SOURCE: Venoco, Inc.

Venoco, Inc.

November 13, 2013 07:00 ET

Venoco, Inc. Announces 3rd Quarter 2013 Financial and Operational Results

Successful Well Drilled to Probable Location at Coal Oil Point; Repayment of $150 Million 11.50% Senior Notes

DENVER, CO--(Marketwired - Nov 13, 2013) - Venoco, Inc. ("Venoco" or the "company") today reported financial and operational results for the third quarter of 2013. The company reported a net loss of $2.9 million for the quarter on total revenues of $80.9 million.

Adjusted Earnings, which adjusts for unrealized derivative gains and losses and certain other items, were $22.8 million for the quarter, up from $15.1 million in the second quarter of 2013. Adjusted EBITDA was $51.1 million in the third quarter of 2013, compared to $48.6 million in the second quarter. Please see the end of this release for definitions of Adjusted Earnings and Adjusted EBITDA and a reconciliation of those measures to net income/loss.

Highlights include the following:

  • Production of 831 thousand barrels of oil equivalent (MBOE) for the quarter, or 9,036 BOE per day (BOE/d).

  • Successful completion of a well to a probable location in a separate geologic structure, Coal Oil Point, northeast of Platform Holly in the South Ellwood field.

  • Repayment of $150 million of 11.50% senior unsecured notes as a result of a capital contribution from Denver Parent Corporation.

During the third quarter, Venoco successfully completed a well to a probable location in a separate geologic structure, known as Coal Oil Point, located to the northeast of Platform Holly in the South Ellwood field. The Coal Oil Point structure has two separate fault blocks. The well path of the probable well resulted in the intersection of the northern fault block in only the lowermost Monterey zone (M7), whereas the southern fault block was intersected in only the uppermost Monterey zone (M1). The well was completed in two sections, the first of which was in the northern fault block and was wet and the second of which was in the southern fault block and was successful. The well was on production for approximately 15 days prior to the annual maintenance shutdown at Platform Holly and produced at an average rate of approximately 220 barrels of oil per day over that period. Subsequent to the shutdown, production from the well declined to an average rate of approximately 100 barrels of oil per day.

"We are very encouraged by the positive results from the well we drilled to Coal Oil Point. Since the second section of the well intersected and was completed in the uppermost interval of seven Monterey zones, which is typically not the most productive zone, we believe the success of this well strongly indicates that additional opportunities exist for further development of the fault block," stated Ed O'Donnell, Venoco's CEO. "We will continue to analyze the results from this well to help us better understand those opportunities and aid us in constructing our development plan for the area." 

Repayment of 11.50% Senior Notes

On August 6, 2013, Venoco initiated a tender offer for the purchase of the outstanding principal balance of $150 million of its 11.50% senior notes. Notes representing $149.5 million of the outstanding principal balance were tendered and redeemed by early September. The remaining $0.5 million of notes were called for redemption in early October and repaid on October 11, 2013.

On August 15, 2013, Denver Parent Corporation ("DPC"), Venoco's sole stockholder, completed an offering of $255 million of senior PIK toggle notes due in 2018. If paid in cash, the notes bear interest at an annual rate of 12.25%, but if paid in kind, the notes bear interest at an annual rate of 13.00%. Proceeds from the offering were used to repay existing indebtedness at DPC and to make a capital contribution to Venoco to fund the tender offer for Venoco's 11.50% senior notes.

Third Quarter 2013 Production

Production in the third quarter of 2013 was 9,036 BOE/d compared to 9,852 BOE/d in the second quarter of 2013 and 9,505 BOE/d in the third quarter of 2012, pro forma for the sale of the company's Sacramento Basin assets. Daily oil production in the third quarter of 2013 of 8,543 Bbls/d was down 9% compared to 9,363 Bbls/d in the second quarter of 2013. The decrease in daily production compared to the second quarter is due primarily to lower production from the South Ellwood field (discussed below), as well as lower production from the Sockeye and West Montalvo fields due to mechanical issues that resulted in well down time during quarter. Production from the Dos Cuadras field was also lower during the quarter as a result of two weeks of down time for repair work on one of the three platforms in the field.

As previously disclosed, production results from the company's South Ellwood field indicate that there may be communication between some of the recently drilled wells in the field.

"Late in the quarter, prior to the annual maintenance shutdown at Platform Holly, we inserted pressure gauges in several of the wells at South Ellwood to help us evaluate the potential communication issues in the field. Following the completion of the annual maintenance shutdown, we removed the gauges and sent the data to an outside party for analysis and interpretation," stated Mr. O'Donnell. "In addition, we have recently experienced some gas handling capacity issues related to the associated gas produced from a few of the recently drilled wells at South Ellwood. The capacity issues have forced us to curtail production from one of the high-rate wells in the field, which has negatively impacted our daily oil rate. We are currently working to identify corrective actions that will allow us to produce the South Ellwood field at full capacity."

The following table details the company's daily production by region (BOE(1)/d):

       
  Quarter Ended   Nine Months Ended
Region 9/30/12   6/30/13   9/30/13   9/30/12   9/30/13
Southern California 9,505   9,852   9,036   8,306   9,460
Sacramento Basin(2) 8,394   -   -   9,164   373
  Total 17,899   9,852   9,036   17,470   9,833
(1) Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
(2) Nine months ended 2013 production from the Sacramento Basin relates to properties that were held in escrow pending the receipt of consents regarding the transfer of ownership. As of May 1, 2013, title to all properties included in the sale on December 31, 2012 had been transferred to the purchaser.
   

"While production from our South Ellwood field remains a significant portion of our overall company production, the recent performance from some of our lease line wells at the South Ellwood field, along with lower production from Sockeye and West Montalvo due to mechanical issues in the quarter, has required us to reassess our expected production for the year. As a result, we have revised our production guidance to 9,400 to 9,600 BOE per day for full year 2013," said Mr. O'Donnell.

Third Quarter 2013 Costs

Venoco's third quarter 2013 lease operating expenses of $21.99 per BOE were up from $19.97 per BOE in the second quarter of 2013 and $13.90 per BOE in the third quarter of 2012. Pro forma for the sale of the Sacramento Basin properties, third quarter 2013 LOE was up from $21.25 per BOE in the third quarter of 2012.

Venoco's third quarter G&A costs, excluding going private related costs and non-cash share-based compensation, was $9.26 per BOE compared to $10.32 per BOE in the second quarter of 2013 and $5.59 per BOE in the third quarter of 2012. Excluding production from the Sacramento Basin properties, Venoco's per barrel G&A costs, excluding the costs outlined above, were $10.54 per BOE in the third quarter of 2012.

Venoco's third quarter property and production tax expense was $(0.5) million compared to $1.4 million in the second quarter of 2013 and $1.7 million in the third quarter of 2012 ($0.9 million excluding taxes related to the Sacramento Basin properties). The decrease in the third quarter of 2013 is due to revised estimates for supplemental property taxes related to the South Ellwood and West Montalvo fields.

The following table details the company's operating costs on a per BOE basis (BOE/d):

         
  Quarter Ended     Nine Months Ended
UNAUDITED (per BOE) 9/30/12   6/30/13   9/30/13     9/30/12   9/30/13
Lease Operating Expenses $ 13.90   $ 19.97   $ 21.99     $ 14.09   $ 20.39
Property and Production Taxes   1.01     1.57     (0.57 )     1.79     0.77
DD&A Expense   13.50     13.83     15.10       13.73     13.61
G&A Expense (1)   5.59     10.32     9.26       5.37     11.00
                               
(1) Net of amounts capitalized and excluding non-cash share-based compensation costs and costs related to the going-private transaction. See the end of this release for a reconciliation of G&A per BOE.
   

Third Quarter 2013 Capital Investment

Venoco's third quarter 2013 capital expenditures for exploration, development and other spending were $29 million, including $20 million for drilling and rework activities, $6 million for facilities, and the remaining $3 million for land, seismic and capitalized G&A. 

In the third quarter, the company spent $28 million or 97% of its capital expenditures on its Southern California legacy fields, a significant amount of which was incurred at the South Ellwood field. During the quarter, the company completed the 3242-15RD well in the South Ellwood field, which bottoms near the eastern boundary of the lease. After drilling the 3242-15RD well, Venoco returned to drilling the 3242-19 well, which was suspended earlier in the year. The 3242-19 well, as discussed above, targeted a probable location in a separate geologic structure, Coal Oil Point, northeast of Platform Holly in the South Ellwood field. The well was completed in two sections, the first of which was completed in early August and was tested for about 30 days. This section, which intersected only the lowermost Monterey zone (M7), produced a high volume of water with no measurable oil cut. The second section intersected only the uppermost Monterey interval (M1) out of seven potentially productive zones and was put on production in early September. The well produced an average of approximately 220 gross barrels of oil per day during the period that it was on production in September. Following the maintenance shutdown, production from this well has averaged approximately 100 gross barrels of oil per day. In addition to the drilling and completion activity during the quarter at the South Ellwood field, the company commenced the annual maintenance shutdown on September 29 and completed the shutdown by October 8. During the shutdown, the power cable to Platform Holly was successfully replaced with a new cable which is currently providing power to the platform.

At the West Montalvo field, during the quarter, the company completed one well which was spud in the second quarter and spud the second well for the year. In the fourth quarter, the company expects to complete the well spud in the third quarter and spud two additional wells. The 2013 drilling program at West Montalvo was delayed by about two months due to the unavailability of the drilling rig. 

In the third quarter of 2013, the company had relatively minimal onshore Monterey capital expenditures of $1 million or 3% of its total third quarter capital expenditures.

DPC Financial Statements

The indentures governing the senior PIK / toggle notes issued by DPC require DPC to file periodic reports with the SEC beginning with the quarter ended September 30, 2013. DPC and Venoco have filed a combined report on Form 10-Q for the quarter that includes information for both companies.

2013 Guidance

The company has revised 2013 guidance as summarized below:

         
    Original Guidance   Revised Guidance
Production:   10,000 - 10,500 BOE/d   9,400 - 9,600 BOE/d
Capital Budget:   $90 - $100 million   $90 - $95 million
Lease Operating Expenses:   $20.50 - $21.50 per BOE   $21.50 - $22.50 per BOE
General & Administrative Expenses (excluding non-cash charges related to share-based compensation):   $11.00 - $11.50 per BOE   $11.50 - $12.00 per BOE
Production & Property Taxes:   $1.80 - $2.20 per BOE   $1.00 - 1.50 per BOE
DD&A:   $12.50 - $13.50 per BOE   $13.00 - $14.00 per BOE
         

Earnings Conference Call

Venoco will host a conference call to discuss results Wednesday, November 13, 2013 at 11:00 a.m. Eastern time (9 a.m. Mountain). The conference call will be webcast and those wanting to listen may do so by using a link on the Investor Relations page of the company's website at http://www.venocoinc.com. Those wanting to participate in the Q & A portion can call (888) 679-8018 and use conference code 52304954. International participants can call (617) 213-4845 and use the same conference code.

A replay of the conference call will be available for one week by calling (888) 286-8010 or, for international callers, (617) 801-6888, and using passcode 39799178. The replay will also be available on the Venoco website for 30 days.

About the Company

Venoco is an independent energy company primarily engaged in the acquisition, exploitation and development of oil and natural gas properties primarily in California. Venoco operates three offshore platforms in the Santa Barbara Channel, has non-operated interests in three other platforms and operates several onshore properties in Southern California.

Forward-looking Statements

Statements made in this news release relating to Venoco's future production, expenses, capital expenditures and development projects, and all other statements except statements of historical fact, are forward-looking statements. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and the company's future performance are both subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the timing and extent of changes in oil and gas prices, the timing and results of drilling and other development activities, the availability and cost of obtaining drilling equipment and technical personnel, risks associated with the availability of acceptable transportation arrangements and the possibility of unanticipated operational problems, delays in completing production, treatment and transportation facilities, higher than expected production costs and other expenses, and pipeline curtailments by third parties. The company's exploration and development activities with respect to our projects are subject to numerous operating, geological and other risks and may not be successful. All forward-looking statements are made only as of the date hereof and the company undertakes no obligation to update any such statement. Further information on risks and uncertainties that may affect the company's operations and financial performance, and the forward-looking statements made herein, is available in the company's filings with the Securities and Exchange Commission, which are incorporated by this reference as though fully set forth herein.

References to reserve estimates other than proved are by their nature more uncertain than estimates of proved reserves, and are subject to substantially greater risk of not actually being realized by the company. Initial and test results from a well may not be indicative of the well's longer-term performance.

   
OIL AND NATURAL GAS PRODUCTION AND PRICES  
   
   
    Quarter Ended     Quarter Ended     Nine Months Ended  
UNAUDITED   6/30/13     9/30/13     % Change     9/30/12     9/30/13     % Change     9/30/12     9/30/13     % Change  
Production Volume:                                                                  
Oil (MBbls) (1)     852       786     -8 %     839       786     -6 %     2,172       2,449     13 %
Natural Gas (MMcf)     267       272     2 %     4,846       272     -94 %     15,688       1,412     -91 %
MBOE     897       831     -7 %     1,647       831     -50 %     4,787       2,684     -44 %
Daily Average Production Volume:                                                                  
Oil (Bbls/d)     9,363       8,543     -9 %     9,120       8,543     -6 %     7,927       8,971     13 %
Natural Gas (Mcf/d)     2,934       2,957     1 %     52,674       2,957     -94 %     57,255       5,172     -91 %
BOE/d     9,852       9,036     -8 %     17,899       9,036     -50 %     17,470       9,833     -44 %
Oil Price per Barrel Produced (in dollars):                                                                  
Realized price before hedging   $ 93.46     $ 99.16     6 %   $ 96.20     $ 99.16     3 %   $ 98.26     $ 97.36     -1 %
Realized hedging gain (loss)     (1.78 )     (5.42 )   204 %     (9.68 )     (5.42 )   -44 %     (8.34 )     (5.93 )   -29 %
Net realized price   $ 91.68     $ 93.74     2 %   $ 86.52     $ 93.74     8 %   $ 89.92     $ 91.43     2 %
Natural Gas Price per Mcf (in dollars):                                                                  
Realized price before hedging   $ 4.58     $ 4.19     -9 %   $ 2.86     $ 4.19     47 %   $ 2.67     $ 3.97     49 %
Realized hedging gain (loss)     -       -     0 %     0.11       -     -100 %     0.40       -     -100 %
Net realized price   $ 4.58     $ 4.19     -9 %   $ 2.97     $ 4.19     41 %   $ 3.07     $ 3.97     29 %
Expense per BOE (in dollars):                                                                  
Lease operating expenses   $ 19.97     $ 21.99     10 %   $ 13.90     $ 21.99     58 %   $ 14.09     $ 20.39     45 %
Production and property taxes   $ 1.57     $ (0.57 )   -136 %   $ 1.01     $ (0.57 )   -156 %   $ 1.79     $ 0.77     -57 %
Transportation expenses   $ 0.05     $ 0.06     20 %   $ 0.29     $ 0.06     -79 %   $ 1.08     $ 0.05     -95 %
Depreciation, depletion and amortization   $ 13.83     $ 15.10     9 %   $ 13.50     $ 15.10     12 %   $ 13.73     $ 13.61     -1 %
General and administrative (2)   $ 11.57     $ 6.45     -44 %   $ 7.18     $ 6.45     -10 %   $ 7.11     $ 11.44     61 %
Interest expense   $ 19.40     $ 18.86     -3 %   $ 10.02     $ 18.86     88 %   $ 10.05     $ 19.35     93 %
   
(1) Amounts shown are oil production volumes for offshore properties and sales volumes for onshore properties (differences between onshore production and sales volumes are minimal). Revenue accruals are adjusted for actual sales volumes since offshore oil inventories can vary significantly from month to month based on pipeline inventories, oil pipeline sales nominations, and prior to February 2012, the timing of barge deliveries and oil in tanks.
(2) Net of amounts capitalized.
   
   
   
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS  
   
   
    Quarter Ended     Quarter Ended     Nine Months Ended  
UNAUDITED (In thousands)   6/30/13     9/30/13     9/30/12     9/30/13     9/30/12     9/30/13  
REVENUES:                                                
Oil and natural gas sales   $ 81,449     $ 79,696     $ 95,377     $ 79,696     $ 259,701     $ 247,104  
Other     910       1,249       1,321       1,249       4,859       3,463  
Total revenues     82,359       80,945       96,698       80,945       264,560       250,567  
EXPENSES:                                                
Lease operating expense     17,914       18,274       22,899       18,274       67,442       54,719  
Property and production taxes     1,407       (472 )     1,671       (472 )     8,588       2,062  
Transportation expense     45       50       482       50       5,151       133  
Depletion, depreciation and amortization     12,406       12,551       22,240       12,551       65,707       36,529  
Accretion of asset retirement obligation     615       595       1,457       595       4,298       1,866  
General and administrative     10,375       5,358       11,822       5,358       34,052       30,708  
Total expenses     42,762       36,356       60,571       36,356       185,238       126,017  
Income from operations     39,597       44,589       36,127       44,589       79,322       124,550  
FINANCING COSTS AND OTHER:                                                
Interest expense     17,401       15,674       16,498       15,674       48,089       51,929  
Amortization of deferred loan costs     906       868       597       868       1,751       2,887  
Loss on extinguishment of debt     -       16,787       -       16,787       -       38,084  
Commodity derivative realized (gains) losses     5,132       4,261       7,597       4,261       (40,285 )     24,010  
Commodity derivative unrealized (gains) losses and amortization of derivative premiums     (25,083 )     9,910       41,492       9,910       113,216       (26,447 )
Total financing costs and other     (1,644 )     47,500       66,184       47,500       122,771       90,463  
Income (loss) before taxes     41,241       (2,911 )     (30,057 )     (2,911 )     (43,449 )     34,087  
Income tax provision (benefit)     -       -       -       -       -       -  
Net income (loss)   $ 41,241     $ (2,911 )   $ (30,057 )   $ (2,911 )   $ (43,449 )   $ 34,087  
   
   
   
CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION  
   
   
UNAUDITED ($ in thousands) 12/31/12     9/30/13  
ASSETS              
  Cash and cash equivalents $ 53,818     $ 16  
  Accounts receivable   108,356       26,171  
  Inventories   5,101       5,380  
  Other current assets   4,448       5,322  
  Commodity derivatives   153       1,346  
    Total current assets   171,876       38,235  
    Net property, plant and equipment   648,602       650,649  
    Total other assets   25,603       18,715  
TOTAL ASSETS $ 846,081     $ 707,599  
LIABILITIES AND STOCKHOLDERS' EQUITY              
  Accounts payable and accrued liabilities $ 57,315     $ 41,494  
  Interest payable   27,862       6,319  
  Current maturities of long-term debt   104,494       -  
  Commodity derivatives   20,607       7,002  
  Share based compensation   10,424       15,123  
    Total current liabilities   220,702       69,938  
LONG-TERM DEBT   849,190       708,521  
COMMODITY DERIVATIVES   20,287       7,589  
ASSET RETIREMENT OBLIGATIONS   41,119       35,307  
SHARE BASED COMPENSATION   10,441       5,239  
    Total liabilities   1,141,739       826,594  
    Total stockholders' equity   (295,658 )     (118,995 )
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 846,081     $ 707,599  
               

GAAP RECONCILIATIONS

Adjusted Earnings and Adjusted EBITDA

In addition to net income (loss) determined in accordance with GAAP, we have provided in this release our Adjusted Earnings and Adjusted EBITDA for recent periods. Both Adjusted Earnings and Adjusted EBITDA are non-GAAP financial measures that we use as supplemental measures of our performance.

We define Adjusted Earnings as net income (loss) before the effects of the items listed in the table below. We calculate the tax effect of reconciling items by re-performing our period-end tax calculation excluding the reconciling items from earnings. The difference between this calculation and the tax expense/benefit recorded for the period results in the tax effect disclosed below. We believe that Adjusted Earnings facilitates comparisons to earnings forecasts prepared by stock analysts and other third parties. Such forecasts generally exclude the effects of items that are difficult to predict or to measure in advance and are not directly related to our ongoing operations. Adjusted Earnings should not be considered a substitute for net income (loss) as reported in accordance with GAAP.

We define Adjusted EBITDA as net income (loss) before the effects of the items listed in the table below. Because the use of Adjusted EBITDA facilitates comparisons of our historical operating performance on a more consistent basis, we use this measure for business planning and analysis purposes, in assessing acquisition opportunities and in determining how potential external financing sources are likely to evaluate our business.

We present Adjusted Earnings and Adjusted EBITDA because we consider them to be important supplemental measures of our performance. Neither Adjusted Earnings nor Adjusted EBITDA is a measurement of our financial performance under GAAP and neither should be considered as an alternative to net income (loss), operating income or any other performance measure derived in accordance with GAAP, as an alternative to cash flow from operating activities or as a measure of our liquidity. You should not assume that the Adjusted Earnings or Adjusted EBITDA amounts shown are comparable to similarly named measures disclosed by other companies.

           
  Quarter Ended     Nine Months Ended  
UNAUDITED ($ in thousands) 9/30/12     6/30/13     9/30/13     9/30/12     9/30/13  
Adjusted Earnings Reconciliation                                      
Net Income $ (30,057 )   $ 41,241     $ (2,911 )   $ (43,449 )   $ 34,087  
Plus:                                      
Unrealized commodity (gains) losses   40,289       (26,101 )     8,893       101,994       (29,431 )
Going private related costs   1,277       -       -       4,757       -  
Loss on extinguishment of debt   -       -       16,787       -       38,084  
Tax effects   -       -       -       -       -  
Adjusted Earnings $ 11,509     $ 15,140     $ 22,769     $ 63,302     $ 42,740  
                                       
           
  Quarter Ended     Nine Months Ended  
UNAUDITED ($ in thousands) 9/30/12     6/30/13     9/30/13     9/30/12     9/30/13  
Adjusted EBITDA Reconciliation                                      
Net income $ (30,057 )   $ 41,241     $ (2,911 )   $ (43,449 )   $ 34,087  
Interest expense   16,498       17,401       15,674       48,089       51,929  
DD&A   22,240       12,406       12,551       65,707       36,529  
Accretion of asset retirement obligation   1,457       615       595       4,298       1,866  
Amortization of deferred loan costs   597       906       868       1,751       2,887  
Loss on extinguishment of debt   -       -       16,787       -       38,084  
Non-cash share-based compensation expense   1,497       1,122       (2,335 )     4,245       1,188  
Going private related costs   1,277       -       -       4,757       -  
Amortization of derivative premiums   1,203       1,018       1,017       11,222       2,984  
Unrealized commodity derivative (gains) losses   40,289       (26,101 )     8,893       101,994       (29,431 )
Adjusted EBITDA $ 55,001     $ 48,608     $ 51,139     $ 198,614     $ 140,123  
                                       

We also provide per BOE G&A expenses excluding costs associated with the going-private transaction and non-cash share-based compensation charges. We believe that these non-GAAP measures are useful in that the items excluded do not represent cash expenses directly related to our ongoing operations. These non-GAAP measures should not be viewed as an alternative to per BOE G&A expenses as determined in accordance with GAAP. 

         
UNAUDITED ($ in thousands, except per BOE amounts) Quarter Ended   Nine Months Ended  
  9/30/12     6/30/13     9/30/13   9/30/12     9/30/13  
G&A per BOE Reconciliation                                    
                                     
G&A expense $ 11,822     $ 10,375     $ 5,358   $ 34,052     $ 30,708  
Less:                                    
Non-cash share-based compensation expense   (1,337 )     (1,122 )     2,335     (3,575 )     (1,188 )
Going private related costs   (1,277 )     -       -     (4,757 )     -  
G&A Expense Excluding Share-Based Comp Going Private Costs   9,208       9,253       7,693     25,720       29,520  
MBOE   1,647       897       831     4,787       2,684  
G&A Expense per BOE Excluding Share-Based Comp and Going Private Costs $ 5.59     $ 10.32     $ 9.26   $ 5.37     $ 11.00  
MBOE excluding Sacramento Basin production   874       -       -     2,276       2,583  
G&A Expense per BOE Excluding Non-Cash Share-Based Comp and Going Private Costs-Excluding Sacramento Basin Production $ 10.54     $ 10.32     $ 9.26   $ 11.30     $ 11.43  
                                     

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