Mid-Con Energy Partners, LP - FORM 10-Q

Mid-Con Energy Partners, LP - FORM 10-Q - May 5, 2015

Attached files

Attached files

Mid-Con Energy Partners, LP Reports

file	filename
EX-31.2 - EXHIBIT 31.2 - Mid-Con Energy Partners, LP	mcep03312015ex312.htm
EX-32.2 - EXHIBIT 32.2 - Mid-Con Energy Partners, LP	mcep03312015ex322.htm
EX-32.1 - EXHIBIT 32.1 - Mid-Con Energy Partners, LP	mcep03312015ex321.htm
EX-31.1 - EXHIBIT 31.1 - Mid-Con Energy Partners, LP	mcep03312015ex311.htm
EXCEL - IDEA: XBRL DOCUMENT - Mid-Con Energy Partners, LP	Financial_Report.xls

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended March 31, 2015



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

Commission File No.: 1-35374

Mid-Con Energy Partners, LP

(Exact name of registrant as specified in its charter)



Delaware		45-2842469
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

2501 North Harwood Street, Suite 2410

Dallas, Texas 75201

(Address of principal executive offices and zip code)

(972) 479-5980

(Registrant’s telephone number, including area code)

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

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

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

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

As of May 5, 2015, the registrant had 29,655,804 limited partner units and 360,000 general partner units outstanding.

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION



Forward-Looking Statements	3
ITEM 1. FINANCIAL STATEMENTS
Unaudited Condensed Consolidated Balance Sheets	5
Unaudited Condensed Consolidated Statements of Operations	6
Unaudited Condensed Consolidated Statements of Cash Flows	7
Unaudited Condensed Consolidated Statement of Changes in Equity	8
Notes to Unaudited Condensed Consolidated Financial Statements	9

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	25
ITEM 4. CONTROLS AND PROCEDURES	26

PART II
OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	27
ITEM 1A. RISK FACTORS	27
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	27
ITEM 3. DEFAULTS UPON SENIOR SECURITIES	27
ITEM 4. MINE SAFETY DISCLOSURES	27
ITEM 5. OTHER INFORMATION	27
ITEM 6. EXHIBITS	27

Signatures	28

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Form 10-Q”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (each a “forward–looking statement”). These forward–looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:


•	business strategies;


•	ability to replace the reserves we produce through acquisitions and the development of our properties;


•	oil and natural gas reserves;


•	technology;


•	realized oil and natural gas prices;


•	production volumes;


•	lease operating expenses;


•	general and administrative expenses;


•	future operating results;


•	cash flow and liquidity;


•	availability of production equipment;


•	availability of oil field labor;


•	capital expenditures;


•	availability and terms of capital;


•	marketing of oil and natural gas;


•	general economic conditions;


•	competition in the oil and natural gas industry;


•	effectiveness of risk management activities;


•	environmental liabilities;


•	counterparty credit risk;


•	governmental regulation and taxation;


•	developments in oil producing and natural gas producing countries; and


•	plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this Form 10-Q, are forward-looking statements. These forward-looking statements may be found in Item 1. “Financial Statements,” Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Form 10-Q. In some

cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” “goal,” “forecast,” “guidance,” “might,” “scheduled” and the negative of such terms or other comparable terminology.

The forward-looking statements contained in this Form 10-Q are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this Form 10-Q are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the forward-looking events will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in the “Risk Factors” section included in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014 (“Annual Report”). This document is available through our website, www.midconenergypartners.com or through the Securities and Exchange Commission’s

(“SEC”) Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. All forward-looking statements speak only as of the date made, and other than as required by law; we do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.midconenergypartners.com) copies of our Annual Reports, Form 10-Qs, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct and Ethics, Governance Guidelines, Partnership Agreement and the written charter of our Audit Committee are also available on our website, and we will provide copies of these documents upon request. Our website and any contents thereof are not incorporated by reference into this report.

We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T.

PART I

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Mid-Con Energy Partners, LP and subsidiaries

Condensed Consolidated Balance Sheets

(in thousands, except number of units)

(Unaudited)



	March 31, 2015			December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	300		$	3,232
Accounts receivable:
Oil and natural gas sales	6,148			8,051
Other	496			4,070
Derivative financial instruments	22,944			26,202
Prepaids and other	570			652
Total current assets	30,458			42,207
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, successful efforts method:
Proved properties	506,147			501,191
Accumulated depletion, depreciation, amortization and impairment	(101,742		)	(93,896		)
Total property and equipment, net	404,405			407,295
DERIVATIVE FINANCIAL INSTRUMENTS	5,081			842
OTHER ASSETS	4,005			4,284
Total assets	$	443,949		$	454,628
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable:
Trade	$	3,151		$	3,630
Related parties	1,089			3,989
Accrued liabilities	173			397
Total current liabilities	4,413			8,016
DERIVATIVE FINANCIAL INSTRUMENTS	818			—
OTHER LONG-TERM LIABILITIES	107			107
LONG-TERM DEBT	203,000			205,000
ASSET RETIREMENT OBLIGATIONS	7,476			7,363
COMMITMENTS AND CONTINGENCIES
EQUITY, per accompanying statements:
Partnership equity:
General partner interest	1,233			1,328
Limited partners- 29,655,804 and 29,166,112 units issued and outstanding as of March 31, 2015 and December 31, 2014, respectively.	226,902			232,814
Total equity	228,135			234,142
Total liabilities and equity	$	443,949		$	454,628

See accompanying notes to condensed consolidated financial statements

Mid-Con Energy Partners, LP and subsidiaries

Condensed Consolidated Statements of Operations

(in thousands, except per unit data)

(Unaudited)



	Three Months Ended March 31,
	2015			2014
Revenues:
Oil sales	$	17,294		$	21,638
Natural gas sales	277			169
Gain (loss) on derivatives, net	1,644			(2,048		)
Total revenues	19,215			19,759
Operating costs and expenses:
Lease operating expenses	8,915			4,691
Oil and natural gas production taxes	1,109			1,356
Depreciation, depletion and amortization	7,846			3,663
Accretion of discount on asset retirement obligations	92			52
General and administrative	3,641			7,631
Total operating costs and expenses	21,603			17,393
Income (loss) from operations	(2,388		)	2,366
Other income (expense):
Interest income and other	3			2
Interest expense	(1,727		)	(807		)
Total other expense	(1,724		)	(805		)
Net income (loss)	$	(4,112	)	$	1,561
Computation of net income (loss) per limited partner unit:
General partners’ interest in net income (loss)	$	(50	)	$	28
Limited partners’ interest in net income (loss)	$	(4,062	)	$	1,533

Net income (loss) per limited partner unit:
Basic	$	(0.14	)	$	0.08
Diluted	$	(0.14	)	$	0.08

Weighted average limited partner units outstanding:
Limited partner units (basic)	29,487			19,997
Limited partner units (diluted)	29,487			20,026

See accompanying notes to condensed consolidated financial statements

Mid-Con Energy Partners, LP and subsidiaries

Condensed Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)



	Three Months Ended March 31,
	2015			2014
Cash Flows from Operating Activities:
Net income (loss)	$	(4,112	)	$	1,561
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	7,846			3,663
Debt issuance costs amortization	279			43
Accretion of discount on asset retirement obligations	92			52
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(1,644		)	2,048
Cash settlements received (paid) for matured derivatives, net	4,760			(921		)
Cash settlements received from early termination and modification of derivatives, net	11,069			—
Cash premiums paid for derivatives, net	(14,348		)	—
Non-cash equity-based compensation	1,944			5,514
Changes in operating assets and liabilities:
Accounts receivable	1,903			(1,086		)
Other receivables	3,574			104
Prepaids and other	82			(314		)
Accounts payable and accrued liabilities	(3,162		)	1,186
Net cash provided by operating activities	8,283			11,850
Cash Flows from Investing Activities:
Additions to oil and natural gas properties	(5,376		)	(6,393		)
Acquisitions of oil and natural gas properties	—			(7,246		)
Net cash used in investing activities	(5,376		)	(13,639		)
Cash Flows from Financing Activities:
Proceeds from line of credit	11,000			27,000
Payments on line of credit	(13,000		)	(16,000		)
Offering costs	(87		)	—
Distributions paid	(3,752		)	(10,262		)
Net cash (used in) provided by financing activities	(5,839		)	738
Net decrease in cash and cash equivalents	(2,932		)	(1,051		)
Beginning cash and cash equivalents	3,232			1,434
Ending cash and cash equivalents	$	300		$	383

Supplemental Cash Flow Information:
Cash paid for interest	$	1,442		$	866
Non-Cash Investing and Financing Activities:
Accrued capital expenditures - oil and natural gas properties	$	836		$	1,508
Common units issued - acquisition of oil properties	$	—		$	34,001

See accompanying notes to condensed consolidated financial statements

Mid-Con Energy Partners, LP and subsidiaries

Condensed Consolidated Statement of Changes in Equity

(in thousands)

(Unaudited)



				Limited Partner
	General Partner			Units	Amount			Total Equity
Balance, December 31, 2014	$	1,328		29,166	$	232,814		$	234,142
Equity-based compensation	—			490	1,944			1,944
Offering costs	—				(87		)	(87		)
Distributions	(45		)	—	(3,707		)	(3,752		)
Net loss	(50		)	—	(4,062		)	(4,112		)
Balance, March 31, 2015	$	1,233		29,656	$	226,902		$	228,135

See accompanying notes to condensed consolidated financial statements

Mid-Con Energy Partners, LP

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Organization and Nature of Operations

Nature of Operations

Mid-Con Energy Partners, LP (“we,” “our,” “us,” the “Partnership,” the "Company") is a publicly held Delaware limited partnership formed in July 2011 that engages in the ownership, acquisition, exploitation and development of producing oil and natural gas properties in North America, with a focus on enhanced oil recovery. Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company. Our limited partner units ("common units") are traded on the NASDAQ Global Select Market under the symbol “MCEP.”

Basis of Presentation

Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the SEC. These financial statements have not been audited by our independent registered public accounting firm, except that the condensed consolidated balance sheet at December 31, 2014 is derived from the audited financial statements. Accordingly, certain information and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted in this Form 10-Q. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014.

All intercompany transactions and account balances have been eliminated.

Reclassifications

The condensed consolidated financial statements for previous periods include certain reclassifications to the derivative accounts that were made to conform to current presentation. Such reclassifications have no impact on previously reported total assets, net income (loss) or total operating cash flows.

Note 2. Acquisitions

Acquisitions 2014

The following acquisitions were accounted for under the acquisition method of accounting. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition dates, while transaction and integration costs associated with the acquisitions were expensed as incurred. The results of all acquisitions have been included in the consolidated financial statements since the acquisition dates.

Permian acquisition

During November 2014, we acquired multiple oil properties located in Coke, Coleman, Fisher, Haskell, Jones, Kent, Nolan, Runnels, Stonewall, Taylor, and Tom Green Counties, Texas ("Permian") for an aggregate purchase price of approximately $117.6 million, subject to customary post-closing purchase price adjustments. The transaction was primarily funded with borrowings under our revolving credit facility of approximately $21.6 million in cash and the issuance of 5,800,000 common units having an approximate value of $96.0 million, net of offering costs. The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands):



Fair value of net assets:
Oil properties	$	119,438
Total assets acquired	$	119,438
Fair value of net liabilities assumed:
Asset retirement obligation	1,851
Fair value of net assets acquired	$	117,587

Creek County, Oklahoma acquisition

During August 2014, we acquired from our affiliate, Mid-Con Energy III, LLC, a certain oil property located in Creek County, Oklahoma for an aggregate purchase price of approximately $56.5 million. The transaction was primarily funded with borrowings under our revolving credit facility of approximately $4.5 million in cash and the issuance of 2,214,659 common units having an approximate value of $52.0 million.

The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands):



Fair Value of net assets:
Oil property	$	56,979
Total assets acquired	$	56,979
Fair Value of net liabilities assumed:
Asset retirement obligation	479
Net assets acquired	$	56,500

Liberty County, Texas acquisition

During August 2014, we acquired a waterflood unit in Liberty County, Texas for approximately $18.9 million. The acquisition was financed with borrowings under our revolving credit facility.

Southern Oklahoma acquisition

During May 2014, we acquired additional working interest in some of our Southern Oklahoma core area properties for an aggregate purchase price of approximately $7.3 million. The acquisition was financed with borrowings under our revolving credit facility.

Hugoton acquisition

During February 2014, we acquired from our affiliate, Mid-Con Energy III, LLC, certain oil properties located in Cimarron, Love and Texas Counties, Oklahoma and Potter County, Texas ("Hugoton") for an aggregate purchase price of approximately $41.0 million. The transaction was primarily funded with borrowings under our revolving credit facility of approximately $7.0 million and the issuance of 1,500,000 common units having an approximate value of $34.0 million. The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands):



Fair Value of net assets:
Oil properties	$	41,589
Total assets acquired	$	41,589
Fair Value of net liabilities assumed:
Asset retirement obligation	589
Net assets acquired	$	41,000

The following table reflects pro forma revenues, net income and net income per limited partner unit for the three months ended March 31, 2014, as if the acquisitions occurred on January 1, 2014. Since we took over the interests in the Hugoton properties on February 28, 2014, the values for the March 2014 are reflected in the condensed consolidated statement of operations. The unaudited pro forma financial data does not include the results of operations for the Liberty County, Texas,

Southern Oklahoma or Northeastern Oklahoma properties, as the results of operations were deemed not to be material. The table also reflects incremental depreciation, depletion and amortization expense using the unit-of-production method related to the oil and natural gas properties acquired, incremental accretion expense related to asset retirement obligations on the oil and natural gas properties acquired, and interest expense related to the incremental debt incurred to fund the acquisitions. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the period presented or that may be obtained in the future (in thousands, except for per unit numbers):



	Three Months Ended March 31, 2014

Revenues	$	34,381
Net income	$	7,461
Net income per limited partner unit:
Basic	$	0.37
Diluted	$	0.37

Note 3. Equity Awards

We have a long-term incentive program (the “Long-Term Incentive Program”) for employees, officers, consultants and directors of our general partner and its affiliates, including Mid-Con Energy Operating, LLC (“Mid-Con Energy Operating”), who perform services for us. The Long-Term Incentive Program allows for the award of unit options, unit appreciation rights, unrestricted units, restricted units, phantom units, distribution equivalent rights granted with phantom units, and other types of awards, and it is administered by the members of our general partner (the "Founders") and approved by the Board of Directors of the general partner. The Long-Term Incentive Program permits the grant of awards covering an aggregate of 1,764,000 units under the Form S-8 we filed with the SEC on January 25, 2012. If an employee terminates employment prior to the restriction lapse date, the awarded units are forfeited and canceled and are no longer considered issued and outstanding. The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at March 31, 2015:



	Number of Common Units
Approved and authorized awards	1,764,000
Unrestricted units granted	(1,040,824	)
Restricted units granted, net of forfeitures	(460,321	)
Phantom units issued, net of forfeitures	(22,166	)
Awards available for future grant	240,689

We account for restricted units as equity awards since these awards will be settled by issuing common units. These restricted units generally vest over a three-year period and we assume a 10% forfeiture rate. A summary of our restricted units awarded for the three months ended March 31, 2015 is presented below:



Restricted awards:	Number of Restricted Units		Average Grant Date Fair Value per Unit
Outstanding at December 31, 2014	109,800		$23.28
Units granted	294,100		$5.42
Units vested	(118,137	)	$9.57
Units forfeited	(6,408	)	$18.50
Outstanding at March 31, 2015	279,355		$10.39

As of March 31, 2015, there was approximately $2.1 million of unrecognized compensation costs related to non-vested restricted units. The cost is expected to be recognized over a weighted average period of approximately 1.7 years.

During the three months ended March 31, 2015, we granted 202,000 unrestricted and 268,000 restricted common units with one-third vesting immediately and the other two-thirds vesting over two -years, and 26,100 restricted common units with a three-year vesting period.

We recognized $1.9 million and $5.5 million of total equity-based compensation expense for the three months ended March 31, 2015 and 2014, respectively. These costs are reported as a component of general and administrative expense in our unaudited condensed consolidated statement of operations.

Note 4. Derivative Financial Instruments

Our risk management program is intended to reduce our exposure to commodity prices and to assist with stabilizing cash flows. Accordingly, we utilize derivative financial instruments to manage our exposure to commodity price fluctuations and fluctuations in location differences between published index prices and the NYMEX futures prices. Our policies do not permit the use of derivatives for speculative purposes.

At March 31, 2015, our open positions consisted of crude oil price swaps and collars consisting of long puts and short calls with the same strike price. Under commodity swap agreements, we exchange a stream of payments over time according to specified terms with another counterparty. In a typical commodity swap agreement, we agree to pay an adjustable or floating price tied to an agreed upon index for the oil commodity and in return receive a fixed price based on notional quantities. With the collars having the same strike prices, they settle like a swap.

Each call transaction has an established fixed price. When the settlement price is above the fixed price, we pay the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract volume. If the settlement price is below the fixed price, the call option expires.

Each put transaction has an established fixed price. The counterparty charges a premium in order to enter into the put transactions. These premiums are deferred and will be paid monthly as the contracts settle. If the floating price is below the floor price, we receive from the counterparty an amount equal to the difference multiplied by the contract volume net of the deferred premium we owe upon contract settlement. If the floating price exceeds the fixed price, the put option expires and we pay the deferred premium.

We have elected not to designate commodity derivative contracts as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of unsettled derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Net settlement gains or losses on derivative contracts only arise from net payments made or received on monthly settlements or if a commodity derivative contract is terminated prior to its expiration. Pursuant to the accounting standard that permits netting of assets and liabilities where the right of offset exists, we present the fair value of derivative financial instruments on a net basis by counterparty. At March 31, 2015 and December 31, 2014, we recorded the estimated fair value of the derivative contracts as a net asset of $27.2 million and $27.0 million, respectively.

As of March 31, 2015, we had the following oil derivative open positions:



Period Covered	Weighted Average Fixed Price	Weighted Average Floor Price		Weighted Average Ceiling Price		Total Bbls Hedged/day
Swaps - 2015	$91.17					1,521
Swaps - 2016	$90.01					1,110
Collars - 2015		$	50.00	$	50.00	699
Collars - 2016		$	50.00	$	50.00	1,110

During the three months ended March 31, 2015, we restructured a significant portion of our existing oil derivatives that were in place at December 31, 2014. This resulted in the early settlement of certain contracts existing at December 31, 2014, and entering into new oil derivative contracts which extend through September 2016. In connection with the early termination and modifications of our commodity derivative contracts, we received net proceeds of approximately $11.1 million from the early termination of contracts at January 31, 2015, received approximately $5.9 million from selling calls and paid out approximately $19.8 million in premiums to extend the contracts through September 2016. The restructuring also resulted in approximately $4.1 million in deferred put options. During the three months ended March 31, 2015 we paid $0.5 million of the deferred put premiums in connection with contract settlements.

Our oil derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, it is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers. We evaluate the credit standing of such counterparties by reviewing their credit rating. The counterparties to our derivative contracts currently in place are lenders under our revolving credit facility and have investment grade credit ratings.

The following tables summarizes the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in our unaudited condensed consolidated balance sheets at March 31, 2015 and December 31, 2014 (in thousands):



	Gross Amounts Recognized			Gross Amounts Offset in the Unaudited Condensed Consolidated Balance Sheet			Net Amounts Presented in the Unaudited Condensed Consolidated Balance Sheet
March 31, 2015:
Assets
Derivative financial instruments - current asset	$	27,392		$	(4,448	)	$	22,944
Derivative financial instruments - long-term asset	9,253			(4,172		)	5,081
Total	$	36,645		$	(8,620	)	$	28,025

Liabilities
Derivative financial instruments - current liability	$	(2,385	)	$	2,385		$	—
Derivative deferred premium - current liability	(2,063		)	2,063			—
Derivative financial instruments - long-term liability	(3,508		)	2,690			(818		)
Derivative deferred premium - long-term liability	(1,482		)	1,482			—
Total	$	(9,438	)	$	8,620		$	(818	)

Net asset	$	27,207		$	—		$	27,207



	Gross Amounts Recognized		Gross Amounts Offset in the Unaudited Condensed Consolidated Balance Sheet		Net Amounts Presented in the Unaudited Condensed Consolidated Balance Sheet
December 31, 2014:
Assets
Derivative financial instruments - current asset	$	26,202	$	—	$	26,202
Derivative financial instruments - long-term asset	842		—		842
Total	$	27,044	$	—	$	27,044

Liabilities
Derivative financial instruments - current liability	$	—	$	—	$	—
Derivative financial instruments - long-term liability	—		—		—
Total	$	—	$	—	$	—

Net Asset	$	27,044	$	—	$	27,044

The following table presents the impact of derivative financial instruments on the unaudited condensed consolidated statements of operations (in thousands):



	Three Months Ended March 31,
	2015			2014
Net settlements on matured derivatives	$	4,760		$	(921	)
Net settlements on early terminations and modifications of derivatives	11,069			—
Change in fair value of unsettled derivatives, net	(14,185		)	(1,127		)
Total gain (loss) on derivatives, net	$	1,644		$	(2,048	)

Note 5. Fair Value Disclosures

Fair Value of Financial Instruments

The carrying amounts reported in our balance sheet for cash, accounts receivable and accounts payable approximate their fair values. The carrying amount of long-term debt under our revolving credit facility approximates fair value because the revolving credit facility’s variable interest rate resets frequently and approximates current market rates available to us.

We account for our derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined utilizing NYMEX closing prices for the contract period.

Fair Value Measurements

Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP establishes a three-tier fair value hierarchy that is intended to increase consistency and comparability in fair value measurements and related disclosures. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Our assets and liabilities recorded in the balance sheet are categorized based on the inputs to the valuation technique as follows:

Level 1—Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.

Level 2—Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

Level 3—Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

We account for our commodity derivatives and their corresponding deferred premiums at fair value on a recurring basis. We use certain pricing models to determine the fair value of our derivative financial instruments. Inputs to the pricing models include publicly available prices from a compilation of data gathered from third parties and brokers. We validate the data provided by our counterparties and third-party providers by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. See Note 4 for a summary of our derivative financial instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

We estimate the fair value of the asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note 6 for a summary of changes in asset retirement obligations.

We review our long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In this circumstance, we recognize an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. There were no impairment charges for the three months ended March 31, 2015 and 2014.

The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value as of March 31, 2015 and December 31, 2014 (in thousands):



	Level 1		Level 2			Level 3

March 31, 2015
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Derivative financial instruments- asset	$	—	$	36,645		$	—
Derivative financial instruments- liability	—		(5,893		)	—
Derivative deferred premiums - liability	—		—			(3,545		)
Net financial assets	$	—	$	30,752		$	(3,545	)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Asset retirement obligations	$	—	$	—		$	21

December 31, 2014
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Derivative financial instruments- asset	$	—	$	27,044		$	—
Derivative financial instruments- liability	—		—			—
Net financial assets	$	—	$	27,044		$	—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Asset retirement obligations	$	—	$	—		$	3,171
Impairment of proved oil and natural gas properties	$	—	$	—		$	30,206

A summary of the changes in Level 3 fair value measurements for the periods presented are as follows:



	Three Months Ended March 31, 2015			Year Ended December 31, 2014
	(in thousands)
Balance of Level 3 at beginning of period	$	—		$	—
Derivative deferred premiums - purchases	(4,068		)	—
Derivative deferred premiums - settlements	523			—
Balance of Level 3 at end of period	$	(3,545	)	$	—

Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no changes in valuation techniques or related inputs for the three months ended March 31, 2015 and 2014.

Note 6. Asset Retirement Obligations

Our asset retirement obligations ("ARO") represent the estimated present value of the amount we will incur to plug, abandon and remediate our oil and natural gas properties at the end of their production lives, in accordance with applicable

state laws. We determine our ARO by calculating the present value of estimated cash flow related to the liability. Each year we review and to the extent necessary, revise our ARO estimates.

AROs are recorded as a liability at their estimated present value at the various assets’ inception, with the offsetting charge to oil and natural gas properties. Periodic accretion of the discounted estimated liability is recorded in our unaudited condensed consolidated statement of operations. The discounted capitalized cost is amortized to expense through the depreciation calculation over the life of the assets based on proved developed reserves.

Changes in our ARO for the periods indicated are presented in the following table:



	Three Months Ended March 31, 2015		Year Ended December 31, 2014
	(in thousands)
Asset retirement obligation - beginning of period	$	7,363	$	3,942
Liabilities incurred for new wells and interest	21		3,171
Accretion expense	92		250
Asset retirement obligation - end of period	$	7,476	$	7,363

As of March 31, 2015 and December 31, 2014, all of our ARO were classified as long-term and were reported as “Asset Retirement Obligations” in our unaudited condensed consolidated balance sheets.

Note 7. Debt

As of March 31, 2015, our credit facility consists of a $250.0 million senior secured revolving credit facility that expires in November 2018. Borrowings under the revolving credit facility may not exceed our current borrowing base of $220.0 million as determined at April 2, 2015.

Borrowings under the facility are secured by liens on not less than 80% of our assets and the assets of our subsidiaries. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general partnership purposes and for funding distributions to our unitholders. At March 31, 2015, we had $203.0 million of borrowings outstanding under the revolving credit facility. The facility requires us and our subsidiaries to maintain a leverage ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX (as defined in the facility) of not more than 4.0 to 1.0, and a current ratio of not less than 1.0 to 1.0.

Borrowings under the revolving credit facility bear interest at a floating rate based on, at our election: (i) the greater of the prime rate of the Royal Bank of Canada, the federal funds effective rate plus 0.50%, or the one month adjusted London Interbank Offered Rate (“LIBOR”) plus 1.0%, all of which are subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. For the three months ended March 31, 2015, the average effective interest rate was approximately 2.69%. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.

During February 2015, the revolving credit facility was amended to allow our EBITDAX calculation, as defined in section 7.13 of the original revolving credit agreement, to reflect the net cash flows attributable to the restructured commodity derivative contracts that occurred during January 2015 to be recognized in specific amounts for the periods of the first quarter 2015 through the third quarter of 2016.

With the April 2, 2015 redetermination, our borrowing base was reduced to $220.0 million from $240.0 million. No other material terms of the original credit agreement were amended. The next scheduled borrowing base redetermination is expected to take place in October 2015. The borrowing base is determined by the lenders based on the value of our proved oil and natural gas reserves using assumptions regarding future prices, costs and other matters that may vary. The borrowing base is subject to scheduled redeterminations on or about April 30 and October 31 of each year with an additional redetermination during the period between each scheduled borrowing base determination, either at our request or at the request of the lenders. An additional borrowing base redetermination may be made at the request of the lenders in connection with a material disposition of our properties or a material liquidation of a hedge contract.

The revolving credit facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and payments. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under

the credit agreement, together with accrued interest could be declared immediately due and payable. We were in compliance with all debt covenants throughout the period ended March 31, 2015.

Note 8. Commitments and Contingencies

We have a service agreement with Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating will provide certain services to us, our subsidiaries and our general partner, including management, administrative and operations services, which include marketing, geological and engineering services. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for or on our behalf and other expenses allocated by Mid-Con Energy Operating to us.

We are party to various claims, legal actions and complaints arising in the ordinary course of business. In the opinion of management, the ultimate resolution of all claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our financial position, results of operations or cash flows.

Our general partner has entered into employment agreements with the following named employees of our general partner: Jeffrey R. Olmstead, Chief Executive Officer; and Charles R. Olmstead, Executive Chairman of the Board of our general partner. The previous employment agreement with S. Craig George was terminated in August 2014. The employment agreements provide for a term that commenced on August 1, 2011 and automatically renewed on August 1, 2014 for an additional year, unless earlier terminated, and will continue to automatically renew for one-year terms unless either we or the employee gives written notice of termination at least by February 1st preceding any such August 1st. Pursuant to the employment agreements, each employee will serve in his respective position with our general partner, as set forth above, and has duties, responsibilities, and authority as the board of directors of our general partner may specify from time to time, in roles consistent with such positions that are assigned to him. The agreement stipulates that if there is a change of control, termination of employment with cause or without cause, or death of the executive certain payments will be made to the executive officer. These payments, depending on the reason for termination, currently range from $0.8 million to $1.4 million, including the value of vesting of any outstanding units.

Note 9. Equity

Common Units

At March 31, 2015 and December 31, 2014, the Partnership’s equity consisted of 29,655,804 and 29,166,112 common units, respectively, representing approximately a 98.8% limited partnership interest in us.

Cash Distributions

We intend to continue to make regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our revolving credit facility prohibits us from making cash distributions if any potential default or event of default, as defined in our revolving credit facility, occurs or would result from the cash distribution.

Our partnership agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.

The following sets forth the distributions we paid during the three months ended March 31, 2015 (in thousands, except per unit distribution):



Date Paid	Period Covered	Distribution per Unit	Total Distribution
February 13, 2015	October 1, 2014 - December 31, 2014	$0.125	$3,752

On April 20, 2015, the Board of Directors of our general partner approved a quarterly cash distribution for the first quarter of 2015 of $0.125 per unit, or $0.50 per unit on an annualized basis, which will be paid on May 14, 2015 to unitholders of record at the close of business on May 7, 2015. The aggregate amount of the distribution will be approximately $3.7 million.

Allocation of Net Income

Net income is allocated between our general partner and the limited partner unitholders in proportion to their pro rata ownership during the period.

Note 10. Related Party Transactions

The following agreements were negotiated among affiliated parties and, consequently, are not the result of arm’s length negotiations. The following is a description of those agreements that have been entered into with the affiliates of our general partner and with our general partner.

Services Agreement

We are party to a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating provides certain services to us, including management, administrative and operational services. The operational services include marketing, geological and engineering services. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. During the three months ended March 31, 2015 and 2014, we reimbursed Mid-Con Energy Operating approximately $0.9 million and $1.0 million, for direct expenses, respectively. These costs are included in the general and administrative expenses in our unaudited condensed consolidated statements of operations.

Other Transactions with Related Persons

We, various third parties with an ownership interest in the same property and our affiliate, Mid-Con Energy Operating, are party to standard oil and natural gas joint operating agreements, pursuant to which we and those third parties pay Mid-Con Energy Operating overhead charges associated with operating our properties (commonly referred to as the Council of Petroleum Accountants Societies, or COPAS, fee). We and those third parties will also pay Mid-Con Energy Operating for its direct and indirect expenses that are chargeable to the wells under their respective operating agreements.

During February and August, 2014, we acquired from Mid-Con Energy III, LLC, an affiliated company, certain oil properties located in Oklahoma and Texas. The terms of the acquisitions were approved by the Conflicts Committee of the Board of Directors of the General Partner (the “Conflicts Committee”). The Conflicts Committee, which is composed entirely of independent directors, retained independent legal and financial counsel to assist it in evaluating and negotiating the purchase agreements and the acquisitions. The purchase agreements contained representations and warranties, covenants and indemnification provisions that are typical for transactions of this nature and that were made or agreed to, among other things, to provide the parties thereto with specified rights and obligations and to allocate risk among them. See Note 2 to the Unaudited Condensed Consolidated Financial Statements for more information regarding these acquisitions.

At March 31, 2015, we had payables to Mid-Con Energy Operating of approximately $1.1 million which was comprised of a joint interest billing payable of approximately $0.8 million and a payable for operating services of approximately $0.3 million. These amounts are included in the Accounts payable-related parties in our unaudited condensed consolidated balance sheets.

Note 11. New Accounting Standards

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers, which provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. The standard is effective for public entities for annual and interim periods beginning after December 15, 2016. Early adoption is not permitted. We are currently evaluating the impact the pronouncement will have on our consolidated financial statements and related disclosures. On April 1, 2015, the Financial Accounting Standard Board tentatively decided to defer the effective date of Accounting Standard Update No. 2014-09 by one year. As a result, public entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017, and to interim periods within that reporting period, with early adoption permitted.

four to two, the guidance simplifies and improves current guidance by placing more emphasis on risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a VIE. The standard is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are currently evaluating the effect, if any, that this new guidance will have on our consolidated financial statements and related disclosures.

In April 2015, the Financial Accounting Board issued Accounting Standards Update No. 2015-03, Interest: Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal years beginning after December 15, 2015, with early adoption permitted. We are currently evaluating the impact the pronouncement will have on our consolidated financial statements and related disclosures.

Note 12. Subsequent Events

Distributions

On April 20, 2015, the Board of Directors of our general partner approved a quarterly cash distribution for the first quarter of 2015 of $0.125 per unit, or $0.50 on an annualized basis, which will be paid on May 14, 2015 to unitholders of record at the close of business on May 7, 2015. The aggregate amount of the distribution will be approximately $3.7 million.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes thereto, as well as our Annual Report.

Overview

Mid-Con Energy Partners, LP (“we,” “our,” “us,” the “Partnership”) is a publicly held Delaware limited partnership

formed in July 2011 that engages in the ownership, acquisition, exploitation and development of producing oil and natural gas properties in North America, with a focus on enhanced oil recovery ("EOR"). Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company. Our limited partner units ("common units") are traded on the NASDAQ Global Select Market under the symbol “MCEP”.

Our properties are located primarily in the Mid-Continent and Permian Basin regions of the United States in five core areas: Southern Oklahoma, Northeastern Oklahoma, parts of Oklahoma, Colorado and Texas within the Hugoton, upper Texas Gulf Coast and West Texas within the Eastern Shelf of the Permian. Our properties primarily consist of mature, legacy onshore oil reservoirs with long-lived, relatively predictable production profiles and low production decline rates.

We are an “emerging growth company” as defined in Section 101 of the Jumpstart Our Business Startups Act of 2012, or the JOBS Act.

Quarterly Highlights

On January 23, 2015, the Board of Directors of our general partner granted the issuance of 202,000 unrestricted

and 268,000 restricted common units with one-third vesting immediately and the other two thirds vesting over two years, and

26,100 restricted common units with a three-year vesting period. All of these units were granted to certain employees of our

affiliates and certain directors and founders of our general partner.

On January 26, 2015, we restructured a significant portion of our existing oil derivatives that were in place at December 31, 2014. This resulted in the early settlement of certain contracts existing at December 31, 2014, and entering into new oil derivative contracts which extend through September 2016.

On February 9, 2015, the revolving credit facility was amended to allow our EBITDAX calculation, as defined in section

7.13 of the original revolving credit agreement, to reflect the net cash flows attributable to the restructured commodity

derivative contracts that occurred during January 2015 to be recognized in specific amounts for the periods of the first quarter 2015 through the third quarter of 2016.

On February 13, 2015, we paid a cash distribution to unitholders for the fourth quarter of 2014 at a rate of $0.125 per unit. The aggregate amount of the distribution was approximately $3.8 million.

Business Environment

The markets for oil, natural gas, and NGLs have been volatile historically and may continue to be volatile in the future, which means that the price of oil can fluctuate widely. Sustained periods of low prices for oil could materially and adversely affect our financial position, our results of operations, the quantities of oil reserves that we can economically produce and our access to capital.

Our hedging strategy is to enter into various commodity derivative contracts intended to achieve more predictable cash flows and to reduce exposure to commodity market volatility. Our hedging program’s objective is to protect our ability to make current distributions, and to allow us to be better positioned to increase our quarterly distributions over time, while retaining some ability to participate in upward moves in commodity prices. We use a phased approach, looking approximately 36 months forward while targeting a higher amount of hedged volumes in the near 12 months.

Our business faces the challenge of natural production declines. As initial reservoir pressures are depleted, oil production from a given well or formation decreases. Although our waterflood operations tend to restore reservoir pressure and production, once a waterflood is fully effected, production, once again, begins to decline. Our future growth will depend on our ability to continue to add reserves in excess of our production. Our focus on adding reserves is primarily through improving the economics of producing oil from our existing fields and, secondarily, through acquisitions and development of additional proved reserves. Our ability to add reserves through exploitation projects and acquisitions is dependent upon many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel, and successfully identify and close acquisitions.

We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flows from operations are impacted by our ability to manage our overall cost structure.

How We Evaluate Our Operations

Our primary business objective is to manage our oil and natural gas properties for the purpose of generating stable cash flows, which will provide stability and, over time, growth of distributions to our unitholders. The amount of cash that we can distribute to our unitholders depends principally on the cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other factors:


•	the amount of oil and natural gas we produce;


•	the prices at which we sell our oil and natural gas production;


•	our ability to hedge commodity prices; and


•	the level of our operating and administrative costs.

Results of Operations

The table below summarizes certain of the results of operations and period-to-period comparisons for the periods indicated (dollars in thousands, except price per unit data):



	Three Months Ended March 31,
	2015		2014
Revenues:
Oil sales	$	17,294	$	21,638
Natural gas sales	277		169
Gain (loss) on derivatives, net	1,644		(2,048		)
Total revenues	$	19,215	$	19,759
Operating costs and expenses:
Lease operating expenses	$	8,915	$	4,691
Oil and natural gas production taxes	$	1,109	$	1,356
Depreciation, depletion and amortization	$	7,846	$	3,663
General and administrative (1)	$	3,641	$	7,631
Interest expense	$	1,727	$	807
Production:
Oil (MBbls)	391		232
Natural gas (MMcf)	127		21
Total (MBoe)	412		236
Average net production (Boe/d)	4,578		2,622
Average sales price:
Oil (per Bbl):
Sales price	$	44.23	$	93.27
Effect of net settlements on matured derivative instruments (3)	$	11.45	$	(3.97	)
Realized oil price after derivatives	$	55.68	$	89.30
Natural gas (per Mcf):
Sales price (2)	$	2.18	$	8.05
Average unit costs per Boe:
Lease operating expenses	$	21.64	$	19.88
Oil and natural gas production taxes	$	2.69	$	5.75
Depreciation, depletion and amortization	$	19.04	$	15.52
General and administrative expenses	$	8.84	$	32.33


(1)	General and administrative expenses include non-cash, equity-based compensation of $1.9 million and $5.5 million for the three months ended March 31, 2015 and 2014.


(2)	Natural gas sales price per Mcf includes the sale of natural gas liquids.


(3)	Effect of net settlements on commodity derivative instruments does not include the $11.1 million received from restructuring the previous oil derivative contracts in January 2015.

Three Months Ended March 31, 2015 Compared with the Three Months Ended March 31, 2014

We reported a net loss of approximately $4.1 million for the three months ended March 31, 2015, compared to a net income of approximately $1.6 million for the three months ended March 31, 2014, a decrease of approximately $5.7 million. The change was primarily attributable to lower oil prices, higher depreciation, depletion and amortization ("DD&A") expense and higher lease operating expenses for the three months ended March 31, 2015.

Sales Revenues. Revenues from oil and natural gas sales for the three months ended March 31, 2015, were approximately $17.6 million compared to approximately $21.8 million for the three months ended March 31, 2014. Despite the year over year production growth resulting from incremental volumes from acquisitions of properties in 2014, revenues were negatively affected by lower oil and gas prices driven by market conditions. Oil market prices fell from $100.51 per barrel in March 2014 to $55.00 per barrel by the end of 2014 and $47.85 at March 31, 2015. Our average sales price per barrel of oil, excluding commodity derivative contracts, for the three months ended March 31, 2015 was approximately $44.23, compared with approximately $93.27 for the three months ended March 31, 2014.

On average, our production volumes for the three months ended March 31, 2015, were approximately 412 MBoe, or approximately 4,578 Boe per day on average. In comparison, our total production volumes for the three months ended March 31, 2014, were approximately 236 MBoe, or approximately 2,622 Boe per day on average. The increase in production volumes was primarily due to acquisitions of additional oil properties in 2014 and drilling and recompletion efforts in our Northeastern Oklahoma core area.

Effects of Commodity Derivative Contracts. We utilize NYMEX contracts to hedge against changes in commodity prices. To the extent the future commodity price outlook declines between measurement periods, we will have gains on our unsettled derivatives. To the extent future commodity price outlook increases between measurement periods, we will have losses on our unsettled derivatives. During the three months ended March 31, 2015, we recorded a net gain of approximately $1.6 million which was composed of approximately $15.8 million gain on net cash settlements of derivative contracts and approximately $14.2 million non-cash loss on changes in fair value of unsettled derivative contracts. The realized gain of approximately $15.8 million consists of approximately $11.1 million for the early termination of our contracts in place and approximately $4.7 million from settled derivatives in place during the three months ended March 31, 2015. The unrealized loss of approximately $14.2 million is primarily related to the $11.1 million gain from early termination of the contracts and to the $3.6 million gain upon settlement in January 2015 for contracts that were not early terminated or modified, both of which were previously recognized in the results of operations during the year ended December 31, 2014. For the three months ended March 31, 2014, we recorded a net loss from our commodity hedging instruments of approximately $2.0 million, which was composed of a loss of approximately $0.9 million on net cash settlements of derivative contracts and approximately $1.1 million non-cash loss on changes in fair value of unsettled derivative contracts.

Lease Operating Expenses. Our lease operating expenses were approximately $8.9 million for the three months ended March 31, 2015, or approximately $21.64 per Boe, compared to approximately $4.7 million for the three months ended March 31, 2014, or approximately $19.88 per Boe. The increase in total lease operating expenses over the prior year’s quarter was primarily attributable to the acquisitions of additional oil properties in 2014 and the additional number of producing wells resulting from our drilling and recompletion programs. The increase in average costs per Boe reflects higher costs of operations in comparison to the proportional increases in production in our Hugoton and Southern Oklahoma core areas during the current period.

Production Taxes. Production taxes are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts. For the three months ended March 31, 2015, our production taxes were approximately $1.1 million, or approximately $2.69 per Boe for an effective tax rate of approximately 6.3%, compared to approximately $1.4 million for the three months ended March 31, 2014, or approximately $5.75 per Boe for an effective tax rate of approximately 6.2%. The decrease in production taxes during the three months ended March 31, 2015 was directly related to lower oil and natural gas revenues driven by lower oil prices. The decrease in price per Boe is primarily attributable to the 2014 acquisitions of properties in Texas that have a lower production tax rate as compared to our legacy properties in Oklahoma.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses (“DD&A”) on producing properties for the three months ended March 31, 2015, were approximately $7.8 million, or approximately $19.04 per Boe produced, compared to approximately $3.7 million, or approximately $15.52 per Boe produced, for the three months ended March 31, 2014. The increase in DD&A was primarily due to the increase in the total asset value of our oil and natural gas properties due to the acquisitions of additional oil properties in 2014. The increase in DD&A per Boe was due to higher depletion rates in some of the oil and gas properties acquired in 2014.

General and Administrative Expenses. Our general and administrative expenses were approximately $3.6 million for the three months ended March 31, 2015, or approximately $8.84 per Boe produced, compared to approximately $7.6 million for the three months ended March 31, 2014 or approximately $32.33 per Boe produced. The overall decrease in general and administrative expenses for the three months ended March 31, 2015 was attributed to lower compensation costs related to our non-cash equity-based compensation plan resulting principally from the lower price of our common units. Non-cash equity based compensation was $1.9 million and $5.5 million for the three months ended March 31, 2015 and 2014, respectively.

Interest Expense. Our interest expense for the three months ended March 31, 2015, was approximately $1.7 million, compared to $0.8 million for the three months ended March 31, 2014. The increase in interest expense during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 was due to higher borrowings outstanding from our revolving credit facility.

Liquidity and Capital Resources

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for oil and natural gas, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

Crude oil prices have fallen to five-year lows, potentially impacting the way we conduct business. We have implemented

a number of adjustments to strengthen our competitive position. In addition to restructuring our commodity derivative contracts during the first quarter of 2015 to provide greater oil price protection over a longer period of time, we are aggressively pursuing costs reductions in order to improve profitability.

Our liquidity position as of March 31, 2015, consisted of approximately $0.3 million of available cash, and $37.0 million of available borrowings under our revolving credit facility. On April 2, 2015, our borrowing base was revised downward from $240.0 million to $220.0 million upon the scheduled borrowing redetermination. As of April 2, 2015, our $250.0 million revolving credit facility had a remaining borrowing capacity of $17.0 million ($220.0 million borrowing base less $203.0 million of outstanding borrowings). Borrowings under the revolving credit facility may not exceed our current borrowing base of $220.0 million. The next scheduled borrowing base redetermination is expected to take place in October 2015.

Our primary use of capital has been for the acquisition and development of oil and natural gas properties. Our future success in growing reserves and production volumes will be highly dependent on the capital resources available and our success in drilling or acquiring additional reserves. As we pursue profitable reserves and production growth, we continually monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our revolving credit facility.

Cash Flow

Cash flow provided by (used in) each type of activity was as follows (in thousands):



	Three Months Ended March 31,
	2015			2014
Operating activities	$	8,283		$	11,850
Investing activities	(5,376		)	(13,639		)
Financing activities	(5,839		)	738

Operating Activities. Net cash provided by operating activities was approximately $8.3 million and $11.9 million for the three months ended March 31, 2015 and 2014, respectively. The $3.6 million decrease from 2014 to 2015 was primarily attributable to decreased oil sales revenues due to lower oil prices combined with higher lease operating expenses and partially offset by a decrease in working capital.

Investing Activities. Net cash used in investing activities was approximately $5.4 million and approximately $13.6 million for the three months ended March 31, 2015 and 2014, respectively. Cash used in investing activities during the three months ended March 31, 2015 included capital expenditures of approximately $5.4 million primarily for drilling and completion activities in our Northeastern Oklahoma and Permian properties. Cash used in investing activities during the three

months ended March 31, 2014 included approximately $7.2 million for the acquisition of additional working interests. We also spent $6.4 million on capital expenditures, primarily for drilling, development and completion activities.

Financing Activities. Our cash flows from financing activities consisted primarily of proceeds from and payments on our revolving credit facility, and distributions to unitholders. Net cash used in financing activities was approximately $5.8 million which included net payments on our revolving credit facility of $2.0 million, cash distributions to unitholders of approximately $3.7 million and approximately $0.1 million of incremental offering costs from our November 2014 public offering. Cash provided by financing activities during the three months ended March 31, 2014 was approximately $0.7 million which included net proceeds from borrowings under our revolving credit facility of $11.0 million which were used to finance the acquisition of properties located in Cimarron, Love and Texas Counties, Oklahoma and Potter County, Texas, in February 2014 and to develop capital projects.We also made cash distributions to our unitholders of approximately $10.3 million.

Capital Requirements

Our business requires continual investment to upgrade or enhance existing operations in order to increase and maintain our production and the size of our asset base. The primary purpose of growth capital is to acquire, develop and produce assets that allow us to increase our production levels and asset base. Given the current commodity pricing situation that has oil prices

at a five year low, we have limited capital spending to include only the most attractive development projects with a more

conservative approach than in prior years. We are actively engaged in the acquisition of oil and natural gas properties and

through our focus on returns, we expect to be well positioned to capitalize on attractive acquisition opportunities in the current oil price environment. We have funded acquisition transactions through a combination of cash, available borrowing capacity under our current revolving credit facility and through the issuance of equity. We expect to finance any significant acquisition of oil and natural gas properties in 2015 through the issuance of equity, debt financing or borrowings under our revolving credit facility.

We currently expect capital spending for the remainder of 2015 for the development, growth and maintenance of our oil and natural gas properties to be approximately $11.3 million. We will consider adjustments to this capital program based on our assessment of additional development opportunities that are identified during the year and the cash available to invest in our development projects.

Revolving Credit Facility

We have a $250.0 million senior secured revolving credit facility that expires in November 2018. Borrowings under the revolving credit facility may not exceed our current borrowing base of $220.0 million as determined at April 2, 2015.

Borrowings under the facility are secured by liens on not less than 80% of our assets and the assets of our subsidiaries. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general partnership purposes and for funding distributions to our unitholders. The remaining borrowing capacity under our revolving credit facility was approximately $37.0 million and $17.0 million at March 31, 2015 and April 2, 2015, respectively. The facility requires us and our subsidiaries to maintain a leverage ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX (as defined in the facility) of not more than 4.0 to 1.0, and a current ratio of not less than 1.0 to 1.0. We were in compliance with all of the facility’s financial covenants throughout the period ended March 31, 2015.

With the April 2, 2015 redetermination, our borrowing base was reduced to $220.0 million from $240.0 million. The next scheduled borrowing base redetermination is expected to take place in October 2015.

For additional information about our long-term debt, such as interest rates and covenants, please see “Item 1. Financial Statements” contained herein.

Derivative Contracts

At March 31, 2015, our open commodity derivative contracts were in a net asset position with a fair value of approximately $27.2 million. All of our commodity derivative contracts are with major financial institutions. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments in the event of lower commodity prices and we could incur a loss. As of March 31, 2015, all of our counterparties had performed pursuant to their commodity derivative contracts.

See Note 4 to the unaudited condensed consolidated financial statements within this report for a discussion of our commodity derivative contracts.

Off–Balance Sheet Arrangements

As of March 31, 2015, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

In February 2015, the Financial Accounting Standards Board issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which provides guidance on the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities such as limited partnerships, limited liability corporations, and securitization structures (collateralized debt obligations, collateralized loan obligations, and mortgage-backed security transactions). In addition to reducing the number of consolidation models from four to two, the guidance simplifies and improves current guidance by placing more emphasis on risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a VIE. The standard is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are currently evaluating the effect, if any, that this new guidance will have on our consolidated financial statements and related disclosures.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to a variety of market risks including commodity price risk, interest rate risk and credit risk. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

The following should be read in conjunction with the financial statements and related notes included elsewhere in this Form10-Q and in our Annual Report.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil production. Realized pricing is primarily driven by the spot market prices applicable to the prevailing price for oil. Pricing for oil has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil production depend on many factors outside of our control, such as the strength of the global economy and changes in supply and demand.

To reduce the impact of fluctuations in oil prices on our revenues, or to protect the economics of property acquisitions, we have entered into, and may enter into, additional commodity derivative contracts for a portion of our oil production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil production over a fixed period of time. These hedging activities are intended to manage our exposure to oil price fluctuations.

Our oil derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, it is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers. We evaluate the credit standing of such counterparties by reviewing their credit ratings. The counterparties to our derivative contracts currently in place are lenders under our revolving credit facility and have investment grade ratings. We expect to enter into future derivative contracts with these or other lenders under our revolving credit facility whom we expect will also carry investment grade ratings.

Our commodity price risk management activities could have the effect of reducing net income and the value of our securities. The fair value of our oil commodity contracts at March 31, 2015, was a net asset of approximately $27.2 million. A 10% change in oil prices with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil commodity contracts of approximately $5.6 million. Please see “Item 1. Financial Statements” contained herein for additional information.

Interest Rate Risk

Our exposure to changes in interest rates relates primarily to debt obligations. At March 31, 2015, we had debt outstanding of $203.0 million, with an effective interest rate of approximately 2.7%. Assuming no change in the amount outstanding, the impact on interest expense of a 10% increase or decrease in the average interest rate would be approximately $0.5 million for the three months ended March 31, 2015. Our revolving credit facility allows borrowings up to $220.0 million at an interest rate ranging from LIBOR plus a margin ranging from 1.75% to 2.75% or the prime rate plus a margin ranging from 0.75% to 1.75%, depending on the amount borrowed. The prime rate will be the United States prime rate as announced from time-to-time by the Royal Bank of Canada. Please see “Item 1. Financial Statements” contained herein for additional information.

Counterparty and Customer Credit Risk

We are subject to credit risk due to the concentration of our revenues attributable to a small number of customers for our current 2015 production. The inability or failure of any of our customers to meet its obligations to us or its insolvency or liquidation may adversely affect our financial results. However, our current purchasers have positive payment histories.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our chief executive officer (principal executive officer) and chief financial officer (principal financial officer), the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2015. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we filed under the Exchange Act is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on this evaluation, our chief executive officer and chief financial officer have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this Form 10-Q.

Changes in Internal Controls Over Financial Reporting

There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the quarterly period ended March 31, 2015, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

In the course of our ongoing preparations for making management’s report on internal control over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002, from time to time we have identified areas in need of improvement and have taken remedial actions to strengthen the affected controls as appropriate. We make these and other changes to enhance the effectiveness of our internal control over financial reporting, which do not have a material effect on our overall internal control over financial reporting.

PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

ITEM 1A. RISK FACTORS

There have been no material changes with respect to the risk factors disclosed in our Annual Report for the year ended December 31, 2014.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

See our current reports on Form 8-K filed with the SEC on March 5, 2014 and August 11, 2014.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

The exhibits listed below are filed or furnished as part of this Quarterly Report:




Exhibit No.		Exhibit Description

10.1		Amendment No.6 to Credit Agreement, dated as of February 12, 2015, among Mid-Con Energy Properties, LLC, as Borrower, Royal Bank of Canada, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated by reference to Exhibit 10.01 to Mid-Con Energy Partners, LP's current report on Form 8-K filed with the SEC on February 17, 2015).

31.1+		Rule 13a-14(a)/ 15(d)- 14(a) Certification of Chief Executive Officer

31.2+		Rule 13a-14(a)/ 15(d)- 14(a) Certification of Chief Financial Officer

32.1+		Section 1350 Certificate of Chief Executive Officer

32.2+		Section 1350 Certificate of Chief Financial Officer

101.INS++		XBRL Instance Document

101.SCH++		XBRL Taxonomy Extension Schema Document

101.CAL++		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF++		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB++		XBRL Taxonomy Extension Label Linkbase Document

101.PRE++		XBRL Taxonomy Extension Presentation Linkbase Document

_________________________


+	Filed herewith

In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101 to this Form 10-Q shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

SIGNATURE

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



	MID-CON ENERGY PARTNERS, LP

	By:	Mid-Con Energy GP, LLC, its general partner

May 5, 2015	By:	/s/ Michael D. Peterson
		Michael D. Peterson
		Chief Financial Officer

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