Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - NEWFIELD EXPLORATION CO /DE/ | nfx8k-102412.htm |
| EX-99.2 - EXHIBIT 992 - NEWFIELD EXPLORATION CO /DE/ | ex992.htm |
Exhibit 99.1
Newfield Exploration Announces Third Quarter 2012 Financial and Operating Results
The Woodlands, Texas – October 23, 2012 – Newfield Exploration Company (NYSE: NFX) today reported its unaudited third quarter 2012 financial results and provided an update on its operations. In addition, the Company placed an updated slide deck on its website. Newfield will host a conference call at 8:30 a.m. CDT on October 24, 2012. To participate in the call, dial 719-325-2231 or listen through the investor relations section of Newfield’s website at http://www.newfield.com.
For the third quarter of 2012, Newfield recorded a net loss of $33 million, or ($0.24) per diluted share (all per share amounts are on a diluted basis). Third quarter results were negatively impacted by the following items:
|
·
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An unrealized loss on commodity derivatives of $135 million ($85 million after-tax), or $0.63 per share;
|
|
·
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Non-recurring expenses of approximately $20 million ($13 million after-tax), or $0.09 per share. The largest component of these expenses is related to the July 2012 redemption of $550 million of 6 5/8% Senior Subordinated Notes due 2016.
|
Without the effect of the above items, reported net income for the third quarter of 2012 would have been $65 million, or $0.48 per share.
Revenues for the third quarter of 2012 were $615 million. Net cash provided by operating activities before changes in operating assets and liabilities was $308 million. See “Explanation and Reconciliation of Non-GAAP Financial Measures” found after the financial statements in this release.
Newfield’s oil and natural gas liquids (NGLs) liftings in the third quarter increased 20% over the comparable period in 2011 to 6.1 MMBbls, or an average of more than 66,000 BOEPD. Natural gas production in the third quarter of 2012 was 39 Bcf, an average of 420 MMcf/d. Combined, Newfield’s production in the third quarter of 2012 was 75 Bcfe (43% oil and 6% natural gas liquids). Capital expenditures in the third quarter of 2012 were approximately $450 million.
OPERATIONAL HIGHLIGHTS:
Cana Woodford
The Company continues to post strong well results in the Cana Woodford, located in central Oklahoma’s Anadarko Basin. Throughout 2012, Newfield has maintained a 4-5 rig program and is aggressively assessing its acreage position which totals approximately 142,000 net acres (up 7,000 net acres since mid-year). Net production from Newfield’s Cana Woodford play is today approximately 9,800 BOEPD (60% liquids).
Production from the following wells, initially announced in the second quarter, has been updated to reflect recent longer-term data:
Wright 1H-9 –The well had an initial gross production rate of more than 1,900 BOEPD (27% oil). The well averaged approximately 1,050 BOEPD over its first 100 days of production. The well has a 4,730’ lateral length. Based on available public data, Newfield’s Wright well (74% working interest) had the highest initial flow rate (all rates are 24-hour) achieved to date in the South Cana Woodford.
Branch 1H-16 – The Branch well (100% working interest) had an initial gross production rate of more than 1,850 BOEPD (27% oil). The well averaged approximately 1,030 BOEPD over its first 100 days of production. The well has a 4,950’ lateral length.
Whitt 1H-25 – The Whitt well (93% working interest) had an initial gross production rate of approximately 1,050 BOEPD (50% oil). The well averaged nearly 500 BOEPD over its first 100 days of production. The well has a lateral length of approximately 4,900’.
Faith 1H-12 – The Faith well (52% working interest) had an initial gross production rate of nearly 1,000 BOEPD (22% oil). The well averaged approximately 880 BOEPD over its first 100 days of production. The well has a lateral length of approximately 4,200’.
Greenwood 1H-4 – The Greenwood well (63% working interest) had an initial gross production rate of approximately 1,000 BOEPD (16% oil). The well averaged 900 BOEPD over its first 100 days of production. The well has a lateral length of approximately 4,900’.
Williams 1H-19 – The Williams well (94% working interest) had an initial gross production rate of approximately 650 BOEPD (69% oil). The well averaged 400 BOEPD over its first 100 days of production. The well has a lateral length of approximately 4,900’.
The following wells are notable recent completions in the Company’s South Cana Woodford, an area which covers approximately 80,000 net acres:
Mashburn 1H-4 – The Mashburn well (55% working interest) had an initial gross production rate of approximately 1,390 BOEPD (28% oil). The well averaged 1,120 BOEPD over its first 30 days of production. The well has a lateral length of 4,519’.
Vinson 1H-14 – The Vinson well (61% working interest) had an initial gross production rate of approximately 1,090 BOEPD (21% oil). The well averaged 1,000 BOEPD over its first 30 days of production. The well has a lateral length of 4,900’.
Baxendale 1H-12 – The Baxendale well (87% working interest) had an initial gross production rate of approximately 1,020 BOEPD (53% oil). The well averaged 900 BOEPD over its first 30 days of production. The well has a lateral length of 4,900’.
During the third quarter, Newfield began assessment of its “North Cana” acreage position – an area also prone to high oil and liquids yields.
Klade 1H-19 – The Klade well (99% working interest) had an initial gross production rate of approximately 925 BOEPD (93% oil). The well averaged 660 BOEPD over its first 30 days of production. The well has a lateral length of 10,200’.
Hogshooter
During the third quarter, Newfield drilled and completed its first Hogshooter well, located in Wheeler County, Texas. The well had a gross initial production rate of 5,045 BOEPD (90% liquids) and averaged more than 4,200 BOEPD gross over a 30-day period. The well has a lateral length of 4,850’. Newfield is operator of the well with a 90% working interest. An operated rig is dedicated to the play and three additional wells are in progress.
2
Uinta Basin
Newfield’s net production from the Uinta Basin hit a high in the third quarter of approximately 39,000 BOEPD, or 27,000 BOEPD net. Newfield owns interest in approximately 230,000 net acres in the Uinta Basin. In addition to the ongoing development of the Green River formation in the Monument Butte field, today’s assessment drilling efforts are focused on two primary plays – the Uteland Butte and the Wasatch.
Uteland Butte – To date, the Company has drilled 11 wells in the play and is encouraged by the results. The Company is operating two rigs in the play today where it has more than 200,000 prospective net acres. Eight of the wells drilled to date are located in the over-pressured Uteland Butte trend. Four wells had average gross initial production of approximately 1,200 BOEPD (87% oil) and an average gross 60-day rate of more than 550 BOEPD.
A fifth Uteland Butte well recently commenced production and is now producing 850 BOEPD and continues to clean-up after fracture stimulation. Five additional Uteland Butte wells are awaiting completion and will be on-line in the fourth quarter of 2012.
Wasatch – Since mid-2011, Newfield has drilled and completed more than 35 vertical wells in the Wasatch, a pressured formation more than 1,200’ thick and prevalent on approximately 60,000 net acres. The vertical wells to date have averaged initial gross production of nearly 900 BOEPD. The wells have averaged approximately 400 BOEPD, 275 BOEPD and 250 BOEPD over 30, 60 and 90 days, respectively.
The Company recently drilled and completed its first two horizontal Wasatch wells. The wells were located approximately five miles apart and were oriented in the upper-most prospective interval of the Wasatch. The wells had lateral lengths of approximately 3,200’ and average gross initial production of more than 1,200 BOEPD (88% oil). The wells averaged 750 BOEPD and 625 BOEPD over 60 and 90 days, respectively.
Lateral lengths on the Company’s horizontal wells drilled to date in the Uinta Basin average approximately 3,500’. Newfield is working with Utah state regulatory authorities for approval of a plan to drill longer laterals in the Uinta Basin as part of its overall development. In all resource plays where Newfield is active, longer laterals (up to 10,000’) have proven advantageous to reducing surface footprint, maximizing ultimate recoveries and improving overall returns.
Before year-end, the Company plans to drill six additional horizontal pressured wells in the Central Basin, targeting the Uteland Butte and Wasatch formations.
Williston Basin
Newfield’s net production in the Williston Basin achieved a recent high of more than 10,500 BOEPD. To date, the Company has completed 71 wells in the basin, of which 35 are super extended laterals (SXLs). The table below details all Newfield-operated Williston Basin wells drilled from 2010 through today:
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Well Type
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# Wells
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Avg. Gross IP
(24-Hours)
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Avg. Gross
30-Day Cum
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Avg. Gross
60-Day Cum
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Avg. Gross
90-Day Cum
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XL (<5,000’)
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36
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2,009 BOEPD
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19,552 BOE
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31,995 BOE
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40,120 BOE
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SXL (>5,000’)
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35
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2,524 BOEPD
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30,486 BOE
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49,524 BOE
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67,420 BOE
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3
Newfield’s focus in 2012 has been on improving execution at the field level. Year-to-date, Newfield has averaged about 25 days from spud to rig release in its Williston Basin program. During the third quarter, a “best-in-class” well was drilled and cased in 18 days. Completed well costs continue to reflect efficiency gains and the Company estimates that its 2013 wells can be drilled and completed for about $10 million gross.
Production from the Williston Basin is expected to increase more than 35% over 2011 levels. Three operated rigs are running today and a fourth rig will be added in early 2013. The Company has approximately 100,000 net acres in the Williston Basin and an expected inventory of more than 300 locations in the Bakken and Three Forks formations. During the quarter, Newfield initiated a detailed study taking cores through the Bakken and the multiple benches prevalent at deeper intervals. The data will be used to plan a future program to exploit the prospective Three Forks/Sanish formation.
Eagle Ford
Newfield has approximately 230,000 net acres in the Maverick Basin of Texas and has been active in Maverick, Zavala and Dimmit counties since 2010. In early 2012, Newfield commenced a program to test SXLs on its Eagle Ford acreage. Year-to-date, Newfield has drilled and completed four successful SXL wells with lateral lengths of approximately 7,500’ in Dimmit County. Newfield has a 100% working interest in all of the SXL wells drilled to date. Recent SXLs are being drilled and cased in as few as 12 days.
The four SXL wells had average initial gross production rates ranging from 750 BOEPD to 1,020 BOEPD gross (approximately 75% oil). Two of the wells have now been on-line for more than 180 days and have averaged 530 BOEPD gross. A third well has been on-line for 120 days, averaging approximately 800 BOEPD gross. Most recently, a fourth SXL well was completed and turned to sales. Over a 10-day period, the well has averaged 730 BOEPD gross. Newfield is currently completing its first 10,000’ lateral in Dimmit County.
Based on production data to date, Newfield estimates its SXL wells have a gross EUR of more than 500 MBOE.
In Atascosa County, Texas, the Company has an average 65% working interest in approximately 8,000 gross operated and outside-operated acres, which are held by production. An active drilling campaign is underway. The first well recently commenced production with an initial gross production rate of 615 BOEPD and average gross production of 483 BOEPD over 60 days. An additional six wells are expected to be online in early 2013.
International
Newfield’s net production from its international operations is today approximately 36,000 BOEPD. The Company’s production from offshore Malaysia has performed above expectations year-to-date and recently attained a new record of more than 78,000 BOEPD gross. Full-year oil/liquids liftings from international operations are expected to increase about 50% over 2011 levels.
4
Earlier this year, Newfield accelerated its planned development drilling at the East Piatu field and today is producing a record 23,000 BOEPD gross (13,000 BOEPD net). The field achieved “pay-out” over its first nine months of production. Additional drilling opportunities remain.
The East Belumut complex averaged 36,000 BOEPD gross and 14,000 BOEPD net during the third quarter. The Puteri field is producing approximately 6,000 BOPD gross (2,600 BOPD net).
Newfield is currently drilling the second and third wells of a planned three-well exploration program. Results are expected in early 2013.
In China, fabrication of offshore production facilities for the Company’s Pearl oil development, located in the Pearl River Mouth Basin, is on schedule for first sales in early 2014. The field is expected to produce approximately 15,000 BOPD net.
Full-Year 2012 Guidance
As previously announced, Newfield expects 2012 total Company production to be approximately 298 Bcfe. Our cost structure per Mcfe during 2012 is expected to be within 5% of the amounts listed below.
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2012 Estimates
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||||||||||||
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Domestic
|
Int’l
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Total
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||||||||||
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Production/Liftings Note 1
|
||||||||||||
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Natural gas – Bcf
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151.5 | 0.7 | 152.2 | |||||||||
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Oil, condensate and NGLs– MMBbls
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14.5 | 9.8 | 24.3 | |||||||||
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Total Bcfe
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238.5 | 59.5 | 298.0 | |||||||||
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Operating Expenses
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||||||||||||
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Lease operating (per Mcfe)
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||||||||||||
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Recurring
|
$ | 0.91 | $ | 1.75 | $ | 1.10 | ||||||
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Major (workovers, etc.) Note 2
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$ | 0.30 | $ | 0.30 | $ | 0.30 | ||||||
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Transportation
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$ | 0.45 | $ | – | $ | 0.37 | ||||||
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Production and other taxes (per Mcfe)
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$ | 0.35 | $ | 5.45 | $ | 1.25 | ||||||
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DD&A expense (per Mcfe) Note 3
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$ | 2.80 | $ | 4.25 | $ | 3.10 | ||||||
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General and administrative (G&A), net (per Mcfe)
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$ | 0.74 | ||||||||||
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Capitalized internal costs (per Mcfe)
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$ | (0.42 | ) | |||||||||
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|
||||||||||||
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Interest expense (per Mcfe)
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$ | 0.68 | ||||||||||
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Capitalized interest (per Mcfe)
|
$ | (0.25 | ) | |||||||||
______
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Note 1:
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Production/liftings is subject to timing and will vary by quarter.
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Note 2:
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The timing of “major expense” items varies and includes well workovers and repairs and related expenses.
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Note 3:
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The DD&A rate per Mcfe is reflective of the composition of the investments and reserves associated with our existing asset base and the assumed cost to add new reserves during the year. The timing and impact of the Company’s activities on this rate will vary by quarter.
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5
Newfield Exploration Company is an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids. Our principal domestic areas of operation include the Mid-Continent, the Rocky Mountains and onshore Texas. Internationally, we focus on offshore oil developments in Malaysia and China.
**This release contains forward-looking information. All information other than historical facts included in this release, such as information regarding estimated or anticipated drilling plans and planned capital expenditures, is forward-looking information. Although Newfield believes that these expectations are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. Actual results may vary significantly from those anticipated due to many factors, including drilling results, oil and gas prices, industry conditions, the prices of goods and services, the availability of drilling rigs and other support services, the availability of refining capacity for the crude oil Newfield produces in the Uinta Basin, the availability and cost of capital resources, new regulations or changes in tax legislation, labor conditions and severe weather conditions (such as hurricanes). In addition, the drilling of oil and natural gas wells and the production of hydrocarbons are subject to numerous governmental regulations and operating risks. Other factors that could impact forward-looking statements are described in "Risk Factors" in Newfield's 2011 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other subsequent public filings with the Securities and Exchange Commission, which can be found at www.sec.gov. Unpredictable or unknown factors not discussed in this press release could also have material adverse effects on forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Unless legally required, Newfield undertakes no obligation to publicly update or revise any forward-looking statements.
For additional information, please contact Newfield’s Investor Relations department.
Phone: 281-210-5201
Email: info@newfield.com
6
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3Q12 Actual
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||||||||||||
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3Q 12 Actual Results
|
Domestic
|
Int’l
|
Total
|
|||||||||
|
Production/Liftings Note 1
|
||||||||||||
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Natural Gas – Bcf
|
38.4 | 0.3 | 38.7 | |||||||||
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Oil, condensate and NGLs – MMBbls
|
3.8 | 2.3 | 6.1 | |||||||||
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Total Bcfe
|
61.3 | 14.2 | 75.5 | |||||||||
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Average Realized Prices Note 2
|
||||||||||||
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Natural Gas - $/Mcf
|
$ | 3.56 | $ | 3.89 | $ | 3.57 | ||||||
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Oil, condensate and NGLs - $/Bbl
|
$ | 72.25 | $ | 104.67 | $ | 84.50 | ||||||
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Mcf equivalent - $/Mcfe
|
$ | 6.82 | $ | 17.17 | $ | 8.81 | ||||||
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Operating Expenses:
|
||||||||||||
|
Lease operating ($MM)
|
||||||||||||
|
Recurring
|
$ | 55.9 | $ | 27.7 | $ | 83.6 | ||||||
|
Major (workovers, etc.)
|
$ | 16.1 | $ | 1.7 | $ | 17.8 | ||||||
|
Transportation
|
$ | 27.0 | $ | – | $ | 27.0 | ||||||
|
Lease operating (per Mcfe)
|
||||||||||||
|
Recurring
|
$ | 0.94 | $ | 1.95 | $ | 1.13 | ||||||
|
Major (workovers, etc.)
|
$ | 0.27 | $ | 0.12 | $ | 0.24 | ||||||
|
Transportation
|
$ | 0.46 | $ | – | $ | 0.37 | ||||||
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Production and other taxes ($MM)
|
$ | 16.8 | $ | 62.1 | $ | 78.9 | ||||||
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per Mcfe
|
$ | 0.28 | $ | 4.37 | $ | 1.07 | ||||||
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General and administrative (G&A), net ($MM)
|
$ | 57.3 | $ | 1.6 | $ | 58.9 | ||||||
|
per Mcfe
|
$ | 0.96 | $ | 0.11 | $ | 0.80 | ||||||
|
Capitalized internal costs $MM)
|
$ | (29.3 | ) | |||||||||
|
per Mcfe
|
$ | (0.40 | ) | |||||||||
|
Interest expense ($MM)
|
$ | 53.4 | ||||||||||
|
per Mcfe
|
$ | 0.72 | ||||||||||
|
Capitalized interest ($MM)
|
$ | (17.3 | ) | |||||||||
|
per Mcfe
|
$ | (0.23 | ) | |||||||||
|
Note 1:
|
Represents volumes lifted and sold regardless of when produced. Includes natural gas produced and consumed in our operations of 1.7 Bcfe during the three months ended September 30, 2012.
|
|
Note 2:
|
Average realized prices include the effects of hedging contracts. If the effects of these contracts were excluded, the average realized price for domestic and total natural gas would have been $2.64 and $2.65 per Mcf, respectively and the domestic and total oil and condensate average realized prices would have been $71.45 and $84.01 per barrel, respectively.
|
7
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|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENT OF NET INCOME
|
|
|
|
|
|
|
|
|
|
||
|
(Unaudited, in millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the
Three Months Ended
September 30,
|
|
For the
Nine Months Ended
September 30,
|
||||||||
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues
|
$
|
615
|
|
$
|
628
|
|
$
|
1,921
|
|
$
|
1,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
128
|
|
115
|
|
|
384
|
|
|
333
|
|
|
Production and other taxes
|
|
79
|
|
|
95
|
|
|
250
|
|
|
245
|
|
Depreciation, depletion and amortization
|
|
237
|
|
|
189
|
|
|
702
|
|
|
528
|
|
General and administrative
|
|
59
|
|
|
51
|
|
|
165
|
|
|
132
|
|
Other
|
|
6
|
|
|
—
|
|
|
6
|
|
|
—
|
|
Total operating expenses
|
|
509
|
|
|
450
|
|
|
1,507
|
|
|
1,238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
106
|
|
|
178
|
|
|
414
|
|
|
556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
(53)
|
|
|
(43)
|
|
|
(153)
|
|
|
(124)
|
|
Capitalized interest
|
|
17
|
|
|
24
|
|
|
53
|
|
|
61
|
|
Commodity derivative income (expense)
|
|
(98)
|
|
|
262
|
|
|
61
|
|
|
249
|
|
Other
|
|
(16)
|
|
|
3
|
|
|
(18)
|
|
|
2
|
|
Total other income (expense)
|
|
(150)
|
|
|
246
|
|
|
(57)
|
|
|
188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
(44)
|
|
|
424
|
|
|
357
|
|
|
744
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision (benefit)
|
|
(11)
|
|
|
155
|
|
|
139
|
|
|
273
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
$
|
(33)
|
|
$
|
269
|
|
$
|
218
|
|
$
|
471
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.24)
|
|
$
|
2.00
|
|
$
|
1.62
|
|
$
|
3.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
$
|
(0.24)
|
|
$
|
1.99
|
|
$
|
1.61
|
|
$
|
3.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average number of shares outstanding for basic earnings (loss) per share
|
|
135
|
|
|
134
|
|
|
134
|
|
|
134
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average number of shares outstanding for diluted earnings (loss) per share
|
|
135
|
|
|
135
|
|
|
135
|
|
|
135
|
8
|
|
|
|
||||||
|
CONDENSED CONSOLIDATED BALANCE SHEET
|
|
|
||||||
|
(Unaudited, in millions)
|
|
|
||||||
|
|
September 30,
|
December 31,
|
||||||
|
|
2012
|
2011
|
||||||
|
ASSETS
|
|
|
||||||
|
Current assets:
|
|
|
||||||
|
Cash and cash equivalents
|
$ | 125 | $ | 76 | ||||
|
Derivative assets
|
88 | 129 | ||||||
|
Other current assets
|
646 | 570 | ||||||
|
Total current assets
|
859 | 775 | ||||||
|
|
||||||||
|
Property and equipment, net (full cost method)
|
8,406 | 8,020 | ||||||
|
Derivative assets
|
22 | 61 | ||||||
|
Other assets
|
144 | 135 | ||||||
|
Total assets
|
$ | 9,431 | $ | 8,991 | ||||
|
|
||||||||
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
||||||||
|
Current liabilities:
|
||||||||
|
Derivative liabilities
|
$ | 19 | $ | 50 | ||||
|
Other current liabilities
|
880 | 882 | ||||||
|
Total current liabilities
|
899 | 932 | ||||||
|
|
||||||||
|
Other liabilities
|
185 | 179 | ||||||
|
Derivative liabilities
|
16 | 3 | ||||||
|
Long-term debt
|
3,190 | 3,006 | ||||||
|
Deferred taxes
|
973 | 951 | ||||||
|
Total long-term liabilities
|
4,364 | 4,139 | ||||||
|
|
||||||||
|
|
||||||||
|
STOCKHOLDERS' EQUITY
|
||||||||
|
Common stock and additional paid-in capital
|
1,474 | 1,446 | ||||||
|
Accumulated other comprehensive loss
|
(8 | ) | (10 | ) | ||||
|
Retained earnings
|
2,702 | 2,484 | ||||||
|
Total stockholders' equity
|
4,168 | 3,920 | ||||||
|
Total liabilities and stockholders' equity
|
$ | 9,431 | $ | 8,991 | ||||
|
|
||||||||
9
|
|
|
|||||||
|
CONDENSED CONSOLIDATED STATEMENT OF
CASH FLOWS
|
|
|||||||
|
(Unaudited, in millions)
|
|
|
||||||
|
|
For the
Nine Months Ended
September 30,
|
|||||||
|
|
2012
|
2011
|
||||||
|
Cash flows from operating activities:
|
|
|
||||||
|
Net income
|
$ | 218 | $ | 471 | ||||
|
Adjustments to reconcile net income to net cash
|
||||||||
|
provided by operating activities:
|
||||||||
|
Depreciation, depletion and amortization
|
702 | 528 | ||||||
|
Deferred tax provision
|
5 | 234 | ||||||
|
Stock-based compensation
|
27 | 20 | ||||||
|
Commodity derivative income
|
(61 | ) | (249 | ) | ||||
|
Cash receipts on derivative settlements, net
|
123 | 156 | ||||||
|
Other non-cash charges
|
11 | 2 | ||||||
|
|
1,025 | 1,162 | ||||||
|
Changes in operating assets and liabilities
|
(221 | ) | 11 | |||||
|
Net cash provided by operating activities
|
804 | 1,173 | ||||||
|
|
||||||||
|
Cash flows from investing activities:
|
||||||||
|
Additions to oil and gas properties and other
|
(1,294 | ) | (1,746 | ) | ||||
|
Acquisitions of oil and gas properties
|
(9 | ) | (299 | ) | ||||
|
Proceeds from sales of oil and gas properties
|
382 | 202 | ||||||
|
Redemptions of investments
|
— | 1 | ||||||
|
Net cash used in investing activities
|
(921 | ) | (1,842 | ) | ||||
|
|
||||||||
|
Cash flows from financing activities:
|
||||||||
|
Net proceeds (repayments) under credit arrangements
|
59 | (69 | ) | |||||
|
Proceeds from issuance of senior notes
|
1,000 | 750 | ||||||
|
Repayment of senior subordinated notes
|
(875 | ) | — | |||||
|
Other
|
(18 | ) | (20 | ) | ||||
|
Net cash provided by financing activities
|
166 | 661 | ||||||
|
|
||||||||
|
Increase (decrease) in cash and cash equivalents
|
49 | (8 | ) | |||||
|
Cash and cash equivalents, beginning of period
|
76 | 39 | ||||||
|
Cash and cash equivalents, end of period
|
$ | 125 | $ | 31 | ||||
|
|
||||||||
10
Explanation and Reconciliation of Non-GAAP Financial Measures
Earnings Stated Without the Effect of Certain Items
Earnings stated without the effect of certain items is a non-GAAP financial measure. Newfield discloses earnings without the effect of certain items because it affects the comparability of operating results from period to period. In addition, earnings without the effect of certain items is more comparable to earnings estimates provided by securities analysts.
A reconciliation of earnings for the third quarter of 2012 stated without the effect of certain items to net income is shown below:
|
|
|
|
3Q12
|
|
|
|
|
|
(in millions)
|
|
|
Net income (loss)
|
$
|
(33)
|
||
|
|
Net unrealized loss on commodity derivatives(1)
|
|
135
|
|
|
Non-recurring expenses
|
20
|
|||
|
|
Income tax adjustment for above items
|
|
(57)
|
|
|
Earnings stated without the effect of the above items
|
$
|
65
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) The determination of "Net unrealized loss on commodity derivatives" for the third quarter 2012 is as follows:
|
||||
|
|
|
|
|
|
3Q12
|
|
|
|
|
|
|
(in millions)
|
|
Commodity derivative expense
|
$
|
(98)
|
|||
|
Cash receipts on derivative settlements, net
|
|
(37)
|
|||
|
|
|
Net unrealized loss on commodity derivatives
|
$
|
(135)
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities Before Changes in Operating Assets and Liabilities
Net cash provided by operating activities before changes in operating assets and liabilities is presented because of its acceptance as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. This measure should not be considered as an alternative to net cash provided by operating activities as defined by generally accepted accounting principles.
A reconciliation of net cash provided by operating activities before changes in operating assets and liabilities to net cash provided by operating activities is shown below:
|
|
|
|
3Q12
|
||
|
|
|
|
(in millions)
|
||
|
Net cash provided by operating activities
|
|
$
|
229
|
||
|
|
Net change in operating assets and liabilities
|
|
|
79
|
|
|
Net cash provided by operating activities before changes
|
|
|
|
||
|
|
in operating assets and liabilities
|
|
$
|
308
|
|
11