Total sales volumes for the quarter averaged a record 302 thousand barrels of oil equivalent per day (MBoe/d). This represents an increase of three percent compared to the third quarter of 2013, or 10 percent after adjusting for divested assets. Liquids comprised 43 percent (33 percent crude oil and condensate and 10 percent natural gas liquids) of third quarter 2014 volumes, with natural gas volumes the remaining 57 percent. U.S. sales volumes for the quarter totaled 182 MBoe/d, while International sales volumes totaled 120 MBoe/d, lower than produced volumes by two thousand barrels per day (MBbl/d) due to the timing of liftings in Equatorial Guinea. Versus the third quarter of last year, total sales volumes were up due to the Company's continued development of the
Third quarter 2014 total production costs, including lease operating expense, production and ad valorem taxes, and transportation and gathering averaged
Included in the adjustments to net income for the third quarter of 2014 were non-cash commodity derivative gains and a gain on the sale of certain non-core U.S. Onshore assets, primarily the Company's
OPERATIONS UPDATE
DJ BASIN
In the
- Record quarterly horizontal volumes, which totaled 74 MBoe/d for the third quarter of 2014, up more than five percent from the second quarter of 2014 and 30 percent from the same quarter of last year, after excluding the impact of volumes associated with the exchange executed in late 2013.
- Drilled 75 wells in the quarter, including 22 extended reach laterals, for an average lateral length of more than 6,000 feet.
- Commenced production on 73 operated wells, including 14 extended reach lateral wells (86 standard length equivalent wells). Approximately 50 percent of the wells brought online during the quarter were evaluating downspacing performance.
-
Included in the wells brought online in the quarter were 23 wells from the
Wells Ranch 30 Section, with six of the wells developed at 16 wells per section spacing and seventeen wells developed on a 32 well per section spacing pattern. The downspaced wells include wells in each of the Niobrara benches. On average, the downspace wells are performing in line with standard spacing wells on the pad and slightly better than theWells Ranch type curve after more than 30 days on production. - Four additional Plug-n-Perf completions were performed late in the third quarter. Production from these wells and additional Plug-n-Perf completions are planned to come online in the fourth quarter of 2014. The Company's initial two Plug-n-Perf completion wells, at the Peppler/Peaks pad in the Core IDP, continue to outperform the comparable sliding sleeve completion after 150 days on production.
- Additional expansion of oil handling at the Wells Ranch Central Processing Facility was complete and is fully operational, increasing oil handling capacity to approximately 45 MBbl/d.
- Progress on the Company's Keota gas plant and LNG facility, which will service the East Pony IDP, remains on schedule, with project start-ups anticipated in the fourth quarter of 2014 and the first quarter of 2015, respectively. When complete, the Keota gas plant will be able to process up to 30 million cubic feet of natural gas per day (MMcf/d) and the LNG facility will produce up to 100,000 gallons per day of LNG.
-
Noble Energy continues to expand its transportation on pipeline and rail projects exporting crude oil out of theDJ Basin . Approximately 80 percent of the Company's gross crude oil production was transported outside of theDJ Basin in the third quarter. -
Currently operating nine drilling rigs in the
DJ Basin .
MARCELLUS SHALE
Production volumes in the
- Net operated production volumes averaged approximately 130 MMcfe/d, up more than 50 percent from the second quarter of 2014 and nearly 250 percent from the third quarter of last year.
-
Drilled 23 operated wells at an average lateral length of more than 8,600 feet. Included in the wells drilled for the quarter was the
Moundsville -6A well, with a 12,425 foot lateral. This well represents anAppalachian Basin and Company record for lateral length, with the lateral drilled in just three days, and located 100 percent within target reservoir. -
Commenced production on 23 operated wells, including nine wells completed with Reduced Stage and Cluster Spacing. Included in the wells brought online during the quarter were the Company's first pads in the Oxford and Shirley areas of
West Virginia (Doddridge andTyler counties, respectively). Initial production from these areas is performing in line with the Company's best wells in the Majorsville area. - At the Oxford-1 pad, six wells (6,400 foot average lateral) are flowing back at a combined rate of 40 MMcfe/d after more than 30 days, with more than 20 percent of the volumes representing liquids. Each of the wells is completed on an average of 550 foot lateral spacing, versus historical spacing patterns of 750 to 1,000 feet. The downspaced wells are all performing better than expected type curves for the area.
- At the Shirley-1 pad, four wells (8,710 foot average lateral) are flowing back at a combined rate of 50 MMcfe/d after more than 30 days, while two additional wells on the pad are planned to come online in the fourth quarter. The wells are all performing better than expected type curves for the area.
- Joint Venture partner CONSOL Energy drilled 27 wells during the quarter (8,100 foot average lateral length), including seven Upper Devonian wells. These wells represent the Joint Venture's first Upper Devonian wells in 2014. Initial production from these wells is anticipated in early 2015.
- CONSOL Energy brought 14 wells to first gas sales. Eleven of these wells were completed with Reduced Stage and Cluster Spacing.
-
Agreed on binding terms to add additional firm capacity out of basin, with 100 MMcf/d commencing in mid-2015 to
Gulf Coast , Mid-Continent, and Northeast markets, and 75 MMcf/d toGreat Lakes markets beginning late 2017. Following the completion of these agreements, total firm capacity and firm sales commitments have been increased to approximately 800 MMcf/d net beginning late 2017. -
The Joint Venture is currently operating eight horizontal rigs in the
Marcellus Shale , split evenly between the wet and dry gas areas. -
Successfully completed the CONE Midstream MLP Initial Public Offering, generating over
$200 million in net proceeds toNoble Energy .
In the
- Cumulative gross production at Swordfish exceeded 30 million barrels of oil equivalent (MMBoe).
-
Announced positive results at Katmai, which represents the Company's fifth exploration discovery in the
Gulf of Mexico since 2011. Located inGreen Canyon 40, total gross discovered resources at Katmai are 40 to 60 MMBoe, with further upside potential to a total of 100 MMBoe. -
Successfully drilled the
Dantzler -2 appraisal well, increasing total gross discovered resources at the field to between 65 and 100 MMBoe. A drilling rig is currently performing completion operations atDantzler -2, to be followed by the completion of theDantzler -1 well. -
Development progress remains on schedule for the Company's near-term major projects, including Big Bend,
Dantzler , and Gunflint. The subsea installation schedule for all fields has been finalized and necessary topside facility modifications are underway. First production at Big Bend is estimated in the fourth quarter of 2015,Dantzler in the first quarter of 2016, and Gunflint in mid-2016. Following field ramp-up, the combined initial net production rates for the three developments is approximately 30 MBoe/d, with more than 80 percent of the volume anticipated to be oil. -
Accelerated the Madison exploration prospect for drilling in the fourth quarter. Madison, located on
Mississippi Canyon 479, contains unrisked gross resources of 45 to 120 MMBoe (P75-P25).Noble Energy is operator of the Madison prospect with a 60 percent working interest. Results are expected in early 2015.
Hydrocarbon sales in
- Active production management and strong reservoir performance at the Aseng oil field, which averaged 40 MBbl/d gross during the quarter, maintained production essentially flat with the second quarter of 2014.
- Successful sidetrack at the Alen 1P well commenced production in early October, and additional workover activities are planned in the fourth quarter of 2014.
- Recently completed a 1,700 square kilometer 3D seismic acquisition over Blocks O and I offshore Equatorial Guinea. Data processing, which is anticipated to be complete in late 2015, and interpretation is designed to assist in the Company's project development and exploration plans over the licenses.
EASTERN MEDITERRANEAN
In the Eastern Mediterranean,
- Exceptional reservoir and facility performance continued at Tamar, with only two hours of downtime experienced during the quarter.
-
Additional progress was made at the
Ashdod Onshore Terminal compression project, which is approximately 80 percent complete. The expansion is targeted to increase deliverability at Tamar to 1.2 billion cubic feet per day (Bcf/d), gross, beginning in mid-2015. -
Debottlenecking of the Tamar facilities has increased current peak production deliverability at Tamar to more than 1.1 Bcf/d, gross. This peak production rate was reached at various intervals during the third quarter to meet local
Israel demand for natural gas. -
Executed a Letter of Intent to supply a minimum of 300 MMcf/d of natural gas for 15 years from the Leviathan field to the
National Electric Power Company of Jordan. Combined for Tamar and Leviathan,Noble Energy and partners have executed Letters of Intent to export gross daily volumes of up to 1.7 Bcf/d and total volumes of more than 8 trillion cubic feet of natural gas to regional export customers. Negotiations of final gas purchase and sales agreements are underway. -
Received
Israel government approval for a Leviathan gas delivery point in the northern region of the country. -
Submitted the Plan of Development for the initial phase of development at the Leviathan field to the
Ministry of Energy and Water Resources . The initial phase of development is planned to include a 1.6 Bcf/d Floating, Production, Storage, and Offloading (FPSO) vessel, with initial sales targeted to begin in early 2018 at 75 percent of total FPSO capacity.
FRONTIER VENTURES
Key highlights for the quarter included:
-
Secured an exploration license, Block F15, offshore
Gabon , covering 670,000 gross acres in the pre-saltGabon Coastal Basin . 3D seismic acquisition is planned to commence in the first half of 2015. -
Entered into a rig sharing agreement for offshore
Falkland Islands , to provide rig resources for twoNoble Energy -operated exploration prospects in 2015. The first of the prospects has been named Humpback, one of multiple stacked fan prospects located in the Fitzroy sub-basin of the Southern Area license. The group of stacked fan prospects combined has an estimated gross unrisked resource potential of approximately one billion barrels of oil equivalent. Drilling operations at Humpback are anticipated to commence in mid-2015. -
Relocated a drilling rig from the
DJ Basin to the Company's NE Nevada Wilson play. Drilling operations commenced inSeptember 2014 , and the Company is planning to drill three additional wells testing the extent of the Elko reservoir in new areas. The Company's initial vertical well began oil sales inJuly 2014 and has proven the productive nature of the Elko reservoir.
FOURTH QUARTER GUIDANCE
Detailed guidance is available in the supplemental information for the conference call, which can be located on the Company's website.
Beginning in the fourth quarter of 2014, the Company is reporting its equity earnings in
(1) A Non-GAAP measure, see attached Reconciliation Schedules
WEBCAST AND CONFERENCE CALL INFORMATION
This news release contains certain "forward-looking statements" within the meaning of federal securities law. Words such as "anticipates", "believes," "expects", "intends", "will", "should", "may", and similar expressions may be used to identify forward-looking statements. Forward-looking statements are not statements of historical fact and reflect
This news release also contains certain historical non-GAAP measures of financial performance that management believes are good tools for internal use and the investment community in evaluating
Schedule 1
Reconciliation of Net Income to Adjusted Income (in millions, except per share amounts, unaudited) |
||||||||||||||||||||||||||||||||
Three Months Ended |
Nine Months Ended |
|||||||||||||||||||||||||||||||
2014 |
Per Diluted Share [5] |
2013 |
Per Diluted Share |
2014 |
Per Diluted Share [5] |
2013 |
Per Diluted Share |
|||||||||||||||||||||||||
Net Income |
$ |
419 |
$ |
1.12 |
$ |
205 |
$ |
0.56 |
$ |
811 |
$ |
2.21 |
$ |
843 |
$ |
2.33 |
||||||||||||||||
(Gain) loss on commodity derivative instruments, net of cash settlements [1] |
(397) |
(1.08) |
147 |
0.41 |
(169) |
(0.46) |
67 |
0.18 |
||||||||||||||||||||||||
Asset impairments [2] |
33 |
0.09 |
63 |
0.17 |
164 |
0.45 |
63 |
0.17 |
||||||||||||||||||||||||
(Gain) on divestitures [3] |
(30) |
(0.08) |
— |
— |
(72) |
(0.20) |
(67) |
(0.18) |
||||||||||||||||||||||||
Other adjustments |
(2) |
(0.01) |
8 |
0.02 |
(2) |
(0.01) |
6 |
0.01 |
||||||||||||||||||||||||
Total adjustments before tax |
(396) |
(1.08) |
218 |
0.60 |
(79) |
(0.22) |
69 |
0.18 |
||||||||||||||||||||||||
Income tax effect of adjustments [4] |
87 |
0.24 |
(62) |
(0.17) |
(6) |
(0.01) |
(40) |
(0.11) |
||||||||||||||||||||||||
Adjusted Income |
$ |
110 |
$ |
0.28 |
$ |
361 |
$ |
0.99 |
$ |
726 |
$ |
1.98 |
$ |
872 |
$ |
2.40 |
||||||||||||||||
Weighted average number of shares outstanding |
||||||||||||||||||||||||||||||||
Diluted |
367 |
363 |
367 |
363 |
NOTE: |
Adjusted income should not be considered a substitute for net income as reported in accordance with GAAP. Adjusted income is provided for comparison to earnings forecasts prepared by analysts and other third parties. Our management believes, and certain investors may find, that adjusted income is beneficial in evaluating our financial performance. We believe such measures can facilitate comparisons of operating performance between periods and with our peers. See Schedule 2: Summary Statement of Operations. |
All per share and shares outstanding amounts have been retroactively adjusted for the two-for-one stock split, which was distributed on |
|
[1] |
Many factors impact our gain or loss on commodity derivatives, net of cash settlements, including: increases and decreases in the commodity forward price curves compared to our executed hedging arrangements; increases in hedged future volumes; and the mix of hedge arrangements between NYMEX WTI, Dated Brent and NYMEX HH commodities. These gains or losses on commodity derivative instruments, net of cash settlements recognized in the current period, will be realized in the future when cash settlement occurs. |
[2] |
Amounts for 2014 primarily represent impairments related to the |
[3] |
During 2014 and 2013, we sold certain non-core onshore U.S. properties and our |
[4] |
The income tax effect of adjustments is determined for each major tax jurisdiction for each adjusting item. |
[5] |
The diluted earnings per share calculations for the three and nine months ended September 30, 2014 include deferred compensation (gains) losses from NBL shares held in a rabbi trust. Consistent with GAAP, when dilutive, the deferred compensation gain or loss, net of tax, is excluded from net income while the NBL shares held in the rabbi trust are included in the diluted sharecount. |
Schedule 2
Summary Statement of Operations (in millions, except per share amounts, unaudited) |
||||||||||||||||
Three Months Ended |
Nine Months Ended |
|||||||||||||||
2014 |
2013 |
2014 |
2013 |
|||||||||||||
Revenues |
||||||||||||||||
Crude oil and condensate |
$ |
849 |
$ |
1,017 |
$ |
2,748 |
$ |
2,683 |
||||||||
Natural gas |
310 |
286 |
932 |
719 |
||||||||||||
Natural gas liquids |
69 |
38 |
213 |
135 |
||||||||||||
Income from equity method investees |
41 |
53 |
138 |
150 |
||||||||||||
Total revenues |
1,269 |
1,394 |
4,031 |
3,687 |
||||||||||||
Operating Expenses |
||||||||||||||||
Lease operating expense |
133 |
137 |
432 |
393 |
||||||||||||
Production and ad valorem taxes |
44 |
51 |
146 |
137 |
||||||||||||
Transportation and gathering expense |
40 |
33 |
119 |
89 |
||||||||||||
Exploration expense |
217 |
60 |
350 |
211 |
||||||||||||
Depreciation, depletion and amortization |
460 |
412 |
1,297 |
1,146 |
||||||||||||
General and administrative |
132 |
109 |
399 |
324 |
||||||||||||
(Gain) on divestitures |
(30) |
— |
(72) |
(12) |
||||||||||||
Asset impairments |
33 |
63 |
164 |
63 |
||||||||||||
Other operating expense, net |
10 |
6 |
33 |
27 |
||||||||||||
Total operating expenses |
1,039 |
871 |
2,868 |
2,378 |
||||||||||||
Operating Income |
230 |
523 |
1,163 |
1,309 |
||||||||||||
Other (Income) Expense |
||||||||||||||||
(Gain) loss on commodity derivative instruments |
(385) |
157 |
(74) |
69 |
||||||||||||
Interest, net of amount capitalized |
52 |
46 |
151 |
104 |
||||||||||||
Other non-operating (income) expense, net |
(13) |
9 |
1 |
21 |
||||||||||||
Total other (income) expense |
(346) |
212 |
78 |
194 |
||||||||||||
Income from Continuing Operations Before Income Taxes |
576 |
311 |
1,085 |
1,115 |
||||||||||||
Income Tax Provision |
157 |
116 |
274 |
330 |
||||||||||||
Income from Continuing Operations |
419 |
195 |
811 |
785 |
||||||||||||
Discontinued Operations, Net of Tax |
— |
10 |
— |
58 |
||||||||||||
Net Income |
$ |
419 |
$ |
205 |
$ |
811 |
$ |
843 |
||||||||
Earnings Per Share [1] |
||||||||||||||||
Basic |
||||||||||||||||
Income from continuing operations |
$ |
1.16 |
$ |
0.54 |
$ |
2.25 |
$ |
2.19 |
||||||||
Discontinued operations, net of tax |
— |
0.03 |
— |
0.16 |
||||||||||||
Net Income |
$ |
1.16 |
$ |
0.57 |
$ |
2.25 |
$ |
2.35 |
||||||||
Diluted |
||||||||||||||||
Income from continuing operations |
$ |
1.12 |
$ |
0.53 |
$ |
2.21 |
$ |
2.17 |
||||||||
Discontinued operations, net of tax |
— |
0.03 |
— |
0.16 |
||||||||||||
Net Income |
$ |
1.12 |
$ |
0.56 |
$ |
2.21 |
$ |
2.33 |
||||||||
Weighted average number of shares outstanding [1] |
||||||||||||||||
Basic |
362 |
359 |
361 |
359 |
||||||||||||
Diluted |
367 |
363 |
367 |
363 |
[1] |
All per share and shares outstanding amounts have been retroactively adjusted for the two-for-one stock split, which was distributed on |
Schedule 3
Volume and Price Statistics (unaudited) |
||||||||||||||||
Three Months Ended |
Nine Months Ended |
|||||||||||||||
2014 |
2013 |
2014 |
2013 |
|||||||||||||
Crude Oil and Condensate Sales Volumes (MBbl/d) |
||||||||||||||||
|
67 |
64 |
66 |
61 |
||||||||||||
|
29 |
37 |
32 |
31 |
||||||||||||
Other International |
— |
4 |
3 |
4 |
||||||||||||
Total consolidated operations |
96 |
105 |
101 |
96 |
||||||||||||
Equity method investee - |
2 |
2 |
2 |
2 |
||||||||||||
Total sales volumes |
98 |
107 |
103 |
98 |
||||||||||||
Crude Oil and Condensate Realized Prices ($/Bbl) |
||||||||||||||||
|
$ |
94.21 |
$ |
103.59 |
$ |
96.84 |
$ |
98.03 |
||||||||
|
98.63 |
107.67 |
104.38 |
106.78 |
||||||||||||
Other International |
— |
101.58 |
104.47 |
103.00 |
||||||||||||
Consolidated average realized prices |
$ |
95.55 |
$ |
104.95 |
$ |
99.48 |
$ |
101.08 |
||||||||
Natural Gas Sales Volumes (MMcf/d) |
||||||||||||||||
|
538 |
489 |
497 |
434 |
||||||||||||
|
233 |
257 |
241 |
251 |
||||||||||||
|
262 |
255 |
233 |
196 |
||||||||||||
Total sales volumes |
1,033 |
1,001 |
971 |
881 |
||||||||||||
Natural Gas Realized Prices ($/Mcf) |
||||||||||||||||
|
$ |
3.41 |
$ |
3.57 |
$ |
4.12 |
$ |
3.64 |
||||||||
|
0.27 |
0.27 |
0.27 |
0.27 |
||||||||||||
|
5.59 |
5.08 |
5.59 |
5.03 |
||||||||||||
Consolidated average realized prices |
$ |
3.26 |
$ |
3.11 |
$ |
3.52 |
$ |
3.00 |
||||||||
Natural Gas Liquids Sales Volumes (MBbl/d) |
||||||||||||||||
|
25 |
13 |
22 |
15 |
||||||||||||
Equity method investee - |
6 |
6 |
6 |
6 |
||||||||||||
Total sales volumes |
31 |
19 |
28 |
21 |
||||||||||||
Natural Gas Liquids Realized Prices ($/Bbl) |
||||||||||||||||
|
$ |
29.53 |
$ |
31.26 |
$ |
35.39 |
$ |
33.60 |
||||||||
Barrels of Oil Equivalent Volumes (MBoe/d) |
||||||||||||||||
|
182 |
159 |
171 |
148 |
||||||||||||
|
68 |
80 |
72 |
73 |
||||||||||||
|
44 |
43 |
39 |
33 |
||||||||||||
Other International |
— |
4 |
3 |
4 |
||||||||||||
Total consolidated operations |
294 |
286 |
285 |
258 |
||||||||||||
Equity method investee - |
8 |
7 |
7 |
8 |
||||||||||||
Total sales volumes from continuing operations |
302 |
293 |
292 |
266 |
||||||||||||
Total sales volumes from discontinued operations |
— |
1 |
— |
1 |
||||||||||||
Total sales volumes |
302 |
294 |
292 |
267 |
Schedule 4
Condensed Balance Sheets (in millions, unaudited) |
||||||||
|
|
|||||||
2014 |
2013 |
|||||||
ASSETS |
||||||||
Current Assets |
||||||||
Cash and cash equivalents |
$ |
1,169 |
$ |
1,117 |
||||
Accounts receivable, net |
740 |
947 |
||||||
Other current assets |
361 |
547 |
||||||
Total current assets |
2,270 |
2,611 |
||||||
Net property, plant and equipment |
17,758 |
15,725 |
||||||
Goodwill |
620 |
627 |
||||||
Other noncurrent assets |
538 |
679 |
||||||
Total Assets |
$ |
21,186 |
$ |
19,642 |
||||
LIABILITIES AND SHAREHOLDERS' EQUITY |
||||||||
Current Liabilities |
||||||||
Accounts payable - trade |
$ |
1,425 |
$ |
1,354 |
||||
Other current liabilities |
807 |
988 |
||||||
Total current liabilities |
2,232 |
2,342 |
||||||
Long-term debt |
5,498 |
4,566 |
||||||
Deferred income taxes |
2,464 |
2,441 |
||||||
Other noncurrent liabilities |
1,054 |
1,109 |
||||||
Total Liabilities |
11,248 |
10,458 |
||||||
Total Shareholders' Equity |
9,938 |
9,184 |
||||||
Total Liabilities and Shareholders' Equity |
$ |
21,186 |
$ |
19,642 |
Schedule 5
Discretionary Cash Flow and Reconciliation to Net Cash Provided by Operating Activities (in millions, unaudited) |
||||||||||||||||
Three Months Ended |
Nine Months Ended |
|||||||||||||||
2014 |
2013 |
2014 |
2013 |
|||||||||||||
Adjusted Income [1] |
$ |
110 |
$ |
361 |
$ |
726 |
$ |
872 |
||||||||
Adjustments to reconcile adjusted income to discretionary cash flow: |
||||||||||||||||
Depreciation, depletion and amortization |
460 |
412 |
1,297 |
1,146 |
||||||||||||
Exploration expense |
217 |
60 |
350 |
211 |
||||||||||||
(Income)/Dividends from equity method investments, net |
56 |
6 |
53 |
(12) |
||||||||||||
Deferred compensation (income) expense |
(12) |
10 |
— |
24 |
||||||||||||
Deferred income taxes |
(49) |
125 |
68 |
214 |
||||||||||||
Stock-based compensation expense |
22 |
20 |
67 |
59 |
||||||||||||
Other |
7 |
— |
7 |
1 |
||||||||||||
Discretionary Cash Flow |
$ |
811 |
$ |
994 |
$ |
2,568 |
$ |
2,515 |
||||||||
Reconciliation to Operating Cash Flows |
||||||||||||||||
Net changes in working capital |
181 |
(32) |
286 |
(201) |
||||||||||||
Cash exploration costs |
(47) |
(53) |
(154) |
(167) |
||||||||||||
Current tax benefit of earnings adjustments |
— |
— |
— |
(5) |
||||||||||||
Other adjustments |
— |
— |
3 |
11 |
||||||||||||
Net Cash Provided by Operating Activities |
$ |
945 |
$ |
909 |
$ |
2,703 |
$ |
2,153 |
||||||||
Capital expenditures (accrual based) |
$ |
1,335 |
$ |
1,147 |
$ |
3,558 |
$ |
3,186 |
||||||||
Increase in capital lease obligations [2] |
60 |
18 |
81 |
54 |
||||||||||||
Total Capital Expenditures (Accrual Based) |
$ |
1,395 |
$ |
1,165 |
$ |
3,639 |
$ |
3,240 |
NOTE: |
The table above reconciles discretionary cash flow to net cash provided by operating activities. While discretionary cash flow is not a GAAP measure of financial performance, our management believes it is a useful tool for evaluating our overall financial performance. Among our management, research analysts, portfolio managers and investors, discretionary cash flow is broadly used as an indicator of a company's ability to fund exploration and production activities and meet financial obligations. Discretionary cash flow is also commonly used as a basis to value and compare companies in the oil and gas industry. |
[1] |
See Schedule 1: Reconciliation of Net Income to Adjusted Income. |
[2] |
Increase in capital lease obligations represents estimated construction in progress to date on US operating assets and corporate buildings. |
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