Attached files

file filename
EX-32.2 - SECTION 906 CFO CERTIFICATION - Targa Energy LPd303489dex322.htm
EX-21.1 - SUBSIDIARIES OF ATLAS ENERGY LP - Targa Energy LPd303489dex211.htm
EX-99.1 - SUMMARY RESERVE REPORT - Targa Energy LPd303489dex991.htm
EX-10.7 - FORM OF STOCK OPTION GRANT UNDER 2010 LONG TERM-INCENTIVE PLAN - Targa Energy LPd303489dex107.htm
EX-10.6 - FORM OF PHANTOM UNIT GRANT UNDER 2010 LONG-TERM INCENTIVE PLAN - Targa Energy LPd303489dex106.htm
EX-32.1 - SECTION 906 CEO CERTIFICATION - Targa Energy LPd303489dex321.htm
EX-23.1 - CONSENT OF GRANT THORNTON LLP - Targa Energy LPd303489dex231.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - Targa Energy LPd303489dex311.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - Targa Energy LPd303489dex312.htm
EX-23.2 - CONSENT OF WRIGHT & COMPANY INC - Targa Energy LPd303489dex232.htm
EX-10.18 - EMPLOYMENT AGREEMENT FOR MATTHEW A. JONES DATED NOVEMBER 4, 2011 - Targa Energy LPd303489dex1018.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

(Mark One)

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number: 001-32953

 

 

ATLAS ENERGY, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware   43-2094238

(State or other jurisdiction or

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

Park Place Corporate Center One

1000 Commerce Drive, 4th Floor

Pittsburgh, PA

  15275
(Address of principal executive offices)   Zip code

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

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Name of each exchange on which registered

Common Units representing Limited Partnership Interests

  New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Title of class

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “small reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨      Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

The aggregate market value of the voting common stock held by non-affiliates of the registrant, based on the closing price of such stock on the last business day of the registrant’s most recently completed second quarter, June 30, 2011, was approximately $1.1 billion.

The number of outstanding shares of the registrant’s common stock on February 22, 2012 was 51,297,814 shares.

 

 

DOCUMENTS INCORPORATED BY REFERENCE: None

 

 

 


ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

 

                  Page      
PART I   Item 1:    Business      7   
  Item 1A:    Risk Factors      22   
  Item 1B:    Unresolved Staff Comments      43   
  Item 2:    Properties      44   
  Item 3:    Legal Proceedings      47   
  Item 4:    (Removed and Reserved)      47   
PART II   Item 5:   

Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

     47   
  Item 6:    Selected Financial Data      48   
  Item 7:   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     50   
  Item 7A:    Quantitative and Qualitative Disclosures about Market Risk      72   
  Item 8:    Financial Statements and Supplementary Data      75   
  Item 9:    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      122   
  Item 9A:    Controls and Procedures      122   
  Item 9B:    Other Information      125   
PART III   Item 10:    Directors, Executive Officers and Corporate Governance      125   
  Item 11:    Executive Compensation      132   
  Item 12:   

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

     158   
  Item 13:    Certain Relationships and Related Transactions, and Director Independence      160   
  Item 14:    Principal Accountant Fees and Services      161   
PART IV   Item 15:    Exhibits and Financial Statement Schedules      162   
SIGNATURES      167   

 

2


GLOSSARY OF TERMS

Definitions of terms and acronyms generally used in the energy industry and in this report are as follows:

Bbl. One stock tank barrel or 42 United States gallons liquid volume.

Bcf. One billion cubic feet.

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl oil, condensate or natural gas liquids.

Bpd. Barrels per day.

Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed acreage. Acres spaced or assigned to productive wells.

Development well. A well drilled within a proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dth. One dekatherm, equivalent to one million British thermal units.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

EBITDA. Net income (loss) before net interest expense, income taxes, and depreciation and amortization. EBITDA is considered to be a non-GAAP measurement.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well as those items are defined in this section.

FASB. Financial Accounting Standards Board.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Fractionation. The process used to separate an NGL stream into its individual components.

GAAP. Generally Accepted Accounting Principles.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

Mcfd. One thousand cubic feet per day.

MLP. Master Limited Partnership.

MMBtu. One million British thermal units.

 

3


MMcf. One million cubic feet.

MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

MMcfed. One Mmcfe per day.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGL. Natural gas liquids, which are the hydrocarbon liquids contained within gas.

NYMEX. The New York Mercantile Exchange.

Oil. Crude oil and condensate.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Proved oil and gas reserves are those quantities of oil and gas that by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

PV-10. Present value of future net revenues. See the definition of “standardized measure.”

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Residue gas. The portion of natural gas remaining after natural gas is processed for removal of NGLs and impurities.

SEC. Securities Exchange Commission.

Standardized Measure. Standardized measure, or standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, is the present value of estimated future net revenues to be generated from the production of

 

4


proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Successful well. A well capable of producing oil and/or gas in commercial quantities.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Unproved reserves. Lease acreage on which wells have not been drilled and where it is either probable or possible that the acreage contains reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

FORWARD-LOOKING STATEMENTS

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:

 

   

the demand for natural gas, oil, NGLs and condensate;

 

   

the price volatility of natural gas, oil, NGLs and condensate;

 

   

Atlas Pipeline Partners, L.P.’s (“APL”) ability to connect new wells to its gathering systems;

 

   

changes in the market price of our common units;

 

   

future financial and operating results;

 

   

economic conditions and instability in the financial markets;

 

   

resource potential;

 

   

realized natural gas and oil prices;

 

   

success in efficiently developing and exploiting our reserves and economically finding or acquiring additional recoverable reserves;

 

   

the accuracy of estimated natural gas and oil reserves;

 

   

the financial and accounting impact of hedging transactions;

 

   

the ability to fulfill the respective substantial capital investment needs of us and APL;

 

   

expectations with regard to acquisition activity, or difficulties encountered in connection with acquisitions;

 

   

the limited payment of dividends or distributions, or failure to declare a dividend or distribution, on outstanding common units or other equity securities

 

5


   

any issuance of additional common units or other equity securities, and any resulting dilution or decline in the market price of any such securities;

 

   

restrictive covenants in indebtedness of us and APL that may adversely affect operational flexibility;

 

   

potential changes in tax laws which may impair the ability to obtain capital funds through investment partnerships;

 

   

the ability to raise funds through the investment partnerships or through access to capital markets;

 

   

the ability to obtain adequate water to conduct drilling and production operations, and to dispose of the water used in and generated by these operations, at a reasonable cost and within applicable environmental rules;

 

   

the introduction of Pennsylvania severance tax or impact fee;

 

   

changes and potential changes in the regulatory and enforcement environment in the areas in which we and APL conduct business;

 

   

the effects of intense competition in the natural gas and oil industry;

 

   

general market, labor and economic conditions and related uncertainties;

 

   

the ability to retain certain key customers;

 

   

dependence on the gathering and transportation facilities of third parties;

 

   

the availability of drilling rigs, equipment and crews;

 

   

potential incurrence of significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment;

 

   

uncertainties with respect to the success of drilling wells at identified drilling locations;

 

   

expirations of undeveloped leasehold acreage;

 

   

uncertainty regarding operating expenses, general and administrative expenses and finding and development costs;

 

   

exposure to financial and other liabilities of the managing general partners of the investment partnerships;

 

   

the ability to comply with, and the potential costs of compliance with, new and existing federal, state, local and other laws and regulations applicable to our and APL’s business and operations;

 

   

exposure to new and existing litigations;

 

   

the potential failure to retain certain key employees and skilled workers; and

 

   

development of alternative energy resources.

Other factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under “Item 1A: Risk Factors” in this report. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

 

6


PART I

 

ITEM 1: BUSINESS

General

We are a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS), whose common units are listed on the New York Stock Exchange under the symbol “ATLS”. We are an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, Illinois Basin and the Rocky Mountain region. We sponsor and manage tax-advantaged investment partnerships, in which we co-invest, to finance a portion of our natural gas and oil production activities. Our goal is to increase the distributions to our unitholders by continuing to grow the net production from our natural gas and oil production business as well as the fee-based revenues from our partnership management business.

On February 17, 2011, we acquired certain assets and liabilities (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner. These assets principally included the following:

 

   

AEI’s investment management business, which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which we fund a portion of our natural gas and oil well drilling;

 

   

proved reserves located in the Appalachia Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan, and the Chattanooga Shale of northeastern Tennessee;

 

   

certain producing natural gas and oil properties, upon which we are developers and producers;

 

   

all of the ownership interests in Atlas Energy GP, LLC, our general partner; and

 

   

a direct and indirect ownership interest in Lightfoot LP and Lightfoot GP (collectively, “Lightfoot”), which incubates new MLPs and invest in existing MLPs. At December 31, 2011, we had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot.

Concurrent with our acquisition of the Transferred Business, AEI completed its merger with Chevron Corporation (“Chevron”), whereby AEI became a wholly owned subsidiary of Chevron.

As of December 31, 2011, our principal development and production assets consisted of:

 

   

working interests in approximately 8,500 gross producing natural gas and oil wells;

 

   

overriding royalty interests in over 500 gross producing natural gas and oil wells;

 

   

net daily production of 35.9 Mmcfed for the twelve months ended December 31, 2011;

 

   

proved reserves of 167.6 Bcfe at December 31, 2011; and

 

   

our partnership management business, which includes equity interests in 98 investment partnerships and a registered broker-dealer that acts as the dealer-manager of our investment partnership offerings.

In addition to our natural gas and oil development and production operations, we maintain an ownership interest in Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider. APL is a leading provider of natural gas gathering, processing and treating services in the Anadarko and Permian Basins located in the southwestern and mid-continent regions of the United States; a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and a provider of NGL transportation services in the southwest region of the United States. At December 31, 2011, we owned a 2% general partner interest, all of the incentive distribution rights, and an approximate 10.7% common limited partner interest. Please see our further discussion of these ownership interests under “Interests in APL.”

Our operations include four reportable operating segments: gas and oil production, well construction and completion, other partnership management and APL.

 

7


Business Strategy

The key elements of our business strategy are:

Expand our natural gas and oil production. We generate a significant portion of our revenue and net cash flow from natural gas and oil production. We believe our program of sponsoring investment partnerships to exploit our acreage opportunities provides us with enhanced economic returns. For the five year period ended December 31, 2011, we raised over $1.4 billion from outside investors through our investment partnerships. We intend to continue to finance the majority of our drilling and production activities through our investment partnerships.

Expand our fee-based revenue through our sponsorship of investment partnerships. We generate substantial revenue and cash flow from fees paid by the investment partnerships to us for acting as the managing general partner. As we continue to sponsor investment partnerships, we expect that our fee revenues from our drilling and operating agreements with our investment partnerships will increase. We expect that the fee revenue we generate with respect to fees paid by the investment partnerships to us for partnership management will add stability to our revenue and cash flows. Furthermore, the carried interests and fees we earn reduce the net investment in our drilling program and therefore enhance our rates of return on investment.

Expand operations through strategic acquisitions. We continually evaluate opportunities to expand our operations through acquisitions of developed and undeveloped properties or companies that can increase our cash available for distribution. We will continue to seek strategic opportunities in our current areas of operation, as well as other regions of the United States.

Continue to maintain control of operations and costs. We believe it is important to be the operator of wells in which we or our investment partnerships have an interest because we believe it will allow us to achieve operating efficiencies and control costs. As operator, we are better positioned to control the timing and plans for future enhancement and exploitation efforts, costs of enhancing, drilling, completing and producing the well, and marketing negotiations for our natural gas and oil production to maximize both volumes and wellhead price. We were the operator of the vast majority of the properties in which we or our investment partnerships had a working interest at December 31, 2011.

Continue to manage our exposure to commodity price risk. To limit our exposure to changing commodity prices, we use financial hedges for a portion of our natural gas and oil production. We principally use fixed price swaps and collars as the mechanism for the financial hedging of our commodity prices.

Competitive Strengths

We believe our competitive strengths favorably position us to execute our business strategy and to maintain and grow our distributions to unitholders. Our competitive strengths are:

Our partnership management business can improve the economic rates of return associated with our natural gas and oil production activities. A well drilled, net to our equity interest, in our partnership management business will provide us with an enhanced rate of return. For each well drilled in a partnership, we receive an upfront 15% to 18% markup on the investors’ well construction and completion costs and a fixed administration and oversight fee of $15,000 to $250,000. Further, we receive an approximate 5% to 10% incremental equity interest in each well, for which we do not make any corresponding capital contribution. Consequently, our economic interest in each well is significantly greater than our proportional contribution to the total cash costs which enhances our overall rate of return. Additionally, we receive monthly per well fees from the partnership for the life of each individual well, which also increases our rate of return.

Fee-based revenues from our investment partnerships provide a stable foundation for our distributions. Our investment partnerships provide us with stable, fee-based revenues which diminish the influence of commodity price fluctuations on our cash flows. Our fees for managing our investment partnerships accounted for approximately 41% of our segment margin in the twelve months ended December 31, 2011. In addition, because our investment partnerships reimburse us on a cost-plus basis for drilling capital expenses, we are partially protected against increases in drilling costs.

We are one of the leading sponsors of tax-advantaged investment partnerships. We have sponsored limited and general partnerships to raise funds from investors to finance our development drilling activities since 1968, and we believe that we are one of the leading sponsors of such investment partnerships in the country. We believe that our lengthy association with many of the broker-dealers that act as placement agents for our investment partnerships provide us with a competitive advantage over entities with similar operations. We also believe that our sponsorship of investment partnerships has allowed us to generate attractive returns on drilling, operating and production activities.

 

8


We have a high quality, long-lived reserve base. Our natural gas properties are located principally in the Appalachian Basin and are characterized by long-lived reserves, favorable pricing for our production and readily available transportation. Moreover, because our production in the Appalachian Basin is located near markets in the northeast United States, we believe we will generally receive a premium over quoted prices on the NYMEX for the natural gas we produce.

We have significant experience in making accretive acquisitions. Our management team has extensive experience in consummating accretive acquisitions. We believe we will be able to generate acquisition opportunities of both producing and non-producing properties through our management’s extensive industry relationships. We intend to use these relationships and experience to find, evaluate and execute on acquisition opportunities.

We have significant engineering, geologic and management experience. Our technical team of geologists and engineers has extensive industry experience. We believe that we have been one of the most active drillers in our core operating areas and, as a result, that we have accumulated extensive geological and geographical knowledge about the area. We have also recently added geologists and engineers to our technical staff that have significant experience in other productive basins within the continental United States, which will allow us to evaluate and possibly expand our core operating areas.

Subsequent Events

Formation of Atlas Resource Partners, L.P. In February 2012, our General Partner’s board of directors approved the formation of a newly created exploration and production master limited partnership named Atlas Resource Partners, L.P. (“ARP”), which will hold substantially all of our current natural gas and oil development and production assets and the partnership management business. Our General Partner’s board of directors also approved the distribution of approximately 5.24 million ARP common units, which will be distributed on March 13, 2012 to our unitholders using a ratio of 0.1021 ARP limited partner units for each of our common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units will represent an approximate 19.6% limited partner interest. Subsequent to the distribution, we will own a 2% general partner interest, all of the incentive distribution rights in ARP and common units representing an approximate 78.4% limited partner interest in ARP. For a further description of ARP’s cash distribution policy, please see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations - Cash Distributions”.

Geographic and Geologic Overview

Over the last decade, the energy industry in the United States has seen tremendous growth due to advancements in the technology to extract natural gas and oil from conventional and unconventional resource plays, which has made such extraction more economically attractive.

Our proved reserves, both developed and undeveloped, are concentrated in the following areas:

Appalachian Basin Overview. The Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee. It is the most mature oil and natural gas producing region in the United States, having established the first oil production in 1860. Because the Appalachian Basin is located near the leading energy-consuming regions of the mid-Atlantic and northeastern United States, Appalachian producers have historically sold their natural gas at a premium to the benchmark price for natural gas on the NYMEX. For the year ended December 31, 2011, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $0.36 per million British thermal units (“MMBtu”). In addition, Appalachian natural gas production has the advantage of a high energy content, ranging from 1.00 to 1.11 dekatherms (“Dth”) per Mcf. The majority of our existing natural gas sales contracts yield upward adjustments from index based pricing for throughput with an energy content above 1.0 Dth per Mcf. This higher energy content resulted in realized premiums averaging 1.05% over normal pipeline quality natural gas for the year ended December 31, 2011.

Historically, producers in the Appalachian Basin developed oil and natural gas from shallow sandstones with low permeability which are prevalent in the region. These shallow wells are characterized by modest initial volumes, low pressures, and high initial decline rates followed by low annual decline rates. Almost all of these wells were drilled vertically and usually produce for 30 years or more. Shallow sandstone formations in the Appalachian Basin are typically homogenous and have a high degree of step-out development success. The primary shallow pay zones are shallow sandstones in the Upper Devonian Shale formation. As the step-out development progresses, reserves from newly completed wells are reclassified from proved undeveloped to proved developed and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Traditional shallow wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing.

 

9


In recent years, our predecessors and other operators have targeted the Marcellus Shale for development activity. The Marcellus Shale is a black, organic rich shale formation located at depths between 6,000 and 8,500 feet and ranges in thickness from 75 to 150 feet. As of December 31, 2011, we had an interest in Pennsylvania in approximately 221 wells, consisting of 207 vertical wells and 14 horizontal wells. An additional 24 wells, consisting of eight vertical wells and 16 horizontal wells, have been completed and are scheduled to be turned on-line during the first half of 2012.

As of December 31, 2011, we have drilled 11 Marcellus Shale wells and will be drilling an additional two Marcellus Shale wells during the first quarter of 2012 in West Virginia, all of which we are drilling through our partnership management business, consisting of seven vertical wells and six horizontal wells. We have maximized the lateral lengths of each of the horizontal wells based on lease boundaries. To date, there have been multiple Marcellus Shale wells drilled near our well sites that have shown strong initial production. Our future drilling activity in portions of the Appalachian Basin located in parts of Pennsylvania, West Virginia and New York will be limited by the terms of the non-competition agreements between certain of Atlas Energy’s officers and directors and Chevron.

Additionally, as of December 31, 2011, we have leased additional Marcellus Shale acreage in Lycoming County, PA. We are currently drilling four additional Marcellus wells on this acreage through our partnership management program and have additional sites available to drill. We anticipate expanding our acreage in Lycoming County, which will give us the ability to drill additional wells.

The Chattanooga Shale is a Devonian-age shale found at a depth of approximately 3,500 feet. We have over 100,000 net undeveloped acres in the Chattanooga Shale in northeastern Tennessee. We operate approximately 425 wells in the region, 421 of which are funded through our investment partnerships and 30 of which are horizontal wells. Based on some recent successes around our leasehold acreage, we plan to drill additional horizontal wells during 2012. We also own two gas processing plants in eastern Tennessee with combined capacity of approximately 35 Mmcf per day, which capacity we believe can be increased.

The Utica Shale is an Ordovician-age shale which lies several thousand feet below the Devonian-age Marcellus Shale. The Utica Shale is much thicker than the Marcellus Shale, and we believe has the potential to become a significant resource play. The Utica Shale begins in eastern Ohio and extends eastward, covering a large portion of Pennsylvania, New York and West Virginia. The Utica Shale has a western oil phase, central wet gas phase and eastern dry gas phase. We currently have an interest in approximately 2,100 wells in Ohio and operate three field offices which we intend to use for future Utica Shale development.

Illinois Basin Overview. The Devonian-age New Albany Shale is a blanket formation found at depths of 500 to 3,000 feet, with thicknesses ranging from 100 to 200 feet. We have a leasehold of over 100,000 net acres in the New Albany Shale in southwestern Indiana located is in the “biogenic gas window.” The natural fracture patterns in the New Albany Shale are vertically oriented, which lends itself to a horizontal drilling approach. As of December 31, 2011, we have an interest in 92 wells in the New Albany Shale, of which we operate 90.

Denver-Julesburg Basin Overview. Within the Denver-Julesburg (“DJ”) Basin, we have primarily focused on the Niobrara Shale, which extends from northeastern Colorado to southern Wyoming into western Nebraska. Our developmental drilling program is focused on the shallow, gas-rich Niobrara in eastern Colorado, western Nebraska, and Kansas. Although natural gas was discovered in the Niobrara Shale in 1919, drilling in the area did not become commercial until the use of fracturing technologies became prevalent in the 1970s and 1980s. Development continued through the 1990s, but drilling success rates in the region were enhanced by the more recent development of 3-D seismic technology. The Niobrara Shale is suitable for conventional drilling of shallow developmental natural gas wells, which are wells drilled in an area of proven reserves to the depth of a horizon known to be productive. The Niobrara Shale presents the potential for efficient drilling, completion and production operations, as well as relatively quick well turn-in-line timeframes and favorable topography.

We are a party to a farm-out agreement with Black Raven Energy covering 178,000 acres located in the Niobrara formation in eastern Colorado and western Nebraska, pursuant to which we pay a per well fee and production royalties to Black Raven. The acreage subject to our farm-out agreement encompasses the development of shallow Niobrara gas wells at about 2,700 feet in depth with site selection based on the identification of 3D seismic structures. We operate 41 wells in the region, all of which were funded through our investment partnerships. We have run 3-D seismic imaging over a portion of the acreage subject to the farm-out agreement, which has identified over 600 potential drilling sites. Along with identifying potential Niobrara Shale drilling sites, the 3-D seismic imaging has allowed us to identify potential drilling sites in the D-Sand located under the Niobrara Shale. The D-Sand is a well-established exploration target in the Denver-Julesberg basin. The 3-D seismic imaging helps limit the potential of drilling dry holes while increasing drilling efficiency.

 

10


Gas and Oil Production

Production Volumes

Currently, our natural gas, oil and natural gas liquids production operations are focused in various shale plays in the northeastern and midwestern United States, and include direct interest wells and ownership interests in wells drilled through our drilling partnerships. When we drill new wells through our partnership management business we receive an interest in each investment partnership proportionate to the value of our coinvestment in it and the value of the acreage we contribute to it, typically 15% to 31% of the overall capitalization of a particular partnership. We also receive an incremental interest in each partnership, typically 5% to 10%, for which we do not make any additional capital contribution. Consequently, our equity interest in the reserves and production of each partnership is typically between 20% and 41%. The following table presents our total net natural gas, oil and natural gas liquids production volumes and production per day for the three year period ended December 31, 2011, 2010 and 2009:

 

     Years Ended December 31,  
     2011      2010      2009  

Production per day:(1)(2)

        

Natural gas (Mcfd)

     31,403         35,855         38,644   

Oil (Bpd)

     307         373         427   

Natural gas liquids (Bpd)

     444         499         101   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

     35,912         41,090         41,814   
  

 

 

    

 

 

    

 

 

 

 

(1) Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.
(2) “MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day.

Production Revenues, Prices and Costs

We market the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price, the natural gas produced in the New Albany Shale and Antrim Shale has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices, and the gas produced in the Niobrara formation has been primarily based upon the Cheyenne Index. Crude oil produced from our wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil. Natural gas liquids are produced by our natural gas processing plants, which extract the natural gas liquids from the natural gas production, enabling the remaining “dry” gas (low BTU content) to meet pipeline specifications for long-haul transport to end users. We sell natural gas liquids produced by our natural gas processing plants to regional refining companies at the prevailing spot market price for natural gas liquids.

Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 94% of our proved reserves on an energy equivalent basis at December 31, 2011. The following table presents our production revenues and average sales prices for our natural gas, oil and natural gas liquids production for the years ended December 31, 2011, 2010 and 2009, along with our average production costs, taxes, and transportation and compression costs in each of the reported periods:

 

     Years Ended December 31,  
     2011      2010      2009  

Production revenues (in thousands):

        

Natural gas revenue

   $ 49,096       $ 75,630       $ 100,526   

Oil revenue

     10,057         10,541         11,119   

Natural gas liquids revenue

     7,826         6,879         1,334   
  

 

 

    

 

 

    

 

 

 

Total revenues

   $ 66,979       $ 93,050       $ 112,979   
  

 

 

    

 

 

    

 

 

 

 

11


     Years Ended December 31,  
     2011      2010      2009  

Average sales price:(1)

        

Natural gas (per Mcf):

        

Total realized price, after hedge(2)

   $ 4.98       $ 7.08       $ 7.54   

Total realized price, before hedge(2)

   $ 4.53       $ 4.60       $ 4.04   

Oil (per Bbl):

        

Total realized price, after hedge

   $ 89.70       $ 77.31       $ 71.34   

Total realized price, before hedge

   $ 89.07       $ 71.37       $ 57.41   

Natural gas liquids (per Bbl) total realized price:

   $ 48.26       $ 37.78       $ 36.19   

Production costs (per Mcfe):(1)

        

Lease operating expenses(3)

   $ 1.06       $ 1.27       $ 1.10   

Production taxes

     0.10         0.04         0.03   

Transportation and compression

     0.46         0.65         0.68   
  

 

 

    

 

 

    

 

 

 

Total

   $ 1.61       $ 1.96       $ 1.80   
  

 

 

    

 

 

    

 

 

 

 

(1) “Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.
(2) Excludes the impact of subordination of our production revenue to investor partners within our investment partnerships for the years ended December 31, 2011, 2010 and 2009. Including the effect of this subordination, the average realized gas sales prices were $4.28 per Mcf ($3.83 per Mcf before the effects of financial hedging), $5.78 per Mcf ($3.30 per Mcf before the effects of financial hedging) and $7.13 per Mcf ($3.62 per Mcf before the effects of financial hedging) for the years ended December 31, 2011, 2010 and 2009, respectively.
(3) Excludes the effects of our proportionate share of lease operating expenses associated with subordination of our production revenue to investor partners within our investment partnerships. Including the effects of these costs, total lease operating expenses per Mcfe were $0.75 per Mcfe ($1.30 per Mcfe for total production costs), $0.86 per Mcfe ($1.56 per Mcfe for total production costs) and $0.97 per Mcfe ($1.67 per Mcfe for total production costs) for the years ended December 31, 2011, 2010 and 2009, respectively.

Partnership Management Business

We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the partnerships. We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. We receive an interest in the investment partnerships proportionate to the amount of capital and the value of the leasehold acreage that we contribute, which interest is typically 15% to 31% of the overall capitalization in a particular partnership. We also receive an additional interest in each partnership, typically 5% to 10%, for operating the wells and managing the general partner for which we do not make any additional capital contribution. This brings our total interest in the partnerships in a range from 20% to 41%.

Over the last five years, we raised over $1.4 billion from outside investors for participation in our drilling partnerships. Net proceeds from these partnerships are used to fund the investors’ share of drilling and completion costs under our drilling contracts with the partnerships. We recognize revenues from drilling operations on the percentage-of-completion method as the wells are drilled, rather than when funds are received.

Our fund raising activities for sponsored drilling partnerships during the last five years are summarized in the following table (amounts in millions):

 

     Drilling Program Capital  
     Investor
Contributions
     Our
Contributions
     Total
Capital
 

2011

   $ 141.9       $ 28.3       $ 170.2   

2010(1)

     149.3         53.4         202.7   

2009

     353.4         97.5         450.9   

2008

     438.4         146.3         584.7   

2007

     363.3         137.6         500.9   
  

 

 

    

 

 

    

 

 

 

Total

   $ 1,446.3       $ 463.1       $ 1,909.4   
  

 

 

    

 

 

    

 

 

 

 

(1)

Does not include funds raised for a fall 2010 drilling program, which was cancelled due to the announcement of the acquisition of the Transferred Business in November 2010.

 

12


As managing general partner of our investment partnerships, we receive the following fees:

 

   

Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% to 18% mark-up on those costs incurred to drill and complete the well.

 

   

Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee of between $15,000 and $250,000, depending on the type of well drilled. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

 

   

Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $1,500 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

 

   

Gathering. Each royalty owner, partnership and certain other working interest owners pay us a gathering fee, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the natural gas. In general, pursuant to gathering agreements we have with a third-party gathering system which gathers the majority of our natural gas, we must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). As a result, some of our gathering expenses within our partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from investment partnerships by approximately 3%.

Our investment partnerships provide tax advantages to our investors because an investor’s share of the partnership’s intangible drilling cost deduction may be used to offset ordinary income. Intangible drilling costs include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling. Generally, for our investment partnerships that were formed after October 2008, approximately 85% of the subscription proceeds received have been used to pay 100% of the partnership’s intangible drilling costs. For example, an investment of $10,000 generally permits the investor to deduct from taxable ordinary income approximately $8,500 in the year in which the investor invests. For our investment partnerships that were formed prior to October 2008, approximately 90% of the subscription proceeds received were used to pay 100% of the partnership’s intangible drilling costs.

Within our investment partnerships, we have agreed to subordinate a portion of our share of production revenues, net of corresponding production costs, to the investor partners until the partners have received specified returns, typically 10% per year, over a specific period, typically the first five to seven years, as stipulated within the individual investor partnership agreement.

Drilling Activity

The number of wells we drill will vary depending on, among other things, the amount of money we raise through our investment partnerships, the cost of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table sets forth information with respect to the number of wells we drilled, both gross and for our interest, during the periods indicated. There were no exploratory wells drilled during the years ended December 31, 2011, 2010 and 2009.

 

     Years Ended December 31,  
     2011      2010      2009  

Gross wells drilled

     160         117         267   

Our share of gross wells drilled(1)

     31         34         68   

 

(1) Includes (i) our percentage interest in the wells in which we have a direct ownership interest and (ii) our percentage interest in the wells based on our percentage interest in our investment partnerships.

We do not operate any of the rigs or related equipment used in our drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables us to streamline our operations and conserve capital for investments in new wells, infrastructure and property acquisitions, while generally retaining control over all geological, drilling, engineering and operating decisions. We perform regular inspection, testing and monitoring functions on our operated wells.

 

13


As of December 31, 2011, we had the following ongoing drilling activities:

 

     Gross      Net  
     Spud      Total
Depth
     Completed      Spud      Total
Depth
     Completed  

Marcellus – Vertical

     —           3         1         —           2         1   

Marcellus – Horizontal

     2         —           —           2         —           —     

Chattanooga – Vertical

     —           —           —           —           —           —     

Chattanooga – Horizontal

     —           2         2         —           2         2   

Niobrara - Vertical

     6         21         32         6         21         32   

Ohio – Vertical

     —           3         —           —           3         —     

Natural Gas and Oil Leases

The typical natural gas and oil lease agreement provides for the payment of royalties to the mineral owner for all natural gas and oil produced from any well(s) drilled on the leased premises. In the Appalachian Basin and Colorado Basin, this amount is typically 1/8th (12.5%) resulting in a 87.5% net revenue interest to us, and, in Michigan, this amount is typically 1/6th (16.67%) resulting in an 83.3% net revenue interest to us. In certain instances, this royalty amount may increase to 1/6th in the Appalachian Basin and to 3/16th (18.75%) in Michigan when leases are taken from larger landowners or mineral owners such as coal and timber companies.

In almost all of the areas we operate in the Appalachian Basin, Colorado, Indiana and Michigan, the surface owner is normally the natural gas and oil owner allowing us to deal with a single owner. This simplifies the research process required to identify the proper owners of the natural gas and oil rights and reduces the per acre lease acquisition cost and the time required to successfully acquire the desired leases.

Because the acquisition of natural gas and oil leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are often held by other natural gas and oil operators. In order to gain the right to drill these leases, we may elect to farm-in leases and/or purchase leases from other natural gas and oil operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging in the Appalachian Basin and Colorado from 1/32nd to 1/16th (3.125% to 6.25%), which further reduces the net revenue interest available to us to between 84.375% and 81.25%, and in Michigan from 3.33% to 5.33%, which further reduces the net revenue interest available to us to between 80.0% and 78.0%.

The interests in some of our operated properties and of natural gas and oil leases retain the option to participate in the drilling of wells on leases farmed out or assigned to us for a retained working interest of up to 50% of the wells drilled on the covered acreage. In this event, our working interest ownership will be reduced by the amount retained by the third party. In all other instances, we anticipate owning a 100% working interest in newly drilled wells.

Contractual Revenue Arrangements

Natural Gas. We market the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price, the natural gas produced in the New Albany Shale and Antrim Shale has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices, and the gas produced in the Niobrara formation has been primarily based upon the Cheyenne Index. For the year ended December 31, 2011, Chevron, South Jersey Resources Group and Sequent Energy Management accounted for approximately 17%, 14% and 10% of our total natural gas and oil production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Crude Oil. Crude oil produced from our wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil.

Natural Gas Liquids. Natural gas liquids are produced by our natural gas processing plants, which extract the natural gas liquids from natural gas production, enabling the remaining “dry” gas (low BTU content) to meet pipeline specifications for long-haul transport to end users. We sell natural gas liquids produced by our natural gas processing plants to regional refining companies at the prevailing spot market price for natural gas liquids.

 

14


We do not have delivery commitments for fixed and determinable quantities of natural gas or oil in any future periods under existing contracts or agreements.

Investment Partnerships. We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. See “Partnership Management Business” for further discussion.

Natural Gas and Oil Hedging

We seek to provide greater stability in our cash flows through our use of financial hedges. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures and options contracts with qualified counterparties. Financial hedges are contracts between ourselves and counterparties and do not require physical delivery of hydrocarbons. Financial hedges allow us to mitigate hydrocarbon price risk, and cash is settled to the extent there is a price difference between the hedge price and the actual NYMEX settlement price. Settlement typically occurs on a monthly basis, at the time in the future dictated within the hedge contract. Financial hedges executed in accordance with our secured credit facility do not require cash margin and are secured by our natural gas and oil properties. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we have a management committee to assure that all financial trading is done in compliance with our hedging policies and procedures. We do not intend to contract for positions that we cannot offset with actual production.

Natural Gas Gathering Agreements

We are party to two natural gas gathering agreements with Laurel Mountain Midstream, LLC (“Laurel Mountain”), in which APL formerly owned a 49% interest: (1) a Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System with respect to the existing gathering systems and expansions to it (the “Legacy Agreement”) and (2) a Gas Gathering Agreement for Natural Gas on the Expansion Gathering System with respect to other gathering systems constructed within the specified area of mutual interest (the “Expansion Agreement” and, collectively with the Legacy Agreement, the “Gathering Agreements”). Under the Gathering Agreements, we dedicate our natural gas production in certain areas within the Appalachian Basin to Laurel Mountain for transportation to interstate pipeline systems, local distribution companies, and/or end users in the area, subject to certain exceptions. In return, Laurel Mountain is required to accept and transport our dedicated natural gas in the Appalachian Basin subject to certain conditions.

Under the Gathering Agreements, we are required to pay a gathering fee to Laurel Mountain that is the greater of $0.35 per mcf or 16% of the gross sales price except that a lower fee applies with respect to specific wells subject to existing contracts calling for lower minimum gathering fees and if Laurel Mountain fails to perform specified obligations. In addition, if an investment partnership pays a lesser competitive gathering fee for the natural gas it transports using Laurel Mountain’s gathering system, which currently is 13% of the gross sales price, then we, and not the partnership, will have to pay the difference to Laurel Mountain.

The Gathering Agreements require that, to the extent that we own wells or propose wells that are within 2,500 feet of Laurel Mountain’s gathering system, we must at our cost construct up to 2,500 feet of flowline as necessary to connect the wells to the gathering system. For wells more than 2,500 feet from Laurel Mountain’s gathering system, if we construct a flow line to within 1,000 feet of Laurel Mountain’s gathering system, then Laurel Mountain must, at its own cost, extend its gathering system to connect to such flowline.

The Gathering Agreements remain in effect so long as gas from our wells is produced in economic quantities without lapse of more than 90 days.

Availability of Oil Field Services

We contract for drilling rigs and purchase goods and services necessary for the drilling and completion of wells from a number of drillers and suppliers, none of which supplies a significant portion of our annual needs. During the years ended December 31, 2011 and 2010, we faced no shortage of these goods and services. Over the past several years, we and other oil and natural gas companies have experienced higher drilling and operating costs. We cannot predict the duration or stability of the current level of supply and demand for drilling rigs and other goods and services required for our operations with any certainty due to numerous factors affecting the energy industry, including the demand for natural gas and oil.

 

15


We maintain certain agreements pursuant to which subsidiaries of Chevron have agreed to provide certain specified operational services for a limited period of time, including:

 

   

Pennsylvania Operating Services Agreement. Pursuant to this agreement, a subsidiary of Chevron provides us (including drilling partnerships which we manage) with certain operational services including, among other things, gas volumetric control, measurement and balancing services and water disposal services with respect to certain wells in Pennsylvania in exchange for specified fees. We will indemnify the provider against all claims and liabilities arising out of its provision of services under this agreement. We may terminate the agreement or any portion of the services provided under the agreement at any time, and either party may terminate the agreement following an uncured material breach of the agreement by the other party. The initial term of this agreement will expire on February 17, 2014. The agreement may continue from month to month thereafter, subject to the right of either party to cancel the agreement at any time following the expiration of the initial term.

 

   

Petro-Technical Services Agreement. Pursuant to this agreement, a subsidiary of Chevron provides us with certain consulting services including, among others, planning, designing, drilling, stimulating, completing and equipping wells, in exchange for a payment in the amount of the actual costs of providing such services, up to a maximum of the market rate for the same or similar services in Pittsburgh, Pennsylvania or Traverse City, Michigan, depending on the location of the well. We will indemnify the provider against all claims and liabilities arising out of its provision of services under this agreement. The agreement remained in place at December 31, 2011.

Competition

The energy industry is intensely competitive in all of its aspects. We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through our investment partnerships, contracting for drilling equipment and securing trained personnel. We also compete with the exploration and production divisions of public utility companies for natural gas and oil property acquisitions. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Our competitors may be able to pay more for natural gas and oil properties and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Product availability and price are the principal means of competition in selling natural gas, oil, and natural gas liquids.

Many of our competitors possess greater financial and other resources which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we do. Moreover, we also compete with a number of other companies that offer interests in investment partnerships. As a result, competition for investment capital to fund investment partnerships is intense.

Markets

The availability of a ready market for natural gas, oil and natural gas liquids and the price obtained, depends upon numerous factors beyond our control, as described in “Item 1A: Risk Factors—Risks Relating to Our Business.” Product availability and price are the principal means of competition in selling natural gas, oil and natural gas liquids. During the years ended December 31, 2011, 2010 and 2009, we did not experience problems in selling our natural gas, oil and natural gas liquids, although prices have varied significantly during those periods.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas of the Appalachian region and Michigan/Indiana. These seasonal anomalies may pose challenges for meeting our well construction objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay our operations. We have in the past drilled a greater number of wells during the winter months, because we have typically received the majority of funds from investment partnerships during the fourth calendar quarter. Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

 

16


Environmental Matters and Regulation

Overview. Our operations are subject to comprehensive and stringent federal, state and local laws and regulations governing, among other things, where and how we install wells, how we handle wastes from our operations and the discharge of materials into the environment. Our operations will be subject to the same environmental laws and regulations as other companies in the natural gas and oil industry. Among other requirements and restrictions, these laws and regulations:

 

   

require the acquisition of various permits before drilling commences;

 

   

require the installation of expensive pollution control equipment and water treatment facilities;

 

   

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

 

   

limit or prohibit drilling activities on lands lying within or, in some cases, adjoining wilderness, wetlands and other protected areas;

 

   

require remedial measures to reduce, mitigate or respond to releases of pollutants or hazardous substances from former operations, such as pit closure and plugging of abandoned wells;

 

   

impose substantial liabilities for pollution resulting from our operations; and

 

   

with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs. We believe that our operations substantially comply with all currently applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how environmental laws and regulations that may take effect in the future may impact our properties or operations. For the three-year period ended December 31, 2011, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2012, or that will otherwise have a material impact on our financial position or results of operations.

Environmental laws and regulations that could have a material impact on the natural gas and oil exploration and production industry include the following:

National Environmental Policy Act. Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically require an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that will be made available for public review and comment. All of our proposed exploration and production activities on federal lands require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

Waste Handling. The Solid Waste Disposal Act, including the Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil and natural gas constitute “solid wastes”, which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.

 

17


We believe that our operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes to be significant, any more stringent regulation of natural gas and oil exploitation and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. Further, much of our natural gas extraction activity utilizes a process called hydraulic fracturing, which results in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements. Recently, this subject has received much regulatory and legislative attention at both the federal and state level and we anticipate that the permitting and compliance requirements applicable to hydraulic fracturing activity are likely to become more stringent and could have a material adverse impact on our business and operations.

The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe our operations are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions. The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through permits and other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic and other air pollutants at specified sources. Specific federal regulations applicable to the natural gas industry have been proposed under the New Source Performance Standards (“NSPS”) program along with National Emissions Standards for Hazardous Air Pollutants (“NESHAP”s). Final NSPS and NESHAP rules are anticipated in the spring of 2012 and will likely impose additional emissions control requirements and practices on our operations. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of compliance of our customers to the point where demand for natural gas is affected. We believe that our operations are in substantial compliance with the requirements of the Clean Air Act.

 

18


OSHA and Other Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Greenhouse Gas Regulation and Climate Change. Natural gas contains methane, which is considered to be a greenhouse gas. Additionally, the burning of natural gas produces carbon dioxide, which is also a greenhouse gas. Published studies have suggested that the emission of greenhouse gases may be contributing to global warming. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on our business. However, Congress has been actively considering climate change legislation. More directly, the EPA has begun regulating greenhouse gas emissions under the federal Clean Air Act. In response to the Supreme Court’s decision in Massachusetts V. EPA, 549 U.S. 497 (2007)(holding that greenhouse gases are air pollutants covered by the Clean Air Act), the EPA made a final determination that greenhouse gases endangered public health and welfare, 74 Fed. Reg. 66,496 (December 15, 2009). This finding led to the regulation of greenhouse gases under the Clean Air Act. Currently, the EPA has promulgated two rules that will impact our business.

First, the EPA promulgated the so-called “Tailoring Rule” which established emission thresholds for greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31514 (June 3, 2010). Both the federal preconstruction review program (Prevention of Significant Deterioration) and the operating permit program (Title V) are now implicated by emissions of greenhouse gases. These programs, as modified by the Tailoring Rule, could require some new facilities to obtain a PSD permit depending on the size of the new facilities. In addition, existing facilities as well as new facilities that exceed the emissions thresholds could be required to obtain Title V operating permits.

Second, the EPA finalized its Mandatory Reporting of Greenhouse Gases rule in 2009, 74 Fed. Reg. 56,260 (October 30, 2009). Subsequent revisions, additions, and clarification rules were promulgated, including a rule specifically addressing the natural gas industry. These rules require certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to the EPA on an annual basis. The natural gas industry is covered by the rule and requires annual greenhouse gas emissions to be reported starting in 2011 with the initial reports due in 2012. This rule imposes additional reporting obligations on us.

There are also ongoing legislative and regulatory efforts to encourage the use of cleaner energy technologies. While natural gas is a fossil fuel, it is considered to be more benign, from a greenhouse gas standpoint, than other carbon-based fuels, such as coal or oil. Thus future regulatory developments could have a positive impact on our business to the extent that they either decrease the demand for other carbon-based fuels or position natural gas as a favored fuel.

In addition to domestic regulatory developments, the United States is a participant in multi-national discussion intended to deal with the greenhouse gas issue on a global basis. To date, those discussions have not resulted in the imposition of any specific regulatory system, but such talks are continuing and may result in treaties or other multi-national agreements that could have an impact on our business.

Finally, as noted above, the scientific community continues to engage in a healthy debate as to the impact of greenhouse gas emissions on planetary conditions. For example, such emissions may be responsible for increasing global temperatures, and/or enhancing the frequency and severity of storms, flooding and other similar adverse weather conditions. We do not believe that these conditions are having any material current adverse impact on our business, and we are unable to predict at this time what, if any, long-term impact such climate effects would have.

Other Regulation of the Natural Gas and Oil Industry. The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

 

19


Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we will operate also regulate one or more of the following:

 

   

the location of wells;

 

   

the manner in which water necessary to develop wells is managed;

 

   

the method of drilling and casing wells;

 

   

the surface use and restoration of properties upon which wells are drilled;

 

   

the plugging and abandoning of wells; and

 

   

notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from its wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax or impact fee with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

State Regulation. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Michigan imposes a 5% severance tax on natural gas and a 6.6% severance tax on oil, Tennessee imposes a 3% severance tax on natural gas and oil production and Ohio imposes a severance tax of $0.025 per Mcf of natural gas and $0.10 per Bbl of oil, Indiana imposes a severance tax of $.03 per MCF on natural gas and $.24 per bbl of oil, Colorado imposes a severance tax up to 5% of the value of oil and gas severed from earth, in addition to other applicable taxes, while West Virginia imposes a 5% severance tax on oil and gas. While Pennsylvania has not imposed a severance tax, there is legislation that has been approved by the Pennsylvania legislature and signed by the Governor that will impose an impact fee on oil and gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our unitholders.

Interest in Atlas Pipeline Partners, L.P.

In addition to our production operations, we also maintain the following interest in APL at December 31, 2011:

 

   

a 2.0% general partner interest, which entitles us to receive 2% of the cash distributed by APL;

 

   

all of the incentive distribution rights (“IDRs”), which entitle us to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter; and

 

   

5,754,253 common units, representing approximately 10.7% of the outstanding common units, or a 10.5% ownership interest in APL.

 

20


APL is a leading provider of natural gas gathering, processing and treating services in the Anadarko and Permian Basins located in the southwestern and mid-continent regions of the United States, a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States and a provider of NGL transportation services in the southwestern region of the United States.

As of December 31, 2011, through its Gathering and Processing operations, APL owns and operates:

 

   

seven active natural gas processing plants with aggregate capacity of approximately 610 MMcfd;

 

   

9,000 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which transport gas from wells and central delivery points in the Anadarko and Permian Basins to APL’s natural gas processing and treating plants or third party pipelines;

 

   

100 miles of active natural gas gathering systems located in Tennessee, which gather gas from wells and central delivery points and deliver to natural gas processing and treating plants, as well as third-party pipelines; and

 

   

a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”), which was acquired in May 2011. WTLPG owns an approximately 2,200 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron, which owns the remaining 80% interest.

Our ownership of APL’s incentive distribution rights entitles us to receive the following increasing percentage of cash distributed by APL as it reaches certain target distribution levels:

 

   

13.0% of all cash distributed in any quarter after each APL common unit has received $0.42 for that quarter;

 

   

23.0% of all cash distributed in any quarter after each APL common unit has received $0.52 for that quarter; and

 

   

48.0% of all cash distributed in any quarter after each APL common unit has received $0.60 for that quarter.

In conjunction with a previous acquisition made by APL, in 2009 we agreed to allocate up to $3.75 million of our IDRs per quarter back to APL after we receive an initial $7.0 million per quarter of IDRs.

Employees

As of December 31, 2011, we employed 683 persons.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K and any amendments to those reports, available through our website at www.atlasenergy.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. To view these reports, click on “Investor Relations”, then “SEC Filings”. You may also receive, without charge, a paper copy of any such filings by request to us at Park Place Corporate Center One, 1000 Commerce Drive - 4th Floor, Pittsburgh, Pennsylvania 15275, telephone number (412) 489-0006. A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings is also available at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

 

21


ITEM 1A: RISK FACTORS

As described above in “Item 1: Business – Subsequent Events”, in February 2012, our General Partner’s board of directors approved the formation of Atlas Resource Partners, L.P. (“ARP”), a newly-created exploration and production master limited partnership that will receive and hold substantially all of our natural gas and oil production and development assets and our partnership management business. After we contribute these assets to ARP, we will distribute approximately 5.24 million ARP common units to our unitholders using a ratio of 0.1021 ARP limited partner units for each common unit of ours owned on the record date. Upon completion of the distribution, substantially all of our assets will be represented by our limited partner interests, general partner interests and incentive distribution rights in ARP and Atlas Pipeline Partners, L.P. (“APL”). After completion of the distribution, we will become dependent principally upon the cash distributions from ARP and APL to grow, fund our operations, pay debt service or make distributions to our limited partners. Many of the risk factors set forth below with respect to our interests in APL, such as the impact of reduced distributions, ability to sell general partner interests and incentive distribution rights, as well as various tax risks, will equally apply to our ownership in ARP after we contribute the assets referenced above.

Risks Relating to Our Business

If commodity prices decline significantly, our cash flow from operations will decline.

Our revenue, profitability and cash flow substantially depend upon the prices and demand for natural gas and oil. The natural gas and oil markets are very volatile, and a drop in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices will have a significant impact on the value of our reserves and on our cash flow. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

   

the level of domestic and foreign supply and demand;

 

   

the price and level of foreign imports;

 

   

the level of consumer product demand;

 

   

weather conditions and fluctuating and seasonal demand;

 

   

overall domestic and global economic conditions;

 

   

political and economic conditions in natural gas and oil producing countries, including those in the Middle East and South America;

 

   

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

   

the impact of the U.S. dollar exchange rates on natural gas and oil prices;

 

   

technological advances affecting energy consumption;

 

   

domestic and foreign governmental relations, regulations and taxation;

 

   

the impact of energy conservation efforts;

 

22


   

the cost, proximity and capacity of natural gas pipelines and other transportation facilities; and

 

   

the price and availability of alternative fuels.

In the past, the prices of natural gas and oil have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2011, the NYMEX Henry Hub natural gas index price ranged from a high of $4.85 per MMBtu to a low of $2.99 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $113.93 per Bbl to a low of $75.67 per Bbl. Between January 1, 2012 and February 17, 2012, the NYMEX Henry Hub natural gas index price ranged from a high of $3.10 per MMBtu to a low of $2.32 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $103.24 per Bbl to a low of $96.36 per Bbl.

Competition in the natural gas and oil industry is intense, which may hinder our ability to acquire natural gas and oil properties and companies and to obtain capital, contract for drilling equipment and secure trained personnel.

We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through our investment partnerships, contracting for drilling equipment and securing trained personnel. Our competitors may be able to pay more for natural gas and oil properties and drilling equipment and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Moreover, our competitors for investment capital may have better track records in their programs, lower costs or stronger relationships with participants in the oil and gas investment community than we do. All of these challenges could make it more difficult for us to execute our growth strategy. We may not be able to compete successfully in the future in acquiring leasehold acreage or prospective reserves or in raising additional capital.

Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling natural gas and oil. Many of our competitors possess greater financial and other resources than we do, which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we can.

Shortages of drilling rigs, equipment and crews, or the costs required to obtain the foregoing in a highly competitive environment, could impair our operations and results.

Increased demand for drilling rigs, equipment and crews, due to increased activity by participants in our primary operating areas or otherwise, can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues.

Many of our leases are in areas that have been partially depleted or drained by offset wells.

Our key project areas are located in active drilling areas in the Appalachian Basin, and many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas.

Our operations require substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our asset base will decline, which could cause our revenues to decline and affect our ability to pay distributions.

The natural gas and oil industry is capital intensive. If we are unable to obtain sufficient capital funds on satisfactory terms with capital raised through equity and debt offerings, cash flow from operations, bank borrowings and the investment partnerships, we may be unable to increase or maintain our inventory of properties and reserve base, or be forced to curtail drilling or other activities. This could cause our revenues to decline and diminish our ability to service any debt that we may have at such time. If we do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we will be unable to expand our business operations, and may not generate sufficient revenue or have sufficient available cash to pay distributions on our units.

 

23


Our cash distribution policy limits our ability to grow.

Consistent with the terms of our partnership agreement, we distribute to our partners our available cash each quarter. In determining the amount of cash available for distribution, we each set aside cash reserves, including reserves we believe prudent to maintain for the proper conduct of our businesses or to provide for future distributions. Accordingly, to the extent we do not have sufficient cash reserves or are unable to finance growth externally, our cash distribution policies will significantly impair our ability to grow. In addition, to the extent either of us issue additional units or incur additional debt in connection with any acquisitions or capital expenditures, the payment of distributions on those additional common units may increase the risk that we will be unable to maintain our or increase our prior per common unit distribution level. Moreover, the incurrence of additional debt to finance our growth strategy would result in increased interest expense, which in turn, may impact the cash we have available to distribute to our unitholders.

We may not have sufficient cash to pay distributions.

Our ability to fund our operations, pay debt service and to make distributions to our unitholders may fluctuate based on the level of distribution APL makes to its partners and the cash flows generated by our assets.

Our ability to distribute cash to our unitholders will be limited by a number of factors, including:

 

   

interest expense and principal payments on any current or future indebtedness;

 

   

restrictions on distributions contained in any current or future debt agreements;

 

   

our general and administrative expenses, including expenses we incur as a result of being a public company;

 

   

expenses of our subsidiaries other than APL, including tax liabilities of our corporate subsidiaries, if any;

 

   

reserves necessary for us to make the necessary capital contributions to maintain our 2.0% general partner interest in APL as required by its partnership agreement upon the issuance of additional partnership securities by APL; and

 

   

reserves our general partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

We cannot guarantee that in the future we will be able to pay distributions or that any distribution we make will be at or above our previous quarterly distribution levels. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner.

We may issue an unlimited number of limited partner interests without the consent of our unitholders, which will dilute existing limited partners’ ownership interest in us and may increase the risk that we will not have sufficient available cash to make distributions.

We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders on terms and conditions established by our general partner at any time. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

   

our unitholders’ proportionate ownership interest in us will decrease;

 

   

the amount of cash available for distribution on each unit may decrease;

 

   

the relative voting strength of each previously outstanding unit may be diminished;

 

   

the ratio of taxable income to distributions may increase; and

 

   

the market price of the common units may decline.

Our ability to sell our general partner interest and incentive distribution rights in APL is limited.

We face contractual limitations on our ability to sell our general partner interest and incentive distribution rights in APL and the market for such interests is illiquid.

 

24


Our ability to meet our future financial needs may be adversely affected by our cash distribution policy.

Our cash distribution policy, which is consistent with our partnership agreement, requires us to distribute all of our available cash quarterly. Given that our cash distribution policy is to distribute available cash and not retain it, we may not have enough cash to meet our needs if any of the following events occur:

 

   

an increase in our operating expenses;

 

   

an increase in general and administrative expenses;

 

   

an increase in principal and interest payments on our outstanding debt; or

 

   

an increase in working capital requirements.

There is no guarantee that our unitholders will receive quarterly distributions from us.

While our cash distribution policy, which is consistent with the terms of our partnership agreement, requires that we distribute all of our available cash quarterly, our cash distribution policy is subject to the following restrictions and limitations and may be changed at any time, including in the following ways:

 

   

We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including increases in our general and administrative expenses, principal or interest payments on our current and future outstanding debt, elimination of future distributions from APL, the effect of the IDR Adjustment Agreement, working capital requirements and anticipated cash needs of us or APL and its subsidiaries;

 

   

Our cash distribution policy is, and APL’s cash distribution policy is, subject to restrictions on distributions under our credit facility and APL’s credit facility, respectively, such as material financial tests and covenants and limitations on paying distributions during an event of default;

 

   

Our general partner’s board of directors has the authority under our partnership agreement to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders. The establishment of those reserves could result in a reduction in future cash distributions to our unitholders pursuant to our stated cash distribution policy;

 

   

Our partnership agreement, including the cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our common units;

 

   

Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement; and

 

   

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

Because of these restrictions and limitations on our cash distribution policy and our ability to change our cash distribution policy, we may not have available cash to distribute to our unitholders, and there is no guarantee that our unitholders will receive quarterly distributions from us.

Covenants in our credit facility restrict our business in many ways.

Our credit facility contains various restrictive covenants that limit our ability to, among other things:

 

   

incur additional debt or liens or provide guarantees in respect of obligations of other persons;

 

   

pay distributions or redeem or repurchase our securities;

 

   

prepay, redeem or repurchase debt;

 

   

make loans, investments and acquisitions;

 

25


   

enter into hedging arrangements;

 

   

sell assets;

 

   

enter into certain transactions with affiliates; and

 

   

consolidate or merge with or into, or sell substantially all of our assets to, another person.

In addition, our credit facility requires us to maintain specified financial ratios. Our ability to meet those financial ratios can be affected by events beyond our control, and we may be unable to meet those tests. A breach of any of these covenants could result in a default under our credit facility. Upon the occurrence of an event of default under our credit facility, the lenders could elect to declare all amounts outstanding immediately due and payable and terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness. We have pledged a significant portion of our assets as collateral under our credit facility. If the lenders under our credit facility accelerate the repayment of borrowings, we may not have sufficient assets to repay our credit facility and our other liabilities. Our borrowings under our credit facility are, and are expected to continue to be, at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.

We or one of our subsidiaries may be exposed to financial and other liabilities as the managing general partner in investment partnerships.

We or one of our subsidiaries serves as the managing general partner of the investment partnerships and will be the managing general partner of new investment partnerships that we sponsor. As a general partner, we or one of our subsidiaries will be contingently liable for the obligations of the partnerships to the extent that partnership assets or insurance proceeds are insufficient. We have agreed to indemnify each investor partner in the investment partnerships from any liability that exceeds such partner’s share of the investment partnership’s assets, and we or one of our subsidiaries are bound by this agreement after the sale of the Transferred Business.

Economic conditions and instability in the financial markets could negatively impact our and APL’s business which, in turn, could impact the cash we have to make distributions to our unitholders.

Our and APL’s operations are affected by the financial markets and related effects in the global financial system. The consequences of an economic recession and the effects of the financial crisis include a lower level of economic activity and increased volatility in energy prices. This may result in a decline in energy consumption and lower market prices for oil and natural gas and has previously resulted in a reduction in drilling activity in our and APL’s service areas and in wells currently connected to APL’s pipeline system being shut in by their operators until prices improved. Any of these events may adversely affect our and APL’s revenues and ability to fund capital expenditures and, in the future, may impact the cash that we have available to fund our operations, pay required debt service on our credit facility and make distributions to our unitholders.

Potential instability in the financial markets, as a result of recession or otherwise, can cause volatility in the markets and may affect our and APL’s ability to raise capital and reduce the amount of cash available to fund operations. We cannot be certain that additional capital will be available to us or APL to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively impact our and APL’s access to liquidity needed for our businesses and impact flexibility to react to changing economic and business conditions. We and APL may be unable to execute our growth strategies, take advantage of business opportunities or to respond to competitive pressures, any of which could negatively impact our business.

Economic situations could have an adverse impact on producers, key suppliers or other customers, or on our and APL’s lenders, causing them to fail to meet their obligations to APL. Market conditions could also impact our and APL’s derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our and APL’s cash flow and ability to pay distributions could be impacted which in turn affects the amount of distributions that we are able to make to our unitholders. The uncertainty and volatility surrounding the global financial system may have further impacts on our business and financial condition that we and APL currently cannot predict or anticipate.

 

26


Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate-related damages to our facilities or our costs of operation potentially rising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

We currently sell the majority of our natural gas production to a single customer. To the extent this customer reduces the volumes of natural gas it purchases from us, or ceases to purchase natural gas from us, upon the expiration of our existing sales contracts, our revenues could be negatively affected.

Certain of our subsidiaries sell gas produced in four key counties in southwest Pennsylvania to a subsidiary of Chevron Corporation pursuant to a gas marketing agreement with a term expiring in February 2014, and all of the gas produced by the wells in Michigan owned by the investment partnerships are marketed by a subsidiary of Chevron pursuant to an operating agreement between the parties. To the extent Chevron reduces the amount of natural gas it purchases from us upon the expiration of these contracts, or if the gas marketing agreement is terminated or the gas marketing services provided under the operating agreement are no longer provided, our revenues could be harmed in the event we are unable to sell to other purchasers at similar prices.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price that we receive for our production could significantly reduce our cash available for distribution and adversely affect our financial condition.

The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price that we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price that we receive could significantly reduce our cash available for distribution to our unitholders and adversely affect our financial condition. We use the relevant benchmark price to calculate our hedge positions, and we do not have or plan to have any commodity derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials, which could adversely affect our results of operations.

Some of our undeveloped leasehold acreage is subject to leases that may expire in the near future.

As of December 31, 2011, leases covering approximately 25,541 of our 286,533 net undeveloped acres, or 8.9%, are scheduled to expire on or before December 31, 2012. An additional 15% and 9% are scheduled to expire in the years 2013 and 2014, respectively. If we are unable to renew these leases or any leases scheduled for expiration beyond their expiration date, on favorable terms, we will lose the right to develop the acreage that is covered by an expired lease and our production would decline, which would reduce our cash flows from operations.

Drilling for and producing natural gas are high-risk activities with many uncertainties.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

   

the high cost, shortages or delivery delays of equipment and services;

 

   

unexpected operational events and drilling conditions;

 

   

adverse weather conditions;

 

27


   

facility or equipment malfunctions;

 

   

title problems;

 

   

pipeline ruptures or spills;

 

   

compliance with environmental and other governmental requirements;

 

   

unusual or unexpected geological formations;

 

   

formations with abnormal pressures;

 

   

injury or loss of life;

 

   

environmental accidents such as gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment or oil leaks, including groundwater contamination;

 

   

fires, blowouts, craterings and explosions; and

 

   

uncontrollable flows of natural gas or well fluids.

Any one or more of the factors discussed above could reduce or delay our receipt of drilling and production revenues, thereby reducing our earnings, and could reduce revenues in one or more of our investment partnerships, which may make it more difficult to finance our drilling operations through sponsorship of future partnerships. In addition, any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

Although we will maintain insurance against various losses and liabilities arising from our operations, insurance against all operational risks will not be available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could reduce our results of operations.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would reduce our cash flow from operations and income.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our reserves and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on our generating sufficient cash flow from operations and other sources of capital, principally from the sponsorship of new investment partnerships, all of which are subject to the risks discussed elsewhere in this section.

A decrease in natural gas prices could subject our oil and gas properties to a non-cash impairment loss under U.S. generally accepted accounting principles.

U.S. generally accepted accounting principles require oil and gas properties and other long-lived assets to be reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. We test our oil and gas properties on a field-by-field basis, by determining if the historical cost of proved properties less the applicable depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on our economic interests and our plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. We estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published future prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. Accordingly, further declines in the

 

28


price of natural gas may cause the carrying value of our oil and gas properties to exceed the expected future cash flows, and a non-cash impairment loss would be required to be recognized in the financial statements for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

Hedging transactions may limit our potential gains or cause us to lose money.

Pricing for natural gas and oil has been volatile and unpredictable for many years. To limit exposure to changing natural gas and oil prices, we use financial and physical hedges for our production. Physical hedges are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We generally limit these arrangements to smaller quantities than those projected to be available at any delivery point.

In addition, we may enter into financial hedges, which may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to six years in the future.

These hedging arrangements may reduce, but will not eliminate, the potential effects of changing commodity prices on our cash flow from operations for the periods covered by this hedging arrangement. Furthermore, while intended to help reduce the effects of volatile commodity prices, such transactions, depending on the hedging instrument used, may limit our potential gains if commodity prices were to rise substantially over the price established by the hedge. If, among other circumstances, production is substantially less than expected, the counterparties to our futures contracts fail to perform under the contracts or a sudden, unexpected event materially changes commodity prices, we may be exposed to the risk of financial loss. In addition, it is not always possible for us to engage in a derivative transaction that completely mitigates our exposure to commodity prices and interest rates. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which we are unable to enter into a completely effective hedge transaction.

Due to the accounting treatment of derivative contracts, increases in prices for natural gas, crude oil and NGLs could result in non-cash balance sheet reductions and non-cash losses in our statement of operations.

With the objective of enhancing the predictability of future revenues, from time to time we and APL enter into natural gas, natural gas liquids and crude oil derivative contracts. We and APL account for these derivative contracts by applying the mark-to-market accounting treatment required for these derivative contracts. We and APL could recognize incremental derivative liabilities between reporting periods resulting from increases or decreases in reference prices for natural gas, crude oil and NGLs, which could result in us recognizing a non-cash loss in our consolidated combined statements of operations and a consequent non-cash decrease in our equity between reporting periods. Any such decrease could be substantial. In addition, we or APL may be required to make cash payments upon the termination of any of these derivative contracts.

Regulations promulgated by the Commodities Futures Trading Commission could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our and APL’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our and APL’s business. The Dodd-Frank Wall Street Reform and Consumer Protection Act, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new legislation. The CFTC finalized its regulations and has set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The financial reform legislation may also require us and APL to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our and APL’s existing or future derivative activities, although the application of those provisions to us and APL is uncertain at this time. The financial reform legislation may also require the counterparties to our and APL’s derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts; materially alter the terms of derivative contracts; reduce the availability of derivatives to protect against risks we and APL encounter; reduce our and APL’s ability to monetize or restructure our and APL’s derivative contracts in existence at that time; and increase our and APL’s exposure to less creditworthy counterparties. If we and APL reduce or change the way we use derivative instruments as a result of the legislation or regulations, our and APL’s results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our and APL’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments

 

29


related to oil and natural gas. Our and APL’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our and APL’s consolidated financial position, results of operations and/or cash flows.

The scope and costs of the risks involved in making acquisitions may prove greater than estimated at the time of the acquisition.

Any acquisition involves potential risks, including, among other things:

 

   

mistaken assumptions about revenues and costs, including synergies;

 

   

significant increases in our indebtedness and working capital requirements;

 

   

an inability to integrate successfully or timely the businesses we acquire;

 

   

the assumption of unknown liabilities;

 

   

limitations on rights to indemnity from the seller;

 

   

the diversion of management’s attention from other business concerns;

 

   

increased demands on existing personnel;

 

   

customer or key employee losses at the acquired businesses; and

 

   

the failure to realize expected growth or profitability.

The scope and cost of these risks may be materially greater than estimated at the time of the acquisition. Any of these factors could adversely affect our future growth.

We may be unsuccessful in integrating the operations from any future acquisitions with our operations and in realizing all of the anticipated benefits of these acquisitions.

The integration of previously independent operations can be a complex, costly and time-consuming process. The difficulties of combining these systems, as well as any operations we may acquire in the future, include, among other things:

 

   

operating a significantly larger combined entity;

 

   

the necessity of coordinating geographically disparate organizations, systems and facilities;

 

   

integrating personnel with diverse business backgrounds and organizational cultures;

 

   

consolidating operational and administrative functions;

 

   

integrating internal controls, compliance under Sarbanes-Oxley Act of 2002 and other corporate governance matters;

 

   

the diversion of management’s attention from other business concerns;

 

   

customer or key employee loss from the acquired businesses;

 

   

a significant increase in our indebtedness; and

 

   

potential environmental or regulatory liabilities and title problems.

 

30


Costs incurred and liabilities assumed in connection with an acquisition and increased capital expenditures and overhead costs incurred to expand our operations could harm our business or future prospects, and result in significant decreases in our gross margin and cash flows.

Properties that we acquire may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

One of our growth strategies is to capitalize on opportunistic acquisitions of natural gas reserves. However, reviews of acquired properties are often incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. A detailed review of records and properties also may not necessarily reveal existing or potential problems, and may not permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively affect our financial condition and results of operations.

Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable and may be limited by floors and caps on such indemnity.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions or by state environmental agencies.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has imposed a de facto moratorium on the issuance of permits for high volume, horizontal hydraulic fracturing until state administered environmental studies are finalized. Public hearings on the studies and proposed regulations were held in November 2011, with the public comment period for the proposed regulations closing in January 2012. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. In February 2012, legislation was passed in Pennsylvania requiring, among other things, disclosure of chemicals used in hydraulic fracturing. Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (RCT) and the public of certain information regarding the components used in the hydraulic fracturing process. In December 2011, West Virginia enacted legislation imposing more stringent regulation of horizontal drilling. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. If state, local, or municipal legal restrictions are adopted in areas where we and our subsidiaries are currently conducting, or in the future plan to conduct, operations, we and our subsidiaries may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

Although the process is not generally subject to regulation at the federal level, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices, and some federal regulation has taken place. The Environmental Protection Agency, or EPA, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel as an additive under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation that would provide for federal regulation of hydraulic fracturing and require disclosure of the chemicals used in the hydraulic fracturing process could be introduced in the future. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.

 

31


Certain members of U.S. Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could result in initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or one or more other regulatory mechanisms. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us and our subsidiaries to perform hydraulic fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our and our subsidiaries’ ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our and our subsidiaries’ fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we and our subsidiaries are ultimately able to produce from our respective reserves.

Recently proposed rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs.

On July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (VOCs) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. Final regulations are anticipated in the spring of 2012. Once finalized, these rules will likely require a number of modifications to our and our subsidiaries’ operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our and our subsidiaries’ businesses.

In addition, both houses of U.S. Congress have actively considered legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved. The adoption of any legislation or regulations that requires reporting of greenhouse gases or otherwise limits emissions of greenhouse gases from our and our subsidiaries’ equipment and operations could require us and our subsidiaries to incur costs to monitor and report on greenhouse gas emissions or reduce emissions of greenhouse gases associated with our and our subsidiaries’ operations, and such requirements also could adversely affect demand for the oil and natural gas that we and our subsidiaries produce.

Climate change legislation or regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for our and our subsidiaries’ services.

In response to findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that require entities that produce certain gases to inventory, monitor and report such gases. On November 30, 2010, the EPA published a final GHG emissions reporting rule relating to natural gas processing, transmission, storage, and distribution activities, which requires reporting beginning in 2012 for emissions occurring in 2011. Additionally, in 2010, EPA issued rules to regulate GHG emissions through traditional major source construction and operating permit programs. These permitting programs require consideration of and, if deemed necessary, implementation of best available control technology to reduce GHG emissions. As a result, our and our subsidiaries’ operations could face additional costs for emissions control and higher costs of doing business.

 

32


The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulation. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.

Our and our subsidiaries’ drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of that water. If we and our subsidiaries are unable to dispose of the water we and our subsidiaries use or remove from the strata at a reasonable cost and within applicable environmental rules, our and our subsidiaries’ ability to produce gas commercially and in commercial quantities could be impaired.

A significant portion of our and our subsidiaries’ natural gas extraction activity will utilize hydraulic fracturing, which results in water that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our and our subsidiaries’ operations and financial performance. Our and our subsidiaries’ ability to collect and dispose of water will affect our and our subsidiaries’ production, and the cost of water treatment and disposal may affect our and our subsidiaries’ profitability. The imposition of new environmental initiatives and regulations could include restrictions on our and our subsidiaries’ ability to conduct hydraulic fracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of gas and oil.

A severance tax or impact fee in Pennsylvania could materially increase our liabilities.

While Pennsylvania has historically not imposed a severance tax (relating to the extraction of natural gas), with a focus on its budget deficit and the increasing exploration of the Marcellus Shale, various legislation has been proposed since 2008. In February 2012, Pennsylvania implemented an impact fee. This new law imposes an impact fee on all unconventional wells drilled in the Commonwealth of Pennsylvania in counties that elect to impose the fee. The fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. Based upon natural gas prices for 2011, operators will pay $50,000 per unconventional horizontal well. Unconventional vertical wells will pay a fee equal to twenty percent of the horizontal well fee and the impact fee will not apply to any unconventional vertical well that produces less than 90mcf per day. The payment structure for the impact fee makes the fee due the year after an unconventional well is spudded and the fee will continue for 15 years for a horizontal well and 10 years for a vertical well.

Because we and our subsidiaries handle natural gas and oil, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

The operations of our and our subsidiaries’ wells and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

 

   

the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

 

   

the federal Clean Water Act and comparable state laws and regulations that impose obligations related to spills, releases, streams, wetlands and discharges of pollutants into regulated bodies of water;

 

   

the federal Resource Conservation and Recovery Act (which we refer to as “RCRA”) and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from our and our subsidiaries’ facilities; and

 

   

the federal Comprehensive Environmental Response, Compensation, and Liability Act (which we refer to as “CERCLA”) and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us, our subsidiaries and Atlas Energy, Inc. (“AEI”) or at locations to which we, our subsidiaries and AEI have sent waste for disposal.

 

33


Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Certain environmental statutes, including RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

There is an inherent risk that we and our subsidiaries may incur environmental costs and liabilities due to the nature of our and our subsidiaries’ businesses and the substances we and our subsidiaries handle. For example, an accidental release from one of our or our subsidiaries’ wells could subject us or the applicable subsidiary to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our and our subsidiaries’ compliance costs and the cost of any remediation that may become necessary. We or the applicable subsidiary may not be able to recover remediation costs under our respective insurance policies.

We and our subsidiaries are subject to comprehensive federal, state, local and other laws and regulations that could increase the cost and alter the manner or feasibility of us doing business.

Our and our subsidiaries’ operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells. Under these laws and regulations, we and our subsidiaries could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our or our subsidiaries’ operations and subject us and our subsidiaries to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we and our subsidiaries operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our and our subsidiaries’ activities will be subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our and our subsidiaries’ operations and limit the quantity of natural gas we and our subsidiaries may produce and sell. A major risk inherent in our and our subsidiaries’ drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our and our subsidiaries’ ability to develop our respective properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, reduce our and our subsidiaries’ profitability. For example, Pennsylvania’s General Assembly approved legislation in February 2012 that would impose significant, costly requirements on the natural gas industry, including the imposition of increased bonding requirements and impact fees for gas wells, based on the price of natural gas and the age of the well. Furthermore, we and our subsidiaries may be put at a competitive disadvantage to larger companies in our industry who can spread these additional costs over a greater number of wells and larger operating staff.

We may not be able to continue to raise funds through our investment partnerships at desired levels, which may in turn restrict our ability to maintain our drilling activity at recent levels.

We have sponsored limited and general partnerships to finance certain of our development drilling activities. Accordingly, the amount of development activities that we will undertake depends in large part upon our ability to obtain investor subscriptions to invest in these partnerships. We have raised $141.9 million, $149.3 million and $353.4 million in calendar years 2011, 2010 and 2009, respectively. In the future, we may not be successful in raising funds through these investment partnerships at the same levels that we experienced, and we also may not be successful in increasing the amount of funds we raise. Our ability to raise funds through our investment partnerships depends in large part upon the perception of investors of their potential return on their investment and their tax benefits from investing in them, which perception is influenced significantly by our historical track record of generating returns and tax benefits to the investors in our existing partnerships.

 

34


In the event that our investment partnerships do not achieve satisfactory returns on investment or the anticipated tax benefits, we may have difficulty in maintaining or increasing the level of investment partnership fundraising relative to the levels achieved by us. In this event, we may need to seek financing for our drilling activities through alternative methods, which may not be available, or which may be available only on a less attractive basis than the financing we realized through these investment partnerships, or we may determine to reduce drilling activity.

Changes in tax laws may impair our ability to obtain capital funds through investment partnerships.

Under current federal tax laws, there are tax benefits to investing in investment partnerships, including deductions for intangible drilling costs and depletion deductions. However, the current administration has proposed, among other tax changes, the repeal of certain oil and gas tax benefits, including the repeal of the percentage depletion allowance, the election to expense intangible drilling costs, the passive activity exception for working interests and the marginal production tax credit. These proposals may or may not be adopted. The repeal of these oil and gas tax benefits, if it happens, would result in a substantial decrease in tax benefits associated with an investment in our investment partnerships. These or other changes to federal tax law may make investment in our investment partnerships less attractive and, thus, reduce our ability to obtain funding from this significant source of capital funds.

Fee-based revenues may decline if we are unsuccessful in sponsoring new investment partnerships.

Our fee-based revenues will be based on the number of investment partnerships we sponsor and the number of partnerships and wells we manage or operate. If we are unsuccessful in sponsoring future investment partnerships, our fee-based revenues may decline.

Our revenues may decrease if investors in our investment partnerships do not receive a minimum return.

We have agreed to subordinate up to 50% of our share of production revenues, net of corresponding production costs, to specified returns to the investor partners in our investment partnerships, typically 10% per year for the first five years of distributions, and we are bound by this agreement following the sale of the Transferred Business. Our revenues from a particular investment partnership will therefore decrease if the investment partnership does not achieve the specified minimum return. For the years ended December 31, 2011, 2010 and 2009, $4.0 million, $10.9 million and $3.9 million, respectively, of our revenues, net of corresponding production costs, were subordinated, which reduced our cash distributions received from the investment partnerships.

Certain of our officers and directors are subject to non-competition agreements that may effectively restrict our ability to expand our business in the Marcellus Shale.

Edward Cohen, who serves as our Chief Executive Officer, and Jonathan Cohen, who serves as our Chairman of the board of our general partner, are each parties to a non-competition and non-solicitation agreement with Chevron Corporation. These agreements restrict each such individual, until February 17, 2014, from engaging in any capacity (whether as officer, director, owner, partner, stockholder, investor, consultant, principal, agent, employee, coventurer or otherwise) in a business engaged in the exploration, development or production of hydrocarbons in certain designated counties within the States of Pennsylvania, West Virginia and New York, and from engaging in certain solicitation activities with respect to oil and gas leases, customers, suppliers and contractors of AEI. The foregoing restrictions are subject to certain limited exceptions, including exceptions permitting Jonathan Cohen and Edward Cohen in certain circumstances to engage in the businesses conducted by us (including with respect to the operation of the assets we acquired from AEI in February 2011) and APL. The non-competition agreements also prohibit Edward Cohen and Jonathan Cohen, until February 17, 2013, from soliciting for employment, or hiring, any person who was employed by AEI before its merger with Chevron and became an employee of AEI or Chevron after the merger, subject to certain limited exceptions.

Therefore, our ability to expand our business in the Marcellus Shale may be limited.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and

 

35


operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

Estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our engineers prepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we will make certain assumptions regarding future natural gas prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Our PV-10 and standardized measure are calculated using natural gas prices that include our physical hedges but not our financial hedges. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we ultimately recover being different from our reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on historical prices and costs. However, actual future net cash flows from our natural gas properties also will be affected by factors such as:

 

   

actual prices we receive for natural gas;

 

   

the amount and timing of actual production;

 

   

the amount and timing of our capital expenditures;

 

   

supply of and demand for natural gas; and

 

   

changes in governmental regulations or taxation.

The timing of both our production and incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Any significant variance in our assumptions could materially affect the quantity and value of reserves, the amount of PV-10 and standardized measure, and our financial condition and results of operations. In addition, our reserves or PV-10 and standardized measure may be revised downward or upward based upon production history, results of future exploitation and development activities, prevailing natural gas and oil prices and other factors. A material decline in prices paid for our production can reduce the estimated volumes of our reserves because the economic life of our wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our PV-10 and standardized measure.

 

36


Certain provisions of our limited partnership agreement and Delaware law could deter acquisition proposals and make it difficult for a third party to acquire control of us. This could have a negative effect on the price of our common units.

Our limited partnership agreement contains provisions that are intended to deter coercive takeover practices and inadequate takeover bids and to encourage prospective acquirers to negotiate with our board of directors rather than to attempt a hostile takeover. These provisions include:

 

   

a board of directors that is divided into three classes with staggered terms;

 

   

rules regarding how our common unitholders may present proposals or nominate directors for election;

 

   

rules regarding how our common unitholders may call special meetings; and

 

   

limitations on the right of our common unitholders to remove directors.

These provisions are intended to protect our common unitholders from coercive or otherwise unfair takeover tactics by requiring potential acquirers to negotiate with our board of directors and by providing our board of directors with more time to assess any acquisition proposal. These provisions are not intended to make us immune from takeovers. However, these provisions will apply even if an offer may be considered beneficial by some of our unitholders and could delay or prevent an acquisition that our board of directors determines is in our best interest and that of our unitholders. Any of the foregoing provisions could limit the price that some investors might be willing to pay for our common units.

APL may issue additional units, which may increase the risk of not having sufficient available cash to make distributions at prior per unit distribution levels.

APL has wide discretion to issue additional limited partner units, including units that rank senior to its common units and the incentive distribution rights as to quarterly cash distributions, on the terms and conditions established by its general partner. The payment of distributions on additional APL common units may increase the risk of APL being unable to make distributions at its prior per unit distribution levels. To the extent new APL limited partner units are senior to the APL common units and the incentive distribution rights, their issuance will increase the uncertainty of the payment of distributions on the common units and the incentive distribution rights. Neither the common units nor the incentive distribution rights are entitled to any arrearages from prior quarters.

Reduced incentive distributions from APL will disproportionately affect the amount of cash distributions to which we are entitled.

We are entitled to receive incentive distributions from APL, through our ownership of Atlas Pipeline GP, with respect to any particular quarter only if APL distributes more than $0.42 per common unit for such quarter. Atlas Pipeline GP agreed to allocate up to $3.75 million of incentive distributions per quarter back to APL.

Atlas Pipeline GP’s incentive distribution rights entitle it to receive percentages increasing up to 48% of all cash distributed by APL, subject to the IDR Adjustment Agreement. Distribution by APL above $0.60 per common unit per quarter would result in Atlas Pipeline GP’s incremental cash distributions to be the maximum 48%. Atlas Pipeline GP’s percentage of the incremental cash distributions reduces from 48% to 23% if APL’s distribution is between $0.52 and $0.59, and to 13% if APL’s distribution is between $0.43 and $0.51, subject in both cases to the effect of the IDR Adjustment Agreement. As a result, lower quarterly cash distributions from APL have the effect of disproportionately reducing the amount of all incentive distributions that Atlas Pipeline GP receives as compared to cash distributions Atlas Pipeline GP receives on its 2.0% general partner interest in APL.

We, as the parent of APL’s general partner, may limit or modify the incentive distributions we are entitled to receive from APL in order to facilitate the growth strategy of APL. Our general partner’s board of directors can give this consent without a vote of our unitholders.

We own APL’s general partner, which owns the incentive distribution rights in APL that entitle us to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per common unit in any quarter. APL’s board of directors may reduce the incentive distribution rights payable to us without our consent, which we may provide without the approval of our unitholders. In July 2007, in connection with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems, Atlas Pipeline GP agreed to allocate up to $3.75 million of incentive distribution rights per quarter back to APL after it receives the initial $7.0 million per quarter of incentive distribution rights.

 

37


In order to facilitate acquisitions by APL, the general partner of APL may elect to limit the incentive distributions we are entitled to receive with respect to a particular acquisition or unit issuance contemplated by APL. This is because a potential acquisition might not be accretive to APL’s common unitholders as a result of the significant portion of that acquisition’s cash flows which would be paid as incentive distributions to us. By limiting the level of incentive distributions in connection with a particular acquisition or issuance of units of APL, the cash flows associated with that acquisition could be accretive to APL’s common unitholders as well as substantially beneficial to us. In doing so, the managing board of APL’s general partner would be required to consider both its fiduciary obligations to investors in APL as well as to us. Our partnership agreement specifically permits our general partner to authorize the general partner of APL to limit or modify the incentive distribution rights held by us if our general partner determines that such limitation or modification does not adversely affect our limited partners in any material respect.

APL’s common unitholders have the right to remove APL’s general partner with the approval of the holders of 66 2/3% of all units, which would cause us to lose our general partner interest and incentive distribution rights in APL and the ability to manage APL.

We currently manage APL through Atlas Pipeline GP, APL’s general partner and our wholly-owned subsidiary. APL’s partnership agreement, however, gives common unitholders of APL the right to remove the general partner of APL upon the affirmative vote of holders of 66 2/3% of APL’s outstanding common units. If Atlas Pipeline GP were removed as general partner of APL, it would receive cash or common units in exchange for its 2.0% general partner interest and the incentive distribution rights and would lose ability to manage APL. While the common units or cash we would receive are intended under the terms of APL’s partnership agreement to fully compensate us in the event such an exchange is required, the value of these common units or investments we make with the cash over time may not be equivalent to the value of the general partner interest and the incentive distribution rights had we retained them.

If APL’s general partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of APL, its value, and therefore the value of our common units, could decline.

The general partner of APL may make expenditures on behalf of APL for which it will seek reimbursement from APL. In addition, under Delaware partnership law, APL’s general partner, in its capacity, has unlimited liability for the obligations of APL, such as its debts and environmental liabilities, except for those contractual obligations of APL that are expressly made without recourse to the general partner. To the extent Atlas Pipeline GP incurs obligations on behalf of APL, it is entitled to be reimbursed or indemnified by APL. If APL is unable or unwilling to reimburse or indemnify its general partner, Atlas Pipeline GP may be unable to satisfy these liabilities or obligations, which would reduce its value and therefore the value of our common units.

If in the future we cease to manage and control APL through our ownership of its general partner interests, we may be deemed to be an investment company.

If we cease to manage and control APL and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

Risks Relating to the Ownership of Our Common Units

If the unit price declines, our common unitholders could lose a significant part of their investment.

The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

 

   

changes in securities analysts’ recommendations and their estimates of our financial performance;

 

   

the public’s reaction to our or APL’s press releases, announcements and our filings with the SEC;

 

   

fluctuations in broader securities market prices and volumes, particularly among securities of natural gas and oil companies and securities of publicly traded limited partnerships and limited liability companies;

 

38


   

changes in market valuations of similar companies;

 

   

departures of key personnel;

 

   

commencement of or involvement in litigation;

 

   

variations in our quarterly results of operations or those of other natural gas and oil companies;

 

   

variations in the amount of our quarterly cash distributions;

 

   

future issuances and sales of our units; and

 

   

changes in general conditions in the U.S. economy, financial markets or the natural gas and oil industry.

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

Increases in interest rates could adversely affect our unit price.

Credit markets recently have experienced record lows in interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our and APL’s financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our and APL’s cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units. A rising interest rate environment could have an adverse impact on our unit price and our and APL’s ability to issue additional equity or to incur debt to make acquisitions or for other purposes and could impact our and APL’s ability to make cash distributions at our and APL’s intended levels.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.

The amount of cash that we have available for distribution depends primarily on our cash flow, including cash reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income.

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Unitholders could be liable for any and all of our obligations as it they were a general partner if, among other potential reasons:

 

   

a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

 

   

a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them, or other liabilities with respect to ownership of our units.

 

39


Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement.

Risks Related to Our Conflicts of Interest

Although we control APL through our ownership of its general partner, APL’s general partner owes fiduciary duties to APL and APL’s unitholders, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including APL’s general partner, on the one hand, and APL and its limited partners, on the other hand. The directors and officers of Atlas Pipeline GP have fiduciary duties to manage APL in a manner beneficial to us, its owner. At the same time, these directors and officers have a fiduciary duty to manage APL in a manner beneficial to APL and its limited partners. The managing board of APL or its conflicts committee will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

For example, conflicts of interest may arise in the following situations:

 

   

the allocation of shared overhead expenses to APL and us;

 

   

the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and APL, on the other hand;

 

   

the determination and timing of the amount of cash to be distributed to APL’s partners and the amount of cash reserved for the future conduct of APL’s business;

 

   

the decision as to whether APL should make acquisitions, and on what terms; and

 

   

any decision we make in the future to engage in business activities independent of, or in competition with, APL.

The fiduciary duties of our general partner’s officers and directors may conflict with those of APL’s general partner’s officers and directors.

Our general partner’s officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. However, certain of our general partner’s executive officers and non-independent directors also serve as executive officers and directors of APL’s general partner, and, as a result, have fiduciary duties to manage the business of APL in a manner beneficial to APL and its partners. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to APL, on one hand, and us, on the other hand, are in conflict. The resolution of these conflicts of interest may not always be in our best interest or that of our unitholders.

If we are presented with certain business opportunities, APL will have the first right to pursue such opportunities.

Pursuant to the omnibus agreement between us and APL, we have agreed to certain business opportunity arrangements to address potential conflicts that may arise between us and APL. If a business opportunity in respect of any business activity in which APL is currently engaged is presented to us or APL, then APL will have the first right to pursue such business opportunity.

APL and affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

 

40


Neither our partnership agreement nor the omnibus agreement between us and APL prohibits APL or affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us or one another. In addition, APL and its affiliates may acquire, construct or dispose of additional assets related to the gathering and processing of natural gas, NGLs or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. As a result, competition among these entities could adversely impact APL’s or our results of operations and cash available for paying required debt service on our credit facility or making distributions.

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the IRS were to treat us as a corporation for U.S. federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.

The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to them. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore result in a substantial reduction in the value of our common units.

Current law or our business may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to unitholders would be reduced.

Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.

Unitholders will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on its share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in APL.

Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in APL. Other holders of common units in APL will receive remedial allocations of deductions from APL. Although we will receive remedial allocations of deductions from APL, remedial allocations of deductions to us will be very limited. In addition, our ownership of APL incentive distribution rights will cause more taxable income to be allocated to us from APL than will be allocated to holders who hold only common units in APL. If APL is successful in increasing its distributions over time, our income allocations from our APL incentive distribution rights will increase, and, therefore, our ratio of taxable income to cash distributions will increase. Because our ratio of taxable income to cash distributions will be greater than the ratio applicable to holders of common units in APL, our unitholders’ allocable taxable income will be significantly greater than that of a holder of common units in APL who receives cash distributions from APL equal to the cash distributions our unitholders would receive from us.

Tax gain or loss on disposition of our common units could be more or less than expected.

If a unitholder sells their common units, they will recognize a gain or loss equal to the difference between the amount realized and the adjusted tax basis in those common units. Prior distributions and the allocation of losses, including depreciation deductions, to the unitholder in excess of the total net taxable income allocated to them, which decreased the tax basis in their common units, will, in effect, become taxable income to them if the common units are sold at a price greater than their tax basis in those common units, even if the price is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the unitholder.

 

41


Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

A successful IRS contest of the U.S. federal income tax positions we take may harm the market for our common units, and the costs of any contest will reduce cash available for distribution.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may disagree with some or all of those positions. Any contest with the IRS may lower the price at which our common units trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

We treat each holder of our common units as having the same tax benefits without regard to the common units held. The IRS may challenge this treatment, which could reduce the value of the common units.

Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of existing U.S. Treasury regulations. A successful IRS challenge to those positions could reduce the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.

The sale or exchange of 50% or more of our or APL’s capital and profits interest within a 12-month period will result in the termination of our or APL’s partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in our capital and profits within a 12-month period. Likewise, APL will be considered to have terminated its partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in APL’s capital and profits within a 12-month period. The termination would, among other things, result in the closing of our or APL’s taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. Thus, if this occurs, the unitholder will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to the unitholder with respect to that period.

Tax gain or loss on the disposition of our common units could be more or less than expected because prior distributions in excess of allocations of income will decrease unitholders’ tax basis in their units.

If unitholders sell any of their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions to them in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that unit, will, in effect, become taxable income to them if the unit is sold at a price greater than their tax basis in that unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to them. In addition, a unitholder may incur a tax liability in excess of the amount of cash it receives from the sale.

Unitholders may be subject to state and local taxes and return filing requirements as a result of investing in our common units.

In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or APL do business or own property now or in the future, even if our unitholders do not reside in any of those

 

42


jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We and APL presently anticipate that substantially all of our income will be generated in Oklahoma, Pennsylvania and Texas. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all U.S. federal, foreign, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

The IRS may challenge our tax treatment related to transfers of units, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. If the IRS were to challenge this method or new U.S. Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

APL has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and the public unitholders of APL. The IRS may challenge this treatment, which could adversely affect the value of APL’s common units and our common units.

When we or APL issue additional units or engage in certain other transactions, APL determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of APL’s unitholders and us. Although APL may from time to time consult with professional appraisers regarding valuation matters, including the valuation of its assets, APL makes many of the fair market value estimates of its assets itself using a methodology based on the market value of its common units as a means to measure the fair market value of its assets. APL’s methodology may be viewed as understating the value of APL’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain APL unitholders and us, which may be unfavorable to such APL unitholders. Moreover, under APL’s current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to APL’s tangible assets and a lesser portion allocated to APL’s intangible assets. The IRS may challenge APL’s valuation methods, or our or APL’s allocation of Section 743(b) adjustment attributable to APL’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of APL’s unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain on the sale of common units by our unitholders and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of our unitholders without the benefit of additional deductions.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

 

ITEM 1B: UNRESOLVED STAFF COMMENTS

None.

 

43


ITEM 2: PROPERTIES

Natural Gas and Oil Reserves

The following tables summarize information regarding our estimated proved natural gas and oil reserves as of December 31, 2011. In accordance with prevailing accounting literature, we determined that the acquisition of the Transferred Business constituted a transaction between entities under common control, and as such, we retrospectively adjusted prior year amounts within the tables below (See “Item 1: Business – General”). Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our direct ownership interests in oil and gas properties as well as the reserves attributable to our percentage interests in the oil and gas properties owned by investment partnerships in which we own partnership interests. All of the reserves are located in the United States. We base these estimated proved natural gas and oil reserves and future net revenues of natural gas and oil reserves upon reports prepared by Wright & Company, Inc. We have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. A summary of the reserve report related to our estimated proved reserves at December 31, 2011 is included as Exhibit 99.2 to this report. In accordance with SEC guidelines, we make the standardized measure estimates of future net cash flows from proved reserves using natural gas and oil sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. Our estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month price for each month within the prior 12-month period, and are listed below as of the dates indicated:

 

     December 31,  
     2011      2010  

Unadjusted

     

Natural gas (per Mcf)

   $ 4.12       $ 4.38   

Oil (per Bbl)

   $ 96.19       $ 79.43   

Adjusted

     

Natural gas (per Mcf)(1)

   $ 4.42       $ 4.63   

Oil (per Bbl) (1)

   $ 91.04       $ 72.70   

 

(1) The adjusted weighted average natural gas price is the Base product price, with the representative price of natural gas adjusted for basis premium and the Btu content to arrive at the appropriate net price. The adjusted weighted average oil price is the Base product price, adjusted for local contracted gathering arrangements. Natural gas liquid prices have not been presented as the reserve amounts are immaterial. Amounts shown do not include financial hedging transactions.

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

The preparation of our natural gas and oil reserve estimates was completed in accordance with our prescribed internal control procedures by our reserve engineers. The accompanying reserve information included below was derived from the reserve reports prepared for our annual report on Form 10-K for the year ended December 31, 2011. For the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located in the United States, primarily in Colorado, Indiana, New York, Ohio, Pennsylvania, Tennessee and West Virginia. The independent reserves engineer’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 13 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by our Executive Vice President.

Results of drilling, testing and production subsequent to the date of the estimate may justify revision of these estimates. Future prices received from the sale of natural gas and oil may be different from those estimated by Wright &

 

44


Company, Inc. in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. Please read “Item 1A: Risk Factors—Risks Relating to Our Business.” You should not construe the estimated standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. We base the estimates on operating methods and conditions prevailing as of the dates indicated:

 

     Proved natural gas and oil
reserves at December 31,
 
     2011      2010  

Proved reserves:

     

Natural gas reserves (Mmcf):

     

Proved developed reserves

     138,403         137,393   

Proved undeveloped reserves(1)

     19,273         38,672   
  

 

 

    

 

 

 

Total proved reserves of natural gas

     157,676         176,065   

Oil reserves (Mbbl):

     

Proved developed reserves

     1,638         1,833   

Proved undeveloped reserves(1)

     8         —     
  

 

 

    

 

 

 

Total proved reserves of oil(2)

     1,646         1,833   
  

 

 

    

 

 

 

Total proved reserves (Mmcfe)

     167,552         187,056   
  

 

 

    

 

 

 

Standardized measure of discounted future cash flows (in thousands)(3)

   $ 219,859       $ 236,630   
  

 

 

    

 

 

 

 

(1) Our ownership in these reserves is subject to reduction as we generally make capital contributions, which includes leasehold acreage associated with our proved undeveloped reserves, to our investment partnerships in exchange for an equity interest in these partnerships, which historically ranges from 20% to 41%, which effectively will reduce our ownership interest in these reserves from 100% to our respective ownership interest as we make these contributions.
(2) Includes less than 500 Mbbl of natural gas liquids proved reserves.
(3) Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to commodity derivative contracts. Because we are a limited partnership, no provision for federal or state income taxes has been included in the December 31, 2011 and 2010 calculations of standardized measure, which is, therefore, the same as the PV-10 value.

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

Proved Undeveloped Reserves (“PUDS”)

PUD Locations. As of December 31, 2011, we had 76 PUD locations totaling approximately 19.3 Bcfe’s of natural gas and oil. These PUDS are based on the definition of PUD’s in accordance with the Securities and Exchange Commission rules allowing the use of techniques that have been proven effective through documented evidence, such as actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.

Historically, the primary focus of our drilling operations has been in the Appalachian Basin. We will continue to focus in this area to increase our proved reserves through organic leasing as well as drilling on our existing undeveloped acreage.

Our organic growth will focus on expanding our Marcellus Shale acreage position and targeting other formations in the United States. Through our previous drilling in the Marcellus as well as our geologic analysis of these areas, we are expecting these expansion locations to have a significant impact on our proved reserves. In addition, we have drilled successful Clinton formation natural gas and oil wells in eastern Ohio. We plan to continue drilling shallow Clinton wells.

 

45


In the Chattanooga Shale in Tennessee, where we have drilled more than 90 producing wells, we plan to increase our proved reserves through continued drilling activity in this area.

Changes in PUDs. Changes in PUDS that occurred during the year ended December 31, 2011 were due to the following:

 

   

Conversion of approximately 15.7 Bcfe from Marcellus Shale PUDs to proved developed reserves;

 

   

Addition of approximately 0.8 Bcfe of Marcellus, Clinton/Medina and Niobrara drilled locations; and

 

   

Negative revisions of approximately 4.5 Bcfe in PUDs primarily due to the reduction of drilling plans in the New Albany Shale formation over the next five years.

Development Costs. Costs incurred related to the development of PUDs were approximately $40.5 million, $80.1 million, and $80.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Productive Wells

The following table sets forth information regarding productive natural gas and oil wells in which we have a working interest as of December 31, 2011. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, directly or through our ownership interests in investment partnerships, and net wells are the sum of our fractional working interests in gross wells, based on the percentage interest we own in the investment partnership that owns the well:

 

     Number of productive  wells(1)  
     Gross      Net  

Appalachia:

     

Gas wells

     7,715         3,198   

Oil wells

     498         314   
  

 

 

    

 

 

 

Total

     8,213         3,512   
  

 

 

    

 

 

 

New Albany/Antrim:

     

Gas wells

     153         42   

Oil wells

     —           —     
  

 

 

    

 

 

 

Total

     153         42   
  

 

 

    

 

 

 

Niobrara:

     

Gas wells

     85         23   

Oil wells

     —           —     
  

 

 

    

 

 

 

Total

     85         23   
  

 

 

    

 

 

 

Total:

     

Gas wells

     7,953         3,263   

Oil wells

     498         314   
  

 

 

    

 

 

 

Total

     8,451         3,577   
  

 

 

    

 

 

 

 

(1) Includes our proportionate interest in wells owned by 98 investment partnerships for which we serve as managing general partner and various joint ventures. This does not include royalty or overriding interests in 514 wells.

Developed and Undeveloped Acreage

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of December 31, 2011. The information in this table includes our proportionate interest in acreage owned by investment partnerships.

 

46


     Developed acreage (1)      Undeveloped  acreage(2)  
     Gross (3)      Net (4)      Gross (3)      Net (4)  

Pennsylvania

     154,492         154,492         758         758   

Ohio(5)

     104,612         75,619         31,608         31,608   

Indiana

     33,916         29,033         174,572         104,712   

Tennessee

     19,841         19,475         101,185         98,936   

New York

     13,197         12,699         43,697         42,379   

Other

     27,706         23,105         12,799         8,140   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     353,764         314,423         364,619         286,533   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Developed acres are acres spaced or assigned to productive wells.
(2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.
(3) A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.
(4) Net acres is the sum of the fractional working interests owned in gross acres. For example, a 50% working interest in an acre is one gross acre but is 0.5 net acres.
(5) Does not include Utica Shale natural gas and oil rights.

The leases for our developed acreage generally have terms that extend for the life of the wells, while the leases on our undeveloped acreage have terms that vary from less than one year to five years. There are no concessions for undeveloped acreage as of December 31, 2011.

We believe that we hold good and indefeasible title to our producing properties, in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the natural gas industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We or our predecessors have obtained title examinations for substantially all of our managed producing properties. No single property represents a material portion of our holdings.

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.

 

ITEM 3: LEGAL PROCEEDINGS

We are party to various routine legal proceedings arising in the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. See Note 13 of Notes to the Consolidated Combined Financial Statements.

 

ITEM 4: [REMOVED AND RESERVED]

PART II

 

ITEM 5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units trade on the New York Stock Exchange under the symbol “ATLS.” At the close of business on February 22, 2012, the closing price of our units was $25.98, and there were 205 holders of record of our common units. The following table sets forth the high and low sales price per unit of our common limited partner units as reported by the New York Stock Exchange and the cash distributions declared by quarter per unit on our common limited partner units for the years ended December 31, 2011 and 2010:

 

                  

Cash Distribution

per Common

Limited Partner

 
     High      Low      Declared(1)  

Year ended December 31, 2011:

        

Fourth quarter

   $ 25.59       $ 15.82       $ 0.24   

Third quarter

   $ 25.72       $ 17.69       $ 0.24   

Second quarter

   $ 27.36       $ 20.41       $ 0.22   

First quarter

   $ 23.24       $ 13.11       $ 0.11   

Year ended December 31, 2010:

        

Fourth quarter

   $ 15.44       $ 8.86       $ 0.07   

Third quarter

   $ 9.88       $ 3.76       $ 0.05   

Second quarter

   $ 6.80       $ 3.67       $ —     

First quarter

   $ 7.45       $ 5.14       $ —     

 

(1) The determination of the amount of future cash distributions declared, if any, is at the sole discretion of our General Partner’s board of directors and will depend on various factors affecting our financial conditions and other matters the board of directors deems relevant.

 

47


We have a cash distribution policy under which we distribute, within 50 days after the end of each quarter, all of our available cash (as defined in the partnership agreement) for that quarter to our common unitholders. See “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Distributions.”

For information concerning common units authorized for issuance under our long-term incentive plans, see “Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters – Equity Compensation Plan Information”.

 

ITEM 6. SELECTED FINANCIAL DATA

We have derived the selected financial data set forth in the following table for each of the years ended December 31, 2011, 2010 and 2009 from our consolidated financial statements appearing elsewhere in this report, which have been audited by Grant Thornton LLP, independent registered public accounting firm. We derived the financial data for the years ended December 31, 2008 and 2007 from our consolidated financial statements which are not included in this report.

The consolidated combined financial statements include our accounts and that of our consolidated subsidiaries, all of which are wholly-owned at December 31, 2011 except for APL, which we control. Due to the structure of our ownership interests in APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of APL into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in APL are reflected as income (loss) attributable to non-controlling interests in our consolidated combined statements of operations and as a component of partners’ capital on our consolidated combined balance sheets. Throughout this section, when we refer to “our” consolidated combined financial statements, we are referring to the consolidated combined results for us and our wholly-owned subsidiaries and the consolidated results of APL, adjusted for non-controlling interests in APL.

On February 17, 2011, we acquired certain producing natural gas and oil properties, an investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner. In accordance with prevailing accounting literature, we determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. In comparison to the purchase method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our consolidated combined financial statements in the following manner:

 

   

Recognized the assets and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital;

 

   

Retrospectively adjusted our consolidated combined balance sheets, our consolidated combined statements of operations, our consolidated combined statements of partners’ capital, our consolidated combined statements of comprehensive income (loss) and our consolidated combined statements of cash flows to reflect our results combined with the results of the Transferred Business as of or at the beginning of the respective period;

 

   

Adjusted the presentation of our consolidated combined statements of operations to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income (loss) to determine income (loss) attributable to common limited partners. However, the Transferred Business’ historical

 

48


 

financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense. The Transferred Business was not managed by AEI as a separate business segment and did not have identifiable labor and other ancillary costs. The general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron in February 2011 and not activities related to the Transferred Business.

The following table should be read together with our consolidated financial statements and notes thereto included within Item 7: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8: “Financial Statements and Supplementary Data” of this report.

 

     Years Ended December 31,  
     2011     2010     2009     2008     2007  
     (in thousands, except per unit data)  

Statement of operations data:

          

Revenues:

          

Gas and oil production

   $ 66,979      $ 93,050      $ 112,979      $ 127,083      $ 99,015   

Well construction and completion

     135,283        206,802        372,045        415,036        321,471   

Gathering and processing

     1,329,753        945,228        714,145        1,185,254        591,570   

Administration and oversight

     7,741        9,716        15,554        19,277        17,955   

Well services

     19,803        20,994        17,859        18,513        16,663   

Gain (loss) on mark-to-market derivatives

     (20,453     (5,944     (35,815     29,741        (104,524

Other, net

     31,803        17,437        15,295        7,330        5,263   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     1,570,909        1,287,283        1,212,062        1,802,234        947,413   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

          

Gas and oil production

     17,100        23,323        25,557        25,104        17,638   

Well construction and completion

     115,630        175,247        315,546        359,609        279,540   

Gathering and processing

     1,123,386        790,167        605,222        978,178        450,984   

Well services

     8,738        10,822        9,330        10,654        9,062   

General and administrative

     80,584        37,561        38,932        633        63,175   

Depreciation, depletion and amortization

     109,373        115,655        119,396        111,545        62,841   

Goodwill and other asset impairment

     6,995        50,669        166,684        615,724        —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     1,461,806        1,203,444        1,280,667        2,101,447        883,240   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     109,103        83,839        (68,605     (299,213     64,173   

(Loss) gain on early extinguishment of debt

     (19,574     (4,359     (2,478     17,420        (4,972

Gain (loss) on asset sales

     256,292        (13,676     108,947        —          —     

Interest expense

     (38,394     (90,448     (104,053     (89,284     (60,120
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations

     307,427        (24,644     (66,189     (371,077     (919

Income (loss) from discontinued operations

     (81     321,155        84,148        (93,802     (23,641
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

     307,346        296,511        17,959        (464,879     (24,560

(Income) loss attributable to non-controlling interests

     (257,643     (245,764     (53,924     536,455        129,380   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) after non-controlling interests

     49,703        50,747        (35,965     71,576        104,820   

(Income) loss not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition)

     (4,711     (22,813     40,000        (145,229     (120,467
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners

   $ 44,992      $ 27,934      $ 4,035      $ (73,653   $ (15,647
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Allocation of net income (loss) attributable to common limited partners:

          

Continuing operations

   $ 45,002      $ (11,994   $ (7,287   $ (62,331   $ (12,940

Discontinued operations

     (10     39,928        11,322        (11,322     (2,707
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   $ 44,992      $ 27,934      $ 4,035      $ (73,653   $ (15,647
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners per unit:

          

Basic:

          

Income (loss) from continuing operations attributable to common limited partners

   $ 0.91      $ (0.43   $ (0.26   $ (2.23   $ (0.55

Income (loss) from discontinued operations attributable to common limited partners

     —          1.44        0.41        (0.45     (0.11
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners

   $ 0.91      $ 1.01      $ 0.15      $ (2.68   $ (0.66
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted(1):

          

Income (loss) from continuing operations attributable to common limited partners

   $ 0.88      $ (0.43   $ (0.26   $ (2.23   $ (0.55

Income (loss) from discontinued operations attributable to common limited partners

     —          1.44        0.41        (0.45     (0.11
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners

   $ 0.88      $ 1.01      $ 0.15      $ (2.68   $ (0.66
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance sheet data (at period end):

          

Property, plant and equipment, net

   $ 2,093,283        1,849,486      $ 1,831,090      $ 2,031,774      $ 1,675,934   

Total assets

     2,684,098        2,435,262        2,838,007        3,262,986        3,405,466   

Total debt, including current portion

     524,140        601,389        1,262,183        1,539,427        1,254,426   

Total partners’ capital

     1,744,081        1,406,123        1,053,855        1,135,216        1,518,807   

Cash flow data:

          

Net cash provided by operating activities

   $ 88,195      $ 157,253      $ 236,664      $ 108,844      $ 312,115   

Net cash provided by (used in) investing activities

     14,159        502,330        142,637        (555,123     (2,181,118

Net cash provided by (used in) financing activities

     (25,225     (660,439     (385,483     435,477        1,885,216   

 

(1) For the year ended December 31, 2010, approximately 180,000 stock awards were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such common limited partner units would have been anti-dilutive. For the year ended December 31, 2009, approximately 187,000 stock awards were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such common limited partner units would have been anti-dilutive. For the year ended December 31, 2008, approximately 553,000 stock awards were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such common limited partner units would have been anti-dilutive. For the year ended December 31, 2007, approximately 515,000 stock awards were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such common limited partner units would have been anti-dilutive.

 

49


ITEM 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with “Item 6 – Selected Financial Data” and “Item 8 – Financial Statements and Supplemental Data”.

BUSINESS OVERVIEW

We are a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS), and independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, Illinois Basin and the Rocky Mountain region. We sponsor and manage tax-advantaged investment partnerships, in which we co-invest, to finance a portion of our natural gas and oil production activities.

On February 17, 2011, we acquired certain assets and liabilities (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner (see “Recent Developments”). These assets principally included the following:

 

   

AEI’s investment management business, which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which we fund a portion of our natural gas and oil well drilling;

 

   

proved reserves located in the Appalachia Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan, and the Chattanooga Shale of northeastern Tennessee;

 

   

certain producing natural gas and oil properties, upon which we are developers and producers;

 

   

all of the ownership interests in Atlas Energy GP, LLC, our general partner; and

 

   

a direct and indirect ownership interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC (collectively, “Lightfoot”), which incubates new MLPs and invest in existing MLPs. At December 31, 2011, we had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot.

We also maintain an ownership interest in Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions of the United States. At December 31, 2011, we owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 10.7% common limited partner interest.

FINANCIAL PRESENTATION

Our consolidated combined financial statements contain our accounts and those of our consolidated subsidiaries, all of which are wholly-owned at December 31, 2011 except for APL, which we control. Due to the structure of our ownership interests in APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of APL into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in APL are reflected as income attributable to non-controlling interests in our consolidated combined statements of operations and as a component of partners’ capital on our consolidated combined balance sheets. Throughout this section, when we refer to “our” consolidated combined financial statements, we are referring to the consolidated combined results for us, our wholly-owned subsidiaries and the consolidated results of APL, adjusted for non-controlling interests in APL’s.

In accordance with prevailing accounting literature, we determined that the acquisition of the Transferred Business constituted a transaction between entities under common control (see –“Recent Developments”). In comparison to the purchase method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital. Also, in comparison to the purchase method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect of the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our consolidated combined financial statements in the following manner:

 

   

Recognized the assets acquired and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital;

 

50


   

Retrospectively adjusted our consolidated combined balance sheet as of December 31, 2010, our consolidated combined statement of partners’ capital for the years ended December 31, 2011, 2010 and 2009, our consolidated combined statements of comprehensive income (loss) for the years ended December 31, 2011, 2010 and 2009, and our consolidated combined statements of operations for the years ended December 31, 2011, 2010 and 2009, and our consolidated combined statements of cash flows for the years ended December 31, 2011, 2010 and 2009 to reflect our results combined with the results of the Transferred Business as of or at the beginning of the respective period; and

 

   

Adjusted the presentation of our consolidated combined statements of operations for the years ended December 31, 2011, 2010 and 2009 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income to determine income attributable to common limited partners. However, the Transferred Business’ historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense. The Transferred Business was not managed by AEI as a separate business segment and did not have identifiable labor and other ancillary costs. The general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron Corporation in February 2011 and not activities related to the Transferred Business.

SUBSEQUENT EVENTS

Formation of Atlas Resource Partners, L.P. In February 2012, our General Partner’s board of directors approved the formation of a newly created exploration and production master limited partnership named Atlas Resource Partners, L.P. (“ARP”), which will hold substantially all of our current natural gas and oil development and production assets and the partnership management business. Our General Partner’s board of directors also approved the distribution of approximately 5.24 million ARP common units, which will be distributed on March 13, 2012 to our unitholders using a ratio of 0.1021 ARP limited partner units for each of our common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units will represent an approximate 19.6% limited partner interest. Subsequent to the distribution, we will own a 2% general partner interest, all of the incentive distribution rights in ARP and common units representing an approximate 78.4% limited partner interest in ARP. For a further description of ARP’s cash distribution policy, please see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations - Cash Distributions”.

Cash Distributions. On January 26, 2012, we declared a cash distribution of $0.24 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2011. The $12.3 million distribution was paid on February 17, 2012 to unitholders of record at the close of business on February 7, 2012.

APL Cash Distributions. On January 26, 2012, APL declared a cash distribution of $0.55 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2011. The $31.5 million distribution, including $5.2 million to us, was paid on February 14, 2012 to unitholders of record at the close of business on February 7, 2012.

RECENT DEVELOPMENTS

APL Senior Notes. In November 2011, APL issued $150.0 million of its 8.75% Senior Notes in a private placement transaction. The 8.75% Senior Notes were issued at a premium of 103.5% of the principal amount for a yield of 7.82%. APL received net proceeds of $154.2 million after underwriting commissions and other transaction costs and utilized the proceeds to reduce the outstanding balance on its revolving credit facility.

Lightfoot Capital Partners. In October 2011, we announced that GE Energy Financial Services, a unit of General Electric, has invested in Lightfoot. GE Financial Services will own a general partner interest and a 58% limited partner interest. Following this investment, we will hold an approximate 16% general partner interest and 12% limited partner interest in Lightfoot.

 

51


APL Credit Facility. In July 2011, APL exercised the $100.0 million accordion feature on its revolving credit facility to increase the capacity from $350.0 million to $450.0 million. The other terms of the credit agreement put in place in December 2010 remain unchanged.

APL Pipeline Acquisition. In May 2011, APL acquired a 20% interest in West Texas LPG Pipeline Limited Partnership (“West Texas LPG”) from Buckeye Partners, L.P. for $85.0 million. West Texas LPG owns a common-carrier pipeline system that transports natural gas liquids from New Mexico and Texas to Mont Belvieu for fractionation. West Texas LPG is operated by Chevron Pipeline Company, a subsidiary of Chevron, which owns the remaining 80% interest.

Redemption of APL Senior Notes. In April 2011, APL completed the redemption of all of its 8.125% Senior Notes for a total redemption of $293.7 million, including accrued interest of $7.0 million and premium of $11.2 million. Also in April, APL redeemed $7.2 million of the APL 8.75% Senior Notes, which were tendered upon its offer to purchase the senior notes at par. APL funded its purchase with a portion of the net proceeds from its sale of its 49% non-controlling interest in Laurel Mountain.

Acquisition from AEI. On February 17, 2011, we completed an acquisition of the Transferred Business from AEI, the former parent of our general partner. For the assets acquired and liabilities assumed, we issued approximately 23.4 million of our common limited partner units and paid $30.0 million in cash consideration. Based on our February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. In connection with the transaction, we also received $118.7 million with respect to a contractual cash transaction adjustment from Chevron related to certain liabilities assumed by the Transferred Business, including certain amounts subject to a reconciliation period following the consummation of the transaction. Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $522.9 million.

Concurrent with our acquisition of the Transferred Business, AEI completed its merger with Chevron Corporation (“Chevron”), whereby AEI became a wholly-owned subsidiary of Chevron. Also concurrent with our acquisition of the Transferred Business and immediately preceding AEI’s merger with Chevron, APL completed its sale to AEI of its 49% non-controlling interest in the Laurel Mountain joint venture (the “Laurel Mountain Sale”). APL received $409.5 million in cash, net of expenses, including adjustments based on certain capital contributions APL made to and distributions it received from the Laurel Mountain joint venture after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of the Laurel Mountain joint venture entitling APL to receive all payments made under the note receivable issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of the Laurel Mountain joint venture. The note was paid in full as of December 31, 2011.

CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas. We market the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price, the natural gas produced in the New Albany Shale and Antrim Shale has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices, and the gas produced in the Niobrara formation has been primarily based upon the Cheyenne Index. For the year ended December 31, 2011, Chevron, South Jersey Resources Group and Sequent Energy Management accounted for approximately 17%, 14% and 10% of our total natural gas and oil production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Crude Oil. Crude oil produced from our wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil.

Natural Gas Liquids. Natural gas liquids (“NGL’s”) are produced by our natural gas processing plants, which extract the natural gas liquids from the natural gas production, enabling the remaining “dry” gas (low BTU content) to meet pipeline specifications for long-haul transport to end users. We sell natural gas liquids produced by our natural gas processing plants to regional refining companies at the prevailing spot market price for natural gas liquids.

We do not have delivery commitments for fixed and determinable quantities of natural gas, oil or natural gas liquids in any future periods under existing contracts or agreements.

 

52


Investment Partnerships. We generally have funded a portion of our drilling activities through sponsorship of tax-advantaged investment drilling partnerships. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. As managing general partner of the investment partnerships, we receive the following fees:

 

   

Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% to 18% mark-up on those costs incurred to drill and complete the well;

 

   

Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee of between $15,000 and $250,000, depending on the type of well drilled. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well;

 

   

Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $1,500, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the wells; and

 

   

Gathering. Each royalty owner, partnership and certain other working interest owners pay us a gathering fee, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the natural gas. In general, pursuant to gathering agreements we have with a third-party gathering system which gathers the majority of our natural gas, we must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). As a result, some of our gathering expenses within our partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from investment partnerships by approximately 3%.

APL Revenue. APL’s principal revenue is generated from the gathering and sale of natural gas, natural gas liquids and condensate. Variables that affect its revenue are:

 

   

the volumes of natural gas APL gathers and processes, which in turn, depend upon the number of wells connected to its gathering systems, the amount of natural gas they produce, and the demand for natural gas, NGLs and condensate;

 

   

the price of the natural gas APL gathers and processes and the NGLs and condensate it recovers and sells, which is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States;

 

   

the NGL and BTU content of the gas that is gathered and processed;

 

   

the contract terms with each producer; and

 

   

the efficiency of APL’s gathering systems and processing plants.

Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems and then sells the natural gas and NGLs off of delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas.

GENERAL TRENDS AND OUTLOOK

We expect our business to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural Gas Supply and Outlook. The areas in which we operate are experiencing a significant increase in natural gas production related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. This increase in the supply of natural gas has put a downward pressure on domestic prices. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves.

 

53


Reserve Outlook. Our future gas and oil reserves, production, cash flow, our ability to make payments on our revolving credit facility and our ability to make distributions to our unitholders depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular wells decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce.

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

Production Profile. Currently, we have focused our natural gas and oil production operations in various shale plays in the northeastern and midwestern United States. As part of our agreement with AEI to acquire the Transferred Business, we have entered into certain agreements which restrict our ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale. Through December 31, 2011, we have established production positions in the following areas:

 

   

the Appalachia basin, including the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas, and the Chattanooga Shale in northeastern Tennessee, which enables us to access other formations in that region such as the Monteagle and Ft. Payne Limestone;

 

   

the Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas;

 

   

the New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile; and

 

   

the Antrim Shale in Michigan, where we produce out of the biogenic region of the shale similar to the New Albany Shale;

The following table presents the number of wells we drilled, both gross and for our interest, and the number of gross wells we turned in line during the three years ended December 31, 2011, 2010 and 2009:

 

     Years Ended December 31,  
     2011      2010      2009  

Gross wells drilled:

        

Appalachia

     22         22         174   

New Albany/Antrim

     —           66         93   

Niobrara

     138         29         —     
  

 

 

    

 

 

    

 

 

 
     160         117         267   
  

 

 

    

 

 

    

 

 

 

Our share of gross wells drilled(1):

        

Appalachia

     4         6         45   

New Albany/Antrim

     —           19         23   

Niobrara

     27         9         —     
  

 

 

    

 

 

    

 

 

 
     31         34         68   
  

 

 

    

 

 

    

 

 

 

Gross wells turned in line:

        

Appalachia

     9         83         307   

New Albany/Antrim

     13         76         65   

Niobrara

     77         8         —     
  

 

 

    

 

 

    

 

 

 
     99         167         372   
  

 

 

    

 

 

    

 

 

 

 

(1) 

Includes (i) our percentage interest in the wells in which we have a direct ownership interest and (ii) our percentage interest in the wells based on our percentage ownership in our investment partnerships.

 

54


Production Volumes. The following table presents our total net natural gas, oil, and natural gas liquids production volumes and production per day for the years ended December 31, 2011, 2010 and 2009:

 

     Years Ended December 31,  
     2011      2010      2009  

Production:(1)(2)

        

Appalachia:(3)

        

Natural gas (MMcf)

     10,163         12,363         13,905   

Oil (000’s Bbls)

     112         136         156   

Natural gas liquids (000s Bbls)

     162         182         37   
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

     11,809         14,274         15,062   
  

 

 

    

 

 

    

 

 

 

New Albany/Antrim:

        

Natural gas (MMcf)

     1,148         724         200   

Oil (000’s Bbls)

     —           —           —     

Natural gas liquids (000s Bbls)

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

     1,148         724         200   
  

 

 

    

 

 

    

 

 

 

Niobrara:

        

Natural gas (MMcf)

     152         —           —     

Oil (000’s Bbls)

     —           —           —     

Natural gas liquids (000s Bbls)

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

     152         —           —     
  

 

 

    

 

 

    

 

 

 

Total:

        

Natural gas (MMcf)

     11,462         13,087         14,105   

Oil (000’s Bbls)

     112         136         156   

Natural gas liquids (000s Bbls)

     162         182         37   
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

     13,108         14,998         15,262   
  

 

 

    

 

 

    

 

 

 

Production per day: (1)(2)

        

Appalachia:(3)

        

Natural gas (Mcfd)

     27,843         33,872         38,096   

Oil (Bpd)

     307         373         427   

Natural gas liquids (Bpd)

     444         499         101   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

     32,352         39,107         41,267   
  

 

 

    

 

 

    

 

 

 

New Albany/Antrim:

        

Natural gas (Mcfd)

     3,144         1,983         548   

Oil (Bpd)

     —           —           —     

Natural gas liquids (Bpd)

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

     3,144         1,983         548   
  

 

 

    

 

 

    

 

 

 

Niobrara:

        

Natural gas (Mcfd)

     416         —           —     

Oil (Bpd)

     —           —           —     

Natural gas liquids (Bpd)

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

     416         —           —     
  

 

 

    

 

 

    

 

 

 

Total:

        

Natural gas (Mcfd)

     31,403         35,855         38,644   

Oil (Bpd)

     307         373         427   

Natural gas liquids (Bpd)

     444         499         101   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

     35,912         41,090         41,814   
  

 

 

    

 

 

    

 

 

 

 

(1) 

Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

(2) 

“MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of approximately six Mcf’s to one barrel.

(3)

Appalachia includes our production located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

 

55


Production Revenues, Prices and Costs. Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 94% of our proved reserves on an energy equivalent basis at December 31, 2011. The following table presents our production revenues and average sales prices for our natural gas, oil, and natural gas liquids production for the years ended December 31, 2011, 2010, and 2009, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods:

 

     Years Ended December 31,  
     2011      2010      2009  

Production revenues (in thousands):

        

Appalachia:(1)

        

Natural gas revenue

   $ 43,310       $ 71,726       $ 99,024   

Oil revenue

     10,057         10,541         11,119   

Natural gas liquids revenue

     7,826         6,879         1,334   
  

 

 

    

 

 

    

 

 

 

Total revenues

   $ 61,193       $ 89,146       $ 111,477   
  

 

 

    

 

 

    

 

 

 

New Albany/Antrim:

        

Natural gas revenue

   $ 5,154       $ 3,904       $ 1,502   

Oil revenue

     —           —           —     

Natural gas liquids revenue

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total revenues

   $ 5,154       $ 3,904       $ 1,502   
  

 

 

    

 

 

    

 

 

 

Niobrara:

        

Natural gas revenue

   $ 632       $ —         $ —     

Oil revenue

     —           —           —     

Natural gas liquids revenue

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total revenues

   $ 632       $ —         $ —     
  

 

 

    

 

 

    

 

 

 

Total:

        

Natural gas revenue

   $ 49,096       $ 75,630       $ 100,526   

Oil revenue

     10,057         10,541         11,119   

Natural gas liquids revenue

     7,826         6,879         1,334   
  

 

 

    

 

 

    

 

 

 

Total revenues

   $ 66,979       $ 93,050       $ 112,979   
  

 

 

    

 

 

    

 

 

 

Average sales price:(2)

        

Natural gas (per Mcf):

        

Total realized price, after hedge(3)

   $ 4.98       $ 7.08       $ 7.54   

Total realized price, before hedge(3)

   $ 4.53       $ 4.60       $ 4.04   

Oil (per Bbl):

        

Total realized price, after hedge

   $ 89.70       $ 77.31       $ 71.34   

Total realized price, before hedge

   $ 89.07       $ 71.37       $ 57.41   

Natural gas liquids (per Bbl) total realized price:

   $ 48.26       $ 37.78       $ 36.19   

Production costs (per Mcfe):(2)

        

Appalachia:(1)

        

Lease operating expenses(4)

   $ 1.05       $ 1.25       $ 1.08   

Production taxes

     0.10         0.03         0.03   

Transportation and compression

     0.50         0.68         0.68   
  

 

 

    

 

 

    

 

 

 
   $ 1.64       $ 1.97       $ 1.79   
  

 

 

    

 

 

    

 

 

 

New Albany/Antrim:

        

Lease operating expenses

   $ 1.14       $ 1.59       $ 2.54   

Production taxes

     0.13         0.10         0.05   

Transportation and compression

     0.03         0.09         0.09   
  

 

 

    

 

 

    

 

 

 
   $ 1.31       $ 1.77       $ 2.67   
  

 

 

    

 

 

    

 

 

 

Niobrara:

        

Lease operating expenses

   $ 1.16       $ —         $ —     

Production taxes

     0.03         —           —     

Transportation and compression

     0.43         —           —     
  

 

 

    

 

 

    

 

 

 
   $ 1.62       $ —         $ —     
  

 

 

    

 

 

    

 

 

 

Total:

        

Lease operating expenses(4)

   $ 1.06       $ 1.27       $ 1.10   

Production taxes

     0.10         0.04         0.03   

Transportation and compression

     0.46         0.65         0.68   
  

 

 

    

 

 

    

 

 

 
   $ 1.61       $ 1.96       $ 1.80   
  

 

 

    

 

 

    

 

 

 

 

(1)

Appalachia includes our operations located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

(2) 

“Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.

(3) 

Excludes the impact of subordination of our production revenue to investor partners within our investment partnerships for the years ended December 31, 2011, 2010 and 2009. Including the effect of this subordination, the average realized gas sales price was $4.28 per Mcf ($3.83 per Mcf before the effects of financial hedging), $5.78 per Mcf ($3.30 per Mcf before the effects of financial hedging), and $7.13 per Mcf ($3.62 per Mcf before the effects of financial hedging) for the years ended December 31, 2011, 2010 and 2009, respectively.

 

56


(4) 

Excludes the effects of our proportionate share of lease operating expenses associated with subordination of our production revenue to investor partners within our investment partnerships for the years ended December 31, 2011, 2010 and 2009. Including the effects of these costs, Appalachia lease operating expenses per Mcfe were $0.71 per Mcfe ($1.30 per Mcfe for total production costs), $0.83 per Mcfe ($1.54 per Mcfe for total production costs), and $0.95 per Mcfe ($1.66 per Mcfe for total production costs) for the years ended December 31, 2011, 2010 and 2009, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $0.75 per Mcfe ($1.30 per Mcfe for total production costs), $0.86 per Mcfe ($1.56 per Mcfe for total production costs), and $0.97 per Mcfe ($1.67 per Mcfe for total production costs) for the years ended December 31, 2011, 2010 and 2009, respectively.

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Total natural gas revenues were $49.1 million for the year ended December 31, 2011, a decrease of $26.5 million from $75.6 million for the year ended December 31, 2010. This decrease consisted of a $24.0 million decrease attributable to lower realized natural gas prices and an $11.5 million decrease attributable to lower production volumes, partially offset by a $9.0 million decrease in gas revenues subordinated to the investor partners within our investment partnerships for the year ended December 31, 2011 compared with the prior year period. Total oil and natural gas liquids revenues were $17.9 million for the year ended December 31, 2011, an increase of $0.4 million from $17.5 million for the comparable prior year period. This increase resulted from a $1.4 million increase associated with higher average oil and natural gas liquids realized prices and a $0.9 million increase from the sale of natural gas liquids, partially offset by a $1.9 million decrease associated with lower oil production volumes. The decrease in natural gas and oil volumes was the result of fewer wells turned in line due to the cancellation of our fall 2010 drilling program, which was the result of AEI’s announcement of the acquisition of the Transferred Business in November 2010. The decrease in gas revenues subordinated to the investor partners within our investment partnerships was related to the overall decrease in natural gas revenue.

Appalachia production costs were $15.4 million for the year ended December 31, 2011, a decrease of $6.6 million from $22.0 million for the year ended December 31, 2010. This decrease was principally due to a $3.8 million decrease in transportation costs, a $3.0 million decrease associated with water hauling and disposal costs, a $0.5 million decrease for labor-related costs and a $1.3 million decrease associated with maintenance expenses and other costs associated with our natural gas and oil operations, partially offset by a $2.0 million decrease associated with our proportionate share of lease operating expenses associated with our revenue that was subordinated to the investor partners within our investment partnerships. The decreases in transportation costs, water hauling and disposal costs, labor-related costs and maintenance expenses and other costs were primarily due to a decrease in natural gas volumes between the periods. New Albany/Antrim production costs were $1.5 million for the year ended December 31, 2011, an increase of $0.2 million from $1.3 million for the comparable prior year period. This increase was primarily attributable to a $0.1 million increase for maintenance and repair expense and a $0.1 million increase associated with parts, materials and other costs associated with our increased natural gas production in New Albany/Antrim.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Total natural gas revenues were $75.6 million for the year ended December 31, 2010, a decrease of $24.9 million from $100.5 million for the year ended December 31, 2009. This decrease consisted of a $7.8 million decrease attributable to lower natural gas production volumes, a $6.0 million decrease attributable to lower realized natural gas prices and an $11.1 million increase in gas revenues subordinated to the investor partners within our investment partnerships for the year ended December 31, 2010 compared with the prior year. Total oil and natural gas liquids revenues were $17.4 million for the year ended December 31, 2010, an increase of $4.9 million from $12.5 million for the year ended December 31, 2009. This increase resulted from a $5.7 million increase from the sale of natural gas liquids and a $0.8 million increase attributable to higher average oil and natural gas liquids realized prices, partially offset by a $1.6 million decrease associated with lower oil production volumes. The decrease in natural gas and oil volumes was the result of fewer wells turned in line due to the cancellation of our fall 2010 drilling program, which was the result of AEI’s announcement of the acquisition of the Transferred Business in November 2010. The increase in gas revenues subordinated to the investor partners within our investment partnerships was primarily the result of an increase in our natural gas revenues that qualified for subordination to the investor partners within our investment partnerships, partially offset by an overall decrease in our realized natural gas revenues between the periods.

Appalachia production costs were $22.0 million for the year ended December 31, 2010, a decrease of $3.0 million from $25.0 million for the year ended December 31, 2009. This decrease was principally due a $4.1 million increase associated with our proportionate share of lease operating expenses associated with our revenue that was subordinated to the investor partners within our investment partnerships, partially offset by an increase of $1.1 million associated with labor, maintenance expenses and other costs associated with the growth of our operations. New Albany/Antrim production costs were $1.3 million for the year ended December 31, 2010, an increase of $0.8 million from $0.5 million for the prior year. This increase was primarily attributable to an increase in labor, maintenance and compression station expenses associated with the growth of our operations.

 

57


PARTNERSHIP MANAGEMENT

Well Construction and Completion

Drilling Program Results. The number of wells we drill will vary within the partnership management segment depending on the amount of capital we raise through our investment partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table presents the amounts of drilling partnership investor capital raised and deployed (in thousands), as well as the number of gross and net development wells we drilled for our investment partnerships during the years ended December 31, 2011, 2010 and 2009. There were no exploratory wells drilled during the years ended December 31, 2011, 2010 and 2009:

 

     Years Ended December 31,  
     2011      2010      2009  

Drilling partnership investor capital:

        

Raised

   $ 141,929       $ 149,342       $ 353,444   

Deployed

   $ 135,283       $ 206,802       $ 372,045   

Gross partnership wells drilled:

        

Appalachia

     22         22         174   

New Albany/Antrim

     —           66         93   

Niobrara

     138         29         —     
  

 

 

    

 

 

    

 

 

 

Total

     160         117         267   
  

 

 

    

 

 

    

 

 

 

Net partnership wells drilled:

        

Appalachia

     19         21         159   

New Albany/Antrim

     —           58         84   

Niobrara

     138         29         —     
  

 

 

    

 

 

    

 

 

 

Total

     157         108         243   
  

 

 

    

 

 

    

 

 

 

Well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for investment partnerships we sponsor. The following table sets forth information relating to these revenues and the related costs and number of net wells associated with these revenues during the periods indicated (dollars in thousands):

 

     Years Ended December 31,  
     2011      2010      2009  

Average construction and completion:

        

Revenue per well

   $ 886       $ 1,600       $ 1,531   

Cost per well

     757         1,356         1,299   
  

 

 

    

 

 

    

 

 

 

Gross profit per well

   $ 129       $ 244       $ 232   
  

 

 

    

 

 

    

 

 

 

Gross profit margin

   $ 19,653       $ 31,555       $ 56,499   
  

 

 

    

 

 

    

 

 

 

Partnership net wells associated with revenue recognized(1):

        

Appalachia

     21         44         166   

New Albany/Antrim

     3         63         77   

Niobrara

     129         22         —     
  

 

 

    

 

 

    

 

 

 
     153         129         243   
  

 

 

    

 

 

    

 

 

 

 

(1) 

Consists of partnership net wells for which well construction and completion revenue was recognized on a percentage of completion basis.

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Well construction and completion segment margin was $19.7 million for the year ended December 31, 2011, a decrease of $11.9 million from $31.6 million for the year ended December 31, 2010. This decrease consisted of a $14.9 million decrease associated with lower gross profit per well, partially offset by a $3.0 million increase related to an increased number of wells recognized for revenue within the investment partnerships. Average revenue and cost per well decreased between periods due to higher capital deployed for Niobrara formation wells within the drilling partnerships during 2011, while 2010 included higher capital deployment pertaining to Marcellus Shale and New Albany/Antrim Shale wells. Typically, the Niobrara formation wells we have drilled within the drilling partnerships have a lower cost per well as compared to the Marcellus Shale and New Albany/Antrim Shale wells. Since our drilling contracts with the investment partnerships are on a “cost-plus” basis, an increase or decrease in our average cost per well also results in a proportionate increase or decrease in our average revenue

 

58


per well, which directly affects the number of wells we drill. In addition, the decrease in well construction and completion margin was due to the cancellation of our Fall 2010 drilling program, which occurred following AEI’s announcement of the acquisition of the Transferred Business in November 2010.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Well construction and completion segment margin was $31.6 million for the year ended December 31, 2010, a decrease of $24.9 million from $56.5 million for the year ended December 31, 2009. This decrease was due to a $26.4 million decrease associated with a decrease in the number of wells recognized for revenue within the investment partnerships, partially offset by a $1.5 million increase associated with higher gross profit per well. The decrease in the number of wells recognized for revenue was the result of the cancellation of our Fall 2010 drilling program, as discussed above.

Our consolidated combined balance sheet at December 31, 2011 includes $71.7 million of “liabilities associated with drilling contracts” for funds raised by our investment partnerships that have not been applied to the completion of wells due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue on our consolidated combined statements of operations. We expect to recognize this amount as revenue during 2012.

Administration and Oversight

Administration and oversight fee revenues represent supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for our investment partnerships.

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Administration and oversight fee revenues were $7.7 million for the year ended December 31, 2011, a decrease of $2.0 million from $9.7 million for the year ended December 31, 2010. This decrease was primarily due to a decrease in the number of Marcellus Shale and New Albany Shale wells drilled during the current year period in comparison to the prior year period, partially offset by the increase in the number of wells drilled in the Niobrara Shale during the current year period in comparison to the prior year period. Typically, we receive a lower administration and oversight fee related to the Niobrara formation wells we have drilled within the drilling partnerships as compared to the Marcellus Shale and New Albany/Antrim Shale wells. In addition, the decrease in administration and oversight revenues was due to the cancellation of our Fall 2010 drilling program, which occurred following AEI’s announcement of the acquisition of the Transferred Business in November 2010.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Administration and oversight fee revenues were $9.7 million for the year ended December 31, 2010, a decrease of $5.9 million from $15.6 million for the year ended December 31, 2009. This decrease was primarily due to a decrease in the number of wells drilled during the current year in comparison to the prior year resulting from the cancellation of our Fall 2010 drilling program, as discussed above.

Well Services

Well service revenue and expenses represent the monthly operating fees we charge and the work our service company performs for our investment partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells in which we serve as operator.

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Well services revenues were $19.8 million for the year ended December 31, 2011, a decrease of $1.2 million from $21.0 million for year ended December 31, 2010. Well services expenses were $8.7 million for the year ended December 31, 2011, a decrease of $2.1 million from $10.8 million for the year ended December 31, 2010. The decrease in well services revenue and expense is primarily related to a reduction in repairs and maintenance projects due to fewer wells turned in line during the year ended December 31, 2011 as compared with the comparable prior year period.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Well services revenues were $21.0 million for the year ended December 31, 2010, an increase of $3.1 million from $17.9 million for the year ended December 31, 2009. Well services expenses were $10.8 million for the year ended December 31, 2010, an increase of $1.5 million from $9.3 million for the year ended December 31, 2009. These increases were primarily attributable to a temporary increase in the quantity and scope of ongoing maintenance projects and an increase in the number of producing wells.

Gathering and Processing

Gathering and processing margin includes gathering fees we charge to our investment partnership wells and the related expenses, as well as gross margin for our processing plants in the New Albany Shale and the Chattanooga Shale, and the operating revenues and expenses of APL. The gathering fees charged to our investment partnership wells generally range from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the

 

59


natural gas. In general, pursuant to gathering agreements we have with a third-party gathering system which gathers the majority of our natural gas, we must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). However, in most of our direct investment partnerships we collect a gathering fee of 13% of the realized natural gas sales price per the respective partnership agreement. As a result, some of our gathering expenses within our partnership management segment, specifically those in the Appalachia Basin, will generally exceed the revenues collected from the investment partnerships by approximately 3%.

The following table presents our gathering and processing revenues and expenses and those attributable to APL for each of the respective periods:

 

     Years Ended December 31,  
     2011     2010     2009  

Gathering and Processing:

      

Atlas Energy:

      

Revenue

   $ 17,746      $ 14,087      $ 18,839   

Expense

     (20,842     (20,221     (25,269
  

 

 

   

 

 

   

 

 

 

Gross Margin

   $ (3,096   $ (6,134   $ (6,430
  

 

 

   

 

 

   

 

 

 

Atlas Pipeline:

      

Revenue

   $ 1,312,007      $ 931,141      $ 695,306   

Expense

     (1,102,544     (769,946     (579,953
  

 

 

   

 

 

   

 

 

 

Gross Margin

   $ 209,463      $ 161,195      $ 115,353   
  

 

 

   

 

 

   

 

 

 

Total:

      

Revenue

   $ 1,329,753      $ 945,228      $ 714,145   

Expense

     (1,123,386     (790,167     (605,222
  

 

 

   

 

 

   

 

 

 

Gross Margin

   $ 206,367      $ 155,061      $ 108,923   
  

 

 

   

 

 

   

 

 

 

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Our net gathering and processing expense for the year ended December 31, 2011 was $3.1 million compared with $6.1 million for the year ended December 31, 2010. This favorable decrease was principally due to lower natural gas volume and prices between the periods.

Gathering and processing margin for APL was $209.5 million for the year ended December 31, 2011 compared with $161.2 million for the year ended December 31, 2010. This increase was due principally to higher production volumes related to on-going capacity expansion projects, as well as higher average natural gas liquids and crude oil commodity prices between periods.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Our net gathering and processing expense for the year ended December 31, 2010 was $6.1 million compared with $6.4 million for the year ended December 31, 2009. This favorable decrease was principally due to lower natural gas prices as compared with the prior year period, partially offset by an increase in gathering expenses in the Appalachian Basin resulting from a full year of our third-party gathering system agreement formed in June 2009, whereby our gathering expenses generally exceeded the revenues collected from the investment partnerships by approximately 3%.

Gathering and processing margin for APL was $161.2 million for the year ended December 31, 2010 compared with $115.4 million for the year ended December 31, 2009. This increase was due principally to higher production volumes and higher average natural gas liquids and crude oil commodity prices between periods.

Loss on Mark-to-Market Derivatives

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Loss on mark-to-market derivatives was $20.5 million for the year ended December 31, 2011 as compared with $5.9 million for the year ended December 31, 2010. This unfavorable movement was due primarily due to a $33.5 million unfavorable variance in non-cash mark-to-market adjustments on APL’s derivatives and a $15.7 million unfavorable movement in cash settlements on net cash derivative expense related to APL’s commodity based derivatives, partially offset by a $34.6 million favorable variance of net cash derivative expense related to the early termination of a portion of APL’s derivative contracts in the prior period.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Loss on mark-to-market derivatives was $5.9 million for the year ended

 

60


December 31, 2010 as compared with $35.8 million for the year ended December 31, 2009. This favorable movement was due primarily to a $63.6 million favorable variance in non-cash mark-to-market adjustments on APL’s derivatives and $3.9 million favorable variance in non-cash derivative gains related to early termination of a portion of APL’s derivative contracts, partially offset by a $32.3 million unfavorable variance of net cash derivative expense related to the early termination of a portion of APL’s derivative contracts in the prior period, and a $5.3 million unfavorable movement in cash settlements on net cash derivative expense related to APL’s commodity-based derivatives.

Other, Net

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Other, net was $31.8 million for the year ended December 31, 2011 as compared with $17.4 million for the comparable prior year period. This favorable increase was due primarily to a $14.4 million increase associated with our equity earnings in Lightfoot. During the year ended December 31, 2011, we recorded a gain of $15.0 million pertaining to our share of Lightfoot LP’s gain recognized on the sale of International Resource Partners LP, its metallurgical and steam coal business, in March 2011.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Other, net was $17.4 million for the year ended December 31, 2010 as compared with $15.3 million for the comparable prior year period. This favorable increase was due primarily to a $2.1 million increase associated with our equity earnings in Lightfoot.

OTHER COSTS AND EXPENSES

General and Administrative Expenses

The following table presents our general and administrative expenses and those attributable to APL for each of the respective periods:

 

     Years Ended December 31,  
     2011      2010      2009  

General and Administrative expenses:

        

Atlas Energy

   $ 44,230       $ 3,540       $ 1,652   

Atlas Pipeline

     36,354         34,021         37,280   
  

 

 

    

 

 

    

 

 

 

Total

   $ 80,584       $ 37,561       $ 38,932   
  

 

 

    

 

 

    

 

 

 

Total general and administrative expenses increased to $80.6 million for the year ended December 31, 2011 compared with $37.6 million for the year ended December 31, 2010. Because the Transferred Business was not accounted for by AEI as a stand-alone business unit, it was not practicable for us to allocate general and administrative expenses to it for historical periods. Therefore, the general and administrative expenses for the years ended December 31, 2010 and 2009 were comprised of our stand-alone general and administrative expenses, while the expenses for the year ended December 31, 2011 were comprised of our stand-alone general and administration expenses and that of the Transferred Business. In addition, our general and administrative expenses for the year ended December 31, 2011 included $19.0 million of reimbursements received from Chevron for the transition services we provided during the period. Our $44.2 million of general and administrative expense for the year ended December 31, 2011 was comprised of $17.8 million of net salary and wages expense, $13.1 million of non-cash compensation expense, $1.8 million of syndication expenses related to the cancellation of our Fall 2010 drilling program, $2.1 million of transaction costs related to the acquisition of the Transferred Business, and $9.4 million of other corporate activities. APL’s $36.4 million of general and administrative expense for the year ended December 31, 2011 represents an increase of $2.3 million from the comparable prior year period, which was principally due to an increase in salaries and wages resulting mainly from the expansion of its business.

Depreciation, Depletion and Amortization

The following table presents our depreciation, depletion and amortization expense and that which was attributable to APL for each of the respective periods:

 

     Years Ended December 31,  
     2011      2010      2009  

Depreciation, depletion and amortization:

        

Atlas Energy

   $ 31,938       $ 40,758       $ 43,712   

Atlas Pipeline

     77,435         74,897         75,684   
  

 

 

    

 

 

    

 

 

 

Total

   $ 109,373       $ 115,655       $ 119,396   
  

 

 

    

 

 

    

 

 

 

 

61


Total depreciation, depletion and amortization decreased to $109.4 million for the year ended December 31, 2011 compared with $115.7 million for the comparable prior year period primarily due to a $9.3 million decrease in our depletion expense. Total depreciation, depletion and amortization decreased to $115.7 million for the year ended December 31, 2010 compared with $119.4 million for the comparable prior year period primarily due to a $3.4 million decrease in our depletion expense. The following table presents our depletion expense per Mcfe for our operations for the respective periods:

 

     Years Ended December 31,  
     2011     2010     2009  

Depletion expense (in thousands):

      

Total

   $ 27,430      $ 36,668      $ 40,067   

Depletion expense as a percentage of gas and oil production revenue

     41     39     35

Depletion per Mcfe

   $ 2.09      $ 2.44      $ 2.63   

Depletion expense varies from period to period and is directly affected by changes in our gas and oil reserve quantities, production levels, product prices and changes in the depletable cost basis of our gas and oil properties. For the year ended December 31, 2011, depletion expense decreased $9.3 million to $27.4 million compared with $36.7 million for the year ended December 31, 2010. Our depletion expense of gas and oil properties as a percentage of gas and oil revenues was 41% for the year ended December 31, 2011, compared with 39% for the year ended December 31, 2010, which was primarily due to a decrease in realized natural gas prices between periods. Depletion expense per Mcfe was $2.09 for the year ended December 31, 2011, a decrease of $0.35 per Mcfe from $2.44 for the year ended December 31, 2010. Depletion expense decreased between periods principally due to the $50.7 million impairment of our Chattanooga and Upper Devonian shale fields recorded during the three months ended December 31, 2010 and an overall decrease in production volumes.

For the year ended December 31, 2010, depletion expense decreased $3.4 million to $36.7 million compared with $40.1 million for the year ended December 31, 2009. Our depletion expense of gas and oil properties as a percentage of gas and oil revenues was 39% for the year ended December 31, 2010, compared with 35% for the year ended December 31, 2009. Depletion expense per Mcfe was $2.44 for the year ended December 31, 2010, a decrease of $0.19 per Mcfe from $2.63 for the year ended December 31, 2009. Depletion expense decreased between periods principally due to an overall decrease in production volumes combined with the $156.4 million impairment of our Upper Devonian Shale field recorded during the three months ended December 31, 2009.

Asset Impairment

During the year ended December 31, 2011, we recognized $7.0 million of asset impairment related to gas and oil properties within property, plant and equipment on the consolidated combined balance sheet for our shallow natural gas wells in the Niobrara Shale. This impairment related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2011. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices during the fourth quarter of 2011.

During the year ended December 31, 2010, we recognized $50.7 million of asset impairment related to gas and oil properties within property, plant and equipment on the consolidated combined balance sheet for our shallow natural gas wells in the Chattanooga and Upper Devonian shales. This impairment related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2010. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices.

During the year ended December 31, 2009, we recognized $156.4 million of asset impairment related to gas and oil properties within property, plant and equipment on the consolidated combined balance sheet for our shallow natural gas wells in the Upper Devonian Shale. This impairment related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2009. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices. In addition, during the year ended December 31, 2009, APL evaluated its long-lived assets for impairment and recognized $10.3 million of impairment related to inactive pipelines and a reduction in estimated useful lives.

Gain (Loss) on Asset Sales

During the year ended December 31, 2011, the gain on asset sales was $256.3 million, compared to a loss of $13.7 million for the year ended December 31, 2010. This increase is principally due to APL’s gain on the sale of its 49% non- controlling interest in the Laurel Mountain joint venture which was finalized and recorded in February 2011.

 

62


During the year ended December 31, 2010, the loss on asset sales was $13.7 million, compared to a gain of $108.9 million for the year ended December 31, 2009. This decrease is principally due to APL’s sale of a 51% ownership interest in its Appalachia natural gas gathering system to the Laurel Mountain joint venture during 2009.

Interest Expense and Loss on Early Extinguishment of Debt

The following table presents our interest expense and that which was attributable to APL for each of the respective periods:

 

     Years Ended December 31,  
     2011      2010      2009  

Interest Expense:

        

Atlas Energy

   $ 6,791       $ 3,175       $ 2,744   

Atlas Pipeline

     31,603         87,273         101,309   
  

 

 

    

 

 

    

 

 

 

Total

   $ 38,394       $ 90,448       $ 104,053   
  

 

 

    

 

 

    

 

 

 

Total interest expense decreased to $38.4 million for the year ended December 31, 2011 as compared with $90.4 million for the year ended December 31, 2010. This $52.1 million decrease was primarily due to a $55.7 million decrease related to APL, partially offset by our $3.6 million increase. Our $3.6 million increase in interest expense was primarily due to $4.9 million of accelerated amortization of deferred financing costs for our interim bridge credit facility that was used for the acquisition of the Transferred Business and our note payable to AEI, which was terminated in 2011. The bridge credit facility was terminated and replaced in March 2011. The $55.7 million decrease in interest expense for APL was primarily due to a $21.1 million decrease in interest expense associated with its term loan, an $11.6 million decrease in interest expense associated with its revolving credit facility and a $16.4 million decrease in interest expense associated with its 8.125% Senior Notes. The lower interest expense on APL’s term loan and revolving credit facility was due to the retirement of its term loan and a reduction of its credit facility borrowings with proceeds from the sale of its Elk City system. The lower interest expense on APL’s 8.125% Senior Notes was due to the redemption of the 8.125% Senior Notes in April 2011, with proceeds from the sale of APL’s 49% non-controlling interest in Laurel Mountain.

Total interest expense decreased to $90.4 million for the year ended December 31, 2010 as compared with $104.1 million for the year ended December 31, 2009. This $13.6 million decrease was primarily due to a $14.0 million decrease related to APL, partially offset by our $0.4 million increase. Our $0.4 million increase in interest expense relates to the note payable with AEI, which was terminated in 2011. The $14.0 million decrease in interest expense for APL was due to a $9.5 million decrease in interest rate swap expense due to the interest rate swaps expiring in April 2010 and a $5.8 million decrease in interest expense associated with its term loan. The lower interest expense on APL’s term loan is due to the retirement of the term loan in September 2010 with proceeds from the sale of Elk City.

Loss on early extinguishment of debt of $19.6 million for the year ended December 31, 2011 represents the premium paid for the redemption of the APL 8.125% Senior Notes and APL’s recognition of deferred finance costs related to the redemption. Loss on early extinguishment of debt of $4.4 million for the year ended December 31, 2010 represents the accelerated amortization of deferred financing costs related to the early retirement of APL’s term loan with proceeds from the sale of its Elk City processing and gathering system in September 2010. Loss on extinguishment of debt for the year ended December 31, 2009 represents the accelerated amortization of deferred financing costs related to the early retirement of a portion of APL’s term loan with proceeds from the sale of NOARK gas gathering and interstate pipeline, which was sold in May 2009.

Income (Loss) from Discontinued Operations

For the year ended December 31, 2010, income from discontinued operations, which consists of amounts associated with APL’s Elk City system that was sold in September 2010, was $321.2 million including the gain on sale. For the year ended December 31, 2009, income from discontinued operations, which consists of amounts associated with APL’s NOARK gas gathering and interstate pipeline system that was sold in May 2009 and APL’s Elk City natural gas gathering and processing system that was sold in September 2010, was $84.1 million including the gain on sale.

Income Attributable to Non-Controlling Interests

Income attributable to non-controlling interests was $257.6 million for the year ended December 2011 as compared with $245.8 million for the comparable prior year period. Income attributable to non-controlling interests includes an

 

63


allocation of APL’s net income (loss) to non-controlling interest holders. The increase between the year ended December 31, 2011 and the prior year comparable period was primarily due to the increase in APL’s net earnings between periods, which was related to an increase in APL’s gathering and processing revenue.

Income attributable to non-controlling interests was $245.8 million for the year ended December, 2010 as compared with $53.9 million for the comparable prior year period. Income attributable to non-controlling interests includes an allocation of APL’s net income (loss) to non-controlling interest holders. The increase between the year ended December 31, 2010 and the prior year comparable period was primarily due to APL’s increase in net earnings between periods.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary sources of liquidity are cash generated from operations, capital raised through investment partnerships, and borrowings under our credit facility. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and quarterly distributions to our common unitholders. In general, we expect to fund:

 

   

Cash distributions and maintenance capital expenditures through existing cash and cash flows from operating activities;

 

   

Expansion capital expenditures and working capital deficits through cash generated from operations, additional borrowings and capital raised through investment partnerships; and

 

   

Debt principal payments through additional borrowings as they become due or by the issuance of additional common units or asset sales.

We rely on cash flow from operations and our credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. We believe that we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve month period. However, we are subject to business, operational and other risks that could adversely affect our cash flow. We may supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings, the issuance of additional common units, the sale of assets and other transactions.

Credit Facility

On March 22, 2011, we entered into a new credit facility with a syndicate of banks that matures in March 2016. The credit facility has maximum lender commitments of $300 million and a current borrowing base of $160 million. The borrowing base is redetermined semiannually in May and November subject to changes in gas and oil reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes we issued. Up to $20.0 million of the credit facility may be in the form of standby letters of credit. The facility is secured by substantially all of our assets and is guaranteed by substantially all of our subsidiaries (excluding APL and its subsidiaries). The credit agreement contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of our assets. The credit agreement also requires us to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011, a ratio of current assets (as defined in the credit agreement) to current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011. Based on the definitions contained in the credit facility, our ratio of current assets to current liabilities was 1.7 to 1.0, our ratio of Total Funded Debt to EBITDA was 0.01 to 1.0 and our ratio of EBITDA to Consolidated Interest Expense was 63.3 to 1.0 at December 31, 2011.

Upon the closing of the Atlas Resource Partners transaction, most of the collateral which secures our current credit facility will be owned by Atlas Resource Partners. Accordingly, we anticipate that our credit facility will terminate and that Atlas Resource Partners will enter into a senior secured revolving credit facility that will be substantially similar to our current credit facility. We anticipate that the credit facility will allow Atlas Resource Partners to borrow up to the determined amount of the borrowing base, which will be based upon the loan collateral value assigned to our various natural gas and oil properties and other assets.

 

64


Cash Flows – Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010

Net cash provided by operating activities of $88.2 million for the year ended December 31, 2011 represented an unfavorable movement of $69.1 million from net cash provided by operating activities of $157.3 million for the comparable prior year period. The decrease was derived principally from a $20.1 million unfavorable movement in working capital, a $64.5 million increase in distributions paid to non-controlling interests and a $23.5 million unfavorable movement in net cash provided by discontinued operations, partially offset by a $30.1 million increase in net income excluding non-cash items and an $8.9 million increase in distributions received from unconsolidated subsidiaries. The non-cash charges which impacted net income include a $332.1 million increase in net income from continuing operations and a favorable movement in non-cash gain on derivatives of $11.7 million, partially offset by a $270.0 million unfavorable movement in gains on asset sales, a $28.8 million unfavorable movement in non-cash expenses, including loss on early extinguishment of debt, asset impairment loss, compensation expense, depreciation, depletion and amortization and amortization of deferred financing costs and a $14.9 million movement in equity income from unconsolidated subsidiaries. The increase in net income from continuing operations was primarily due to a $256.3 million net gain on the sale of APL’s interest in Laurel Mountain, partially offset by a decrease in well construction and completion margin due to the cancellation of our fall 2010 drilling program, which was the result of our announcement of the acquisition of the Transferred Business in November 2010. The movement in cash distributions to non-controlling interest holders was due principally to increases in the cash distributions of APL. The movement in working capital was principally due to a $60.6 million unfavorable movement in accounts receivable and other current assets, due to an increase in subscriptions receivable for funds raised for our new drilling program in the fourth quarter of 2011 and an increase in APL’s accounts receivable between the periods, partially offset by a $40.6 million favorable movement in accounts payable and other current liabilities.

Net cash provided by investing activities of $14.2 million for the year ended December 31, 2011 represented an unfavorable movement of $488.1 million from net cash provided by investing activities of $502.3 million for the comparable prior year period. This unfavorable movement was principally due to a $669.2 million unfavorable movement in cash provided by discontinued investing activities related to APL’s sale of its Elk City system in September 2010, a $70.7 million unfavorable movement in investments in our and APL’s unconsolidated subsidiaries, including APL’s 20% investment in the West Texas LPG Pipeline, a $153.4 million unfavorable movement in capital expenditures and a $0.5 million unfavorable movement in other assets, partially offset by a $405.7 million increase in net proceeds from asset sales associated with APL’s sale of its investment in the Laurel Mountain joint venture. See further discussion of capital expenditures under “- Capital Requirements”.

Net cash used in financing activities of $25.2 million for the year ended December 31, 2011 represented a change of $635.2 million from $660.4 million for the comparable prior year period. This movement was principally due to a net $336.0 million increase in APL’s net borrowings under its credit facility, a $152.4 million increase in net proceeds from the issuance of long-term debt, a $104.2 million decrease in repayments of long-term debt, an $85.5 million non-cash transaction adjustment related to the acquisition of the Transferred Business and a $18.4 million favorable movement in other financing activities, partially offset by a $31.5 million decrease in net proceeds from APL’s equity and preferred unit offerings and an $29.8 million increase in distributions paid to unitholders.

Cash Flows—Year Ended December 31, 2010 Compared with Year Ended December 31, 2009

Net cash provided by operating activities of $157.3 million for the year ended December 31, 2010 represented an unfavorable movement of $79.4 million from net cash provided by operating activities of $236.7 million for the comparable prior year period. The decrease was derived principally from by a $77.1 million unfavorable movement in working capital and an $18.8 million unfavorable movement in net cash provided from discontinued operations, partially offset by a $9.0 million increase in net income excluding non-cash items and a $7.5 million increase in distributions received from unconsolidated subsidiaries. The non-cash charges which impacted net income include a $111.9 million unfavorable movement in non-cash expenses, including asset impairment loss, compensation expense, depreciation, depletion and amortization and amortization of deferred financing costs, an unfavorable movement in non-cash gain on derivatives of $40.6 million and a $2.7 million movement in equity in income from unconsolidated subsidiaries, partially offset by a $41.6 million increase in net income from continuing operations and a $122.6 million favorable movement in loss on asset sales. The increase in net income from continuing operations was primarily due to an increase in APL’s gathering and processing margin partially offset by a decrease in our well construction and completion margin due to the cancellation of our fall 2010 drilling program, which was the result of our announcement of the acquisition of the Transferred Business in November 2010. The movement in working capital was principally due to a $73.8 million unfavorable movement in accounts payable and other current liabilities, due to a reduction in our liabilities associated with drilling contracts and well drilling and completion liabilities in 2010 and a $3.2 million favorable movement in accounts receivable and other current assets.

 

65


Net cash provided by investing activities of $502.3 million for the year ended December 31, 2010 represented a favorable movement of $359.7 million from net cash provided by investing activities of $142.6 million for the comparable prior year period. This favorable movement was principally due to a $403.8 million favorable movement in cash provided by discontinued investing activities primarily related to APL’s sale of its Elk City system in September 2010, a $70.2 million favorable movement in capital expenditures and a $2.0 million favorable movement in other assets, partially offset by an $24.8 million unfavorable movement in investments in our and APL’s unconsolidated subsidiaries and a $91.5 million decrease in net proceeds from asset sales. See further discussion of capital expenditures under “- Capital Requirements”.

Net cash used in financing activities of $660.4 million for the year ended December 31, 2010 represented a change of $274.9 million from $385.5 million for the comparable prior year period. This movement was principally due to a net $250.0 million decrease in APL’s net borrowings under its credit facility and a $159.8 million increase in repayments of long-term debt, partially offset by a $22.4 million increase in net proceeds from APL’s equity and preferred unit offerings, a $25.6 million non-cash transaction adjustment related to the acquisition of the Transferred Business, an $83.3 million movement in net investment received from AEI prior to February 17, 2011, a $0.3 million decrease in distributions paid to unitholders and a $3.3 million movement in deferred financing costs and other.

Capital Requirements

Our capital requirements consist primarily of:

 

   

maintenance capital expenditures — capital expenditures we make on an ongoing basis to maintain our current levels of production over the long term; and

 

   

expansion capital expenditures — capital expenditures we make to increase our current levels of production for longer than the short-term and includes new leasehold interests and the development and exploitation of existing leasehold interests through acquisitions and investments in our drilling partnerships.

Atlas Pipeline Partners. APL’s operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational and environmental regulations. APL’s capital requirements consist primarily of:

 

   

maintenance capital expenditures to maintain equipment reliability and safety and to address environmental regulations; and

 

   

expansion capital expenditures to acquire complementary assets and to expand the capacity of its existing operations.

The following table summarizes our consolidated maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):

 

     Years Ended December 31,  
     2011      2010      2009  

Atlas Energy

        

Maintenance capital expenditures

   $ 9,833       $ —         $ —     

Expansion capital expenditures

     37,491         93,608         99,302   
  

 

 

    

 

 

    

 

 

 

Total

   $ 47,324       $ 93,608       $ 99,302   
  

 

 

    

 

 

    

 

 

 

Atlas Pipeline

        

Maintenance capital expenditures

   $ 18,247       $ 10,921       $ 3,750   

Expansion capital expenditures

     227,179         34,831         106,524   
  

 

 

    

 

 

    

 

 

 

Total

   $ 245,426       $ 45,752       $ 110,274   
  

 

 

    

 

 

    

 

 

 

Consolidated Combined

        

Maintenance capital expenditures

   $ 28,080       $ 10,921       $ 3,750   

Expansion capital expenditures

     264,670         128,439         205,826