pub14-10q_20160630.htm

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):

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

	June 30, 2016		December 31, 2015
ASSETS
Current assets:
Cash	$	-	$	-
Accounts receivable trade -affiliate		81,900		78,500
Current portion of derivative assets		10,500		26,500
Total current assets		92,400		105,000
Gas and oil properties, net		2,144,800		2,144,800
Long-term asset retirement receivable-affiliate		783,300		481,000
Total assets	$	3,020,500	$	2,730,800
LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities:
Accounts payable trade-affiliate	$	1,348,500	$	795,200
Accrued liabilities		12,000		11,100
Put premiums payable-affiliate		7,100		12,200
Total current liabilities		1,367,600		818,500
Asset retirement obligations		5,842,900		5,749,100
Commitments and contingencies (Note 6)
Partners’ deficit:
Managing general partner’s deficit		(571,000)		(447,600	)
Limited partners’ deficit (5,256.95 units)		(3,619,600)		(3,390,700	)
Accumulated other comprehensive income		600		1,500
Total partners’ deficit		(4,190,000)		(3,836,800	)
Total liabilities and partners’ deficit	$	3,020,500	$	2,730,800

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
REVENUES
Natural gas, oil and liquids	$	111,000	$	130,900	$	205,600	$	358,900
(Loss) gain on mark-to-market derivatives		(4,500)		(3,800)		700		300
Total revenues		106,500		127,100		206,300		359,200
COSTS AND EXPENSES
Production		211,600		211,500		372,500		465,000
Depletion		-		23,000		-		49,200
Accretion of asset retirement obligations		46,900		77,700		93,900		155,500
General and administrative		51,700		45,500		92,200		96,800
Total costs and expenses		310,200		357,700		558,600		766,500
Net loss	$	(203,700)	$	(230,600)	$	(352,300)	$	(407,300)
Allocation of net loss:
Managing general partner	$	(69,600)	$	(83,700)	$	(123,400)	$	(151,200)
Limited partners	$	(134,100)	$	(146,900)	$	(228,900)	$	(256,100)
Net loss per limited partnership unit	$	(26)	$	(28)	$	(44)	$	(49)

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Net loss	$	(203,700)	$	(230,600)	$	(352,300)	$	(407,300)
Other comprehensive loss:
Difference in estimated hedge receivable		-		2,100		-		4,300
Reclassification adjustment to net loss of mark-to-market (gains) losses on cash flow hedges		(500)		(3,500)		(900)		(7,100)
Total other comprehensive loss		(500)		(1,400)		(900)		(2,800)
Comprehensive loss	$	(204,200)	$	(232,000)	$	(353,200)	$	(410,100)

	Managing General Partner		Limited Partners		Accumulated Other Comprehensive Income (Loss)		Total
Balance at December 31, 2015	$	(447,600)	$	(3,390,700)	$	1,500	$	(3,836,800)
Participation in revenues, costs and expenses:
Net production expenses		(58,300)		(108,600)		-		(166,900)
Gain on mark-to-market derivatives		-		700		-		700
Accretion of asset retirement obligations		(32,800)		(61,100)		-		(93,900)
General and administrative		(32,300)		(59,900)		-		(92,200)
Net loss		(123,400)		(228,900)		-		(352,300)
Other comprehensive loss		-		-		(900)		(900)

Balance at June 30, 2016	$	(571,000)	$	(3,619,600)	$	600	$	(4,190,000)

	Six Months Ended
	June 30,
	2016		2015
Cash flows from operating activities:
Net loss	$	(352,300)	$	(407,300)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion		-		49,200
Non cash loss (gain) on derivative value		10,000		(3,100)
Accretion of asset retirement obligations		93,900		155,500
Asset retirement obligations settled		(100)		-
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable trade-affiliate		(3,400)		51,200
Increase in asset retirement receivable-affiliate		(302,300)		(151,200)
Increase in accounts payable trade-affiliate		553,300		309,600
Increase (decrease) in accrued liabilities		900		(3,800)
Net cash used in operating activities		-		100

Cash flows from investing activities:
Net cash used in investing activities		-		-

Cash flows from financing activities:
Net cash used in financing activities		-		-
Net change in cash		-		100
Cash at beginning of period		-		200
Cash at end of period	$	-	$	300

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”) (OTC: ARPJ). Unless the context otherwise requires, references to “the Partnership,” “we”, “us” and “our”, refer to Atlas America Public #14-2004 L.P.

Atlas Energy Group, LLC (“Atlas Energy Group”; OTC: ATLS) manages 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, for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas, oil and NGL. Produced natural gas, oil and NGL 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 condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2015, which is derived from audited financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made are adequate to make the information not misleading. 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, 2015. The results of operations for the three and six months ended June 30, 2016 may not necessarily be indicative of the results of operations for the year ended December 31, 2016.

The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.

The prices at which the Partnership’s natural gas, oil and NGL will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas, oil and NGL prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas, oil and NGL prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas, oil and NGL that the Partnership can produce economically.

The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position. In addition, the Partnership has experienced significant downward revisions of its natural gas and oil reserves volumes and values due to the declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be strategic in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations.

If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations have been adequate to fund its obligations and distributions to its partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months. To the extent commodity prices remain low or decline further or ARP is unsuccessful in completing its Restructuring (as defined below) or the Plan (as defined below), the MGP’s ability to continue the Partnership’s operations may be further impacted.

On July 25, 2016, ARP and certain of its subsidiaries, including the MGP, and Atlas Energy Group, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) to support ARP’s restructuring that will reduce debt on its balance sheet (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”). The Plan will position ARP for the future and is expected to be completed before the end of the third quarter of 2016, after which ARP should emerge from Chapter 11 (as defined below), backed by its stakeholders, committed to investing capital to develop its exploration and production assets, as well as its tax-advantaged drilling partnership program.

On July 27, 2016, ARP and certain of its subsidiaries, including the MGP, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The cases commenced thereby are being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.” Interested parties should refer to the information and the limitations and qualifications discussed in the disclosure statement related to the Restructuring which was filed as Exhibit 99.1 to ARP’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 25, 2016.

The MGP intends to continue to operate the Partnership’s businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, it is contemplated that all suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired and will be satisfied in full in the ordinary course of business, and the MGP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, the MGP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to the Partnership, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

The Partnership is not a party to the Restructuring Support Agreement. The ARP Restructuring is not expected to materially impact the MGP or its ability to perform as the managing general partner and operator of the Partnership’s operations. On July 26, 2016, the MGP adopted certain amendments to our partnership agreement, in accordance with the MGP’s ability to amend our partnership agreement to cure an ambiguity in or correct or supplement any provision of our partnership agreement as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the MGP’s Chapter 11 filing, with respect to the managing general partner will not cause the managing general partner to cease to serve as the managing general partner of the Partnership nor cause the termination of the Partnership.

Atlas Energy Group is not a party to the ARP Restructuring. Atlas Energy Group remains controlled by the same ownership group and management team and thus, the ARP Restructuring is not expected to have a material impact on the ability of Atlas Energy Group management to operate ARP or the other Atlas Energy Group businesses.

The preparation of the Partnership’s condensed 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 condensed financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s condensed 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. The natural gas industry principally conducts its business by processing actual transactions 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. Actual results could differ from those estimates.

	June 30, 2016			December 31, 2015
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		(66,523,400	)		(66,523,400	)
Gas and oil properties, net	$	2,144,800		$	2,144,800

As a result of the recent significant declines in commodity prices and associated recorded impairment charges, the remaining net book value of gas and oil properties on our condensed balance sheets at June 30, 2016 and December 31, 2015 was primarily related to the estimated salvage value of such properties. The estimated salvage values were based on the MGP’s historical experience in determining such values.

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. The updated guidance is effective as of January 1, 2017 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its condensed financial statements.

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its condensed financial statements and its method of adoption.

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally put contracts, in connection with the partnership’s commodity price risk management activities. The Partnership does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings.

The Partnership enters into commodity put contracts to achieve more predictable cash flows by hedging the Partnership’s exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Stock Exchange (“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. These contracts have been recorded at their fair values.

The Partnership reflected net derivative assets on its condensed balance sheets of $10,500 and $26,500 at June 30, 2016 and December 31, 2015, respectively.

The following table summarizes the commodity derivative activity presentation in the condensed statements of operations for the periods indicated:

(3) The production volume for 2016 include the remaining six months of 2016 beginning July 1, 2016.

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, 2016 and 2015 for hedge ineffectiveness.

The Partnership uses a market approach fair value methodology to value its outstanding derivative contracts. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. The Partnership separates the fair value of its financial instruments into three levels (Levels 1, 2 and 3) based on its assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of June 30, 2016 and December 31, 2015, all derivative financial instruments were classified as Level 2.

Information for assets measured at fair value at June 30, 2016 and December 31, 2015 was as follows:

	Level 1		Level 2		Level 3		Total
As of June 30, 2016
Derivative assets, gross
Commodity puts	$	-	$	10,500	$	-	$	10,500

	Level 1		Level 2		Level 3		Total
As of December 31, 2015
Derivative assets, gross
Commodity puts	$	-	$	26,500	$	-	$	26,500

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 condensed 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 condensed 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 expenses in the Partnership’s condensed 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 condensed 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,
	2016		2015		2016		2015
Administrative fees	$	37,300	$	30,700	$	63,900	$	67,300
Supervision fees		158,200		130,200		271,000		285,400
Transportation fees		17,200		17,700		30,900		45,300
Direct costs		50,600		78,400		98,900		163,800
Total	$	263,300	$	257,000	$	464,700	$	561,800

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 condensed balance sheets includes the net production expenses due to the MGP.

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, 2016, the MGP has withheld $783,300 of net production revenue for future plugging and abandonment costs.

The Partnership and affiliates of the MGP and their subsidiaries party to various routine legal proceedings arising out of the ordinary course of its business. Management and the MGP’s management believe that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s or the MGP’s financial condition or results of operations.

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.

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”) (OTCQX: ARPJ). Unless the context otherwise requires, references to “the Partnership,” “we,” “us” and “our” refer to Atlas America Public #14-2004 L.P.

Atlas Energy Group, LLC (“Atlas Energy Group”) manages ARP’s operations and activities through its ownership of the 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, 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.

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:

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, 2016, our MGP has withheld $783,300 of net production revenues for this purpose.

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 2016 and 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.

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,
	2016			2015			2016			2015
Production revenues (in thousands):
Gas	$	89		$	118		$	179		$	327
Oil		22			13			25			30
Liquids		-			-			1			2
Total	$	111		$	131		$	205		$	359
Production volumes:
Gas (mcf/day) ⁽¹⁾		662			830			655			887
Oil (bbl/day) ⁽¹⁾		6			2			3			3
Liquids (bbl/day) ⁽¹⁾		-			-			1			-
Total (mcfe/day) ⁽¹⁾		698			842			679			905
Average sales prices: ⁽²⁾
Gas (per mcf) ⁽¹⁾	$	1.48		$	1.56		$	1.50		$	2.04
Oil (per bbl) ⁽¹⁾	$	42.50		$	58.04		$	41.61		$	50.76
Liquids (per bbl) ⁽¹⁾	$	13.25		$	22.56		$	16.84		$	36.36
Production costs:
As a percent of revenues		191	%		162	%		181	%		130	%
Per mcfe ⁽¹⁾	$	3.33		$	2.75		$	3.02		$	2.83
Depletion per mcfe	$	-		$	0.30		$	-		$	0.30

Natural Gas Revenues. Our natural gas revenues were $89,100 and $118,000 for the three months ended June 30, 2016 and 2015, respectively, a decrease of $28,900 (24%). The $28,900 decrease in natural gas revenues for the three months ended June 30, 2016 as compared to the prior year similar period was attributable to a decrease of $23,900 in production volumes, and a $5,000 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions. Our production volumes decreased to 662 mcf per day for the three months ended June 30, 2016 from 830 mcf per day for the three months ended June 30, 2015, a decrease of 168 mcf per day (20%).

Our natural gas revenues were $179,300 and $327,000 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $147,700 (45%). The $147,700 decrease in natural gas revenues for the six months ended June 30, 2016 as compared to the prior year similar period was attributable to a $63,700 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions, and a $84,000 decrease in production volumes. Our production volumes decreased to 655 Mcf per day for the six months ended June 30, 2016 from 887 Mcf per day for the six months ended June 30, 2015, a decrease of 232 Mcf per day (26%). The overall decrease in natural gas production volumes for the six months ended June 30, 2016 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 $21,500 and $12,700 for the three months ended June 30, 2016 and 2015, respectively, an increase of $8,800 (69%). The $8,800 increase in oil revenues for the three months ended June 30, 2016 as compared to the prior year similar period was attributable to a $16,600 increase in production volumes, partially offset by a $7,800 decrease in oil prices. Our production volumes increased to 5.55 bbls per day for the three months ended June 30, 2016 from 2.40 bbls per day for the three months ended June 30, 2015, an increase of 3.15 bbl per day (131%).

Our oil revenues were $24,600 and $29,600 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $5,000 (17%). The $5,000 decrease in oil revenues for the six months ended June 30, 2016 as compared to the prior year similar period was attributable to a $5,400 decrease in oil prices, partially offset by a $400 increase in production volumes. Our production volumes increased to 3.24 bbls per day for the six months ended June 30, 2016 from 3.23 bbls per day for the six months ended June 30, 2015, an increase of 0.01 bbls per day (1%).

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 liquid revenues were $400 and $200 for the three months ended June 30, 2016 and 2015, respectively, an increase of $200 (100%). The $200 increase in natural gas liquid revenues for the three months ended June 30, 2016 as compared to the prior year similar period was attributed to a $500 increase in production volumes, partially offset by a $300 decrease in our natural gas liquid prices, which were driven by market conditions. Our production volumes increased to 0.37 bbl per day for the three months ended June 30, 2016 from 0.11 bbls per day for the three months ended June 30, 2015, an increase of 0.26 bbls per day (236%).

Our natural gas liquids revenues were $1,700 and $2,300 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $600 (26%). The $600 decrease in natural gas liquids revenues for the six months ended June 30, 2016 as compared to the prior year similar period was attributable to a $1,900 decrease in natural gas liquid prices, partially offset by a $1,300 increase in production volumes. Our production volumes increased to 0.54 bbls per day for the six months ended June 30, 2016 from 0.34 bbls per day for the six months ended June 30, 2015, an increase of 0.20 bbls per day (59%).

(Loss) Gain on Mark-to-Market Derivatives. We recognize changes in fair value of our derivatives immediately within (loss) gain on mark-to-market derivatives on our condensed statements of operations.

We recognized a loss on mark-to-market derivatives of $4,500 and $3,800 for the three months ended June 30, 2016 and 2015, respectively, and a gain of $700 and $300 for the six months ended June 30, 2016 and 2015, respectively. These changes were due primarily to mark-to-market fluctuations primarily related to the change in natural gas prices during the periods.

Costs and Expenses. Production expenses were $211,600 and $211,500 for the three months ended June 30, 2016 and 2015, respectively, an increase of $100. Production expenses were $372,500 and $465,000 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $92,500 (20%). The decrease for the six months ended June 30, 2016 is primarily due to a combination of a decrease in repairs and maintenance and a decrease in supervision fees.

For the three and six months ended June 30, 2016, there was no depletion recorded due to the recent significant declines in commodity prices and associated previously recorded impairment charges. Therefore, the remaining net book value of gas and oil properties on our condensed balance sheets at June 30, 2016 and December 31, 2015 was primarily related to the estimated salvage value of such properties. For the three and six months ended June 30, 2015, depletion of gas and oil properties as a percentage of gas and oil revenues was 18% and 14%, respectively.

General and administrative expenses for the three months ended June 30, 2016 and 2015 were $51,700 and $45,500, respectively, an increase of $6,200 (14%). For the six months ended June 30, 2016 and 2015, these expenses were $92,200 and $96,800 respectively, a decrease of $4,600 (5%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP and vary from period to period due to the costs charge to us and services provided to us.

We are generally limited to the amount of funds generated by the cash flow from our operations to fund our obligations and make distributions, if any, to our partners. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on our liquidity position. In addition, we have experienced significant downward revisions of its natural gas and oil reserves volumes and values due to the declines in commodity prices. The MGP continues to implement various cost saving measures to reduce our operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be strategic in managing our cost structure and, in turn, liquidity to meet our operating needs. To the extent commodity prices remain low or decline further, or we experience other disruptions in the industry, our ability to fund our operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate our operations.

If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of our assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from our operations have been adequate to fund our obligations and distributions to our partners. However, the recent significant declines in commodity prices have challenged our ability to fund our operations and may make it uneconomical for us to produce our wells until they are depleted as we originally intended. Accordingly, the MGP determined that there is substantial doubt about our ability to continue as a going concern. The MGP intends, as necessary, to continue our operations and to fund our obligations for at least the next twelve months. To the extent commodity prices remain low or decline further or ARP is unsuccessful in completing its Restructuring (as defined below) or the Plan (as defined below), the MGP’s ability to continue our operations may be further impacted.

Cash provided by operating activities decreased $100 in the six months ended June 30, 2016 to $0 as compared to $100 for the six months ended June 30, 2015. This was mostly due to a decrease the change in asset retirement receivable of $151,100, a decrease in the change in accounts receivable trade-affiliate of $54,600, a decrease in net earnings before depletion and accretion of $55,800, and a decrease in asset retirement obligation settled of $100. The decrease was partially offset by an increase in the change in accounts payable trade-affiliate of $243,700, an increase in the change in accrued liabilities of $4,700, and an increase in non-cash loss (gain) on derivative value of $13,100 for the six months ended June 30, 2016 compared to the six months ended June 30, 2015.

There was no cash used in financing activities for the six months ended June 30, 2016 and 2015.

Our MGP may withhold funds for future plugging and abandonment costs. Through June 30, 2016, our MGP has withheld $783,300 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.

See Note 2 to our condensed financial statements for additional information related to recently issued accounting standards.

For a more complete discussion of the accounting policies and estimates that we have identified as critical in the preparation of our condensed financial statements, please refer to our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2016, our disclosure controls and procedures were effective at the reasonable assurance level.

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.

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.

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

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)

		PAGE
PART I.	FINANCIAL INFORMATION (Unaudited)

Item 1:

	Condensed Balance Sheets as of June 30, 2016 and December 31, 2015	3

	Condensed Statements of Operations for the Three and Six Months ended June 30, 2016 and 2015	4

	Condensed Statements of Comprehensive Loss for the Three and Six Months ended June 30, 2016 and 2015	5

	Condensed Statement of Changes in Partners’ Deficit for the Six Months ended June 30, 2016	6

	Condensed Statements of Cash Flows for the Six Months ended June 30, 2016 and 2015	7

	Notes to Condensed Financial Statements	8

Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

Item 4:	Controls and Procedures	17

PART II.	OTHER INFORMATION

Item 1:	Legal Proceedings	17

Item 6:	Exhibits	18

SIGNATURES		19

CERTIFICATIONS

Production Period Ending December 31,	Volumes⁽³⁾		Average Fixed Price		Fair Value Asset ⁽²⁾
	(MMBtu) ⁽¹⁾		(per MMBtu) ⁽¹⁾
2016		9,300	$	4.15	$	10,500

Exhibit No.		Description

31.1		Certification Pursuant to Rule 13a-14/15(d)-14

31.2		Certification Pursuant to Rule 13a-14/15(d)-14

32.1		Section 1350 Certification

32.2		Section 1350 Certification

101		Interactive Data File


	ATLAS AMERICA PUBLIC #14-2004 L.P.

	By: Atlas Resources, LLC, its Managing General Partner

Date: August 15, 2016	By:	/s/ FREDDIE M. KOTEK
		Freddie M. Kotek, Chief Executive Officer and President of the Managing General Partner

Large accelerated filer	¨	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	þ