News Column

NEW SOURCE ENERGY PARTNERS L.P. - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

August 14, 2014

The following discussion and analysis is intended to help investors understand the Partnership's business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with the Partnership's accompanying unaudited condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as the Partnership's audited consolidated financial statements and the accompanying notes included in the 2013 Form 10-K. The Partnership's discussion and analysis includes the following subjects:



•Overview;

•Results by Segment; •Results of Operations; •Liquidity and Capital Resources; and •Critical Accounting Policies and Estimates. The financial information with respect to the three and six months ended June 30, 2014 and 2013, discussed below, is unaudited. In the opinion of management, this information contains all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the unaudited condensed consolidated financial statements in accordance with GAAP. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control, including among other things, the risk factors discussed in "Item 1A. Risk Factors" of this Quarterly Report. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Quarterly Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See "Cautionary Statements Regarding Forward-Looking Statements" in this Quarterly Report.



Overview

We are a vertically integrated independent energy partnership formed in October 2012. The Partnership is actively engaged in the development and production of onshore oil and natural gas properties that extend across conventional resource reservoirs in east-central Oklahoma. Our oil and natural gas properties consist of non-operated working interests primarily in the Misener-Hunton formation, or Hunton formation. In addition, the Partnership is engaged in oilfield services through its oilfield services subsidiaries. Our oilfield services business provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, throughout the Mid-Continent region and in South Texas and West Texas. In June 2014, we acquired oilfield services companies that specialize in providing well testing and flowback services to the oil and natural gas industry primarily in Oklahoma, Texas, Pennsylvania and Ohio. Our business operates in two segments: (i) exploration and production and (ii) oilfield services. Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions.



Recent Developments

Shelf Registration Statement. On April 8, 2014, we filed a registration statement with the Securities and Exchange Commission ("SEC") which registered offerings of up to $500.0 million of any combination of common units and preferred units. Net proceeds, terms and pricing of each offering of securities issued under the shelf registration statement will be determined at the time of such offering. Our ability to utilize the shelf registration statement for the purpose of issuing, from time to time, any combination of common units or preferred units will depend upon, among other things, market conditions. Equity Offering. On April 29, 2014, we completed a public offering of 3,450,000 common units at a price of $23.25 per unit. We received net proceeds of approximately $76.2 million from this offering, after deducting underwriting discounts of $3.6 million and offering costs of $0.3 million. We used $5.0 million of the net proceeds from this offering to repay indebtedness outstanding under our credit facility with the remaining proceeds used to fund the cash portion of the Services Acquisition, described below, related acquisition costs and for general corporate purposes. 34 -------------------------------------------------------------------------------- Services Acquisition. On June 26, 2014, the Partnership acquired 100% of the outstanding membership interests in EFS and RPS for total consideration of approximately $108.3 million. The Services Acquisition helps to facilitate the Partnership's goals of becoming a more fully integrated oil and natural gas partnership. Results by Segment The Partnership operates in two business segments: (i) exploration and production and (ii) oilfield services. These segments represent the Partnership's two main business units, each offering different products and services. The exploration and production segment is engaged in the development and production of oil and natural gas properties. The oilfield services segment provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, as well as well testing and flowback services. Management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (i) revenues, (ii) operating expenses, (iii) segment margin, (iv) adjusted EBTIDA and (v) distributable cash flow. To evaluate the performance of the Partnership's business segments, management uses the excess of revenue over direct operating expenses or segment margin. Results of these measurements provide important information to management about the activity, profitability and contributions of the Partnership's business segments. The results of the Partnership's business segments for the three and six months ended June 30, 2014 and 2013 are discussed below. Exploration and Production Segment The Partnership generates a portion of its consolidated revenues and cash flow from the production and sale of oil, natural gas and NGLs. The exploration and production segment's revenues, profitability and future growth depend substantially on prevailing prices for oil, natural gas and NGLs and on the Partnership's reserves. The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our oil, natural gas and NGL production, the quantity of oil, natural gas and NGLs we produce and changes in the fair value of our commodity derivative contracts. Prices for oil, natural gas and NGLs fluctuate widely and are difficult to predict. In order to reduce the Partnership's exposure to price fluctuations, we enter into commodity derivative contracts for a portion of our anticipated future oil, natural gas, and NGL production as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk." Set forth in the table below is financial, production and pricing information for our exploration and production segment for the three and six months ended June 30, 2014 and 2013. For periods prior to the completion of our initial public offering in February 2013, the data below reflects results attributable to the IPO Properties. For periods following the completion of our initial public offering, the data below reflects results attributable to the IPO Properties for the entire period, and properties subsequently acquired from the closing date of their respective acquisition forward. 35 --------------------------------------------------------------------------------

Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 Results (in thousands): Oil sales $ 4,402 $ 1,636$ 8,348$ 2,834 Natural gas sales 3,850 2,642 9,217 4,449 NGL sales 8,466 6,371 18,004 12,726 Total revenues 16,718 10,649 35,569 20,009 Production expenses 4,516 2,827 9,019 5,274 Production taxes 792 486 1,671 1,439 Total segment margin 11,410 7,336 24,879 13,296 General and administrative 2,022 1,246 5,866 10,100 Depreciation, depletion, amortization and accretion 6,970 3,634 12,857 6,858 Operating income (loss) $ 2,418 $ 2,456$ 6,156$ (3,662 ) Production volumes: Oil (Bbls) 43,625 18,059 84,306 31,134 Natural gas (Mcf) 927,828 658,792 1,916,044 1,199,897 NGLs (Bbls) 241,695 192,740 447,278 372,206 Total production volumes (Boe)(1) 439,958 320,598 850,925 603,323 Average daily production volumes (Boe) 4,835 3,523 4,701 3,333 Average price (excluding derivatives): Oil (per Bbl) $ 100.91$ 90.59$ 99.02 91.03 Natural gas (per Mcf) $ 4.15 $ 4.01$ 4.81 3.71 NGL (per Bbl) $ 35.03 $ 33.05$ 40.25 34.19 Total (per Boe) $ 38.00 $ 33.22$ 41.80 33.16 Average production costs (per Boe)(2) $ 10.26 $ 8.82$ 10.60$ 8.74 __________



(1) Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of oil.

(2) Includes lease operating expense and workover expense.

Revenue

Revenues from our exploration and production segment were $16.7 million for the three months ended June 30, 2014, an increase of $6.1 million, or 57.0%, compared to the three months ended June 30, 2013. Revenues were $35.6 million for the six months ended June 30, 2014, an increase of $15.6 million, or 77.8%, compared to the six months ended June 30, 2013. The increase in revenues during the three and six months ended June 30, 2014 was primarily due to increased production from oil and natural gas properties acquired during 2013 and 2014. Production increased 119,360 Boe, or 37.2%, and 247,602 Boe, or 41.0%, in the three and six months ended June 30, 2014, respectively, from the same periods in 2013. Additionally, the increase in prices received on our production contributed to higher revenues in the three and six months ended June 30, 2014 compared to the same periods in 2013. The average price received on our combined production increased $4.78, or 14.4%, and $8.64, or 26.1%, in the three and six months ended June 30, 2014, respectively, from the same periods in 2013. Operating Expenses Production expenses. Production expense includes costs associated with exploration and production activities, including lease operating expense and treating costs. Production expenses increased $1.7 million, or 59.7%, for the three months ended June 30, 2014 from the three months ended June 30, 2013 and $3.7 million, or 71.0%, for the six months ended June 30, 2014 from the six months ended June 30, 2013. The increase in production expenses for the three and six months ended June 30, 2014 was partially due to increased production from oil and natural gas properties acquired during 2013 and 2014, a portion of which relates to acquisitions in the Southern Dome field, which produces more oil than properties in our other fields. Higher production 36 -------------------------------------------------------------------------------- costs were incurred on oil production compared to production costs on natural gas volumes. In addition, we incurred higher operator fees and costs on our production in 2014. As a result of these factors, production expense increased $1.44 per Boe and $1.86 per Boe for the three and six months ended June 30, 2014, respectively, compared to the same periods in 2013. As a non-operating working interest owner, we are subject to costs and fees as incurred and determined by the operator. We monitor such costs and are working with our contact operator and other working interest owners to ensure costs are reasonable. Production taxes. Production taxes increased $0.3 million, or 63.0%, and $0.2 million, or 16.1%, in the three and six months ended June 30, 2014, respectively, from the same periods in 2013. The increase in production taxes is due to the increase in volumes produced and prices received on our production in 2014 versus 2013. A portion of our wells benefit from certain tax credits relating to the drilling of horizontal wells. Due to these credits and the types of wells drilled, our production taxes will fluctuate from period to period in addition to variances from changes in production. General and administrative. General and administrative expense increased $0.8 million, or 62.3%, for the three months ended June 30, 2014 from the same period in 2013. The increase is attributable, in part, to $1.3 million of acquisition-related costs associated with the Services Acquisition in June 2014. Also contributing to the increase in 2014 is additional corporate costs related to salary and benefits due to an increase in the number of corporate-level employees. These increases were partially offset by $0.7 million in fees paid in 2013 to New Source Energy for administrative services as there were no such fees paid in 2014 and a reduction attributable to the decrease in the MCE Contingent Consideration of $1.3 million during the three months ended June 30, 2014. General and administrative expense decreased $4.2 million, or 41.9%, for the six months ended June 30, 2014 from the same period in 2013. The decrease is primarily the result of a decrease in equity-based compensation of $7.1 million and fees paid to New Source Energy for administrative services in 2013 and a reduction attributable to the decrease in the MCE Contingent Consideration of $0.9 million during the six months ended June 30, 2014 offset by an increase of $3.0 million for acquisition related costs and additional corporate costs related to salary and benefits due to an increase in the number of corporate-level employees in 2014. Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion expense increased $3.3 million and $6.0 million for the three and six months ended June 30, 2014, respectively, from the comparable periods in 2013. The majority of the increase in depreciation, depletion and amortization is attributable to the increase in combined production during 2014. Oilfield Services Segment The financial results of our oilfield services segment depend primarily on demand and prices that can be charged for its services. The primary factors affecting the results of the oilfield services segment are the rates received and the amount of oilfield services provided. The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. See Note 2 "Acquisitions" for discussion. Management monitors the oilfield services segment by revenue achieved per the average number of all rigs drilling in the areas we operate. Three Months Ended June Six Months Ended June 30, 2014 30, 2014 Results (in thousands): Oilfield service revenue $ 10,100 $ 18,676 Cost of providing oilfield services 5,968 10,534 Total segment margin 4,132 8,142 General and administrative 1,467 3,184 Depreciation, depletion and amortization 3,393 6,853 Operating loss $ (728 ) $ (1,895 ) Oilfield services statistic: Average weekly rig count drilling in operational areas (1) 1,057 1,025 Revenue per average weekly rig count $ 9,558 $ 9,096



__________

(1) Calculated using quarterly average of Baker Hughes rig count for

geographic areas we operate in for the three and six months ended June 30,

2014. 37

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Revenue

Revenues from our oilfield services segment was $10.1 million and $18.7 million for the three and six months ended June 30, 2014, respectively. Oilfield services revenues fluctuate based on drilling activity in the areas in which we operate. Operating Expenses Costs of providing oilfield services. The cost of providing oilfield services was $6.0 million and $10.5 million for the three and six months ended June 30, 2014, respectively. General and administrative. General and administrative expense of $1.5 million and $3.2 million for the three and six months ended June 30, 2014, respectively, represents the costs for ongoing operations in our expanding oilfield services segment. Depreciation, depletion and amortization. Depreciation, depletion and amortization expense of $3.4 million and $6.9 million for the three and six months ended June 30, 2014, respectively, primarily represents the amortization of our intangible asset - customer list from the MCE Acquisition. See "Results of Operations" below for a discussion of other income (expense).



Results of Operations

Refer to "Results by Segment" for discussion of our operating revenues and expenses. Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 (in thousands, except per unit amounts) Operating income (loss) $ 1,690$ 2,456$ 4,261$ (3,662 ) Other income (expense): Interest expense (1,015 ) (487 ) (1,984 ) (2,566 ) (Loss) gain on derivatives, net (1,396 ) 6,182 (4,528 ) 856 Gain on investment in acquired business 2,298 - 2,298 - Other income 9 - 7 - Income (loss) before income taxes 1,586 8,151 54 (5,372 ) Income tax benefit - - - 12,126 Net income $ 1,586$ 8,151$ 54$ 6,754 Other Income/Expense Interest expense. Interest expense increased $0.5 million, or 108.4%, for the three months ended June 30, 2014 from the three months ended June 30, 2013. The increase was due to higher average debt balances in 2014 compared to 2013, primarily as a result of additional borrowings under our credit facility as a result of acquisitions and corporate growth. Interest expense decreased $0.6 million or 22.7% for the six months ended June 30, 2014 from the six months ended June 30, 2013. The decrease was due to a write off of $1.4 million of loan fees associated with extinguishing debt in 2013. This decrease was partially offset by additional interest expense related to higher average debt balances in 2014 compared to 2013. (Loss) gain on derivatives, net. The following table presents (loss) gain on our derivative contracts for the three and six months ended June 30, 2014 and 2013 (in thousands): 38 --------------------------------------------------------------------------------

Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 Total (loss) gain on derivative contracts, net (1) $ (1,396 )$ 6,182$ (4,528 )$ 856 __________



(1) Included in the (loss) gain on derivative contracts for the three months

ended June 30, 2014 and 2013 are net cash payments upon contract

settlement of $1.0 million and $0.1 million, respectively. Included in the

(loss) gain on derivative contracts for the six months ended June 30, 2014

and 2013 are net cash payments upon contract settlement of $3.4 million

and $0.3 million, respectively.

Our derivative contracts are not designated as accounting hedges and, as a result, gains or losses on commodity derivative contracts are recorded each quarter as a component of operating expenses. In general, cash is received on settlement of contracts due to lower oil, natural gas and NGL prices at the time of settlement compared to the contract price for our oil, natural gas and NGL price swaps, and cash is paid on settlement of contracts due to higher oil, natural gas and NGL prices at the time of settlement compared to the contract price for our oil, natural gas and NGL price swaps. Gain on investment in acquired business. As discussed in Note 2 "Acquisitions," the Partnership initially recorded the 50% equity interest in MCCS acquired from Mr. Kos at his equity method carrying basis, which was $0.1 million as of June 26, 2014. The Partnership remeasured the 50% interest to determine the acquisition-date fair value and recognized a corresponding gain of $2.3 million on investment in acquired business. Income taxes. Income tax benefit was $12.1 million for the six months ended June 30, 2013. The IPO Properties were owned by a tax paying entity in 2012 and incurred deferred income taxes based on the differences in book and tax basis of the properties at that date. Upon completion of our initial public offering, all of our properties were owned by a nontaxable entity, and at such time we recognized a tax benefit due to the change in tax status.



Non-GAAP Financial Measures

Adjusted EBITDA. We define Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion and amortization, accretion expense, non-cash compensation expense, non-recurring advisory fees and acquisition costs, unrealized derivative gains and losses and non-recurring gains and losses.

Our management believes Adjusted EBITDA, a non-GAAP financial measure, is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods, book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.



A reconciliation of Adjusted EBITDA to net income is provided below:

39 --------------------------------------------------------------------------------

Three Months Ended Six Months Ended June 30, June 30, 2014 2013 (1) 2014 2013 (1) Reconciliation of adjusted EBITDA to net income: (in thousands) Net income $ 1,586$ 8,151$ 54$ 6,754 Interest expense 1,015 487 1,984 2,566 Income tax benefit - - - (12,126 ) Depreciation, depletion and amortization 10,289 3,577 19,567 6,772 Accretion expense 74 57 143 86 Non-cash compensation expense 386 - 644 7,738 Non-recurring advisory and acquisition fees 1,321 461 3,232 461 Gain on acquisition of business (2,298 ) - (2,298 ) - Loss (gain) on derivative contracts, net 1,396 (6,182 ) 4,528 (856 ) Cash paid on settlement of derivative contracts (983 ) (120 ) (3,412 ) (341 ) Change in fair value of contingent consideration (1,345 ) - (912 ) - Adjusted EBITDA $ 11,441$ 6,431$ 23,530$ 11,054 __________



(1) Reflects certain changes to align to current methodology for preparing Adjusted EBITDA.

A reconciliation of Adjusted EBITDA to net income (loss) for our exploration and production and oilfield services segments for the three and six months ended June 30, 2014 is provided below: Three Months Ended Six Months Ended June 30, 2014 June 30, 2014 E&P OFS E&P OFS Reconciliation of adjusted EBITDA to net income (loss): (in thousands) Net income (loss) $ 2,431$ (845 )$ 2,180$ (2,126 ) Interest expense 888 127 1,745 239 Depreciation, depletion and amortization 6,896 3,393 12,714 6,853 Accretion expense 74 - 143 - Non-cash compensation expense 386 - 644 - Non-recurring advisory and acquisition fees 1,104 217 3,015 217 Gain on acquisition of business (2,298 ) - (2,298 ) - Loss on derivative contracts, net 1,396 - 4,528 - Cash paid on settlement of derivative contracts (983 ) - (3,412 ) - Change in fair value of contingent consideration (1,345 ) - (912 ) - Adjusted EBITDA $ 8,549$ 2,892$ 18,347$ 5,183 40

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Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are cash flows generated by operating activities, borrowings under our credit facility and the issuance of equity securities in the capital markets. We may also issue debt securities as needed. To date, our primary use of capital has been for the acquisition and development of oil and natural gas properties and the acquisition of our oilfield services business through the MCE Acquisition and the Services Acquisition.



Distributions

Our Partnership Agreement requires that we distribute all of our available cash (as defined in the Partnership Agreement) to our unitholders and the general partner. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. To facilitate this, our Partnership Agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our Partnership Agreement allows our general partner to borrow funds to make distributions for certain purposes, including in circumstances where our general partner believes that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. Distributions are declared and distributed within 45 days following the end of each quarter. The Partnership has declared quarterly distributions per unit to unitholders of record, including holders of common, subordinated and general partner units during the three and six months ended June 30, 2014 and 2013, as shown in the following table (in thousands): Distributions Common Units Subordinated Units General Partner Units Total 2014 First Quarter (1) $ 4,681 $ 1,268 $ 89 $ 6,038 Second Quarter (2) $ 7,852 $ 1,279 $ 90 $ 9,221 2013 Second Quarter (3) $ 1,857 $ 604 $ 43 $ 2,504 __________ (1) Reflects quarterly distributions of $0.575 per unit paid in the first quarter of 2014. (2) Reflects quarterly distributions of $0.58 per unit paid in the second quarter of 2014. (3) Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit paid in the second quarter of 2013.



Capital Requirements

Because we distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our proved reserves and production, and as a result, we may not grow as quickly as other oil and natural gas entities or at all. We plan to reinvest a sufficient amount of our cash flow to fund our maintenance capital expenditures, and we plan to primarily use external financing sources, including borrowings under our credit facility and the issuance of debt and equity securities, rather than cash reserves established by our general partner, to fund our growth capital expenditures and any acquisitions. Because our proved reserves and production decline continually over time and because we own a limited amount of undeveloped properties, we may need to make acquisitions to sustain our level of distributions to unitholders over time. Cash Flows Net cash provided by operating activities was approximately $14.7 million and $2.7 million for the six months ended June 30, 2014 and 2013, respectively. The increase in the cash provided by operating activities is a result of the acquisitions that occurred throughout 2013 and in 2014, which increased the Partnership's overall oil and natural gas production and revenue from oilfield services. Net cash used in investing activities was approximately $84.7 million and $12.2 million for the six months ended June 30, 2014 and 2013, respectively. The increase is primarily attributable to the Services Acquisition and the CEU Acquisition during 2014. 41 -------------------------------------------------------------------------------- Net cash provided by financing activities was approximately $71.0 million and $10.3 million for the six months ended June 30, 2014 and 2013, respectively. Financing cash flows are primarily related to debt and equity financing of the property development and working capital. The increase in net cash provided by financing activities is primarily due to the equity offering in April 2014. Working Capital Working capital is the difference in current assets and current liabilities and is an indicator of liquidity and the potential need for short-term funding. The change in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, and maintenance capital expenditures. Our working (deficit) capital was $(36.7) million and $3.7 million at June 30, 2014 and December 31, 2013, respectively. The working deficit is primarily attributable to the contingent consideration from the MCE Acquisition and Services Acquisition and the factoring payable and notes payable assumed in the Services Acquisition. The MCE Contingent Consideration will be paid in the form of Partnership common units and the EFS/RPS Contingent Consideration will be paid in both cash and Partnership common units.



Capital Expenditures

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base (including our undeveloped leasehold acreage). The primary purpose of maintenance capital is to maintain the revenue generating capabilities of our assets at current levels over the long term. For the six months ended June 30, 2014, our maintenance capital expenditures were approximately $7.6 million. Growth capital expenditures are capital expenditures that we expect to increase our production and the size of our asset base. The purpose of growth capital is primarily to acquire producing assets that will increase our distributions per unit and secondarily to increase the rate of development and production of our existing properties and increase the size and scope of our oilfield services business in a manner that is expected to be accretive to our unitholders. Growth capital expenditures on existing properties may include projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth. We expect to primarily rely upon external financing sources, including borrowings under our credit facility and the issuance of debt and equity securities, rather than cash reserves established by our general partner, to fund growth capital expenditures and any acquisitions. We are party to other operating agreements pursuant to which the operator could decide to engage in capital spending that would require us to pay our share or suffer substantial penalties. Based on our current oil, natural gas and NGL price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for the year ending December 31, 2014. However, future cash flows are subject to a number of variables, including the level of our production and the prices we receive for our production. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures.



Credit Facility

Our credit facility is a four-year, senior secured credit facility. The amount we may borrow under the credit facility is limited to a borrowing base, which is primarily based on the value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders at their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, natural gas, and NGL reserves, which will take into account the prevailing oil, natural gas, and NGL prices at such time, as adjusted for the impact of our derivative contracts. A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we will be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our credit facility. Additionally, we anticipate that if, at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed of the then-specified borrowing base, we will not be able to pay distributions to our unitholders in any such quarter without first making the required repayments of indebtedness under our credit facility. Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) the Administrative Agent's prime rate or (c) the London interbank Offered rate ("LIBOR") plus 1.0%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans at shorter intervals. The average annual interest rate paid on amounts outstanding under the credit facility during 42 -------------------------------------------------------------------------------- the three months ended June 30, 2014 and 2013 was 3.27% and 3.29%, respectively. The average annual interest rate paid on amounts outstanding under the credit facility during the six months ended June 30, 2014 and 2013 was 3.30% and 3.29%, respectively. At June 30, 2014 and December 31, 2013, the average annual interest rates on borrowings outstanding under the credit facility were 3.19% and 3.25%, respectively. At June 30, 2014, the borrowing base under the credit facility was $102.5 million with $17.5 million of available borrowing capacity and approximately $7.3 million available borrowing capacity before restriction on distribution occurs. As of June 30, 2014, the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and amortization, and income taxes) to interest expense of not less than 2.5 to 1.0; (ii) a ratio of total debt to EBITDA of not more than 3.5 to 1.0; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully described in the credit agreement governing the credit facility. The financial covenants are calculated based on the results of the Partnership, excluding its subsidiaries. As of June 30, 2014, the Partnership was in compliance with all covenants under the credit facility.



Line of Credit

In February 2014, MCE entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to the oilfield services segment's accounts receivable. Interest only payments are due monthly with the line of credit maturing in February 2015. The line of credit replaced MCE's factoring payable agreement described below. Interest on the line of credit accrues at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at June 30, 2014. The line of credit is secured by accounts receivable, inventory, chattel paper and general intangibles of MCE. Based on the outstanding balance of $3.2 million, there was $0.8 million of available borrowing capacity at June 30, 2014. As of June 30, 2014, the line of credit contained a covenant requiring a debt service coverage ratio, as defined in agreement, of not less than 1.25 to 1.0. As of June 30, 2014, MCE was in compliance with this covenant under the line of credit. Notes Payable



The Partnership has $4.5 million in debt as of June 30, 2014 related to financing notes with various lending institutions for certain property and equipment through MCE. These notes range from 36-60 months in duration with maturity dates from May 2016 through April 2018 and carry variable interest rates ranging from 5.50% to 10.51%. All notes are associated with specific capital assets of MCE and are secured by such assets.

In conjunction with the Services Acquisition, the Partnership assumed the outstanding balances on term loans held by EFS. These term loans had a balance of $16.8 million as of June 30, 2014 and mature on June 26, 2015. The term loans have a variable interest rate based on the Bank 7 Base Rate minus 2.3%, which was 5.5% at June 30, 2014, with a minimum interest rate of 5.5%. The Partnership is required to maintain a reserve bank account of the lesser of $0.3 million or 100% of excess cash flow (as defined in the loan agreement). The Partnership has a balance of $1.0 million in the reserve account at June 30, 2014, which is shown as restricted cash on the accompanying unaudited condensed consolidated balance sheet. Payments of principal and interest are due in monthly installments. The term loans are collateralized by various assets of the parties to the agreement and guaranteed by MCE and former owners of EFS and RPS. The EFS term loan agreement contains various covenants and restrictive provisions that, among other things, limit the ability of EFS and RPS to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments; and dispose of assets. Additionally, beginning October 1, 2014, EFS and RPS must comply with certain financial covenants, including maintaining (i) a fixed charge ratio of not less than 1.25 to 1.0 (ii) a leverage ratio of not greater than 1.5 to 1.0, and (iii) a working capital and cash balance of at least $4.0 million, in each case as more fully described in the loan agreement.



Factoring Payable

In conjunction with the Services Acquisition, the Partnership assumed the EFS and RPS factoring agreements. Under these factoring agreements, invoices to pre-approved customers are submitted to the bank and the Partnership receives 90% funding immediately, and 10% is held in a reserve account with the factoring company for each invoice that is factored. Factoring fees, calculated based on three month LIBOR plus 5% (subject to a monthly minimum), are deducted from collected receivables. These factoring fees, along with an annual fee, are included in interest expense in the statement of operations. If a receivable is not 43 -------------------------------------------------------------------------------- collected within 90 days, the receivable is repurchased by the Partnership out of either the Partnership's reserve fund or current advances. The outstanding balance of the factoring payable was $16.2 million as of June 30, 2014. Equity Offering On April 29, 2014, we completed a public offering of 3,450,000 of our common units at a price of $23.25 per unit. We received net proceeds of approximately $76.2 million from this offering, after deducting underwriting discounts of $3.6 million and offering costs of $0.3 million. We used $5.0 million of the net proceeds from this offering to repay indebtedness outstanding under our credit facility with the remaining proceeds used to fund the cash portion of the Services Acquisition and pay related acquisition costs and for general corporate purposes. Contractual Obligations From time to time, we enter into transactions that can give rise to significant contractual obligations. Since December 31, 2013, we have completed the CEU Acquisition, the Services Acquisition and the MCCS Acquisition. These acquisitions or transactions conducted in conjunction with these acquisitions resulted in the following contractual obligations as of June 30, 2014, which are in addition to the contractual obligations of the Partnership that were presented in the 2013 Form 10-K. • Notes payable. The principal amount of $16.8 million assumed in the Services Acquisition is due in June 2015. • Leases. EFS and RPS have leases, primarily for field



offices, in

place through September 2022. Amounts due under such leases are approximately $0.3 million for remainder of 2014, $0.4 million for 2015, $0.3 million for each of 2016 through 2018, and $0.8 million thereafter.



Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves, the fair value of assets and liabilities acquired in business combinations, valuation of derivatives, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations and accrued revenues. Actual results could differ from these estimates.



Refer to Note 1 of the consolidated financial statements and Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in the 2013 Form 10-K for a description of the Partnership's critical accounting policies and estimates.


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Source: Edgar Glimpses


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