ITEM 1: BUSINESS
Overview
Atlas America Public #9 LTD. (“we, “us” or the “Partnership”) is a Pennsylvania limited partnership and was formed on July 27, 2000 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP). ARP is a publicly traded master limited partnership and an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. ARP is a leading sponsor and manager of tax-advantaged investment partnerships, in which it co-invests, to finance a portion of its natural gas and oil production activities.
On February 27, 2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS). Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of the ARP’s general partner interest.
The Partnership has drilled and currently operates wells located in Pennsylvania and Ohio. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group (February 27, 2015 and prior, Atlas Energy), for administrative services. (See Item 11: “Executive Compensation”).
The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.
The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.
The prices at which the Partnership’s natural gas and oil will be sold are uncertain and the Partnership is not guaranteed a specific natural gas price for the sale of its natural gas production. Changes in natural gas and oil prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas and oil prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas and oil that the Partnership can produce economically.
Historically, there has been no need to borrow funds from the MGP to fund operations as the amount of funds generated by the Partnership’s operations has been adequate to fund future operations and distributions to the partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s operations for at least the next 12 months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern.
After formation, we received total cash subscriptions from investors of $14,905,500 which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreement. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $6,256,300. We have drilled 85 development wells within the Clinton/Medina and Upper Devonian Sandstones geological formations in Pennsylvania and Ohio.
Business Strategy
We intend to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling (See Item 2:
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, 2015 and 2014. Proved reserves are the estimated quantities of crude oil and natural gas 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. 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., an independent third-party reserve engineer. 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, 2015 is included as Exhibit 99.1 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 during the years ended December 31, 2015 and 2014 and are adjusted for basis differentials:
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 MGP’s prescribed internal control procedures by its reserve engineers. For the periods presented, Wright & Company, Inc., 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. The independent reserves engineer’s evaluation was based on more than 39 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions and government regulations. Our MGP’s 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 MGP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 17 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our MGP’s Senior Engineering Staff and management, with final approval by our MGP’s 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 & 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. 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. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. We base the estimates on operating methods and conditions prevailing as of the dates indicated:
(1)
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, 2015 and 2014 calculations of standardized measure, which is, therefore, the same as the PV-10 value.
(2)
This value per limited partner unit is determined by following the methodology used for determining our proved reserves using the data discussed above. However, this value does not necessarily reflect the fair market value of a unit, and each unit is illiquid. Also, the value of the unit for purposes of presentment of the unit to our MGP for purchase is different, because it is calculated under a formula set forth in the Partnership Agreement.
(3)
The Partnership does not have any proved undeveloped reserves as of December 31, 2015 and 2014.
(4)
We have experienced significant downward revisions of our natural gas and oil reserves volumes and values to zero in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of our gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations.
Productive Wells
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 and net wells are the sum of our fractional working interests in gross 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, 2015:
Developed Acreage
The following table sets forth information about our developed natural gas and oil acreage as of December 31, 2015:
The leases for our developed acreage generally have terms that extend for the life of the wells. 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:
ITEM 3: LEGAL PROCEEDINGS
We are party to various routine legal proceedings arising out of 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 Item 8: Note 9 Commitments and Contingencies).
Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.
ITEM 4:
ITEM 4: MINE SAFETY DISCLOSURES (Not applicable)
PART II
ITEM 5:
ITEM 5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
There is no established public trading market for our units and we do not anticipate that a market for our units will develop. Our units may be transferred only in accordance with the provisions of Article VI of our Partnership Agreement which requires:
●
our MGP’s consent;
●
the transfer not result in materially adverse tax consequences to us; and
●
the transfer does not violate federal or state securities laws.
An assignee of a unit may become a substituted partner only upon meeting the following conditions:
●
the assignor gives the assignee the right;
●
our MGP consents to the substitution;
●
the assignee pays to us all costs and expenses incurred in connection with the substitution; and
●
the assignee executes and delivers the instruments, which our MGP requires to effect the substitution and to confirm his or her agreement to be bound by the term of our partnership agreement.
A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote. As of December 31, 2015, we had 508 limited partners.
Our MGP reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. We distribute those funds which our MGP determines are not necessary for us to retain. We will not advance or borrow funds for purposes of making distributions. During the years ended December 31, 2015 and 2014, we distributed the following:
ITEM 7:
ITEM 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The discussion and analysis presented below provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with “Item 8:
ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
Atlas America Public #9 LTD.
We have audited the accompanying balance sheets of Atlas America Public #9 LTD. (a Pennsylvania limited partnership) (the “Partnership”) as of December 31, 2015 and 2014, and the related statements of operations, comprehensive loss, changes in partners’ deficit, and cash flows for each of the two years in the period ended December 31, 2015. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Atlas America Public #9 LTD. as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
April 14, 2016
ATLAS AMERICA PUBLIC #9 LTD.
BALANCE SHEETS
DECEMBER 31, 2015 AND 2014
See accompanying notes to financial statements.
ATLAS AMERICA PUBLIC #9 LTD.
STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2015 AND 2014
See accompanying notes to financial statements.
ATLAS AMERICA PUBLIC #9 LTD.
STATEMENTS OF COMPREHENSIVE LOSS
YEARS ENDED DECEMBER 31, 2015 AND 2014
See accompanying notes to financial statements.
ATLAS AMERICA PUBLIC #9 LTD.
STATEMENTS OF CHANGES IN PARTNERS’ DEFICIT
YEARS ENDED DECEMBER 31, 2015 AND 2014
See accompanying notes to financial statements.
ATLAS AMERICA PUBLIC #9 LTD.
STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2015 AND 2014
See accompanying notes to financial statements.
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2015 AND 2014
NOTE 1-BASIS OF PRESENTATION
Atlas America Public #9 LTD.(the “Partnership”) is a Pennsylvania limited partnership, formed on July 27, 2000 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).
On February 27, 2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS). Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of the ARP’s general partner interest.
The Partnership has drilled and currently operates wells located in Pennsylvania and Ohio. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group (February 27, 2015, and prior, Atlas Energy), for administrative services.
The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.
The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.
The prices at which the Partnership’s natural gas and oil will be sold are uncertain and the Partnership is not guaranteed a specific natural gas price for the sale of its natural gas production. Changes in natural gas and oil prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas and oil prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas and oil that the Partnership can produce economically.
Liquidity and Capital Resources
The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners.
The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the fourth quarter of 2014 and throughout 2015. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact the Partnership’s outlook. The Partnership has experienced downward revisions of its natural gas and oil reserves volumes and values due to the significant declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be opportunistic and aggressive in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations.
Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations have been adequate to fund its obligations and distributions to its partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern.
If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.
NOTE 2-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of the Partnership’s financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices (see “Revenue Recognition”). Actual results could differ from those estimates.
Receivables
Accounts receivable trade-affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2015 and 2014, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.
Asset retirement receivable - affiliate on the balance sheets consist solely of the net amount withheld from distributions for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the Partnership’s wells less any amounts used for the plugging and abandonment of the Partnership’s wells. As amounts are withheld, they are paid to the MGP and held until the Partnerships wells are plugged and abandoned, at which time, the funds are used to cover the actual expenditures incurred. The total amount withheld from distributions will not exceed the MGP’s estimate of the costs to plug and abandon the Partnership’s wells.
The following is a reconciliation of the Partnership’s asset retirement receivable - affiliate for the periods indicated:
Gas and Oil Properties
Gas and oil properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.
The Partnership follows the successful efforts method of accounting for gas and oil producing activities. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six mcf of natural gas.
The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties.
Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale or retirement of an individual well, the Partnership reclassifies the costs associated with the well and credits the proceeds to accumulated depletion and impairment within its balance sheets.
Impairment of Long-Lived Assets
The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value (see Note 4).
The review of the Partnership’s gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by the discounted cash flows) and the carrying value of the assets.
The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.
In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.
Derivative Instruments
The Partnership’s MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (See Note 6). The derivative instruments recorded on the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ (deficit) capital on the Partnership’s balance sheets and reclassified to the Partnership’s statements of operations at the time the originally hedged physical transactions affected earnings.
Asset Retirement Obligations
The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (See Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.
Income Taxes
The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the financial statements. The federal and state income taxes related to the Partnership were immaterial to the financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the financial statements.
The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2015 and 2014.
The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2015.
Environmental Matters
The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2015 and 2014.
Concentration of Credit Risk
The Partnership sells natural gas and crude oil, under contracts to various purchasers in the normal course of business. For the year ended December 31, 2015, the Partnership had four customers that individually accounted for approximately 27%, 17%, 12% and 12% of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2014, the Partnership had three customers that individually accounted for approximately 33%, 22%, and 13% of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity.
Revenue Recognition
The Partnership generally sells natural gas and crude oil at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.
The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and condensate, and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (See “-Use of Estimates”). The Partnership had unbilled revenues at December 31, 2015 and 2014 of $29,600 and $75,500, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
Comprehensive Income (Loss)
Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s financial statements and, at December 31, 2015, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 6). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).
Recently Issued Accounting Standards
In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. The updated guidance is effective as of January 1, 2017 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its financial statements.
In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its financial statements and its method of adoption.
NOTE 3-PARTICIPATION IN REVENUES AND COSTS
Working Interest
The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.
The MGP and the limited partners generally participated in revenues and costs in the following manner:
(1)
Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 7% of the partnership revenues.
(2)
These costs will be charged to the partners in the same ratio as the related production revenues are credited.
NOTE 4-PROPERTY, PLANT AND EQUIPMENT
The following is a summary of natural gas and oil properties at the dates indicated:
The Partnership recorded depletion expense on natural gas and oil properties of $27,600 and $166,000 for the years ended December 31, 2015 and 2014, respectively.
During the year ended December 31, 2015, the Partnership recognized $457,200, of impairment related to gas and oil properties on its balance sheet. This impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2015. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement. During the year ended December 31, 2014, the Partnership recognized $1,282,200 of impairment related to gas and oil properties on its balance sheet.
As a result of the recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our balance sheet at December 31, 2015 was primarily related to the estimated salvage value of such properties. The estimated salvage values were based on the MGP’s historical experience in determining such values and were discounted based on the remaining lives of those wells using an assumed credit adjusted risk-free interest rate.
NOTE 5-ASSET RETIREMENT OBLIGATIONS
The estimated liability for asset retirement obligations was based on the MGP’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.
The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On a partnership-by-partnership basis, the MGP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells and current and future costs. Generally, the MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership, the MGP will assume the related asset retirement obligations of the limited partners. As of December 31, 2015, the MGP withheld $188,100 of net production revenue for future plugging and abandonment costs.
A reconciliation of the Partnership’s asset retirement obligation liability for well plugging and abandonment costs for the periods indicated is as follows:
NOTE 6-DERIVATIVE INSTRUMENTS
The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally put options, in connection with the Partnership’s commodity price risk management activities. Management uses financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike price, and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged.
The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $13,400 and $12,800 at December 31, 2015 and 2014, respectively.
At December 31, 2015, the Partnership had the following commodity derivatives:
Natural Gas Put Options
(1)
“MMBtu” represents million British Thermal Units.
(2)
Fair value based on forward NYMEX natural gas prices, as applicable.
The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated:
Put Premiums Payable
During June 2012, a premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At December 31, 2015 and 2014, the put premiums were recorded as short-term payables to affiliate of $6,200 and $4,500, respectively, and long-term payables to affiliate of $0 and $5,100, respectively.
NOTE 7-FAIR VALUE OF FINANCIAL INSTRUMENTS
The Partnership has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:
Level 1-Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2-Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
Level 3-Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (See Note 6). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. The fair values of these derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and the pricing formula utilized in the derivative instrument.
Information for assets and liabilities measured at fair value was as follows:
Other Financial Instruments
The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale of such financial instruments. The Partnership’s other current assets and liabilities on its balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (See Note 5). There were no adjustments to retirement obligations for the year ended December 31, 2015. Adjustments to retirement obligations defined as Level 3, measured at fair value on a non-recurring basis was $537,900 for the year ended December 31, 2014.
The Partnership estimates the fair value of its long-lived assets in conjunction with the review of assets for impairment or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions, and judgments regarding such events or circumstances. For the years ended December 31, 2015 and 2014, the Partnership recognized a $457,200 and $1,282,200, respectively, of impairment of long-lived assets which was defined as a Level 3 fair value measurement (See Note 4: Property, Plant, and Equipment).
NOTE 8-CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations, are payable at $337 per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are generally payable at 13% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf.
The following table provides information with respect to these costs and the periods incurred:
The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts payable trade-affiliate on the Partnership’s balance sheet includes the net production expenses due to the MGP. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP.
NOTE 9-COMMITMENTS AND CONTINGENCIES
General Commitments
Subject to certain conditions, limited partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the Partnership Agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.
Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of December 31, 2015 and 2014, the MGP withheld $188,100 and $9,900, respectively, of net production revenue for future plugging and abandonment costs.
Legal Proceedings
The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.
Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.
NOTE 10-SUBSEQUENT EVENTS
Management has considered for disclosure any material subsequent events through the date the financial statements were issued.
NOTE 11-SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED)
Gas and Oil Reserve Information. The preparation of the Partnership’s natural gas and oil reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. The reserve information included below is attributable to the reserves of the Partnership and was derived from the reserve reports prepared for Atlas America Public #9 LTD. annual Form 10-K for the years ended December 31, 2015 and 2014 (See Note 2). For the periods presented, Wright & Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to the Partnership. The reserve information for the Partnership includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 39 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The MGP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 17 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the MGP’s Senior Engineering Staff and management, with final approval by the MGP’s President.
The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas, crude oil, and natural gas liquids owned at year end. Proved developed reserves are those 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. The proved reserves quantities and future net cash flows as of December 31, 2015 and 2014 were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2015 and 2014, including adjustments related to regional price differentials and energy content.
There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of gas and oil reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in gas and oil prices and in production and development costs and other factors, for their effects have not been proved.
Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows:
(1)
The downward revision in natural gas forecasts is primarily due to forecast adjustments in order to better reflect actual production. The downward revision in oil forecasts is primarily due to forecast adjustments in order to better reflect actual production.
(2)
The downward revision in natural gas forecasts is primarily due to a decrease in the SEC base pricing from the prior year, resulting in a shorter economic life.
(3)
We have experienced significant downward revisions of our natural gas and oil reserves volumes and values to zero in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations.
Capitalized Costs Related to Gas and Oil Producing Activities. The components of capitalized costs related to gas and oil producing activities of the Partnership during the periods indicated were as follows:
Results of Operations from Gas and Oil Producing Activities. The results of operations related to the Partnership’s gas and oil producing activities during the periods indicated were as follows:
Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved gas and oil reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2015 and 2014, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations:
_______________
(1)
We have experienced significant downward revisions of our natural gas and oil reserves volumes and values to zero in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations.
ITEM 9:
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A:
ITEM 9A: CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2015, our disclosure controls and procedures were effective at the reasonable assurance level.
Management’s Report on Internal Control over Financial Reporting
The management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our general partner’s Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 Internal Control - Integrated Framework (COSO framework).
An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.
Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2015. This annual report does not include an attestation report by our registered public accounting firm regarding internal control over financial reporting because such a report is not required pursuant to the rules of the Securities and Exchange Commission.
There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART III
ITEM 10:
ITEM 10: DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Our general partner manages our activities. Unitholders do not directly or indirectly participate in our management or operation or have actual or apparent authority to enter into contracts on our behalf or to otherwise bind us.
Officers and Key Operations Employees of Our General Partner
The following table sets forth information with respect to those persons who serve as the officers of and on the board of directors of, our general partner:
Name
Age
Position(s)
Jeffrey M. Slotterback
Chief Financial Officer
Freddie M. Kotek
Senior Vice President of Investment Partnership Division
Daniel C. Herz has served as Executive Vice President of the MGP since May 2011. He has served as ARP’s Chief Executive Officer since August 2015 and as President of Atlas Energy Group since April 2015. Mr. Herz has served as President and a director of the general partner of Atlas Growth Partners, L.P. since its inception in 2013. Mr. Herz served as Senior Vice President of Corporate Development and Strategy of Atlas Energy Group from March 2012 to April 2015. Mr. Herz served as Senior Vice President of Corporate Development and Strategy of Atlas Energy’s general partner from February 2011 until February 2015. Mr. Herz was Senior Vice President of Corporate Development of Atlas Pipeline Partners GP, LLC from August 2007 until February 2015. He also was Senior Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Energy Resources, LLC from August 2007 until February 2011. Before that, Mr. Herz was Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Pipeline Partners GP, LLC from December 2004 and of Atlas Energy’s general partner from January 2006.
Freddie M. Kotek has been Chairman of the MGP since September 2001 and has served as its Chief Executive Officer and President since January 2002. He has served as ARP’s Senior Vice President of the Investment Partnership Division since August 2015 and served as Senior Vice President of Investment Partnership Division of Atlas Energy Group since March 2012. Mr. Kotek has also served as Executive Vice President and a director of the board of directors of the general partner of Atlas Growth Partners, L.P. since its inception in 2013. Mr. Kotek served as Senior Vice President of the Investment Partnership Division of Atlas Energy’s general partner from February 2011 until February 2015. Mr. Kotek was an Executive Vice President of Atlas Energy, Inc. from February 2004 until February 2011 and served as a director from September 2001 until February 2004. Mr. Kotek also was Chief Financial Officer of Atlas Energy, Inc. from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America, Inc. from 1995 until May 2004 and President of Resource Leasing, Inc. (a wholly owned subsidiary of Resource America, Inc.) from 1995 until May 2004.
Jeffrey M. Slotterback has served as Chief Financial Officer of each of the MGP and ARP since September 2015. Mr. Slotterback has served as Chief Financial Officer of Atlas Energy Group since September 2015 and served as its Chief Accounting Officer from March 2012 to October 2015. Mr. Slotterback has also served as the Chief Financial Officer of the general partner of Atlas Growth Partners, L.P. since September 2015 and served as its Chief Accounting Officer from its inception in 2013 to October 2015. Mr. Slotterback served as Chief Accounting Officer of Atlas Energy’s general partner from March 2011 until February 2015. Mr. Slotterback was the Manager of Financial Reporting for Atlas Energy, Inc. from July 2009 until February 2011 and then served as the Manager of Financial Reporting for Atlas Energy GP, LLC from February 2011 until March 2011. Mr. Slotterback served as Manager of Financial Reporting for both Atlas Energy GP, LLC and Atlas Pipeline Partners GP, LLC from May 2007 until July 2009. Mr. Slotterback was a Senior Auditor at Deloitte and Touche, LLP from 2004 until 2007, where he focused on energy and health care clients. Mr. Slotterback is a Certified Public Accountant.
Key Operations Employees
Mark D. Schumacher has served as the Chief Operating Officer of the MGP since January 2014. He has served as ARP’s President since April 2015 and as a Senior Vice President of Atlas Energy Group since April 2015. Mr. Schumacher served as Chief Operating Officer of Atlas Energy Group from October 2013 to April 2015. Mr. Schumacher has been the Executive Vice President of Operations of the general partner of Atlas Growth Partners, L.P. since its inception in 2013. He served as Executive Vice President of Atlas Energy from July 2012 to October 2013. From August 2008 to July 2012, Mr. Schumacher served as President of Titan Operating, LLC, which ARP acquired in July 2012. From November 2006 until August 2008, Mr. Schumacher served as President of Titan Resources, LLC, which built an acreage position in the Barnett Shale that it sold to XTO Energy in October 2008. From February 2005 to November 2006, Mr. Schumacher served as the Team Lead of EnCana Oil & Gas (USA) Inc. where he was responsible for Encana’s Barnett Shale development. Mr. Schumacher was an engineer with Union Pacific Resources from 1984 to 2000. Mr. Schumacher has over 29 years of experience in drilling, production and reservoir engineering management, operations and business development in East Texas, Austin Chalk, Barnett Shale, Mid-Continent, the Rockies, the Gulf of Mexico, Latin America and Canada.
Code of Business Conduct and Ethics
Because the Partnership does not directly employ any persons, the MGP has determined that the partnership will rely on a code of business conduct and ethics that applies to the principal executive officer, principal financial officer, and principal accounting officer of our general partner, as well as to persons performing services for us generally. We will make a printed copy of our code of ethics available to any limited partner who so requests. Requests for print copies may be directed to us as follows: Atlas Resource Partners, L.P., Park Place Corporate Center One, 1000 Commerce Drive, 4th Floor, Pittsburgh, Pennsylvania 15275-1011, Attention: Secretary. The code of business conduct is also posted, and any waivers we grant thereunder will be posted, on our website at www.atlasresourcepartners.com.
ITEM 11:
ITEM 11: EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Introduction
We do not directly employ any persons to manage or operate our businesses. Instead, all of the persons (including executive officers of our general partner and other personnel) necessary for the management of our business are employed and compensated by Atlas Energy. Pursuant to our partnership agreement, our general partner manages our operations and activities through its and its affiliates’ employees (including employees of Atlas Energy and its general partner). No officer or director of our MGP receives any direct remuneration or other compensation from us. (See “Item 13: Certain Relationships and Related Transactions” for a discussion of compensation paid by us to our MGP).
ITEM 12:
ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
As of December 31, 2015, we had 1,500 units outstanding. No officer or director of our MGP owns any units. Although, subject to certain conditions, investor partners may present their units to us for purchase, the MGP is not obligated by the Partnership Agreement to purchase more than 5% of our total outstanding units in any calendar year. The MGP is owned 100% by ARP, whose ultimate parent was Atlas Energy Group at December 31, 2015.
ITEM 13:
ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Our Relationship with Atlas Resources, LLC
Gas and Oil Revenues. Our MGP is allocated 35.5% of our gas and oil revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 15% of our subscriptions, its payment of 100% of the tangible costs of drilling and completing our wells and its contributions to us of all of our gas and oil leases for a total capital contribution of $6,256,300. During the year ended December 31, 2015, our MGP paid $29,600 for our net production expenses. During the year ended December 31, 2014, our MGP received $76,300 for our net production revenues.
Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $337 per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are generally payable at 13% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf.
The following table provides information with respect to these costs and the periods incurred:
Other Compensation. For the years ended December 31, 2015 and 2014, our MGP did not advance any funds to us, nor did it provide us with any equipment, supplies or other services.
ITEM 14:
ITEM 14: PRINCIPAL ACCOUNTANT FEES AND SERVICES
For the years ended December 31, 2015 and 2014, the accounting fees and services charged by Grant Thornton, LLP, our independent auditors, were as follows:
Audit Committee Pre-Approval Policies and Procedures
The audit committee of our general partner, on at least an annual basis, will review audit and non-audit services performed by Grant Thornton LLP as well as the fees charged by Grant Thornton LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee. All of such services and fees were pre-approved during 2015 and 2014.
PART IV
ITEM 15:
ITEM 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
EXHIBIT INDEX
Description
4(a)
Certificate of Limited Partnership for Atlas America Public #9 LTD. (1)
4(b)
Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #9 LTD. (1)
4(c)
Drilling and Operating Agreement for Atlas America Public #9 LTD. (1)
23.1
Consent of Wright & Company, Inc.
31.1
Rule 13a-14(a)/15(d) - 14 (a) Certification
31.2
Rule 13a-14(a)/15(d) - 14 (a) Certification.
32.1
Section 1350 Certification.
32.2
Section 1350 Certification.
99.1
Summary Reserve Report
Interactive Data File
(1)
Filed on September 8, 2000 in our Form SB-2 Registration Statement dated September 8, 2000, as amended, File No. 333-44130
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ATLAS AMERICA PUBLIC #9 LTD.
BY: ATLAS RESOURCES, LLC, ITS GENERAL PARTNER
Date: April 14, 2016
By:
/s/ FREDDIE M. KOTEK
Freddie M. Kotek, Chairman of the Board and Chief Executive Officer (principal executive officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following person on behalf of the registrant and in the capacities and on the dates indicated.
Date: April 14, 2016
By:
/s/ FREDDIE M. KOTEK
Freddie M. Kotek, Chairman of the Board and Chief Executive Officer (principal executive officer)
Date: April 14, 2016
By:
/s/ JEFFREY M. SLOTTERBACK
Jeffrey M. Slotterback, Chief Financial Officer (principal financial officer and principal accounting officer)
Date: April 14, 2016
By:
/s/ MATTHEW J. FINKBEINER
Matthew J. Finkbeiner, Chief Accounting Officer (principal accounting officer)
Date: April 14, 2016
By:
/s/ DANIEL C. HERZ
Daniel C. Herz, Executive Vice President and Director