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EVEP > SEC Filings for EVEP > Form 10-Q on 11-Aug-2014All Recent SEC Filings

Show all filings for EV ENERGY PARTNERS, LP

Form 10-Q for EV ENERGY PARTNERS, LP


11-Aug-2014

Quarterly Report


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 on Form 10-K for the year ended December 31, 2013.

OVERVIEW

We are a Delaware limited partnership formed in April 2006 by EnerVest to acquire, produce and develop oil and natural gas properties. Our general partner is EV Energy GP, a Delaware limited partnership, and the general partner of our general partner is EV Management, a Delaware limited liability company.

We have two reportable segments: exploration and production and midstream. Our exploration and production segment is responsible for the acquisition, development and production of our oil and natural gas properties. Our midstream segment, which consists of our investments in Cardinal and UEO, is engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio. We account for our investments in Cardinal and UEO using the equity method of accounting.

Our oil and natural gas properties are located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Monroe Field in Northern Louisiana, Central and East Texas (which includes the Austin Chalk area), the San Juan Basin, Michigan, and the Permian Basin. As of December 31, 2013, we had estimated net proved reserves of 13.1 MMBbls of oil, 819.7 Bcf of natural gas and 48.9 MMBbls of natural gas liquids, or 1,191.6 Bcfe, and a standardized measure of $1,039.8 million.

CURRENT DEVELOPMENTS

In January 2014 and February 2014, we closed on additional sales of our Utica Shale acreage in Ohio and received aggregate proceeds of $1.5 million.

In January 2014, the assets and liabilities that were held for sale as of December 31, 2013 were sold for $5.8 million.

In the six months ended June 30, 2014, we invested $83.2 million in our midstream segment.

In August 2014, we announced that we, along with certain institutional partnerships managed by EnerVest, have signed an agreement to sell certain deep rights in the Eagle Ford formation in Burleson, Brazos and Grimes counties. Our share of the proceeds is expected to be approximately $30 million, net to our ownership interest, and we will retain all non-Eagle Ford formation rights, including the Austin Chalk formation and corresponding production. The transaction is expected to close in October and is subject to customary closing conditions and purchase price adjustments.

BUSINESS ENVIRONMENT

Our primary business objective is to provide stability and growth in cash distributions per unit over time. The amount of cash we can distribute on our units principally depends upon the amount of cash generated from our operations, which will fluctuate from quarter to quarter based on, among other things:

the prices at which we will sell our oil, natural gas liquids and natural gas production;

our ability to hedge commodity prices;

the distributions that we may receive from our interests in Cardinal and UEO;

the amount of oil, natural gas liquids and natural gas we produce; and

the level of our operating and administrative costs.

Oil, natural gas and natural gas liquids prices are expected to be volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas and natural gas liquids include the discovery of substantial accumulations of natural gas in unconventional reservoirs due to technological advancements necessary to commercially produce these unconventional reserves, North American weather conditions, industrial and consumer demand for natural gas and natural gas liquids, storage levels of natural gas and natural gas liquids and the availability and accessibility of natural gas deposits in North America.

In order to mitigate the impact of changes in prices on our cash flows, we are a party to derivatives, and we intend to enter into derivatives in the future to reduce the impact of price volatility on our cash flows. By removing a significant portion of this price volatility on our future production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flows from operations for those periods. If commodity prices are depressed for an extended period of time, it could alter our acquisition and development plans, and adversely affect our growth strategy and ability to access additional capital in the capital markets.

The primary factors affecting our production levels are capital availability, our ability to make accretive acquisitions, the success of our drilling program and our inventory of drilling prospects. In addition, as initial reservoir pressures are depleted, production from our wells decreases. We attempt to overcome this natural decline through a combination of drilling and acquisitions. Our future growth will depend on our ability to continue to add reserves through drilling and acquisitions in excess of production. We will maintain our focus on the costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact our production, which may have an adverse effect on our revenues and, as a result, cash available for distribution.

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

Cardinal and UEO generate revenues from fees charged for gathering, compressing, processing, fractionating and storing natural gas and natural gas liquids. The primary drivers of revenues are the capacity of our midstream facilities and the production available for gathering, processing and fractionating. As we account for our investments in Cardinal and UEO using the equity method of accounting, our proportionate share of their revenues or expenses is reflected in "Equity in income of unconsolidated affiliates" in our unaudited condensed consolidated statements of operations.

Utica Shale

Primarily through acquisitions completed in 2009 and 2010, we hold over 170,000 net working interest acres in Pennsylvania and Ohio and an approximate 2% average ORRI in 880,000 gross acres in Ohio which we believe may be prospective for the Utica Shale. In addition, partnerships managed by EnerVest own acreage which may be prospective for the Utica Shale. At June 30, 2014, our estimated net proved reserves in the Utica Shale were not material to us. Exploration and development activities targeting the Utica Shale are in the early stages, and it is possible that our estimates of the acreage in Ohio that we believe is prospective for the Utica Shale may change, perhaps materially, as additional exploration and development activities are conducted in the area.

The Utica Shale area can be divided into wet natural gas, volatile oil, black oil and dry natural gas areas. We own over 40,000 net acres in the wet natural gas area and approximately 80,000 net acres in the volatile oil area, with the remaining acreage primarily in the black oil area. Most drilling activity in the Utica Shale area has been in the wet natural gas area, but drilling activity is increasing in the dry natural gas and volatile oil areas. The current focus in the volatile oil area is on hydraulic fracturing techniques necessary to economically drill and produce in this area. We are currently seeking joint venture partners to develop and design hydraulic fracturing techniques that will allow wells in the volatile oil window to produce at economic levels.

In mid-2012, we initiated the process for the monetization of a majority of our working interest acres related to the Utica Shale, and in 2013, we, along with certain institutional partnerships managed by EnerVest, signed agreements to divest a portion of our Utica Shale acreage. Through June 2014, we have closed on sales with proceeds of $45.6 million for these acres. We continue to pursue additional forms of monetizations, and we cannot at this time predict the type of transactions we may enter into or the type or amount of consideration we may receive. We may not be successful in our additional efforts to monetize the Utica Shale properties, it may take longer to complete the divestiture process than we expect, or we may decide to delay the monetization of all or a portion of the Utica Shale properties.

RESULTS OF OPERATIONS



                                             Three Months Ended          Six Months Ended
                                                  June 30,                   June 30,
                                              2014          2013         2014         2013
Production data:
Oil (MBbls)                                       255          245          520          508
Natural gas liquids (MBbls)                       571          526        1,121        1,029
Natural gas (MMcf)                             10,962       11,057       21,798       21,324
Net production (MMcfe)                         15,920       15,683       31,645       30,547
Average sales price per unit:
Oil (Bbl)                                  $    98.84     $  92.56     $  96.48     $  93.03
Natural gas liquids (Bbl)                       30.36        28.83        31.89        29.59
Natural gas (Mcf)                                4.16         3.84         4.42         3.53
Mcfe                                             5.54         5.12         5.76         5.01
Average unit cost per Mcfe:
Production costs:
Lease operating expenses                   $     1.64     $   1.67     $   1.63     $   1.71
Production taxes                                 0.19         0.19         0.20         0.19
Total                                            1.83         1.86         1.83         1.90
Depreciation, depletion and amortization         1.57         1.76         1.62         1.92
General and administrative expenses              0.80         0.58         0.79         0.71

Three Months Ended June 30, 2014 Compared with the Three Months Ended June 30, 2013

Net (loss) income for the three months ended June 30, 2014 was $(9.0) million compared with $32.9 million for the three months ended June 30, 2013. The significant factors in this change were (i) a $52.6 million unfavorable change in loss (gain) on derivatives, net; (ii) a $7.8 million increase in total revenues; (iii) a $3.6 million increase in general and administrative expenses;
(iv) a $3.3 million increase in income of unconsolidated affiliates; and (v) a $2.6 million decrease in depreciation, depletion and amortization ("DD&A").

Oil, natural gas and natural gas liquids revenues for the three months ended June 30, 2014 totaled $88.1 million, an increase of $7.8 million compared with the three months ended June 30, 2013. This was the result of increases of $5.8 million related to higher prices for oil, natural gas and natural gas liquids and $2.4 million related to increased oil and natural gas liquids production offset by $0.4 million of lower natural gas production.

Lease operating expenses for the three months ended June 30, 2014 decreased $0.2 million compared with the three months ended June 30, 2013 as the result of $0.6 million from a lower unit cost per Mcfe offset by $0.4 million related to our expanded development drilling program. Lease operating expenses per Mcfe were $1.64 in the three months ended June 30, 2014 compared with $1.67 in the three months ended June 30, 2013.

DD&A for the three months ended June 30, 2014 decreased $2.6 million compared with the three months ended June 30, 2013 due to $3.0 million from a lower average DD&A rate per Mcfe offset by $0.4 million from increased production. The lower average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates and the decrease in the carrying value of our oil and natural gas properties from the impact of the impairments that were recognized in 2013. Depreciation, depletion and amortization for the three months ended June 30, 2014 was $1.57 per Mcfe compared with $1.76 per Mcfe for the three months ended June 30, 2013.

General and administrative expenses for the three months ended June 30, 2014 totaled $12.7 million, an increase of $3.6 million compared with the three months ended June 30, 2013. This increase is primarily the result of (i) $2.3 million of additional equity compensation costs related to the accelerated vesting of the phantom units of a former officer; (ii) $0.7 million of higher compensation costs due to the separation payment made to our former senior vice president of acquisitions; and (iii) $0.5 million of higher fees paid to EnerVest under the omnibus agreement. General and administrative expenses were $0.80 per Mcfe in the three months ended June 30, 2014 compared with $0.58 per Mcfe in the three months ended June 30, 2013.

In the three months ended June 30, 2014, we incurred leasehold impairment charges of $1.1 million. In the three months ended June 30, 2013, we incurred leasehold impairment charges of $2.8 million.

(Loss) gain on derivatives, net was $(17.8) million for the three months ended June 30, 2014 compared with $34.7 million for the three months ended June 30, 2013. This change was attributable to changes in future oil and natural gas prices and the impact of decreased cash settlements of matured derivative contracts with more favorable terms that expired as of December 31, 2013. The 12 month forward price at June 30, 2014 for oil averaged $97.49 per Bbl compared with $97.33 per Bbl at March 31, 2014, and the 12 month forward price at June 30, 2014 for natural gas averaged $4.07 per MmBtu compared with $4.50 at March 31, 2014. The 12 month forward price at June 30, 2013 for oil averaged $93.33 per Bbl compared with $96.21 at March 31, 2013, and the 12 month forward prices at June 30, 2013 for natural gas averaged $3.74 per MmBtu compared with $4.17 at March 31, 2013.

Interest expense for the three months ended June 30, 2014 increased $0.8 million compared with the three months ended June 30, 2013 due to $1.4 million from a higher weighted average long-term debt balance offset by $0.6 million from a lower weighted effective interest rate offset.

Equity in income of unconsolidated affiliates was $3.3 million for the three months ended June 30, 2014 compared with $0.1 million for the three months ended June 30, 2013. The significant factor in the increase was that both Cardinal and UEO have begun operations and are continuing to increase throughput as more wells come on line.

Six Months Ended June 30, 2014 Compared with the Six Months Ended June 30, 2013

Net loss for the six months ended June 30, 2014 was $15.3 million compared with $13.7 million for the six months ended June 30, 2013. The significant factors in this change were (i) a $48.0 million unfavorable change in loss (gain) on derivatives, net; (ii) a $29.4 million increase in total revenues; (iii) a $7.3 million decrease in DD&A; (iv) a $6.7 million decrease in impairments of our oil and natural gas properties; and (iv) a $3.3 million increase in general and administrative expenses.

Oil, natural gas and natural gas liquids revenues for the six months ended June 30, 2014 totaled $182.2 million, an increase of $29.2 million compared with the six months ended June 30, 2013. This was the result of increases of $23.0 million related to higher prices for oil, natural gas and natural gas liquids and $6.2 million related to increased production.

Lease operating expenses for the six months ended June 30, 2014 decreased $0.9 million compared with the six months ended June 30, 2013 as the result of $2.7 million from a lower unit cost per Mcfe, primarily related to decreased gathering costs at our Barnett Shale oil and natural gas properties offset by $1.8 million from our expanded development drilling program. Lease operating expenses per Mcfe were $1.63 in the six months ended June 30, 2014 compared with $1.71 in the six months ended June 30, 2013.

Production taxes, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, for the six months ended June 30, 2014 increased $0.6 million compared with the six months ended June 30, 2013 primarily due to increased oil, natural gas and natural gas liquids revenues. Production taxes for the six months ended June 30, 2014 were $0.20 per Mcfe compared with $0.19 per Mcfe for the six months ended June 30, 2013.

DD&A for the six months ended June 30, 2014 decreased $7.3 million compared with the six months ended June 30, 2013 due to $9.0 million from a lower average DD&A rate per Mcfe offset by $1.7 million from increased production. The lower average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates and the decrease in the carrying value of our oil and natural gas properties from the impact of the impairments that were recognized in 2013. Depreciation, depletion and amortization for the six months ended June 30, 2014 was $1.62 per Mcfe compared with $1.92 per Mcfe for the six months ended June 30, 2013.

General and administrative expenses for the six months ended June 30, 2014 totaled $25.0 million, an increase of $3.3 million compared with the six months ended June 30, 2013. This increase is primarily the result of (i) $2.3 million of additional equity compensation costs related to the accelerated vesting of the phantom units of a former officer; (ii) $1.0 million of higher fees paid to EnerVest under the omnibus agreement; and (iii) $0.7 million of higher compensation costs due to the separation payment made to our former senior vice president of acquisitions partially offset by $1.0 million of lower compensation costs primarily related to the January 2014 vesting of our phantom units issued under our equity-based compensation plan. General and administrative expenses were $0.79 per Mcfe in the six months ended June 30, 2014 compared with $0.71 per Mcfe in the six months ended June 30, 2013.

In the six months ended June 30, 2014, we incurred impairment charges of $1.3 million, of which $0.2 million related to a charge to write down assets held for sale to their fair value and $1.1 million related to leasehold impairment charges. In the six months ended June 30, 2013, we incurred leasehold impairment charges of $8.0 million.

(Loss) gain on derivatives, net was $(40.8) million for the six months ended June 30, 2014 compared with $7.2 million for the six months ended June 30, 2013. This change was attributable to changes in future oil and natural gas prices and the impact of decreased cash settlements of matured derivative contracts with more favorable terms that expired as of December 31, 2013. The 12 month forward price at June 30, 2014 for oil averaged $97.49 per Bbl compared with $95.66 per Bbl at December 31, 2013, and the 12 month forward price at June 30, 2014 for natural gas averaged $4.07 per MmBtu compared with $4.19 at December 31, 2013. The 12 month forward price at June 30, 2013 for oil averaged $93.33 per Bbl compared with $93.09 at December 31, 2012, and the 12 month forward prices at June 30, 2013 for natural gas averaged $3.74 per MmBtu compared with $3.54 at December 31, 2012.

Interest expense for the six months ended June 30, 2014 was flat compared with the six months ended June 30, 2013 due to an increase in capitalized interest of $1.2 million and $1.5 million from a lower weighted effective interest rate offset by $2.7 million from a higher weighted average long-term debt balance.

Equity in income of unconsolidated affiliates was $5.2 million for the six months ended June 30, 2014 compared with $0.3 million for the six months ended June 30, 2013. The significant factor in the increase was that both Cardinal and UEO have begun operations and are continuing to increase throughput as more wells come on line.

LIQUIDITY AND CAPITAL RESOURCES

Historically, our primary sources of liquidity and capital have been issuances of equity and debt securities, borrowings under our credit facility and cash flows from operations. Our primary uses of cash have been acquisitions of oil and natural gas properties and related assets, development of our oil and natural gas properties, contributions to our midstream investments, distributions to our unitholders and general partner and working capital needs. For 2014, we believe that cash on hand, proceeds from sales of assets, net cash flows generated from operations and borrowings under our credit facility will be adequate to fund our capital budget, pay distributions to our unitholders and general partner and satisfy our short-term liquidity needs. We may also utilize borrowings under our credit facility and various financing sources available to us, including the issuance of equity or debt securities through public offerings or private placements, to fund our acquisitions and long-term liquidity needs. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

Long-term Debt

As of June 30, 2014, we have a $1.0 billion credit facility that expires in April 2016. Borrowings under the facility may not exceed a "borrowing base" determined by the lenders based on our oil and natural gas reserves. As of June 30, 2014, the borrowing base was $730.0 million, and we had $625.0 million outstanding.

As of June 30, 2014, we have $500.0 million in aggregate principal amount outstanding of 8.0% senior notes due 2019. As of June 30, 2014, the aggregate carrying amount of the senior notes due 2019 was $499.3 million.

For additional information about our long-term debt, such as interest rates and covenants, please see "Item 1. Condensed Consolidated Financial Statements (unaudited)" contained herein.

Cash and Short-term Investments

At June 30, 2014, we had $18.7 million of cash and short-term investments, which included $3.9 million of short-term investments. With regard to our short-term investments, we invest in money market accounts with major financial institutions.

Counterparty Exposure

All of our derivative contracts are with major financial institutions who are also lenders under our credit facility. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative contracts and we could incur a loss. As of June 30, 2014, all of our counterparties have performed pursuant to their derivative contracts.

Cash Flows



Cash flows provided by (used in) type of activity were as follows:



                           Six Months Ended
                               June 30,
                          2014           2013
Operating activities   $   63,280     $   70,407
Investing activities     (123,050 )     (162,229 )
Financing activities       66,737         92,613

Operating Activities

Cash flows from operating activities provided $63.3 million and $70.4 million in the six months ended June 30, 2014 and 2013, respectively. The significant factors in the change were a $29.2 million increase in our oil, natural gas and natural gas liquids revenues offset by $27.9 million of decreased cash settlements from our matured derivative contracts and an increase in working capital, primarily related to higher accounts receivable from our higher oil, natural gas and natural gas liquids revenues. The decreased cash settlements are due to increased oil, natural gas and natural gas liquids prices and the impact of derivative contracts with more favorable terms that expired as of December 31, 2013.

Investing Activities

During the six months ended June 30, 2014, we spent $44.9 million for additions to our oil and natural gas properties and increased our investment in unconsolidated affiliates by $83.2 million. In addition, we received $7.3 million in proceeds from the sale of oil and natural gas properties.

During the six months ended June 30, 2013, we spent $51.8 million for additions to our oil and natural gas properties and increased our investment in unconsolidated affiliates by $118.4 million. In addition, we received $8.0 million in final purchase price settlements related to our August 2012 acquisition of additional working interests in acreage in Ohio.

Financing Activities

During the six months ended June 30, 2014, we received $144.0 million from borrowings under our credit facility and paid distributions of $77.4 million to holders of our common units, phantom units and our general partner.

During the six months ended June 30, 2013, we received $160.0 million from borrowings under our credit facility and paid distributions of $67.7 million to holders of our common units, phantom units and our general partner.

FORWARD-LOOKING STATEMENTS

This 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 Exchange Act (each a "forward-looking statement"). These forward-looking statements relate to, among other things, the following:

our future financial and operating performance and results;

our business strategy and plans, including plans for the sale of acreage in the Utica Shale;

our estimated net proved reserves, PV-10 value and standardized measure;

market prices;

our future derivative activities; and

our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

The words "anticipate," "believe," "ensure," "expect," "if," "intend," "estimate," "project," "forecasts," "predict," "outlook," "aim," "will," "could," "should," "would," "may," "likely" and similar expressions, and the negative thereof, are intended to identify forward-looking statements. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other "forward-looking" information. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Form 10-Q including, but not limited to:

fluctuations in prices of oil, natural gas and natural gas liquids;

significant disruptions in the financial markets;

future capital requirements and availability of financing;

our limited control over operations in our midstream business:

uncertainty inherent in estimating our reserves;

risks associated with drilling and operating wells;

discovery, acquisition, development and replacement of reserves;

cash flows and liquidity;

timing and amount of future production of oil, natural gas and natural gas liquids;

availability of drilling and production equipment;

marketing of oil, natural gas and natural gas liquids;

developments in oil and natural gas producing countries;

competition;

general economic conditions;

governmental regulations;

activities taken or non-performance by third parties, including suppliers, contractors, operators, transporters and purchasers of our production and counterparties to our derivative financial instruments; . . .

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