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 November 3, 2015 - 6:01 PM EST
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Contango Announces Third Quarter 2015 Financial Results and Provides Operations Update

Contango Oil & Gas Company (NYSE MKT: MCF) (“Contango”) announced today its financial results for the three months ended September 30, 2015 and provided an operational update.

Third Quarter 2015 Summary

  • Production of 8.4 Bcfe for the quarter (90.9 Mmcfed), within guidance.
  • 24% reduction in recurring direct lease operating expenses for the quarter (i.e. excluding workovers), 15% decrease in per unit costs.
  • 20% reduction in recurring cash G&A costs for the quarter.
  • Adjusted EBITDAX of $20.7 million for the quarter.
  • Two wells in progress to further delineate our June 2015 discovery in the Muddy Sandstone formation in Weston County, Wyoming.

Management Commentary

Allan D. Keel, the Company’s President and Chief Executive Officer, said, “We continued to pursue a very conservative strategy during the third quarter due to the challenging commodity price environment. We limited our capital program to completing wells in process at the end of the second quarter and the drilling of strategic wells in our Muddy Sandstone play in Wyoming. That strategy allowed us to keep our debt level relatively flat and preserve our balance sheet to potentially capitalize on acquisition opportunities that may surface in this environment. We also continue to find ways to cut costs in the field, and implemented a meaningful and painful reduction in force in our corporate office in August 2015. We believe that it is important for us to remain conservative, i.e. limit capital expenditures, reduce costs and focus on maintaining our financial flexibility, during this period of commodity price uncertainty.”

Summary Financial Results for the Quarter Ended September 30, 2015

Net loss for the three months ended September 30, 2015 was $185.7 million, or $9.79 per basic and diluted share, compared to net income of $3.7 million, or $0.19 per basic and diluted share, for the prior year quarter. Impacting our earnings this quarter was a $235.1 million pre-tax, non-cash impairment mandated by U.S. GAAP as a result of the impact of the decline in commodity prices on the value of the Company’s reserve base. Other factors contributing to the decrease in net income period over period were the impact of lower commodity prices on our revenue stream and lower production resulting from our strategically reduced capital drilling program. Offsetting the impact of these items, in part, were decreases in operating expenses and cash G&A costs compared with the 2014 third quarter. Included in the prior year quarter results was a $5.2 million credit in exploration expense for an adjustment to estimated final costs for our unsuccessful Ship Shoal 255 exploratory well drilled in the second quarter of 2014. Average weighted shares outstanding were approximately 19.0 million for the current quarter and 19.1 million for the prior year quarter.

The Company reported Adjusted EBITDAX, as defined below, of approximately $20.7 million for the three months ended September 30, 2015, compared to $47.7 million for the same period last year, a decrease mainly attributable to the decrease in revenues, partially offset by a decrease in lease operating costs and cash G&A, and an increase in other income.

Revenues for the three months ended September 30, 2015 were $29.0 million compared to $67.6 million for the same period last year, a decrease attributable to lower commodity prices and lower production resulting from our decision to reduce our capital drilling program in the latter half of 2014 and in 2015 during the dramatic decline in commodity prices. Revenues for the prior year quarter were negatively impacted by an estimated $12.1 million related to the shut-in of our Eugene Island 11 platform for compressor installation.

Production for the three months ended September 30, 2015 was approximately 8.4 Bcfe, or 90.9 Mmcfed, less than the 9.4 Bcfe, or 102.3 Mmcfed, for the same period last year, but within our previously provided guidance. As previously disclosed, due to the low and uncertain commodity price environment, we strategically reduced our capital activity level dramatically in the latter half of 2014 and in 2015 and focused on confirmation of our exploratory prospects. This approach emphasizes strategic confirmation of unproved plays and ultimate recovery and further delineation of new discoveries, rather than production growth. For the fourth quarter of 2015, we estimate our production will be between 85,000 – 90,000 Mcfed.

The weighted average equivalent sales price during the three months ended September 30, 2015 was $3.47 per Mcfe, compared to $7.17 per Mcfe for the same period last year. The decrease in the weighted average equivalent prices quarter over quarter was attributable to a 54% decrease in average oil and condensate prices, a 25% decline in natural gas prices, a 59% decrease in natural gas liquids prices, and a lower percentage of total production coming from crude oil and natural gas liquids.

Total operating expenses for the three months ended September 30, 2015 were approximately $9.0 million, or $1.08 per Mcfe, compared to $13.8 million, or $1.47 per Mcfe, for the same period last year. Included in total operating expenses are direct lease operating expenses (“LOE”), transportation and processing costs, workover expenses and production and ad valorem taxes.

Direct operating expenses (i.e. total operating expenses, excluding production and ad valorem taxes) for the three months ended September 30, 2015 were approximately $8.2 million, or $0.98 per Mcfe, which was below our previously provided guidance, compared to approximately $10.6 million, or $1.13 per Mcfe, for the same period last year. This improvement resulted from our ongoing efforts to reduce field costs during this challenging commodity price environment. Direct lease operating costs, exclusive of expense workovers, declined 24% period over period. We are pleased to have been able to reduce recurring costs in total, but it is notable that we were also able to reduce our per unit cost despite lower production and given that a large majority of field operating costs are essentially fixed costs.

Production and ad valorem tax expense for the three months ended September 30, 2015 was $0.8 million, or $0.10 per Mcfe, compared to $3.2 million, or $0.34 per Mcfe, for the same period last year, a decrease associated with lower revenues.

Exploration expense for the three months ended September 30, 2015 were $0.4 million, compared to a credit of $4.7 million for the same period last year. The prior year quarter included a $5.2 million credit related to a downward adjustment to estimated costs for our unsuccessful Ship Shoal 255 exploratory well drilled in the second quarter of 2014.

DD&A expenses for the three months ended September 30, 2015 were $38.4 million, or $4.59 per Mcfe, compared to $40.6 million, or $4.31 per Mcfe, for the same period last year. The higher overall per unit charge in 2015 is primarily a result of specific field rate increases associated with price-related year-end 2014 reserve revisions.

Impairment expenses for the three months ended September 30, 2015 included a $225.6 million impairment of proved properties related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated reserves compared to the carrying value of our properties on the balance sheet. Approximately $196.5 million of the total proved property impairment for the current quarter is attributable to the Madison/Grimes counties and Zavala/Dimmit/Karnes counties properties. No impairment of proved properties was recognized for the three months ended September 30, 2014.

Impairment expenses for the three months ended September 30, 2015 also included a $9.5 million impairment of certain unproved properties, including approximately $8.2 million related to amortization of unproved lease cost associated with our Elm Hill project in Fayette and Gonzales counties Texas. Impairment expense for the three months ended September 30, 2014 included a $6.7 million impairment of certain unproved prospects due to expiring leases and leases not likely to be drilled.

G&A expenses for the three months ended September 30, 2015 were $7.5 million, or $0.90 per Mcfe, compared to $6.8 million, or $0.72 per Mcfe, for the prior year quarter. Cash G&A expenses for the current and prior year quarters, i.e. exclusive of $2.4 million and $1.2 million, respectively, in non-cash stock compensation expense, were $5.1 million and $5.6 million, respectively, for the two quarters. Also included in cash G&A for the current quarter is approximately $600,000 in cash severance costs incurred in implementing a reduction in force in August 2015. The reduction in force (30% of the personnel count in our corporate office) is a major part of our ongoing cost cutting efforts necessitated by the current commodity price environment and related reduction in capital activity. For the fourth quarter of 2015, we have provided guidance of $4.5 million to $5.0 million for general and administrative expenses, exclusive of non-cash stock compensation.

Derivative Instruments

We have the following derivative contract in place for the remainder of the year:

               
Commodity Period Derivative Volume/Month Price/Unit (1)
 
Crude Oil Oct 2015 - Dec 2015 Collar 35,000 Bbls $55.00 - $65.15
 

(1) Commodity derivative based on NYMEX West Texas Intermediate crude oil prices.

 

Drilling Activity Update

Our drilling activity during the quarter ended September 30, 2015 was designed to keep our debt level flat and focus on delineating our Wyoming and Fayette County plays.

Muddy Sandstone - Weston County, Wyoming

In June 2015, we announced the discovery and successful completion of the Elliot #1H well (80% WI) in the Muddy Sandstone formation in Weston County, Wyoming (referred to as our North Cheyenne Project). Based on the encouraging results from this well, we spud two more wells in September 2015, the WC 45N-66W-35 1H and the WC 44N-66W-9 1H. Both wells are currently in various stages of drilling or completion. We have approximately 49,000 gross acres (35,000 net) in this area. Our 2016 drilling program for this area will be developed based on results of the wells in process and the commodity price environment. Approximately 200 to 300 Muddy horizontal well locations may be prospective on the acreage based on a drilling density of three to four wells per 640 acres. Additional prospective horizons in this area will be evaluated during the delineation phase with additional log and core data and could also add significantly to the total number of potential horizontal locations.

Elm Hill Project – Fayette and Gonzales Counties, Texas

In 2014, we acquired approximately 25,000 net acres primarily in Fayette and Gonzales counties, Texas (referred to as our Elm Hill Project), to pursue horizontal drilling in this multiple formation area. As of September 30, 2015, we had drilled and completed five gross (2.5 net) wells in the Navarro, Buda and Austin Chalk formations, and were producing from two of these wells; the other three wells were not commercial successes. We have recovered four whole cores to further evaluate six hydrocarbon bearing formations that we believe might have potential for development. We and our partner are discussing future plans for this area.

2015 Capital Program & Liquidity

Capital expenditures incurred for the three months ended September 30, 2015 were $7.9 million, including $1.2 million for final testing on two non-commercial wells in our Elm Hill Project in Fayette and Gonzales counties; $3.7 million on the two delineation wells in Weston County Wyoming; and $4.3 million for the acquisition of leases and other rights in these and other areas. We currently anticipate that our total capital expenditure program for 2015 will be approximately $58 million, which will be funded primarily from internally generated cash flow. We are in the process of developing our capital program for 2016, and similar to our strategy for 2015, that program will likely be focused more on strategic projects and delineation of recent success, with the goal of maintaining or reducing debt and/or working capital obligations in this low commodity price environment. We will continually reassess that strategy during the year based on forecasted commodity prices and service costs.

As of September 30, 2015, we had approximately $114.6 million of debt outstanding under our credit facility compared to approximately $63.4 million at the end of 2014, an increase due to having incurred the vast majority of our 2015 capital expenditures during the first half of the year, as planned, and the reduction in the beginning of the year working capital deficit associated with a more active capex program. We currently project that our debt level at year-end 2015 will be similar to our current level with a simultaneous decrease expected in overall current trade payables and accruals.

Our borrowing base was redetermined at $225 million effective May 7, 2015 with the next regular scheduled redetermination expected to be completed in mid-November. Due to the lower commodity price environment and the reduced capital program, we expect some reduction in the borrowing base from that level. Based on preliminary discussions with our agent bank, and their borrowing base recommendation currently being considered by the remaining lenders under the facility, we expect that the proposed borrowing base will not impact our liquidity position in a material adverse way.

Selected Financial and Operating Data

The following tables reflect certain comparative financial and operating data as of, and for the three and nine month periods ended, September 30, 2015 and 2014:

                         
Three Months Ended Nine Months Ended
September 30, September 30,
2015 2014 % 2015 2014 %
Offshore Volumes Sold:
Oil and condensate (Mbbls) 42 57 -26 % 149 211 -29 %
Natural gas (Mmcf) 4,191 4,039 4 % 13,117 14,302 -8 %
Natural gas liquids (Mbbls)   133   121 10 %   392   439 -11 %
Natural gas equivalents (Mmcfe) 5,244 5,104 3 % 16,367 18,201 -10 %
 
Onshore Volumes Sold:
Oil and condensate (Mbbls) 171 335 -49 % 581 919 -37 %
Natural gas (Mmcf) 1,389 1,598 -13 % 4,043 4,896 -17 %
Natural gas liquids (Mbbls)   117   117 0 %   348   323 8 %
Natural gas equivalents (Mmcfe) 3,115 4,312 -28 % 9,615 12,352 -22 %
 
Total Volumes Sold:
Oil and condensate (Mbbls) 213 392 -46 % 730 1,130 -35 %
Natural gas (Mmcf) 5,580 5,637 -1 % 17,160 19,198 -11 %
Natural gas liquids (Mbbls)   250   238 5 %   740   762 -3 %
Natural gas equivalents (Mmcfe) 8,359 9,416 -11 % 25,982 30,553 -15 %
 
Daily Sales Volumes:
Oil and condensate (Mbbls) 2.3 4.3 -46 % 2.7 4.1 -35 %
Natural gas (Mmcf) 60.7 61.3 -1 % 62.9 70.3 -11 %
Natural gas liquids (Mbbls)   2.7   2.6 5 %   2.7   2.8 -3 %
Natural gas equivalents (Mmcfe) 90.9 102.3 -11 % 95.2 111.9 -15 %
 
Average sales prices:
Oil and condensate (per Bbl) $ 44.56 $ 96.05 -54 % $ 49.14 $ 98.32 -50 %
Natural gas (per Mcf) $ 2.87 $ 3.85 -25 % $ 2.80 $ 4.56 -39 %
Natural gas liquids (per Bbl) $ 14.05 $ 34.55 -59 % $ 14.86 $ 36.17 -59 %
Total (per Mcfe) $ 3.47 $ 7.17 -52 % $ 3.66 $ 7.40 -51 %
           
Three Months Ended Nine Months Ended
September 30, September 30,
2015     2014     % 2015     2014     %
Offshore Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 0.69 $ 0.83 -17 % $ 0.64 $ 0.57 12 %
Production and ad valorem taxes $ 0.07 $ 0.11 -36 % $ 0.08 $ 0.10 -20 %
 
Onshore Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 1.47 $ 1.48 -1 % $ 1.63 $ 1.36 20 %
Production and ad valorem taxes $ 0.14 $ 0.62 -77 % $ 0.25 $ 0.61 -59 %
 
Total Selected Costs ($ per Mcfe):
Lease operating expenses (1) $ 0.98 $ 1.13 -13 % $ 1.01 $ 0.89 13 %
Production and ad valorem taxes $ 0.10 $ 0.34 -71 % $ 0.14 $ 0.30 -53 %
General and administrative expense (cash) $ 0.61 $ 0.60 2 % $ 0.68 $ 0.76 -11 %
Interest expense $ 0.09 $ 0.07 29 % $ 0.09 $ 0.07 29 %
 
Adjusted EBITDAX (2) (thousands) $ 20,701 $ 47,694 $ 54,646 $ 162,467
 
Weighted Average Shares Outstanding (thousands)
Basic 18,966 19,077 18,948 19,074
Diluted 18,966 19,122 18,948 19,074
 

(1) LOE includes transportation and workover expenses.

(2) Adjusted EBITDAX is a non-GAAP financial measure. See below for a reconciliation to net income (loss).

     
September 30, December 31,
2015 2014

ASSETS

(in thousands)
Cash and cash equivalents $

-

$

-

Accounts receivable, net 21,335 25,309
Other current assets 8,679 5,731
Net property and equipment 444,775 748,623
Investments in affiliates and other non-current assets   62,583   63,752
 
TOTAL ASSETS $ 537,372 $ 843,415
 

LIABILITIES AND SHAREHOLDERS' EQUITY

Accounts payable and accrued liabilities 47,445 92,892
Other current liabilities 6,417 4,123
Long-term debt 114,569 63,359
Deferred tax liability

-

93,952
Asset retirement obligations 20,314 21,623
Total shareholders’ equity   348,627   567,466
 
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY $ 537,372 $ 843,415
           
 
Three Months Ended Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
(in thousands)
REVENUES
Oil and condensate sales $ 9,500 $ 37,662 $ 35,882 $ 111,102
Natural gas sales 16,020 21,676 48,130 87,547
Natural gas liquids sales   3,515     8,214     11,004     27,579  
Total revenues   29,035     67,552     95,016     226,228  
 
EXPENSES
Operating expenses 9,036 13,797 29,919 36,426
Exploration expenses 407 (4,713 ) 11,814 33,071
Depreciation, depletion and amortization 38,386 40,550 112,271 114,853
Impairment and abandonment of oil and gas properties 235,150 6,693 237,667 23,259
General and administrative expenses   7,504     6,821     22,683     26,485  
Total expenses   290,483     63,148     414,354     234,094  
 
OTHER INCOME (EXPENSE)
Gain (loss) from investment in affiliates (net of income taxes) (375 ) 1,287 (562 ) 4,387
Interest expense (785 ) (672 ) (2,315 ) (2,077 )
Loss on derivatives, net 2,011 1,734 2,001 (1,488 )
Other income (expense)   4,288     48     5,278     (148 )
Total other income (expense)   5,139     2,397     4,402     674  
 
NET INCOME (LOSS) BEFORE INCOME TAXES   (256,309 )   6,801     (314,936 )   (7,192 )
 
Income tax benefit (provision)   70,624     (3,137 )   91,159     5,244  
 
NET INCOME (LOSS) $ (185,685 ) $ 3,664   $ (223,777 ) $ (1,948 )
 

Non-GAAP Financial Measures

EBITDAX represents net income (loss) before interest expense, taxes, and depreciation, depletion and amortization, and oil & gas expenses. Adjusted EBITDAX represents EBITDAX as further adjusted to reflect the items set forth in the table below, all of which will be required in determining our compliance with financial covenants under our credit facility with the Royal Bank of Canada and other lenders (the “RBC Credit Facility”).

We have included EBITDAX and Adjusted EBITDAX in this release to provide investors with a supplemental measure of our operating performance and information about the calculation of some of the financial covenants that are contained in our credit agreements. We believe EBITDAX is an important supplemental measure of operating performance because it eliminates items that have less bearing on our operating performance and so highlights trends in our core business that may not otherwise be apparent when relying solely on GAAP financial measures. We also believe that securities analysts, investors and other interested parties frequently use EBITDAX in the evaluation of companies, many of which present EBITDAX when reporting their results. Adjusted EBITDAX is a material component of the covenants that are imposed on us by our credit agreements. We are subject to financial covenant ratios that are calculated by reference to Adjusted EBITDAX. Non-compliance with the financial covenants contained in these credit agreements could result in a default, an acceleration in the repayment of amounts outstanding and a termination of lending commitments. Our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, also use EBITDAX and Adjusted EBITDAX to assess:

  • the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
  • the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;
  • our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and
  • the feasibility of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX and Adjusted EBITDAX are not presentations made in accordance with generally accepted accounting principles, or GAAP. As discussed above, we believe that the presentation of EBITDAX and Adjusted EBITDAX in this release is appropriate. However, when evaluating our results, you should not consider EBITDAX and Adjusted EBITDAX in isolation of, or as a substitute for, measures of our financial performance as determined in accordance with GAAP, such as net income (loss). EBITDAX and Adjusted EBITDAX have material limitations as performance measures because they exclude items that are necessary elements of our costs and operations. Because other companies may calculate EBITDAX and Adjusted EBITDAX differently than we do, EBITDAX may not be, and Adjusted EBITDAX as presented in this release is not, comparable to similarly-titled measures reported by other companies.

The following table reconciles net loss to EBITDAX and Adjusted EBITDAX for the periods presented:

           
Three Months Ended Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
(in thousands)
Net income (loss) $ (185,685 ) $ 3,664 $ (223,777 ) $ (1,948 )
Interest expense 785 672 2,315 2,077
Income tax provision (benefit) (70,624 ) 3,137 (91,159 ) (5,244 )
Depreciation, depletion and amortization 38,386 40,550 112,271 114,853
Exploration expenses   407     (4,713 )   11,814     33,071  
EBITDAX $ (216,731 ) $ 43,310   $ (188,536 ) $ 142,809  
 
Unrealized gain on derivative instruments $ (1,009 ) $ (1,963 ) $ (999 ) $ (1,494 )
Non-cash stock-based compensation charges 2,430 1,217 5,008 3,333
Impairment of oil and gas properties 235,112 6,417 237,656 22,010
Loss (gain) on sale of assets and investment in affiliates   899     (1,287 )   1,517     (4,191 )
Adjusted EBITDAX $ 20,701   $ 47,694   $ 54,646   $ 162,467  
 

Guidance for Fourth Quarter 2015

The Company is providing the following guidance for the fourth calendar quarter of 2015.

       
Fourth quarter 2015 production 85,000 – 90,000 Mcfe per day
 
LOE (including transportation and workovers) $7.8 million - $8.3 million
 
Production and ad valorem taxes 4.0%
(% of Revenue)
 
Cash G&A $4.5 million - $5.0 million
 
DD&A rate $2.50 - $2.75
 

Teleconference Call

Contango management will hold a conference call to discuss the information described in this press release on Wednesday, November 4, 2015 at 9:30am CST. Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-800-756-4697, (International 1-913-312-0398) and entering the following participation code: 824286. A replay of the call will be available from Wednesday, November 4, 2015 at 12:30pm CST through Wednesday, November 11, 2015 at 12:30pm CST by dialing toll free 1-888-203-1112, (International 1-719-457-0820) and asking for replay ID code 824286.

Contango Oil & Gas Company is a Houston, Texas based, independent energy company engaged in the acquisition, exploration, development, exploitation and production of crude oil and natural gas properties offshore in the shallow waters of the Gulf of Mexico and in the onshore Texas Gulf Coast and Rocky Mountain regions of the United States. Additional information is available on the Company's website at http://contango.com.

This press release contains forward-looking statements regarding Contango that are intended to be covered by the safe harbor "forward-looking statements" provided by the Private Securities Litigation Reform Act of 1995, based on Contango’s current expectations and includes statements regarding acquisitions and divestitures, estimates of future production, future results of operations, quality and nature of the asset base, the assumptions upon which estimates are based and other expectations, beliefs, plans, objectives, assumptions, strategies or statements about future events or performance (often, but not always, using words such as "expects", “projects”, "anticipates", "plans", "estimates", "potential", "possible", "probable", or "intends", or stating that certain actions, events or results "may", "will", "should", or "could" be taken, occur or be achieved). Statements concerning oil and gas reserves also may be deemed to be forward looking statements in that they reflect estimates based on certain assumptions that the resources involved can be economically exploited. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those, reflected in the statements. These risks include, but are not limited to: the risks of the oil and gas industry (for example, operational risks in exploring for, developing and producing crude oil and natural gas; risks and uncertainties involving geology of oil and gas deposits; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; health, safety and environmental risks and risks related to weather such as hurricanes and other natural disasters); uncertainties as to the availability and cost of financing; fluctuations in oil and gas prices; risks associated with derivative positions; inability to realize expected value from acquisitions, inability of our management team to execute its plans to meet its goals, shortages of drilling equipment, oil field personnel and services, unavailability of gathering systems, pipelines and processing facilities and the possibility that government policies may change or governmental approvals may be delayed or withheld. Additional information on these and other factors which could affect Contango’s operations or financial results are included in Contango’s other reports on file with the Securities and Exchange Commission. Investors are cautioned that any forward-looking statements are not guarantees of future performance and actual results or developments may differ materially from the projections in the forward-looking statements. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Contango does not assume any obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.

Contango Oil & Gas Company
E. Joseph Grady, 713-236-7400
Senior Vice President and Chief Financial Officer
or
Sergio Castro, 713-236-7400
Vice President and Treasurer


Source: Business Wire (November 3, 2015 - 6:01 PM EST)

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