- Organic capital expenditures of
$664 million , below the low end of guidance. Full year 2015 capital is now estimated at slightly below$3 billion , a reduction of approximately$100 million from prior estimates. - Discretionary cash flow(1)was
$708 million for the quarter. - Production costs, including lease operating expense, production taxes, and transportation & gathering averaged
$6.74 per BOE, a 14 percent reduction from the second quarter of 2015. - Record quarterly sales volumes of 379 MBoe/d and increased volume guidance for the fourth quarter.
- Closed the merger with
Rosetta Resources Inc. onJuly 20, 2015 . - Exited the third quarter
of 2015 with
$5 billion in liquidity, including cash on hand and unused capacity on the credit facility. - Recently commenced production from the Big Bend and
Dantzler fields in theGulf of Mexico . - Recently announced filing of a registration statement on Form S-1 by a wholly owned subsidiary in connection with a proposed initial public offering of common units of
Noble Midstream Partners LP .
Total sales volumes for the quarter averaged 379 thousand barrels of oil equivalent per day (MBoe/d), with liquids comprising 44 percent (30 percent crude oil and condensate and 14 percent natural gas liquids) and natural gas the remaining 56 percent. Included in sales volumes for the third quarter of 2015 were the
Third quarter 2015 total production costs, including lease operating expense (LOE), production taxes, and transportation and gathering declined to
Adjustments to the net loss for the third quarter of 2015 included non-cash commodity derivative losses of
OPERATIONS UPDATE
DJ BASIN
In the
Highlights include:
- Natural gas processing capacity on the DCP
system, following the start-up of the Lucerne-2 gas processing plant, increased to more than 800 million cubic feet of natural gas per day. Accordingly, line pressures in the northern part of the field, particularly in and around the Company's
Wells Ranch area, have been reduced by up to 100 psi. Construction of a third-party low-pressure line-loop system (DCP Grand Parkway ) in the northern part of the field continues and is expected to be complete by the end of 2015 / early 2016. - As a result of the reduction in field line pressures, the Company's legacy vertical well production averaged nearly 25 MBoe/d in the third quarter, which is a high point over the last year and an increase of more than five MBoe/d versus pre-Lucerne-2 rates. Horizontal sales volumes totaled 91 MBoe/d, above expectations and an increase of 23 percent from
the same quarter of last year.
- Operated four drilling rigs in the Basin for the majority of the third quarter of 2015. Accelerated cycle times are resulting in higher than originally planned 2015 well counts (spud, total depth, and wells on production).
Noble Energy is currently operating three drilling rigs and two full time completion crews in theDJ Basin . - Drilled 39 wells at an average lateral length of over 7,300 feet. The average spud to rig release time for a standard lateral length well (4,500 lateral feet) decreased to 5.7 days.
- Standard lateral length well costs, including allocated facility costs, are on track to be below second half 2015 targets of
$3.5 million inWells Ranch and$3.9 million in East Pony. - Commenced production on 58 wells (equivalent to 70 standard lateral length wells). Well performance in both
Wells Ranch and East Pony continues in-line with or above expectations.Wells Ranch volumes in the third quarter were up more than 15 percent and East Pony volumes were up more than 20 percent versus the second quarter of 2015. - Refined completion techniques continue to enhance overall productivity. Included in the wells brought online during the quarter was a development area with 13 wells in
Wells Ranch , including nine wells completed with slickwater fluid and four wells completed with hybrid gel systems. Cumulative production from the slickwater completions is outperforming the hybrid gel wells by more than 20 percent on average after 30 days. For a standard lateral length well, those designed with slickwater are approximately 10 percent lower total well cost versus hybrid gel wells. - Based on the current drilling and completion activity plans, the Company estimates exiting 2015 with approximately 40 wells drilled but uncompleted.
Production volumes for the Eagle Ford and Permian assets averaged 54 MBoe/d from
Highlights since closing the merger include:
- Drilled eight operated wells to total depth, including seven Lower Eagle Ford wells and one Wolfcamp A well in the
Delaware Basin (Permian). - Realized a substantial reduction in the spud to rig release timing in both areas as a result of various operational enhancements. In the Eagle Ford, spud to rig release times have been reduced to approximately eight days for a 5,000 foot lateral, down approximately 30 percent from prior 2015 activity on these assets. The well drilled in the
Delaware had a lateral length of approximately 5,000 feet and was drilled in approximately 10 days less time than prior activity on these assets. - Commenced production on five operated Lower Eagle Ford wells. The two most recent wells represent
Noble Energy's initial designed and executed completions. These wells were drilled with 950 foot effective lateral spacing and were completed with 20 foot cluster spacing and approximately 2,000 pounds of proppant per lateral foot. Each of the two wells, normalized to a 5,000 foot lateral length, is materially outperforming the 3 MMBoe estimated ultimate recovery type curve for the area.
- Based on the current drilling and completion activity plans, the Company estimates exiting 2015 with approximately 50 wells drilled but uncompleted (including 35 wells in the Eagle Ford and 15 wells in the
Delaware ).Noble Energy anticipates exiting 2015 with two rigs operating inTexas , one in the Eagle Ford and one in theDelaware Basin .
MARCELLUS SHALE
Production volumes in the
Highlights include:
- Reduced current operated and non-operated drilling activity to zero rigs.
- Commenced production on 16 operated wells having an average lateral length of nearly 8,000 feet. Included in the wells brought online was the six-well RHL-4 pad located in the Majorsville area (
Marshall County, West Virginia ). Three of the wells were completed with reduced stage and cluster spacing, and all of the wells are laterally spaced 500 feet apart. After 30 days online, the RHL-4 pad, which averaged more than 2,200 pounds of proppant per lateral foot, was producing more than 60 MMcfe/d. - Completed the Company's initial Utica well, the MND-6H, with a lateral length of 9,090 feet. The well, located in
Marshall County, West Virginia , is anticipated to commence production in the fourth quarter of 2015. - JV partner CONSOL Energy commenced production on 12 dry gas wells.
- Successful completion of the initial phase of de-bottlenecking of the dry gas North Nineveh gathering system (owned by CONE Midstream) added approximately 100 MMcf/d of throughput capacity and supported the Company's quarterly volumes.
- Based on
the current drilling and completion activity plans, the Company estimates exiting 2015 with approximately 80 wells drilled but uncompleted (including both the wet and dry gas areas).
In the
Highlights include:
- Delivery of the Rio Grande major project (including the Big Bend and
Dantzler fields) has been executed ahead of schedule and within sanction budget. First oil production at the Big Bend field commenced in late October. Maximum peak production from the field of over 20 MBoe/d gross (10 MBoe/d net toNoble Energy ) is anticipated to be reached within the next couple of weeks.Noble Energy operates Big Bend with a 54 percent working interest. - First oil production from
Dantzler , anticipated to produce at a maximum rate of over 25 MBoe/d gross (10 MBoe/d net toNoble Energy ), has also recently commenced.Noble Energy operatesDantzler with a 45 percent working interest. Crude oil and condensate comprise more than 85 percent of the planned production from Rio Grande. - Successfully sidetracked the second development well at Gunflint and commenced completion operations in the field. Installation of pipelines and
umbilicals is currently underway, with first production from the field projected in mid-2016 as a tieback to the Gulfstar One facility.
Hydrocarbon sales in
Highlights include:
- Active production management, facility optimization, and strong reservoir performance resulted in gross daily production averages of over 33 MBbl/d for Aseng and 30 MBbl/d for Alen.
- Successfully commenced production on
the C-21 development well at Alba ahead of schedule.
- Project status on the Alba compression project was advanced to approximately 80 percent complete. Installation of the new compression platform is expected to commence in the first quarter of 2016, which will result in temporary full field shut-in. First production from the compression facility, which will ultimately help stem decline and extend life of field recovery, is anticipated in the middle of 2016.
- The Cheetah exploration well, drilled in the Tilapia license offshore
Cameroon , reached total depth and did not encounter commercial reservoir sands.
EASTERN MEDITERRANEAN
In the Eastern Mediterranean,
Highlights include:
- During the month of August, the Tamar field averaged more than 1 billion cubic feet per day of natural gas production, gross.
- Negotiation of natural gas sales contracts for Tamar and Leviathan volumes continued with multiple regional customers.
- A comprehensive regulatory framework for hydrocarbon development was finalized and fully approved by the government of Israel. Government action to follow through with the regulatory framework is ongoing.
OTHER
- Extended the Company's unsecured credit facility by two years, to a maturity date of
August 2020 , with a lower pricing grid and no changes to associated financial covenants. - Exited the third quarter of 2015 with
$5 billion in financial liquidity, including$1 billion in cash and$4 billion of unused credit facility capacity. - Completed a
$1.8 billion debt exchange offer by issuing an equivalent aggregate principal amount of investment grade-ratedNoble Energy Senior Notes in exchange for validly tendered and acceptedRosetta Resources Inc. Notes. Following the debt exchange, both credit rating agencies affirmed their investment grade ratings and outlooks onNoble Energy credit. - The Humpback exploration well, drilled in the Company's
Southern Basin acreage offshore theFalkland Islands , reached total depth in late-October, and is being plugged and abandoned.
GUIDANCE
Year-to date, organic capital expenditures total
(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", "estimates", and similar expressions may be used to identify forward-looking statements. Forward-looking
statements are not statements of historical fact and reflect
The
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 | ||||||||||||||||
Summary Statement of Operations | ||||||||||||||||
(in millions, except per share amounts, unaudited) | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Revenues | ||||||||||||||||
Crude oil and condensate | $ | 438 | $ | 849 | $ | 1,352 | $ | 2,748 | ||||||||
Natural gas | 293 | 310 | 785 | 932 | ||||||||||||
Natural gas liquids | 34 | 69 | 90 | 213 | ||||||||||||
Income from equity method investees | 36 | 41 | 60 | 138 | ||||||||||||
Total revenues | 801 | 1,269 | 2,287 | 4,031 | ||||||||||||
Operating Expenses | ||||||||||||||||
Lease operating expense | 133 | 132 | 419 | 424 | ||||||||||||
Production and ad valorem taxes | 28 | 44 | 89 | 146 | ||||||||||||
Transportation and gathering expense | 74 | 40 | 185 | 119 | ||||||||||||
Exploration expense | 203 | 217 | 308 | 350 | ||||||||||||
Depreciation, depletion and amortization | 539 | 460 | 1,444 | 1,297 | ||||||||||||
General and administrative | 109 | 132 | 308 | 399 | ||||||||||||
Asset impairments | — | 33 | 43 | 164 | ||||||||||||
Other operating (income) expense, net | 182 | (19 | ) | 252 | (31 | ) | ||||||||||
Total operating expenses | 1,268 | 1,039 | 3,048 | 2,868 | ||||||||||||
Operating Income (Loss) | (467 | ) | 230 | (761 | ) | 1,163 | ||||||||||
Other (Income) Expense | ||||||||||||||||
(Gain) on commodity derivative instruments | (267 | ) | (385 | ) | (331 | ) | (74 | ) | ||||||||
Interest, net of amount capitalized | 71 | 52 | 183 | 151 | ||||||||||||
Other non-operating (income) expense, net | (12 | ) | (13 | ) | (20 | ) | 1 | |||||||||
Total other (income) expense | (208 | ) | (346 | ) | (168 | ) | 78 | |||||||||
Income (Loss) Before Income Taxes | (259 | ) | 576 | (593 | ) | 1,085 | ||||||||||
Income Tax (Benefit) Provision | 24 | 157 | (180 | ) | 274 | |||||||||||
Net Income (Loss) | $ | (283 | ) | $ | 419 | $ | (413 | ) | $ | 811 | ||||||
Earnings (Loss) Per Share | ||||||||||||||||
Earnings (Loss) Per Share, Basic | $ | (0.67 | ) | $ | 1.16 | $ | (1.05 | ) | $ | 2.25 | ||||||
Earnings (Loss) Per Share, Diluted | $ | (0.67 | ) | $ | 1.12 | $ | (1.05 | ) | $ | 2.21 | ||||||
Weighted average number of shares outstanding | ||||||||||||||||
Basic | 420 | 362 | 392 | 361 | ||||||||||||
Diluted | 420 | 367 | 392 | 367 |
These financial statements should be read in conjunction with the financial statements and the
accompanying notes and other information included in | ||||||||||||||||||||||||||||||
On |
Schedule 2 | ||||||||
Condensed Balance Sheets | ||||||||
(in millions, unaudited) | ||||||||
2015 | 2014 | |||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 1,028 | $ | 1,183 | ||||
Accounts receivable, net | 571 | 857 | ||||||
Commodity derivative assets, current | 650 | 710 | ||||||
Other current assets | 281 | 325 | ||||||
Total current assets | 2,530 | 3,075 | ||||||
Net property, plant and equipment | 21,749 | 18,143 | ||||||
945 | 620 | |||||||
Other noncurrent assets | 741 | 715 | ||||||
Total Assets | $ | 25,965 | $ | 22,553 | ||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts payable - trade | $ | 1,297 | $ | 1,578 | ||||
Other current liabilities | 795 | 944 | ||||||
Total current liabilities | 2,092 | 2,522 | ||||||
Long-term debt | 8,033 | 6,103 | ||||||
Deferred income taxes, noncurrent | 2,286 | 2,516 | ||||||
Other noncurrent liabilities | 1,104 | 1,087 | ||||||
Total Liabilities | 13,515 | 12,228 | ||||||
Total Shareholders' Equity | 12,450 | 10,325 | ||||||
Total Liabilities and Shareholders' Equity | $ | 25,965 | $ | 22,553 |
These financial statements should be read in conjunction with the financial statements and the accompanying notes and other information included in |
Schedule 3 | ||||||||||||||||
Volume and Price Statistics | ||||||||||||||||
(unaudited) | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Crude Oil and Condensate Sales Volumes (MBbl/d) | ||||||||||||||||
83 | 67 | 73 | 66 | |||||||||||||
27 | 29 | 29 | 32 | |||||||||||||
Other International | — | — | 1 | 3 | ||||||||||||
Total consolidated operations | 110 | 96 | 103 | 101 | ||||||||||||
Equity method investee - | 2 | 2 | 2 | 2 | ||||||||||||
Total sales volumes | 112 | 98 | 105 | 103 | ||||||||||||
Crude Oil and Condensate Realized Prices ($/Bbl) | ||||||||||||||||
$ | 42.42 | $ | 94.21 | $ | 46.02 | $ | 96.84 | |||||||||
45.99 | 98.63 | 52.15 | 104.38 | |||||||||||||
Other International | — | — | 55.52 | 104.47 | ||||||||||||
Consolidated average realized prices | $ | 43.30 | $ | 95.55 | $ | 47.79 | $ | 99.48 | ||||||||
Natural Gas Sales Volumes (MMcf/d) | ||||||||||||||||
| 741 | 538 | 658 | 497 | ||||||||||||
231 | 233 | 221 | 241 | |||||||||||||
303 | 262 | 254 | 233 | |||||||||||||
Total sales volumes | 1,275 | 1,033 | 1,133 | 971 | ||||||||||||
Natural Gas Realized Prices ($/Mcf) | ||||||||||||||||
$ | 2.01 | $ | 3.41 | $ | 2.20 | $ | 4.12 | |||||||||
0.27 | 0.27 | 0.27 | 0.27 | |||||||||||||
5.39 | 5.59 | 5.39 | 5.59 | |||||||||||||
Consolidated average realized prices | $ | 2.50 | $ | 3.26 | $ | 2.54 | $ | 3.52 | ||||||||
Natural Gas Liquids Sales Volumes (MBbl/d) | ||||||||||||||||
49 | 25 | 34 | 22 | |||||||||||||
Equity method investee - | 6 | 6 | 5 | 6 | ||||||||||||
Total sales volumes | 55 | 31 | 39 | 28 | ||||||||||||
Natural Gas Liquids Realized Prices ($/Bbl) | ||||||||||||||||
$ | 7.49 | $ | 29.53 | $ | 9.78 | $ | 35.39 | |||||||||
Barrels of Oil Equivalent Volumes (MBoe/d) | ||||||||||||||||
255 | 182 | 217 | 171 | |||||||||||||
65 | 68 | 66 | 72 | |||||||||||||
51 | 44 | 43 | 39 | |||||||||||||
Other International | — | — | 1 | 3 | ||||||||||||
Total consolidated operations | 371 | 294 | 327 | 285 | ||||||||||||
Equity method investee - | 8 | 8 | 6 | 7 | ||||||||||||
Total sales volumes | 379 | 302 | 333 | 292 |
On |
Schedule 4 | ||||||||||||||||||||||||||||||||
Reconciliation of Net Income (Loss) to Adjusted Income (Loss) | ||||||||||||||||||||||||||||||||
(in millions, except per share amounts, unaudited) | ||||||||||||||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||
2015 | Per Diluted Share | 2014 | Per Diluted Share | 2015 | Per Diluted Share | 2014 | Per Diluted Share | |||||||||||||||||||||||||
Net Income (Loss) | $ | (283 | ) | $ | (0.67 | ) | $ | 419 | $ | 1.14 | $ | (413 | ) | $ | (1.05 | ) | $ | 811 | $ | 2.21 | ||||||||||||
(Gain) loss on commodity derivative instruments, net of cash settlements [1] | 17 | 0.04 | (397 | ) | (1.08 | ) | 352 | 0.90 | (169 | ) | (0.46 | ) | ||||||||||||||||||||
Asset impairments [2] | — | — | 33 | 0.09 | 43 | 0.11 | 164 | 0.45 | ||||||||||||||||||||||||
(Gain) on divestitures [3] | — | — | (30 | ) | (0.08 | ) | — | — | (72 | ) | (0.20 | ) | ||||||||||||||||||||
Deferred compensation [4] | (13 | ) | (0.03 | ) | (12 | ) | (0.03 | ) | (19 | ) | (0.05 | ) | — | — | ||||||||||||||||||
Corporate restructuring [5] | 21 | 0.05 | — | — | 39 | 0.10 | — | — | ||||||||||||||||||||||||
Stacked drilling rig [6] | 13 | 0.03 | — | — | 20 | 0.05 | — | — | ||||||||||||||||||||||||
Pension plan expense [7] | 67 | 0.16 | — | — | 88 | 0.22 | — | — | ||||||||||||||||||||||||
Rosetta Merger expenses [8] | 71 | 0.17 | — | — | 73 | 0.18 | — | — | ||||||||||||||||||||||||
Other adjustments | 1 | — | (2 | ) | — | 7 | 0.02 | (2 | ) | — | ||||||||||||||||||||||
Total adjustments before tax | 177 | 0.42 | (408 | ) | (1.10 | ) | 603 | 1.53 | (79 | ) | (0.21 | ) | ||||||||||||||||||||
Income tax effect of adjustments [9] | 16 | 0.04 | 91 | 0.24 | (169 | ) | (0.43 | ) | (6 | ) | (0.02 | ) | ||||||||||||||||||||
Adjusted Income (Loss) | $ | (90 | ) | $ | (0.21 | ) | $ | 102 | $ | 0.28 | $ | 21 | $ | 0.05 | $ | 726 | $ | 1.98 | ||||||||||||||
Weighted average number of shares outstanding | ||||||||||||||||||||||||||||||||
Diluted | 420 | 367 | 395 | 367 |
NOTE: | Adjusted income (loss) should not be considered an alternative to, or more meaningful than, net income (loss) as reported in accordance with GAAP. Adjusted income (loss) 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 (loss) is beneficial in evaluating our financial performance. We believe such measures can facilitate comparisons of operating performance between periods and with our peers. However, |
On |
[1] | Many factors impact our gain or loss on commodity derivative instruments, net of cash settlements, including: increases and decreases in the commodity forward price curves compared to our executed hedging arrangements; increases in hedged future revenues; 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] | Amount for 2015 relates primarily to Eastern Mediterranean and |
[3] | Amount for 2014 represents sales of non-core onshore U.S. properties and |
[4] | Amount represents (increases) decreases in the fair value of shares of our common stock held in a rabbi trust. |
[5] | Amount represents expenses associated with the relocation of our personnel. The expenses primarily include the relocation of our |
[6] | Amount represents the day rate cost associated with drilling rigs under contract, but not currently being utilized in our US onshore drilling programs. |
[7] | Amount includes the expensing of the actuarial loss from AOCL, related to the termination and re-measurement of our defined benefit pension plan. |
[8] | Amount represents expenses associated with the completion of the Rosetta Merger. |
[9] | The income tax effect of adjustments is determined for each major tax jurisdiction for each adjusting item. The difference between the GAAP income tax provision of |
Schedule 5 | ||||||||||||||||
Discretionary Cash Flow and Reconciliation to Net Cash Provided by Operating Activities | ||||||||||||||||
(in millions, unaudited) | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Adjusted Income (Loss) [1] | $ | (90 | ) | $ | 102 | $ | 21 | $ | 726 | |||||||
Adjustments to reconcile adjusted income to discretionary cash flow | ||||||||||||||||
Depreciation, depletion and amortization | 539 | 460 | 1,444 | 1,297 | ||||||||||||
Exploration expense | 203 | 217 | 308 | 350 | ||||||||||||
(Income)/Dividends from equity method investments, net | (8 | ) | 56 | (4 | ) | 53 | ||||||||||
Deferred income taxes | 42 | (53 | ) | (95 | ) | 68 | ||||||||||
Stock-based compensation expense | 16 | 22 | 54 | 67 | ||||||||||||
Other | 6 | 7 | (3 | ) | 7 | |||||||||||
Discretionary Cash Flow | $ | 708 | $ | 811 | $ | 1,725 | $ | 2,568 | ||||||||
Reconciliation to Operating Cash Flows | ||||||||||||||||
Net changes in working capital | (108 | ) | 181 | (74 | ) | 286 | ||||||||||
Cash exploration costs | (13 | ) | (47 | ) | (73 | ) | (154 | ) | ||||||||
Current tax benefit of earnings adjustments | 12 | — | 20 | — | ||||||||||||
Corporate restructuring | (21 | ) | — | (39 | ) | — | ||||||||||
Stacked drilling rig | (13 | ) | — | (20 | ) | — | ||||||||||
Rosetta Merger expenses | (56 | ) | — | (58 | ) | — | ||||||||||
Other adjustments | 11 | — | 5 | 3 | ||||||||||||
Net Cash Provided by Operating Activities | $ | 520 | $ | 945 | $ | 1,486 | $ | 2,703 | ||||||||
Capital expenditures (accrual based) | $ | 664 | $ | 1,335 | $ | 2,325 | $ | 3,558 | ||||||||
Increase in capital lease obligations [2] | 29 | 60 | 60 | 81 | ||||||||||||
Total Capital Expenditures (Accrual Based) | $ | 693 | $ | 1,395 | $ | 2,385 | $ | 3,639 |
NOTE: | Discretionary cash flow should not be considered an alternative to, or more meaningful than, net income (loss), net cash provided by operating activities, or any other measure as reported in accordance with GAAP. The table above reconciles discretionary cash flow to net cash provided by operating activities. Our management believes, and certain investors may find that discretionary cash flow is useful as an indicator of the company's ability to fund exploration and production activities and meet financial obligations. Discretionary cash flow is also useful as a basis for valuing companies in the oil
and gas industry. However, |
On |
[1] | See Schedule 4: Reconciliation of Net Income (Loss) to Adjusted Income (Loss). |
[2] | Represents estimated construction in progress to date on US operating assets and corporate buildings. |
Investor Contacts:Source:Brad Whitmarsh (281) 943-1670 brad.whitmarsh@nblenergy.comJohn Nicholson (281) 876-6186 John.nicholson@nblenergy.com Media Contacts:Reba Reid (281) 943-1789 media@nblenergy.comPaula Beasley (281) 876-6133 media@nblenergy.com
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