Dynagas LNG Partners (DLNG) 20-F 18 Apr 16 2015 FY Annual report (foreign) Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2015shares
Document Information
Document Type	20-F
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Entity Registrant Name	Dynagas LNG Partners LP
Entity Central Index Key	1,578,453
Trading Symbol	DLNG
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Well-known Seasoned Issuer	No
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Common Limited Partner
Document Information
Entity's units outstanding	20,505,000
Preferred Limited Partner
Document Information
Entity's units outstanding	3,000,000
Subordinated Limited Partner
Document Information
Entity's units outstanding	14,985,000
General Partner
Document Information
Entity's units outstanding	35,526

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 24,293	$ 11,949
Trade receivables, net	103	0
Prepayments and other assets	610	737
Inventories	348	357
Due from related party	460	889
Total current assets	25,814	13,932
FIXED ASSETS, NET:
Vessels, net	1,036,157	839,883
Total fixed assets, net	1,036,157	839,883
OTHER NON CURRENT ASSETS:
Restricted cash	25,000	24,000
Deferred revenue	0	943
Due from related party	1,350	1,125
Above-market acquired time charter contract	19,782	0
Total assets	1,108,103	879,883
CURRENT LIABILITIES:
Current portion of long term debt, net of deferred financing fees	27,467	19,584
Trade payables	4,935	2,369
Due to related party, current	230	142
Accrued liabilities	3,595	3,716
Unearned revenue	15,126	7,022
Total current liabilities	51,353	32,833
NON-CURRENT LIABILITIES:
Deferred revenue	1,094	1,429
Due to related party, non-current	35,000	0
Long-term debt, net of current portion and deferred financing fees	652,818	547,923
Total non-current liabilities	$ 688,912	$ 549,352
Commitments and contingencies
PARTNERS' EQUITY:
Common unitholders (unlimited authorized; 20,505,000 units issued and outstanding as at December 31, 2015and 2014)	$ 302,954	$ 304,729
Preferred unitholders (3,450,000 authorized; 3,000,000 Series A Preferred Units issued and outstanding as at December 31, 2015)	73,216	0
Subordinated unitholders(14,985,000 units issued and outstanding as at December 31, 2015 and 2014)	(8,427)	(7,131)
General Partner(35,526 units issued and outstanding as at December 31, 2015 and 2014)	95	100
Total partners' equity	367,838	297,698
Total liabilities and partners' equity	$ 1,108,103	$ 879,883

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - shares	Dec. 31, 2015	Dec. 31, 2014
Statement Of Financial Position
Common unitholders - units authorized	999,999,999	999,999,999
Common unitholders - units issued	20,505,000	20,505,000
Common unitholders - units outstanding	20,505,000	20,505,000
Series A Preferred Units authorized	3,450,000
Series A Preferred Units issued	3,000,000
Series A Preferred Units outstanding	3,000,000
Subordinated unitholders - units issued	14,985,000	14,985,000
Subordinated unitholders - units outstanding	14,985,000	14,985,000
General Partner unitholders - units issued	35,526	35,526
General Partner unitholders - units outstanding	35,526	35,526

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES:
Voyage revenues	$ 145,202	$ 107,088	$ 85,679
EXPENSES:
Voyage expenses	(983)	(910)	(675)
Voyage expenses-related party	(1,821)	(1,363)	(1,011)
Vessel operating expenses	(23,244)	(16,813)	(11,909)
General and administrative expenses	(1,086)	(1,014)	(387)
General and administrative expenses- related party	(719)	(937)	0
Management fees-related party	(4,870)	(3,566)	(2,737)
Depreciation	(24,387)	(17,822)	(13,579)
Operating income	88,092	64,663	55,381
OTHER INCOME/(EXPENSES):
Interest and finance costs	(27,974)	(14,524)	(9,732)
Interest income	35	221	0
Other, net	(103)	201	(29)
Total other expenses	(28,042)	(14,102)	(9,761)
Partnership's Net Income	60,050	50,561	45,620
Common unitholders' interest in Net Income	32,878	28,323	22,787
Preferred unitholders' interest in Net Income	3,019	0	0
Subordinated unitholders' interest in Net Income	24,028	22,170	22,787
General Partner's interest in Net Income	$ 125	$ 68	$ 46
Earnings per unit, basic and diluted:
Common unit (basic and diluted)	$ 1.6	$ 1.58	$ 2.95
Weighted average number of units outstanding, basic and diluted:
Common units	20,505,000	17,964,288	7,729,521

Consolidated Statements of Part

Consolidated Statements of Partners' Equity - USD ($) $ in Thousands	Total	Series A Preferred	Common	Subordinated	General
Balance at Dec. 31, 2012	$ 75,175		$ 23,278	$ 51,793	$ 104
Balance at Dec. 31, 2012			6,735,000	14,985,000	30,000
-Net income	45,620		$ 22,787	$ 22,787	$ 46
-Issuance of units, net of issuance costs (Note 9), value	136,904		$ 136,904
-Issuance of units (Note 9), shares			8,250,000
Balance at Dec. 31, 2013	257,699		$ 182,969	$ 74,580	$ 150
Balance at Dec. 31, 2013			14,985,000	14,985,000	30,000
-Net income	50,561		$ 28,323	$ 22,170	$ 68
-Issuance of units, net of issuance costs (Note 9), value	120,570		$ 120,444		$ 126
-Issuance of units (Note 9), shares			5,520,000		5,526
-Distributions declared and paid (Note 9)	(43,010)		$ (23,568)	(19,398)	$ (44)
-Preferential deemed dividend (Note 9)	(88,122)		(3,439)	(84,483)	(200)
Balance at Dec. 31, 2014	297,698		$ 304,729	$ (7,131)	$ 100
Balance at Dec. 31, 2014			20,505,000	14,985,000	35,526
-Net income	60,050	$ 3,019	$ 32,878	$ 24,028	$ 125
-Issuance of units, net of issuance costs (Note 9), value	72,297	$ 72,297
-Issuance of units (Note 9), shares		3,000,000
-Distributions declared and paid (Note 9)	(62,207)	$ (2,100)	(34,653)	(25,324)	(130)
Balance at Dec. 31, 2015	$ 367,838	$ 73,216	$ 302,954	$ (8,427)	$ 95
Balance at Dec. 31, 2015		3,000,000	20,505,000	14,985,000	35,526

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from Operating Activities:
Net income:	$ 60,050	$ 50,561	$ 45,620
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	24,387	17,822	13,579
Amortization and write-off of deferred financing fees	1,545	785	1,050
Deferred revenue amortization	608	2,065	(4,245)
Amortization of fair value of acquired time charters	218	0	0
Provision for doubtful debt	0	0	63
Changes in operating assets and liabilities:
Trade receivables	(103)	190	118
Prepayments and other assets	94	(250)	(178)
Inventories	9	(357)	0
Due from/to related party	292	278	(5,450)
Trade payables	1,808	310	(3,156)
Accrued liabilities	(68)	2,636	(1,081)
Unearned revenue	8,104	2,403	(2,116)
Net cash provided by Operating Activities	96,944	76,443	44,204
Cash flows from/(used in) Investing Activities:
Vessel Acquisitions	(205,045)	(404,530)	0
Net cash used in Investing Activities	(205,045)	(404,530)	0
Cash flows from/(used in) Financing Activities:
Increase in restricted cash	(1,000)	(2,000)	(15,227)
Payment of IPO issuance costs and other filing costs	(65)	(1,938)	0
Issuance of preferred units, net of issuance costs paid	72,446	0	0
Issuance of common units, net of issuance costs paid	0	120,514	138,800
Issuance of general partner units	0	126	0
Preferential deemed dividend	0	(88,122)	0
Distributions declared and paid	(62,207)	(43,010)	0
Proceeds from long-term debt	133,333	590,000	214,085
Repayment of long-term debt	(20,000)	(229,085)	(380,715)
Loan from/ (Repayment of loan to) related party	0	(5,500)	5,500
Payment of deferred finance fees	(2,062)	(6,626)	(970)
Net cash provided by/(used in) Financing Activities	120,445	334,359	(38,527)
Net increase in cash and cash equivalents	12,344	6,272	5,677
Cash and cash equivalents at beginning of the year	11,949	5,677	0
Cash and cash equivalents at end of the year	24,293	11,949	5,677
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the year for Interest	25,798	$ 10,724	$ 9,487
Non-cash Investing Activities:
Vessel acquisitions	$ 35,000

Basis of Presentation and Gener

Basis of Presentation and General Information:	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements
Basis of Presentation and General Information:	1. Basis of Presentation and General Information: Dynagas LNG Partners LP (“Dynagas Partners” or “the Partnership”) was incorporated as a limited Partnership on May 30, 2013, under the laws of the Republic of the Marshall Islands. On November 18 2013, the Partnership successfully completed its initial public offering (the “IPO”) on the NASDAQ Global Select Market, whereas, on December 29, 2014, the Partnership's common units ceased trading on NASDAQ and, on December 30, 2014, commenced trading on the NYSE. At the closing of the Offering, the Partnership entered into the following agreements: i) an Omnibus agreement with Dynagas Holding Ltd. (“Dynagas Holding” or the “Sponsor”, a company beneficially wholly owned by Mr. George Prokopiou, the Partnership's Chairman and major unitholder and his close family members) that provides the Partnership the right to purchase LNG carrier vessels at a purchase price to be determined pursuant to the terms and conditions contained therein and ii) a $30 million revolving credit facility with the Sponsor to be used for general Partnership purposes (Note 3(b)). The Partnership is engaged in the seaborne transportation industry through the ownership and operation of high specification liquefied natural gas (“LNG”) vessels and is the sole owner of all outstanding shares or units of the following subsidiaries as of December 31, 2015: Vessel Owning Subsidiaries: Company Name Country of incorporation Vessel Name Delivery Date to Partnership Year Built Cbm Capacity Pegasus Shipholding S.A. (“Pegasus”) Marshall Islands Clean Energy March 2007 2007 149,700 Lance Shipping S.A. (“Lance”) Marshall Islands Ob River July 2007 2007 149,700 Seacrown Maritime Ltd. (“Seacrown”) Marshall Islands Amur River (1) January 2008 2008 149,700 Fareastern Shipping Limited (“Fareastern”) Malta Arctic Aurora June 2014 2013 155,000 Navajo Marine Limited (“Navajo”) Marshall Islands Yenisei River September 2014 2013 155,000 Solana Holding Ltd. (“Solana”) Marshall Islands Lena River December 2015 2013 155,000 Renamed from Clean Force in June 2015. Non-Vessel Owning Subsidiaries: Company Name Country of incorporation Purpose of incorporation Quinta Group Corp. (“Quinta”) Nevis Holding company that owns all of the outstanding capital stock of Pegasus. Pelta Holdings S.A. (“Pelta”) Nevis Holding company that owns all of the outstanding capital stock of Lance. Dynagas Equity Holdings Ltd.(“Dynagas Equity”) Liberia Holding company that owns all of the outstanding capital stock of Quinta, Pelta, Seacrown, Fareastern, Navajo, Solana and Arctic LNG. Dynagas Operating GP LLC. (“Dynagas Operating GP”) Marshall Islands Limited Liability Company, in which the Partnership holds 100% membership interests and that has 100% of the Non-Economic General Partner Interest in Dynagas Operating LP. Dynagas Operating LP. ("Dynagas Operating") Marshall Islands Limited partnership in which the Partnership holds 100% percentage interests. Dynagas Finance Inc. (“Dynagas Finance”) Marshall Islands Wholly owned subsidiary of the Partnership whose activities are limited to co-issuing the Notes discussed under Note 5 and engaging in other activities incidental thereto. Arctic LNG Carriers Ltd. (“Arctic LNG”) Marshall Islands Wholly owned subsidiary of Dynagas Equity that currently has no operations in place nor is it engaged in any other activities. The technical, administrative and commercial management of the Partnership's vessels is performed by Dynagas Ltd. (the “Manager”), a related company, wholly owned by Mr. George Prokopiou, the Partnership's Chairman of the Board of Directors (Note 3(a)). As of December 31, 2015, Dynagas Holding owned 44.0% of the outstanding equity interests in the Partnership (excluding the Series A Preferred Units, which, generally, have no voting rights), including the 0.1% General Partner interest retained by it, as the General Partner is owned and controlled by the Partnership's Sponsor.

Significant Accounting Policies

Significant Accounting Policies and Recent Accounting Pronouncements:	12 Months Ended
	Dec. 31, 2015
Significant Accounting Policies and Recent Accounting Pronouncements
Significant Accounting Policies and Recent Accounting Pronouncements:	2. Significant Accounting Policies and Recent Accounting Pronouncements: (a) Principles of Consolidation: Dynagas Partners, as the holding company, determines whether it has a controlling financial interest in an entity by first evaluating whether the entity is a voting interest entity or a variable interest entity. Under Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 810 "Consolidation" a voting interest entity is an entity in which the total equity investment at risk is deemed sufficient to absorb the expected losses of the entity, the equity holders have all the characteristics of a controlling financial interest and the legal entity is structured with substantive voting rights. The holding company consolidates voting interest entities in which it owns all, or at least a majority (generally, greater than 50%) of the voting interest. Variable interest entities ("VIE") are entities as defined under ASC 810 that in general either has equity investors with non-substantive voting rights or that have equity investors that do not provide sufficient financial resources for the entity to support its activities. The holding company has a controlling financial interest in a VIE and is, therefore, the primary beneficiary of a VIE if it has the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. A VIE should have only one primary beneficiary which is required to consolidate the VIE. A VIE may not have a primary beneficiary if no party meets the criteria described above. The Partnership evaluates all arrangements that may include a variable interest in an entity to determine if it is the primary beneficiary, and would be required to include assets, liabilities and operations of a VIE in its consolidated financial statements. As of December 31, 2015 and 2014, no such interests existed. (b) Use of Estimates: (c) Other Comprehensive Income: (d) Foreign Currency Translation: (e) Cash and Cash Equivalents: (f) Restricted cash: (g) Trade Receivables: (h) Inventories: (i) Insurance Claims: (j) Vessels, Net: (k) Impairment of Long-Lived Assets: (l) Intangible assets/liabilities related to time charter acquired: (m) Accounting for Special Survey and Dry-Docking Costs: (n) Financing Costs: (o) Concentration of Credit Risk: During the years ended December 31, 2015 and 2014, charterers that individually accounted for more than 10% of the Partnership's revenues were as follows: Charterer 2015 2014 A 52 % 36 % B 29 % 50 % C 19 % 14 % 100 % 100 % (p) Accounting for Revenues and Related Expenses: (q) Repairs and Maintenance: (r) Earnings Per Unit: (s) Segment Reporting: (t) Fair Value Measurements: (u) Commitments and Contingencies: (v) Accounting for Financial Instruments: Recent Accounting Pronouncements: ASU 2014-15: In August 2014, FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern. ASU 2014-15 provides guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 requires an entity's management to evaluate at each reporting period based on the relevant conditions and events that are known at the date when financial statements are issued, whether there are conditions or events, that raise substantial doubt about the entity's ability to continue as a going concern within one year after the date that the financial statements are issued and to disclose the necessary information. The guidance is effective for annual periods ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. Management is in the process of assessing the impact of the new standard on the Partnership's consolidated financial position and performance. ASU 2015-06: In April 2015, the FASB issued ASU 2015-06, Effects of Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. The amendments in this Update specify that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business for periods before the date of a dropdown of net assets accounted for as a common control transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. The amendments in this Update are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Earlier application is permitted. An entity must apply the new guidance on a retrospective basis. The adoption of this standards update is not expected to have a material effect on the Partnership's future or historical financial position, results of operations or cash flows, to the extent that no drop down of a transferred business occurs. ASU 2015-11: In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory. ASU 2015-11 simplifies the subsequent measurement of inventory by replacing today's lower of cost or market test with a lower of cost and net realizable value test. The guidance applies only to inventories for which cost is determined by methods other than last-in first-out (LIFO) and the retail inventory method (RIM). Entities that use LIFO or RIM will continue to use existing impairment models. The guidance is effective for public business entities for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is permitted, and the new guidance must be applied prospectively after the date of adoption. Management is in the process of assessing the impact of the new standard on the Partnership's consolidated financial position and performance. ASU 2015-14: In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which will supersede the current revenue recognition guidance and outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. The ASU 2014-09 was amended by ASU 2015-14, Revenue from Contracts with Customers: Deferral of the Effective Date, which was issued in August 2015. Public entities can now elect to defer implementation of ASU 2014-09 to interim and annual periods beginning after December 15, 2017. Additionally, ASU 2015-14 permits early adoption of the standard but not before the original effective date, i.e. annual period beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. Based on current circumstances, the adoption of this new standard is not expected to have a material effect on the Partnership's future or historical financial position, results of operations or cash flows. The Partnership will evaluate the impact that ASU 2014-09 might have on its future consolidated financial statements, if relevant circumstances arise. ASU 2016-01: In January 2016, the FASB issued ASU 2016-01, Financial Instruments- Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The amendments in this Update affect all entities that hold financial assets or owe financial liabilities and address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. More precisely, the amendments in this Update i) require all equity investments to be measured at fair value with changes in the fair value recognized through net income (other than those accounted for under equity method of accounting or those that result in consolidation of the investee), ii) an entity to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments, iii) eliminate the requirement to disclose the fair value of financial instruments measured at amortized cost for entities that are not public business entities and the requirement for to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet for public business entities, iv) require public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes and v) require separate presentation of financial assets and financial liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments to the FASB Accounting Standards Codification prescribed in this Update are not expected to have a material effect on the Partnership's future financial position. ASU 2016-02: In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which provides new guidance related to accounting for leases and supersedes existing U.S. GAAP on lease accounting. The ASU will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases, unless the lease is a short term lease. Lessee accounting: A short term lease is defined in the ASU as a lease that, at the commencement date, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that the lessee is reasonably certain to exercise. The lease term is defined as the non-cancellable period for which a lessee has the right to use an underlying asset, together with all of the following: periods covered by an option to extend the lease if the lessee is reasonably certain to exercise that option; periods covered by an option to terminate the lease if the lessee is reasonably certain not to exercise that option; and periods covered by an option to extend (or not to terminate) the lease in which exercise of the option is controlled by the lessor. For short term leases, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. Leases not considered short term - For all other leases, the lessee will be required to recognize the following at the commencement date of the lease: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. Reasonably certain is a high threshold that is consistent with and intended to be applied in the same way as the reasonably assured threshold in the current leases guidance. In addition, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. Consistent with current guidance, the recognition, measurement, and presentation in the statements of income and cash flows will depend on the lease's classification as finance or operating lease. For finance leases, a lessee is required to recognize interest on the lease liability separately from amortization of the right-of-use asset in the statement of income; and classify repayments of the principal portion of the lease liability within financing activities and payments of interest on the lease liability and variable lease payments within operating activities in the statement of cash flows. For operating leases, a lessee is required to recognize a single lease cost in the statement of income (which will include both the amortization of the right-of-use asset and the “interest” element associated with the lease liability), calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis; and classify all cash payments within operating activities in the statement of cash flows. Lessor accounting: Under the new guidance, lessor accounting is largely unchanged. Certain targeted improvements were made to align, where necessary, lessor accounting with the lessee accounting model and Topic 606, Revenue from Contracts with Customers. Public business entities should apply the amendments in ASU 2016-02 for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities and all nonpublic business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. The adoption of this new standard is not expected to have a material effect on the Partnership's future or historical financial position, results of operations or cash flows.

Transactions with related parti

Transactions with related parties:	12 Months Ended
	Dec. 31, 2015
Related Party Transaction, Due from (to) Related Party
Transactions with related parties:	3. Transactions with related parties: During the years ended December 31, 2015, 2014 and 2013, the Partnership incurred the following charges in connection with related party transactions, which are included in the accompanying consolidated financial statements: Year ended December 31, 2015 2014 2013 Included in voyage expenses Charter hire commissions (a) $ 1,821 $ 1,363 $ 1,011 Included in general and administrative expenses Executive services fee (d) $ 599 $ 803 $ — Administrative services fee (e) $ 120 $ 134 $ — Management fees-related party Management fees (a) $ 4,870 $ 3,566 $ 2,737 As of December 31, 2015 and 2014 balances with related parties consisted of the following: Year ended December 31, 2015 2014 Assets: Working capital advances granted to the Manager (a) $ 460 $ 889 Security deposits to Manager (a) $ 1,350 $ 1,125 Liabilities included in Due to related party: Executive service charges due to Manager (d) $ — $ 135 Administrative service charges due to Manager (e) $ 30 $ — Other Partnership expenses due to Manager $ 200 $ 7 Total liabilities due to related party, current $ 230 $ 142 Credit financing balance due to Sponsor (c) $ 35,000 $ — Total liabilities due to related party, non-current $ 35,000 $ — (a) Dynagas Ltd. Dynagas Ltd.is a company beneficially owned by the Partnership's Chairman. The Manager provides each vessel-owning entity of the Partnership with certain technical and vessel administrative management services in exchange for a daily management fee, pursuant to identical management agreements that initially terminate on December 31, 2020, and which shall, thereafter, automatically be extended in additional eight-year increments if notice of termination is not previously provided by the Partnership's vessel-owning subsidiaries. The management agreements initially provided for a daily management fee of $2.5. Beginning on the first calendar year after the commencement of the vessel management agreements and each calendar year thereafter, these fees are adjusted upwards by 3% until expiration of the management agreement, subject to further annual increases to reflect material unforeseen costs of providing the management services, by an amount to be agreed between the Partnership and the Manager, which amount will be reviewed and approved by the Partnership's conflicts committee. Under the terms of the management agreements, the Manager charges the Partnership for any additional capital expenditures, financial costs, operating expenses for the vessels and general and administrative expenses of the vessel owning subsidiaries of the Partnership that are not covered by the management fees. In each of the years ended December 31, 2015, 2014 and 2013, each vessel was charged with a daily management fee of $2.7, $2.6 and $2.5, respectively. The management agreements also provide for: (i) a commission of 1.25% over charter-hire agreements arranged by the Manager and, (ii) a lump sum new-building supervision fee of $700 for the services rendered by the Manager in respect of the construction of the vessel plus out of pocket expenses. The agreements will terminate automatically after a change of control of the owners and/or of the owners' ultimate parent, in which case an amount equal to the estimated remaining fees but in any case not less than for a period of at the least 36 months and not more than 60 months, will become payable to the Manager. As of December 31, 2015, based on the maximum period prescribed in the management agreements and the basic daily fee in effect during the year ended December 31, 2015, such termination fee would be approximately $29.1 million. The management agreements also provide for an advance equal to three months daily management fee. In the case of termination of the management agreements, prior to their eight year term, by any reason other than Manager's default, the advance is not refundable. Such advances as of December 31, 2015 and 2014, amounted to $1,350 and $1,125, respectively, and are separately reflected in Non-Current Assets as Due from related party in the accompanying consolidated balance sheets. (b) Loan from related party On November 18, 2013, upon the completion of its IPO, the Partnership entered into an interest free $30.0 million revolving credit facility with its Sponsor, with an original term of five years from the closing date, to be used for general Partnership purposes, including working capital. The facility may be drawn and be prepaid in whole or in part at any time during the life of the facility. No amounts have been drawn under the respective facility as of December 31, 2015 and 2014. (c) Omnibus Agreement On November 18, 2013, the Partnership entered into an agreement with its Sponsor (the “Omnibus Agreement”) to govern among other things i) the terms and the extent the Partnership and the Sponsor may compete each other, ii) the procedures to be followed for the exercise of Partnership's options to acquire certain vessels offered by its Sponsor (the “Optional Vessels”) , iii) certain rights of first offer to the Sponsor for the acquisition of LNG carriers from the Partnership and, iv) Sponsor's provisions of certain indemnities to the Partnership. On June 23, 2014 and September 25, 2014, the Partnership completed the drop down of two of these Optional Vessels and acquired, the two sister, 2013 built, ice class, LNG carriers namely Arctic Aurora Yenisei River Arctic Aurora Yenisei River control transactions, with the aggregate amount of $88.1 million in excess of the assets' net book value recognized as preferential deemed dividend to the Sponsor (Note 9). Under the partnership agreement, the general partner has irrevocably delegated to the Partnership's Board of Directors the power to oversee and direct the operations, manage and determine the strategies and policies of Dynagas Partners. During the period from the IPO in November 2013 until the time of the Partnership's first annual general meeting ("AGM") in October 2014, the General Partner retained the sole power to appoint, remove and replace all members of the Partnership's Board of Directors. From the first AGM, three of the five board members became electable by the common unitholders and as a result, the Partnership no longer accounts for vessel acquisitions from the Sponsor as transfers of equity interests between entities under common control. On December 21, 2015, the Partnership completed the third dropdown from its Sponsor and acquired 100% of the ownership interests in the entity that owns and operates the Lena River Arctic Aurora Yenisei River Lena River Lena River Lena River The acquisition was funded with i) the net proceeds of an underwritten offering of 3,000,000 9.00% Series A Cumulative Perpetual Redeemable Preferred Units (the “Series A Preferred Units”) concluded in July 2015 (Note 9), ii) approximately $126.3 million from the borrowings under a new $200 million senior term loan facility backed by a group of lenders, with ABN Amro NV acting as agent, dated December 17, 2015 (the “$200 Million Term Loan Facility”) (Note 5), and iii) cash on hand. At the closing date of the transaction, the Sponsor provided a $35.0 million interest free credit financing to the Partnership in respect of unsettled amounts in connection with the acquisition, which should be repaid by the Partnership on the first business day falling 180 after the delivery of the vessel or at any earlier date at the Partnership's option. The Lena River As of December 31, 2015, the Partnership still retained the legal right to purchase from its' Sponsor four Optional Vessels, wholly owned by it. Following an amendment to the Omnibus Agreement in April 2016 (Note 13 (g)), the Partnership has also the right, but not the obligation, to acquire from its Sponsor its ownership interest in each of the five entities that each owns a 172,000 cubic meter ARC7 LNG carrier that is currently under construction, or the Additional Optional Vessels. (d) Executive Services Agreement On March 21, 2014, the Partnership entered into an executive services agreement with its Manager with retroactive effect from the IPO closing date, pursuant to which the Manager provides the Partnership the services of its executive officers, who report directly to the Board of Directors. Under the agreement, the Manager is entitled to an executive services fee of €538 per annum (or $587 on the basis of a Euro/US Dollar exchange rate of €1.0000/$1.0906 at December 31, 2015), payable in equal monthly installments. The agreement has an initial term of five years and automatically renews for successive five year terms unless terminated earlier. (e) Administrative Services Agreement On December 30, 2014 and effective as of the IPO closing date, the Partnership entered into an administrative services agreement with its Manager, according to which the Partnership is provided with certain financial, accounting, reporting, secretarial and information technology services, for a monthly fee of $10, plus expenses, payable in quarterly installments. The agreement can be terminated upon 120 days' notice granted either by the Partnership's Board of Directors or by Dynagas.

Vessels, net_

Vessels, net:	12 Months Ended
	Dec. 31, 2015
Vessels, Net [Abstract]
Vessels, net:	4. Vessels, net: The amounts in the accompanying consolidated balance sheets are analyzed as follows: Vessel Accumulated Net Book Balance December 31, 2013 $ 540,454 $ (87,279) $ 453,175 —Vessel acquisitions (Note (3(c)) 404,530 — 404,530 —Depreciation — (17,822 ) (17,822 ) Balance December 31, 2014 $ 944,984 $ (105,101) $ 839,883 —Vessel acquisitions and other additions to vessels' cost (Note (3(c)) 220,661 — 220,661 —Depreciation — (24,387 ) (24,387 ) Balance December 31, 2015 $ 1,165,645 $ (129,488) $ 1,036,157 On December 17, 2015, the Partnership entered into a Share Purchase Agreement with its Sponsor for the acquisition of one 2013 built 155,000 cubic meter (cbm) ice class LNG carrier with a time charter attached, the Lena River In June and September 2014, the Partnership entered into Share Purchase agreements with its Sponsor to acquire the Arctic Aurora Yenisei River Effective October 1, 2014, the Partnership revised its scrap rate estimate, used to calculate the value of scrap steel for the purpose of estimating the residual values of vessels, from an average fleet scrap rate of $0.717 per lightweight ton (or a vessel specific of 12% of the initial vessel cost) to $0.685 per lightweight ton per LNG carrier. The effect of this change in the year ended December 31, 2015, was to increase annual depreciation expense by $152. As of December 31, 2015, all vessels comprising the Partnership's fleet were first priority mortgaged as collateral to secure the Partnership's debt financing outstanding as of December 31, 2015, further discussed in Note 5.

Long-Term Debt_

Long-Term Debt:	12 Months Ended
	Dec. 31, 2015
Debt Disclosure
Long-Term Debt:	5. Long-Term Debt: The amounts shown in the accompanying consolidated balance sheets are analyzed as follows: December 31, Debt instruments Borrowers-Issuers 2015 2014 $340.0 million Credit Facility Pegasus-Lance-Seacrown-Fareastern 305,000 325,000 $250.0 million Senior Unsecured Notes Dynagas LNG Partners LP - Dynagas Finance Inc. 250,000 250,000 $200 Million Term Loan Facility Navajo- Solana 133,333 — Total debt $ 688,333 $ 575,000 Less deferred financing fees (8,048 ) (7,493 ) Total debt, net of deferred finance costs $ 680,285 $ 567,507 Less current portion, net of deferred financing fees $ (27,467 ) $ (19,584 ) Long-term portion $ 652,818 $ 547,923 $340 million Senior Secured Revolving Credit Facility: On June 19, 2014, certain subsidiaries of the Partnership entered, on a joint and several basis, into a Senior Secured Revolving Credit Facility (the “$340 Million Credit Facility”) with an affiliate of Credit Suisse for $340.0 million to refinance the $214.1 million outstanding under a previous credit facility with the same lender and to fund a portion of the purchase price for the Arctic Aurora 2014, the Partnership drew down in full the amount available under the respective facility, a part of which, along with the net proceeds from a follow on public common units offering concluded in June 2014 (Note 9), was utilized to fund the acquisition of the Arctic Aurora under the facility was used to fully repay the then outstanding principal and interest of the previous facility. The $340 Million Credit Facility is guaranteed by the Partnership, Dynagas Equity Holding Ltd. and Dynagas Operating LP and is secured by a first priority or preferred cross-collateralized mortgage on each of the Amur River Ob River Clean Energy Arctic Aurora The $340 Million Credit Facility contains financial and other covenants that require the Partnership to maintain: • a maximum ratio of total consolidated liabilities of the Partnership's consolidated market value adjusted total assets; • a minimum interest coverage ratio; • minimum consolidated liquidity of $24.0 million; • employ at least three vessels in the fleet on charters with a minimum initial term of at least three years at above breakeven costs and • a minimum hull cover ratio, being the ratio of the aggregate of the vessels' market values and the net realizable value of any additional security over the outstanding amount of the facility. In addition, during the security period, the Sponsor, will be required to own, directly or indirectly, at least 30% of the outstanding voting interests of the Partnership (which shall include common and subordinated units of the Partnership) and 100% of the outstanding voting interests and limited liability company interests in the General Partner. Finally, the $340 Million Credit Facility similarly restricts the Partnership from paying any distributions if an event of default occurs. $250 Million Senior Unsecured Notes due 2019 On September 15, 2014 the Partnership completed a public offering of $250.0 million aggregate principal amount Senior Unsecured Notes offering due October 30, 2019, (the “Notes”) with the purpose of funding the majority of the purchase price related to the Yenisei River Yenisei River The Notes contain financial covenants that require the Partnership to: • maintain aggregate free liquidity, which includes the minimum liquidity held under the $340 Million Credit Facility, of at least $20.0 million; • a maximum ratio expressed as a percentage of total borrowings to total book assets and • maintain a certain minimum net worth level. On terms similar with the $340 Million Credit Facility, the Notes restrict the Partnership from declaring or making any distributions if an event of default occurs. $200 Million Term Loan Facility On December 17, 2015, Navajo and Solana, wholly owned subsidiaries of the Partnership, entered, on a joint and several basis, into a facility agreement with a group of lenders (ABN AMRO N.V., KFW IPEX-Bank GMBH and DNB ASA), with ABN Amro NV acting as agent, for a senior secured term loan facility of up to $200.0 million, to partially finance the Lena River Lena River Lena River Yenisei River Lena River The $200 Million Term Loan Facility contains financial and other covenants similar to those of the $340 Million Credit Facility and the Notes that require the Partnership to maintain: • a maximum ratio of total consolidated liabilities of the Partnership's consolidated market value adjusted total assets; • a minimum interest coverage ratio; • minimum consolidated liquidity of at least $25.0 million, which shall include the $24.0 million minimum consolidated liquidity requirement imposed under the $340 Million Credit Facility and • a minimum asset cover ratio, on a per vessel basis, being the ratio of the vessel's market value and the net realizable value of any additional security over the outstanding amount of the relevant tranche. The $200 Million Term Loan Facility further imposes certain additional cash related restrictions that require the borrowing entities (Solana and Navajo) to: • maintain minimum liquidity of $2.5 million on a per vessel basis and • build up, by the third anniversary from drawdown date, a cash collateral reserve of $7.5 million per vessel on a designated account by 33 and 31 equal monthly installments for each of the Lena River Yenisei River The $200 Million Term Loan Facility contains customary general undertakings that require the Partnership to limit shareholder loans with respect to the borrowers up to maximum amount, restrict additional indebtedness with respect to the borrowers and ensure that the Sponsor always maintains, directly or indirectly, at least 30% of the outstanding voting interests of the Partnership. On terms similar with the $340 Million Credit Facility and the Notes, the $200 Million Term Loan Facility restricts the Partnership from paying any distributions if an event of default occurs. The undrawn borrowing capacity under the Partnership's debt agreements as at December 31, 2015, and 2014 was $66.7 million and nil, respectively. As of December 31, 2015, the Partnership was in compliance with all financial covenants prescribed in its debt agreements. The annual principal payments for the Partnership's outstanding debt arrangements as at December 31, 2015, required to be made after the balance sheet date were as follows: Year ending December 31, Amount 2016 $ 28,333 2017 28,333 2018 28,333 2019 278,334 2020 120,000 2021 and thereafter 205,000 Total long term debt $ 688,333 The Partnership's weighted average interest rate on its long-term debt for the years ended December 31, 2015, 2014 and 2013 was 4.5%, 3.8% and 2.4%, respectively. Total interest incurred on long-term debt for the years ended December 31, 2015, 2014 and 2013, amounted to$25,926, $13,338 and $8,248, respectively and is included in Interest and finance costs (Note 11) in the accompanying consolidated statements of income. Commitment fees incurred for 2015, 2014 and 2013, amounted to $15, $360 and $327 respectively. Such fees are included in Interest and finance costs (Note 11) in the accompanying consolidated statements of income.

Fair Value Measurements_

Fair Value Measurements:	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements
Fair Value Measurements:	6. Fair Value Measurements: The carrying amounts of cash and cash equivalents, trade receivables, trade payables and current portion of amounts due to/from related party reported in the accompanying consolidated balance sheets approximate their respective fair values because of the short-term nature of these accounts. The fair values of long-term bank loan and restricted cash approximate the recorded values due to the variable interest rates payable. The Notes have a fixed rate, and their estimated fair value, determined through Level 2 inputs of the fair value hierarchy (quoted price in the over-the counter-market), is approximately $172.5 million as of December 31, 2015, compared to its carrying value of $250.0 million. The fair value of non-current portion of amounts due from related party, determined through Level 3 inputs of the fair value hierarchy by discounting future cash flows using the Partnership's estimated cost of capital, is $891 as of December 31, 2015, compared to its carrying value of $1,350. Additionally, the Partnership considers its creditworthiness in determining the fair value of the credit facilities. The guidance for fair value measurements applies to all assets and liabilities that are being measured and reported on a fair value basis. This guidance enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. The statement requires that assets and liabilities carried at fair value be classified and disclosed in one of the following three categories: Level 1: Quoted market prices in active markets for identical assets or liabilities. Level 2: Observable market-based inputs or unobservable inputs that are corroborated by market data. Level 3: Unobservable inputs that are not corroborated by market data.

Time charters acquired_

Time charters acquired:	12 Months Ended
	Dec. 31, 2015
Amortization of above-market acquired time charter contract to revenues
Time charters acquired:	7. Time charters acquired: During 2015, the Partnership acquired from its Sponsor one LNG carrier, the Lena River For the year ended December 31, 2015, the amortization of the above market acquired time charter related to the Lena River Year ending December 31, Amount 2016 $ 7,267 2017 7,247 2018 5,268 Total $ 19,782

Commitments and Contingencies_

Commitments and Contingencies:	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure
Commitments and Contingencies:	8. Commitments and Contingencies: (a) Long-term time charters: In June 2015, the Amur River Amur River The Partnership's future minimum contractual charter revenues under its non-cancelable long-term time charter contracts as of December 31, 2015, gross of brokerage commissions, without taking into consideration any assumed off-hire (including those arising out of periodical class survey requirements), are as analyzed below: Year ending December 31, Amount 2016 $ 178,590 2017 147,211 2018 79,791 2019 24,273 2020 24,339 Thereafter 176,425 Total $ 630,629 (b) Other: Various claims, suits, and complaints, including those involving government regulations and product liability, arise in the ordinary course of the shipping business. In addition, losses may arise from disputes with charterers, agents, insurance and other claims with suppliers relating to the operations of the Partnership's vessels. Currently, management is not aware of any such claims not covered by insurance or contingent liabilities, which should be disclosed, or for which a provision should be established in the accompanying unaudited interim condensed consolidated financial statements. The Partnership accrues for the cost of environmental liabilities when management becomes aware that a liability is probable and is able to reasonably estimate the probable exposure. Currently, management is not aware of any such claims or contingent liabilities, which should be disclosed, or for which a provision should be established in the accompanying unaudited interim condensed consolidated financial statements. The Partnership is covered for liabilities associated with the individual vessels' actions to the maximum limits as provided by Protection and Indemnity (P&I) Clubs, members of the International Group of P&I Clubs. (c) Technical and Commercial Management Agreement: As further disclosed in Note 3, the Partnership has contracted the commercial, administrative and technical management of its vessels to Dynagas Ltd. For the commercial services provided under this agreement the Partnership pays a commission of 1.25% over the charter-hire revenues arranged by the Manager, which will survive the termination of the agreement under all circumstances until the termination of each charter party in force at the time of termination. The estimated commission payable to the Manager over the minimum contractual charter revenues, discussed under (a) above, is $7,883. For vessel administrative and technical management fees the Partnership currently pays a daily management fee of $2.7 per vessel (Note 3(a)). Such management fees for the period from January 1, 2016 to the expiration of the agreements on December 31, 2020, adjusted for 3% inflation as per agreement, are estimated to be $31,798 and are analyzed as follows: Period/ Year ending December 31, Amount 2016 $ 6,000 2017 6,162 2018 6,347 2019 6,537 2020 6,752 Total $ 31,798

Partners' Equity_

Partners' Equity:	12 Months Ended
	Dec. 31, 2015
Partners' Equity
Partners' Equity:	9. Partners' Equity: (a) Initial Public Offering (b) Common Units Offering: Arctic Aurora (c) Preferred Units Offering: Lena River As of December 31, 2015, the Partnership had 20,505,000 common units, 14,985,000 subordinated units, 3,000,000 Series A Preferred Units and 35,526 general partner units issued and outstanding. Common, Subordinated and General Partner Units Distributions: • first • second • third Thereafter, the percentage allocations of the additional available cash from operating surplus among the unitholders, the General Partner and the holders of the incentive distribution rights up to the various target distribution levels are as follows: Total Quarterly Unitholders General Holders Minimum Quarterly Distribution $0.365 99.9 % 0.1 % 0.0 % First Target Distribution up to $0.420 99.9 % 0.1 % 0.0 % Second Target Distribution above $0.420 up to $0.456 85.0 % 0.1 % 14.9 % Third Target Distribution Above $0.456 up to $0.548 75.0 % 0.1 % 24.9 % Thereafter above $0.548 50.0 % 0.1 % 49.9 % Under the partnership agreement, the holder of the incentive distribution rights in the Partnership, which is currently the General Partner, assuming that there are no cumulative arrearages on common unit distributions, has the right to receive an increasing percentage of cash distributions after the first target distribution. General Partner Distributions: Preferred Units Distributions: Any time on or after August 12, 2020, the Series A Preferred Units may be redeemed, in whole or in part, at the issuer's option, out of amounts legally available thereof, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption. The Series A Preferred Units represent perpetual equity interests in the Partnership and, unlike the Partnership's indebtedness, do not give rise to a claim for payment of a principal amount at a particular date. The Series A Preferred Units rank senior to the Partnership's common units and to each other class or series of limited partner interests or other equity established after the original issue date of the Series A Preferred Units that is not expressly made senior to or on a parity with the Series A Preferred Units as to payment of distributions. The Series A Preferred Units rank junior to all of the Partnership's indebtedness. On January 14, 2015, the Partnership's Board of Directors approved its increased over the previous quarter cash distribution for the fourth quarter of 2014 of $0.4225 per common and subordinated unit, or $15.0 million, which was paid on February 12, 2015, to all unitholders of record as of February 5, 2015. On April 16, 2015, the Partnership's Board of Directors approved a quarterly cash distribution, for the quarter ended March 31, 2015, of $0.4225 per common and subordinated unit, or $15.0 million, which was paid on May 12, 2015, to all unitholders of record as of May 5, 2015. On July 22, 2015, the Partnership's Board of Directors approved a quarterly cash distribution, for the quarter ended June 30, 2015, of $0.4225 per common and subordinated unit, or $15.0 million, which was paid on August 13, 2015, to all unitholders of record as of August 6, 2015. On October 21, 2015, the Partnership's Board of Directors approved a quarterly cash distribution, for the quarter ended September 30, 2015 of $0.4225 per common and subordinated unit, or $15.0 million which was paid up to November 12, 2015, to all unitholders of record as of November 5, 2015. On October 21, 2015, the Partnership's Board of Directors further approved the first prorated cash distribution on the Series A Preferred units, for the period from July 20, 2015 to November 12, 2015, which was paid on November 12, 2015, to all preferred unitholders of record as of November 5, 2015. In addition, on June 23, 2014 and September 25, 2014, upon acquisition from the Partnership's Sponsor of the Arctic Aurora Yenisei River,

Earnings per Unit_

Earnings per Unit:	12 Months Ended
	Dec. 31, 2015
Earnings Per Unit
Earnings per Unit:	10. Earnings per Unit: The Partnership calculates earnings per unit by allocating distributed and undistributed net income/ (losses) for each period to common, subordinated and general partner units, after adjusting for the effect of preferred distributions, only to the extent that they are earned. Any undistributed earnings for the period are allocated to the various unitholders based on the distribution waterfall for cash available for distribution specified in Dynagas Partners' partnership agreement, as generally prescribed in Note 9 above. Where distributions relating to the period are in excess of earnings, the deficit is also allocated according to the cash distribution model.The sum of the distributed amounts and the allocation of the undistributed earnings or deficit to each class of unitholders is divided by the weighted average number of units outstanding during the period. Diluted earnings per unit, if applicable, reflects the potential dilution that could occur if potentially dilutive instruments were exercised, resulting in the issuance of additional units that would then share in the Partnership's net earnings. The calculations of the basic and diluted earnings per common unit are presented below: Year ended December 31, 2015 2014 2013 Partnership's Net income $ 60,050 $ 50,561 $ 45,620 Less: Net Income attributable to preferred unitholders 3,019 — — Net Income attributable to subordinated unitholders 24,028 22,170 22,787 General Partner's interest in Net Income 125 68 46 Net income attributable to common unitholders $ 32,878 $ 28,323 $ 22,787 Weighted average number of common units outstanding, basic and diluted 20,505,000 17,964,288 7,729,521 Earnings per common unit, basic and diluted $ 1.60 $ 1.58 $ 2.95

Interest and Finance Costs_

Interest and Finance Costs:	12 Months Ended
	Dec. 31, 2015
Interest and Finance Costs
Interest and Finance Costs:	11. Interest and Finance Costs: The amounts in the accompanying consolidated statements of income are analyzed as follows: Year ended December 31, 2015 2014 2013 Interest expense (Note 5) $ 25,926 $ 13,338 $ 8,248 Amortization of deferred financing fees 1,545 785 1,050 Commitment fees (Note 5) 15 360 327 Other 488 41 107 Total $ 27,974 $ 14,524 $ 9,732

Taxes_

Taxes:	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure
Taxes:	12. Taxes: Under the laws of the countries of the companies' incorporation and / or vessels' registration, the companies are not subject to tax on international shipping income; however, they are subject to registration and tonnage taxes, which are included in Vessel operating expenses in the accompanying consolidated statements of income. In addition, effective January 1, 2013, each foreign flagged vessel managed in Greece by Greek or foreign ship management companies is subject to Greek tonnage tax, under the laws of the Greek Republic. The technical manager of the Partnership's vessels, Dynagas Ltd an affiliate (Note 3(a)) which is established in Greece under Greek Law 89/67 is responsible for the filing and payment of the respective tonnage tax on behalf the Partnership. These tonnage taxes for the years ended December 31, 2015, 2014 and 2013 amounted $270, $245 and $96, respectively, and have also been included in Vessel operating expenses in the accompanying consolidated statements of income. Pursuant to the Internal Revenue Code of the United States (the “Code”), U.S. source income from the international operations of ships is generally exempt from U.S. tax if the Partnership operating the ships meets both of the following requirements, (a) the Partnership is organized in a foreign country that grants an equivalent exception to corporations organized in the United States and exempts the type of income earned by the vessel owing Partnership and (b) either (i) more than 50% of the value of the Partnership's stock is owned, directly or indirectly, by individuals who are “residents” of the Partnership's country of organization or of another foreign country that grants an “equivalent exemption” to corporations organized in the United States (50% Ownership Test) or (ii) the Partnership's stock is “primarily and regularly traded on an established securities market” in its country of organization, in another country that grants an “equivalent exemption” to United States corporations, or in the United States (Publicly-Traded Test). Additionally, the Partnership must meet all of the documentation requirements as outlined in the regulations. The Partnership and each of its subsidiaries expects to qualify for this statutory tax exemption for the 2015, 2014 and 2013 taxable years, and the Partnership takes this position for United States federal income tax return reporting purposes. In the absence of an exemption under Section 883, based on its U.S. source Shipping Income, the Partnership would be subject to U.S. federal income tax approximately nil for the year ended December 31, 2013, $15 for the year ended December 31, 2014, and $42 for the year ended December 31, 2015.

Subsequent Events_

Subsequent Events:	12 Months Ended
	Dec. 31, 2015
Subsequent Events
Subsequent Events:	13. Subsequent Events: (a) $200 Million Term Loan Facility draw down Lena River (b) Fourth quarter of 2015 common and subordinated units distribution: (c) Quarterly Series A Preferred Units distribution: (d) Lena River new time charter: Lena River Lena River Lena River Lena River (e) Yenisei River new time charter: Yenisei iver Yenisei River Yenisei River Lena River Yenisei River which, if not satisfied or waived with Yamal, may result in the termination of the charter at the charterer's option, prior to or after employment commences. (f) Ob River new time charter: (g) Omnibus Agreement Amendment: i) the terms and the extent the Partnership and the Sponsor may compete each other, ii) the procedures to be followed for the exercise of Partnership's options to acquire the Optional Vessels (as defined in the Omnibus Agreement) , including the Partnership's right to acquire the Sponsor's ownership interest (which is currently 49.0%) in each of five joint venture entities, each of which owns a 172,000 cubic meter ARC 7 LNG carrier, currently under construction, iii) certain rights of first offer to the Sponsor for the acquisition of LNG carriers from the Partnership and, iv) the Sponsor's provisions of certain indemnities to the Partnership.

Significant Accounting Polici20

Significant Accounting Policies and Recent Accounting Pronouncements (Policy)	12 Months Ended
	Dec. 31, 2015
Significant Accounting Policies and Recent Accounting Pronouncements
Principles of Consolidation:	(a) Principles of Consolidation: Dynagas Partners, as the holding company, determines whether it has a controlling financial interest in an entity by first evaluating whether the entity is a voting interest entity or a variable interest entity. Under Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 810 "Consolidation" a voting interest entity is an entity in which the total equity investment at risk is deemed sufficient to absorb the expected losses of the entity, the equity holders have all the characteristics of a controlling financial interest and the legal entity is structured with substantive voting rights. The holding company consolidates voting interest entities in which it owns all, or at least a majority (generally, greater than 50%) of the voting interest. Variable interest entities ("VIE") are entities as defined under ASC 810 that in general either has equity investors with non-substantive voting rights or that have equity investors that do not provide sufficient financial resources for the entity to support its activities. The holding company has a controlling financial interest in a VIE and is, therefore, the primary beneficiary of a VIE if it has the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. A VIE should have only one primary beneficiary which is required to consolidate the VIE. A VIE may not have a primary beneficiary if no party meets the criteria described above. The Partnership evaluates all arrangements that may include a variable interest in an entity to determine if it is the primary beneficiary, and would be required to include assets, liabilities and operations of a VIE in its consolidated financial statements. As of December 31, 2015 and 2014, no such interests existed.
Use Of Estimates:	(b) Use of Estimates:
Other Comprehensive Income:	(c) Other Comprehensive Income:
Foreign Currency Translation:	(d) Foreign Currency Translation:
Cash and Cash Equivalents:	(e) Cash and Cash Equivalents:
Restricted cash:	(f) Restricted cash:
Trade Receivables:	(g) Trade Receivables:
Inventories:	(h) Inventories:
Insurance Claims:	(i) Insurance Claims:
Vessels, Net:	(j) Vessels, Net:
Impairment of Long-Lived Assets:	(k) Impairment of Long-Lived Assets:
Intangible assets/liabilities related to time charter acquired:	(l) Intangible assets/liabilities related to time charter acquired: Impairment testing is performed when events or changes in circumstances indicate that the carrying amount of the intangible asset may not be recoverable.
Accounting for Special Survey and Dry-Docking Costs:	(m) Accounting for Special Survey and Dry-Docking Costs:
Financing Costs:	(n) Financing Costs:
Concentration of Credit Risk:	(o) Concentration of Credit Risk: During the years ended December 31, 2015 and 2014, charterers that individually accounted for more than 10% of the Partnership's revenues were as follows: Charterer 2015 2014 A 52 % 36 % B 29 % 50 % C 19 % 14 % 100 % 100 %
Accounting for Revenues and Related Expenses:	(p) Accounting for Revenues and Related Expenses:
Repairs and Maintenance:	(q) Repairs and Maintenance
Earnings Per Unit:	(r) Earnings Per Unit
Segment Reporting:	(s) Segment Reporting:
Fair Value Measurements:	(t) Fair Value Measurements:
Commitments and Contingencies:	(u) Commitments and Contingencies:
Accounting for Financial Instruments:	(v) Accounting for Financial Instruments:
Recent Accounting Pronouncements:	Recent Accounting Pronouncements: ASU 2014-15: In August 2014, FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern. ASU 2014-15 provides guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 requires an entity's management to evaluate at each reporting period based on the relevant conditions and events that are known at the date when financial statements are issued, whether there are conditions or events, that raise substantial doubt about the entity's ability to continue as a going concern within one year after the date that the financial statements are issued and to disclose the necessary information. The guidance is effective for annual periods ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. Management is in the process of assessing the impact of the new standard on the Partnership's consolidated financial position and performance. ASU 2015-06: In April 2015, the FASB issued ASU 2015-06, Effects of Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. The amendments in this Update specify that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business for periods before the date of a dropdown of net assets accounted for as a common control transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. The amendments in this Update are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Earlier application is permitted. An entity must apply the new guidance on a retrospective basis. The adoption of this standards update is not expected to have a material effect on the Partnership's future or historical financial position, results of operations or cash flows, to the extent that no drop down of a transferred business occurs. ASU 2015-11 : ASU 2015-14: In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which will supersede the current revenue recognition guidance and outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. The ASU 2014-09 was amended by ASU 2015-14, Revenue from Contracts with Customers: Deferral of the Effective Date, which was issued in August 2015. Public entities can now elect to defer implementation of ASU 2014-09 to interim and annual periods beginning after December 15, 2017. Additionally, ASU 2015-14 permits early adoption of the standard but not before the original effective date, i.e. annual period beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. Based on current circumstances, the adoption of this new standard is not expected to have a material effect on the Partnership's future or historical financial position, results of operations or cash flows. The Partnership will evaluate the impact that ASU 2014-09 might have on its future consolidated financial statements, if relevant circumstances arise. ASU 2016-01: In January 2016, the FASB issued ASU 2016-01, Financial Instruments- Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The amendments in this Update affect all entities that hold financial assets or owe financial liabilities and address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. More precisely, the amendments in this Update i) require all equity investments to be measured at fair value with changes in the fair value recognized through net income (other than those accounted for under equity method of accounting or those that result in consolidation of the investee), ii) an entity to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments, iii) eliminate the requirement to disclose the fair value of financial instruments measured at amortized cost for entities that are not public business entities and the requirement for to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet for public business entities, iv) require public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes and v) require separate presentation of financial assets and financial liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments to the FASB Accounting Standards Codification prescribed in this Update are not expected to have a material effect on the Partnership's future financial position. ASU 2016-02: In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which provides new guidance related to accounting for leases and supersedes existing U.S. GAAP on lease accounting. The ASU will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases, unless the lease is a short term lease. Lessee accounting: A short term lease is defined in the ASU as a lease that, at the commencement date, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that the lessee is reasonably certain For short term leases, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. Leases not considered short term - all only Consistent with current guidance, the recognition, measurement, and presentation in the statements of income and cash flows will depend on the lease's classification as finance or operating lease. For finance leases, a lessee is required to recognize interest on the lease liability separately from amortization of the right-of-use asset in the statement of income; and classify repayments of the principal portion of the lease liability within financing activities and payments of interest on the lease liability and variable lease payments within operating activities in the statement of cash flows. For operating leases, a lessee is required to recognize a single lease cost in the statement of income (which will include both the amortization of the right-of-use asset and the “interest” element associated with the lease liability), calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis; and classify all cash payments within operating activities in the statement of cash flows. Lessor accounting: Under the new guidance, lessor accounting is largely unchanged. Certain targeted improvements were made to align, where necessary, lessor accounting with the lessee accounting model and Topic 606, Revenue from Contracts with Customers Public business entities should apply the amendments in ASU 2016-02 for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities and all nonpublic business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. The adoption of this new standard is not expected to have a material effect on the Partnership's future or historical financial position, results of operations or cash flows.

Basis of Presentation and Gen21

Basis of Presentation and General Information (Tables)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements
Vessel Owning Subsidiaries	Company Name Country of incorporation Vessel Name Delivery Date to Partnership Year Built Cbm Capacity Pegasus Shipholding S.A. (“Pegasus”) Marshall Islands Clean Energy March 2007 2007 149,700 Lance Shipping S.A. (“Lance”) Marshall Islands Ob River July 2007 2007 149,700 Seacrown Maritime Ltd. (“Seacrown”) Marshall Islands Amur River (1) January 2008 2008 149,700 Fareastern Shipping Limited (“Fareastern”) Malta Arctic Aurora June 2014 2013 155,000 Navajo Marine Limited (“Navajo”) Marshall Islands Yenisei River September 2014 2013 155,000 Solana Holding Ltd. (“Solana”) Marshall Islands Lena River December 2015 2013 155,000 Renamed from Clean Force in June 2015.
Non-Vessel Owning Subsidiaries	Company Name Country of incorporation Purpose of incorporation Quinta Group Corp. (“Quinta”) Nevis Holding company that owns all of the outstanding capital stock of Pegasus. Pelta Holdings S.A. (“Pelta”) Nevis Holding company that owns all of the outstanding capital stock of Lance. Dynagas Equity Holdings Ltd.(“Dynagas Equity”) Liberia Holding company that owns all of the outstanding capital stock of Quinta, Pelta, Seacrown, Fareastern, Navajo, Solana and Arctic LNG. Dynagas Operating GP LLC. (“Dynagas Operating GP”) Marshall Islands Limited Liability Company, in which the Partnership holds 100% membership interests and that has 100% of the Non-Economic General Partner Interest in Dynagas Operating LP. Dynagas Operating LP. ("Dynagas Operating") Marshall Islands Limited partnership in which the Partnership holds 100% percentage interests. Dynagas Finance Inc. (“Dynagas Finance”) Marshall Islands Wholly owned subsidiary of the Partnership whose activities are limited to co-issuing the Notes discussed under Note 5 and engaging in other activities incidental thereto. Arctic LNG Carriers Ltd. (“Arctic LNG”) Marshall Islands Wholly owned subsidiary of Dynagas Equity that currently has no operations in place nor is it engaged in any other activities.

Significant Accounting Polici22

Significant Accounting Policies and Recent Accounting Pronouncements (Tables)	12 Months Ended
	Dec. 31, 2015
Significant Accounting Policies and Recent Accounting Pronouncements
Major Charterers	Charterer 2015 2014 A 52 % 36 % B 29 % 50 % C 19 % 14 % 100 % 100 %

Transactions with related par23

Transactions with related parties (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transaction, Due from (to) Related Party
Related parties transactions	Year ended December 31, 2015 2014 2013 Included in voyage expenses Charter hire commissions (a) $ 1,821 $ 1,363 $ 1,011 Included in general and administrative expenses Executive services fee (d) $ 599 $ 803 $ — Administrative services fee (e) $ 120 $ 134 $ — Management fees-related party Management fees (a) $ 4,870 $ 3,566 $ 2,737
Related parties balances	Year ended December 31, 2015 2014 Assets: Working capital advances granted to the Manager (a) $ 460 $ 889 Security deposits to Manager (a) $ 1,350 $ 1,125 Liabilities included in Due to related party: Executive service charges due to Manager (d) $ — $ 135 Administrative service charges due to Manager (e) $ 30 $ — Other Partnership expenses due to Manager $ 200 $ 7 Total liabilities due to related party, current $ 230 $ 142 Credit financing balance due to Sponsor (c) $ 35,000 $ — Total liabilities due to related party, non-current $ 35,000 $ —

Vessels, net (Tables)

Vessels, net (Tables)	12 Months Ended
	Dec. 31, 2015
Property Plant and Equipment Net
Vessels Table	Vessel Accumulated Net Book Balance December 31, 2013 $ 540,454 $ (87,279) $ 453,175 —Vessel acquisitions (Note (3(c)) 404,530 — 404,530 —Depreciation — (17,822 ) (17,822 ) Balance December 31, 2014 $ 944,984 $ (105,101) $ 839,883 —Vessel acquisitions and other additions to vessels' cost (Note (3(c)) 220,661 — 220,661 —Depreciation — (24,387 ) (24,387 ) Balance December 31, 2015 $ 1,165,645 $ (129,488) $ 1,036,157

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure
Loans And Credit Facilities Amounts Outstanding	December 31, Debt instruments Borrowers-Issuers 2015 2014 $340.0 million Credit Facility Pegasus-Lance-Seacrown-Fareastern 305,000 325,000 $250.0 million Senior Unsecured Notes Dynagas LNG Partners LP - Dynagas Finance Inc. 250,000 250,000 $200 Million Term Loan Facility Navajo- Solana 133,333 — Total debt $ 688,333 $ 575,000 Less deferred financing fees (8,048 ) (7,493 ) Total debt, net of deferred finance costs $ 680,285 $ 567,507 Less current portion, net of deferred financing fees $ (27,467 ) $ (19,584 ) Long-term portion $ 652,818 $ 547,923
Minimum Annual Principal Payments	Year ending December 31, Amount 2016 $ 28,333 2017 28,333 2018 28,333 2019 278,334 2020 120,000 2021 and thereafter 205,000 Total long term debt $ 688,333

Time charters acquired (Tables)

Time charters acquired (Tables)	12 Months Ended
	Dec. 31, 2015
Amortization of above-market acquired time charter contract to revenues
Time charters acquired:	Year ending December 31, Amount 2016 $ 7,267 2017 7,247 2018 5,268 Total $ 19,782

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure
Minimum Future Charter Revenues	Year ending December 31, Amount 2016 $ 178,590 2017 147,211 2018 79,791 2019 24,273 2020 24,339 Thereafter 176,425 Total $ 630,629
Management Fees	Period/ Year ending December 31, Amount 2016 $ 6,000 2017 6,162 2018 6,347 2019 6,537 2020 6,752 Total $ 31,798

Partners' Equity (Tables)

Partners' Equity (Tables)	12 Months Ended
	Dec. 31, 2015
Partners' Equity
Percentage allocations of additional available cash from operating surplus amongst the unit holders	Total Quarterly Unitholders General Holders Minimum Quarterly Distribution $0.365 99.9 % 0.1 % 0.0 % First Target Distribution up to $0.420 99.9 % 0.1 % 0.0 % Second Target Distribution above $0.420 up to $0.456 85.0 % 0.1 % 14.9 % Third Target Distribution Above $0.456 up to $0.548 75.0 % 0.1 % 24.9 % Thereafter above $0.548 50.0 % 0.1 % 49.9 %

Earnings per Unit (Tables)

Earnings per Unit (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Unit
Basic and Diluted Earnings per Unit	Year ended December 31, 2015 2014 2013 Partnership's Net income $ 60,050 $ 50,561 $ 45,620 Less: Net Income attributable to preferred unitholders 3,019 — — Net Income attributable to subordinated unitholders 24,028 22,170 22,787 General Partner's interest in Net Income 125 68 46 Net income attributable to common unitholders $ 32,878 $ 28,323 $ 22,787 Weighted average number of common units outstanding, basic and diluted 20,505,000 17,964,288 7,729,521 Earnings per common unit, basic and diluted $ 1.60 $ 1.58 $ 2.95

Interest and Finance Costs (Tab

Interest and Finance Costs (Tables)	12 Months Ended
	Dec. 31, 2015
Interest and Finance Costs
Interest and Finance Costs	Year ended December 31, 2015 2014 2013 Interest expense (Note 5) $ 25,926 $ 13,338 $ 8,248 Amortization of deferred financing fees 1,545 785 1,050 Commitment fees (Note 5) 15 360 327 Other 488 41 107 Total $ 27,974 $ 14,524 $ 9,732

Basis of Presentation and Gen31

Basis of Presentation and General Information - Vessel Owning Subsidiaries (Table) (Details)	12 Months Ended
	Dec. 31, 2015
Clean Energy
Property, Plant and Equipment [Line Items]
Delivery Date to Partnership	March 2,007
Year Built	2,007
Cbm Capacity	149,700
Ob River
Property, Plant and Equipment [Line Items]
Delivery Date to Partnership	July 2,007
Year Built	2,007
Cbm Capacity	149,700
Amur River (renamed from Clean Force)
Property, Plant and Equipment [Line Items]
Delivery Date to Partnership	January 2,008
Year Built	2,008
Cbm Capacity	149,700
Arctic Aurora
Property, Plant and Equipment [Line Items]
Delivery Date to Partnership	June 2,014
Year Built	2,013
Cbm Capacity	155,000
Yenisei River
Property, Plant and Equipment [Line Items]
Delivery Date to Partnership	September 2,014
Year Built	2,013
Cbm Capacity	155,000
Lena River
Property, Plant and Equipment [Line Items]
Delivery Date to Partnership	December 2,015
Year Built	2,013
Cbm Capacity	155,000

Basis of Presentation and Gen32

Basis of Presentation and General Information - Non-Vessel Owning Subsidiaries (Table) (Details)	12 Months Ended
	Dec. 31, 2015
Dynagas Operating GP LLC.
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Ownership interest in subsidiary	100.00%
Dynagas Operating LP.
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Ownership interest in subsidiary	100.00%

Basis of Presentation and Gen33

Basis of Presentation and General Information (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 18, 2014	Dec. 31, 2015	Nov. 18, 2013
General Partner
Related Party Transaction [Line Items]
General Partner Interest in Dynagas LNG Partners LP	0.10%	0.10%
Dynagas Holding Ltd
Related Party Transaction [Line Items]
Ownership percentage in Dynagas LNG Partners LP		44.00%
Revolving credit facility for general purposes			$ 30,000

Significant Accounting Polici34

Significant Accounting Policies and Recent Accounting Pronouncements - Major Charterers (Table) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Entity Wide Revenue Major Customer
Concentration risk benchmark description	During the years ended December 31, 2015 and 2014, charterers that individually accounted for more than 10% of the Partnership's revenues were as follows
Percentage of time charter revenue	100.00%	100.00%
Charterer A
Entity Wide Revenue Major Customer
Percentage of time charter revenue	52.00%	36.00%
Charterer B
Entity Wide Revenue Major Customer
Percentage of time charter revenue	29.00%	50.00%
Charterer C
Entity Wide Revenue Major Customer
Percentage of time charter revenue	19.00%	14.00%
Sales Revenue, Net
Entity Wide Revenue Major Customer
Percentage of time charter revenue	10.00%

Significant Accounting Polici35

Significant Accounting Policies and Recent Accounting Pronouncements (Details) - USD ($)	9 Months Ended	12 Months Ended		15 Months Ended
	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015
Provision for doubtful accounts		$ 0	$ 0	$ 0
Vessels dry-dock or special survey period within the first 15 years of useful life		5 years
Vessels dry-dock or special survey period within the remaining useful life		2 years 6 months
Scrap value per light weight ton	$ 717			$ 685
Percentage for estimation of vessel residual value	12.00%
Vessels useful life		35 years
New Accounting Pronouncement, Early Adoption, Effect
New accounting pronouncement or change in accounting principle, reduction effect of change on current portion long-term debt, net			416,000
New accounting pronouncement or change in accounting principle, reduction effect of change on non-current portion of long-term debt, net			$ 7,077,000

Transactions with related par36

Transactions with related parties - Statements of Income (Table) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Included in voyage expenses
Charter hire commissions (a)	$ 1,821	$ 1,363	$ 1,011
Included in general and administrative expenses
Executive services fee (d)	599	803	0
Administrative services fee (e)	120	134	0
Management fees-related party
Management fees (a)	$ 4,870	$ 3,566	$ 2,737

Transactions with related par37

Transactions with related parties - Balance Sheet (Table) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets:
Due from related party	$ 460	$ 889
Due from related party	1,350	1,125
Liabilities:
Due to related party, current	230	142
Due to related party, non-current	35,000	0
Working capital advances granted to the Manager (a)
Assets:
Due from related party	460	889
Security deposits to Manager (a)
Assets:
Due from related party	1,350	1,125
Executive service charges due to Manager (d)
Liabilities:
Due to related party, current	0	135
Administrative service charges due to Manager (e)
Liabilities:
Due to related party, current	30	0
Other Partnership expenses due to Manager
Liabilities:
Due to related party, current	200	7
Credit financing balance due to Sponsor (c)
Liabilities:
Due to related party, non-current	35,000	0
Dynagas Ltd.
Liabilities:
Due to related party, current	230	142
Dynagas Holding Ltd
Liabilities:
Due to related party, non-current	$ 35,000	$ 0

Transactions with related par38

Transactions with related parties - Dynagas Ltd. (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction
Management services agreement duration (effected January 1, 2013)	8 years
Management services agreement initial termination date	December 31, 2020
Daily management fee	$ 2,700	$ 2,600	$ 2,500
Management fees annual upward percentage adjustment	3.00%
Charter Hire Commission payable to the Management company	1.25%
Lump sum payable to the management company for the supervision of vessels construction	$ 700,000
Cancellation of management agreement termination fee	29,100,000
Management fee paid in advance	$ 1,350,000	$ 1,125,000
Management agreement terms	The agreements will terminate automatically after a change of control of the owners and/or of the owners' ultimate parent, in which case an amount equal to the estimated remaining fees but in any case not less than for a period of at the least 36 months and not more than 60 months, will become payable to the Manager.
Minimum
Related Party Transaction
Period For Calculation Of Management Agreement Termination Fee	36 months
Maximum
Related Party Transaction
Period For Calculation Of Management Agreement Termination Fee	60 months

Transactions with related par39

Transactions with related parties - Loan from related party (Details) - Dynagas Holding Ltd - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Nov. 18, 2013
Debt Instruments
Revolving credit facility borrowing capacity			$ 30,000
Line of credit facility, duration	5 years
Revolving credit facility amount drawn down	$ 0	$ 0

Transactions with related par40

Transactions with related parties - Omnibus Agreement - Vessel acquisitions from our Sponsor (Details) $ in Thousands	Dec. 21, 2015USD ($)	Sep. 25, 2014	Jun. 23, 2014	Apr. 12, 2016	Jul. 20, 2015shares	Dec. 31, 2015USD ($)shares	Dec. 21, 2015USD ($)shares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Related Party Transaction [Line Items]
Number Of Vessels Dropped Down						1		2
Preferential deemed dividend						$ 0		$ 88,122	$ 0
Principal amount due						35,000		0
Proceeds from Issuance of Long-term Debt						133,333		590,000	$ 214,085
Subsequent Event | Amended Omnibus Agreement | Legal right to acquire Sponsor's interests
Related Party Transaction [Line Items]
Percentage of ownership in entity				49.00%
LNG Carrier Capacity				172,000
Number Of Vessels				5
Vessel Type				ARC7 LNG carrier
$200 Million Term Loan Facility
Related Party Transaction [Line Items]
Proceeds from Issuance of Long-term Debt							$ 133,333
Debt instrument, remaining borrowing capacity						$ 66,700
Series A Preferred Units
Related Party Transaction [Line Items]
Issuance of preferred units | shares					3,000,000	3,000,000
Preferred stock dividend rate percentage						9.00%
Dynagas Holding Ltd
Related Party Transaction [Line Items]
Principal amount due						$ 35,000		0
Credit facility amount drawn down						$ 0		0
Dynagas Holding Ltd | Legal right to acquire Sponsor's interests
Related Party Transaction [Line Items]
Number Of Vessels						4
Arctic Aurora and Yenisei River
Related Party Transaction [Line Items]
Consideration for vessel and related time charter								492,500
Arctic Aurora and Yenisei River | Dynagas Holding Ltd
Related Party Transaction [Line Items]
Preferential deemed dividend								$ 88,122
Arctic Aurora
Related Party Transaction [Line Items]
Percentage of ownership in entity			100.00%
LNG Carrier Year Built						2,013
LNG Carrier Capacity						155,000
Yenisei River
Related Party Transaction [Line Items]
Percentage of ownership in entity		100.00%
LNG Carrier Year Built						2,013
LNG Carrier Capacity						155,000
Lena River
Related Party Transaction [Line Items]
Percentage of ownership in entity	100.00%
LNG Carrier Year Built						2,013
LNG Carrier Capacity						155,000
Consideration for vessel and related time charter							240,000
Lena River | $200 Million Term Loan Facility
Related Party Transaction [Line Items]
Proceeds from Issuance of Long-term Debt							$ 126,300
Lena River | Series A Preferred Units
Related Party Transaction [Line Items]
Issuance of preferred units | shares							3,000,000
Preferred stock dividend rate percentage							9.00%
Lena River | Dynagas Holding Ltd
Related Party Transaction [Line Items]
Principal amount due	$ 35,000						$ 35,000
Payment obligation settlement period							180 days

Transactions with related par41

Transactions with related parties - Executive - Administrative Services Agreement (Details) € in Thousands, $ in Thousands	Dec. 30, 2014USD ($)	Mar. 21, 2014EUR (€)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Related Party Transaction [Line Items]
Eur/US Dollar exchange rate			1.0906
Administrative services fee			$ 120	$ 134	$ 0
Executive services agreement
Related Party Transaction [Line Items]
Annual executive services fee		€ 538	$ 587
Executive services agreement duration		Initial term of five years and automatically renews for successive five year terms unless terminated earlier.
Executive Services Agreement - Initial Term
Related Party Transaction [Line Items]
Executive services agreement duration				5 years
Executive Services Agreement - Automatic Renewal
Related Party Transaction [Line Items]
Executive services agreement duration				5 years
Administrative Services Agreement
Related Party Transaction [Line Items]
Administrative services fee	$ 10
Administrative services duration			perpetual
Administrative services days notice			120 days

Vessels, net (Table) (Details)

Vessels, net (Table) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property Plant And Equipment
Balance beginning of period	$ 839,883
Vessel acquisitions (Note 3(c))	205,045	$ 404,530	$ 0
Depreciation	(24,387)	(17,822)	(13,579)
Balance end of period	1,036,157	839,883
Vessel Cost
Property Plant And Equipment
Balance beginning of period	944,984	540,454
Vessel acquisitions (Note 3(c))		404,530
Vessel acquisitions and other additions to vessels' cost (Note 3(c))	220,661
Depreciation	0	0
Balance end of period	1,165,645	944,984	540,454
Accumulated Depreciation
Property Plant And Equipment
Balance beginning of period	(105,101)	(87,279)
Vessel acquisitions (Note 3(c))		0
Vessel acquisitions and other additions to vessels' cost (Note 3(c))	0
Depreciation	(24,387)	(17,822)
Balance end of period	(129,488)	(105,101)	(87,279)
Net Book Value
Property Plant And Equipment
Balance beginning of period	839,883	453,175
Vessel acquisitions (Note 3(c))		404,530
Vessel acquisitions and other additions to vessels' cost (Note 3(c))	220,661
Depreciation	(24,387)	(17,822)
Balance end of period	$ 1,036,157	$ 839,883	$ 453,175

Vessels, Net (Details)

Vessels, Net (Details)	9 Months Ended	12 Months Ended			15 Months Ended
	Sep. 30, 2014USD ($)	Dec. 31, 2015USD ($)	Dec. 21, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2015USD ($)
Debt Instruments
Scrap value per light weight ton	$ 717				$ 685
Property Plant And Equipment Salvage Value Percentage	12.00%
Change in accounting estimate effect on depreciation		$ 152,000
Lena River
Debt Instruments
Consideration for vessel and related time charter			$ 240,000,000
Year Built		2,013
Cubic Meters		155,000
Value of vessel acquired		$ 220,000,000			$ 220,000,000
Arctic Aurora and Yenisei River
Debt Instruments
Consideration for vessel and related time charter				$ 492,500,000

Long-Term Debt - Credit Facilit

Long-Term Debt - Credit Facilities And Senior Notes (Table) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instruments
Total debt	$ 688,333	$ 575,000
Less deferred financing fees	(8,048)	(7,493)
Total debt, net of deffered finance costs	680,285	567,507
Less current portion, net of deferred financing fees	(27,467)	(19,584)
Long-term portion	652,818	547,923
$250.0 Million Senior Unsecured Notes
Debt Instruments
Senior Unsecured Notes	250,000
$250.0 Million Senior Unsecured Notes | Dynagas LNG Partners LP - Dynagas Finance Inc.
Debt Instruments
Senior Unsecured Notes	250,000	250,000
$340 million Senior Secured Revolving Credit Facility | Pegasus-Lance-Seacrown-Fareastern
Debt Instruments
Long-term debt	305,000	$ 325,000
$200 Million Term Loan Facility | Navajo And Solana
Debt Instruments
Long-term debt	$ 133,333

Long-Term Debt - Principal Paym

Long-Term Debt - Principal Payments (Table) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure
2,016	$ 28,333
2,017	28,333
2,018	28,333
2,019	278,334
2,020	120,000
2021 and thereafter	205,000
Total long term debt	$ 688,333	$ 575,000

Long-Term Debt - Credit Facil46

Long-Term Debt - Credit Facilities And Senior Notes (Details) $ in Thousands	Jan. 05, 2016USD ($)	Jun. 23, 2014USD ($)	Jun. 19, 2014USD ($)	Sep. 15, 2014USD ($)	Dec. 31, 2015USD ($)	Dec. 21, 2015USD ($)	Dec. 17, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Debt Instruments
Principal amount due					$ 35,000			$ 0
Proceeds from long-term debt					$ 133,333			$ 590,000	$ 214,085
Weighted average interest rate					4.50%			3.80%	2.40%
Total interest incurred on long-term debt					$ 25,926			$ 13,338	$ 8,248
Line of credit facility, commitment fee amount					15			360	$ 327
Dynagas Holding Ltd
Debt Instruments
Principal amount due					35,000			0
Credit facility amount drawn down					$ 0			$ 0
Dynagas Holding Ltd | Lena River
Debt Instruments
Principal amount due						$ 35,000
$250.0 Million Senior Unsecured Notes due 2019
Debt Instruments
Principal amount				$ 250,000
Debt Instrument, Maturity Date					Oct. 30, 2019
Net proceeds from issuance of Senior Notes				$ 244,900
Senior notes, terms					The Notes bear interest from the date of the original issue until maturity at a rate of 6.25% per year, payable quarterly in arrears on January 30, April 30, July 30 and October 30 of each year.
Senior notes interest rate					6.25%
$340 million Senior Secured Revolving Credit Facility
Debt Instruments
Principal amount			$ 340,000
Line of credit facility, frequency of payments					quarterly
Line of credit facility, repayment installments			28
Line of credit facility, expiration date					Mar. 31, 2021
Debt instrument, periodic payment terms, balloon payment			$ 200,000
Debt Instrument, Periodic Payment			$ 5,000
Amount repaid		$ 214,100
Credit facility amount drawn down		$ 340,000
Debt instrument, description of variable rate basis			LIBOR
$200 Million Term Loan Facility
Debt Instruments
Principal amount							$ 200,000
Line of credit facility, frequency of payments					quarterly
Line of credit facility, repayment installments							20
Proceeds from long-term debt						133,333
Debt instrument, description of variable rate basis							LIBOR
Debt instrument, remaining borrowing capacity					$ 66,700
Maturity Profile					5 years
$200 Million Term Loan Facility | Lena River
Debt Instruments
Proceeds from long-term debt						126,300
$200 Million Term Loan Facility | Navajo And Solana | Subsequent Event
Debt Instruments
Proceeds from long-term debt	$ 66,700
$200 Million Term Loan Facility | Navajo
Debt Instruments
Principal amount							$ 100,000
Debt instrument, periodic payment terms, balloon payment							68,800
Debt Instrument, Periodic Payment							1,560
Proceeds from long-term debt						66,650
$200 Million Term Loan Facility | Solana
Debt Instruments
Principal amount							100,000
Debt instrument, periodic payment terms, balloon payment							68,800
Debt Instrument, Periodic Payment							$ 1,560
Proceeds from long-term debt						$ 66,660

Long-Term Debt - Loans And Cred

Long-Term Debt - Loans And Credit Facilities Terms and Compliance (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 18, 2014	Dec. 31, 2015	Dec. 31, 2014
Debt Instruments
Covenant compliance		As of December 31, 2015, the Partnership was in compliance with all financial covenants prescribed in its debt agreements.
Minimum liquidity required for compliance		$ 25,000	$ 24,000
General Partner
Debt Instruments
General Partner's outstanding voting interests in Dynagas Partners	0.10%	0.10%
Dynagas Holding Ltd
Debt Instruments
Outstanding voting interests in the Partnership, including General Partner interest		44.00%
$250.0 Million Senior Unsecured Notes
Debt Instruments
Minimum liquidity required for compliance		$ 20,000
$340 million Senior Secured Revolving Credit Facility
Debt Instruments
Minimum liquidity required for compliance		$ 24,000
$340 million Senior Secured Revolving Credit Facility | Dynagas Holding Ltd | Minimum
Debt Instruments
Outstanding voting interests in the Partnership, including General Partner interest		30.00%
General Partner's outstanding voting interests in Dynagas Partners		100.00%
$200 Million Term Loan Facility
Debt Instruments
Minimum liquidity required for compliance		$ 25,000
$200 Million Term Loan Facility | Lena River
Debt Instruments
Cash reserve build up installments number		33
$200 Million Term Loan Facility | Yenisei River
Debt Instruments
Cash reserve build up installments number		31
$200 Million Term Loan Facility | Cash | Lena River and Yenisei River
Debt Instruments
Debt service reserve account balance		$ 7,500
$200 Million Term Loan Facility | Dynagas Holding Ltd | General Partner | Minimum
Debt Instruments
Outstanding voting interests in the Partnership, including General Partner interest		30.00%
$200 Million Term Loan Facility | Navajo And Solana | Minimum
Debt Instruments
Minimum liquidity required for compliance		$ 2,500

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instruments
Due from related parties non current carrying value	$ 1,350	$ 1,125
Due from related parties non current fair value - determined through level 3 inputs	891
$250.0 Million Senior Unsecured Notes
Debt Instruments
Senior notes carrying value	250,000
Senior notes fair value - determined through level 2 inputs	$ 172,500

Time Charters Acquired (Table)

Time Charters Acquired (Table) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Amortization of above-market acquired time charter contract to revenues
2,016	$ 7,267
2,017	7,247
2,018	5,268
Total	$ 19,782	$ 0

Time Charters Acquired (Details

Time Charters Acquired (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Fair value of the favorable time charter acquired	$ 20,000
Amortization of Intangible Assets	218	$ 0	$ 0
Finite Lived Intangible Assets Net	$ 19,782	$ 0
Lena River
Finite-Lived Intangible Assets [Line Items]
Time charter contract, remaining term	2 years 9 months 18 days
Amortization of Intangible Assets	$ 218

Commitments and Contingencies -

Commitments and Contingencies - Charter Hire (Table) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Minimum Future Charter Revenues for the year ending
2,016	$ 178,590
2,017	147,211
2,018	79,791
2,019	24,273
2,020	24,339
Thereafter	176,425
Total	$ 630,629

Commitments and Contingencies52

Commitments and Contingencies - Management Fees (Table) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Management Fees for the year ending
2,016	$ 6,000
2,017	6,162
2,018	6,347
2,019	6,537
2,020	6,752
Total	$ 31,798

Commitments and Contingencies53

Commitments and Contingencies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Charter Hire Commission payable to the Management company	1.25%
Commission payable over the minimum contractual charter revenues	$ 7,883,000
Daily management fee	$ 2,700	$ 2,600	$ 2,500
Inflation rate adjustement to management fees	3.00%
Future minimum contractual charter revenues	$ 630,629,000
Amur River (renamed from Clean Force)
Property, Plant and Equipment [Line Items]
Future minimum contractual charter revenues	$ 298,800,000
Time charter contract, remaining term	13 years

Partner's Equity (Table) (Detai

Partner's Equity (Table) (Details)	12 Months Ended
	Dec. 31, 2015$ / shares
Total Quarterly Distribution Target Amount | Minimum Quarterly Distribution | Minimum
Distribution Per Unit	$ 0.365
Total Quarterly Distribution Target Amount | First Target Distribution | Maximum
Distribution Per Unit	0.42
Total Quarterly Distribution Target Amount | Second Target Distribution | Minimum
Distribution Per Unit	0.42
Total Quarterly Distribution Target Amount | Second Target Distribution | Maximum
Distribution Per Unit	0.456
Total Quarterly Distribution Target Amount | Third Target Distribution | Minimum
Distribution Per Unit	0.456
Total Quarterly Distribution Target Amount | Third Target Distribution | Maximum
Distribution Per Unit	0.548
Total Quarterly Distribution Target Amount | Thereafter | Minimum
Distribution Per Unit	$ 0.548
Limited Unitholders | Minimum Quarterly Distribution
Percentage allocations of the additional available cash	99.90%
Limited Unitholders | First Target Distribution
Percentage allocations of the additional available cash	99.90%
Limited Unitholders | Second Target Distribution
Percentage allocations of the additional available cash	85.00%
Limited Unitholders | Third Target Distribution
Percentage allocations of the additional available cash	75.00%
Limited Unitholders | Thereafter
Percentage allocations of the additional available cash	50.00%
General Partner | Minimum Quarterly Distribution
Percentage allocations of the additional available cash	0.10%
General Partner | First Target Distribution
Percentage allocations of the additional available cash	0.10%
General Partner | Second Target Distribution
Percentage allocations of the additional available cash	0.10%
General Partner | Third Target Distribution
Percentage allocations of the additional available cash	0.10%
General Partner | Thereafter
Percentage allocations of the additional available cash	0.10%
Holders of IDRs | Minimum Quarterly Distribution
Percentage allocations of the additional available cash	0.00%
Holders of IDRs | First Target Distribution
Percentage allocations of the additional available cash	0.00%
Holders of IDRs | Second Target Distribution
Percentage allocations of the additional available cash	14.90%
Holders of IDRs | Third Target Distribution
Percentage allocations of the additional available cash	24.90%
Holders of IDRs | Thereafter
Percentage allocations of the additional available cash	49.90%

Partner's Equity (Details)

Partner's Equity (Details) - USD ($) $ / shares in Units, $ in Thousands

Jan. 14, 2015

Apr. 16, 2015

Jun. 18, 2014

Jul. 22, 2015

Jul. 20, 2015

Oct. 21, 2015

Nov. 18, 2013

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Dec. 05, 2013

Oct. 29, 2013

Related Party Transaction

Common unitholders - units issued

20,505,000

20,505,000

Common unitholders - units offered

5,520,000

8,250,000

Subordinated unitholders - units issued

14,985,000

14,985,000

General Partner unitholders - units issued

35,526

35,526

Units issued price per unit

$ 18

Issuance of Series A preferred units, net of issuance costs paid

$ 72,446

$ 0

$ 0

Proceeds from Initial Public Offering

$ 148,500

Proceeds from issuance of common units, net of issuance costs

136,900

Underwriting discounts and commissions

$ 4,700

8,900

Other offering costs

600

$ 2,700

Proceeds from issuance of common units, net of commissions and expenses

120,500

Proceeds from issuance of general partners units

$ 126

Total distributions paid to all classes of unitholders

62,207

43,010

0

Preferential deemed dividend

$ 0

$ 88,122

$ 0

Distribution 4 - FY 2014

Related Party Transaction

Distributions paid, Per unit

$ 0.4225

Total distributions paid to all classes of unitholders

$ 15,000

Distributions per unit declared - record date

Feb. 5, 2015

Distributions per unit declared - distribution date

Feb. 12, 2015

Distribution 1 - FY 2015

Related Party Transaction

Distributions paid, Per unit

$ 0.4225

Total distributions paid to all classes of unitholders

$ 15,000

Distributions per unit declared - record date

May 5, 2015

Distributions per unit declared - distribution date

May 12, 2015

Distribution 2 - FY 2015

Related Party Transaction

Distributions paid, Per unit

$ 0.4225

Total distributions paid to all classes of unitholders

$ 15,000

Distributions per unit declared - record date

Aug. 6, 2015

Distributions per unit declared - distribution date

Aug. 13, 2015

Distribution 3 - FY 2015

Related Party Transaction

Distributions paid, Per unit

$ 0.4225

Total distributions paid to all classes of unitholders

$ 15,000

Distributions per unit declared - record date

Nov. 5, 2015

Distributions per unit declared - distribution date

Nov. 12, 2015

General Partner

Related Party Transaction

Units issued

5,526

General Partner Interest in Dynagas LNG Partners LP

0.10%

0.10%

General Partner Distributions

$ 130

$ 44

Series A Preferred

Related Party Transaction

Units issued

3,000,000

3,000,000

Preferred Stock Dividend Rate Percentage

9.00%

Preferred stock liquidation preference

$ 25

Issuance of preferred units, net of issuance costs incurred

$ 72,300

Underwriting discounts and commissions

2,400

Offering costs

$ 300

Series A Preferred | Distribution 3 - FY 2015

Related Party Transaction

Distributions per unit declared - record date

Nov. 5, 2015

Distributions per unit declared - distribution date

Nov. 12, 2015

Over-allotment

Related Party Transaction

Common unitholders - units offered

720,000

Dynagas Holding Ltd

Related Party Transaction

Common unitholders - units offered

4,250,000

Dynagas Holding Ltd | Arctic Aurora and Yenisei River

Related Party Transaction

Preferential deemed dividend

$ 88,122

Dynagas Holding Ltd | Over-allotment

Related Party Transaction

Common unitholders - units offered

1,875,000

Dynagas GP LLC

Related Party Transaction

General Partner unitholders - units issued

5,526

30,000

Earnings per Unit (Table) (Deta

Earnings per Unit (Table) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share
Partnership's Net Income	$ 60,050	$ 50,561	$ 45,620
Less:
Net Income attributable to preferred unitholders	3,019	0	0
Net Income attributable to subordinated unitholders	24,028	22,170	22,787
General Partner's interest in Net Income	125	68	46
Net income attributable to common unitholders	$ 32,878	$ 28,323	$ 22,787
Weighted average number of common units outstanding, basic and diluted	20,505,000	17,964,288	7,729,521
Earnings per common unit, basic and diluted	$ 1.6	$ 1.58	$ 2.95

Interest and Finance Costs (T57

Interest and Finance Costs (Table) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Finance Costs
Interest expense (Note 5)	$ 25,926	$ 13,338	$ 8,248
Amortization of deferred financing fees	1,545	785	1,050
Commitment fees (Note 5)	15	360	327
Other	488	41	107
Total	$ 27,974	$ 14,524	$ 9,732

Taxes (Details)

Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure
Tonnage taxes for the period	$ 270	$ 245	$ 96
Potential income tax in absence of exemption	42	15	0

Subsequent Events (Details)

Subsequent Events (Details) $ / shares in Units, $ in Thousands

Jan. 14, 2016

Jan. 05, 2016USD ($)

Dec. 21, 2015

Sep. 25, 2014

Jan. 19, 2016USD ($)$ / shares

Apr. 12, 2016

Mar. 23, 2016

Dec. 31, 2015USD ($)

Dec. 21, 2015USD ($)

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Dec. 17, 2015USD ($)

Proceeds from long-term debt

$ 133,333

$ 590,000

$ 214,085

Distribution Made To Limited Partner Cash Distributions Paid

$ 62,207

$ 43,010

$ 0

Lena River

Time charter contract

2 years 9 months 18 days

Percentage of ownership in entity

100.00%

LNG Carrier Capacity

155,000

Yenisei River

Percentage of ownership in entity

100.00%

LNG Carrier Capacity

155,000

Ob River

LNG Carrier Capacity

149,700

Dynagas Holding Ltd | Legal right to acquire Sponsor's interests

Number Of Vessels

4

$200 Million Term Loan Facility

Debt Instrument, Face Amount

$ 200,000

Proceeds from long-term debt

$ 133,333

$200 Million Term Loan Facility | Lena River

Proceeds from long-term debt

$ 126,300

Subsequent Event | Amended Omnibus Agreement | Legal right to acquire Sponsor's interests

Percentage of ownership in entity

49.00%

Number Of Vessels

5

Vessel Type

ARC7 LNG carrier

LNG Carrier Capacity

172,000

Subsequent Event | Installment 4 - FY 2015

Distributions paid, Per unit | $ / shares

$ 0.4225

Distribution Made To Limited Partner Cash Distributions Paid

$ 15,000

Distribution Made To Limited And General Partner Distribution Date

Feb. 12, 2016

Distribution Made To Limited And General Partner Date Record

Feb. 5, 2016

Subsequent Event | Installment 4 - FY 2015 | Series A Preferred

Distributions paid, Per unit | $ / shares

$ 0.5625

Distribution Made To Limited And General Partner Distribution Date

Feb. 12, 2016

Distribution Made To Limited And General Partner Date Record

Feb. 5, 2016

Subsequent Event | Lena River | Yamal

Expected commencement date

between July 1, 2019 and June 30, 2020

Time charter contract

15 years

Charter agreement description of terms

Yamal the right but not the obligation to extend the term of the charter for three consecutive periods of up to five years

Subsequent Event | Yenisei River | Yamal

Expected commencement date

between January 1, and December 31, 2019

Time charter contract

15 years

Charter agreement description of terms

The terms and conditions of the New Yenisei River Charter are identical with the New Lena River Charter

Subsequent Event | Ob River | Gazprom

Time charter contract

10 years

Subsequent Event | $200 Million Term Loan Facility | Navajo And Solana

Proceeds from long-term debt

$ 66,700

Subsequent Event | $200 Million Term Loan Facility | Dynagas Holding Ltd

Repayment of financing

$ 35,000