10-Q

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2015

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

For the transition period from to

Commission file number 000-51275

ATLAS AMERICA PUBLIC #14-2004 L.P.

(Name of small business issuer in its charter)

Delaware	86-1111314
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, 4th Floor Pittsburgh, PA	15275
(Address of principal executive offices)	(zip code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  þ    No  ¨

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

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

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

ATLAS AMERICA PUBLIC 14-2004 L.P.

(A Delaware Limited Partnership)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

		PAGE
PART I.	FINANCIAL INFORMATION (Unaudited)
Item 1:
	Condensed Balance Sheets as of June 30, 2015 and December 31, 2014	3
	Condensed Statements of Operations for the Three and Six Months ended June 30, 2015 and 2014	4
	Condensed Statements of Comprehensive (Loss) Income for the Three and Six Months ended June 30, 2015 and 2014	5
	Condensed Statement of Changes in Partners’ Capital for the Six Months ended June 30, 2015	6
	Condensed Statements of Cash Flows for the Six Months ended June 30, 2015 and 2014	7
	Notes to Condensed Financial Statements	8
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 4:	Controls and Procedures	20
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings	21
Item 6:	Exhibits	22
SIGNATURES		23
CERTIFICATIONS

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS AMERICA PUBLIC #14-2004 L.P.

CONDENSED BALANCE SHEETS

(Unaudited)

	June 30, 2015			December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	300		$	200
Accounts receivable trade -affiliate		102,100			153,300
Asset retirement receivable -affiliate		178,600			27,400
Current portion of derivative assets		14,600			14,000
Total current assets		295,600			194,900
Gas and oil properties, net		2,911,100			2,960,300
Long-term derivative assets		6,900			11,700
	$	3,213,600		$	3,166,900
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable trade-affiliate	$	309,600		$	-
Accrued liabilities		6,500			10,300
Current portion of put premiums payable-affiliate		9,600			9,000
Total current liabilities		325,700			19,300
Asset retirement obligations		5,593,600			5,438,100
Long-term put premiums payable-affiliate		5,100			10,200
Commitments and contingencies
Partners’ capital:
Managing general partner’s interest		37,000			188,200
Limited partners’ interest (5,256.95 units)		(2,751,500	)		(2,495,400	)
Accumulated other comprehensive income		3,700			6,500
Total partners’ capital		(2,710,800	)		(2,300,700	)
	$	3,213,600		$	3,166,900

See accompanying notes to condensed financial statements.

3

ATLAS AMERICA PUBLIC #14-2004 L.P.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
REVENUES
Natural gas, oil and liquids	$	130,900		$	493,400	$	358,900		$	983,500
(Loss) gain on mark-to-market derivatives		(3,800	)		-		300			-
Total revenues		127,100			493,400		359,200			983,500
COSTS AND EXPENSES
Production		211,500			325,200		465,000			613,800
Depletion		23,000			58,800		49,200			113,400
Accretion of asset retirement obligation		77,700			53,500		155,500			107,100
General and administrative		45,500			47,300		96,800			98,600
Total costs and expenses		357,700			484,800		766,500			932,900
Net (loss) income	$	(230,600	)	$	8,600	$	(407,300	)	$	50,600
Allocation of net (loss) income:
Managing general partner	$	(83,700	)	$	1,700	$	(151,200	)	$	16,300
Limited partners	$	(146,900	)	$	6,900	$	(256,100	)	$	34,300
Net (loss) income per limited partnership unit	$	(28	)	$	2	$	(49	)	$	7

See accompanying notes to condensed financial statements.

4

ATLAS AMERICA PUBLIC #14-2004 L.P.

CONDENSED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Net (loss) income	$	(230,600	)	$	8,600		$	(407,300	)	$	50,600
Other comprehensive loss:
Unrealized holding gain (loss) on cash flow hedging contracts		-			1,000			-			(15,100	)
Difference in estimated hedge gains receivable		2,100			(2,500	)		4,300			26,300
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net (loss) income		(3,500	)		500			(7,100	)		(15,400	)
Total other comprehensive loss		(1,400	)		(1,000	)		(2,800	)		(4,200	)
Comprehensive (loss) income	$	(232,000	)	$	7,600		$	(410,100	)	$	46,400

See accompanying notes to condensed financial statements.

5

ATLAS AMERICA PUBLIC #14-2004 L.P.

CONDENSED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE SIX MONTHS ENDED

June 30, 2015

(Unaudited)

	Managing General Partner			Limited Partners			Accumulated Other Comprehensive Income (Loss)			Total
Balance at December 31, 2014	$	188,200		$	(2,495,400	)	$	6,500		$	(2,300,700	)
Participation in revenues, costs and expenses:
Net production expenses		(39,500	)		(66,600	)		-			(106,100	)
Gain on mark-to-market derivatives		-			300			-			300
Depletion		(23,400	)		(25,800	)		-			(49,200	)
Accretion of asset retirement obligation		(54,400	)		(101,100	)		-			(155,500	)
General and administrative		(33,900	)		(62,900	)		-			(96,800	)
Net loss		(151,200	)		(256,100	)		-			(407,300	)
Other comprehensive loss		-			-			(2,800	)		(2,800	)
Balance at June 30, 2015	$	37,000		$	(2,751,500	)	$	3,700		$	(2,710,800	)

See accompanying notes to condensed financial statements.

6

ATLAS AMERICA PUBLIC #14-2004 L.P.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months EndedJune 30,
	2015			2014
Cash flows from operating activities:
Net (loss) income	$	(407,300	)	$	50,600
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion		49,200			113,400
Non cash (gain) loss on derivative value		(3,100	)		9,200
Accretion of asset retirement obligation		155,500			107,100
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable trade-affiliate		51,200			(32,800	)
Increase in asset retirement receivable-affiliate		(151,200	)		(14,100	)
Increase in accounts payable trade-affiliate		309,600			-
Decrease in accrued liabilities		(3,800	)		(2,400	)
Asset retirement obligations settled		-			(200	)
Net cash provided by operating activities		100			230,800
Cash flows from financing activities:
Distributions to partners		-			(233,900	)
Net cash used in financing activities		-			(233,900	)
Net change in cash and cash equivalents		100			(3,100	)
Cash and cash equivalents at beginning of period		200			77,500
Cash and cash equivalents at end of period	$	300		$	74,400

See accompanying notes to condensed financial statements.

7

ATLAS AMERICA PUBLIC #14-2004

NOTES TO CONDENSED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

NOTE 1 - DESCRIPTION OF BUSINESS

Atlas America Public #14-2004 L.P. (the “Partnership”) is a Delaware limited partnership, formed on May 3, 2004 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”; NYSE: 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 ARP’s general partner interest.

The Partnership has drilled and currently operates wells located in Pennsylvania and Tennessee. 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 accompanying condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2014, which is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in the Partnership’s Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014. The results of operations for the three and six months ended June 30, 2015 may not necessarily be indicative of the results of operations for the year ended December 31, 2015.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

In addition to matters discussed further in this note, the Partnership’s significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2014 filed with the Securities and Exchange Commission (“SEC”).

8

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 the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.

The natural 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. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and six months ended June 30, 2015 and 2014 represent actual results in all material respects (See “-Revenue Recognition”).

Accounts Receivable

Accounts receivable on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of the Partnership’s accounts receivable, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At June 30, 2015 and December 31, 2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for uncollectible accounts receivable.

Gas and Oil Properties

Gas and oil properties are stated at cost. Maintenance and repairs which 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 and natural gas liquids (“NGLs”) are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six Mcf of natural gas. Mcf is defined as one thousand cubic feet.

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. The Partnership recorded depletion expense on natural gas and oil properties of $49,200 and $113,400 for the six months ended June 30, 2015 and 2014, respectively.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depletion within its balance sheets.

The following is a summary of gas and oil properties at the dates indicated:

	June 30, 2015			December 31, 2014
Proved properties:
Leasehold interests	$	1,402,200		$	1,402,200
Wells and related equipment		67,266,000			67,266,000
Total natural gas and oil properties		68,668,200			68,668,200
Accumulated depletion and impairment		(65,757,100	)		(65,707,900	)
Gas and oil properties, net	$	2,911,100		$	2,960,300

9

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.

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 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.

There was no gas and oil properties impairment recorded for the three and six months ended June 30, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized an impairment charge of $3,254,800.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, 2014. The estimate of the 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.

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 expenses 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 and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

Revenue Recognition

The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, 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, crude oil and NGLs, 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.

10

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, 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 June 30, 2015 of $84,700which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets. The Partnership had unbilled revenues at December 31, 2014 of $158,200, which wasoffset by $4,900 of amounts due to the MGP, which was included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive (Loss) Income

Comprehensive (loss) income includes net (loss) income 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 (loss) income. These changes, other than net (loss) income, are referred to as “other comprehensive loss” on the Partnership’s financial statements and, at June 30, 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 4). The Partnership does not have any other type of transaction which would be included within other comprehensive loss.

Recently Issued Accounting Standards

In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations and related disclosures.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required 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. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations and related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. On July 9, 2015, the FASB decided to defer the effective date of ASU 2014-09 by one year. As a result, public entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017, and to interim periods within that reporting period, with the option to adopt the standard as of the original effective date. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2018, and is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

11

NOTE 3—ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells. It also recognizes a liability for future asset retirement obligations 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.

The estimated liability is based on the MGP’s 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 an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates, 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 the Partnership’s 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 June 30, 2015, the MGP has withheld $178,600 of net production revenue for future plugging and abandonment costs.

A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows:

	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015		2014
Asset retirement obligation at beginning of period	$	5,515,900	$	3,662,800		$	5,438,100	$	3,609,200
Asset retirement obligations settled		-		(200	)		-		(200	)
Accretion expense		77,700		53,500			155,500		107,100
Asset retirement obligation at end of period	$	5,593,600	$	3,716,100		$	5,593,600	$	3,716,100

NOTE 4 - DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, collars and options, in connection with the Partnership’s commodity price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to New York Mercantile Exchange (“NYMEX”), the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. 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. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

12

On January 1, 2015, the Partnership discontinued hedge accounting for its qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within partners’ capital on the Partnership’s balance sheet, will be reclassified to the Partnership’s statements of operations in the future at the time the originally hedged physical transactions affect earnings.

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 $21,500 and $25,700 at June 30, 2015 and December 31, 2014, respectively.

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:

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015		2014
Gain (loss) reclassified from accumulated other comprehensive income into natural gas, oil and liquids revenues	$	3,500		$	(500	)	$	7,100	$	15,400
(Loss) gain subsequent to December 31, 2014 recognized in (loss) gain on mark-to-market derivatives	$	(3,800	)	$	-		$	300	$	-

The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have been recorded at their fair values.

At June 30, 2015, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production Period Ending December 31,	Volumes		AverageFixed Price		Fair Value Asset (2)
	(MMBtu) (1)		(per MMBtu) (1)
2015		6,700	$	4.00	$	7,400
2016		13,400		4.15		14,100
					$	21,500

(1) “MMBtu” represents million British Thermal Units.

(2) Fair value based on forward NYMEX natural gas prices, as applicable.

13

As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and six months ended June 30, 2015 and 2014 for hedge ineffectiveness.

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 June 30, 2015 and December 31, 2014, $9,600 and $9,000, respectively, of the put premiums were recorded as short-term payables to affiliate and long-term payables to affiliate and $5,100 and $10,200, respectively, were recorded as long-term payables to affiliate.

Accumulated Other Comprehensive Income

As a result of the put options, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $3,700 as of June 30, 2015. During the six months ending June 30, 2015 the Partnership allocated $6,800 of net gains only to the limited partners. Of the remaining $3,700 of net unrealized gains in accumulated other comprehensive income, the Partnership will reclassify $3,000 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining gains of $700 in later periods.

NOTE 5 - 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 carrying values of cash, accounts receivable and accounts payable approximate their respective fair values due to the short-term maturities of such financial instruments. The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (See Note 4). 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.

14

Information for assets measured at fair value at June 30, 2015 and December 31, 2014wasas follows:

	Level 1		Level 2		Level 3		Total
As of June 30, 2015
Derivative assets, gross
Commodity puts	$	-	$	21,500	$	-	$	21,500

	Level 1		Level 2		Level 3		Total
As of December 31, 2014
Derivative assets, gross
Commodity puts	$	-	$	25,700	$	-	$	25,700

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 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 3). There were no additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2015 and 2014.

NOTE 6 - 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 expense in the Partnership’s statements of operations, are payable at $318 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 the working interest in a well. Transportation fees are included in production expense 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:

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Administrative fees	$	30,700	$	39,000	$	67,300	$	75,100
Supervision fees		130,200		165,300		285,400		318,300
Transportation fees		17,700		54,700		45,300		109,200
Direct costs		78,400		113,500		163,800		209,800
Total	$	257,000	$	372,500	$	561,800	$	712,400

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 sheets includes the net production revenues due to the MGP. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP.

15

NOTE 7 — COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor 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 June 30, 2015, the MGP has withheld $178,600 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.

ITEM  2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (UNAUDITED)

Forward-Looking Statements

When used in this Form 10-Q, the words “believes”, “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties, which could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

General

Atlas America Public #14-2004 L.P. (“we”, “us” or the “Partnership”) is a Delaware limited partnership, formed on May 3, 2004 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”; NYSE: 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 ARP’s general partner interest.

We have drilled and currently operate wells located in Pennsylvania and Tennessee. We have no employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas Energy Group (February 27, 2015 and prior, Atlas Energy), for administrative services.

We intend to continue to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. We expect that no other wells will be drilled and no additional funds will be required for drilling.

16

Overview

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 produce primarily 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 services 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 June 30, 2015, our MGP has withheld $178,600 of net production revenues for this purpose.

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 2014 and the first six months of 2015, 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.

17

Results of Operations

The following table sets forth information relating to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Production revenues (in thousands):
Gas	$	118		$	448		$	327		$	873
Oil		13			39			30			100
Liquids		-			6			2			11
Total	$	131		$	493		$	359		$	984
Production volumes:
Gas (Mcf/day) (1)		830			1,072			887			995
Oil (bbl/day) (1)		2			4			3			6
Liquids (bbl/day) (1)		-			1			-			1
Total (Mcfe/day) (1)		842			1,102			905			1,037
Average sales prices: (2)
Gas (per Mcf) (1) (3)	$	1.56		$	4.65		$	2.04		$	4.90
Oil (per bbl) (1)	$	58.04		$	97.36		$	50.76		$	94.65
Liquids (per bbl) (1)	$	22.56		$	58.05		$	36.36		$	55.64
Production costs:
As a percent of revenues		162	%		66	%		130	%		62	%
Per Mcfe (1)	$	2.75		$	3.23		$	2.83		$	3.27
Depletion per Mcfe	$	0.30		$	0.58		$	0.30		$	0.60

(1) “Mcf” represents thousand cubic feet, “Mcfe” represents thousand cubic feet equivalent, and “bbl” represents barrels. Bbl is converted to Mcfe using the ratio of six Mcfs to one bbl.

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

(3) 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 $5,800 for the three months ended June 30, 2014. Previously recognized derivative gains were $9,200 for the six months ended June 30, 2014.

18

Natural Gas Revenues. Our natural gas revenues were $118,000 and $448,000 for the three months ended June 30, 2015 and 2014, respectively, a decrease of $330,000 (74%). The $330,000 decrease in natural gas revenues for the three months ended June 30, 2015 as compared to the prior year similar period was attributable to a $229,000 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions, and a $101,000 decrease in production volumes. Our production volumes decreased to 830 Mcf per day for the three months ended June 30, 2015 from 1,072 Mcf per day for the three months ended June 30, 2014, a decrease of 242 Mcf per day (23%). The overall decrease in natural gas production volumes for the three months ended June 30, 2015 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well and a decrease in the number of producing wells due to wells shut-in due to a decline in natural gas prices.

Our natural gas revenues were $327,000 and $872,500 for the six months ended June 30, 2015 and 2014, respectively, a decrease of $545,500 (66%). The $545,500 decrease in natural gas revenues for the six months ended June 30, 2015 as compared to the prior year similar period was attributable to a $450,700 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions, and a $94,800 decrease in production volumes. Our production volumes decreased to 887 Mcf per day for the six months ended June 30, 2015 from 995 Mcf per day for the six months ended June 30, 2014, a decrease of 108 Mcf per day (11%). The overall decrease in natural gas production volumes for the six months ended June 30, 2015 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well and a decrease in the number of producing wells due to wells shut-in due to a decline in natural gas prices.

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $12,700 and $39,300 for the three months ended June 30, 2015 and 2014, respectively, a decrease of $26,600 (68%). The $26,600 decrease in oil revenues for the three months ended June 30, 2015 as compared to the prior year similar period was attributable to an $18,000 decrease in production volumes and an $8,600 decrease in oil prices. Our production volumes decreased to 2 bbls per day for the three months ended June 30, 2015 from 4 bbls per day for the three months ended June 30, 2014, a decrease of 2 bbls per day (50%).

Our oil revenues were $29,600 and $100,200 for the six months ended June 30, 2015 and 2014, respectively, a decrease of $70,600 (70%). The $70,600 decrease in oil revenues for the six months ended June 30, 2015 as compared to the prior year similar period was attributable to a $44,900 decrease in production volumes and a $25,700 decrease in oil prices. Our production volumes decreased to 3 bbls per day for the six months ended June 30, 2015 from 6 bbls per day for the six months ended June 30, 2014 a decrease of 3 bbls per day (50%).

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 $200 and $6,100 for the three months ended June 30, 2015 and 2014, respectively, a decrease of $5,900 (97%). The $5,900 decrease in liquid revenues for the three months ended June 30, 2015 as compared to the prior year similar period was attributed to a $5,600 decrease in production volumes and a $300 decrease in natural gas liquid prices. Our production volumes decreased to 0.11 bbls per day for the three months ended June 30, 2015 from 1.16 bbls per day for the three months ended June 30, 2014 a decrease of 1.05 bbls per day (91%).

Our natural gas liquids revenues were $2,300 and $10,800 for the six months ended June 30, 2015 and 2014, respectively, a decrease of $8,500 (79%). The $8,500 decrease in natural gas liquids revenues for the six months ended June 30, 2015 as compared to the prior year similar period was attributable to a $7,400 decrease in production volumes and a $1,100 decrease in natural gas liquid prices. Our production volumes decreased to 0.34 bbls per day for the six months ended June 30, 2015 from 1.07 bbls per day for the six months ended June 30, 2014 a decrease of 0.73 bbls per day (68%).

Costs and Expenses.Production expenses were $211,500 and $325,200 for the three months ended June 30, 2015 and 2014, respectively, a decrease of $113,700 (35%). Production expenses were $465,000 and $613,800 for the six months ended June 30, 2015 and 2014, respectively, a decrease of $148,800 (24%). The decrease for the three and six months ended June 30, 2015 was primarily due to a combination of a decrease in transportation fees and a decrease in supervision fees.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 18% and 12% for the three months ended June 30, 2015 and 2014, respectively, and 14% and 12% for the six months ended June 30, 2015 and 2014, respectively. These percentage changes are directly attributable to changes in revenues, oil and gas reserve quantities, product prices and production volumes and changes in the depletable cost basis of oil and gas properties.

19

General and administrative expenses for the three months ended June 30, 2015 and 2014 were $45,500 and $47,300, respectively, a decrease of $1,800 (4%). For the six months ended June 30, 2015 and 2014 these expenses were $96,800 and $98,600, respectively, a decrease of $1,800 (2%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. The decreases for the three and six months ended June 30, 2015 were primarily due to third-party costs as compared to the prior year similar period.

Liquidity and Capital Resources

Cash provided by operating activities decreased $230,700 in the six months ended June 30, 2015 to $100 as compared to $230,800 for the six months ended June 30, 2014. This decrease was mostly due to a decrease in net earnings before depletion, accretion and non-cash loss on derivative value of $486,000, a decrease in the change in asset retirement receivable-affiliate of $137,100 and a decrease in the change in accrued liabilities of $1,400. The decrease was partially offset by an increase in accounts payable trade-affiliate of $309,600, an increase in the change in accounts receivable-affiliate of $84,000 and an increase in the change in asset retirement obligations settled of $200 for the six months ended June 30, 2015 compared to the six months ended June 30, 2014.

Cash used in financing activities was $233,900 for the six months ended June 30, 2014. This was due to cash distributions to partners. There was no cash used in financing activities for the six months ended June 30, 2015.

Our MGP may withhold funds for future plugging and abandonment costs. Through June 30, 2015, our MGP has withheld $178,600 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.

We are generally limited to the amount of funds generated by the cash flows from our operations, which we believe is adequate to fund future operations and distributions to our partners. Historically, there has been no need to borrow funds from our MGP to fund operations.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations is based upon our financial statements, which have been prepared in accordance with U.S. GAAP. On an on-going basis, we evaluate our estimates, including those related to our asset retirement obligations, depletion and certain accrued receivables and liabilities. We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. A discussion of significant accounting policies we have adopted and followed in the preparation of our financial statements is included within “Notes to Financial Statements” in Part I, Item 1, “Financial Statements” in this quarterly report and in our Annual Report on Form 10-K for the year ended December 31, 2014.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation 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.

20

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 June 30, 2015, our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There have been no changes in the Partnership’s 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 II OTHER INFORMATION

ITEM  1. 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.

21

ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.	Description
4(a)	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #14-2004 L.P. (1)
10.1	Drilling and Operating Agreement for Atlas America Public #14-2004 L.P. (1)
31.1	Rule 13a-14/15(d)-14 (a) Certification
31.2	Rule 13a-14/15(d)-14 (a) Certification
32.1	Section 1350 Certification
32.2	Section 1350 Certification
101	Interactive Data File

(1) Filed in the Form S-1/A Registration Statement dated September 8, 2004 File No. 333-117035

22

SIGNATURES

Pursuant to the requirements of the Securities of the 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.

			ATLAS AMERICA PUBLIC #14-2004 L.P.
	By:		ATLAS RESOURCES, LLC, ITS
			GENERAL PARTNER
Date: August 14, 2015	By:		/s/ FREDDIE M. KOTEK
			Freddie M. Kotek, Chairman of the Board of Directors and Chief Executive Officer (principal executive officer)
Date: August 14, 2015		By:	/s/ SEAN P. MCGRATH
			Sean P. McGrath, Chief Financial Officer (principal financial officer and principal accounting officer)

23

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Freddie M. Kotek, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2015 of Atlas America Public #14-2004 L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have;

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within the entity, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ FREDDIE M. KOTEK
Name:	Freddie M. Kotek
Title:	Chief Executive Officer and President of the Managing General Partner
Date:	August 14, 2015

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Sean P. McGrath, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2015 of Atlas America Public #14-2004 L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have;

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within the entity, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ SEAN P. MCGRATH
Name:	Sean P. McGrath
Title:	Chief Financial Officer of the Managing General Partner
Date:	August 14, 2015

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Atlas America Public #14-2004 L.P. (the “Partnership”) on Form 10-Q for the period ended June 30, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Freddie M. Kotek, Chief Executive Officer of the Managing General Partner, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/ FREDDIE M. KOTEK
Name:	Freddie M. Kotek
Title:	Chief Executive Officer and President of the Managing General Partner
Date:	August 14, 2015

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Atlas America Public #14-2004 L.P. (the “Partnership”) on Form 10-Q for the period ended June 30, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Sean P. McGrath, Chief Financial Officer of the Managing General Partner, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/ SEAN P. MCGRATH
Name:	Sean P. McGrath
Title:	Chief Financial Officer  of the Managing General Partner
Date:	August 14, 2015

XML

Commitments and Contingencies (Narrative) (Details) - 6 months ended Jun. 30, 2015	USD ($) $ / mo
Commitments And Contingencies Disclosure [Abstract]
Investor Partners Ownership Interest Presented For Purchase By The MGP, Maximum Percentage	5.00%
Operator Fee Per Well To Cover Estimated Future Plugging And Abandonment Costs, Monthly	200
Net production revenue for future plugging and abandonment costs | $	$ 178,600

XML

Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Asset Retirement Obligations, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of period	$ 5,515,900	$ 3,662,800	$ 5,438,100	$ 3,609,200
Asset retirement obligations settled		(200)		(200)
Accretion expense	77,700	53,500	155,500	107,100
Asset retirement obligation at end of period	$ 5,593,600	$ 3,716,100	$ 5,593,600	$ 3,716,100

XML

Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2015

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

In addition to matters discussed further in this note, the Partnership’s significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2014 filed with the Securities and Exchange Commission (“SEC”).

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 the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.

The natural 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. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and six months ended June 30, 2015 and 2014 represent actual results in all material respects (See “-Revenue Recognition”).

Accounts Receivable

Accounts receivable on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of the Partnership’s accounts receivable, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At June 30, 2015 and December 31, 2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for uncollectible accounts receivable.

Gas and Oil Properties

Gas and oil properties are stated at cost. Maintenance and repairs which 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 and natural gas liquids (“NGLs”) are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six Mcf of natural gas. Mcf is defined as one thousand cubic feet.

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. The Partnership recorded depletion expense on natural gas and oil properties of $49,200 and $113,400 for the six months ended June 30, 2015 and 2014, respectively.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depletion within its balance sheets.

The following is a summary of gas and oil properties at the dates indicated:

	June 30, 2015			December 31, 2014
Proved properties:
Leasehold interests	$	1,402,200		$	1,402,200
Wells and related equipment		67,266,000			67,266,000
Total natural gas and oil properties		68,668,200			68,668,200
Accumulated depletion and impairment		(65,757,100	)		(65,707,900	)
Gas and oil properties, net	$	2,911,100		$	2,960,300

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.

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 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.

There was no gas and oil properties impairment recorded for the three and six months ended June 30, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized an impairment charge of $3,254,800.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, 2014. The estimate of the 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.

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 expenses 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 and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

Revenue Recognition

The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, 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, crude oil and NGLs, 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, 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 June 30, 2015 of $84,700 which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets. The Partnership had unbilled revenues at December 31, 2014 of $158,200, which was offset by $4,900 of amounts due to the MGP, which was included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive (Loss) Income

Comprehensive (loss) income includes net (loss) income 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 (loss) income. These changes, other than net (loss) income, are referred to as “other comprehensive loss” on the Partnership’s financial statements and, at June 30, 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 4). The Partnership does not have any other type of transaction which would be included within other comprehensive loss.

Recently Issued Accounting Standards

In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations and related disclosures.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required 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. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations and related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. On July 9, 2015, the FASB decided to defer the effective date of ASU 2014-09 by one year. As a result, public entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017, and to interim periods within that reporting period, with the option to adopt the standard as of the original effective date. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2018, and is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

XML

Fair Value of Financial Instruments (Assets Measured at Fair Value on a Recurring Basis) (Details) - Commodity Puts - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	$ 21,500	$ 25,700
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	$ 21,500	$ 25,700

XML

Derivative Instruments (Commodity Derivatives) (Details)		6 Months Ended
		Jun. 30, 2015 USD ($) MMBTU $ / MMBTU	Dec. 31, 2014 USD ($)
Derivative [Line Items]
Fair Value Asset		$ 21,500	$ 25,700
Natural Gas Put Options
Derivative [Line Items]
Fair Value Asset	[1]	$ 21,500
Natural Gas Put Options | Production Period Ending December 31, 2015
Derivative [Line Items]
Volumes | MMBTU	[2]	6,700
Average Fixed Price (per MMBtu) | $ / MMBTU	[2]	4.00
Fair Value Asset	[1]	$ 7,400
Natural Gas Put Options | Production Period Ending December 31, 2016
Derivative [Line Items]
Volumes | MMBTU	[2]	13,400
Average Fixed Price (per MMBtu) | $ / MMBTU	[2]	4.15
Fair Value Asset	[1]	$ 14,100

[1] Fair value based on forward NYMEX natural gas prices, as applicable.

[2] “MMBtu” represents million British Thermal Units.

XML

Fair Value of Financial Instruments (Narrative) (Details) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Fair Value Disclosures [Abstract]
Assets measured at fair value on nonrecurring basis	$ 0	$ 0
Liabilities measured at fair value on nonrecurring basis	$ 0	$ 0

XML

Certain Relationships and Related Party Transactions (Narrative) (Details) - 6 months ended Jun. 30, 2015 - MGP and Affiliates - $ / mo	Total
Administrative
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well	75
Supervision
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	318
Transportation
Related Party Transaction [Line Items]
Transportation Fee Rate As Percentage Of Natural Gas Sales Price	13.00%

XML

Description of Business

6 Months Ended

Jun. 30, 2015

Organization Consolidation And Presentation Of Financial Statements [Abstract]

DESCRIPTION OF BUSINESS

NOTE 1 - DESCRIPTION OF BUSINESS

Atlas America Public #14-2004 L.P. (the “Partnership”) is a Delaware limited partnership, formed on May 3, 2004 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”; NYSE: 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 ARP’s general partner interest.

The Partnership has drilled and currently operates wells located in Pennsylvania and Tennessee. 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 accompanying condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2014, which is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in the Partnership’s Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014. The results of operations for the three and six months ended June 30, 2015 may not necessarily be indicative of the results of operations for the year ended December 31, 2015.

XML

Certain Relationships and Related Party Transactions (Certain Relationships and Related Party Transactions) (Details) - MGP and Affiliates - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 257,000	$ 372,500	$ 561,800	$ 712,400
Administrative fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	30,700	39,000	67,300	75,100
Supervision fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	130,200	165,300	285,400	318,300
Transportation fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	17,700	54,700	45,300	109,200
Direct Costs
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 78,400	$ 113,500	$ 163,800	$ 209,800

XML

CONDENSED BALANCE SHEETS - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 300	$ 200
Accounts receivable trade -affiliate	102,100	153,300
Asset retirement receivable -affiliate	178,600	27,400
Current portion of derivative assets	14,600	14,000
Total current assets	295,600	194,900
Gas and oil properties, net	2,911,100	2,960,300
Long-term derivative assets	6,900	11,700
TOTAL ASSETS	3,213,600	3,166,900
Current liabilities:
Accounts payable trade-affiliate	309,600
Accrued liabilities	6,500	10,300
Current portion of put premiums payable-affiliate	9,600	9,000
Total current liabilities	325,700	19,300
Asset retirement obligations	5,593,600	5,438,100
Long-term put premiums payable-affiliate	$ 5,100	$ 10,200
Commitments and contingencies
Partners’ capital:
Managing general partner’s interest	$ 37,000	$ 188,200
Limited partners’ interest (5,256.95 units)	(2,751,500)	(2,495,400)
Accumulated other comprehensive income	3,700	6,500
Total partners’ capital	(2,710,800)	(2,300,700)
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 3,213,600	$ 3,166,900

XML

CONDENSED STATEMENT OF CHANGES IN PARTNERS' CAPITAL - 6 months ended Jun. 30, 2015 - USD ($)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive Income (Loss)
Beginning balance at Dec. 31, 2014	$ (2,300,700)	$ 188,200	$ (2,495,400)	$ 6,500
Participation in revenues, costs and expenses:
Net production expenses	(106,100)	(39,500)	(66,600)
(Loss) gain on mark-to-market derivatives	300		300
Depletion	(49,200)	(23,400)	(25,800)
Accretion of asset retirement obligation	(155,500)	(54,400)	(101,100)
General and administrative	(96,800)	(33,900)	(62,900)
Net (loss) income	(407,300)	(151,200)	(256,100)
Other comprehensive loss	(2,800)			(2,800)
Ending balance at Jun. 30, 2015	$ (2,710,800)	$ 37,000	$ (2,751,500)	$ 3,700

XML

Summary of Significant Accounting Policies (Narrative) (Details) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Accounting Policies [Abstract]
Allowance for Uncollectible Accounts Receivable	$ 0		$ 0		$ 0
Depletion of Oil and Gas Properties	23,000	$ 58,800	49,200	$ 113,400
Impairment	0	$ 0	$ 0	$ 0	3,254,800
Additional working interest			7.00%
Unbilled Revenues	$ 84,700		$ 84,700		158,200
Due to affiliate					$ 4,900

XML

Asset Retirement Obligations (Narrative) (Details)	6 Months Ended
	Jun. 30, 2015 USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Net production revenue for future plugging and abandonment costs	$ 178,600

XML

CONDENSED STATEMENTS OF CASH FLOWS - USD ($)	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash flows from operating activities:
Net (loss) income	$ (407,300)	$ 50,600
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion	49,200	113,400
Non cash (gain) loss on derivative value	(3,100)	9,200
Accretion of asset retirement obligation	155,500	107,100
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable trade-affiliate	51,200	(32,800)
Increase in asset retirement receivable-affiliate	(151,200)	(14,100)
Increase in accounts payable trade-affiliate	309,600
Decrease in accrued liabilities	(3,800)	(2,400)
Asset retirement obligations settled		(200)
Net cash provided by operating activities	100	230,800
Cash flows from financing activities:
Distributions to partners		(233,900)
Net cash used in financing activities		(233,900)
Net change in cash and cash equivalents	100	(3,100)
Cash and cash equivalents at beginning of period	200	77,500
Cash and cash equivalents at end of period	$ 300	$ 74,400

XML

CONDENSED BALANCE SHEETS (Parenthetical)	Jun. 30, 2015 shares
Statement Of Financial Position [Abstract]
Limited partners' units	5,256.95

XML

Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows:

	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015		2014
Asset retirement obligation at beginning of period	$	5,515,900	$	3,662,800		$	5,438,100	$	3,609,200
Asset retirement obligations settled		-		(200	)		-		(200	)
Accretion expense		77,700		53,500			155,500		107,100
Asset retirement obligation at end of period	$	5,593,600	$	3,716,100		$	5,593,600	$	3,716,100

XML

Document and Entity Information - Jun. 30, 2015 - shares	Total
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q2
Entity Registrant Name	ATLAS AMERICA Public #14-2004 L.P.
Entity Central Index Key	0001294476
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0

XML

Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2015

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Summary of Gains or Losses Recognized Within Statements of Operations for Derivative Instruments Previously Designated as Cash Flow Hedges

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:

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015		2014
Gain (loss) reclassified from accumulated other comprehensive income into natural gas, oil and liquids revenues	$	3,500		$	(500	)	$	7,100	$	15,400
(Loss) gain subsequent to December 31, 2014 recognized in (loss) gain on mark-to-market derivatives	$	(3,800	)	$	-		$	300	$	-

Commodity Derivatives

At June 30, 2015, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production Period Ending December 31,	Volumes		AverageFixed Price		Fair Value Asset (2)
	(MMBtu) (1)		(per MMBtu) (1)
2015		6,700	$	4.00	$	7,400
2016		13,400		4.15		14,100
					$	21,500

(1) “MMBtu” represents million British Thermal Units.

(2) Fair value based on forward NYMEX natural gas prices, as applicable.

XML

CONDENSED STATEMENTS OF OPERATIONS - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
REVENUES
Natural gas, oil and liquids	$ 130,900	$ 493,400	$ 358,900	$ 983,500
(Loss) gain on mark-to-market derivatives	(3,800)		300
Total revenues	127,100	493,400	359,200	983,500
COSTS AND EXPENSES
Production	211,500	325,200	465,000	613,800
Depletion	23,000	58,800	49,200	113,400
Accretion of asset retirement obligation	77,700	53,500	155,500	107,100
General and administrative	45,500	47,300	96,800	98,600
Total costs and expenses	357,700	484,800	766,500	932,900
Net (loss) income	(230,600)	8,600	(407,300)	50,600
Allocation of net (loss) income:
Managing general partner	(83,700)	1,700	(151,200)	16,300
Limited partners	$ (146,900)	$ 6,900	$ (256,100)	$ 34,300
Net (loss) income per limited partnership unit	$ (28)	$ 2	$ (49)	$ 7

XML

Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

NOTE 5 - 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 carrying values of cash, accounts receivable and accounts payable approximate their respective fair values due to the short-term maturities of such financial instruments. The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (See Note 4). 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 measured at fair value at June 30, 2015 and December 31, 2014 was as follows:

	Level 1		Level 2		Level 3		Total
As of June 30, 2015
Derivative assets, gross
Commodity puts	$	-	$	21,500	$	-	$	21,500

	Level 1		Level 2		Level 3		Total
As of December 31, 2014
Derivative assets, gross
Commodity puts	$	-	$	25,700	$	-	$	25,700

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 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 3). There were no additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2015 and 2014.

XML

Derivative Instruments

6 Months Ended

Jun. 30, 2015

Derivative Instruments And Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

NOTE 4 - DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, collars and options, in connection with the Partnership’s commodity price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to New York Mercantile Exchange (“NYMEX”), the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. 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. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

On January 1, 2015, the Partnership discontinued hedge accounting for its qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within partners’ capital on the Partnership’s balance sheet, will be reclassified to the Partnership’s statements of operations in the future at the time the originally hedged physical transactions affect earnings.

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 $21,500 and $25,700 at June 30, 2015 and December 31, 2014, respectively.

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:

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015		2014
Gain (loss) reclassified from accumulated other comprehensive income into natural gas, oil and liquids revenues	$	3,500		$	(500	)	$	7,100	$	15,400
(Loss) gain subsequent to December 31, 2014 recognized in (loss) gain on mark-to-market derivatives	$	(3,800	)	$	-		$	300	$	-

The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have been recorded at their fair values.

At June 30, 2015, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production Period Ending December 31,	Volumes		AverageFixed Price		Fair Value Asset (2)
	(MMBtu) (1)		(per MMBtu) (1)
2015		6,700	$	4.00	$	7,400
2016		13,400		4.15		14,100
					$	21,500

(1) “MMBtu” represents million British Thermal Units.

(2) Fair value based on forward NYMEX natural gas prices, as applicable.

As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and six months ended June 30, 2015 and 2014 for hedge ineffectiveness.

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 June 30, 2015 and December 31, 2014, $9,600 and $9,000, respectively, of the put premiums were recorded as short-term payables to affiliate and long-term payables to affiliate and $5,100 and $10,200, respectively, were recorded as long-term payables to affiliate.

Accumulated Other Comprehensive Income

As a result of the put options, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $3,700 as of June 30, 2015. During the six months ending June 30, 2015 the Partnership allocated $6,800 of net gains only to the limited partners. Of the remaining $3,700 of net unrealized gains in accumulated other comprehensive income, the Partnership will reclassify $3,000 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining gains of $700 in later periods.

XML

Summary of Significant Accounting Policies (Summary of Gas and Oil Properties) (Details) - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 68,668,200	$ 68,668,200
Accumulated depletion and impairment	(65,757,100)	(65,707,900)
Gas and oil properties, net	2,911,100	2,960,300
Leasehold interests
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	1,402,200	1,402,200
Wells and related equipment
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 67,266,000	$ 67,266,000

XML

Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

Assets Measured at Fair Value on a Recurring Basis

Information for assets measured at fair value at June 30, 2015 and December 31, 2014 was as follows:

	Level 1		Level 2		Level 3		Total
As of June 30, 2015
Derivative assets, gross
Commodity puts	$	-	$	21,500	$	-	$	21,500

	Level 1		Level 2		Level 3		Total
As of December 31, 2014
Derivative assets, gross
Commodity puts	$	-	$	25,700	$	-	$	25,700

XML

Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2015

Accounting Policies [Abstract]

Use of Estimates

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 the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.

The natural 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. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and six months ended June 30, 2015 and 2014 represent actual results in all material respects (See “-Revenue Recognition”).

Accounts Receivable

Accounts Receivable

Accounts receivable on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of the Partnership’s accounts receivable, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At June 30, 2015 and December 31, 2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for uncollectible accounts receivable.

Gas and Oil Properties

Gas and Oil Properties

Gas and oil properties are stated at cost. Maintenance and repairs which 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 and natural gas liquids (“NGLs”) are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six Mcf of natural gas. Mcf is defined as one thousand cubic feet.

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. The Partnership recorded depletion expense on natural gas and oil properties of $49,200 and $113,400 for the six months ended June 30, 2015 and 2014, respectively.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depletion within its balance sheets.

The following is a summary of gas and oil properties at the dates indicated:

	June 30, 2015			December 31, 2014
Proved properties:
Leasehold interests	$	1,402,200		$	1,402,200
Wells and related equipment		67,266,000			67,266,000
Total natural gas and oil properties		68,668,200			68,668,200
Accumulated depletion and impairment		(65,757,100	)		(65,707,900	)
Gas and oil properties, net	$	2,911,100		$	2,960,300

Impairment of Long-Lived Assets

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.

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 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.

There was no gas and oil properties impairment recorded for the three and six months ended June 30, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized an impairment charge of $3,254,800.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, 2014. The estimate of the 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.

Working Interest

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 expenses 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 and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

Revenue Recognition

Revenue Recognition

The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, 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, crude oil and NGLs, 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, 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 June 30, 2015 of $84,700 which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets. The Partnership had unbilled revenues at December 31, 2014 of $158,200, which was offset by $4,900 of amounts due to the MGP, which was included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive (Loss) Income

Comprehensive (Loss) Income

Comprehensive (loss) income includes net (loss) income 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 (loss) income. These changes, other than net (loss) income, are referred to as “other comprehensive loss” on the Partnership’s financial statements and, at June 30, 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 4). The Partnership does not have any other type of transaction which would be included within other comprehensive loss.

Recently Issued Accounting Standards

Recently Issued Accounting Standards

In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations and related disclosures.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required 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. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations and related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. On July 9, 2015, the FASB decided to defer the effective date of ASU 2014-09 by one year. As a result, public entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017, and to interim periods within that reporting period, with the option to adopt the standard as of the original effective date. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2018, and is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

XML

Certain Relationships and Related Party Transactions

6 Months Ended

Jun. 30, 2015

Related Party Transactions [Abstract]

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

NOTE 6 - 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 expense in the Partnership’s statements of operations, are payable at $318 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 the working interest in a well. Transportation fees are included in production expense 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:

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Administrative fees	$	30,700	$	39,000	$	67,300	$	75,100
Supervision fees		130,200		165,300		285,400		318,300
Transportation fees		17,700		54,700		45,300		109,200
Direct costs		78,400		113,500		163,800		209,800
Total	$	257,000	$	372,500	$	561,800	$	712,400

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 sheets includes the net production revenues due to the MGP. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP.

XML

Commitments and Contingencies

6 Months Ended

Jun. 30, 2015

Commitments And Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 7 — COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor 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 June 30, 2015, the MGP has withheld $178,600 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.

XML

Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2015

Accounting Policies [Abstract]

Summary of Gas and Oil Properties

The following is a summary of gas and oil properties at the dates indicated:

	June 30, 2015			December 31, 2014
Proved properties:
Leasehold interests	$	1,402,200		$	1,402,200
Wells and related equipment		67,266,000			67,266,000
Total natural gas and oil properties		68,668,200			68,668,200
Accumulated depletion and impairment		(65,757,100	)		(65,707,900	)
Gas and oil properties, net	$	2,911,100		$	2,960,300

XML

Description of Business (Details)		6 Months Ended
	Feb. 27, 2015	Jun. 30, 2015
Description Of Business [Line Items]
Atlas America Public #14-2004 L.P. Formation Date		May 03, 2004
Atlas Energy Group | Atlas Energy | Spin Off
Description Of Business [Line Items]
Percentage of limited liability company interests distributed to unitholders	100.00%

XML

Derivative Instruments (Narrative) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Derivative [Line Items]
Net derivative assets	$ 21,500		$ 21,500		$ 25,700
Gains (Losses) on Fair Value Hedge Ineffectiveness, Net	0	$ 0	0	$ 0
Current portion of put premiums payable-affiliate	9,600		9,600		9,000
Long-term put premiums payable-affiliate	5,100		5,100		10,200
Accumulated other comprehensive income	$ 3,700		3,700		$ 6,500
Other Comprehensive Income
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months			3,000
Net Deferred Gain (Loss) to be Reclassified into Net Income in Later Periods			700
Allocation To Limited Partner Only | Other Comprehensive Income
Derivative [Line Items]
Net Derivative Gains (Losses) Limited Partner			$ 6,800

XML

CONDENSED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Statement Of Income And Comprehensive Income [Abstract]
Net (loss) income	$ (230,600)	$ 8,600	$ (407,300)	$ 50,600
Other comprehensive loss:
Unrealized holding gain (loss) on cash flow hedging contracts		1,000		(15,100)
Difference in estimated hedge gains receivable	2,100	(2,500)	4,300	26,300
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net (loss) income	(3,500)	500	(7,100)	(15,400)
Total other comprehensive loss	(1,400)	(1,000)	(2,800)	(4,200)
Comprehensive (loss) income	$ (232,000)	$ 7,600	$ (410,100)	$ 46,400

XML

Asset Retirement Obligation

6 Months Ended

Jun. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

NOTE 3—ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells. It also recognizes a liability for future asset retirement obligations 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.

The estimated liability is based on the MGP’s 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 an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates, 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 the Partnership’s 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 June 30, 2015, the MGP has withheld $178,600 of net production revenue for future plugging and abandonment costs.

A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows:

	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015		2014
Asset retirement obligation at beginning of period	$	5,515,900	$	3,662,800		$	5,438,100	$	3,609,200
Asset retirement obligations settled		-		(200	)		-		(200	)
Accretion expense		77,700		53,500			155,500		107,100
Asset retirement obligation at end of period	$	5,593,600	$	3,716,100		$	5,593,600	$	3,716,100

XML

Derivative Instruments (Summary of Gains or Losses Recognized Within Statements of Operations for Derivative Instruments Previously Designated as Cash Flow Hedges) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gain (loss) reclassified from accumulated other comprehensive income into natural gas, oil and liquids revenues	$ 3,500	$ (500)	$ 7,100	$ 15,400
(Loss) gain subsequent to December 31, 2014 recognized in (loss) gain on mark-to-market derivatives	$ (3,800)		$ 300

XML

Certain Relationships and Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2015

Related Party Transactions [Abstract]

Certain Relationships and Related Party Transactions

The following table provides information with respect to these costs and the periods incurred:

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Administrative fees	$	30,700	$	39,000	$	67,300	$	75,100
Supervision fees		130,200		165,300		285,400		318,300
Transportation fees		17,700		54,700		45,300		109,200
Direct costs		78,400		113,500		163,800		209,800
Total	$	257,000	$	372,500	$	561,800	$	712,400