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ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP - 10-K - : 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: Financial Statements and Supplementary Data, which contains our financial statements.

The following discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. Forward-looking statements speak only as of the date the statements were made. The matters discussed in these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from those made, projected or implied in the forward-looking statements. We believe the assumptions underlying the financial statements are reasonable. However, our financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future.

BUSINESS OVERVIEW

Atlas America Public #12-2003 Limited Partnership ("we", "us" or the "Partnership") is a Delaware limited partnership and formed on July 15, 2003 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 Resources 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.


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The Partnership has drilled and currently operates wells located in Pennsylvania. 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 cash flow from our operations has been adequate to fund our obligations and distributions to our partners. However, the recent significant declines in commodity prices have challenged our ability to fund our operations and may make it uneconomical to produce our wells until they are depleted as we originally intended. Accordingly, the MGP determined that there is substantial doubt about our ability to continue as a going concern. The MGP intends, as necessary, to continue our operations and to fund our obligations for at least the next twelve months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to our ability to continue as a going concern.

The following discussion provides information to assist in understanding our financial condition and results of operations. Our operating cash flows are generated from our wells, which primarily produce natural gas, but also some oil. Our produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP, as operator, a monthly well supervision fee, which covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:



  ? Well tending, routine maintenance and adjustment;


     ?  Reading meters, recording production, pumping, maintaining appropriate
        books and records; and


  ? Preparation of reports for us and government agencies.


The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials, and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials, and a competitive charge for service performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month per well to cover the estimated future plugging and abandonment costs of the well. As of December 31, 2015, our MGP withheld $721,200 of net production revenue for this purpose.



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MARKETS AND COMPETITION

The availability of a ready market for natural gas and oil produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in gas and oil producing countries and regions, market demand, competition from other energy sources, the effect of federal regulation on the sale of natural gas and oil in interstate commerce, other governmental regulation of the production and transportation of natural gas and oil and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is responsible for selling our production. During 2015 and 2014, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competing in selling natural gas and oil production. While it is impossible to accurately determine our comparative position in the industry, we do not consider our operations to be a significant factor in the industry.

Natural Gas. The MGP markets the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market the gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indices for the Appalachian Basin are Dominion South Point, Tennessee Gas Pipeline, Transco Leidy Line, Columbia Appalachia, NYMEX and Transco Zone 5.

We do not hold firm transportation obligations on any pipeline that requires payment of transportation fees regardless of natural gas production volumes. As is customary in certain of our other operating areas, we occasionally commit a predictable portion of monthly production to the purchaser in order to maintain a gathering agreement.

Crude Oil. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking charges. We do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining "dry" gas to meet pipeline specifications for transport to end users or marketers operating on the receiving pipeline. The resulting dry natural gas is sold as described above and our NGLs are generally priced using the Mont Belvieu (TX) or Conway (KS) regional processing indices. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a volumetric retention by the processing and fractionation facility. We do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

For the year ended December 31, 2015, Chevron Natural Gas accounted for approximately 74% of our total natural gas, oil and NGL production revenues, with no other single customer accounting for more than 10% of revenues for this period.

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.

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 causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. 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 in the development of new natural gas, oil and NGL reserves.

Our future gas and oil reserves, production, cash flow, our ability to make distributions to our unitholders, depend on our success in producing our current reserves efficiently. We face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decreases.


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RESULTS OF OPERATIONS

GAS, OIL AND NGL PRODUCTION: The following table sets forth information related to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:

                                                Years Ended December 31,
                                                 2015               2014
         Production revenues (in thousands):
         Gas                                 $        357       $        987
         Oil                                           29                 60
         Liquids                                        6                 20
         Total                               $        392       $      1,067

         Production volumes:
         Gas (mcf/day)                                665                782
         Oil (bbls/day)                                 2                  2
         Liquids (bbls/day)                             1                  1
         Total (mcfe/day)                             683                800

         Average sales price: (1)
         Gas (per mcf) (2)                   $       1.47       $       3.50
         Oil (per bbl)                       $      46.61       $      89.96
         Liquids (per bbl)                   $      22.44       $      50.94

         Production costs:
         As a percent of revenues                     171 %               84 %
         Per mcfe                            $       2.71       $       3.09
         Depletion per mcfe                  $       0.25       $       1.10





       (1) Average sales prices represent accrual basis pricing after reversing
           the effect of previously recognized gains resulting from prior period
           impairment charges.


       (2) Average gas prices are calculated by including in total revenue
           derivative gains previously recognized into income in connection with
           prior period impairment charges and dividing by the total volume for
           the period. Previously recognized derivative gains were $9,800 for the
           year ended December 31, 2014.

Natural Gas Revenues. Our natural gas revenues were $357,600 and $987,400 for the years ended December 31, 2015 and 2014, respectively, a decrease of $629,800 (64%). The $629,800 decrease in natural gas revenues for the year ended December 31, 2015 as compared to the prior year was attributable to a $483,100 decrease in natural gas prices after the effect of financial hedges, which were driven by market conditions, and a $146,700 decrease in production volumes. Our production volumes decreased to 665 mcf per day for the year ended December 31, 2015 from 782 mcf per day for the year ended December 31, 2014, a decrease of 117 (15%) mcf per day. The price we receive for our natural gas is primarily a result of the index driven agreements (See Item 1: "Business-Contractual Revenue Arrangements"). Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions. The decrease in production volume is mostly due to the normal decline inherent in the life of the wells in addition to wells shut-in due to it being uneconomical to continue production in the current pricing environment.

Oil Revenues. We drilled wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $28,800 and $59,700 for the years ended December 31, 2015 and 2014, respectively, a decrease of $30,900 (52%). The $30,900 decrease in oil revenues for the year ended December 31, 2015 as compared to the prior year was attributable to $26,800 decrease in oil prices and a $4,100 decrease in production volumes. Our production volumes decreased to 1.69 bbls per day for the year ended December 31, 2015 from 1.82 bbls per day for the year ended December 31, 2014, a decrease of 0.13 bbls per day (7%).


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Natural Gas Liquids Revenue. The majority of our wells produce "dry gas", which is composed primarily of methane and requires no additional processing before being transported and sold to the purchaser. Some wells, however, produce "wet gas", which contains larger amounts of ethane and other associated hydrocarbons (i.e. "natural gas liquids") that must be removed prior to transporting the gas. Once removed, these natural gas liquids are sold to various purchasers. Our natural gas liquids revenues were $5,700 and $20,200 for the years ended December 31, 2015 and 2014, respectively, a decrease of $14,500 (72%). The $14,500 decrease in liquid revenues for the year ended December 31, 2015 as compared to the prior year was attributable to $7,200 decrease in production volumes and a $7,300 decrease in prices. Our production volumes were 0.70 bbls and 1.09 bbls per day for the years ended December 31, 2015 and 2014, respectively, a decrease of 0.39 (36%) bbls per day.

Gain on Mark-to-Market Derivatives. On January 1, 2015, we discontinued hedge accounting for our qualified commodity derivatives. As such, subsequent changes in fair value of these derivatives are recognized immediately within gain on mark-to-market derivatives on our statements of operations. The fair values of these commodity derivative instruments as of December 31, 2014, which were recognized in accumulated other comprehensive income within partners' capital on our balance sheet, will be reclassified to our statements of operations in the future at the time the originally hedged physical transactions settle.

We recognized a gain on mark-to-market derivatives of $18,100 for the year ended December 31, 2015. This gain was due primarily to mark-to-market gains in the current year primarily related to the change in natural gas prices during the year. There were no gains or losses on mark-to-market derivatives during the year ended December 31, 2014.

Costs and Expenses. Production expenses were $672,200 and $899,900 for the years ended December 31, 2015 and 2014, respectively, a decrease of $227,700 (25%). This decrease was primarily due to decreases in supervision fees, transportation fees and water hauling expenses.

Depletion of our gas and oil properties as a percentage of gas and oil revenues was 16% and 30% for the years ended December 31, 2015 and 2014, respectively. This change was primarily attributable to changes in gas and oil reserve quantities, and to a lesser extent, revenues, product prices, production volumes and changes in the depletable cost basis of gas and oil properties.

General and administrative expenses were $168,000 and $181,100 for the years ended December 31, 2015 and 2014, respectively, a decrease of $13,100 (7%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP and vary from period to period due to the timing of the costs and services provided to us.

Impairment of gas and oil properties for the years ended December 31, 2015 and 2014 was $716,100 and $2,770,000, respectively. At least annually, we compare the carrying value of our proved developed gas and oil producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value, an impairment charge is recognized. As a result of this assessment, an impairment charge was recognized for the years ended December 31, 2015 and 2014. This charge is based on reserve quantities, future market prices and our carrying value. We cannot provide any assurance that similar charges may or may not be taken in future periods.

Liquidity and Capital Resources. We are generally limited to the amount of funds generated by the cash flow from our operations to fund our obligations and make distributions to our 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 our outlook. We have experienced downward revisions of our natural gas and oil reserves volumes and values due to the significant declines in commodity prices. Our MGP continues to implement various cost saving measures to reduce our 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. Our MGP will continue to be opportunistic and aggressive in managing our cost structure and, in turn, our liquidity to meet our operating needs. To the extent commodity prices remain low or decline further, or we experience other disruptions in the industry, our ability to fund our operations and make distributions may be further impacted, and could result in the MGP's decision to liquidate our operations.


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Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from our operations has been adequate to fund our obligations and distributions to our partners. However, the recent significant declines in commodity prices have challenged our ability to fund our operations and may make it uneconomical to produce our wells until they are depleted as we originally intended. Accordingly, the MGP determined that there is substantial doubt about our ability to continue as a going concern. The MGP intends, as necessary, to continue our operations and to fund our obligations for at least the next twelve months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to our 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.

Cash provided by operating activities decreased $5,600 for the year ended December 31, 2015 to $0 as compared to $5,600 of cash used by operating activities for the year ended December 31, 2014. This decrease in cash used by operating activities was due to a decrease in net loss before depletion, impairment, and accretion of $416,300, a decrease in the change in accounts receivable trade-affiliate of $265,000, a decrease in the change in asset retirement receivable-affiliate of $72,800, and a decrease in the non-cash loss on derivative value of $22,600. This decrease was partially offset by an increase in the change in accounts payable trade-affiliate of $780,400 and a decrease in the change in accrued liabilities of $1,900 for the year ended December 31, 2015 as compared to the year ended December 31, 2014.

Our MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2015, our MGP withheld $721,200 of funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow at any one time may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

Impairment

During the years ended December 31, 2015 and 2014, we recognized $716,100 and $2,770,000, respectively, of impairment related to gas and oil properties within property, plant, and equipment on our balance sheet. These impairments relate to the carrying amount of our gas and oil properties being in excess of our estimate of their fair value at December 31, 2015 and 2014. 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.

ENVIRONMENTAL REGULATION

Our operations are subject to federal, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety (see "Item 1: Business -Environmental Matters and Regulation"). We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; imposition of remedial requirements; issuance of injunctions affecting our operations; or other measures. We have maintained and expect to continue to maintain environmental compliance programs. However, risks of accidental leaks or spills are associated with our operations. There can be no assurance that we will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our business. Moreover, it is possible other developments, such as increasingly strict federal, state and local environmental laws and regulations and enforcement policies, could result in increased costs and liabilities to us.

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate that such changes will continue. Trends in environmental regulation include increased reporting obligations and placing more restrictions and limitations on operations, such as emissions of greenhouse gases and other pollutants; generation and disposal of wastes, including wastes that may have technologically enhanced naturally occurring radioactive materials; and use, storage and handling of chemical substances that may impact human health, the environment and/or threatened or endangered species. Other increasingly stringent environmental restrictions and limitations have resulted in increased operating costs for us and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations may continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that we will identify and properly anticipate each such change, or that our efforts will prevent material costs, if any, from rising.



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CHANGES IN PRICES AND INFLATION

Our revenues and the value of our assets have been and will continue to be affected by changes in natural gas and oil market prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict.

Inflation affects the operating expenses of our operations. Inflationary trends may occur if commodity prices were to increase, since such an increase may cause the demand for energy equipment and services to increase, thereby increasing the costs of acquiring or obtaining such equipment and services. While we anticipate that inflation will affect our future operating costs, we cannot predict the timing or amounts of any such effects.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with U.S. GAAP requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depletion and amortization, impairment, fair value of derivative instruments, and the probability of forecasted transactions. We summarize our significant accounting policies within our financial statements (See "Item 8: Financial Statements") included in this report. The critical accounting policies and estimates we have identified are discussed below.

Depletion and Impairment of Long-Lived Assets

Long-Lived Assets. The cost of natural gas and oil properties, less estimated salvage value, is generally depleted on the units-of-production method.

Natural gas and oil properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. As discussed in General Trends and Outlook within this section, recent increases in natural gas drilling have driven an increase in the supply of natural gas and put a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods.

Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions.

During the years ended December 31, 2015 and 2014, we recognized $716,100 and $2,770,000, respectively, of impairment within natural gas and oil properties. These impairments relate to the carrying amount of the gas and oil properties being in excess of our estimate of their fair value at December 31, 2015 and 2014. 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.

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 our 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.

Fair Value of Financial Instruments

We have established a hierarchy to measure our financial instruments at fair value, which requires us 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:

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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.


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We use a fair value methodology to value the assets and liabilities for our outstanding derivative contracts. Our commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations ("ARO") that are defined as Level 3. Estimates of the fair value of ARO's are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our MGP's credit-adjusted risk-free rate and inflation rates.

Reserve Estimates

Our estimates of proved natural gas, oil and NGL reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas, oil and NGL prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. We engaged Wright & Company, Inc., an independent third-party reserve engineer, to prepare a report of our proved reserves (See "Item 2: Properties").

Any significant variance in the assumptions utilized in the calculation of our reserve estimates could materially affect the estimated quantity of our reserves. As a result, our estimates of proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas, oil and NGL prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas, oil and NGL reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our ability to pay distributions. In addition, our proved reserves may be subject to downward or upward revision based upon production history, prevailing natural gas, oil and NGL prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control. Our reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of natural gas, oil and NGL properties. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

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.

Asset Retirement Obligations

We recognize and estimate the liability for the plugging and abandonment of our gas and oil wells. The associated asset retirement costs are capitalized as part of the carrying amount of the long lived asset.

The estimated liability is based on our historical experience in plugging and abandoning wells, 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 is discounted using our MGP's 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. We have no assets legally restricted for purposes of settling asset retirement obligations. Except for our gas and oil properties, we believe that there are no other material retirement obligations associated with tangible long lived assets.


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Working Interest

Our Partnership Agreement establishes that revenues and expenses will be allocated to our MGP and limited partners based on their ratio of capital contributions to total contributions ("working interest"). Our 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.


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Source: Equities.com News (April 14, 2016 - 9:30 AM EDT)

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