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Mid-Con Energy Partners, LP Announces Fourth Quarter and Full Year 2014 Operating and Financial Results and 2014 Year End Proved Reserves
FOURTH QUARTER 2014 HIGHLIGHTS
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Production for the fourth quarter of 2014 averaged 4,011 Boe/d, an increase of 29.5% sequentially and 57.7% year-over-year. Production for the month ended
December 31, 2014 , averaged 4,557 Boe/d. -
Prices, inclusive of hedge realizations, averaged
$79.24 /Boe, down 11.1% from the previous quarter and down 14.4% from the fourth quarter of 2013. -
Lease Operating Expenses ("LOE") averaged
$21.56 /Boe, a decrease of 10.3% sequentially and an increase of 11.9% year-over-year. -
Adjusted EBITDA, a non-GAAP measure, was
$17.8 million , 16.7% above the third quarter of 2014 and 23.6% above the fourth quarter of 2013. -
Distributable Cash Flow, a non-GAAP measure, was
$13.5 million , up 17.0% sequentially and above 9.8% year-over-year. - Distribution Coverage, a non-GAAP measure, was 3.59x and 4.15x pro forma of acquisitions closed during the quarter.
FOURTH QUARTER 2014 SIGNIFICANT EVENTS
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Issued 5.8 million limited partner units ("common units") at a price to the public of
$17.27 per unit in an underwritten offering onNovember 11, 2014 . Net proceeds of approximately$96.0 million were used to fund a portion of the Eastern Shelf acquisition. -
Closed the Eastern Shelf acquisition in the Permian on
November 17, 2014 , acquiring net proved reserves (68% proved developed & 89% oil) estimated at 6.1 million barrels of oil equivalent ("MMboe") and average 2Q14 net production of 1,197 Boe/d for an aggregate purchase price of approximately$117.6 million . -
Received a borrowing base increase of
$50 million onNovember 17, 2014 , lifting the Partnership's established commitments from lenders to$240 million . -
Declared a cash distribution for the quarter ended
December 31, 2014 , of$0.125 per unit, or$0.50 per unit annualized. The distribution was paidFebruary 13, 2015 , to unitholders of record at the close of business onFebruary 6, 2015 . -
Recorded a
$29.9 million non-cash charge attributable to the impairment of proved oil and gas properties, primarily in Hugoton andSouthern Oklahoma core areas due to reduced recoverable reserve estimates from current forward oil pricing.
"2014 was a period of significant growth for MCEP, our third full year as a publicly traded partnership," commented
The following table reflects selected operating and financial results for the full year and fourth quarter ended
Three Months Ended | Year Ended | |||
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($ in thousands) | 2014 | 2013 | 2014 | 2013 |
Average net daily production (Boe/d)(1) | 4,011 | 2,543 | 3,118 | 2,542 |
Oil & natural gas sales revenues and net derivative settlements |
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Net income |
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Adjusted EBITDA(2) |
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Distributable Cash Flow(2) |
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(1) Production volumes in Boe equivalents calculated at a rate of six Mcf per Bbl. | ||||
(2) Non-GAAP financial measures. Please refer to the related disclosure and reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow included in this press release. |
FOURTH QUARTER 2014 RESULTS
Production - Production for the fourth quarter of 2014 was 369 Mboe, or 4,011 Boe/d. On a daily basis, this represents a 29.5% increase from the third quarter of 2014 and a 57.7% increase year-over-year. The increase in sequential volumes was primarily due to the acquisition of mature oil properties in the Eastern Shelf of the Permian. The increase in year-over-year volumes was primarily due to production growth in
Price Realizations - Oil and natural gas sales were
Operating Revenues - Operating revenues, which include the effect of settled commodity derivatives but exclude the net impact of unsettled commodity derivatives, were
Lease Operating Expenses ("LOE") - LOE were
Production Taxes - Production taxes in the fourth quarter of 2014 were
Impairment Expense - We review our long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If the carrying amount exceeds the property's estimated fair value, we adjust the carrying amount of the property to fair value through a charge to impairment expense. For the quarter ended
Depreciation, Depletion, and Amortization Expenses ("DD&A") - DD&A for the fourth quarter of 2014 were
General and Administrative Expenses ("G&A") - G&A during the fourth quarter of 2014 were
Net Interest Expense - Net interest expense for the fourth quarter of 2014 was
Net Income - For the fourth quarter of 2014,
Adjusted EBITDA - Adjusted EBITDA, a non-GAAP measure, for the fourth quarter of 2014 was
Distributable Cash Flow ("DCF") - DCF, a non-GAAP measure, for the fourth quarter of 2014 was
DCF Coverage - DCF coverage, a non-GAAP measure, for the fourth quarter of 2014 was 3.59x and 4.15x pro forma of acquisitions closed during the quarter, based on 29.7 million limited partner units and 360,000 general partner units outstanding as of
FOURTH QUARTER 2014 CASH DISTRIBUTION
On
FULL YEAR 2014 HIGHLIGHTS
- Production averaged 3,118 Boe/d, an increase of 22.7% over 2013.
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Prices, inclusive of hedge realizations, averaged
$85.94 /Boe, down 7.3% year-over-year. -
LOE averaged
$22.93 /Boe, an increase of 30.0% from 2013. -
Adjusted EBITDA, a non-GAAP measure, was
$58.5 million , 2.5% below the previous year. -
Distributable Cash Flow, a non-GAAP measure, was
$45.2 million , 8.1% down year-over-year. - Distribution Coverage, a non-GAAP measure, was 1.19x.
2014 SIGNIFICANT EVENTS
ACQUISITIONS
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Closed the Hugoton acquisition on
February 28, 2014 , acquiring net proved reserves (79% PDP & 100% oil) estimated at 1.6 MMboe and average net production of 349 Boe/d for an aggregate purchase price of approximately$41.0 million . -
Acquired additional working interests in various
Southern Oklahoma mature waterflood units onMay 1, 2014 , acquiring net proved reserves (57% PDP & 99% oil) estimated at 0.3 MMboe and net production of 90 Boe/d for an aggregate purchase price of approximately$7.3 million . -
Closed the
Oilton acquisition inNortheastern Oklahoma onAugust 5, 2014 , acquiring net proved reserves (88% PDP & 90% oil) estimated at 2.6 MMboe and average 2Q14 net production of 410 Boe/d for an aggregate purchase price of approximately$56.5 million . -
Closed the Liberty South acquisition in the
Gulf Coast onAugust 29, 2014 , acquiring net proved reserves (100% PDP & 99% oil) estimated at approximately 0.7 MMboe and average net production for the first two months of 2Q14 of 154 Boe/d for an aggregate purchase price of approximately$18.9 million . -
Closed the Eastern Shelf acquisition in the Permian on
November 17, 2014 , acquiring net proved reserves (68% proved developed & 89% oil) estimated at 6.1 MMboe and average 2Q14 net production of 1,197 Boe/d for an aggregate purchase price of approximately$117.6 million .
FINANCIALS
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Issued 1.5 million common units for approximately
$34.0 million in proceeds in a private placement with our affiliateMid-Con Energy III, LLC onFebruary 28, 2014 , funding a significant portion of the Hugoton drop-down. -
Received a borrowing base increase of
$20 million onApril 14, 2014 , lifting the Partnership's established commitments from lenders to$170 million . -
Issued approximately 2.2 million common units for approximately
$52.0 million in proceeds in a private placement with our affiliateMid-Con Energy III, LLC onJuly 24, 2014 , funding a significant portion of theOilton drop-down. -
Received a borrowing base increase of
$20 million onAugust 29, 2014 , lifting the Partnership's established commitments from lenders to$190 million . -
Issued 5.8 million common units at a price to the public of
$17.27 per unit in an underwritten offering onNovember 11, 2014 . Net proceeds of approximately$96.0 million were used to fund a portion of the Eastern Shelf acquisition. -
Received a borrowing base increase of
$50 million onNovember 17, 2014 , lifting the Partnership's established commitments from lenders to$240 million . MUFG Union Bank, N.A. andFrost Bank joinedMid-Con Energy's lending group
YEAR END 2014 ESTIMATED NET PROVED RESERVES
At
The following table shows estimated proved reserves as of
Core Area |
Oil (MBbl) |
Gas (MMcf) |
Total (MBoe) |
% Oil |
% Proved Developed |
% Total |
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8,238 | 2,201 | 8,604 | 96% | 72% | 37% |
Permian | 5,536 | 3,746 | 6,160 | 90% | 63% | 26% |
Hugoton | 3,807 | 486 | 3,888 | 98% | 94% | 17% |
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3,868 | 28 | 3,873 | 99% | 90% | 17% |
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691 | 81 | 705 | 99% | 100% | 3% |
Total | 22,140 | 6,542 | 23,230 | 95% | 77% | 100% |
2015 GUIDANCE
The following outlook is subject to all the cautionary statements and limitations described under the "Forward-Looking Statements" caption at the end of this press release. These estimates and assumptions reflect management's best judgment based on current and anticipated market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control.
These estimates and assumptions, previously announced on
FY 2015 Guidance as of |
2015 |
Net production (Boe/d)(1) | 3,950 - 4,350 |
Lease operating expenses per Boe |
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Production taxes (% of total revenue) | 6.3% - 6.8% |
Estimated capital expenditures |
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(1) Production volumes in Boe equivalents calculated at a rate of six Mcf per Bbl. |
HEDGING SUMMARY
On
On
As of
Oil Hedges | 1Q15 | 2Q15 | 3Q15 | 4Q15 | 1Q16 | 2Q16 | 3Q16 | 4Q16 |
WTI Swap Volume - Conventional (Bbl/d) | 1,722 | 1,154 | 1,957 | 2,935 | 1,648 | 1,319 | 1,467 | — |
Price ($/Bbl) |
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n/a |
WTI Swap Volume - Synthetic(1) (Bbl/d) | 1,111 | 1,813 | 978 | — | 1,319 | 1,648 | 1,467 | — |
Price ($/Bbl) |
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na |
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n/a |
WTI Swap Volume - Total (Bbl/d) | 2,833 | 2,967 | 2,935 | 2,935 | 2,967 | 2,967 | 2,935 | — |
Price ($/Bbl) |
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n/a |
% Hedged(2) | 72% | 75% | 74% | 74% | 75% | 75% | 74% | —% |
(1) Comprised of long deferred premium put options and short call options in equal volumes. | ||||||||
(2) Based on the mid-point of 2015 guidance at a 95% oil composition. |
LIQUIDITY AND BORROWING BASE SUMMARY
As of
FOURTH QUARTER 2014 CONFERENCE CALL
As announced on
A replay of the conference call will be available through
UPCOMING CONFERENCES
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Capital Link's
Master Limited Partnership Forum -March 6, 2015 inNew York, NY . -
IPAA Oil & Gas Investment Symposium -
April 20-22, 2015 inNew York, NY .
Corresponding presentation slides will be made available no later than the morning of each event by clicking on "Events & Presentations" in the investor relations section of the
ANNUAL REPORT ON FORM 10-K AND UNITHOLDERS' SCHEDULE K-1
Certain financial results included in this press release and related footnotes are preliminary and are therefore subject to change prior to filing
Additionally, our unitholders' Schedule K-1 for the tax year 2014 will be available for download on the
ABOUT
FORWARD-LOOKING STATEMENTS
This press release includes "forward-looking statements" — that is, statements related to future, not past, events within meaning of the federal securities laws. Forward-looking statements are based on current expectations and include any statement that does not directly relate to a current or historical fact. In this context, forward-looking statements often address expected future business and financial performance, and often contain words such as "anticipate," "believe," "estimate," "intend," "expect," "plan," "project," "should," "goal," "forecast," "guidance," "could," "may," "continue," "might," "potential," "scheduled," or "will" or other similar words. These forward-looking statements involve certain risks and uncertainties and ultimately may not prove to be accurate. Actual results and future events could differ materially from those anticipated in such statements. For
further discussion of risks and uncertainties, you should refer to
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Consolidated Balance Sheets | ||
(in thousands, except number of units) | ||
(unaudited) | ||
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2014 | 2013 | |
ASSETS | ||
CURRENT ASSETS: | ||
Cash and cash equivalents |
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Accounts receivable: | ||
Oil and natural gas sales | 8,051 | 6,778 |
Other | 4,070 | 104 |
Derivative financial instruments | 26,202 | 153 |
Prepaids and other | 652 | 191 |
Total current assets | 42,207 | 8,660 |
PROPERTY AND EQUIPMENT: | ||
Oil and natural gas properties, successful efforts method: | ||
Proved properties | 501,191 | 216,680 |
Accumulated depletion, depreciation, amortization and impairment | (93,896) | (36,148) |
Total property and equipment, net | 407,295 | 180,532 |
DERIVATIVE FINANCIAL INSTRUMENTS | 842 | 48 |
OTHER ASSETS | 4,284 | 843 |
Total assets | $ 454,628 | $ 190,083 |
LIABILITIES AND EQUITY | ||
CURRENT LIABILITIES: | ||
Accounts payable: | ||
Trade |
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Related parties | 3,989 | 2,982 |
Derivative financial instruments | — | 1,627 |
Accrued liabilities | 397 | 432 |
Total current liabilities | 8,016 | 7,225 |
OTHER LONG-TERM LIABILITIES | 107 | 128 |
LONG-TERM DEBT | 205,000 | 112,000 |
ASSET RETIREMENT OBLIGATIONS | 7,363 | 3,942 |
COMMITMENTS AND CONTINGENCIES | ||
EQUITY, per accompanying statements: | ||
Partnership equity: | ||
General partner interest | 1,328 | 1,716 |
Limited partners-29,166,112 and 19,319,362 units issued and outstanding as of |
232,814 | 65,072 |
Total equity | 234,142 | 66,788 |
Total liabilities and equity | $ 454,628 | $ 190,083 |
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Consolidated Statements of Operations | ||||
(in thousands, except per unit data) | ||||
(unaudited) | ||||
Three Months Ended | Year Ended | |||
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2014 | 2013 | 2014 | 2013 | |
Revenues: | ||||
Oil sales |
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Natural gas sales | 334 | 143 | 784 | 656 |
Net settlements on derivatives | 4,644 | 199 | 891 | 288 |
Gain (loss) on unsettled derivatives, net | 22,376 | 371 | 28,470 | (5,963) |
Total revenues | 51,616 | 22,038 | 126,272 | 80,061 |
Operating costs and expenses: | ||||
Lease operating expenses | 7,955 | 4,507 | 26,091 | 16,366 |
Oil and natural gas production taxes | 1,631 | 1,147 | 6,325 | 3,817 |
Impairment of proved oil and natural gas properties | 29,903 | — | 30,206 | 1,578 |
Depreciation, depletion and amortization | 7,977 | 3,464 | 21,877 | 14,421 |
Accretion of discount on asset retirement obligations | 75 | 49 | 250 | 173 |
General and administrative | 2,355 | 2,577 | 14,313 | 12,244 |
Total operating costs and expenses | 49,896 | 11,744 | 99,062 | 48,599 |
Income from operations | 1,720 | 10,294 | 27,210 | 31,462 |
Other income (expense): | ||||
Interest income and other | 6 | 3 | 13 | 9 |
Interest expense | (1,644) | (962) | (4,731) | (3,282) |
Total other expense | (1,638) | (959) | (4,718) | (3,273) |
Net income |
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Computation of net income per limited partner unit: | ||||
General partner's interest in net income |
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Limited partners' interest in net income |
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Net income per limited partner unit | ||||
Basic | $ — |
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Diluted | $ — |
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Weighted average limited partner units outstanding: | ||||
Limited partner units (basic) | 26,430 | 19,296 | 22,499 | 19,234 |
Limited partner units (diluted) | 26,440 | 19,339 | 22,518 | 19,249 |
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Consolidated Statements of Cash Flows | ||
(in thousands) | ||
(unaudited) | ||
Year Ended |
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2014 | 2013 | |
Cash Flows from Operating Activities: | ||
Net income |
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Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, depletion and amortization | 21,877 | 14,421 |
Debt issuance costs amortization | 348 | 168 |
Accretion of discount on asset retirement obligations | 250 | 173 |
Impairment of proved oil and natural gas properties | 30,206 | 1,578 |
(Gain) loss on unsettled derivative instruments, net | (28,470) | 5,963 |
Non-cash equity-based compensation | 7,394 | 6,376 |
Changes in operating assets and liabilities: | ||
Accounts receivable | (1,273) | (365) |
Other receivables | (3,966) | 499 |
Prepaids and other | (461) | (526) |
Accounts payable and accrued liabilities | 2,067 | 158 |
Net cash provided by operating activities | 50,464 | 56,634 |
Cash Flows from Investing Activities: | ||
Additions to oil and natural gas properties | (33,969) | (22,366) |
Acquisitions of oil and natural gas properties | (155,354) | (28,057) |
Net cash used in investing activities | (189,323) | (50,423) |
Cash Flows from Financing Activities: | ||
Proceeds from line of credit | 168,000 | 105,000 |
Payments on line of credit | (75,000) | (71,000) |
Issuance of common units | 96,010 | — |
Distributions paid | (44,564) | (39,830) |
Debt issuance costs | (3,789) | — |
Net cash provided by (used in) financing activities | 140,657 | (5,830) |
Net increase in cash and cash equivalents | 1,798 | 381 |
Beginning cash and cash equivalents | 1,434 | 1,053 |
Ending cash and cash equivalents |
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Supplemental Cash Flow Information: | ||
Cash paid for interest |
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Non-Cash Investing and Financing Activities: | ||
Accrued capital expenditures -- oil and natural gas properties |
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Common units issued - acquisition of oil properties |
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$ — |
NON-GAAP FINANCIAL MEASURES
This press release, financial tables and other supplemental information include "Adjusted EBITDA" and "Distributable Cash Flow", each of which are non-generally accepted accounting principles ("Non-GAAP") measures used by our management to describe financial performance with external users of our financial statements.
The Partnership believes the Non-GAAP financial measures described above are useful to investors because these measurements are used by many companies in its industry as a measurement of financial performance and are commonly employed by financial analysts and others to evaluate the financial performance of the Partnership and to compare the financial performance of the Partnership with the performance of other publicly traded partnerships within its industry.
Adjusted EBITDA and Distributable Cash Flow should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.
Adjusted EBITDA is defined as net income (loss) plus:
- Interest expense, net;
- Depreciation, depletion and amortization;
- Accretion of discount on asset retirement obligations;
- Loss (gain) on unsettled derivatives, net;
- Non-cash equity-based compensation;
- Impairment of proved oil and natural gas properties;
- Dry hole costs and abandonments of unproved properties; and
- Loss (gain) on sale of asset, net.
Distributable Cash Flow is defined as Adjusted EBITDA less:
- Cash interest expense; and
- Estimated maintenance capital expenditures.
Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow | ||||
(in thousands) | ||||
(unaudited) | ||||
Three Months Ended | Year Ended | |||
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2014 | 2013 | 2014 | 2013 | |
Net income | 82 | 9,335 | 22,492 | 28,189 |
Interest expense | 1,644 | 962 | 4,731 | 3,282 |
Depreciation, depletion and amortization | 7,977 | 3,464 | 21,877 | 14,421 |
Accretion of discount on asset retirement obligations | 75 | 49 | 250 | 173 |
(Gain) loss on unsettled derivatives, net | (22,376) | (371) | (28,470) | 5,963 |
Impairment of proved oil and natural gas properties | 29,903 | — | 30,206 | 1,578 |
Non-cash equity-based compensation | 494 | 957 | 7,394 | 6,376 |
Interest income and other | (6) | (3) | (13) | (9) |
Adjusted EBITDA |
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Less: | ||||
Cash interest expense |
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Estimated maintenance capital expenditures | 2,866 | 1,508 | 8,715 | 8,056 |
Distributable Cash Flow |
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Distributions Attributable to Each Period |
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Distribution Coverage Ratio | 3.59x | 1.20x | 1.19x | 1.22x |
CONTACT: INVESTOR RELATIONS CONTACTSource:Krista McKinney (972) 479-5980 kmckinney@midcon-energy.com
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