Enerplus Announces Second Quarter 2018 Results

Aug 10, 2018

All financial information contained within this news release has been prepared in accordance with U.S. GAAP, except as noted under "Non-GAAP Measures". This news release includes forward-looking statements and information within the meaning of applicable securities laws. Readers are advised to review the "Forward-Looking Information and Statements" at the conclusion of this news release. A full copy of Enerplus' Second Quarter 2018 Financial Statements and MD&A are available on the Company's website at www.enerplus.com, under its SEDAR profile at www.sedar.com and on the EDGAR website at www.sec.gov.

CALGARY, Aug. 10, 2018 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to announce second quarter 2018 operating and financial results. The Company reported second quarter 2018 net income of $12.4 million or $0.05 per share. For the first six months of 2018, net income was $42.0 million, or $0.17 per share.

HIGHLIGHTS

  • Company production of 92,883 BOE per day in the second quarter
  • Company liquids production was up 21% quarter-over-quarter, averaging 50,050 barrels per day, achieving the high end of second quarter guidance of 48,000 to 50,000 barrels per day
  • 33% production growth in North Dakota quarter-over-quarter
  • Increasing 2018 annual production guidance to 91,000 to 93,000 BOE per day, from 86,000 to 91,000 BOE per day
  • Revising 2018 annual liquids production guidance to the upper-end of the range, now 49,000 to 50,000 barrels per day, from 46,000 to 50,000 barrels per day
  • 2018 capital spending guidance tightened to $585 million (from $535 to $585 million previously) largely related to increased non-operated activity
  • Generated adjusted funds flow of $173.7 million during the second quarter
  • 2018 adjusted funds flow expected to exceed capital expenditures and dividends by over $100 million based on current forward strip pricing
  • Reducing cash G&A guidance by $0.10 per BOE to $1.55 per BOE
  • Balance sheet remains among the strongest in the peer group with a net debt to adjusted funds flow ratio of 0.5 times

"We delivered strong financial and operational performance through the first half of 2018," said Ian C. Dundas, President and Chief Executive Officer. "Our plans to continue to drive profitable growth and competitive returns remain firmly on track. We are increasing our production guidance largely underpinned by high-margin, light oil growth out of the Bakken and we have visibility to generating over $100 million in free cash flow in the second half of the year. Notwithstanding this strong outlook, we will remain disciplined with our capital allocation and continue to focus on creating long-term value for our shareholders."

SECOND QUARTER FINANCIAL AND OPERATIONAL SUMMARY

Production
Production in the second quarter of 2018 averaged 92,883 BOE per day, up 9% from the first quarter. Liquids production for the quarter averaged 50,050 barrels per day (90% crude oil and 10% natural gas liquids), achieving the high end of second quarter guidance of 48,000 to 50,000 barrels per day. The Company brought 11 operated high working interest wells on production in North Dakota during the quarter, which drove the 21% increase in liquids production from the prior quarter.

Natural gas production for the second quarter averaged 257 MMcf per day, largely flat to the prior quarter.

Enerplus is increasing its 2018 production guidance to 91,000 to 93,000 BOE per day (from 86,000 to 91,000 BOE per day) and annual liquids production guidance is being revised to 49,000 to 50,000 barrels per day, the high-end of the previous range of 46,000 to 50,000 barrels per day. The increased production guidance reflects better than expected well performance in North Dakota along with higher than forecast non-operated production in the Marcellus.

Net Income and Adjusted Funds Flow
Enerplus generated net income of $12.4 million in the second quarter of 2018, a decrease from the previous quarter primarily as a result of higher non-cash mark-to-market losses on the Company's commodity derivative instruments resulting from the improvement in forward crude oil prices.

Adjusted funds flow was $173.7 million during the second quarter, up 12% compared to $155.2 million in the previous quarter, supported by an increase of 15% in realized crude oil prices and higher crude oil production during the quarter.

Pricing Realizations and Cost Structure
Bakken crude oil differentials continue to see support from improved egress out of the area due to the Dakota Access Pipeline. Enerplus' realized Bakken crude oil price differential averaged US$3.42 per barrel below WTI in the second quarter, in-line with its unchanged 2018 guidance of US$3.50 per barrel below WTI.

The Company's realized Marcellus natural gas price differential was US$0.69 per Mcf below NYMEX in the second quarter. Although weaker than the first quarter due to seasonality and pipeline maintenance issues, Marcellus differentials are expected to improve over the remainder of the year as additional pipeline projects are completed. As a result, the Company's 2018 Marcellus differential guidance of US$0.40 per Mcf below NYMEX is unchanged.

Second quarter operating expenses were $7.20 per BOE, an increase of 3% from the first quarter due to the higher liquids production weighting in the second quarter. Transportation costs of $3.56 per BOE were largely flat to the prior quarter, and second quarter cash general and administrative ("G&A") expenses of $1.44 per BOE were 16% lower compared to the prior quarter largely reflective of higher second quarter production. Enerplus' 2018 guidance for operating costs ($7.00 per BOE) and transportation costs ($3.60 per BOE) remains unchanged. Cash G&A guidance for 2018 is being reduced to $1.55 per BOE (from $1.65 per BOE).

Capital Expenditures and Balance Sheet Position
Exploration and development capital spending in the second quarter was $177.1 million associated with drilling 18.2 net wells and completing and bringing on production 12.2 net wells across the Company. Enerplus is tightening its 2018 capital spending guidance to $585 million, from the previous guidance range of $535 to $585 million, as a result of an increase in non-operated activity and modest inflation on the cost of materials and services. Capital spending for the second half of 2018 is expected to be weighted to the third quarter.

Total debt net of cash at June 30, 2018 was $311.8 million. Total debt was comprised of $672.2 million of senior notes outstanding. The Company was undrawn on its $800 million bank credit facility and had a cash balance of $360.4 million. At June 30, 2018, Enerplus' net debt to adjusted funds flow ratio was 0.5 times.

AVERAGE DAILY PRODUCTION(1)


Three months ended
June 30, 2018


Six months ended
June 30, 2018


Crude Oil

(Mbbl/d)

Natural

Gas

Liquids

(Mbbl/d)

Natural gas

(MMcf/d)

Total

Production

(Mboe/d)


Crude Oil

(Mbbl/d)

Natural Gas

Liquids

(Mbbl/d)

Natural

gas

(MMcf/d)

Total

Production

(Mboe/d)

Williston Basin

35.8

3.7

25.3

43.7


31.7

3.3

22.6

38.8

Marcellus

-

-

202.4

33.7


-

-

205.4

34.2

Canadian Waterfloods

9.0

0.1

3.8

9.8


9.2

0.1

4.4

10.1

Other(2)

0.5

0.9

25.4

5.6


0.4

1.0

26.8

5.9

Total

45.2

4.8

257.0

92.9


41.4

4.4

259.1

89.0

(1) Table may not add due to rounding.
(2) Six months ended June 30, 2018 includes approximately 600 boe/d of production from Canadian natural gas properties sold in Q1 2018.

 

SUMMARY OF WELLS BROUGHT ON-STREAM(1)


Three months ended
June 30, 2018


Six months ended
 June 30, 2018


Operated


Non-Operated


Operated


Non-Operated














Gross

Net


Gross

Net


Gross

Net


Gross

Net













Williston Basin

11

10.3


2

0.7


19

15.5


2

0.7

Marcellus

-

-


14

1.8


-

-


25

3.3

Canadian Waterfloods

-

-


-

-


2

1.9


-

-

Other

-

-


-

-


-

-


1

0.3

Total

11

10.3


16

2.4


21

17.4


28

4.2

(1) Table may not add due to rounding.

 

ASSET ACTIVITY

Williston Basin
Williston Basin production averaged 43,741 BOE per day (82% oil) during the second quarter of 2018, up 29% from the first quarter of 2018. Second quarter Williston Basin production was comprised of 40,479 BOE per day in North Dakota, a 33% increase from the first quarter, and 3,262 BOE per day in Montana.

Enerplus brought on-stream 11 gross operated wells (94% average working interest) across two pads at Fort Berthold during the second quarter. The six-well Cats pad had an average completed lateral length of 9,700 feet per well and average peak 30-day production rates per well of 2,013 BOE per day (84% oil, on a three-stream basis). The five-well Metals North pad had an average completed lateral length of 8,700 feet per well (including one 4,200 foot lateral) and average peak 30-day production rates per well of 1,684 BOE per day (81% oil, on a three-stream basis).

The Company drilled 13 gross operated wells (92% average working interest) in the second quarter.

The Company continues to run two operated drilling rigs and one dedicated completions crew at its Fort Berthold operations.

Marcellus
Marcellus production averaged 202 MMcf per day during the second quarter, a decrease from the previous quarter of 3% primarily due to pipeline maintenance and seasonally weaker natural gas prices in the second quarter.

Fourteen gross non-operated wells (13% average working interest) were brought on-stream during the quarter. Thirteen wells had more than 30 days on production as of the date of this news release with an average completed lateral length of 5,300 feet per well and average peak 30-day production rates per well of 8.1 MMcf per day.

The Company participated in drilling 16 gross non-operated wells (13% average working interest) during the second quarter.

Canadian Waterfloods
Canadian waterflood production averaged 9,770 BOE per day (92% oil) during the second quarter, 5% lower than the previous quarter, primarily due to downtime associated with facility upgrades at Giltedge. Capital activity for the remainder of the year will be focused on the Company's drilling program at Medicine Hat.

DJ Basin
Enerplus drilled four gross (3.2 net) wells in the DJ Basin during the second quarter. The wells were recently completed and have commenced flow back. Post-cleanout well results are not expected until later this year.

2018 GUIDANCE

Enerplus' 2018 updated guidance is summarized below. The Company increased its total production guidance, revised its liquids production and capital guidance, and reduced its cash G&A expense guidance. All other guidance remains unchanged.


Guidance

Capital spending

$585 million (from $535 - $585 million)

Average annual production

91,000 to 93,000 BOE/day (from 86,000 to 91,000 BOE/day)

Average annual crude oil and natural gas liquids production

49,000 to 50,000 bbls/day (from 46,000 to 50,000 bbls/day)

Average royalty and production tax rate

25%

Operating expense

$7.00/BOE

Transportation expense

$3.60/BOE

Cash G&A expense

$1.55/BOE (from $1.65/BOE)

 

2018 Full-Year Differential/Basis Outlook (1)

U.S. Bakken crude oil differential (compared to WTI crude oil)

US$(3.50)/bbl

Marcellus natural gas sales price differential (compared to NYMEX natural gas)

US$(0.40)/Mcf

(1) Excluding transportation costs.

 

RISK MANAGEMENT

Enerplus continues to manage price risk through commodity hedging. Using swaps and collar structures, Enerplus has an average of 22,000 barrels per day of crude oil protected for the remainder of 2018 (approximately 66% of forecast crude oil production at the midpoint of guidance, net of royalties and production taxes), 23,140 barrels per day protected in 2019, and 14,000 barrels per day protected in 2020.

For natural gas, Enerplus has 36,685 Mcf per day protected for the remainder of 2018 (approximately 19% of forecast natural gas production at the midpoint of guidance, net of royalties and production taxes) using collar structures.

Commodity Hedging Detail (As at August 9, 2018)


WTI Crude Oil

(US$/bbl) (1)

Nymex Natural Gas

(US$/Mcf) (1)


Jul 1, –

Sep 30,

2018

Oct 1 –

Dec 31,

2018

Jan 1 –

Mar 31,

2019

Apr 1 –

Jun 30,

2019

Jul 1, –

Sep 30,

2019

Oct 1, – 

Dec 31,

2019

Jan 1, –

Dec 31,

2020

Jul 1, –

Oct 31,

2018

Nov 1, –

Dec 31,

2018











Swaps










Sold Swaps

$53.73

$53.73

$53.73

-

-

-

-

-

-

Volume (bbls/d or Mcf/d)

3,000

3,000

3,000

-

-

-

-

-

-





















Three-Way Collars










Sold Puts

$42.71

$42.74

$44.28

$44.50

$44.64

$44.64

$46.71

-

-

Volume (bbls/d or Mcf/d)

18,000

20,000

17,000

23,500

24,500

24,500

14,000

-

-











Purchased Puts

$52.53

$52.48

$54.12

$54.59

$54.81

$54.81

$57.14

$2.75

$2.75

Volume (bbls/d or Mcf/d)

18,000

20,000

17,000

23,500

24,500

24,500

14,000

40,000

30,000











Sold Calls

$61.22

$61.10

$64.12

$65.52

$65.95

$65.99

$72.07

$3.38

$3.47

Volume (bbls/d or Mcf/d)

18,000

20,000

17,000

23,500

24,500

24,500

14,000

40,000

30,000

(1) Based on weighted average price (before premiums)
(2) The total average deferred premium spent on the three-way collars is US$1.59/bbl from July 1, 2018 to December 31, 2020

 

Q2 2018 CONFERENCE CALL DETAILS

A conference call hosted by Ian C. Dundas, President and CEO will be held at 9:00 AM MT (11:00 AM ET) today to discuss these results. Details of the conference call are as follows:

Date:

Friday, August 10, 2018

Time:

9:00 AM MT (11:00 AM ET)

Dial-In:

587-880-2171 (Alberta)


1-888-390-0546 (Toll Free)

Conference ID:

84144621

Audiocast:   

https://event.on24.com/wcc/r/1788011/F463A916B7AF3CFED0821F4E99352879

 

To ensure timely participation in the conference call, callers are encouraged to dial in 15 minutes prior to the start time to register for the event. A telephone replay will be available for 30 days following the conference call and can be accessed at the following numbers:

Dial-In:

416-764-8677


1-888-390-0541 (Toll Free)

Passcode:

144621 #

 

SELECTED FINANCIAL AND OPERATING RESULTS

SELECTED FINANCIAL RESULTS

Three months ended

June 30, 


Six months ended

June 30, 


2018

2017


2018

2017

Financial (000's)










Net Income/(Loss)

$

12,404

$

129,302


$

42,041

$

205,595

Adjusted Funds Flow(4)


173,708


114,199



328,870


234,119

Dividends to Shareholders - Declared


7,347


7,264



14,667


14,505

Debt Outstanding – net of Cash and Restricted Cash


311,782


308,067



311,782


308,067

Capital Spending


177,082


101,739



328,554


222,086

Property and Land Acquisitions


2,392


4,713



14,664


7,249

Property Divestments


(182)


59,842



6,788


58,942

Net Debt to Adjusted Funds Flow Ratio(4)


0.5x


0.7x



0.5x


0.7x











Financial per Weighted Average Shares Outstanding










Net Income - Basic

$

0.05

$

0.53


$

0.17

$

0.85

Net Income - Diluted


0.05


0.52



0.17


0.83

Weighted Average Number of Shares Outstanding (000's)


244,862


242,127



244,369


241,710











Selected Financial Results per BOE(1)(2)










Oil & Natural Gas Sales(3)

$

48.13

$

35.96


$

45.65

$

36.14

Royalties and Production Taxes


(12.08)


(8.95)



(11.28)


(8.42)

Commodity Derivative Instruments


(2.28)


0.28



(0.57)


0.57

Cash Operating Expenses


(7.21)


(5.88)



(7.12)


(6.23)

Transportation Costs


(3.56)


(3.72)



(3.54)


(3.80)

General and Administrative Expenses


(1.44)


(1.53)



(1.57)


(1.69)

Cash Share-Based Compensation


(0.05)




(0.16)


(0.01)

Interest, Foreign Exchange and Other Expenses


(0.95)


(1.34)



(0.99)


(1.31)

Current Income Tax Recovery/(Expense)


(0.01)


(0.26)



(0.01)


(0.14)

Adjusted Funds Flow(4)

$

20.55

$

14.56


$

20.41

$

15.11





SELECTED OPERATING RESULTS

Three months ended

June 30, 


Six months ended

June 30, 


2018

2017


2018

2017

Average Daily Production(2)










Crude Oil (bbls/day)


45,242


36,861



41,364


35,030

Natural Gas Liquids (bbls/day)


4,808


4,133



4,449


3,648

Natural Gas (Mcf/day)


256,995


271,292



259,141


281,393

Total (BOE/day)


92,883


86,209



89,003


85,577











% Crude Oil and Natural Gas Liquids


54%


48%



51%


45%











Average Selling Price (2)(3)










Crude Oil (per bbl)

$

79.98

$

55.66


$

75.34

$

56.54

Natural Gas Liquids (per bbl)


32.23


25.14



30.36


30.57

Natural Gas (per Mcf)


2.68


3.48



3.09


3.56











Net Wells Drilled


18


13



32


28

(1)

Non-cash amounts have been excluded.

(2)

Based on Company interest production volumes. See "Presentation of Production Information" below.

(3)

Before transportation costs, royalties, and commodity derivative instruments.

(4)

These non-GAAP measures may not be directly comparable to similar measures presented by other entities. See "Non-GAAP Measures" section in this news release.

 


Three months ended

June 30, 


Six months ended

June 30, 

Average Benchmark Pricing

2018


2017


2018


2017

WTI crude oil (US$/bbl)

$

67.88


$

48.29


$

65.37


$

50.10

AECO natural gas– monthly index (CDN$/Mcf)


1.02



2.77



1.44



2.86

AECO natural gas – daily index (CDN$/Mcf)


1.18



2.78



1.63



2.74

NYMEX natural gas – last day (US$/Mcf)


2.80



3.18



2.90



3.25

USD/CDN average exchange rate


1.29



1.34



1.28



1.33

 

Share Trading Summary

CDN(1) - ERF


U.S.(2) - ERF

For the three months ended June 30, 2018

(CDN$)


(US$)

High

$

17.21


$

13.49

Low

$

13.79


$

10.75

Close

$

16.58


$

12.60

(1) TSX and other Canadian trading data combined.

(2) NYSE and other U.S. trading data combined.



2018 Dividends per Share

CDN$


US$(1)

First Quarter Total

$

0.03


$

0.02

Second Quarter Total

$

0.03


$

0.02

Total Year to Date

$

0.06


$

0.04

(1) CDN$ dividends converted at the relevant foreign exchange rate on the payment date.

 

Currency and Accounting Principles
All amounts in this news release are stated in Canadian dollars unless otherwise specified. All financial information in this news release has been prepared and presented in accordance with U.S. GAAP, except as noted below under "Non-GAAP Measures".

Barrels of Oil Equivalent
This news release also contains references to "BOE" (barrels of oil equivalent). Enerplus has adopted the standard of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading.

Presentation of Production Information
Under U.S. GAAP oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production volumes net of royalties. Under Canadian industry protocol oil and gas sales and production volumes are presented on a gross basis before deduction of royalties. To continue to be comparable with its Canadian peer companies, the summary results contained within this news release presents Enerplus' production and BOE measures on a before royalty company interest basis. All production volumes and revenues presented herein are reported on a "company interest" basis, before deduction of Crown and other royalties, plus Enerplus' royalty interest.  

Readers are cautioned that the average initial production rates contained in this news release are not necessarily indicative of long-term performance or of ultimate recovery.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This news release contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "guidance", "ongoing", "may", "will", "project", "should", "believe", "plans", "budget", "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this news release contains forward-looking information pertaining to the following: expected  average production volumes in 2018 and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our funds flow; the results from our drilling program and the timing of related production; oil and natural gas prices and estimated differentials and our commodity risk management programs in 2018 and beyond; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating and transportation costs; capital spending levels in 2018 and its impact on our production level and land holdings; our future royalty and production and cash taxes; future debt and working capital levels and debt to funds flow ratios.

The forward-looking information contained in this news release reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that Enerplus will conduct its operations and achieve results of operations as anticipated; that Enerplus' development plans will achieve the expected results; current commodity price and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of Enerplus' reserves and resources volumes; the continued availability of adequate debt and/or equity financing, cash flow and other sources to fund Enerplus' capital and operating requirements, and dividend payments, as needed; availability of third party services; and the extent of its liabilities. In addition, our 2018 guidance contained in this news release is based on the following forward prices: WTI US$66.00/bbl, NYMEX US$2.84/Mcf, and a USD/CDN exchange rate of 1.30. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information included in this news release is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: changes, including continued volatility, in commodity prices; changes in realized prices for Enerplus' products; changes in the demand for or supply of Enerplus' products; unanticipated operating results, results from Enerplus' capital spending activities or production declines; curtailment of Enerplus' production due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans by Enerplus or by third party operators of Enerplus' properties; increased debt levels or debt service requirements; Enerplus' inability to comply with covenants under its bank credit facility and senior notes; changes in estimates of Enerplus' oil and gas reserves and resources volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners; failure to complete any anticipated acquisitions or divestitures; and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in its Annual Information Form, management's discussion and analysis for the year-ended December 31, 2017, and Form 40-F at December 31, 2017).

The forward-looking information contained in this press release speak only as of the date of this press release. Enerplus does not undertake any obligation to publicly update or revise any forward-looking information contained herein, except as required by applicable laws.

NON-GAAP MEASURES

In this news release, we use the terms "adjusted funds flow", "net debt to adjusted funds flow ratio" and "total debt net of cash" as measures to analyze operating performance, leverage and liquidity. "Adjusted funds flow" is calculated as net cash generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. "Net debt to adjusted funds flow ratio" is calculated as total debt net of cash and restricted cash, divided by a trailing 12 months of adjusted funds flow. "Total debt net of cash" is calculated as senior notes plus any outstanding bank credit facility balance, minus cash and restricted cash. Calculation of these terms is described in Enerplus' MD&A under the "Liquidity and Capital Resources" section.

Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "adjusted funds flow" and "net debt to adjusted funds flow" are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures are not measures recognized by U.S. GAAP and do not have a standardized meaning prescribed by U.S. GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers. For reconciliation of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP, and further information about these measures, see disclosure under "Non-GAAP Measures" in Enerplus' Second Quarter 2018 MD&A.

Electronic copies of Enerplus Corporation's Second Quarter 2018 MD&A and Financial Statements, along with other public information including investor presentations, are available on its website at www.enerplus.com. Shareholders may, upon request, receive a printed copy of the Company's audited financial statements at any time. For further information, please contact Investor Relations at 1-800-319-6462 or email investorrelations@enerplus.com.

Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.

SOURCE Enerplus Corporation

For further information: Ian C. Dundas, President & Chief Executive Officer, Enerplus Corporation


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