HOUSTON, March 23, 2017 (GLOBE NEWSWIRE) -- LINN Energy, Inc. (“LINN” or the “Company”) announced today financial and operating results for the fourth quarter and the year ended Dec. 31, 2016 along with 2017 guidance.
The Company highlights the following:
- Successfully emerged from financial restructuring on Feb. 28, 2017
- Reduced debt by more than $5 billion to total debt of $900 million at Feb. 28, 2017
- Initiated development on ~185,000 net acres in the prolific SCOOP / STACK / Merge play
- Constructed the Chisholm Trail Midstream facility, a strategic gathering and refrigeration system in the Merge
- Increased proved reserves by 2.5% to approximately 3.5 Tcfe on more than 2.6 million net acres
- Proved PV-10 (a non-GAAP financial measure) of ~$3.3 billion at Feb. 15, 2017 strip prices
- Forecast of ~9% total company production growth (Dec. 16 – Dec. 17), from a 2017 oil and gas capital program of $300 million, supported by a 150% growth rate in the Merge play alone
- Expected quotation on the OTCQB market under the symbol LINN in the early second quarter of 2017
“This past year was transformational for the Company as we successfully emerged from financial restructuring while still surpassing our operational targets. We emerged with a strong balance sheet, high quality assets and a proven operating team focused on creating shareholder value,” said Mark E. Ellis, President and Chief Executive Officer. “Our employees and many business partners were important to our success through this process and we are thankful for their extraordinary efforts staying focused while continuing to work safely. As we transition from an upstream MLP to a growth-oriented E&P company, we are excited to accelerate development of our core SCOOP / STACK / Merge acreage in western Oklahoma along with additional emerging stacked pay horizontal opportunities.”
Key Financial Results1
| Fourth Quarter | Full Year | |||||||
| $ in millions, except per unit amounts | 2016 | 2015 | 2016 | 2015 | ||||
| Average daily production (MMcfe/d) | 779 | 856 | 828 | 897 | ||||
| Oil, natural gas and NGL sales | $ 278 | $ 247 | $ 952 | $ 1,151 | ||||
| Net loss | $ (834 | ) | $ (2,472 | ) | $ (2,172 | ) | $ (4,760 | ) |
| Adjusted EBITDAX (a non-GAAP financial measure) | $ 128 | $ 384 | $ 761 | $ 1,526 | ||||
| Net cash provided by (used in) operating activities | $ (7 | ) | $ 201 | $ 874 | $ 1,127 | |||
| Capital expenditures | $ 76 | $ 77 | $ 173 | $ 366 | ||||
| Gross wells drilled | 70 | 201 | 212 | 393 | ||||
| Lease operating expenses ($/Mcfe) | $ 1.15 | $ 1.17 | $ 1.05 | $ 1.15 | ||||
| Transportation expenses ($/Mcfe) | $ 0.52 | $ 0.54 | $ 0.53 | $ 0.51 | ||||
| General and administrative expenses ($/Mcfe) | $ 0.75 | $ 0.70 | $ 0.78 | $ 0.87 | ||||
| 1 All amounts reflect continuing operations with the exception of net loss. | ||||||||
Public Common Stock Listing
The Company is currently in the process of applying for quotation on the OTCQB market (which is operated by the OTC Markets Group, Inc.) for regular trading under the symbol LINN, which would replace any prior symbols once approved. The OTCQB is an interdealer quotation system providing real time “Level 2” quotes, which the Company believes constitutes an “established securities market” within the meaning of the Foreign Investment in Real Property Tax Act of 1980 (“FIRPTA”). The Company expects to complete the OTCQB quotation process in the early part of the second quarter of 2017 and will publicly disclose the results on a Form 8-K filed with the Securities and Exchange Commission.
Corporate Strategy
Prior to the Company’s emergence from voluntary reorganization under Chapter 11, the Company was an upstream master limited partnership with a strategy to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. Upon its emergence from bankruptcy with an improved balance sheet and greater liquidity, the Company is transitioning to a growth-oriented exploration and production company. The Board of Directors has engaged Jefferies LLC as lead advisor and has initiated a process to explore and evaluate potential strategic alternatives to maximize value.
The Company’s current focus is on accelerating the upstream and midstream development of its core SCOOP / STACK / Merge acreage in western Oklahoma, along with additional emerging stacked pay horizontal opportunities in the Mid-Continent, Rockies, North Louisiana and East Texas. The Company has a large inventory of high-return drilling and optimization projects to achieve organic growth and continues to add value by efficiently operating and applying new technology to mature fields. As part of its restructuring, the Company is marketing certain non-strategic assets to focus resources on growth opportunities and continues to leverage its experienced workforce and scalable infrastructure to maximize shareholder value.
Over the past 18 months, the Company made significant improvements in its overall cost structure, including LOE, transportation and G&A expenses. The Company expects continued improvement in its cost structure as the portfolio is realigned to be consistent with the strategy of a more focused growth-oriented exploration and production company. Throughout the financial restructuring process, the Company used Alix Partners to advise on LINN’s overall cost structure and has elected to extend this engagement to help with further review of G&A expenses as the new strategy is executed.
The Company recently posted a presentation to its website which includes an overview of the Company, an update on the capital structure, operational highlights of each asset area, cost savings and additional information on the marketing of non-strategic assets.
SCOOP / STACK / Merge has developed into a strategic growth asset
The Company has approximately 185,000 net acres that is more than 96% held by production in the SCOOP / STACK / Merge of western Oklahoma. There continues to be significant drilling activity (~50 active rigs) in this area as the industry is seeing increasingly stronger well results.
Merge
LINN holds approximately 49,000 net acres in 20 townships located in Canadian County and Grady County, Oklahoma between the SCOOP and STACK plays. To date, the Company has seven operated wells on production with strong results as shown in the table below. LINN has also participated in approximately 40 offset horizontal wells, providing additional production and geologic data. Early well results support the Company’s view that this acreage is comparable to core SCOOP / STACK positions, generating high rates-of-return in excess of 50% at $3.00 per MMBtu and $50.00 per Bbl. The Company currently sees potential for more than 1,400 drilling locations on its Merge acreage assuming 15 wells per section.
| LINN Operated Well | Working Interest | First Production | Zone | Lateral Length (ft) | Peak IP-30 (BOE/d) | % Oil | Total % Liquids | |||||||||||
| 1 | Barbour 12-10-7 1H | 90 | % | Mar-16 | Woodford | 4,209 | 668 | 29 | % | 50 | % | |||||||
| 2 | Hinparr 31-6-10-5 1XH | 90 | % | Nov-16 | Mississippi | 9,898 | 2,268 | 70 | % | 76 | % | |||||||
| 3 | McNeff 22-10-5 1H | 98 | % | Dec-16 | Mississippi | 4,391 | 961 | 44 | % | 54 | % | |||||||
| 4 | Braum 28-21-10-6 1XH | 95 | % | Dec-16 | Woodford | 10,206 | 1,445 | 13 | % | 30 | % | |||||||
| 5 | Braum 33-4-10-6 1XH | 77 | % | Dec-16 | Woodford | 10,179 | 769 | 35 | % | 56 | % | |||||||
| 6 | Langston 13-24-9-6 1XH | 33 | % | Jan-17 | Woodford | 10,135 | 837 | 18 | % | 39 | % | |||||||
| 7 | Jackson 25-24-10-6 1XH | 64 | % | Jan-17 | Mississippi | 9,769 | 1,175 | 52 | % | 61 | % | |||||||
In 2016, the Company had one operated rig running in the Merge resulting in an exit production rate of approximately 6,700 BOE/d. With the addition of a second rig in the second quarter 2017, LINN plans to drill 25 wells during the year, resulting in a forecasted 2017 exit production rate of approximately 16,700 BOE/d, representing a 150% growth rate. The Company expects to invest approximately $100 million in the Merge in 2017 on operated and non-operated drilling projects. An additional $34 million is budgeted for leasing, seismic and water management infrastructure.
Water Management
To support the operated horizontal development program in the Merge, LINN has allocated approximately $8 million in 2017 to construct a system to source, recycle, transfer and dispose of water. This system is critical in the Merge to allow the Company to recycle water, minimize supply interruptions, and greatly reduce completion and operating costs. LINN also sees future upside in handling third-party water.
Chisolm Trail Midstream
With our concentrated acreage position in the Merge, the Company is uniquely positioned to build a valuable midstream business. Existing gathering systems have insufficient takeaway capacity and are not designed for the richer natural gas produced from the Mississippi, Woodford and Hunton targets. The Company invested approximately $33 million in 2016 to build gathering, compression and a 60 MMcf/d refrigeration plant to meet the needs of our initial development phase.
Given our success, the Company plans to invest approximately $82 million in 2017 to expand capacity and install a 200 MMcfe/d cryogenic facility to further improve liquids recoveries. With an anticipated completion in the second quarter of 2018 at a total cost of $150 million, this expansion keeps pace with LINN’s operated horizontal development program and also supports the gathering of non-operated production as well as other third party volumes. The Company anticipates this midstream project to generate a rate-of-return of approximately 40% based only on the Company’s dedicated acreage. Economics can be enhanced by the addition of third party volumes. The Company sees additional upside beyond the 200 MMcf/d throughput target given the strategic location and recent successful drilling results in the area. The Company will evaluate further midstream investments as the play continues to develop.
Greater SCOOP / STACK
Additionally, the Company holds approximately 136,000 net acres across NW STACK / STACK / SCOOP. There is significant offset activity across this acreage position and LINN is actively evaluating investment opportunities as the industry continues to de-risk our acreage. The Company plans to participate in non-operated horizontal wells throughout the year and will look to acquire, partner or evaluate other opportunities to unlock value.
“We see a tremendous and unique opportunity in the Merge to accelerate development of high rate-of-return upstream projects while also building valuable midstream and water management businesses,” said the Board of Directors. “We expect that this integrated development strategy will maximize value of this vast resource position and result in meaningful EBITDAX growth for the Company.”
Emerging Growth Assets
The Company has more the 600,000 net acres that are more than 95% held by production in several maturing horizontal plays in the Rockies, Mid-Continent, East Texas and North Louisiana. Each of these plays has offset horizontal activity from multiple horizons and the potential for expanded development and significant growth on LINN’s leasehold.
Jonah – Rockies
LINN has drilled and completed 68 vertical wells and participated in three horizontal wells on the Company’s Jonah acreage. The most recent horizontal well saw a peak 24-hour rate of more than 11 MMcf/d of natural gas and 200 Bbl/d of condensate. In 2017, the Company plans to invest approximately $30 million of oil and natural gas capital in this area.
Washakie – Rockies
Significant offset horizontal activity continues across our acreage position in southern Wyoming, which has seen peak IP-30 well results of greater than 10 MMcf/d. LINN will evaluate participating in non-operated horizontal activity in 2017.
Bluebell Altamont – Rockies
There has been significant recent offset horizontal drilling activity in Bluebell Altamont Field. The Company has approved drilling an operated horizontal well in 2017 to test the Lower Green River formation on its substantial acreage.
Williston – Rockies
In 2016 the Company invested $23 million on non-operated horizontal activity targeting the middle Bakken and Three Forks formations. The Company plans to invest approximately $20 million of capital in 2017 for new horizontal wells along with ~50 additional wells that have been drilled and are awaiting completion.
Arkoma – Mid-Continent
The Company has approximately 49,000 net acres that are held by production and were initially developed horizontally. About 40% of the operated sections have only one well and a recent offset delivered initial production rates greater than 15 MMcf/d. As a result, LINN is evaluating further infill development using enhanced drilling and completion technology on this acreage. The Company plans to participate in several non-operated horizontal wells in 2017 and sees the possibility of adding an operated rig later in the year.
North Louisiana
In Ruston LINN has drilled two horizontal wells in the southeast extension of the Terryville Field. These wells were completed to the Upper Red formation resulting in IP-30s of 22 MMcfe/d and 16 MMcfe/d. In 2017 LINN plans to drill two operated horizontal wells targeting both the Upper and Lower Red formations.
Industry activity has been successful south and west of the Company’s Calhoun position, which is also on trend with the Terryville Field. LINN approved drilling an operated horizontal well in 2017 to test future potential across our acreage position of approximately 19,000 net acres.
East Texas
The Company has approximately 115,000 net acres that are more than 99% held by production. Within that acreage, the Cotton Valley Lime and Bossier formations have produced from horizontal wells and the Company sees significant upside by applying enhanced drilling and completion technologies across this large acreage position. LINN approved drilling two operated horizontal wells during 2017 to target these formations.
Regarding the emerging growth assets, the Board collectively commented, “In addition to the Company’s premier acreage position in the SCOOP/ STACK / Merge, we are excited about the opportunity to accelerate development in these emerging growth assets. We are committed to the capital investment necessary to further de-risk the acreage with a focus on maximizing the value of these assets for shareholders.”
More details of these core and emerging plays can be found in the Company’s recent presentation on its website.
2017 Guidance
The Company has approved a 2017 capital budget of $395 million that includes ~$300 million of oil and natural gas capital. Approximately $100 million is budgeted for Merge horizontal development, $65 million for emerging horizontal development and $40 million on land, seismic and water management infrastructure. Additionally in the Merge, $82 million of midstream capital is budgeted for the Chisholm Trail cryogenic facility expansion. The Company forecasts the capital program will result in ~9% production growth from Dec. 2016 to Dec. 2017 and live within cash flow excluding restructuring costs.
| $ in millions | |||||||
| Merge | Rest of LINN | 2017 Capital | |||||
| Horizontal development | $100 | $65 | $165 | ||||
| Vertical development and optimization | - | $95 | $95 | ||||
| Land, seismic and water infrastructure | $34 | $6 | $40 | ||||
| Oil and Gas Capital | $134 | $166 | $300 | ||||
| Plant and Pipeline | $82 | $2 | $84 | ||||
| Administrative | - | $11 | $11 | ||||
| Total Capital | $216 | $179 | $395 | ||||
The budget and forecasted production are subject to ongoing adjustments and have not been adjusted for the planned asset sales. Upon successful completion of assets sales, LINN will update guidance as soon as possible.
| 2017 Guidance Table | Q1 2017E (4) | FY 2017E (4) | |||||||
| Net Production | |||||||||
| Natural gas (MMcf/d) | 475 | - | 495 | 465 | - | 510 | |||
| Oil (Bbls/d) | 25,000 | - | 27,000 | 25,000 | - | 28,000 | |||
| NGL (Bbls/d) | 21,000 | - | 24,000 | 22,000 | - | 25,000 | |||
| Total (MMcfe/d) | 750 | - | 800 | 745 | - | 825 | |||
| Other revenues, net (in thousands) (1) | $13,500 | - | $15,500 | $42,000 | - | $46,000 | |||
| Costs (in thousands) | |||||||||
| Lease operating expenses (3) | $76,000 | - | $84,000 | $302,000 | - | $336,000 | |||
| Transportation expenses | 38,000 | - | 42,000 | 151,000 | - | 168,000 | |||
| Taxes, other than income taxes | 22,000 | - | 26,000 | 92,000 | - | 102,000 | |||
| Total operating expenses | $136,000 | - | $152,000 | $545,000 | - | $606,000 | |||
| General and administrative expenses (2)(3)(4) | $30,000 | - | $36,000 | $123,000 | - | $133,000 | |||
| Costs per Mcfe (Mid-Point) | |||||||||
| Lease operating expenses (3) | $1.14 | $1.11 | |||||||
| Transportation expenses | $0.57 | $0.55 | |||||||
| Taxes, other than income taxes | $0.35 | $0.34 | |||||||
| Total operating expenses | $2.06 | $2.00 | |||||||
| General and administrative expenses (2)(3)(4) | $0.47 | $0.45 | |||||||
| Targets (Mid-Point) (in thousands) | |||||||||
| Adjusted EBITDAX (4) | $122,000 | $490,000 | |||||||
| Interest expense | $25,000 | $64,000 | |||||||
| Total capital | $84,000 | $395,000 | |||||||
| Weighted Average NYMEX Differentials | |||||||||
| Natural gas (MMBtu) | ($0.32) - ($0.22) | ($0.35) - ($0.15) | |||||||
| Oil (Bbl) | ($4.50) - ($3.50) | ($5.00) - ($3.00) | |||||||
| NGL price as a % of crude oil price | 40% - 45% | 35% - 45% | |||||||
| Unhedged Commodity Price Assumptions | Jan | Feb | Mar | FY 2017E | |||||
| Natural gas (MMBtu) | $3.93 | $3.39 | $2.63 | $3.23 | |||||
| Oil (Bbl) | $52.61 | $53.46 | $51.77 | $50.48 | |||||
| ______________________________________________ | |||||||||
| (1) Includes other revenues, margin on marketing activities and ~$6 million of Berry management fee reimbursements | |||||||||
| (2) For the first quarter, two months of G&A expenses related to operating Berry’s assets are included. See footnote (1) for ~$6 million of Berry management fee reimbursements in ‘other revenues, net’ | |||||||||
| (3) As included in operating cash flow | |||||||||
| (4) Does not include any post-emergence restructuring costs | |||||||||
Hedging Update
LINN has hedged 370 MMBtu/d of the Company's expected natural gas production for 2017 at an average price of $3.17 per MMBtu. For 2018, LINN has hedged 110 MMBtu/d of the Company's expected natural gas production at an average price of $3.02 per MMBtu. For 2019, LINN has hedged 10 MMcf/d of the Company’s expected natural gas production at an average price of $3.08 per MMBtu.
LINN has hedged 12,000 Bbls/d of the Company's expected oil production for 2017 at an average price of $52.13 per Bbl. For 2018 and 2019, LINN has hedged 5,000 Bbls/d of the Company's expected oil production at an average price ranging from $50.00-$55.50 per Bbl.
Proved Reserves
As of Dec. 31, 2016, the Company’s total proved reserves were approximately 3.5 Tcfe, of which approximately 65% were natural gas, 17% were oil and 18% were NGL. Changes in estimated total proved reserves from Dec. 31, 2015, to Dec. 31, 2016, as well as the Company’s standardized measure of discounted future net cash flows and PV-10, as of Dec. 31, 2016, is shown below.
| Proved reserves at Dec. 31, 2015 in Bcfe | 3,435 | ||
| Revisions of previous estimates | (29 | ) | |
| Extensions, discoveries and other additions | 417 | ||
| Production | (303 | ) | |
| Proved reserves at Dec. 31, 2016 | 3,520 | ||
| Standardized measure of discounted future net cash flows ($ in millions) | $1,929 | ||
| Plus: Difference due to strip prices | $1,184 | ||
| Plus: Difference due to the inclusion of helium | $179 | ||
| Proved PV-10 at Feb. 15, 2017 strip prices (a non-GAAP financial measure) | $3,292 | ||
| Consolidated Balance Sheets (Unaudited) | ||||||||
| December 31, | ||||||||
| 2016 | 2015 | |||||||
| (in thousands, except unit amounts) | ||||||||
| ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 694,857 | $ | 1,145 | ||||
| Accounts receivable – trade, net | 198,064 | 179,124 | ||||||
| Derivative instruments | — | 1,207,012 | ||||||
| Other current assets | 107,613 | 74,696 | ||||||
| Current assets of discontinued operations | — | 81,191 | ||||||
| Total current assets | 1,000,534 | 1,543,168 | ||||||
| Noncurrent assets: | ||||||||
| Oil and natural gas properties (successful efforts method) | 13,232,959 | 13,110,094 | ||||||
| Less accumulated depletion and amortization | (9,999,560 | ) | (9,501,327 | ) | ||||
| 3,233,399 | 3,608,767 | |||||||
| Other property and equipment | 636,487 | 597,216 | ||||||
| Less accumulated depreciation | (224,547 | ) | (183,139 | ) | ||||
| 411,940 | 414,077 | |||||||
| Derivative instruments | — | 566,401 | ||||||
| Other noncurrent assets | 14,718 | 24,182 | ||||||
| Noncurrent assets of discontinued operations | — | 3,780,285 | ||||||
| 14,718 | 4,370,868 | |||||||
| Total noncurrent assets | 3,660,057 | 8,393,712 | ||||||
| Total assets | $ | 4,660,591 | $ | 9,936,880 | ||||
| LIABILITIES AND UNITHOLDERS’ DEFICIT | ||||||||
| Current liabilities: | ||||||||
| Accounts payable and accrued expenses | $ | 295,077 | $ | 338,247 | ||||
| Derivative instruments | 82,508 | — | ||||||
| Current portion of long-term debt, net | 1,937,729 | 2,841,518 | ||||||
| Other accrued liabilities | 26,304 | 102,858 | ||||||
| Current liabilities of discontinued operations | — | 1,017,899 | ||||||
| Total current liabilities | 2,341,618 | 4,300,522 | ||||||
| Derivative instruments | 11,349 | 857 | ||||||
| Long-term debt, net | — | 4,447,308 | ||||||
| Other noncurrent liabilities | 399,607 | 399,676 | ||||||
| Liabilities subject to compromise | 4,305,005 | — | ||||||
| Noncurrent liabilities of discontinued operations | — | 1,057,418 | ||||||
| Unitholders’ deficit: | ||||||||
| 352,792,474 units and 355,017,428 units issued and outstanding at December 31, 2016, and December 31, 2015, respectively | 5,386,885 | 5,343,116 | ||||||
| Accumulated deficit | (7,783,873 | ) | (5,612,017 | ) | ||||
| (2,396,988 | ) | (268,901 | ) | |||||
| Total liabilities and unitholders’ deficit | $ | 4,660,591 | $ | 9,936,880 | ||||
| Consolidated Statements of Operations (Unaudited) | ||||||||||||||||
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| (in thousands, except per unit amounts) | ||||||||||||||||
| Revenues and other: | ||||||||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 277,955 | $ | 247,226 | $ | 952,132 | $ | 1,151,240 | ||||||||
| Gains (losses) on oil and natural gas derivatives | (90,155 | ) | 270,849 | (164,330 | ) | 1,027,014 | ||||||||||
| Marketing revenues | 9,644 | 8,375 | 36,505 | 43,876 | ||||||||||||
| Other revenues | 21,806 | 10,070 | 93,406 | 97,883 | ||||||||||||
| 219,250 | 536,520 | 917,713 | 2,320,013 | |||||||||||||
| Expenses: | ||||||||||||||||
| Lease operating expenses | 82,475 | 92,507 | 317,046 | 375,840 | ||||||||||||
| Transportation expenses | 36,965 | 42,689 | 161,037 | 167,561 | ||||||||||||
| Marketing expenses | 8,243 | 5,288 | 29,736 | 35,278 | ||||||||||||
| General and administrative expenses | 53,481 | 54,826 | 237,841 | 285,996 | ||||||||||||
| Exploration costs | 1,335 | 5,441 | 4,080 | 9,473 | ||||||||||||
| Depreciation, depletion and amortization | 94,540 | 115,510 | 404,237 | 554,386 | ||||||||||||
| Impairment of long-lived assets | — | 2,955,078 | 165,044 | 4,960,144 | ||||||||||||
| Taxes, other than income taxes | 15,155 | 13,033 | 74,838 | 111,302 | ||||||||||||
| (Gains) losses on sale of assets and other, net | 9,462 | (878 | ) | 15,558 | (195,490 | ) | ||||||||||
| 301,656 | 3,283,494 | 1,409,417 | 6,304,490 | |||||||||||||
| Other income and (expenses): | ||||||||||||||||
| Interest expense, net of amounts capitalized | (27,823 | ) | (98,646 | ) | (192,862 | ) | (460,635 | ) | ||||||||
| Gain on extinguishment of debt | — | 505,732 | — | 708,050 | ||||||||||||
| Other, net | (178 | ) | (4,628 | ) | (1,536 | ) | (13,965 | ) | ||||||||
| (28,001 | ) | 402,458 | (194,398 | ) | 233,450 | |||||||||||
| Reorganization items, net | (145,838 | ) | — | 311,599 | — | |||||||||||
| Loss from continuing operations before income taxes | (256,245 | ) | (2,344,516 | ) | (374,503 | ) | (3,751,027 | ) | ||||||||
| Income tax expense (benefit) | 8,250 | 1,229 | 11,194 | (6,393 | ) | |||||||||||
| Loss from continuing operations | (264,495 | ) | (2,345,745 | ) | (385,697 | ) | (3,744,634 | ) | ||||||||
| Loss from discontinued operations, net of income taxes | (569,742 | ) | (126,462 | ) | (1,786,159 | ) | (1,015,177 | ) | ||||||||
| Net loss | $ | (834,237 | ) | $ | (2,472,207 | ) | $ | (2,171,856 | ) | $ | (4,759,811 | ) | ||||
| Loss per unit – continuing operations: | ||||||||||||||||
| Basic | $ | (0.75 | ) | $ | (6.69 | ) | $ | (1.10 | ) | $ | (10.91 | ) | ||||
| Diluted | $ | (0.75 | ) | $ | (6.69 | ) | $ | (1.10 | ) | $ | (10.91 | ) | ||||
| Loss per unit – discontinued operations: | ||||||||||||||||
| Basic | $ | (1.61 | ) | $ | (0.36 | ) | $ | (5.06 | ) | $ | (2.96 | ) | ||||
| Diluted | $ | (1.61 | ) | $ | (0.36 | ) | $ | (5.06 | ) | $ | (2.96 | ) | ||||
| Net loss per unit: | ||||||||||||||||
| Basic | $ | (2.36 | ) | $ | (7.05 | ) | $ | (6.16 | ) | $ | (13.87 | ) | ||||
| Diluted | $ | (2.36 | ) | $ | (7.05 | ) | $ | (6.16 | ) | $ | (13.87 | ) | ||||
| Weighted average units outstanding: | ||||||||||||||||
| Basic | 352,792 | 350,721 | 352,653 | 343,323 | ||||||||||||
| Diluted | 352,792 | 350,721 | 352,653 | 343,323 | ||||||||||||
| Distributions declared per unit | $ | — | $ | — | $ | — | $ | 0.938 | ||||||||
| Consolidated Statements of Cash Flows (Unaudited) | ||||||||
| Year Ended December 31, | ||||||||
| 2016 | 2015 | |||||||
| (in thousands) | ||||||||
| Cash flow from operating activities: | ||||||||
| Net loss | $ | (2,171,856 | ) | $ | (4,759,811 | ) | ||
| Adjustments to reconcile net loss to net cash provided by operating activities – continuing operations: | ||||||||
| Loss from discontinued operations | 1,786,159 | 1,015,177 | ||||||
| Depreciation, depletion and amortization | 404,237 | 554,386 | ||||||
| Impairment of long-lived assets | 165,044 | 4,960,144 | ||||||
| Unit-based compensation expenses | 44,218 | 56,136 | ||||||
| Gain on extinguishment of debt | — | (708,050 | ) | |||||
| Amortization and write-off of deferred financing fees | 13,356 | 30,993 | ||||||
| (Gains) losses on sale of assets and other, net | 13,007 | (188,200 | ) | |||||
| Deferred income taxes | 11,367 | 4,606 | ||||||
| Reorganization items, net | (365,367 | ) | — | |||||
| Derivatives activities: | ||||||||
| Total (gains) losses | 164,330 | (1,027,014 | ) | |||||
| Cash settlements | 503,943 | 1,130,640 | ||||||
| Cash settlements on canceled derivatives | 356,835 | 4,679 | ||||||
| Changes in assets and liabilities: | ||||||||
| (Increase) decrease in accounts receivable – trade, net | (71,059 | ) | 211,884 | |||||
| Increase in other assets | (17,733 | ) | (9,142 | ) | ||||
| Increase (decrease) in accounts payable and accrued expenses | 38,468 | (98,223 | ) | |||||
| Decrease in other liabilities | (515 | ) | (51,266 | ) | ||||
| Net cash provided by operating activities – continuing operations | 874,434 | 1,126,939 | ||||||
| Net cash provided by operating activities – discontinued operations | 6,080 | 122,518 | ||||||
| Net cash provided by operating activities | 880,514 | 1,249,457 | ||||||
| Cash flow from investing activities: | ||||||||
| Deconsolidation of Berry Petroleum Company, LLC cash | (28,549 | ) | — | |||||
| Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | — | — | ||||||
| Development of oil and natural gas properties | (180,313 | ) | (576,256 | ) | ||||
| Purchases of other property and equipment | (45,435 | ) | (48,967 | ) | ||||
| Investment in discontinued operations | — | (132,332 | ) | |||||
| Proceeds from sale of properties and equipment and other | (4,690 | ) | 345,770 | |||||
| Net cash used in investing activities – continuing operations | (258,987 | ) | (411,785 | ) | ||||
| Net cash provided by investing activities – discontinued operations | 23,147 | 101,368 | ||||||
| Net cash used in investing activities | (235,840 | ) | (310,417 | ) | ||||
| Cash flow from financing activities: | ||||||||
| Proceeds from sale of units | — | 233,427 | ||||||
| Proceeds from borrowings | 978,500 | 1,445,000 | ||||||
| Repayments of debt | (913,209 | ) | (1,828,461 | ) | ||||
| Distributions to unitholders | — | (323,878 | ) | |||||
| Financing fees and offering costs | (752 | ) | (26,678 | ) | ||||
| Settlement of advance from discontinued operations | — | (129,217 | ) | |||||
| Excess tax benefit from unit-based compensation | — | (9,467 | ) | |||||
| Other | (14,823 | ) | (74,958 | ) | ||||
| Net cash provided by (used in) financing activities – continuing operations | 49,716 | (714,232 | ) | |||||
| Net cash used in financing activities – discontinued operations | (1,701 | ) | (224,449 | ) | ||||
| Net cash provided by (used in) financing activities | 48,015 | (938,681 | ) | |||||
| Net increase in cash and cash equivalents | 692,689 | 359 | ||||||
| Cash and cash equivalents: | ||||||||
| Beginning | 2,168 | 1,809 | ||||||
| Ending | 694,857 | 2,168 | ||||||
| Less cash and cash equivalents of discontinued operations at end of year | — | (1,023 | ) | |||||
| Ending – continuing operations | $ | 694,857 | $ | 1,145 | ||||
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 loss to adjusted EBITDAX:
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| (in thousands) | ||||||||||||||||
| Net loss | $ | (834,237 | ) | $ | (2,472,207 | ) | $ | (2,171,856 | ) | $ | (4,759,811 | ) | ||||
| Plus (less): | ||||||||||||||||
| Loss from discontinued operations | 569,742 | 126,462 | 1,786,159 | 1,015,177 | ||||||||||||
| Interest expense | 27,823 | 98,646 | 192,862 | 460,635 | ||||||||||||
| Income tax expense (benefit) | 8,250 | 1,229 | 11,194 | (6,393 | ) | |||||||||||
| Depreciation, depletion and amortization | 94,540 | 115,510 | 404,237 | 554,386 | ||||||||||||
| Exploration costs | 1,335 | 5,441 | 4,080 | 9,473 | ||||||||||||
| EBITDAX | (132,547 | ) | (2,124,919 | ) | 226,676 | (2,726,533 | ) | |||||||||
| Plus (less): | ||||||||||||||||
| Impairment of long-lived assets | ― | 2,955,078 | 165,044 | 4,960,144 | ||||||||||||
| Gain on extinguishment of debt | ― | (505,732 | ) | ― | (708,050 | ) | ||||||||||
| (Gains) losses on derivatives | 90,155 | (270,849 | ) | 164,330 | (1,027,014 | ) | ||||||||||
| Cash settlements on derivatives | 3,868 | 320,326 | 503,943 | 1,130,640 | ||||||||||||
| Noncash settlements on derivatives (1) | ― | ― | 34,335 | ― | ||||||||||||
| Accrued settlements on oil derivative contracts related to current production period (2) | (389 | ) | 10 | (73,743 | ) | 28,588 | ||||||||||
| Unit-based compensation expenses | 19,704 | 8,218 | 44,218 | 56,136 | ||||||||||||
| Write-off of deferred financing fees | 60 | 2,926 | 1,462 | 6,790 | ||||||||||||
| (Gains) losses on sale of assets and other, net (3) | 876 | (726 | ) | 6,414 | (194,359 | ) | ||||||||||
| Reorganization items, net (4) | 145,838 | ― | (311,599 | ) | ― | |||||||||||
| Adjusted EBITDAX | $ | 127,565 | $ | 384,332 | $ | 761,080 | $ | 1,526,342 | ||||||||
In addition, the Company reported the following other items:
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| (in thousands) | |||||||||||||||
| Prepetition restructuring costs included in general and administrative expenses (5) | $ | ― | $ | ― | $ | 19,567 | $ | ― | |||||||
| Provision for legal matters (6) | 2,036 | ― | 2,036 | ― | |||||||||||
| Premiums paid for put options that settled during the period (7) | ― | (29,634 | ) | (58,246 | ) | (117,568 | ) | ||||||||
| (1) 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. | |||||||||||||||
| (2) 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. | |||||||||||||||
| (3) 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. | |||||||||||||||
| (4) 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. | |||||||||||||||
| (5) 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. | |||||||||||||||
| (6) Represents reserves and settlements related to legal matters. | |||||||||||||||
| (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. | |||||||||||||||
PV-10 (Non-GAAP Measure)
PV-10 represents the present value, discounted at 10% per year, of estimated future net cash flows. The Company’s calculation of PV-10 herein differs from the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC in that it is calculated before income taxes and including the impact of helium, using strip prices as of Feb. 15, 2017, rather than after income taxes and not including the impact of helium, using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month. The Company’s calculation of PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC.
The following presents a reconciliation of standardized measure of discounted future net cash flows to the Company’s calculation of PV-10 at Dec. 31, 2016 (in millions):
| Standardized measure of discounted future net cash flows (1) | $ | 1,929 | |||
| Plus: Difference due to strip prices(2) | 1,184 | ||||
| Plus: Difference due to the inclusion of helium | 179 | ||||
| PV-10 | $ | 3,292 | |||
| (1) Estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, which were $42.64 per Bbl and $2.48 per MMBtu. There are no future income tax expenses in the Company’s year-end 2016 standardized measure of discounted future net cash flows because the Company’s predecessor was not subject to federal income taxes as of December 31, 2016. | |||||
| (2) Feb. 15, 2017 strip prices | |||||
Form 10‑K
LINN plans to file its Annual Report on Form 10-K for the year ended Dec. 31, 2016, with the SEC on March 23, 2017.
Link to presentations: http://ir.linnenergy.com/presentations.cfm
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, ability to list our common stock on an established securities market, 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 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.
Reserve Estimates
The SEC permits oil and natural gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms. The Company may use terms in this press release that the SEC’s guidelines strictly prohibit in SEC filings, such as “estimated ultimate recovery” or “EUR,” “resources,” “net resources,” “total resource potential” and similar terms to estimate oil and natural gas that may ultimately be recovered. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves as used in SEC filings and, accordingly, are subject to substantially greater uncertainty of being actually realized. These estimates have not been fully risked by management. Actual quantities that may be ultimately recovered will likely differ substantially from these estimates. Factors affecting ultimate recovery include the scope of the Company’s actual drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, actual drilling results and recoveries of oil and natural gas in place, and other factors. These estimates may change significantly as the development of properties provides additional data.