please contact:
Walter Vrataric                         Jason Dranchuk
President and Chief Executive Officer   Vice President, Finance and Chief Financial Officer
Chinook Energy Inc.                     Chinook Energy Inc.
Telephone: (403) 261-6883               Telephone: (403) 261-6883
Website: www.chinookenergyinc.com

Reader Advisory

Abbreviations

Oil and Natural Gas Liquids                                          Natural Gas
bbl       barrel                                                     mcf                                             thousand cubic feet
bbls      barrels                                                    mcf/d                                           thousand cubic feet per day
bbls/d    barrels per day                                            GJ                                              gigajoules
                                                                     GJ/d                                            gigajoules per day
Other
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

Forward-Looking Statements

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: the expected timing of our Birley/Umbach facility capacity expansion to 50 mmcf/d and the consequent release of the flow restrictions and on-stream timing of our four most recent Birley/Umbach wells, the expected decrease in our production costs under $10/boe once production volumes from our most recent 2017 four well drilling campaign are brought on-stream at fully capacity and subject to our ability to maintain our production volumes, the amount of our 2017 capital program, future exploration and development activities and the timing thereof and how we intend to manage our company, our revised guidance regarding average and ending production for 2017, capital expenditures for 2017 and net surplus (debt) at December 31, 2017 set forth under the heading "Outlook" as well as when we anticipate releasing our 2018 capital budget.

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.

Operating Netback

The reader is cautioned that this news release contains the term operating netback, which is not a recognized measure under IFRS and is calculated as a period's sales of petroleum and natural gas, net of realized gains or losses on commodity price contracts, royalties and net production expenses, divided by the period's sales volumes. We use this non-GAAP measure to assist us in understanding our production profitability relative to current and fixed commodity prices and it provides an analytical tool to benchmark changes in field 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.

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.

Adjusted Funds (Outflow) from Operations

The reader is cautioned that this news release contains the term adjusted 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, provision expenditures related to operations and severance/transaction costs. We believe that adjusted funds (outflow) from operations is a key measure to assess our ability to finance capital expenditures and when debt is drawn, debt repayments. Adjusted 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. Adjustments to cash flow from operations are for changes in non-cash operating working capital which are expected to reverse and for those costs that are not directly caused by lifting production volumes.

Net Surplus (Debt)

The reader is cautioned that this news release contains the term net surplus (debt), 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, deferred customer obligations and provisions. We use net surplus (debt) to assist us in understanding our liquidity at specific points in time. We exclude the current portion of provisions and the deferred customer obligation as they are not financial instruments. Mark-to-market derivative contracts and assets and liabilities held for sale are excluded as they are unrealized.

Future Oriented Financial Information

This news release, in particular the information in respect of the anticipated capital expenditures, operating costs per boe, net production expense per boe, G&A per boe and net surplus (debt) 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.

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.

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