Edgar Filing: Mid-Con Energy Partners, LP

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Form 10-Q

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 September 30, 2012

¨	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 November 7, 2012, the registrant had 19,292,849 common units and general partner units outstanding.

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION


Forward-Looking Statements			3
ITEM 1. FINANCIAL STATEMENTS			5
Unaudited Condensed Consolidated Balance Sheets			5
Unaudited Consolidated Statements of Operations			6
Unaudited Consolidated Statements of Cash Flows			7
Unaudited Consolidated Statements 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			14

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			22
ITEM 4. CONTROLS AND PROCEDURES			23

PART II
OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS			23
ITEM 1A. RISK FACTORS			23
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			23
ITEM 3. DEFAULTS UPON SENIOR SECURITIES			24
ITEM 4. MINE SAFETY DISCLOSURES			24
ITEM 5. OTHER INFORMATION			24
ITEM 6. EXHIBITS			24

Signatures			25

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.

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, 2011 (“Annual Report”). This document is available through our web site, 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, changes in expectations 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)


	September 30, 2012			December 31, 2011
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,057		$	228
Accounts receivable:
Oil and gas sales		5,459			5,018
Other		303			2,405
Derivative financial instruments		3,872			1,028
Prepaids and other		129			25

Total current assets		10,820			8,704

PROPERTY AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method:
Proved properties		127,576			97,269
Accumulated depletion, depreciation and amortization		(18,723	)		(11,403	)

Total property and equipment, net		108,853			85,866

DERIVATIVE FINANCIAL INSTRUMENTS		2,299			1,505
OTHER ASSETS		455			536

Total assets	$	122,427		$	96,611

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	5,904		$	4,575
Accrued liabilities		869			138
Other payables		—			1,630

Total current liabilities		6,773			6,343

LONG-TERM DEBT		60,000			45,000

ASSET RETIREMENT OBLIGATIONS		2,506			1,919

EQUITY, per accompanying statements:
Partnership equity
General partner interest		1,491			1,299
Limited partners- 17,932,849 and 17,640,000 units issued and outstanding as of September 30, 2012 and December 31, 2011, respectively		51,657			42,050

Total equity		53,148			43,349

Total liabilities and equity	$	122,427		$	96,611

See accompanying notes to consolidated financial statements

Mid-Con Energy Partners, LP and subsidiaries

Consolidated Statements of Operations

(in thousands, except per unit data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(unaudited)						(unaudited)
Revenues:
Oil sales	$	14,939		$	9,459		$	43,937		$	25,068
Natural gas sales		109			316			462			974
Realized gain (loss) on derivatives, net		1,211			(84	)		1,980			(799	)
Unrealized gain (loss) on derivatives, net		(6,103	)		8,354			3,638			9,400

Total Revenues		10,156			18,045			50,017			34,643

Operating costs and expenses:
Lease operating expenses		2,634			2,401			7,359			5,951
Oil and gas production taxes		585			460			1,298			1,116
Impairment of proved oil and gas properties		1,255			—			1,255			—
Dry holes and abandonments of unproved properties		—			—			—			772
Depreciation, depletion and amortization		2,611			1,900			7,320			4,318
Accretion of discount on asset retirement obligations		35			23			92			55
General and administrative		3,714			1,860			8,583			2,394

Total operating costs and expenses		10,834			6,644			25,907			14,606

Income (loss) from operations		(678	)		11,401			24,110			20,037

Other income (expense):
Interest income and other		2			98			7			160
Interest expense		(461	)		(141	)		(1,164	)		(378	)
Gain on sale of assets		—			350			—			1,559
Other revenue and expenses, net		—			—			—			576

Total other income (expense)		(459	)		307			(1,157	)		1,917

Net income (loss)	$	(1,137	)	$	11,708		$	22,953		$	21,954

Computation of net income (loss) per limited partner unit:
General partners’ interest in net income (loss)	$	(22	)	$	234		$	455		$	439

Limited partners’ interest in net income (loss)	$	(1,115	)	$	11,474		$	22,498		$	21,515

Net income (loss) per limited partner unit (basic and diluted)	$	(0.06	)	$	0.65		$	1.26		$	1.22
Weighted average limited partner units outstanding:
(basic and diluted)		17,933			17,640			17,790			17,640

See accompanying notes to consolidated financial statements

Mid-Con Energy Partners, LP and subsidiaries

Consolidated Statements of Cash Flows

(in thousands)


	Nine Months Ended September 30,
	2012			2011
	(unaudited)
Cash Flows from Operating Activities:
Net income	$	22,953		$	21,954
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		7,320			4,318
Debt placement fee amortization		81			—
Accretion of discount on asset retirement obligations		92			55
Impairment of proved oil and gas properties		1,255			—
Dry holes and abandonments of unproved properties		—			772
Unrealized gain on derivative instruments, net		(3,638	)		(9,400	)
Gain on sale of assets		—			(1,559	)
Equity-based compensation		5,194			1,671
Changes in operating assets and liabilities:
Accounts receivable		(441	)		(1,498	)
Other receivables		(303	)		—
Other current assets		2,300			139
Accounts payable and accrued liabilities		2,972			(1,820	)
Revenues payable		—			42
Advance billings and other		—			(120	)

Net cash provided by operating activities		37,785			14,554

Cash Flows from Investing Activities:
Additions to oil and gas properties		(17,031	)		(21,370	)
Additions to other property and equipment		—			(679	)
Acquisitions of oil and natural gas properties		(16,577	)		(10,146	)
Proceeds from sale of other property and equipment		—			1,219
Proceeds from sale of investment in subsidiary, net of cash sold		—			2,095
Proceeds from sale of property and equipment to subsidiary, net of cash sold		—			4,000

Net cash used in investing activities		(33,608	)		(24,881	)

Cash Flows from Financing Activities:
Proceeds from line of credit		27,000			17,850
Payments on line of credit		(12,000	)		(7,900	)
Borrowings on note payable		—			412
Payments on note payable		—			(84	)
Distributions paid		(18,348	)		—
Issuance of common units		—			13

Net cash provided by (used in) financing activities		(3,348	)		10,291

Net increase (decrease) in cash and cash equivalents		829			(36	)

Beginning cash and cash equivalents		228			222

Ending cash and cash equivalents	$	1,057		$	186

Supplemental Cash Flow Information:

Cash paid for interest	$	1,014		$	340

Non-Cash Investing and Financing Activities:

Accrued capital expenditures - oil and gas properties	$	785		$	1,421

Notes receivable from officers, director and employees	$	—		$	106

Deferred gain on sale of property and equipment to subsidiary	$	—		$	3,224

See accompanying notes to consolidated financial statements

Mid-Con Energy Partners, LP and subsidiaries

Consolidated Statements of Changes in Equity

(in thousands)


	General Partner			Limited Partner					Total Equity
	General Partner			Units		Amount			Total Equity
				(unaudited)
Balance, December 31, 2011	$	1,299			17,640	$	42,050		$	43,349
Distributions		(362	)				(17,986	)		(18,348	)
Equity-based compensation		102			293		5,092			5,194
Net income		452					22,501			22,953

Balance, September 30, 2012	$	1,491			17,933	$	51,657		$	53,148

See accompanying notes to 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,” or “us”) is a publicly held Delaware limited partnership that engages in the acquisition, exploitation and development of producing oil and natural gas properties in North America, with a focus on the Mid-Continent region of the United States. Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company.

In December 2011, Mid-Con Energy I, LLC and Mid-Con Energy II, LLC (together, “our predecessor”), merged into our wholly owned subsidiary, Mid-Con Energy Properties, LLC.

Basis of Presentation

Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the SEC. 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 for the year ended December 31, 2011.

All intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Unaudited Condensed Consolidated Financial Statements, all dollar and unit amounts in tabulations are in thousands of dollars and units, respectively, unless otherwise indicated.

Note 2. Acquisitions

During June 2012, we acquired certain oil properties located in the Northeastern Oklahoma core area, and additional working interests in our existing units in the Southern Oklahoma core area, in unrelated transactions. The combined purchase prices for these properties have been reflected in the unaudited condensed consolidated financial statements along with the results of operations of these properties beginning at the closing date. We paid approximately $16.4 million in aggregate consideration for these properties. The transactions were financed using existing cash and proceeds from our credit facility. During the third quarter 2012, we had miscellaneous acquisitions of $0.2 million.

Note 3. Equity Awards

We have a long-term incentive program (the “Plan”) for employees, officers, consultants and directors of our general partner and its affiliates, including Mid-Con Energy Operating, Inc. (“Mid-Con Energy Operating”), who perform services for us. The Plan allows for the award of unit options, unit appreciation rights, restricted units, phantom units, distribution equivalent rights granted with phantom units, and other types of awards. As of September 30, 2012, the Plan 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.

In January 2012, we issued 125,000 unrestricted common units (“URUs”) to employees, officers, directors and consultants of our general partner and affiliates. Also, in January 2012, we issued 24,561 restricted common units (“RUs”) that have a three- year vesting period. The fair market value of both the URUs and RUs was based on the closing price of our common units at the date of the awards, which was $20.90 per unit.

In July 2012, we issued 112,500 unrestricted common units (“URUs”) to employees, officers, directors and consultants of our general partner and affiliates. Also, in July 2012, we issued 38,097 restricted common units (“RUs”) that have a three-year vesting period. The fair market value of both the URUs and RUs was based on the closing price of our common units at the date of the awards, which was $21.50 per unit. During the third quarter 2012, there were 7,309 RUs forfeited.

The RUs are subject to forfeiture and we assume a 10% forfeiture rate for the RUs to estimate our equity-based compensation expense. These costs are reported as a component of general and administrative expense in our unaudited

consolidated statements of operations. The equity-based compensation expense for the three and nine months ended September 30, 2012 was $2.5 million and $5.3 million respectively. For both the three and nine months ended September 30, 2011, the equity-based compensation expense was $1.7 million.

Note 4. Derivative Financial Instruments

Our risk management program is intended to reduce our exposure to commodity prices and interest rates 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.

We have elected not to designate any of our positions as cash flow hedges for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts as “Unrealized gain (loss) on derivatives, net” in our unaudited consolidated statements of operations. 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.

As of September 30, 2012, 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
Swaps - Oct 2012 through Dec 2012	$	101.85						111,000
Collars - Oct 2012 through Dec 2012			$	100.00	$	117.00		18,000
Swaps - 2013	$	100.14						444,000
Collars - 2013			$	100.00	$	111.00		72,000
Collars - 2013			$	93.00	$	102.25		36,000
Swaps - 2014	$	94.30						480,000

The fair value and location of our derivatives in our condensed consolidated balance sheets was as follows:


	Asset Derivatives				Liability Derivatives
	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
Derivative financial instruments- current asset	$	3,872	$	1,028	$	—	$	—
Derivative financial instruments- long-term asset		2,299		1,505		—		—
Derivative financial instruments- current liability		—		—		—		—
Derivative financial instruments- long-term liability		—		—		—		—

	$	6,171	$	2,533	$	—	$	—

The following table presents the impact of derivative financial instruments and their location within the unaudited consolidated statements of operations:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012		2011
Realized gain (loss) on derivatives, net	$	1,211		$	(84	)	$	1,980	$	(799	)
Unrealized gain (loss) on derivatives, net		(6,103	)		8,354			3,638		9,400

	$	(4,892	)	$	8,270		$	5,618	$	8,601

Note 5. Fair Value Disclosures

Fair Value of Financial Instruments

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

We account for our oil and gas commodity derivatives 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. The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value as of September 30, 2012 and December 31, 2011:


	Level 1		Level 2		Level 3
	(in thousands)
September 30, 2012
Assets and Liabilities Measured at Fair Value on a Recurring Basis
- Derivative financial instruments- asset	$	—	$	6,171	$	—
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
- Asset retirement obligations	$	—	$	—	$	495
- Impairment of proved oil and gas properties	$	—	$	—	$	1,255

December 31, 2011
Assets and Liabilities Measured at Fair Value on a Recurring Basis
- Derivative financial instruments- asset	$	—	$	2,533	$	—
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
- Asset retirement obligations	$	—	$	—	$	716

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 nine months ended September 30, 2012.

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 its estimated fair value. 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. During the three months ended September 30, 2012, we recorded a $1.1 million and $0.2 million non-cash impairment charge within our miscellaneous core area and our Southern Oklahoma core area, respectively, due to a decline in reserve estimates. The charge is included in impairment of proved oil and gas properties in our unaudited consolidated statements of operations. There was no impairment charge for both the three and nine months ended September 30, 2011.

Note 6. Asset Retirement Obligations

Asset retirement obligations (“ARO”) are recorded as a liability at their estimated present value at the various assets’ inception, with the offsetting charge to oil and gas properties. Periodic accretion of the discounted estimated liability is recorded in our unaudited consolidated statements 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.

Our AROs represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their production lives, in accordance with applicable state laws. We determine our asset retirement obligations by calculating the present value of estimated cash flow related to the liability. Each year we review and, to the extent necessary, revise our asset retirement obligation estimates.

Changes in our asset retirement obligations are as follows:


	Nine Months Ended September 30, 2012		Year Ended December 31, 2011
	(in thousands)
Asset retirement obligation – beginning of period	$	1,919	$	2,148
Liabilities incurred for new wells		353		370
Disposition of wells		—		(1,024	)
Revision of estimates		142		347
Accretion expense		92		78

Asset retirement obligation – end of period	$	2,506	$	1,919

As of September 30, 2012 and December 31, 2011, $2.5 million and $1.9 million, respectively, of our ARO was classified as long-term and was reported as “Asset Retirement Obligations” in our unaudited condensed consolidated balance sheets.

Note 7. Debt

As of September 30, 2012, our credit facility consists of a $250.0 million senior secured revolving facility that expires in December 2016. Borrowings under the facility are secured by liens on not less than 80% of our assets and the assets of our subsidiary. 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 facility requires us and our subsidiary to maintain a leverage ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX (as such terms are defined in the Credit Agreement) of not more than 4.0 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0. As of September 30, 2012 and December 31, 2011, we were in compliance with all debt covenants.

Borrowings under the credit agreement 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 September 30, 2012, the average effective interest rate was approximately 2.56%. 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.

On April 23, 2012, the borrowing base under our credit facility was increased from $75.0 million to $100.0 million and Wells Fargo Bank, N.A. was added as an additional lender. No other material terms of the original credit agreement were amended. Borrowings under the facility may not exceed our current borrowing base of $100.0 million. The borrowing base is determined by our 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.

At September 30, 2012, we had approximately $60.0 million in indebtedness outstanding under the facility.

Note 8. Commitment and Contingencies

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.

Note 9. Equity

Common Units

At September 30, 2012, Partnership’s equity consisted of 17,932,849 common units, representing approximately a 98% limited partnership interest in us.

Cash Distributions

The following sets forth the distributions we paid during the nine months ended September 30, 2012:


Date Paid	Period Covered	Distribution per Unit		Total Distribution
February 13, 2012	December 21, 2011 - December 31, 2011	$	0.057	$	1,034	(1)
May 14, 2012	January 1, 2012 - March 31, 2012		0.475		8,622
August 14, 2012	April 1, 2012 - June 30, 2012		0.475		8,692

				$	18,348

(1)	The distribution represented a proration of initial quarterly distribution of $0.475 per unit.

On October 15, 2012, the Board of Directors of our general partner declared a quarterly cash distribution for the third quarter of 2012 of $0.485 per unit, or $1.94 on an annualized basis, an increase of $0.01 from the previous quarter, which will be paid on November 14, 2012 to unitholders of record at the close of business on November 7, 2012. The aggregate amount of the distribution will be approximately $9.4 million.

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. We, our general partner and its affiliates have entered into the various documents and agreements, which are described below.

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 and nine months ended September 30, 2012, we reimbursed Mid-Con Energy Operating approximately $0.8 million and approximately $2.1 million, respectively, for direct expenses.

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 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 fees). These costs are included in lease operating expenses in our unaudited consolidated statements of operations.

Note 11. New Accounting Standards

No new accounting pronouncements issued or effective during the nine months ended September 30, 2012 have had or are expected to have a material impact on our consolidated financial statements.

Note 12. Subsequent Events

On November 2, 2012, we, through our wholly-owned subsidiary, completed the acquisition from the original seller and additional third parties, certain oil properties located in our Hugoton Basin core area for a contract price of approximately $28.9 million, subject to customary post-closing conditions. The acquisition was financed with existing cash and borrowings under our credit facility.

On October 22, 2012, we closed a public offering of 4,000,000 common units (the “Firm Units”) representing limited partner interests in us at a price to the public of $21.20 per unit. 1,000,000 common units were sold by us, and 3,000,000 common units were sold by Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P. and Yorktown Energy Partners VIII, L.P. (collectively, “Yorktown”). Additionally, the underwriters exercised in full their option to purchase an additional 600,000 common units from Yorktown, the closing of which occurred simultaneously with the closing of the underwriters’ purchase of the Firm Units. We intend to use net proceeds of approximately $20.4 million from our 1,000,000 common unit offering, after deducting underwriting discounts but before offering expenses, to repay borrowings outstanding under our credit facility. We did not receive any proceeds from the 3,600,000 common units sold by Yorktown.

On October 22, 2012, we acquired additional working interest in our War Party I and II units located in our Hugoton Basin core area for approximately $3.7 million. The transaction was financed initially with borrowings under our credit facility.

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

We are a Delaware limited partnership formed in July 2011 to own, operate, acquire, exploit and develop producing oil and natural gas properties in North America, with a focus on the Mid-Continent region of the United States. Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company. Our properties are located in the Mid-Continent region of the United States in three core areas: Southern Oklahoma, Northeastern Oklahoma and parts of Oklahoma and Colorado within the Hugoton Basin. Our properties primarily consist of mature, legacy onshore oil reservoirs with long-lived, relatively predictable production profiles and low production decline rates.

In December 2011, we completed our initial public offering of 5,400,000 common units at an initial public offering price of $18.00 per unit, and on January 9, 2012, we closed the sale of an additional 810,000 common units pursuant to the exercise of the underwriters’ over-allotment option. Upon the closing of our initial public offering (and taking into account the underwriters’ exercise of their over-allotment option), we had 17,640,000 common units and 360,000 general partner units outstanding, representing a 98% limited partner interest in us, and a 2.0% general partner interest, respectively.

On October 22, 2012, we closed a public offering of 4,000,000 Firm Units representing limited partner interests in us at a price to the public of $21.20 per unit. 1,000,000 common units were sold by us, and 3,000,000 common units were sold by Yorktown. Additionally, the underwriters exercised in full their option to purchase an additional 600,000 common units from Yorktown, the closing of which occurred simultaneously with the closing of the underwriters’ purchase of the Firm Units. We intend to use net proceeds of approximately $20.4 million from our 1,000,000 common unit offering, after deducting underwriting discounts but before offering expenses, to repay borrowings outstanding under our credit facility. We did not receive any proceeds from the 3,600,000 common units sold by Yorktown.

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 August 14, we paid a cash distribution to unitholders for the second quarter of 2012 at the rate of $0.475 per unit.

Business Environment

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.

While oil prices have generally increased since the second quarter of 2009, the outlook and timing for a worldwide economic recovery remains uncertain for the foreseeable future. As a result, it is likely that commodity prices will continue to be volatile. 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 fluctuations in the price of oil. 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 oil prices. We use a phased approach, looking approximately 36 months forward while targeting a higher amount of hedges 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. We plan to maintain our focus on adding reserves primarily through improving the economics of producing oil from our existing fields and, secondarily, through acquisitions 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.

Results of Operations

The table below summarizes certain of the results of operations for the periods indicated (in thousands, except operating and per unit amounts). The data for the periods reflect our results as they are presented in our unaudited consolidated financial statements included elsewhere in this report.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012		2011
Revenues:
Oil sales	$	14,939		$	9,459		$	43,937	$	25,068
Natural gas sales		109			316			462		974
Realized gain (loss) on derivatives, net		1,211			(84	)		1,980		(799	)
Unrealized gain (loss) on derivatives, net		(6,103	)		8,354			3,638		9,400

Total Revenues	$	10,156		$	18,045		$	50,017	$	34,643

Operating costs and expenses:
Lease operating expenses		2,634			2,401			7,359		5,951
Oil and gas production taxes		585			460			1,298		1,116
Impairment of proved oil and gas properties		1,255			—			1,255		—
Depreciation, depletion and amortization (1)		2,611			1,900			7,320		3,979
General and administrative (2)		3,714			1,860			8,583		2,394
Interest expense		461			141			1,164		378
Production:
Oil (MBbls)		171			111			475		278
Natural gas (MMcf)		31			47			91		126
Total (MBoe)		176			119			490		299
Average net production (Boe/d)		1,913			1,293			1,788		1,095
Average sales price:
Oil (per Bbl):
Sales price	$	87.36		$	85.22		$	92.50	$	90.17
Effect of realized commodity derivative instruments	$	7.08		$	(0.76	)	$	4.17	$	(2.87	)
Realized price, after effect of derivatives	$	94.44		$	84.46		$	96.67	$	87.30
Natural gas (per Mcf):
Sales price (3)	$	3.52		$	6.72		$	5.08	$	7.73
Average unit costs per Boe:
Lease operating expenses	$	14.97		$	20.18		$	15.02	$	19.90
Oil and gas production taxes	$	3.32		$	3.87		$	2.65	$	3.73
Depreciation, depletion and amortization	$	14.84		$	15.97		$	14.94	$	13.31
General and administrative expenses	$	21.10		$	15.63		$	17.52	$	8.01

(1)	Depreciation, depletion and amortization expenses for this table only represents the depletion expense for the producing properties.

(2)	General and administrative expenses include non-cash, equity-based compensation.

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

Three Months Ended September 30, 2012 Compared with the Three Months Ended September 30, 2011

Net loss was approximately $1.1 million for the three months ended September 30, 2012 compared to approximately $11.7 million net income for the three months ended September 30, 2011, a decrease of approximately $12.8 million. The decrease is primarily due to unrealized losses on derivatives in September 2012 resulting from higher future commodity prices, higher general and administrative expenses (including equity-based compensation expense) and higher depreciation expenses, offset by increased oil sales during the three months ended September 30, 2012.

Sales Revenues. Revenues from oil and natural gas sales for the three months ended September 30, 2012 were approximately $15.0 million compared to approximately $9.8 million for the three months ended September 30, 2011. The increase in revenues was primarily due to an increase in daily oil production in 2012.

Our production volumes for the three months ended September 30, 2012 were approximately 176 MBoe, or approximately 1,913 Boe per day. In comparison, our total production volumes for the three months ended September 30, 2011 were approximately 119 MBoe, or approximately 1,293 Boe per day on average. The increase in production volumes was primarily the result of ongoing waterflood response to injection and the drilling programs in our Southern Oklahoma waterflood units. Our average sales price per barrel of oil, excluding commodity derivative contracts, for the three months ended September 30, 2012 was approximately $87.36, compared with approximately $85.22 for the three months ended September 30, 2011.

Effects of Commodity Derivative Contracts. Due to changes in the fair value of our commodity contracts, we recorded a net loss from our commodity hedging instruments for the three months ended September 30, 2012 of approximately $4.9 million, which was composed of an unrealized loss of approximately $6.1 million and a realized gain of approximately $1.2 million. For the three months ended September 30, 2011, we recorded a net gain from our commodity hedging program of approximately $8.3 million, which was composed of an unrealized gain of approximately $8.4 million and a realized loss of approximately $0.1 million.

Lease Operating Expenses. Our lease operating expenses were approximately $2.6 million for the three months ended September 30, 2012, or approximately $14.97 per Boe, compared to approximately $2.4 million for the three months ended September 30, 2011, or approximately $20.18 per Boe. The increase in total lease operating expenses over the prior year quarter was primarily attributable to an increase in production resulting from our drilling programs, the increase in the number of producing wells and the increase in working interest in our properties. The decrease in lease operating expenses per Boe was due to the increased production for the three months ended September 30, 2012.

Production Taxes. Our production taxes were approximately $0.6 million for the three months ended September 30, 2012, or approximately $3.32 per Boe for an effective tax rate of approximately 3.9%, compared to approximately $0.5 million for the three months ended September 30, 2011, or approximately $3.87 per Boe for an effective tax rate of approximately 4.7%. The increase in production taxes during the three months ended September 30, 2012 was primarily due to the increased in production and the realized average oil sales price. Production taxes are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts. The State of Oklahoma, where most of our properties are located, currently imposes a production tax of 7.2% for oil and natural gas properties and an excise tax of 0.095%. A portion of our wells in Oklahoma continue to receive a reduced production rate due to Oklahoma’s Enhanced Recovery Project Gross Production Tax Exemption which has been extended to July 2014.

Impairment Expense. Our impairment expense was approximately $1.3 million for the three months ended September 30, 2012. 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. If the carrying amount exceeds the property’s estimated fair value, we adjust the carrying amount of the property to fair value through a charge to impairment expense. During the three months ended September 30, 2012, we recorded a $1.1 million and $0.2 million non-cash impairment charge within our miscellaneous core area and our Southern Oklahoma core area, respectively. There was no impairment charge for the three months ended September 30, 2011.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses on producing properties for the three months ended September 30, 2012 were approximately $2.6 million, or approximately $14.84 per Boe produced, compared to approximately $1.9 million, or approximately $15.97 per Boe produced, for the three months ended September 30, 2011. The increase in depreciation, depletion and amortization expenses and lower average price per Boe produced was primarily due to the increase in total proved and proved developed reserves estimated at September 30, 2012, the increase in total asset value of the oil and gas properties from our drilling program, the acquisitions of properties in our Hugoton Basin and Southern Oklahoma core areas, which both occurred during the second half of 2011, in addition to the acquisition of oil properties located in the Northeastern Oklahoma core area and the purchase of additional working interest in our Southern Oklahoma properties during 2012.

General and Administrative Expenses. Our general and administrative expenses were approximately $3.7 million for the three months ended September 30, 2012, or approximately $21.10 per Boe produced compared to approximately $1.9 million for the three months ended September 30, 2011 or approximately $15.63 per Boe produced. The increase in general and administrative

expenses for the three months ended September 30, 2012 is primarily due to higher compensation costs related to our non-cash equity-based compensation plan, incremental costs related to the hiring of additional staff, and higher professional fees necessary to comply with public reporting requirements.

Interest Expense. Our interest expense for the three months ended September 30, 2012 was approximately $0.5 million, compared to $0.1 million for the three months ended September 30, 2011. The increase was primarily due to increased borrowings from our credit facility.

Nine Months Ended September 30, 2012 Compared with the Nine Months Ended September 30, 2011

Net income was approximately $23.0 million for the nine months ended September 30, 2012 compared to approximately $22.0 million for the nine months ended September 30, 2011, an increase of approximately $1.0 million. This increase primarily reflects increased oil sales, offset by higher general and administrative expenses (including equity-based compensation expense), higher depreciation and lease operating expenses and the net effect of realized gains and unrealized losses on derivatives.

Sales Revenues. Revenues from oil and natural gas sales for the nine months ended September 30, 2012 were approximately $44.4 million as compared to approximately $26.0 million for the nine months ended September 30, 2011. The increase in revenues was primarily due to an increase in daily oil production in 2012.

Our production volumes for the nine months ended September 30, 2012 were approximately 490 MBoe, or approximately 1,788 Boe per day. In comparison, our total production volumes for the nine months ended September 30, 2011 were approximately 299 MBoe, or approximately 1,095 Boe per day on average. The increase in production volumes was primarily due to ongoing waterflood response to injection as well as the drilling programs in our Southern Oklahoma core area, acquisitions of interests in various properties located in the Hugoton Basin area and Northeast Oklahoma, and the purchase of additional working interest in our Southern Oklahoma properties. Our average sales price per barrel of oil, excluding commodity derivative contracts, for the nine months ended September 30, 2012 was $92.50, compared with $90.17 for the nine months ended September 30, 2011.

Effects of Commodity Derivative Contracts. Due to changes in commodity prices, we recorded a net gain from our commodity hedging program for the nine months ended September 30, 2012 of approximately $5.6 million, which was composed of a realized gain of approximately $2.0 million and an unrealized gain of approximately $3.6 million. For the nine months ended September 30, 2011, we recorded a net gain from our commodity hedging program of approximately $8.6 million, which was composed of a realized loss of approximately $0.8 million and an unrealized gain of approximately $9.4 million.

Lease Operating Expenses. Our lease operating expenses were approximately $7.4 million for the nine months ended September 30, 2012, or $15.02 per Boe, compared to approximately $6.0 million for the nine months ended September 30, 2011, or approximately $19.90 per Boe. The increase in total lease operating expenses during the nine months ended September 30, 2012 was primarily attributable to an increase in production resulting from our drilling programs and the increase in the number of producing wells. The decrease in lease operating expenses per Boe was due to the increased production for the nine months ended September 30, 2012. Ad valorem taxes are also reflected in lease operating expenses. Ad valorem taxes are levied on our properties in Colorado and are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts, and a percentage of production equipment value.

Production Taxes. Our production taxes were approximately $1.3 million for the nine months ended September 30, 2012, or approximately $2.65 per Boe for an effective tax rate of approximately 2.9%, compared to approximately $1.1 million for the nine months ended September 30, 2011, or approximately $3.73 per Boe for an effective tax rate of approximately 4.3%. The decrease in the production taxes per Boe during the nine months ended September 30, 2012 was primarily due to receiving an adjustment of $0.5 million of production taxes for one of our Southern Oklahoma units for periods prior to the year 2012. The adjustment was due to the Enhanced Recovery Project Gross Production Tax Exemption. Production taxes are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts. The State of Oklahoma, where most of our properties are located, currently imposes a production tax of 7.2% for oil and natural gas properties and an excise tax of 0.095%. A portion of our wells in Oklahoma continue to receive a reduced production rate due to Oklahoma’s Enhanced Recovery Project Gross Production Tax Exemption which has been extended to July 2014.

Impairment Expense. Our impairment expense was approximately $1.3 million for the nine months ended September 30, 2012. 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. If the carrying amount exceeds the property’s estimated fair value, we adjust the carrying amount of the property to fair value through a charge to impairment expense. During the nine months ended September 30, 2012, we recorded a $1.1 million and $0.2 million non-cash impairment charge within our miscellaneous core area and our Southern Oklahoma core area, respectively. There was no impairment charge for the nine months ended September 30, 2011.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses on producing properties for the nine months ended September 30, 2012 were approximately $7.3 million, or approximately $14.94 per Boe produced, compared to approximately $4.0 million, or approximately $13.31 per Boe produced, for the nine months ended September 30, 2011. The increase in depreciation, depletion and amortization expenses and average price per Boe produced was primarily due to the increase in total proved and proved developed reserves estimated at September 30, 2012 and also to the increase in total asset value of the oil and gas properties from our drilling program, the acquisitions of properties in our Hugoton Basin and Southern Oklahoma core areas, which both occurred during the second half of 2011, in addition to the acquisition of oil properties located in the Northeastern Oklahoma core area during 2012, and the purchase of additional working interest in our Southern Oklahoma properties.

General and Administrative Expenses. Our general and administrative expenses were approximately $8.6 million for the nine months ended September 30, 2012, or approximately $17.52 per Boe produced compared to approximately $2.4 million for the nine months ended September 30, 2011 or approximately $8.01 per Boe produced. The increase in general and administrative expenses for the nine months ended September 30, 2012 is primarily due to higher compensation costs related to our non-cash equity-based compensation expense, higher professional fees necessary to comply with public reporting requirements, and incremental costs related to the hiring of additional staff.

Interest Expense. Our interest expense for the nine months ended September 30, 2012 was approximately $1.2 million, compared to approximately $0.4 million for the nine months ended September 30, 2011. The increase was primarily due to increased borrowings from our 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. 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.

We believe a strong balance sheet is a necessary pre-requisite for creating sustainable growth in unitholder value. Our liquidity position as of September 30, 2012 consisted of approximately $1.1 million of available cash, and $40.0 million of available borrowings under our credit facility. Our primary use of capital has been for the acquisition and development of oil and natural gas properties. 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 credit facility. As of September 30, 2012, our $250.0 million credit facility had a remaining borrowing capacity of $40.0 million ($100.0 million borrowing base less $60.0 million of outstanding borrowings). The borrowing base is re-determined on or about April 30 and October 31 of each year, beginning with April 30, 2012. On April 23, 2012 the borrowing base of our credit facility was increased from $75.0 million to $100.0 million.

Cash Flow

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


	Nine Months Ended
	September 30,
	2012			2011
Operating activities	$	37,785		$	14,554
Investing activities		(33,608	)		(24,881	)
Financing activities		(3,348	)		10,291

Operating Activities. Net cash provided by operating activities was approximately $37.8 million and $14.6 million for the nine months ended September 30, 2012 and 2011, respectively. Our revenues increased significantly for the nine months ended September 30, 2012 compared to 2011, primarily due to increased production, favorable commodity pricing, our successful exploitation of our proved reserves, our ability to reduce our per unit operating expenses and our successful acquisition activity.

Cash provided by operating activities is impacted by the prices we receive for oil and natural gas sales and production volumes. Our production volumes in the future will in large part be dependent upon the results of past waterflood development activities and results of future capital expenditures. Our future levels of capital expenditures may vary due to many factors, including development and drilling results, oil and natural gas prices, industry conditions, prices and availability of goods and services and the extent to which proved properties are acquired.

Investing Activities. Net cash used in investing activities was approximately $33.6 million and approximately $24.9 million for the nine months ended September 30, 2012, and 2011, respectively. The increase in the amount of cash used in investing activities for the nine months ended September 30, 2012 was primarily due to the increased waterflood development activities in our Southern Oklahoma core area and development activity in our Northeastern Oklahoma core areas along with approximately $16.6 million of acquisitions.

Financing Activities. Net cash used in financing activities for the nine months ended September 30, 2012 was approximately $3.3 million and net cash provided by financing activities for the nine months ended September 30, 2011 was approximately $10.3 million. During the nine months ended September 30, 2012, we had net borrowings of $15.0 million from our credit facility to finance the purchase of certain oil properties located in our Northeastern Oklahoma core area and of certain working interests in our existing units in the Southern Oklahoma core area and also paid cash distributions of approximately $18.3 million. For the nine months ended September 30, 2011, the cash provided by financing activities primarily related to $10.3 million of net borrowings from the credit facility.

Capital Requirements

We are actively engaged in the acquisition of oil and natural gas properties. We expect to finance any significant acquisition of oil and natural gas properties in 2012 with the issuance of equity, debt financing or borrowings under our credit facility. Additionally, we currently expect capital spending for the remainder of 2012 for the development, growth and maintenance of our oil and natural gas properties to be approximately $4.9 million.

Credit Facility

We are party to a $250.0 million senior secured revolving credit facility that expires in December 2016. Borrowings under the facility are secured by liens on not less than 80% of our assets and the assets of our subsidiary. 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 September 30, 2012, we had approximately $60.0 million of borrowings outstanding under our revolving credit facility.

The 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 facility agreement, together with accrued interest, could be declared immediately due and payable. As of September 30, 2012, we were in compliance with all debt covenants.

On April 23, 2012, the borrowing base of our credit facility was increased from $75.0 million to $100.0 million and Wells Fargo Bank, N.A. was added as an additional lender. No other material terms of the original credit agreement were amended.

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 September 30, 2012, our open commodity derivative contracts were in a net asset position with a fair value of approximately $6.2 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 September 30, 2012, all of our counterparties had performed pursuant to their commodity derivative contracts.

All of our derivative contracts for 2012, 2013 and 2014 are either swaps with fixed settlements or collars. These instruments limit our exposure to declines in prices, but also limit the benefits if prices increase. We do not specifically designate commodity derivative contracts as cash flow hedges; therefore, the mark-to-market adjustment reflecting the change in the unrealized gains or losses on these 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.

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

Off–Balance Sheet Arrangements

As of September 30, 2012, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

No new accounting pronouncements issued or effective during the nine months ended September 30, 2012 have had or are expected to have a material impact on our consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business.

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 Form 10-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.

To reduce the impact of fluctuations in oil prices on our revenues, or to protect the economics of property acquisitions, we periodically enter into commodity derivative contracts with respect to a significant portion of our projected oil production through various transactions that fix the future prices received. These hedging activities are intended to manage our exposure to oil price fluctuations. We do not enter into derivative contracts for speculative trading purposes.

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 credit facility and have investment grade ratings. We expect to enter into future derivative contracts with these or other lenders under our credit facility whom we expect will also carry investment grade ratings.

The fair value of our oil and natural gas commodity contracts and swaps at September 30, 2012 was a net asset of approximately $6.2 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 and swaps of approximately $2.5 million. Please see “Item 1. Financial Statements” contained herein for additional information.

Interest Rate Risk

At September 30, 2012, we had long-term debt outstanding of $60.0 million, with an effective interest rate of approximately 2.56% for the third quarter of 2012. 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 $0.2 million on an annual basis. The interest rate we pay under our credit facility ranges from LIBOR plus 1.75% to LIBOR plus 2.75% or the prime rate plus 0.75% to the prime rate plus 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. On April 23, 2012, the borrowing base of our credit facility was increased from $75.0 million to $100.0 million.

Counterparty and Customer Credit Risk

We were subject to credit risk due to the concentration of our revenues attributable to a small number of customers for our current 2012 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, Coffeyville Resources Refining & Marketing, LLC, Vitol Inc., Oil Marketing Division, USA and Valero Marketing & Supply Co., each have positive payment histories. Coffeyville Resources is rated one level below investment grade. Accordingly, we believe that the credit quality of such customers is high.

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 the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed in our reports filed or submitted 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 September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We have taken steps, including hiring additional accounting personnel and purchasing new accounting software, in an effort to enhance our internal control over financial reporting. We continue our efforts to ensure that the new accounting and control procedures that we have put in place are functioning properly.

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, 2011.

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

None.

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		Purchase and Sale Agreement dated October 15, 2012 and filed of record in the Partnership’s Amended S-1 dated October 15, 2012 (incorporated by reference to Exhibit 10.9 to Mid-Con Energy, LP’s Amendment No. 1 to the Registration Statement on Form S-1 dated October 15, 2012 (File No. 333-184120)).
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

Date: November 7, 2012	By:	/s/ Jeffrey R. Olmstead
		Jeffrey R. Olmstead
		President and Chief Financial Officer

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