UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported): February 26, 2015

Commission file number 001-36725

 

 

ATLAS ENERGY GROUP, LLC

(Exact name of registrant as specified in its charter)

 

 

 

Delaware		45-3741247
(State of incorporation or organization)		(I.R.S. Employer Identification No.)

Park Place Corporate Center One

1000 Commerce Drive, Suite 400

Pittsburgh, PA 15275

(Address of principal executive offices) (Zip code)

Registrant’s telephone number, including area code: (412) 489-0006

(Former name or former address, if changed since last report)

 

 

Check the appropriate box if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (127 CFR 240.14a-12)

 

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (27 CFR 240.14d-2(b))

 

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (27 CFR 240.13e-4(c))

 

 

 

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Item 1.01.

Entry Into a Material Definitive Agreement.

Separation-Related Agreements

On February 26, 2015, Atlas Energy Group, LLC (NYSE: ATLS) (the “Company”) entered into a separation and distribution agreement with Atlas Energy, L.P. (“Old Atlas”) and the general partner of Old Atlas, pursuant to which Old Atlas agreed to transfer its assets and liabilities other than those related to its midstream business to the Company (the “Separation”) and distribute to the Old Atlas unitholders 100% of the common units representing limited liability company interests in the Company (the “Distribution”). The Distribution was made after the close of business on February 27, 2015 to Old Atlas unitholders of record as of the close of business on February 25, 2017. As a result of the Distribution, the Company is now an independent public company and its common units are listed under the symbol “ATLS” on the New York Stock Exchange.

In connection with the Separation and Distribution, on February 26, 2015, the Company entered into an employee matters agreement with Old Atlas and the general partner of Old Atlas, which, together with the separation and distribution agreement, provide a framework for the Company’s relationship with Old Atlas after the Separation and Distribution. Old Atlas is now a subsidiary of Targa Resources Corp. as a result of the consummation of the merger of Old Atlas with a subsidiary of Targa Resources Corp. (“TRC”) pursuant to that certain Agreement and Plan of Merger, by and among TRC, Trident GP Merger Sub LLC, Old Atlas and the general partner of Old Atlas.

A summary of the separation and distribution agreement and the employee matters agreement can be found in the Company’s information statement, dated February 9, 2015 (the “Information Statement”), which is included as Exhibit 99.1 to the Company’s Form 8-K filed with the U.S. Securities and Exchange Commission (the “SEC”) on February 9, 2015, under the section entitled “Certain Relationships and Related Person Transactions.” These summaries are incorporated by reference into this Item 1.01 as if restated in full. The description of those agreements set forth under this Item 1.01 is qualified in its entirety by reference to the complete terms and conditions of those agreements, which are attached hereto as Exhibits 2.1 and 2.2.

Financing Transactions

In connection with the Distribution, the Company entered into the financing descriptions described below and used the proceeds to fund a portion of the $150.0 million cash transfer made by the Company to Old Atlas pursuant to the Separation and Distribution Agreement, which cash transfer was a condition to the Distribution.

 

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Item 2.03

Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant.

The information set forth under Item 8.01 of this Current Report on Form 8-K under the heading “Credit Agreement” is incorporated herein by reference.

 

Item 3.02

Unregistered Sale of Equity Securities.

The Information set forth under Item 8.01 of this Current Report on Form 8-K under the heading “Private Placement” is incorporated herein by reference.

 

Item 5.02

Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

New Equity Plan

On February 23, 2015, the Board of the Company and, on February 26, 2015, Old Atlas, as the sole member of the Company, approved the Atlas Energy Group, LLC 2015 Long-Term Incentive Plan (the “New Equity Plan”), effective as of immediately prior to the Distribution. Awards of options to purchase units, restricted units and phantom units may be granted to officers, employees and directors of the Company under the New Equity Plan, and such awards may be subject to vesting terms and conditions in the discretion of the administrator of the New Equity Plan. Up to 5,250,000 common units of the Company, subject to adjustment as provided for under the New Equity Plan, may be issued pursuant to awards granted under the New Equity Plan. The foregoing description does not purport to be complete and is qualified in its entirety by reference to the New Equity Plan, which is attached as Exhibit 10.2 to this report and is incorporated herein by reference.

New Bonus Plan

On February 23, 2015, the Board of the Company and, on February 26, 2015, Old Atlas, as the sole member of the Company, approved the Atlas Energy Group, LLC Annual Incentive Plan for Senior Executives (the “New Bonus Plan”), effective as of immediately prior to the Distribution. The New Bonus Plan provides a means for awarding annual bonuses to the Company’s senior executive employees and senior executive employees of the Company’s subsidiaries based on the achievement of performance goals over a designated performance period. The New Bonus Plan will be administered and interpreted by the Compensation Committee of the Board. The foregoing description does not purport to be complete and is qualified in its entirety by reference to the New Bonus Plan, which is attached as Exhibit 10.3 to this report and is incorporated herein by reference.

 

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Item 5.03

Amendments to Articles of Incorporation or Bylaws; Change in Fiscal Year.

In connection with the Distribution, on February 27, 2015, the limited liability company agreement of the Company was amended and restated in the form included as Exhibit 3.1 to this report, which is incorporated herein by reference (the “Amended and Restated LLCA”). A description of the material provisions of the Amended and Restated LLCA is included under the heading “Our Limited Liability Company Agreement” in the Company’s Information Statement, and such description is incorporated herein by reference. The foregoing description does not purport to be complete and is qualified in its entirety by reference to the actual text of the Amended and Restated LLCA, a copy of which is attached as Exhibit 3.1 to this report and is incorporated herein by reference.

In connection with the issuance of the Series A preferred units, the Company adopted Amendment No. 1 to the Amended and Restated LLCA (“Amendment No. 1”). The disclosure set forth above under Item 8.01 to this Current Report on Form 8-K with respect to the Private Placement is incorporated by reference herein. The foregoing description does not purport to be complete and is qualified in its entirety by reference to the actual text of Amendment No. 1, a copy of which is attached as Exhibit 3.2 to this report and is incorporated herein by reference.

 

Item 5.05

Amendments to the Registrants Code of Ethics, or Waiver of a Provision of the Code of Ethics.

In connection with the Distribution, the Board adopted a Code of Business Conduct and Ethics of the Company effective as of immediately prior to the effective time of the Distribution. A copy of the Company’s Code of Business Conduct is available under the Governance section of the Company’s website at www.atlasenergy.com.

 

Item 7.01

Regulation FD Disclosure.

The Company has updated certain information related to its estimated annual cash distributions that was included in the “Cash Distribution Policy” section of the Company’s information statement, dated February 9, 2015, which is included as Exhibit 99.1 to the Company’s Form 8-K filed with the SEC on February 9, 2015, as follows.

 

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The Company’s Initial Quarterly Distribution Rate

The Company believes, based on the assumptions and considerations discussed below, that upon completion of the distribution of the Company’s common units in the Distribution, the Company’s initial quarterly distribution will, subject to proration as described below, be equal to $0.175 per common unit, or $0.70 per common unit on an annualized basis. This equates to an aggregate cash distribution of approximately $4.6 million per quarter, or approximately $18.2 million per year. The Company’s ability to make cash distributions at the initial distribution rate will be subject to the factors described in the section of the Company’s Information Statement entitled “Cash Distribution Policy—General— Restrictions and Limitations on Our Cash Distribution Policy” beginning on page 77 of that document. There can be no assurance that any distributions will be declared or paid by the Company, and there is no guarantee of distributions at a particular level or of any distributions being made. The Company did not use quarterly estimates in concluding that there would be sufficient distributable cash flow to pay the initial quarterly distributions on the Company’s common units for the year ending December 31, 2015. For more information, see the section of the Company’s Information Statement entitled “Cash Distribution Policy—General—Restrictions and Limitations on Our Cash Distribution Policy” beginning on page 77 of that document.

 

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The following table sets forth the estimated aggregate distribution amounts payable on the Company’s common units during the year following the completion of the distribution of the Company’s common units at its initial distribution rate of $0.175 per common unit (or $0.70 per common unit on an annualized basis).

 

						Initial Quarterly Distribution
		Number of Units				One Quarter				Four Quarters
Common units			26,000,000			$	4,550,000			$	18,200,000

The Company’s cash distributions will not be cumulative. Consequently, if distributions on the Company’s common units are not paid with respect to any fiscal quarter, including those at the anticipated initial quarterly distribution rate, common unitholders will not be entitled to receive that quarter’s payments in the future.

Overview of Presentation

In the following discussion, we present the basis for our belief that we will be able to pay our initial quarterly distribution of $0.175 per common unit for each quarter during the year ending December 31, 2015. In particular, we present our “Estimated Initial Cash Available for Distribution” in which we present our estimated Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay distributions at the initial quarterly distribution rate on all the outstanding common units for each quarter for the year ending December 31, 2015. This discussion should be read together with the section of the Company’s Information Statement titled “Unaudited Pro Forma Cash Available for Distribution,” beginning on page 90 of that document, in which we present the amount of pro forma available cash we would have had available for distribution to our unitholders in the twelve months ended September 30, 2014 and December 31, 2013, based on our pro forma financial statements included elsewhere in this information statement. Our calculation of pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed in an earlier period.

Estimated Initial Cash Available for Distribution

We forecast that our estimated initial cash available for distribution for the year ending December 31, 2015 will be approximately $24.2 million. This amount would exceed the amount of cash available for distribution we must generate to support the payment of the initial quarterly distributions for four quarters on our common units outstanding immediately after the distribution date by $6.0 million for the year ending December 31, 2015. The number of outstanding units on which we have based our estimate does not include any common units that may be issued under the long-term incentive plan that we will adopt prior to the closing of the distribution.

 

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New Atlas

Estimated Cash Available for Distribution⁽¹⁾

 

		Year Ending December 31, 2015
Atlas Resource Partners, L.P.
Revenues:
Gas and oil production		$	503,100
Well construction and completion			155,500
Administration and oversight			13,000
Well services			27,200
Gathering and processing			7,200
Other			100
Total revenues			706,100
Costs and Expenses:
Gas and oil production			198,200
Well construction and completion			135,200
Well services			10,350
Gathering and processing			9,000
General and administrative expense			49,000
Depreciation, depletion and amortization			230,700
Total costs and expenses			632,450
Operating income			73,650
Interest expense			(102,325	)
Net loss			(28,675	)
Preferred limited partner dividends			(15,600	)
Net loss attributable to common limited partners and the general partner		$	(44,275	)
Plus:
Preferred limited partner dividends			15,600
Interest expense			102,325
Depreciation, depletion and amortization			230,700
EBITDA			304,350
Plus: Non-cash stock compensation expense			18,000
Adjusted EBITDA			322,350
Less: Interest expense			(102,325	)
Less: Preferred limited partner dividends			(15,600	)
Plus: Amortization of deferred finance costs			13,850
Less: Expansion capital expenditures			110,100
Plus: Financing for expansion capital expenditures			(110,100	)
Less: Maintenance capital expenditures			(61,700	)
Distributable cash flow attributable to common limited partners and the general partner		$	156,575
Cash Distributions(2):
Common limited partner units owned by 3rd parties		$	86,110
Common limited partner units owned by New Atlas			27,240
Total cash distributions to common limited partner units			113,350
Incentive distribution rights and general partner 2% interest			2,460

 

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		Year Ending December 31, 2015
Total cash distributions		$	115,810
Per limited partner unit		$	1.30
New Atlas cash distributions and dividends
Common limited partner units owned by New Atlas		$	27,240
Incentive distribution rights and general partner 2% interest			2,460
Preferred limited partner dividends			7,600
Total cash distributions/dividends to New Atlas		$	37,300
Excess of distributable cash flow after cash distributions		$	40,765
New Atlas
Revenues:
Atlas Resource Partners, L.P. revenue		$	706,100
Development Subsidiary revenue			56,600
Direct gas and oil production			12,800
Other			1,725
Total revenues			777,225
Costs and Expenses:
Atlas Resource Partners, L.P. costs and expenses			632,450
Development Subsidiary costs and expenses			26,300
Direct gas and oil production			6,200
General and administrative expense			8,050
Depreciation, depletion and amortization			5,500
Total costs and expenses			678,500
Operating income			98,725
Atlas Resource Partners, L.P. interest expense			(102,225	)
Interest expense			(12,700	)
Net loss		$	(16,200	)
Preferred limited partner dividends			(3,350	)
Net loss attributable to common limited partners and the general partner		$	(19,550	)
Plus:
Preferred limited partner dividends			3,350
Atlas Resource Partners, L.P. interest expense			102,225
Interest expense			12,700
Depreciation, depletion and amortization			5,500
EBITDA			104,225
Less: Atlas Resource Partners, L.P. operating income			(73,650	)
Plus: Atlas Resource Partners, L.P. cash distributions			37,300
Less: Development Subsidiary operating income			(30,300	)
Plus: Development Subsidiary cash distributions and fees earned			2,900
Adjusted EBITDA			40,475
Less: Preferred limited liability company dividends			(3,350	)

 

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		Year Ending December 31, 2015
Less: Interest expense			(12,700	)
Plus: Amortization of deferred finance costs			1,400
Less: Maintenance capital expenditures			(1,600	)
Distributable cash flow		$	24,225
Cash distributions:
Initial distribution per common unit		$	0.70
Common units outstanding			26,000
Aggregate initial distributions to common unitholders		$	18,200
Excess of distributable cash flow after cash distributions		$	6,025

Significant Forecast Assumptions

The forecast has been prepared by and is the responsibility of the Company’s management. The forecast reflects management’s judgment as of the date of this Current Report on Form 8-K of conditions we expect to exist and the course of action we expect to take during the year ending December 31, 2015. While the assumptions discussed below are not all-inclusive, they include those that we believe are material to our forecasted results of operations, and any assumptions not discussed below were not deemed to be material. We believe we have a reasonable, objective basis for these assumptions. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and our actual results and those differences could be material. If the forecasted results are not achieved, we may not be able to make cash distributions on our common units at the quarterly distribution rate.

Atlas Resource Partners, L.P. Significant Forecast Assumptions

Our cash flow is currently generated principally from cash distributions we receive from ARP. For the year ending December 31, 2015, we have forecasted that ARP will generate operating income of $73.7 million, or approximately 75% of our $98.7 million of operating income for the period. In addition, we have forecasted that ARP will pay us $37.3 million of cash distributions for the year ending December 31, 2015, or approximately 92% of our $40.5 million of Adjusted EBITDA for the period. As such, we have reflected in the table below the significant forecast assumptions for ARP’s operations, revenues and expenses for the year ending December 31, 2015:

 

						Historical
		Year Ending December 31, 2015				Twelve Months Ended September 30, 2014				Year Ended December 31, 2013
Revenues:
Gas and oil production key assumptions:
Wells initiated:
Gross			75				126				103
Net(1)			36				69				66

 

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Wells connected:
Gross			102				124				117
Net(1)			46				74				80
Net production volume per day:
Natural gas (mcfd)			220,910				226,948				158,886
Crude oil (bpd)			7,099				2,421				1,329
NGL (bpd)			4,333				3,683				3,473
Total (mcfed)			289,501				263,577				187,701
Average sales prices:
Natural Gas (per Mcf):
Total realized price, after hedges		$	3.58			$	3.75			$	3.47
Total realized price, before hedges		$	2.65			$	3.84			$	3.25
Hedge percentage (on production volume)			72	%			77	%			79	%
Basis and btu differentials included in pricing		$	(0.34	)		$	(0.41	)		$	(0.37	)
Crude oil (per Bbl):
Total realized price, after hedges		$	73.76			$	89.83			$	91.01
Total realized price, before hedges		$	48.34			$	93.55			$	95.88
Hedge percentage (on production volume)			68	%			91	%			100	%
Basis differentials included in pricing		$	(5.03	)		$	(5.11	)		$	(2.04	)
NGL (per Bbl):
Total realized price, after hedges		$	17.26			$	30.59			$	28.71
Total realized price, before hedges		$	13.14			$	32.13			$	29.43
Hedge percentage (on production volume)			25	%			38	%			18	%
Partnership management key assumptions:
Partnership management funds raised (in millions)		$	150.0			$	155.6			$	150.0
Partnership management wells initiated			39				101				75
Well construction and completion cost mark-up			15	%			15	%			15	%

 

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				Historical
		Year Ending December 31, 2015		Twelve Months Ended September 30, 2014		Year Ended December 31, 2013
Administration and oversight—fee per well initiated		$100,000 to $500,000		$100,000 to $400,000		$100,000 to $400,000
Administration and oversight fee per well per month		$75		$75		$75
Gross well services per well fee		$100 to $2,000		$100 to $2,000		$100 to $2,000
Expenses:
Gas and oil production key assumptions:
Production costs (per Mcfe):
Lease operating expenses		$1.43		$1.21		$1.09
Production taxes		0.22		0.25		0.18
Transportation and compression		0.25		0.26		0.24
Total		$1.90		$1.73		$1.50

 

(1)	Includes (i) ARP’s percentage interest in the wells in which it has a direct ownership interest and (ii) its percentage interest in the wells based on its percentage ownership in the drilling partnerships.

Gas and oil production revenue. ARP’s forecasted natural gas and oil production volumes, net to its equity interest in the production of its investment partnerships and including its direct interests in producing wells, for the year ending December 31, 2015 assumes that currently producing wells will produce at the rates forecasted in its December 31, 2013 reserve report, and have been adjusted for current well performance and acquisition activity. The forecasted production volumes also include new production from an estimated 102 additional gross wells (46 net wells) ARP projects to connect during the year ending December 31, 2015, consisting of (i) 65 gross wells (22 net wells) which ARP intends to drill and connect on behalf of its investment partnerships and (ii) 37 gross direct interest wells (24 net wells), both of which ARP assumes will produce at rates consistent with wells of similar characteristics contained in its December 31, 2013 reserve report, adjusted for current well performance. ARP has assumed no significant interruptions of production volumes due to mechanical issues such as compressor breakdowns and sales line maintenance. Further, ARP has assumed no significant logistical issues related to new well hookups, such as delays in pipeline construction, permitting and right-of-ways which it primarily depends on gathering system service providers to complete.

Of the 75 additional wells that ARP projects to be initiated during the year ending December 31, 2015, 45 of the wells were recognized as proved, undeveloped locations at December 31, 2013, with total estimated reserves of 35 Bcfe. At the present time, ARP has no new information to adjust its reserve estimates for these wells and, as such, expect to convert 35 Bcfe of estimated reserves from proved undeveloped reserves to proved developed reserves. These wells are estimated to be connected at various dates through 2015, subject to change due to factors including operational issues and weather, and ARP estimates that these 45 wells will produce an aggregate gross production of 3.2 Bcfe (1.4 Bcfe net production) during the year ending December 31, 2015, subject to business plan changes, market factors and operational factors. The remaining 30 wells that ARP projects to initiate during the year ending December 31, 2015 are primarily related to projected drilling activities in Eagle Ford Shale, an acquisition which ARP completed in November 2014, and the Marcellus Shale, of which certain proved undeveloped locations were created through developmental drilling during the nine months ended September 30, 2014.

 

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The 75.9 MMcfed increase in overall production from 187.7 MMcfed for the year ended December 31, 2013 to 263.6 MMcfed for the twelve months ended September 30, 2014 was principally due to partial year contributions from the EP Energy assets, which were acquired in July 2013, the GeoMet assets, which were acquired in April 2014, and the Rangely assets, which were acquired in June 2014, as well as production increases from new drilling, partially offset from natural production declines in other wells. The 25.9 MMcfed increase in overall production from 263.6 MMcfed for the twelve months ended September 30, 2014 to 289.5 MMcfed for the year ending December 31, 2015 is principally due to production from the Eagle Ford Shale assets, which ARP acquired in November 2014, and a full year of production from the acquisitions of the GeoMet and Rangely assets as well as production increases from new drilling, partially offset from natural production declines in other wells.

ARP’s forecasted commodity prices for the year ending December 31, 2015 were based upon average forward prices as of January 5, 2015, with natural gas and crude oil based upon prices quoted on the New York Mercantile Exchange, or NYMEX, and NGLs based upon Mont Belvieu, as quoted by the Oil Price Information Service, or OPIS, for a composite barrel, each on a first-day-of-the-month price. The actual prices that ARP realize for these commodities reflect various adjustments to the applicable NYMEX- and OPIS-based prices due to transportation, quality and regional price differentials, as well as the effect of ARP’s commodity price hedges. ARP’s forecasted estimated commodity prices are principally based on NYMEX and OPIS forward prices for the applicable commodities, but adjusted to take into account third-party market analysis and management’s own judgment.

ARP gas and oil production revenue for the year ending December 31, 2015 includes a $5.1 million reduction for the estimated impact of subordination of its production revenue to investor partners within its investment partnerships, compared with $12.0 million for the twelve months ended September 30, 2014 and $15.2 million for the year ended December 31, 2013. ARP’s decrease in the subordination of production revenue to investor partners within its investment partnerships between the year ending December 31, 2015 and the twelve months ended September 30, 2014 and the year ended December 31, 2013 is due primarily to improved performance of certain programs and other programs concluding their subordination period.

Gas and oil production costs and expenses. ARP’s estimated total natural gas and oil production costs and expenses consist of its equity interest in the production costs and expenses of its investment partnerships and as well as the production costs and expenses associated with its direct interests in producing wells. ARP’s lease operating expenses are comprised primarily of direct labor costs, repair and maintenance costs, and production materials. ARP total estimated production costs per mcfe for the year ending December 31, 2015 are $1.90 per mcfe, compared with $1.72 per mcfe for the twelve months ended September 30, 2014 and $1.50 per mcfe for the year ended December 31, 2013. The increase between the periods is primarily due to an increase in crude oil production volumes as a percentage of total production volumes. ARP’s production costs and expenses have a significant fixed cost component, such as labor and repair and maintenance costs, that cause increases in crude oil and NGL volumes, which generate fewer hydrocarbon production units than natural gas, to result in an increase in production costs per mcfe as oil and NGL volumes increase as a percentage of total volumes.

 

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ARP gas and oil production costs and expenses for the year ending December 31, 2015 includes a $2.4 million reduction for the estimated impact of its proportionate share of lease operating expenses associated with the subordination of its production revenue to investor partners within its investment partnerships, compared with $4.2 million for the twelve months ended September 30, 2014 and $5.6 million for the year ended December 31, 2013. ARP’s decrease in the proportionate share of lease operating expenses associated with the subordination of its production revenue between the year ending December 31, 2015 and the twelve months ended September 30, 2014 and the year ended December 31, 2013 is due primarily to improved performance of certain programs and other programs concluding their subordination period.

Partnership management revenue and costs and expenses. ARP has estimated that it will raise approximately $150.0 million through its investment partnerships during the year ending December 31, 2015 and that its equity interest in such partnerships will be approximately 28.5%. ARP also estimated that it raised approximately $170.0 million through its investment partnerships during the year ending December 31, 2014, and that its equity interest in such partnerships will be approximately 32.6%. 

For the administration and oversight monthly fee for each investment partnership well of $75, ARP has estimated that it will charge the fee on approximately 4,625 investment partnership wells for the year ending December 31, 2015. For the well services monthly fee for each operated investment partnership well of $100 to $2,000, ARP has estimated that it will charge the fee on approximately 4,925 investment partnership wells for the year ending December 31, 2015. Well services revenue also includes fees for services ARP personnel perform on investment partnership wells. ARP estimates that its well services profit margin will be approximately 62% for the year ending December 31, 2015, compared with 57% for the twelve months ended September 30, 2014 and 51% for the year ended December 31, 2013. The increase in profit margin between these periods is primarily due to an increase in service fees charged to investment partnership wells for ARP’s salt water gathering and disposal systems in the Mississippi Lime and Marble Falls areas, which generally have lower ongoing operating and maintenance costs as a percentage of service fees charged than other well service fees.

General and administrative expense. ARP has forecasted general and administrative expense of $49.0 million for the year ending December 31, 2015, as compared with $65.2 million for the twelve months ended September 30, 2014 and $78.1 million for the year ended December 31, 2013. The decrease in general and administrative expense between the forecasted year ending December 31, 2015 and the twelve month periods ended September 30, 2014 and December 31, 2013 is due primarily to costs incurred during the historical periods related to consummated acquisitions, including the EP Energy assets in July 2013, the GeoMet assets in April 2014, and the Rangely assets in June 2014. ARP did not include any consummated acquisitions in its forecast for the year ending December 31, 2015.

Interest expense. ARP has estimated that its interest expense for the year ending December 31, 2015 will be approximately $102.3 million, compared with $55.2 million for the twelve months ended September 30, 2014 and $34.3 million for the year ended December 31, 2013. The

 

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increase in interest expense between these periods is primarily due to a full year of interest expense on borrowings under ARP’s senior secured credit facility, new second lien facility and senior notes that were utilized to fund its historical capital expenditures and acquisitions, including the EP Energy assets in July 2013, the GeoMet assets in April 2014, and the Rangely assets in June 2013, as well as the Eagle Ford Shale assets, which ARP acquired in November 2014. ARP’s estimate of interest expense for the year ending December 31, 2015 is based upon the following significant assumptions:

 

•

$700.0 million of senior notes outstanding with a weighted average interest rate of 8.4%;

 

•

approximately $522.0 million of weighted average borrowings outstanding on ARP’s senior secured credit facility, including borrowings to fund forecasted capital expenditures for the year ending December 31, 2015, at a weighted average interest rate of 2.6%, which is based upon an estimated London Interbank Offer Rate (also referred to as “LIBOR”) of 0.6%. ARP’s weighted LIBOR for the historical nine months ended September 30, 2014 was 0.2%;

 

•

$250.0 million of second lien term loan with an interest rate of 10.0%

 

•

approximately $10.0 million of capitalized interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use; and

 

•

approximately $1.2 million of commitment fees for the unused portion of ARP’s senior secured credit facility.

Preferred dividends. ARP has estimated that it will pay $15.6 million of preferred limited partner dividends for the year ending December 31, 2015, based upon an average of 3,665,000 units outstanding of its 8.625% Class D cumulative redeemable perpetual preferred units, 3,749,986 units outstanding of its Class C convertible preferred units at its minimum quarterly distribution rate of $0.51 per unit, and 39,654 units outstanding of its Class B convertible preferred units at its minimum quarterly distribution rate of $0.40 per unit. The Class B convertible preferred units are mandatorily convertible into an equivalent number common units on July 25, 2015.

Maintenance capital expenditures. Oil and gas assets naturally decline in future periods and, as such, ARP recognizes the estimated capitalized cost of stemming such decline in production margin for the purpose of stabilizing its cash available for distribution and cash distributions, which it refers to as maintenance capital expenditures. ARP calculates the estimate of maintenance capital expenditures by first multiplying its forecasted future full year production margin by its expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. ARP does not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a hypothetical subset of wells it expects to drill in future periods, including Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls wells, on undeveloped acreage already leased. Estimated capitalized cost of wells included within maintenance capital expenditures are

 

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also based upon relevant factors, including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs. ARP’s estimated maintenance capital expenditures for the year ending December 31, 2015 of $61.7 million, compared with $44.8 million and $28.2 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively, are the sum of the estimate calculated the year ending December 31, 2014 plus estimates for the decline in production margin from new wells connected during the year ending December 31, 2015.

Expansion capital expenditures. ARP considers expansion capital expenditures to be any capital expenditure costs expended that are not maintenance capital expenditures—generally, this will include expenditures to increase, rather than maintain, production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures. ARP has estimated that it will incur $110.1 million of expansion capital expenditures for the year ending December 31, 2015, compared with $153.2 million and $232.0 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively, primarily to drill direct interest and investment partnership wells. ARP expects its expansion capital expenditures to be funded through borrowings under its senior secured credit facility.

New Atlas Significant Forecast Assumptions

We have reflected in the table below our significant forecast assumptions, other than for ARP’s operations, revenues and expenses previously detailed, for the year ending December 31, 2015:

 

						Historical
		Year Ending December 31, 2015				Twelve Months Ended September 30, 2014				Year Ended December 31, 2013
Revenues:
New Atlas direct natural gas production key assumptions:
Net natural gas production volume per day (mcfd)(1)			9,484				11,652				12,130
Total realized price, after hedges		$	3.70			$	3.84			$	3.68
Total realized price, before hedges		$	2.83			$	3.94			$	3.41
Hedge percentage (on production volume)			66	%			66	%			81	%
Basis and btu differentials included in pricing		$	(0.15	)		$	(0.36	)		$	(0.16	)
Development Subsidiary gas and oil production key assumptions:
Net production volume per day:
Natural gas (mcfd)			1,347				511				21
Crude oil (bpd)			2,316				97				7
NGL (bpd)			220				66				3
Total (mcfed)			16,561				1,491				79

 

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Average sales prices:
Natural Gas realized price (per Mcf)		$	2.65			$	4.20			$	3.63
Crude oil realized price (per Bbl)		$	48.34			$	93.50			$	93.16
NGL realized price (per Bbl)		$	13.14			$	31.58			$	34.88
Expenses:
New Atlas direct natural gas production key assumptions:
Production costs (per Mcfe)		$	1.80			$	1.47			$	1.54
Development Subsidiary gas and oil production key assumptions:
Production costs (per Mcfe)		$	1.26			$	3.00			$	2.77

 

(1)

The historical data for the twelve month periods ended September 30, 2014 and December 31, 2013 reflect production volume from July 31, 2013, the date of acquisition, through the end of the respective period, and are reflected on a per day basis based upon the number of days in the period from the acquisition date.

New Atlas direct natural gas production revenue. Our forecasted direct net natural gas production volumes for the year ending December 31, 2015 assumes that currently producing wells will produce at the rates forecasted in Atlas Energy’s December 31, 2013 reserve report, and have been adjusted for current well performance. The forecasted production volume does not include production from any new wells drilled and connected during the year ending December 31, 2015. We have assumed no significant interruptions of production volumes due to mechanical issues such as compressor breakdowns and sales line maintenance.

Our forecasted natural gas price for the year ending December 31, 2015 was based upon the average forward prices as of January 5, 2015, which was based upon prices quoted on NYMEX on a first-day-of-the-month price. The actual prices that we realize for natural gas reflect various adjustments to the NYMEX-based price due to regional price differentials, as well as the effect of our commodity price hedges. Our forecasted estimated commodity prices are principally based on NYMEX forward prices, but adjusted to take into account third-party market analysis and management’s own New Atlas direct natural gas production costs and expenses. Our production costs and expenses primarily consist of direct labor costs, repair and maintenance costs, production materials, transportation costs and severance taxes.

General and administrative expense. We have forecasted general and administrative expense of $8.1 million for the year ending December 31, 2015, as compared with $7.4 million and $7.6 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively.

Interest expense. In accordance with the Atlas merger agreement and the separation and distribution agreement, prior to the distribution, New Atlas will enter into one or more financing arrangements pursuant to which it will transfer $150.0 million to Atlas Energy as a cash distribution. Atlas Energy will use this cash distribution as well as a payment due from Targa Resources under the Atlas merger agreement to repay Atlas Energy’s outstanding indebtedness at or prior to

 

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the effective time of the distribution. For more information, see the section entitled “Certain Relationships and Related Party Transactions—Separation and Distribution Agreement—Cash Transfers.” New Atlas currently expects to enter into a term loan similar to Atlas Energy’s currently outstanding term loan to effect these financing arrangements. We have therefore assumed that we will issue a term loan of approximately $120.0 million, with net proceeds received of approximately $115.0 million, at an interest rate of 8.5% for the year ending December 31, 2015, and $40.0 million of preferred limited liability company units with a par value of $25 per unit and a dividend rate of 10%. As such, we have estimated interest expense for the year ending December 31, 2015 of $12.7 million, compared with $11.3 million and $5.4 million of interest expense for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively, which reflect the allocation of interest expense associated with Atlas Energy’s term loan for those historical periods prior to the separation and distribution. The increase in interest expense between the twelve months ended September 30, 2014 and the year ended December 31, 2013 is primarily due to a full year of interest expense on ATLS term loan, which was issued in July 2013.

In preparing the estimates, we and ARP have assumed that there will be no material change in the following matters, and thus they will have no impact on our cash available for distribution:

 

•

There will not be any material expenditures related to new federal, state or local regulations in the areas where we and ARP operate;

 

•

There will not be any material change in the natural gas and oil industry or in market, regulatory and general economic conditions that would affect our cash flow;

 

•

We and ARP will not undertake any extraordinary transactions that would materially affect our or ARP’s cash flow; and

 

•

There will be no material nonperformance or credit-related defaults by suppliers, customers or vendors.

While we and ARP believe that the assumptions we used in preparing the estimates set forth above are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties, including those described in “Risk Factors” elsewhere in this information statement that could cause actual results to differ materially from those we anticipate. If our and ARP’s assumptions are not realized, the actual available cash that we and ARP generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the initial quarterly distribution or any amount on all of our outstanding units with respect to the four calendar quarters for the year ending December 31, 2015 or thereafter, in which event the market price of the common units may decline materially.

Sensitivity Analysis

Our ability to generate sufficient cash from our operations and cash distributions from ARP to pay cash distributions to our unitholders at the initial quarterly cash distribution rate for the year ending December 31, 2015 is a function of the following primary variables:

 

•

The amount of hydrocarbons we and ARP produce;

 

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•

The price at which we and ARP sell our hydrocarbons; and

 

•

The amount of funds raised from ARP’s investment partnerships.

In the paragraphs below, we discuss the impact that changes in these variables, holding all other variables constant, would have on our ability to generate sufficient cash from our operations, including cash distributions received from ARP, to pay the initial quarterly cash distributions on our outstanding units.

Production volume changes. For purposes of our estimates set forth above, ARP has assumed that its net production is approximately 105.7 Bcfe during the year ending December 31, 2015. If ARP’s actual net production realized during the year ending December 31, 2015 is 10% more (or 10% less) than such estimate (that is, if actual net realized production is 95.1 Bcfe or 116.2 Bcfe, representing a pro rata change in natural gas, oil and NGLs), we estimate that ARP’s estimated cash available to pay cash distributions would change by approximately $20.9 million. Also, we have assumed that our net production from direct gas and oil production will total 3.5 Bcfe during the year ending December 31, 2015. If our actual net production realized during the year ending December 31, 2015 is 10% (or 10% less) than such estimate (that is, if actual net realized production is 3.1 Bcfe or 3.8 Bcfe), we estimate that our estimated cash available to pay cash distributions would change by approximately $0.5 million.

Commodity price changes. For purposes of our estimates set forth above, ARP has assumed that its weighted average net realized commodity price before hedges for its net production volumes is $2.65 per Mcf for natural gas, $48.34 per barrel for crude oil and $13.14 per barrel for NGLs. If the average realized commodity price for ARP’s net production volumes that are unhedged were to change by 10%, we estimate that ARP’s estimated cash available to pay cash distributions would change by approximately $10.7 million, assuming no changes in any other variables and inclusive of ARP’s commodity derivative contracts. Also, we have assumed that our weighted average net realized natural gas price for our net production volume is $2.83 per Mcf for natural gas. If the average realized natural gas price for our net production volume that is unhedged were to change by 10%, we estimate that our estimated cash available to pay distributions would change by approximately $0.3 million, assuming no changes in any other variables and inclusive of our commodity derivative contracts.

Funds raised changes. For purposes of our estimates set forth above, ARP has assumed funds raised from its investment partnerships will total $150.0 million during the year ending December 31, 2015. If actual funds raised during such period are 10% more or less than our estimate, we estimate that our estimated cash available for distribution would change by approximately $3.0 million.

 

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The information provided under this Item 7.01 is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that Section.

 

Item 8.01

Other Events.

In connection with the Distribution, the Board adopted revised Governance Guidelines, including director independence standards, effective as of immediately prior to the effective time of the Distribution. A copy of the Company’s Governance Guidelines is available under the Governance section of the Company’s website at www.atlasenergy.com.

Term Loan Credit Facility

On February 27, 2015, the Company, and New Atlas Holdings, LLC, a Delaware limited liability company and a direct wholly owned subsidiary of the Company (the “Borrower”), entered into a Credit Agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders from time to time party thereto (the “Credit Agreement”).

The Credit Agreement provides for a Secured Senior Interim Term Loan Facility in an aggregate principal amount of $30 million (the “Interim Term Loan Facility”) and a Secured Senior Term A Loan Facility in an aggregate principal amount of approximately $97.8 million (the “Term A Loan Facility” and together with the Interim Term Loan Facility, the “Term Loan Facilities”). The Interim Term Loan Facility matures on August 27, 2015 and the Term A Loan Facility matures on February 26, 2016.

The Borrower’s obligations under the Term Loan Facilities are secured on a first priority basis by security interests in substantially all of the assets of the Borrower and each of the Company, Atlas Lightfoot, LLC, ATLS Production Company, LLC and any other material subsidiary of the Company that later guarantees indebtedness under the Term Loan Facilities (the “Guarantors” and together with the Borrower, the “Loan Parties”), including all equity interests directly held by the Borrower or any Guarantor and all tangible and intangible property of the Borrowers and the Guarantors.

Borrowings under the Term Loan Facilities bear interest, at the Borrower’s option, at either (i) LIBOR plus 7.5% (“Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 6.5% (an “ABR Loan”). Interest is generally payable at interest payment periods selected by the Borrower for Eurodollar Loans and quarterly for ABR Loans.

The Borrower has the right at any time to prepay any borrowings outstanding under the Term Loan Facilities, without premium or penalty, so long as the Interim Term Loan Facility is repaid prior to the Term A Loan Facility. Subject to certain exceptions, the Borrower may also be required to prepay all or a portion of the Term Loan Facilities in certain instances, including the following:

 

•

if, at any time, the Recognized Value Ratio is less than 2.00 to 1.00, the Borrower must prepay the Term Loan Facilities and any revolving loans outstanding in an aggregate principal amount necessary to achieve a Recognized Value Ratio of greater than 2.00 to 1.00; the Recognized Value Ratio is equal to the ratio of the Recognized Value (the sum of the discounted net present values of the Loan Parties’ oil and gas properties and the values of the common units, Class A Units and Class C Units of ARP, determined as set forth in the Credit Agreement) to Total Funded Debt (as defined in the Credit Agreement);

 

•

if the Company or any restricted subsidiary of the Company disposes of all or any portion of the Arkoma Assets (as defined in the Credit Agreement) to a person other than a Loan Party, the Borrower must prepay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds resulting from such disposition;

 

•

if the Company or any restricted subsidiary of the Company disposes of property or assets (including equity interests) to a person other than a Loan Party or receives insurance or condemnation proceeds following a casualty event, the Borrower must repay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and

 

•

if the Company or any restricted subsidiary of the Company issues or incurs any debt or issues any equity, the Borrower must repay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity.

        The Credit Agreement contains customary covenants that limit the Borrower’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. The Credit Agreement also requires that the Total Leverage Ratio (as defined in the Credit Agreement) be greater than (i) as of the last day of any fiscal quarter prior to the full repayment of the Interim Term Loan Facility, 3.75 to 1.00, and (ii) as of the last day of any quarter thereafter, 3.50 to 1.00.

This summary of the Credit Agreement does not purport to be complete and is subject to, and qualified in its entirety by, the full text of the Credit Agreement filed as Exhibit 10.1 to this report, which is incorporated herein by reference.

Private Placement

On February 26, 2015, the Company entered into the Series A preferred unit purchase agreement (the “Series A preferred purchase agreement”) with Leon G. Cooperman and certain members of the Company’s management and Board (the “purchasers”), pursuant to which, on February 27, 2015 the Company issued and sold an aggregate of 1.6 million of its newly issued Series A convertible preferred units representing limited liability company interests, with a liquidation preference of $25.00 per unit (the “Series A preferred units”), to the purchasers for a cash purchase price of $25.00 per unit in a privately negotiated transaction (the “Private Placement”). The Company sold the Series A preferred units in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

The Private Placement resulted in proceeds to the Company of $40.0 million. The Company used the proceeds to fund a portion of the $150.0 million cash transfer made by the Company to Old Atlas pursuant to the Separation and Distribution Agreement, which cash transfer was a condition to the Distribution.

The Series A preferred purchase agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities. The foregoing description does not purport to be complete and is qualified in its entirety by reference to the Series A preferred purchase agreement, a copy of which is included as Exhibit 10.4 to this Current Report on Form 8-K and is incorporated herein by reference.

Description of Series A Preferred Units

The Series A preferred units are a new class of voting equity security that ranks senior to all classes or series of equity securities of the Company with respect to distribution rights and rights upon liquidation. The liquidation preference for the Preferred Units is $25.00 per unit plus any accrued and unpaid dividends (the “liquidation preference”). Until all of the Series A preferred units have been redeemed or converted, the Company may not, without obtaining the approval of a majority of the holders of the Series A preferred units voting as a class, issue any capital stock, other than in-kind distributions of such units, that would be senior to or pari passu with the Series A preferred units.

The convertibility of the Series A preferred units into the Company’s common units is conditional on the approval by holders of the Company’s common units under the New York Stock Exchange rules (the “Unitholder Approval”). The Company has agreed to hold a special meeting of unitholders to obtain such approval within 180 days of the Distribution and to distribute a proxy statement in respect of such special meeting within 120 days of the Distribution.

Distributions

Holders of the Series A Preferred Units are entitled to monthly distributions:

 

•

of cash, at a rate equal to the greater of

 

•

10% of the liquidation preference per annum, increasing to 12% per annum, 14% per annum and 16% per annum on the first, second and third anniversaries of the Distribution, respectively;

 

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•

the monthly equivalent of any cash distribution declared by the Company to holders of the Company’s common units in respect of a period that includes such month, on an as-converted basis; and

 

•

of Series A preferred units (“PIK units”), at a rate equal to 2% of the liquidation preference per annum.

In the event that Unitholder Approval is not obtained within one year of the Distribution, the holders of the Series A preferred units will be entitled to additional cash distributions at a rate equal to 2% of the liquidation preference per annum until the Unitholder Approval is obtained.

If the Company fails to pay in full any cash distribution on the Series A preferred units when due because the Company has insufficient available cash (as defined in the Amended and Restated LLCA, as amended by Amendment No. 1) to make such distribution or if payment would result in a default under the Company’s Credit Agreement (an “Available Cash Shortfall”), then the holders of the Series A preferred units will receive, in lieu of such cash distribution, a distribution in kind of additional PIK units. If the Company fails to pay in full any cash distribution on the Series A preferred units when due for any other reason, then the holders of the Series A preferred units will be entitled to such cash distribution in subsequent months (with the amount of such cash distribution being treated as an accrued and unpaid distribution), and the holders of the Series A preferred units will have the right to request the Company to pay a distribution of PIK units in lieu of such cash distribution.

Unless all accumulated and unpaid distributions on the Series A preferred units have been paid for all preceding distribution periods, subject to certain exceptions, the Company (1) will, subject to certain exceptions, not declare or pay on any securities that rank junior or pari passu and (2) may not redeem, purchase or otherwise acquire any such junior or pari passu securities. In addition, the Company may not take any action described in the foregoing clauses (1) or (2) in any distribution period (with respect to the Company’s common units) in which the Company did not have available cash to pay a cash distribution in full on the Series A preferred units.

Conversion; Voting

All or a portion of the Series A preferred units will be convertible into the Company’s common units at the option of the holder at any time following the later of (1) the one year anniversary of the Distribution and (2) receipt of Unitholder Approval. No fractional common units will be issued upon conversion of the Series A preferred units.

The conversion price (the “Conversion Price”) shall be equal to the greater of:

 

•

$8.00 per common unit of the Company; and

 

•

the lower of: (i) 110% of the volume weighted average price for the Company’s common units on the NYSE over the 30 trading days following the Distribution Date; and (ii) $16.00 per common unit of the Company.

 

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The Conversion Price will be subject to customary anti-dilution adjustments, including adjustments for unit splits, business combinations, unit dividends and tender offers. In addition, the Conversion Price for the first month following the Distribution will be determined by reference to the volume weighted average price for the Company’s common units on the NYSE over the first day of regular-way trading following the distribution instead of the volume weighted average price over the first 30 trading days following the Distribution.

Until Unitholder Approval is obtained, the Series A preferred units will be non-voting, except as specified below. Following the receipt of Unitholder Approval, holders of Series A preferred units will be entitled to vote on any and all matters on which holders of the Company’s common units are entitled to vote on an “as if” converted basis. Regardless of whether Unitholder Approval has been obtained, a 66- ²⁄₃% vote of the outstanding Series A preferred units will be required for certain actions, including amendments to the terms of the Series A preferred units or amendments to the Company’s organizational documents, if such changes would adversely affect the holders of the Series A preferred units in any material respect.

Redemption

The Company may redeem all (but not less than all) of the Series A preferred units for cash on at least 30 but no more than 60 days’ prior written notice for an amount of cash equal to: (1) 110% of the liquidation preference, before the one year-anniversary of the Distribution; (2) 105% of the liquidation preference, between the one- and two-year anniversaries of the Distribution; and (3) 100% of the liquidation preference, after the two-year anniversary of the Distribution. If the Company provides a notice of redemption, then, prior to any such redemption, the Company must ensure that the holders of the Series A preferred units will have an opportunity and right to convert all or a portion of their Series A preferred units into the Company’s common units.

The foregoing description of the Series A preferred units does not purport to be complete and is qualified in its entirety by reference to Amendment No. 1, a copy of which is included as Exhibit 3.2 to this Current Report on Form 8-K and is incorporated herein by reference.

The Registration Rights Agreement

On February 27, 2015, the Company entered into a Registration Rights Agreement with the purchasers. Pursuant to the Registration Rights Agreement, the Company will file a resale registration statement with the SEC for the resale of the Series A preferred units (including any PIK units) and the common units issuable upon the conversion of the Series A preferred units (“registrable securities”) upon receipt of a request of from one or more purchasers to register at least $5 million of registrable securities. The Registration Rights Agreement also contains certain piggyback registration rights and provides a holder of $5 million or more of Registrable securities the right to elect to dispose of such common units through an underwritten public offering. The Registration Rights Agreement contains representations, warranties, covenants and indemnities that are customary for private placements.

The foregoing description does not purport to be complete and is qualified in its entirety by reference to the Registration Rights Agreement, a copy of which is included as Exhibit 4.1 to this Current Report on Form 8-K and is incorporated herein by reference.

 

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Cautionary Note Regarding Forward-Looking Statements

Certain statements contained herein are “forward-looking statements” that are subject to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those contained in the forward-looking statements. Readers are cautioned that any forward-looking information is not a guarantee of future performance. Risks and uncertainties related to the proposed transaction include, among others: potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the mergers or the distribution; competitive responses to the mergers and the distribution; unexpected costs, charges or expenses resulting from the mergers and the distribution; litigation relating to the mergers and the distribution; the outcome of potential litigation or governmental investigations; the Company’s ability to operate the assets it acquired in connection with the distribution, and the costs of such distribution; uncertainties regarding the expected financial results of the Company after the distribution, which is dependent on future events or developments; changes in commodity prices; changes in the costs and results of drilling operations; uncertainties about estimates of reserves and resource potential; inability to obtain capital needed for operations; the Company’s level of indebtedness; changes in government environmental policies and other environmental risks; any changes in general economic and/or industry specific conditions; and other risks, assumptions and uncertainties detailed from time to time in Old Atlas’s, Atlas Resource Partners, L.P.’s (“ARP”), Atlas Pipeline Partners, L.P.’s (“APL”) and the Company’s reports filed with the Securities and Exchange Commission, including risks, assumptions and uncertainties described in the Company’s registration statement on Form 10 and Old Atlas’s, ARP’s and APL’s quarterly reports on Form 10-Q, current reports on Form 8-K and annual reports on Form 10-K. Forward-looking statements speak only as of the date hereof, and we assume no obligation to update such statements, except as may be required by applicable law.

 

Item 9.01

Financial Statements and Exhibits.

(d) Exhibits

 

Exhibit No.		Exhibit Description
2.1		Separation and Distribution Agreement, dated February 26, 2015, by and among Atlas Energy, L.P., Atlas Energy GP, LLC and Atlas Energy Group, LLC.*
2.2		Employee Matters Agreement, dated February 26, 2015, by and among Atlas Energy, L.P., Atlas Energy GP, LLC and Atlas Energy Group, LLC.*
3.1		Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, dated as of February 27, 2105.
3.2		Amendment No. 1, dated February 27, 2015, to Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC.

 

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4.1		Registration Rights Agreement, dated February 27, 2015, by and among Atlas Energy Group, LLC and the purchasers signatory thereto.
10.1		Credit Agreement, dated as of February 27, 2015, among Atlas Energy Group, LLC, New Atlas Holdings, LLC, the lenders party thereto and Deutsche Bank AG New York Branch, as administrative agent.
10.2		Atlas Energy Group, LLC 2015 Long-Term Incentive Plan.
10.3		Atlas Energy Group, LLC Annual Incentive Plan for Senior Executives.
10.4		Series A Preferred Unit Purchase Agreement, dated February 26, 2015, by and among Atlas Energy Group, LLC and the purchasers signatory thereto.

* The schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the Securities and Exchange Commission upon request.

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

				ATLAS ENERGY GROUP, LLC
March 2, 2015				By:		/s/ Sean McGrath
						Sean McGrath
						Chief Financial Officer

 

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