Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - NEWFIELD EXPLORATION CO /DE/ | nfx8k-072011.htm |
| EX-99.2 - EXHIBIT 99.2 - NEWFIELD EXPLORATION CO /DE/ | ex992.htm |
| EX-99.3 - EXHIBIT 99.3 - NEWFIELD EXPLORATION CO /DE/ | ex993.htm |
Exhibit 99.1
Newfield Reports Second Quarter 2011 Financial and Operating Results
FOR IMMEDIATE RELEASE
Houston – July 20, 2011 – Newfield Exploration Company (NYSE: NFX) today reported its unaudited second quarter 2011 financial and operating results. Newfield will be hosting a conference call at 8:30 a.m. CT on July 21, 2011. To participate in the call, dial 719-325-4774 or listen through the investor relations section of our website at http://www.newfield.com.
For the second quarter of 2011, Newfield recorded net income of $219 million, or $1.62 per diluted share (all per share amounts are on a diluted basis). Net income for the second quarter includes a net unrealized gain on commodity derivatives of $129 million ($81 million after-tax), or $0.60 per share. Without the effect of this item, net income for the second quarter of 2011 would have been $138 million, or $1.02 per share.
Revenues in the second quarter of 2011 were $621 million. Net cash provided by operating activities before changes in operating assets and liabilities was $393 million. See “Explanation and Reconciliation of Non-GAAP Financial Measures” found after the financial statements in this release.
Newfield’s production in the second quarter of 2011 was 73 Bcfe. Natural gas production in the second quarter of 2011 was 47 Bcf, an average of 517 MMcf/d. Newfield’s oil liftings and liquids production in the second quarter of 2011 were 4.4 MMBbls, or an average of approximately 48,000 BOPD. Capital expenditures in the second quarter of 2011 were approximately $630 million, excluding the Company’s $300 million acquisition in the Uinta Basin.
2011 Capital Investments, Asset Sales
Newfield reiterated its 2011 capital budget of $1.9 billion. The budget excludes capitalized interest and overhead and the May 2011 closing of the Company’s acquisition in the Uinta Basin. Year-to-date, Newfield has divested approximately $130 million in non-strategic domestic assets. The Company continues to market and sell other certain non-strategic domestic assets with total proceeds during 2011 expected to range from $200 – $300 million.
2011 Production Guidance
The sale of non-strategic assets year-to-date has reduced 2011 production by approximately 3 Bcfe. As previously disclosed, second quarter 2011 production was negatively impacted by approximately 0.2 MMBbls of deferred production due to repairs on the Abu field, located offshore Malaysia. Repairs have been completed and the field is on-line today. For the full year, Newfield expects that its production will exceed 312 Bcfe. The Company’s original production guidance was 312 – 323 Bcfe, or an increase of at least 8% over 2010 volumes. The expectation of at least 8% growth does not include adjustments for any additional sales of non-strategic assets in the second half of 2011. A table on Newfield’s production guidance for 2011 is provided within this release.
1
Year-to-Date 2011 Operating Highlights:
Rocky Mountains
Uinta Basin – In conjunction with the release of its second quarter earnings and operating results, the Company today provided a comprehensive update on its Uinta Basin drilling programs, including the disclosure of new oil plays available for development. Recent acquisitions have increased the Company’s acreage position to approximately 250,000 net acres. Over the coming months, the Company expects to increase its operated rig count from a historic five-rig program to at least eight rigs in 2012. As a result, oil production growth from the region is expected to increase more than 25% in 2012. A copy of the recent release and other detailed information on the Uinta Basin can be obtained through Newfield’s website.
Williston Basin – During the second quarter of 2011, Newfield completed nine new wells in the Williston Basin. The recent completions boosted net production to 8,000 BOEPD. Newfield continues to run five operated drilling rigs in the Williston Basin where the Company has approximately 150,000 net acres.
Of the recent completions, eight of the nine wells were super extended laterals and had an average lateral length of more than 9,500’. Average gross initial production (24-hour) from the nine wells completed in the second quarter was 2,100 BOEPD. The wells were drilled and completed for an average of approximately $9.8 million (gross).
Recent results include a “Company-best” – the Wiseness Federal 152-96-4-2H, which had gross initial production (24-hour average) of 5,200 BOEPD. The well has a 5,300’ lateral and was drilled and completed for approximately $5.9 million (gross).
Significant flooding, poor road conditions and road closures in the Williston Basin impacted the timing of planned operations during the second quarter. The Company has an inventory of 10 wells that have been drilled and are in various stages of completion. Newfield expects to complete a total of 13 wells in the third quarter of 2011.
Southern Alberta Basin – To date, Newfield has drilled seven vertical wells and has completed and placed on production two horizontal wells. Fracture stimulation services are in the region today executing on a program to stimulate and test multiple geologic horizons in up to four of the vertical wells. All of the wells to date have encountered oil. Newfield has approximately 320,000 net acres in the play, located in Glacier County, Montana.
Mid-Continent
Granite Wash – Newfield recently set a new record high for its Granite Wash production – 190 MMcfe/d gross (135 MMcfe/d net). This is an increase over the 110 MMcfe/d net reported at the end of the first quarter of 2011. Since early 2009, Newfield has maintained a four-rig development drilling program in the Granite Wash, with its activities primarily located in Wheeler County, Texas.
To date, the Company has completed 47 wells in the play with gross initial production averaging approximately 16 MMcfe/d (24-hour rate). The 2011 Granite Wash program is focused on the Marmaton DE and FG intervals. Year-to-date, wells in these “liquids rich” intervals have had average initial gross production of approximately 17 MMcfe/d.
Throughout 2011, the Company’s drilling personnel have continued to deliver efficiency gains. During the second quarter, Newfield drilled and cased a “best in class” well in 24 days and is averaging approximately 28 days with recent wells. Completed well costs vary by lateral length (5,000’ – 8,000’) and range from $8 – $13 million.
For 2011, the Company plans to drill more than 30 wells and grow production more than 25% over 2010. Newfield’s average working interest in the Granite Wash play is approximately 75%.
2
Onshore Texas
Eagle Ford Shale – Newfield continues to explore and assess its 335,000 net acre position in the Maverick Basin. Oil field services in the region today remain tight. The Company expects that it can meet its contractual drilling obligations and hold its leases by running one to two rigs in the play through the remainder of 2011. By limiting activity to this level, capital can be redirected to the Uinta Basin where the Company is adding operated rigs. We continue to assess and increase our understanding of the Eagle Ford Shale, as well as other prospective formations including the Georgetown and Pearsall.
Year-to-date, the Company has completed 13 wells in the Eagle Ford Shale, four wells in the Georgetown formation and two wells in the Pearsall Shale. Current gross production from the Maverick Basin is approximately 6,500 BOEPD. Newfield’s average working interest in the region is approximately 80%.
Recent drilling activity in the Eagle Ford has focused on the “southern” portion of the Company’s acreage. An area up to 50,000 acres is now being developed along existing infrastructure. A pilot program is underway with recent wells being drilled from pad locations to help determine optimal well spacing. The wells have been drilled in as few as seven days and gross completed well costs have averaged approximately $6.6 million. Initial 24-hour gross production rates from recent wells have ranged from 400 – 1,400 BOEPD.
The Company recently commenced production from a Pearsall Shale horizontal completion at a pipeline-restricted rate of 4.4 MMcf/d and 6,800 psi of flowing tubing pressure (gross). Newfield’s working interest in the Pearsall play averages more than 70%. A recent Georgetown completion commenced production at more than 500 BOEPD (gross). The well was drilled and completed for approximately $1.3 million (gross). Newfield’s working interest in the Georgetown is averages more than 70%.
International Oil Developments
Second quarter 2011 net liftings from the Company’s oil assets in Southeast Asia were 1.2 MMBbls, or an average of about 13,500 BOPD. The largest contributor to Newfield’s international oil production was Malaysia where net liftings during the period averaged approximately 11,200 BOPD. Second quarter 2011 production from Malaysia was negatively impacted by approximately 0.2 MMBbls due to infrastructure damage in the Abu field. Repairs were recently completed and the field has resumed production.
The Company’s production from the East Belumut facility, located at PM 323, has attained recent highs and has averaged approximately 32,000 BOPD (gross) over the last month. On PM 329, the East Piatu development is expected to commence production at about 10,000 BOPD (gross) in late 2011. Newfield has a 70% interest in East Piatu.
Deepwater Gulf of Mexico
The Company’s deepwater Gulf of Mexico production in the second quarter of 2011 was 9 Bcfe, or nearly 95 MMcfe/d. Pyrenees, located at Garden Banks 293, is expected to commence production in late 2011 at approximately 50 MMcf/d and 2,400 BCPD (gross). Outside operated developments, Axe and Dalmatian, are scheduled for first production in 2013.
3
TABLE: 2011 Production Guidance
|
BCFE
|
|
|
Original Production Guidance
|
312-323
|
|
Non-strategic asset sales thru 6/30/11*
|
(3)
|
|
Weather related issues YTD (Rockies, Mid-Continent)
|
(2)
|
|
Abu FSO repairs
|
(1.2)
|
|
Other
|
(.8)
|
|
Updated Production Guidance
|
312-316
|
*Asset sales were not included in the Company’s original production guidance. Additional sales are anticipated in the second half of 2011.
Newfield Exploration Company is an independent crude oil and natural gas exploration and production company. The Company relies on a proven growth strategy of growing reserves through an active drilling program and select acquisitions. Newfield's domestic areas of operation include the Mid-Continent, the Rocky Mountains, onshore Texas, Appalachia and the Gulf of Mexico. The Company has international operations 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 from its Monument Butte field in Utah, the availability and cost of capital resources, labor conditions and severe weather conditions (such as hurricanes). In addition, the drilling of oil and gas wells and the production of hydrocarbons are subject to governmental regulations and operating risks. Other factors that could impact forward-looking statements are described in "Risk Factors" in Newfield's 2010 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 information, contact:
Investor Relations: Steve Campbell (281) 847-6081
Danny Aguirre (281) 668-2657
Media Relations: Keith Schmidt (281) 674-2650
Email: info@newfield.com
4
2Q11 Actual Results
|
2Q11 Actual
|
||||||||||||
|
Domestic
|
Int’l
|
Total
|
||||||||||
|
Production/Liftings
|
||||||||||||
|
Natural gas – Bcf
|
47.0 | – | 47.0 | |||||||||
|
Oil, condensate and NGLs – MMBbls
|
3.2 | 1.2 | 4.4 | |||||||||
|
Total Bcfe
|
65.9 | 7.3 | 73.2 | |||||||||
|
Average Realized Prices Note 1
|
||||||||||||
|
Natural gas – $/Mcf
|
$ | 5.77 | $ | – | $ | 5.77 | ||||||
|
Oil, condensate and NGLs – $/Bbl
|
$ | 80.39 | $ | 118.72 | $ | 91.16 | ||||||
|
Mcf equivalent – $/Mcfe
|
$ | 8.03 | $ | 19.79 | $ | 9.24 | ||||||
|
Operating Expenses:
|
||||||||||||
|
Lease operating ($MM)
|
||||||||||||
|
Recurring
|
$ | 56.6 | $ | 14.9 | $ | 71.5 | ||||||
|
Major (workovers, etc.)
|
$ | 10.5 | $ | 18.8 | $ | 29.3 | ||||||
|
Transportation
|
$ | 23.6 | $ | – | $ | 23.6 | ||||||
|
Lease operating (per Mcfe)
|
||||||||||||
|
Recurring
|
$ | 0.88 | $ | 2.02 | $ | 1.00 | ||||||
|
Major (workovers, etc.)
|
$ | 0.16 | $ | 2.55 | $ | 0.41 | ||||||
|
Transportation
|
$ | 0.37 | $ | – | $ | 0.33 | ||||||
|
Production and other taxes ($MM)
|
$ | 22.1 | $ | 56.9 | $ | 79.0 | ||||||
|
per/Mcfe
|
$ | 0.34 | $ | 7.73 | $ | 1.10 | ||||||
|
General and administrative (G&A), net ($MM)
|
$ | 42.6 | $ | 1.7 | $ | 44.3 | ||||||
|
per/Mcfe
|
$ | 0.66 | $ | 0.24 | $ | 0.62 | ||||||
|
Capitalized internal costs ($MM)
|
$ | (27.1 | ) | |||||||||
|
per/Mcfe
|
$ | (0.38 | ) | |||||||||
|
Interest Expense ($MM)
|
$ | 41.7 | ||||||||||
|
per/Mcfe
|
$ | 0.58 | ||||||||||
|
Capitalized Interest ($MM)
|
$ | (19.4 | ) | |||||||||
|
per/Mcfe
|
$ | (0.27 | ) | |||||||||
|
|
Note 1: Average realized prices include the effects of hedging contracts. If the effects of these contracts were excluded, the average realized price for total gas would have been $4.42 per Mcf and the domestic and total oil and condensate average realized prices would have been $87.03 and $95.94 per barrel, respectively.
|
5
|
3Q11 & FY11 Estimates
|
||||||||||||||||||||||||
|
Domestic
|
Int’l
|
Total
|
||||||||||||||||||||||
|
Production/Liftings
|
3QE
|
FY11
|
3QE
|
FY11
|
3QE
|
FY11
|
||||||||||||||||||
|
Natural gas – Bcf
|
45 – 49 | 188 – 190 | – | 0.2 – 0.2 | 45 – 49 | 189 – 190 | ||||||||||||||||||
|
Oil, condensate and NGLs – MMBbls
|
3.4 – 4.0 | 14.1 – 14.4 | 1.4 – 2.0 | 6.5 – 6.6 | 4.8 – 5.9 | 20.6 – 21.0 | ||||||||||||||||||
|
Total Bcfe
|
65 – 73 | 273 – 276 | 8 – 12 | 39 – 40 | 74 – 84 | 312 – 316 | ||||||||||||||||||
|
Average Realized Prices
|
||||||||||||||||||||||||
|
Natural gas – $/Mcf
|
Note 1
|
Note 1
|
||||||||||||||||||||||
|
Oil, condensate and NGLs – $/Bbl
|
Note 2
|
Note 2
|
Note 3
|
Note 3
|
||||||||||||||||||||
|
Mcf equivalent – $/Mcfe
|
||||||||||||||||||||||||
|
Operating Expenses (per Mcfe):
|
||||||||||||||||||||||||
|
Lease Operating
|
||||||||||||||||||||||||
|
Recurring
|
$ | 0.74 - $0.86 | $ | 0.72 - $0.87 | $ | 1.75 - $2.22 | $ | 1.55 - $1.93 | $ | 0.87 - $1.04 | $ | 0.82 - $1.00 | ||||||||||||
|
Major (workovers, etc.)
|
$ | 0.21 - $0.29 | $ | 0.14 - $0.18 | $ | 0.36 - $0.48 | $ | 0.64 - $0.83 | $ | 0.23 - $0.31 | $ | 0.20 - $0.26 | ||||||||||||
|
Transportation
|
$ | 0.30 - $0.39 | $ | 0.31 - $0.40 | - | - | $ | 0.26 - $0.34 | $ | 0.27 - $0.35 | ||||||||||||||
|
Production/Taxes Note 4
|
$ | 0.33 - $0.42 | $ | 0.29 - $0.39 | $ | 4.74 - $5.77 | $ | 4.96 - $6.23 | $ | 0.90 - $1.10 | $ | 0.86 - $1.11 | ||||||||||||
|
G&A, net
|
$ | 0.62 - $0.75 | $ | 0.55 - $0.72 | $ | 0.16 - $0.21 | $ | 0.15 - $0.19 | $ | 0.56 - $0.68 | $ | 0.50 - $0.65 | ||||||||||||
|
Capitalized internal costs
|
$ | (0.33 - $0.40 | ) | $ | (0.30 - $0.38 | ) | ||||||||||||||||||
|
Interest Expense
|
$ | 0.51 - $0.60 | $ | 0.51 - $0.55 | ||||||||||||||||||||
|
Capitalized Interest
|
$ | (0.23 - $0.30 | ) | $ | (0.22 - $0.27 | ) | ||||||||||||||||||
|
Tax rate (%)Note 5
|
36% - 38 | % | 36% - 38 | % | ||||||||||||||||||||
|
Income taxes (%)
|
||||||||||||||||||||||||
|
Current
|
18% - 22 | % | 18% - 22 | % | ||||||||||||||||||||
|
Deferred
|
78% - 82 | % | 78% - 82 | % | ||||||||||||||||||||
|
Note 1:
|
The price that the Company receives for natural gas production from the Gulf of Mexico and onshore Gulf Coast, after basis differentials, transportation and handling charges, typically averages $0.25 - $0.50 per MMBtu less than the Henry Hub Index. Realized natural gas prices for our Mid-Continent properties, after basis differentials, transportation and handling charges, typically average 90-95% of the Henry Hub Index.
|
|||||||||||||||||||||||
|
Note 2:
|
The price the Company receives for its Gulf Coast oil production, excluding NGLs, typically averages about 98-102% of the NYMEX West Texas Intermediate (WTI) price. The price the Company receives for its oil production in the Rocky Mountains, excluding NGLs, is currently averaging about $15-$17 per barrel below the WTI price. Oil production from the Company’s Mid-Continent properties, excluding NGLs, typically averages 90-95% of the WTI price.
|
|||||||||||||||||||||||
|
Note 3:
|
Oil sales from the Company’s operations in Malaysia typically sell at a slight discount to Tapis, or today about 110-115% of WTI. Oil sales from the Company’s operations in China typically sell at a premium of up to $10 per barrel greater than the WTI price.
|
|||||||||||||||||||||||
|
Note 4:
|
Guidance for production taxes determined using the average of the strip at 06/21/11 ($94.54/bbl, $4.50/mcf).
|
|||||||||||||||||||||||
|
Note 5:
|
Tax rate applied to earnings excluding unrealized gains or losses on commodity derivatives.
|
|||||||||||||||||||||||
6
|
CONSOLIDATED STATEMENT OF INCOME
(Unaudited, in millions, except per share data)
|
For the Three
Months Ended
June 30,
|
For the Six
Months Ended
June 30,
|
||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
|||||||||||||
|
Oil and gas revenues
|
$ | 621 | $ | 448 | $ | 1,166 | $ | 906 | ||||||||
|
Operating expenses:
|
||||||||||||||||
|
Lease operating
|
125 | 84 | 218 | 151 | ||||||||||||
|
Production and other taxes
|
79 | 31 | 150 | 56 | ||||||||||||
|
Depreciation, depletion and amortization
|
173 | 160 | 339 | 307 | ||||||||||||
|
General and administrative
|
44 | 41 | 81 | 77 | ||||||||||||
|
Other
|
- | 2 | - | 10 | ||||||||||||
|
Total operating expenses
|
421 | 318 | 788 | 601 | ||||||||||||
|
Income from operations
|
200 | 130 | 378 | 305 | ||||||||||||
|
Other income (expenses):
|
||||||||||||||||
|
Interest expense
|
(41 | ) | (39 | ) | (81 | ) | (77 | ) | ||||||||
|
Capitalized interest
|
19 | 16 | 37 | 28 | ||||||||||||
|
Commodity derivative income (expense)
|
169 | 46 | (13 | ) | 283 | |||||||||||
|
Other
|
- | (1 | ) | (1 | ) | 1 | ||||||||||
|
Total other income (expenses)
|
147 | 22 | (58 | ) | 235 | |||||||||||
|
Income before income taxes
|
347 | 152 | 320 | 540 | ||||||||||||
|
Income tax provision
|
128 | 56 | 118 | 200 | ||||||||||||
|
Net income
|
$ | 219 | $ | 96 | $ | 202 | $ | 340 | ||||||||
|
Earnings per share:
|
||||||||||||||||
|
Basic --
|
$ | 1.64 | $ | 0.73 | $ | 1.52 | $ | 2.59 | ||||||||
|
Diluted --
|
$ | 1.62 | $ | 0.72 | $ | 1.50 | $ | 2.55 | ||||||||
|
Weighted-average number of shares outstanding
for basic earnings per share
|
134 | 132 | 133 | 131 | ||||||||||||
|
Weighted-average number of shares outstanding
for diluted earnings per share
|
135 | 134 | 135 | 133 | ||||||||||||
7
|
CONDENSED CONSOLIDATED BALANCE SHEET
(Unaudited, in millions)
|
June 30,
2011
|
December 31,
2010
|
||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 74 | $ | 39 | ||||
|
Derivative assets
|
128 | 197 | ||||||
|
Other current assets
|
546 | 495 | ||||||
|
Total current assets
|
748 | 731 | ||||||
|
Property and equipment, net (full cost method)
|
7,564 | 6,608 | ||||||
|
Derivative assets
|
35 | 39 | ||||||
|
Other assets
|
134 | 116 | ||||||
|
Total assets
|
$ | 8,481 | $ | 7,494 | ||||
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
||||||||
|
Current liabilities:
|
||||||||
|
Current liabilities
|
$ | 896 | $ | 875 | ||||
|
Derivative liabilities
|
65 | 53 | ||||||
|
Total current liabilities
|
961 | 928 | ||||||
|
Other liabilities
|
163 | 153 | ||||||
|
Derivative liabilities
|
69 | 46 | ||||||
|
Long-term debt
|
2,889 | 2,304 | ||||||
|
Deferred taxes
|
837 | 720 | ||||||
|
Total long-term liabilities
|
3,958 | 3,223 | ||||||
|
STOCKHOLDERS’ EQUITY
|
||||||||
|
Common stock and additional paid-in capital
|
1,423 | 1,410 | ||||||
|
Accumulated other comprehensive loss
|
(8 | ) | (12 | ) | ||||
|
Retained earnings
|
2,147 | 1,945 | ||||||
|
Total stockholders’ equity
|
3,562 | 3,343 | ||||||
|
Total liabilities and stockholders’ equity
|
$ | 8,481 | $ | 7,494 | ||||
8
|
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited, in millions)
|
For the
Six Months Ended
June 30,
|
|||||||
|
2011
|
2010
|
|||||||
|
Cash flows from operating activities:
|
||||||||
|
Net income
|
$ | 202 | $ | 340 | ||||
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
||||||||
|
Depreciation, depletion and amortization
|
339 | 307 | ||||||
|
Deferred tax provision
|
88 | 173 | ||||||
|
Stock-based compensation
|
14 | 12 | ||||||
|
Commodity derivative (income) expense
|
13 | (283 | ) | |||||
|
Cash receipts on derivative settlements, net
|
95 | 227 | ||||||
|
Other
|
3 | — | ||||||
| 754 | 776 | |||||||
|
Net changes in operating assets and liabilities
|
(25 | ) | 112 | |||||
|
Net cash provided by operating activities
|
729 | 888 | ||||||
|
Cash flows from investing activities:
|
||||||||
|
Additions to oil and gas properties and other, net
|
(1,087 | ) | (774 | ) | ||||
|
Acquisitions of oil and gas properties
|
(311 | ) | (219 | ) | ||||
|
Proceeds from sales of oil and gas properties
|
130 | 14 | ||||||
|
Redemptions of investments
|
1 | 5 | ||||||
|
Net cash used in investing activities
|
(1,267 | ) | (974 | ) | ||||
|
Cash flows from financing activities:
|
||||||||
|
Net proceeds (repayments) under credit arrangements
|
585 | (385 | ) | |||||
|
Net proceeds from issuance of senior subordinated notes
|
— | 694 | ||||||
|
Repayment of senior notes
|
— | (175 | ) | |||||
|
Other
|
(12 | ) | (4 | ) | ||||
|
Net cash provided by financing activities
|
573 | 130 | ||||||
|
Increase in cash and cash equivalents
|
35 | 44 | ||||||
|
Cash and cash equivalents, beginning of period
|
39 | 78 | ||||||
|
Cash and cash equivalents, end of period
|
$ | 74 | $ | 122 | ||||
9
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. Earnings without the effect of these items are presented because they affect the comparability of operating results from period to period. In addition, earnings without the effect of these items are more comparable to earnings estimates provided by securities analysts.
A reconciliation of earnings for the second quarter of 2011 stated without the effect of certain items to net income is shown below:
| 2Q11 | ||||
| (in millions) | ||||
|
Net income
|
$ | 219 | ||
|
Net unrealized gain on commodity derivatives (1)
|
(129 | ) | ||
|
Income tax adjustment for above item
|
48 | |||
|
Earnings stated without the effect of the above items
|
$ | 138 | ||
(1) The determination of “Net unrealized gain on commodity derivatives” for the second quarter of 2011 is as follows:
| 2Q11 | ||||
|
(in millions)
|
||||
|
Commodity derivative income
|
$ | 169 | ||
|
Cash receipts on derivative settlements, net
|
(40 | ) | ||
|
Net unrealized gain on commodity derivatives
|
$ | 129 | ||
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:
| 2Q11 | ||||
|
(in millions)
|
||||
|
Net cash provided by operating activities
|
$ | 420 | ||
|
Net change in operating assets and liabilities
|
(27 | ) | ||
|
Net cash provided by operating activities before changes
in operating assets and liabilities
|
$ | 393 | ||
10