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LINN Energy Reports Second-Quarter 2017 Results

HOUSTON, Aug. 03, 2017 (GLOBE NEWSWIRE) -- LINN Energy, Inc. (OTCQB:LNGG) (“LINN” or the “Company”) announced today financial and operating results for the second quarter of 2017 and provided updated guidance for the third quarter, fourth quarter and full-year 2017.

The Company highlights the following:

  • Signed an agreement to form Roan Resources LLC as a Merge/SCOOP/STACK pure play company with a core, largely contiguous position of approximately 140,000 tier 1 total net acres
  • Successfully tested third bench in the Merge with a peak IP-30 rate of more than 850 BOE/d (~64% liquids); lateral length of 4,186 feet in the Hunton
  • Exceeded $1 billion in net cash proceeds from closed asset sales as of August 1, 2017
  • Eliminated all debt and is in the final stages of negotiating a new credit facility
  • As of July 31, 2017, repurchased ~841,000 shares for ~$27 million as part of the share repurchase program
  • Exceeded midpoint of adjusted production guidance with average daily production of 710 MMcfe/d
  • Revised G&A guidance for 2017 is $95 million, down significantly from the previous guidance of $120 million
  • Raised guidance for production and financial performance pro forma of announced asset sales
  • Commenced construction of Chisholm Trail Cryogenic facility located in the prolific Merge/SCOOP/STACK play

“We had another outstanding quarter as we outperformed midpoint of guidance for volumes, costs and financial targets along with executing on several strategic and value-adding initiatives. This is highlighted by signing an agreement to form Roan Resources LLC, a premier pure play company in the Merge/SCOOP/STACK. With 140,000 total net acres, Roan is expected to have the inventory depth to provide production and reserve growth for many years to come. In addition, LINN’s acreage committed in the deal will remain dedicated to our Chisholm Trail Cryogenic facility that is currently under construction. This year, we successfully closed on more than $1 billion of asset sales resulting in the Company extinguishing all its outstanding debt. This gives us tremendous financial flexibility as we finalize negotiations on a new credit facility and continue to work with the Board of Directors to maximize shareholder value,” said Mark E. Ellis, President and Chief Executive Officer.

Key Financial Results (1)
Second Quarter
$ in millions, except per unit amounts 2017 2016
Average daily production (MMcfe/d) 710 802
Total oil, natural gas and NGL revenues $243 $196
Income from continuing operations$223 $204
Income (loss) from discontinued operations net of income taxes$(3)$4
Net income$220 $208
Adjusted EBITDAX (a non-GAAP financial measure)(3)$112 $179
Total debt(4)$183 $5,961(2)
Net cash provided by operating activities$103 $536
Oil and natural gas capital$71 $14
Total capital$96 $23

  1. All amounts reflect continuing operations with the exception of net income
  2. Includes approximately $4,023 million classified as liabilities subject to compromise on the balance sheet
  3. Excludes Adjusted EBITDAX from discontinued operations of approximately $12 million and $29 million for the three months ended June 30, 2017, and for the three months ended June 30, 2016, respectively
  4. As of June 30, 2017 and June 30, 2016

Formation of Roan Resources – Merge/SCOOP/STACK pure play company
On June 27, 2017, LINN and Citizen Energy II, LLC announced an agreement to contribute certain upstream assets to form a new company, Roan, which will be focused on the accelerated development of the prolific Merge/SCOOP/STACK play in the Anadarko Basin. In exchange, LINN will receive 50 percent of the equity interest in Roan. The combined entity is expected to have no outstanding debt at closing, intends to establish a revolving credit facility of approximately $100 million to $300 million that will be secured by its own assets. The transaction is expected to close in the third quarter of 2017. Roan continues to actively recruit an executive management team and there has been significant interest in this opportunity. Subject to market conditions, Roan anticipates an initial public offering in 2018.

Positive test of a third bench in the Merge
In the second quarter of 2017, LINN completed its first horizontal test of the Hunton with positive results. The Campbell Farms 14-9-6 2H (lateral length of 4,186 feet) had a peak IP-30 rate (gross two-stream) of more than 850 BOE/d (~64% liquids). This test has the potential to add four to eight wells per drilling unit in specific areas of the Roan AMI (area of mutual interest). LINN is currently drilling both Sycamore and Woodford targets from multi-well pads with two operated drilling rigs and the next several completions are scheduled to commence early in the fourth quarter.

Exceeded $1 billion of proceeds from asset sales
As of August 1, 2017, net cash proceeds received from closed transactions this year have exceeded $1 billion, including $560 million for the Jonah and Pinedale fields in Wyoming, $351 million for the South Belridge and Brea fields in California, $76 million for the Salt Creek Field in Wyoming, $32 million for two South Texas asset packages and approximately $25 million (~$21 million and ~$4 million) for a portion of our Permian Basin assets.

The Company has also signed a purchase and sale agreement related to the majority of its remaining South Texas assets for approximately $20 million, subject to normal closing adjustments and transaction costs. We expect this transaction to close in the third quarter of 2017.

Pending and future asset sales
LINN continues to market the remaining packages in Permian, Williston and South Texas. Additionally, the Company plans to sell its interest in the Altamont Bluebell Field in Utah and its mature waterfloods in Oklahoma. LINN continues to work with Jefferies LLC to explore strategic alternatives for the Company.

Eliminated all debt and negotiating a new credit facility
As of August 1, 2017, the Company had extinguished all outstanding debt and is in the final stages of negotiating a new senior revolving credit facility. The new facility is expected to have an initial borrowing base of $500 million.

Initiated share repurchase program and evaluation of uplisting
On June 28, 2017, the Board of Directors authorized an increase in the share repurchase program to a total of $200 million, subject to the closing of the new credit facility. As of July 31, 2017, the Company had purchased approximately 841,000 shares in the open market for approximately $27 million at an average price of $32.41 per share and continues to evaluate further repurchases. In addition, LINN is evaluating uplisting to the New York Stock Exchange or NASDAQ in 2018.

General & administrative expense
Current general and administrative (“G&A”) expense guidance for 2017 is $95 million, down significantly from the previous 2017 guidance of $120 million. Following the completion of all contemplated asset sales, closing the Roan transaction and related transition periods, the Company expects an ongoing annual G&A run rate of approximately $60 million and continues to evaluate further value-adding reductions to our cost structure.

NW STACK activity continues to increase
The Company has a significant acreage position of approximately 105,000 net acres in the NW STACK and offset horizontal results in the Osage and Meramec have been positive with recent IP-30 rates of more than 1,000 BOE/d. Industry activity has significantly increased in the area, with 41 rigs currently running and 101 horizontal well permits filed in the second quarter of 2017 compared to 43 in the first quarter of 2017. LINN is evaluating adding a rig in the NW STACK to test horizontal potential along with evaluating several other potential productive horizons in the area.

Blue Mountain Midstream
The Company’s subsidiary, LINN Midstream, LLC, has been renamed Blue Mountain Midstream LLC (“Blue Mountain”) and holds all previously held LINN Midstream assets, including Chisholm Trail in central Oklahoma and the Jayhawk natural gas processing plant in southwest Kansas. The rebranding of Blue Mountain highlights the significant value of the Company’s growing midstream business that is additive to the upstream value estimates provided at emergence. Blue Mountain charges the upstream business a market rate that is included in the upstream economics.

Chisholm Trail Cryogenic gas plant in the Merge
Chisholm Trail is located in the heart of the prolific liquids-rich Merge/SCOOP/STACK play and has approximately 30 miles of existing gas gathering pipeline and approximately 60 MMcf/d of current refrigeration capacity. LINN acreage recently contributed to Roan remains dedicated to Chisholm Trail. Infrastructure expansions are underway to add 35 miles of low-pressure gathering, increase compression throughput and construct a new cryogenic plant to improve liquids recoveries. Blue Mountain has entered into a definitive agreement with BCCK to construct a highly efficient, state-of-the-art 225 MMcf/d cryogenic gas processing facility with a total capacity of 250 MMcf/d. Construction is underway and the facility is expected to be commissioned during the second quarter of 2018. Blue Mountain is also pursuing third-party dedications to accelerate throughput growth for the facility. The Company estimates that a midstream business of this type at full capacity could generate annual EBITDA (a non-GAAP financial measure) between $100 million and $125 million.

Jayhawk natural gas processing plant in the Hugoton Basin
Blue Mountain owns and operates the Jayhawk natural gas processing plant in southwest Kansas with a capacity of approximately 450 MMcf/d, allowing the Company to receive maximum value from the liquids-rich natural gas and helium produced in the area. The Company’s production in the area is delivered to the plant at market gathering rates via a system of approximately 3,930 miles of pipeline and related facilities operated by the Company, of which approximately 2,075 miles of pipeline are owned by the Company.

Emerging Growth Potential
North Louisiana
The Company has approximately 150,000 net acres that are largely held by production with a focus on acreage in the Ruston and Calhoun areas. There are 10 active rigs in the areas and more than 30 drilling permits have been filed in the first half of 2017. LINN recently drilled two operated horizontal wells in Ruston for our first test of the Lower Red and our third test of the Upper Red. The recently completed Lower Red test continues to clean up with a choked back 24-hr IP rate of 12.6 MMcf/d and the completion of the Upper Red is expected to commence in the next 30 days. Additionally, the Company plans to drill an operated horizontal well to test the Calhoun acreage in the fourth quarter of 2017.

East Texas
LINN has approximately 115,000 net acres that are held by production in East Texas. Horizontal activity is increasing in the area with seven active horizontal rigs and more than 40 horizontal drilling permits filed in the first half of 2017 that target several prospective formations including the Cotton Valley and Bossier formations. The Company sees significant upside by applying enhanced horizontal drilling and completion technologies across its acreage position and is currently drilling one of two planned operated horizontal wells for the second half of 2017.

Washakie
LINN has approximately 200,000 net acres that are held by production in the Washakie, where there has been significant offset horizontal activity. There are currently three active horizontal drilling rigs in the area with more than 60 horizontal drilling permits approved in the first half of 2017. Emerging horizontal targets include the Lewis, Almond marine bar and Middle Almond formations with peak IP-30 well results of greater than 10 MMcf/d. LINN continues to evaluate the play and plans to participate in non-operated horizontal activity in the second half of 2017.

Arkoma
The Company has approximately 49,000 net acres in the Arkoma area that are held by production and there are currently 10 active horizontal rigs in the area with 50 horizontal drilling permits filed in the first half of 2017. About 40 percent of the operated sections have only one horizontal well and LINN is evaluating infill development using enhanced drilling and completion technology.

Capital spending
Adjusted for discontinued operations and the sale of Jonah, LINN forecasted $49 million of oil and natural gas capital for the second quarter of 2017. Actual oil and gas capital for the quarter was approximately $71 million. This was higher than guidance primarily due to an increase in lease acquisition spending in the Merge.

The Company has reduced capital guidance for the full year 2017 from $413 million to $338 million. The reduction is primarily related to the expected closing of all announced asset sales and the contribution of our Merge/SCOOP/STACK acreage to Roan, partially offset by increased non-operated horizontal drilling capital and leasing in the Merge area.

Second Quarter Actuals versus Adjusted Guidance
Second quarter guidance has been adjusted for the closing of the Jonah sale at the end of May and classification of California properties as discontinued operations.

Q2 ActualsAdjusted Q2 Guidance
Net Production (MMcfe/d) 710 663 - 737
Natural gas (MMcf/d) 432 428 - 475
Oil (Bbls/d) 21,600 19,122 - 21,609
NGL (Bbls/d) 24,800 20,135 - 22,044
Other revenues, net (in thousands) (1)$11,962 $9,000 -$10,000
Costs (in thousands)$ 126,316 $ 122,000 -$ 137,000
Lease operating expenses$71,057 $68,000 -$75,000
Transportation expenses$37,388 $35,000 -$40,000
Taxes, other than income taxes$17,871 $19,000 -$22,000
General and administrative expenses (2)$19,036 $27,000 -$30,000
Costs per Mcfe (Mid-Point)$1.96 $2.03
Lease operating expenses$1.10 $1.12
Transportation expenses$0.58 $0.59
Taxes, other than income taxes$0.28 $0.32
General and administrative expenses (2)$0.29 $0.45
Targets (Mid-Point) (in thousands)
Adjusted EBITDAX(3)$111,932 $95,000
Interest expense$7,551 $9,000
Oil and natural gas capital$70,640 $49,000
Total capital$95,741 $85,000
Weighted Average NYMEX Differentials
Natural gas (MMBtu)($0.37)($0.35)-($0.15)
Oil (Bbl)($2.86)($5.00)-($3.00)
NGL price as a % of crude oil price 42%34% - 38%

__________________________

  1. Includes other revenues and margin on marketing activities
  2. As included in operating cash flow and excludes share-based compensation expenses of approximately $15 million
  3. Excludes Adjusted EBITDAX from discontinued operations of approximately $12 million

Third Quarter, Fourth Quarter and Full Year 2017 Guidance Update
Guidance estimates have been adjusted for the closing of the Jonah, Salt Creek, South Texas, Permian and California sales as well as expected timing of the closing for Roan. The guidance provided below excludes LINN’s 50% equity interest in Roan after closing.

Q3 2017EQ4 2017EFY 2017E
Net Production (MMcfe/d)540 – 600500 – 550618 – 655
Natural gas (MMcf/d)330 – 365325 – 355390 – 415
Oil (Bbls/d)16,000 – 18,00014,000 – 16,00018,000 – 19,000
NGL (Bbls/d)19,000 – 21,00015,000 – 16,50020,000 – 21,000
Other revenues, net (in thousands) (1)$ 7,000 - $ 8,000$ 7,000 - $ 8,000$ 40,000 – $ 42,000
Costs (in thousands)$ 101,000 – $ 111,000$ 96,000 – $ 105,000$ 456,000 – $ 485,000
Lease operating expenses$ 56,000 – $ 62,000$ 55,000 – $ 60,000$ 255,000 – $ 270,000
Transportation expenses$ 31,000 – $ 34,000$ 28,000 – $ 31,000$ 136,000 – $ 144,000
Taxes, other than income taxes$ 14,000 – $ 15,000$ 13,000 – $ 14,000$ 65,000 – $ 71,000
General and administrative expenses (2)$ 24,000 – $ 27,000$ 22,000 – $ 24,000$ 92,000 – $ 99,000
Costs per Mcfe (Mid-Point) $2.03$2.08 $2.02
Lease operating expenses$1.13$1.19$1.13
Transportation expenses$0.62$0.61$0.60
Taxes, other than income taxes$0.28$0.28$0.29
General and administrative expenses (2)$0.49$0.48$0.41
Targets (Mid-Point) (in thousands)
Adjusted EBITDAX(3)$71,000$63,000$360,000
Interest expense$1,000$—$28,000
Oil and natural gas capital$78,000$24,000$229,000
Total capital$116,000$62,000$338,000
Weighted Average NYMEX Differentials
Natural gas (MMBtu)($0.35) – ($0.25)($0.35) – ($0.25)($0.35) – ($0.25)
Oil (Bbl)($4.00) – ($3.00)($4.00) – ($3.00)($4.00) – ($3.00)
NGL price as a % of crude oil price34% – 40%34% – 40%36% – 42%


Unhedged Commodity Price Assumptions (4)JulyAugSeptOctNovDec2017E
Natural gas (MMBtu)$3.07$2.97$2.96$3.00$3.07$3.22$3.15
Oil (Bbl)$45.86$45.77$45.95$46.19$46.45$46.69$48.09
NGL (Bbl)$17.04$16.99$17.28$17.02$17.09$17.17$18.95

___________________________

  1. Includes other revenues and margin on marketing activities
  2. As included in operating cash flow and excludes share-based compensation expenses
  3. Excludes Adjusted EBITDAX from discontinued operations of approximately $4 million for Q3 2017E, and $31 million for FY 2017E
  4. Strip prices as of July 21, 2017

Hedging Update
2017
2018
2019
Natural GasVolume (MMMBtu/d)Average Price
(per MMBtu)
Volume (MMMBtu/d)Average Price
(per MMBtu)
Volume (MMMBtu/d)Average Price
(per MMBtu)
Swaps370$3.17131$3.0131$2.97
OilVolume (Bbls/d)Average Price
(per Bbl)
Volume
(Bbls/d)
Average Price
(per Bbl)
Volume
(Bbls/d)
Average Price
(per Bbl)
Swaps12,000$52.131,500$54.07--
Collars--5,000$50.00 - $55.505,000$50.00 - $55.50

Form 10‑Q / Earnings Call
LINN plans to file its Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, with the Securities and Exchange Commission on August 3, 2017 and will host a conference call Thursday, August 3, 2017 at 10 a.m. (CDT) to discuss the Company’s second quarter 2017 results. Investors and analysts are invited to participate in the call by dialing (844) 625-4392, or (409) 497-0988 for international calls using Conference ID: 51104553. Interested parties may also listen over the internet at www.linnenergy.com. A replay of the call and a transcript will be available on the Company’s website until August 17, 2017.

Supplemental information can be found at the following link on our website: http://ir.linnenergy.com/presentations.cfm

About LINN Energy

LINN Energy, Inc. was formed in February 2017 as the reorganized successor to LINN Energy, LLC. Headquartered in Houston, Texas, the Company’s core focus is the upstream and midstream development of the Merge/SCOOP/STACK in Oklahoma. Additionally, the Company is pursuing emerging horizontal opportunities in the Mid-Continent, Rockies, North Louisiana and East Texas while continuing to add value by efficiently operating and applying new technology to a diverse set of long-life producing assets.

Forward-Looking Statements
Statements made in this press release that are not historical facts are “forward-looking statements.” These statements are based on certain assumptions and expectations made by the Company which reflect management’s experience, estimates and perception of historical trends, current conditions, and anticipated future developments. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or anticipated in the forward-looking statements. These include risks relating to financial performance and results, ability to improve our financial results and profitability following emergence from bankruptcy, availability of sufficient cash flow to execute our business plan, ability to execute planned asset sales, continued low or further declining commodity prices and demand for oil, natural gas and natural gas liquids, ability to hedge future production, ability to replace reserves and efficiently develop current reserves, the capacity and utilization of midstream facilities, the regulatory environment and other important factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. These and other important factors could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. Please read “Risk Factors” in the Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and other public filings. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information or future events.

Condensed Consolidated Balance Sheets (Unaudited)
Successor Predecessor
June 30, 2017 December 31, 2016
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents$16,903 $694,857
Accounts receivable – trade, net163,935 198,064
Derivative instruments23,959
Restricted cash98,616 1,602
Other current assets71,836 105,310
Assets held for sale236,421
Current assets of discontinued operations235,643 701
Total current assets847,313 1,000,534
Noncurrent assets:
Oil and natural gas properties (successful efforts method)1,444,110 12,349,117
Less accumulated depletion and amortization(37,572) (9,843,908)
1,406,538 2,505,209
Other property and equipment441,483 618,262
Less accumulated depreciation(12,739) (217,724)
428,744 400,538
Derivative instruments12,759
Deferred income taxes492,182
Other noncurrent assets13,980 13,984
Noncurrent assets of discontinued operations 740,326
518,921 754,310
Total noncurrent assets2,354,203 3,660,057
Total assets$3,201,516 $4,660,591
LIABILITIES AND EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accrued expenses$268,605 $295,081
Derivative instruments486 82,508
Current portion of long-term debt, net 1,937,729
Other accrued liabilities135,416 25,979
Liabilities held for sale36,387
Current liabilities of discontinued operations28,218 321
Total current liabilities469,112 2,341,618
Derivative instruments 11,349
Long-term debt183,430
Other noncurrent liabilities264,025 360,405
Noncurrent liabilities of discontinued operations 39,202
Liabilities subject to compromise 4,305,005
Temporary equity:
Redeemable noncontrolling interests 28,132
Stockholders’/unitholders’ equity (deficit):
Predecessor units issued and outstanding 5,386,885
Predecessor accumulated deficit (7,783,873)
Successor Class A common stock89
Successor additional paid-in capital2,043,927
Successor retained earnings212,801
Total stockholders’/unitholders’ equity (deficit)2,256,817 (2,396,988)
Total liabilities and equity (deficit)$3,201,516 $4,660,591


Condensed Consolidated Statements of Operations (Unaudited)
Successor Predecessor
Three Months Ended June 30, 2017 Three Months Ended June 30, 2016
(in thousands, except per share and per unit amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales$243,167 $195,847
Gains (losses) on oil and natural gas derivatives45,714 (183,794)
Marketing revenues12,547 8,551
Other revenues6,391 23,641
307,819 44,245
Expenses:
Lease operating expenses71,057 70,367
Transportation expenses37,388 41,092
Marketing expenses6,976 6,727
General and administrative expenses34,458 52,169
Exploration costs811 48
Depreciation, depletion and amortization51,987 86,358
Taxes, other than income taxes17,871 18,180
(Gains) losses on sale of assets and other, net(306,969) 2,517
(86,421) 277,458
Other income and (expenses):
Interest expense, net of amounts capitalized(7,551) (50,320)
Other, net(1,163) (1,226)
(8,714) (51,546)
Reorganization items, net(3,377) 485,798
Income from continuing operations before income taxes382,149 201,039
Income tax expense (benefit)158,770 (3,652)
Income from continuing operations223,379 204,691
Income (loss) from discontinued operations, net of income taxes(3,322) 3,801
Net income$220,057 $208,492
Income from continuing operations per share/unit - Basic$2.49 $0.58
Income from continuing operations per share/unit - Diluted$2.47 $0.58
Income (loss) from discontinued operations per share/unit - Basic$(0.04) $0.01
Income (loss) from discontinued operations per share/unit - Diluted$(0.04) $0.01
Net income per share/unit - Basic$2.45 $0.59
Net income per share/unit - Diluted$2.43 $0.59
Weighted average shares/units outstanding - Basic 89,849 352,789
Weighted average shares/units outstanding - Diluted 90,484 352,789


Condensed Consolidated Statements of Operations – Continued (Unaudited)
Successor Predecessor
Four Months Ended June 30, 2017 Two Months Ended February 28, 2017 Six Months Ended June 30, 2016
(in thousands, except per share and per unit amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales$323,492 $188,885 $380,288
Gains (losses) on oil and natural gas derivatives33,755 92,691 (74,341)
Marketing revenues15,461 6,636 17,612
Other revenues8,419 9,915 51,947
381,127 298,127 375,506
Expenses:
Lease operating expenses95,687 49,665 153,613
Transportation expenses51,111 25,972 83,623
Marketing expenses9,515 4,820 14,560
General and administrative expenses44,869 71,745 135,889
Exploration costs866 93 2,741
Depreciation, depletion and amortization71,901 47,155 175,467
Impairment of long-lived assets 123,316
Taxes, other than income taxes24,948 14,877 35,541
(Gains) losses on sale of assets and other, net(306,524) 672 3,786
(7,627) 214,999 728,536
Other income and (expenses):
Interest expense, net of amounts capitalized(11,751) (16,725) (134,193)
Other, net(1,551) (149) (1,158)
(13,302) (16,874) (135,351)
Reorganization items, net(5,942) 2,331,189 485,798
Income (loss) from continuing operations before income taxes369,510 2,397,443 (2,583)
Income tax expense (benefit)153,455 (166) 6,594
Income (loss) from continuing operations216,055 2,397,609 (9,177)
Loss from discontinued operations, net of income taxes(3,254) (548) (1,130,077)
Net income (loss)$212,801 $2,397,061 $(1,139,254)
Income (loss) from continuing operations per share/unit - Basic$2.41 $6.80 $(0.02)
Income (loss) from continuing operations per share/unit - Diluted$2.40 $6.80 $(0.02)
Loss from discontinued operations per share/unit - Basic$(0.04) $(0.01) $(3.21)
Loss from discontinued operations per share/unit - Diluted$(0.04) $(0.01) $(3.21)
Net income (loss) per share/unit - Basic$2.37 $6.79 $(3.23)
Net income (loss) per share/unit - Diluted$2.36 $6.79 $(3.23)
Weighted average shares/units outstanding - Basic 89,849 352,792 352,511
Weighted average shares/units outstanding - Diluted 90,065 352,792 352,511


Condensed Consolidated Statements of Cash Flows (Unaudited)

Successor Predecessor
Four Months Ended June 30, 2017 Two Months Ended February 28, 2017 Six Months Ended June 30, 2016
(in thousands)
Cash flow from operating activities:
Net income (loss)$212,801 $2,397,061 $(1,139,254)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Loss from discontinued operations3,254 548 1,130,077
Depreciation, depletion and amortization71,901 47,155 175,467
Impairment of long-lived assets 123,316
Deferred income taxes131,055 (166) 3,850
Noncash (gains) losses on oil and natural gas derivatives(25,826) (104,263) 931,251
Share-based compensation expenses19,599 50,255 18,553
Amortization and write-off of deferred financing fees82 1,338 9,227
(Gains) losses on sale of assets and other, net(293,811) 1,069 3,929
Reorganization items, net (2,359,364) (498,954)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net27,212 (7,216) (12,046)
(Increase) decrease in other assets(1,245) 402 (19,039)
Increase in restricted cash (80,164)
Increase (decrease) in accounts payable and accrued expenses(49,984) 20,949 47,062
Increase in other liabilities22,421 2,801 26,150
Net cash provided by (used in) operating activities – continuing operations117,459 (29,595) 799,589
Net cash provided by operating activities – discontinued operations13,966 8,781 1,612
Net cash provided by (used in) operating activities131,425 (20,814) 801,201
Cash flow from investing activities:
Development of oil and natural gas properties(61, 534) (50,597) (80,909)
Purchases of other property and equipment(27,287) (7,409) (13,655)
Proceeds from sale of properties and equipment and other641, 219 (166) (2,713)
Net cash provided by (used in) investing activities – continuing operations552,398 (58,172) (97,277)
Net cash provided by (used in) investing activities – discontinued operations(1,645) (584) 26,166
Net cash provided by (used in) investing activities550,753 (58,756) (71,111)
Cash flow from financing activities:
Proceeds from rights offering, net 514,069
Proceeds from borrowings160,000 978,500
Repayments of debt(876,570) (1,038,986) (913,210)
Debt issuance costs paid(2,973) (623)
Payment to holders of claims under the second lien notes (30,000)
Other(87) (6,015) (20,687)
Net cash provided by (used in) financing activities – continuing operations(719,630) (560,932) 43,980
Net cash used in financing activities – discontinued operations (1,593)
Net cash provided by (used in) financing activities(719,630) (560,932) 42,387
Net increase (decrease) in cash and cash equivalents(37,452) (640,502) 772,477
Cash and cash equivalents:
Beginning54,355 694,857 2,168
Ending16,903 54,355 774,645
Less cash and cash equivalents of discontinued operations at end of period (15,008)
Ending – continuing operations$16,903 $54,355 $759,637

Adjusted EBITDAX (Non-GAAP Measure)

The non-GAAP financial measure of adjusted EBITDAX, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, this non-GAAP measure should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for GAAP.

Adjusted EBITDAX is a measure used by Company management to evaluate the Company's operational performance and for comparisons to the Company's industry peers. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company's financial results.

The following presents a reconciliation of net income (loss) to adjusted EBITDAX:

Three Months Ended June 30,
Six Months Ended June 30,
2017
2016 2017 (1)
2016
(in thousands)
Net income (loss)$ 220,057 $ 208,492 $ 2,609,862 $ (1,139,254)
Plus (less):
(Income) loss from discontinued operations 3,322 (3,801) 3,802 1,130,077
Interest expense 7,551 50,320 28,476 134,193
Income tax expense (benefit) 158,770 (3,652) 153,289 6,594
Depreciation, depletion and amortization 51,987 86,358 119,056 175,467
Exploration costs 811 48 959 2,741
EBITDAX 442,498 337,765 2,915,444 309,818
Plus (less):
Impairment of long-lived assets 123,316
Noncash (gains) losses on oil and natural gas derivatives (43,567) 349,158 (130,089) 574,416
Noncash settlements on derivatives (2) 34,335 34,335
Accrued settlements on oil derivative contracts related to current production period (3) 1,583 (65,492) 2,885 (73,354)
Share-based compensation expenses 15,422 6,128 69,854 18,553
Write-off of deferred financing fees 1,332 1,348
(Gains) losses on sale of assets and other, net (4) (307,381) 2,018 (307,407) 3,376
Reorganization items, net (5) 3,377 (485,798) (2,325,247) (485,798)
Adjusted EBITDAX$ 111,932 $ 179,446 $ 225,440 $ 506,010

In addition, the Company reported the following other items:

Three Months Ended June 30,
Six Months Ended June 30,

2017
2016
2017 (1)
2016
(in thousands)
Prepetition restructuring costs included in general and administrative expenses (6)$ $2,403 $ $19,567
Premiums paid for put options that settled during the period (7) (20,761) (58,246)

  1. All amounts reflect the combined results of the four months ended June 30, 2017 (successor) and the two months ended February 28, 2017 (predecessor).
  2. Represent derivative settlements that were paid directly by the counterparties to the lenders under the predecessor’s credit facility, and as such were not included on the Company’s consolidated statement of cash flows.
  3. Represent amounts related to oil derivative contracts that settled during the respective period (contract terms had expired) but cash had not been received as of the end of the period.
  4. Primarily represent gains or losses on the sale of assets, gains or losses on inventory valuation and amortization of basis difference for equity method investments.
  5. Represent costs and income directly associated with the Company’s filing for voluntary reorganization under Chapter 11 of the U.S. Bankruptcy Code since the petition date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined.
  6. Represent restructuring costs incurred by the Company prior to its filing for voluntary reorganization under Chapter 11 of the U.S. Bankruptcy Code, which are included in general and administrative expenses.
  7. Represent premiums paid at inception for put options that settled during the respective period. The Company has not purchased any put options since 2012.


CONTACTS: LINN Energy, Inc. Investors: Thomas Belsha, Vice President — Investor Relations & Corporate Development (281) 840-4110 ir@linnenergy.com

Source:LINN Energy, LLC