News Column

BLACK RIDGE OIL & GAS, INC. - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

August 12, 2014

Cautionary Statements

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the "safe harbor" protection for forward-looking statements that applicable federal securities law affords.

From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations and industry conditions are forward-looking statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as "estimate," "project," "predict," "believe," "expect," "anticipate," "target," "plan," "intend," "seek," "goal," "will," "should," "may" or other words and similar expressions that convey the uncertainty of future events or outcomes. Items making assumptions regarding actual or potential future sales, market size, collaborations, trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our control) that could cause actual results to differ materially from those set forth in the forward-looking statements include the following:

volatility or decline of our stock price;

low trading volume and illiquidity of our common stock, and possible

application of the SEC's penny stock rules;

potential fluctuation in quarterly results;

our failure to collect payments owed to us;

material defaults on monetary obligations owed us, resulting in unexpected

losses;

inability to effectively manage our hedging activities;

inadequate capital to acquire working interests in oil and gas prospects and to

participate in the drilling and production of oil and other hydrocarbons;

unavailability of oil and gas prospects to acquire;

decline in oil prices;

failure to discover or produce commercial quantities of oil, natural gas or

other hydrocarbons;

cost overruns incurred on our oil and gas prospects, causing unexpected

operating deficits; drilling of dry holes;



acquisition of oil and gas leases that are subsequently lost due to the absence

of drilling or production;

dissipation of existing assets and failure to acquire or grow a new business;

litigation, disputes and legal claims involving outside parties; and

risks related to our ability to be listed on a national securities exchange and

meeting listing requirements

We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, results actually achieved may differ materially from expected results in these statements. Forward-looking statements speak only as of the date they are made.

24



Readers are urged not to place undue reliance on these forward-looking statements. We assume no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this report, other than as may be required by applicable law or regulation. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the United States Securities and Exchange Commission (the "SEC") which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.

Overview and Outlook



We are an oil and natural gas exploration and production company. Our properties are located in North Dakota and Montana. Our corporate strategy is the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks trends in North Dakota and Montana. As of June 30, 2014, we owned an interest in 207 gross (6.28 net) producing oil and gas wells and controlled the rights to mineral leases covering approximately 9,800 net acres for prospective drilling to the Bakken and/or Three Forks formations. The following table provides a summary of important information regarding our assets:

As of June 30, 2014 As of December 31, 2013 Productive Wells Average Daily Proved Net Acres (1) Gross Net Production (2) Reserves PV-10 (3) (Boe per day) (000's Boe) ($000) 9,800 207 6.28 715 4,538 74,377 _______________



(1)Includes leases encompassing approximately 6 net acres that we estimate will expire over the remainder of 2014.

(2)Represents average daily production over the three months ended June 30, 2014.

(3)PV-10 is a non-GAAP financial measure. For further information and reconciliation to the most directly comparable GAAP measure, see "Item 2. Properties-Proved Reserves" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

Looking forward, we are pursuing the following objectives:

acquire high-potential mineral leases;

access appropriate capital markets to fund continued acreage acquisition and

drilling activities;

develop and maintain strategic industry relationships;

attract and retain talented associates;

operate a low overhead non-operator business model; and

become a low cost producer of hydrocarbons.

We believe the following are the key drivers to our business performance:

the ability of the Company to acquire acreage at a price that is significantly

below the acreage value when fully developed;

the ability of operators to successfully drill wells on the acreage position we

hold and incur customary costs;

the sales price per barrel of oil;

the number of producing wells we own and the performance of those wells; and

our ability to raise capital to fund drilling costs and acreage acquisitions.

Effective April 2, 2012, we changed our name to Black Ridge Oil & Gas, Inc. Our common stock is still traded on the OTCQB under the trading symbol "ANFC."

25 Operational Highlights



During the second quarter of 2014, we achieved the following financial and operating results:

production reached 715 Boe per day, representing 153% growth compared to the

second quarter of 2013 and 36% growth compared to the first quarter of 2014;

participated in the completion of 19 gross (0.77 net) wells increasing our

total producing wells to 207 gross (6.28 net) wells;

attained adjusted EBITDA from operations of $3.6 million;

reduced general and administrative expenses to $9.75 per Boe, compared to

$22.80/per Boe in the second quarter of 2013, representing a 57% decrease on a

per Boe basis;

realized $1.1 million of cash flow from operating activities; and

continued expansion of our activities in the Bakken and Three Forks plays by

growing production and improving our acreage portfolio.



Operationally, our second quarter of 2014 performance reflects continued success in executing our strategy of developing our acreage position and building production. Our production increased 38% to 65,059 Boe in the second quarter of 2014 as compared to first quarter of 2014 production of 47,211 Boe. The increase in production was driven by a 14% increase in net producing wells from 5.51 net wells at March 31, 2014 to 6.28 net wells at June 30, 2014.

Total revenues increased 105% in the second quarter of 2014 compared to the second quarter of 2013 primarily driven by increased production. Average realized prices on a Boe basis decreased 3% after the effect of settled derivatives, in the second quarter of 2014 compared to the second quarter of 2013. Additionally, our loss on the mark-to-market of derivatives was $881,000. Significant changes in crude oil and natural gas prices can have a material impact on our results of operations and our balance sheet.

Recent Developments



Potential Reverse Stock Split

Our Board approved resolutions authorizing the Company to implement a reverse stock split of the Company's outstanding shares of Common Stock at a ratio of up to 1:10 and any related amendment to the Company's certificate of incorporation. Our stockholders have also approved the amendment by written consent.

Our Board of Directors or a committee of the Board of Directors has the authority to decide whether to implement a reverse stock split and the exact amount of the split within the foregoing range, if it is to be implemented. If the reverse split is implemented, the number of issued and outstanding shares of Common Stock would be reduced in accordance with the exchange ratio selected by the Board of Directors or a committee thereof. The total number of authorized shares of Common Stock will be reduced proportionately as a result of the reverse stock split and the total number of shares of authorized preferred stock will remain unchanged at 20,000,000 shares.

We believe that a reverse split would, among other things, (i) better enable the Company to obtain a listing on a national securities exchange, (ii) facilitate higher levels of institutional stock ownership, where investment policies generally prohibit investments in lower-priced securities and (iii) better enable the Company to raise funds to finance its planned operations. However, there can be no assurance that we will be able to obtain a listing on a national securities exchange even if we implement the reverse stock split.

26



AS OF THE DATE OF THIS FILING, OUR BOARD HAS NOT TAKEN ANY ACTION TO MAKE THE

POTENTIAL REVERSE STOCK SPLIT EFFECTIVE. Production History



The following table presents information about our produced oil and gas volumes during the three month and six month periods ended June 30, 2014 and 2013, respectively. As of June 30, 2014, we controlled approximately 9,800 net acres in the Williston Basin. In addition, the Company owned working interests in 207 gross wells representing 6.28 net wells that are producing and an additional 47 gross wells representing 1.64 net wells that are preparing to drill, drilling, awaiting completion or completing.

Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 Net Production: Oil (Bbl) 58,812 23,663 101,967 44,159 Natural Gas (Mcf) 37,482 12,465 61,819 20,302 Barrel of Oil Equivalent (Boe) 65,059 25,741 112,270 47,543 Average Sales Prices: Oil (per Bbl) $ 91.27$ 88.02$ 89.88$ 89.26 Effect of oil hedges on average price (per Bbl) $ (4.47 ) $ - $ (3.71 ) $ - Oil net of hedging (per Bbl) $ 86.80$ 88.02$ 86.17$ 89.26 Natural Gas (per Mcf) $ 4.97$ 5.48$ 6.78$ 5.94 Effect of natural gas hedges on average price (per Mcf) $ - $ - $ - $ - Natural gas net of hedging (per Mcf) $ 4.97$ 5.48$ 6.78$ 5.94 Average Production Costs: Oil (per Bbl) $ 9.79$ 11.03$ 9.85$ 11.83 Natural Gas (per Mcf) $ 0.53$ 0.69$ 0.75$ 0.78 Barrel of Oil Equivalent (Boe) $ 9.15$ 10.47$ 9.36$ 11.32



Depletion of Oil and Natural Gas Properties

Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses for the six months ended June 30, 2014 and 2013, respectively.

Six Months Ended June 30, 2014 2013



Depletion of oil and natural gas properties $ 3,718,477$ 1,568,388

27 Productive Oil Wells



The following table summarizes gross and net productive oil wells by state at June 30, 2014 and 2013, respectively. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

June 30, 2014 June 30, 2013 Gross Net Gross Net North Dakota 206 6.20 80 2.74 Montana 1 0.08 1 0.08 Total 207 6.28 81 2.82 Exploratory Oil Wells The following table summarizes gross and net exploratory wells as of June 30, 2014 and 2013. The wells are at various stages of completion and the costs incurred are included in unevaluated oil and gas properties on our balance sheet. June 30, 2014 June 30, 20143 Gross Net Gross Net North Dakota 7 0.29 2 0.15 Total 7 0.29 2 0.15 28



Results of Operations for the Three Months Ended June 30, 2014 and 2013.

The following table summarizes selected items from the statement of operations for the three months ended June 30, 2014 and 2013, respectively.

Three Months Ended June 30, Increase / 2014 2013 (Decrease) Oil and gas sales $ 5,553,997$ 2,151,001$ 3,402,996 Loss on settled derivatives (262,719 ) - (262,719 ) Loss on mark-to-market of derivatives (881,124 ) - (881,124 ) Total revenues: 4,410,154 2,151,001 2,259,153 Operating expenses: Production expenses 595,591 269,461 326,130 Production taxes 591,525 232,528 358,997 General and administrative 634,109 586,860 47,249



Depletion of oil and gas properties 2,131,545 868,663 1,262,882 Accretion of discount on asset retirement obligations

5,148 1,811 3,337 Depreciation and amortization 8,188 5,811 2,377 Total operating expenses: 3,966,106 1,965,134 2,000,972 Net operating income (loss) 444,048 185,867 258,151 Total other income (expense) (1,293,123 ) (576,080 ) (717,043 )



Loss before provision for income taxes (849,075 ) (390,213 ) (458,862 )

Provision for income taxes 305,715 92,913 212,802 Net income (loss) $ (543,360 )$ (297,300 )$ (246,060 ) Oil and Natural Gas Sales



We recognized $5,553,997 in revenues from sales of crude oil and natural gas, excluding losses on derivatives, for the three months ended June 30, 2014 compared to revenues of $2,151,001 for the three months ended June 30, 2013, an increase of $3,402,996, or 158%. The increase in revenues was driven by a 153% increase in production and a 2% increase in realized prices before the effects of settled derivatives. We had 6.28 net producing wells as of June 30, 2014 compared to 2.82 net producing as of June 30, 2013.

Derivatives



For the second quarter of 2014 we incurred a loss on settled derivatives of $262,719. We had no derivative instruments in 2013.

We had a mark-to market derivative loss of $881,124 in the second quarter of 2014, resulting in a net derivative liability of $1,308,835. The third quarter of 2013 was the first quarter we entered into derivative contracts.

Production Expenses



Production expenses were $595,591 and $269,461 for the three months ended June 30, 2014 and 2013, respectively, an increase of $326,130, or 121%. Our production expenses are greater than the comparative period due to our rapid increase in production. On a per unit basis, production expenses decreased from $10.47 per Boe in the second quarter of 2013 to $9.15 per Boe in the second quarter of 2014.

29 Production Taxes



Our production taxes of $591,525 and $232,528 for the three months ended June 30, 2014 and 2013, respectively, an increase of $358,997, or 154%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 10.7% and 10.8% of oil and gas sales in the second quarter of 2014 and 2013.

General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2014 were $634,109 compared to $586,860 for the three months ended June 30, 2013, an increase of $47,249, or 8%. The increase in general and administrative expenses was primarily due to increased staffing to facilitate our growing production. General and administrative expenses per Boe produced decreased from $22.80 to $9.75 as we grew administrative staffing and expenses at a slower rate than our production.

Depletion of Oil and Natural Gas Properties

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. We recognized depletion expense of $2,131,545 and $868,663 for the three months ended June 30, 2014 and 2013, respectively, an increase of $1,262,882, or 145%. The increase was due primarily to our increased production. Depletion expense per Boe produced decreased from $33.75 in 2013 to $32.76 in 2014.

Depreciation



Depreciation expense for the three months ended June 30, 2014 was $8,188 compared to $5,811 for the three months ended June 30, 2013.

Other Income and (Expense)



Other income and (expense) for the three months ended June 30, 2014 was ($1,293,123) compared to ($576,080) for the three months ended June 30, 2013. The net other income and (expense) for the three months ended June 30, 2014 consisted of ($1,293,123) of interest expense including ($156,520) of amortized warrant costs, ($33,972) of amortization related to original issue discounts, ($263,909) of PIK interest applied to our debt balances and ($74,654) of amortized debt financing costs for the three months ended June 30, 2014. Additionally, we capitalized $51,781 of interest expense into our full cost pool related to interest costs incurred while our wells were being drilled and completed. Our net other income and (expenses) for the three months ended June 30, 2013 consisted of $73 of interest income and ($576,153) of interest expense including ($55,796) of amortized warrant costs and ($336,582) of amortized debt issuance costs. Amortization of warrant costs and deferred financing costs were accelerated during 2013 due to the termination of the Dougherty credit facility in the third quarter of 2013 as part of a refinancing.

Provision for Income Taxes

We had income tax benefits of $305,715 and $92,913 for the three months ended June 30, 2014 and 2013, respectively, an increase of $212,802, or 229%. The tax benefit for the three months ended June 30, 2014 and 2013 was primarily driven by the Company's loss before provision for income taxes.

30



Results of Operations for the Six months Ended June 30, 2014 and 2013.

The following table summarizes selected items from the statement of operations for the six months ended June 30, 2014 and 2013, respectively.

Six months Ended June 30, Increase / 2014 2013 (Decrease) Oil and gas sales $ 9,584,417$ 4,062,300$ 5,522,117 Loss on settled derivatives (378,882 ) - (378,882 ) Loss on mark-to-market of derivatives (1,095,159 ) - (1,095,159 ) Total revenues: 8,110,376 4,062,300 4,048,076 Operating expenses: Production expenses 1,103,054 538,267 564,787 Production taxes 996,832 451,870 544,962 General and administrative 1,404,882 1,190,438 214,444



Depletion of oil and gas properties 3,718,477 1,568,388 2,150,089 Accretion of discount on asset retirement obligations

9,653 2,963 6,690 Depreciation and amortization 16,113 11,622 4,491 Total operating expenses: 7,249,011 3,763,548 3,485,463 Net operating income (loss) 861,365 298,752 562,613 Total other income (expense) (2,376,023 ) (808,940 ) (1,567,083 )



Loss before provision for income taxes (1,514,658 ) (510,188 ) (1,004,470 )

Provision for income taxes 589,738 526,701 63,037 Net income (loss) $ (924,920 )$ 16,513$ (941,433 ) Oil and Natural Gas Sales



We recognized $9,584,417 in revenues from sales of crude oil and natural gas, excluding losses on derivatives, for the six months ended June 30, 2014 compared to revenues of $4,062,300 for the six months ended June 30, 2013, an increase of $5,522,117, or 136%. The increase in revenues was driven by a 136% increase in production while realized prices before the effects of settled derivatives were relatively consistent between periods. We had 6.28 net producing wells as of June 30, 2014 compared to 2.82 net producing as of June 30, 2013.

Derivatives



For the six months ended June 30, 2014 we incurred a loss on settled derivatives of $378,882. We had no derivative instruments in 2013.

We had a mark-to market derivative loss of $1,095,129 in the six months ended June 30, 2014, resulting in a net derivative liability of $1,308,835. The third quarter of 2013 was the first quarter we entered into derivative contracts.

Production Expenses



Production expenses were $1,103,054 and $538,267 for the six months ended June 30, 2014 and 2013, respectively, an increase of $564,787, or 105%. Our production expenses are greater than the comparative period due to our rapid expansion in production. On a per unit basis, production expenses decreased from $11.32 per Boe in the six months ended June 30, 2013 to $9.83 per Boe in the six months ended June 30, 2014.

31 Production Taxes



Our production taxes of $996,832 and $451,870 for the six months ended June 30, 2014 and 2013, respectively, an increase of $544,962, or 121%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 10.4% and 11.1% of oil and gas sales in the six months ended June 30, 2014 and 2013, respectively, the decrease driven by increased oil production in Montana and certain tax jurisdictions in North Dakota, which have a lower production tax rates, and increased gas and related product sales which have lower average tax rates than oil sales compared to revenue.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2014 were $1,404,882 compared to $1,190,438 for the six months ended June 30, 2013, an increase of $214,444, or 18%. The increase in general and administrative expenses was primarily due to increased staffing and external contract work to facilitate our growing production. General and administrative expenses per Boe produced decreased from $25.04 to $12.51 as we grew administrative staffing and expenses at a slower rate than our production.

Depletion of Oil and Natural Gas Properties

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. We recognized depletion expense of $3,718,477 and $1,568,388 for the six months ended June 30, 2014 and 2013, respectively, an increase of $2,150,089, or 137%. The increase was due primarily to our increased production. Depletion expense per Boe produced increased from $32.99 in 2013 to $33.12 in 2014.

Depreciation



Depreciation expense for the six months ended June 30, 2014 was $16,113 compared to $11,622 for the six months ended June 30, 2013.

Other Income and (Expense)



Other income and (expense) for the six months ended June 30, 2014 was ($2,376,023) compared to ($808,940) for the six months ended June 30, 2013. The net other income and (expense) for the six months ended June 30, 2014 consisted of ($2,376,023) of interest expense including ($310,042) of amortized warrant costs, ($60,288) of amortization related to original issue discounts, ($472,712) of PIK interest applied to our debt balances and ($145,307) of amortized debt financing costs for the six months ended June 30, 2014. Additionally, we capitalized $105,555 of interest expense into our full cost pool related to interest costs incurred while our wells were being drilled and completed. Our net other income and (expenses) for the six months ended June 30, 2013 consisted of $193 of interest income and ($809,133) of interest expense including ($65,884) of amortized warrant costs and ($399,654) of amortized debt issuance costs. Amortization of warrant costs and deferred financing costs were accelerated during 2013 due to the termination of the Dougherty credit facility in the third quarter of 2013 as part of a refinancing.

Provision for Income Taxes

We had income tax benefits of $589,738 and $526,701 for the six months ended June 30, 2014 and 2013, respectively, an increase of $63,037, or 12%. The tax benefit for the six months ended June 30, 2014 of $589,738 was primarily driven by the Company's loss before provision for income taxes. The tax benefit for the six months ended June 30, 2013 was driven by the Company's loss before income taxes and a change in our effective rate from 41.0% to 37.5% due to a change in state apportionment factors.

32 Non-GAAP Financial Measures



In addition to reporting net income (loss) as defined under GAAP, we also present Adjusted Net Income (Loss) and Adjusted EBITDA. We define Adjusted Net Income (Loss) as net income excluding net of losses on the mark-to-market of derivatives, net of tax. We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) accretion of abandonment liability, (v) loss on the mark-to-market of derivatives, and (vi) non-cash expenses relating to share based payments recognized under ASC Topic 718. We believe the use of non-GAAP financial measures provides useful information to investors regarding our current financial performance; however, Adjusted Net Income (Loss) and Adjusted EBITDA do not represent, and should not be considered alternatives to GAAP measurements. We believe these measures are useful in evaluating our fundamental core operating performance. Specifically, we believe the non-GAAP Adjusted Net Income (Loss) and Adjusted EBITDA results provide useful information to both management and investors by excluding certain income and expenses that our management believes are not indicative of our core operating results. Although we use Adjusted Net Income (Loss) and Adjusted EBITDA to manage our business, including the preparation of our annual operating budget and financial projections, we believe that non-GAAP financial measures have limitations and do not reflect all of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures. A reconciliation of Adjusted Net Income (Loss) and Adjusted EBITDA to Net Income, GAAP, are included below:

Black Ridge Oil & Gas, Inc. Reconciliation of Adjusted Net Income (Loss) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 Net Income (Loss) $ (543,360 )$ (297,300 )$ (924,920 )$ 16,513 Add back: Loss on mark-to-market of derivatives, net of tax (a) 555,124 - 690,159 - Adjusted Net Income (Loss) $ 11,764$ (297,300 )$ (234,761 )$ 16,513 Weighted average common shares outstanding - basic 47,979,990 47,979,990 47,979,990 47,979,990 Weighted average common shares outstanding - fully diluted 47,979,990 47,979,990 47,979,990 48,540,032 Net income (loss) per common share - basic $ (0.01 )$ (0.01 )$ (0.02 )$ 0.00 Subtract: Change due to loss on mark-to- market of derivatives, net of tax 0.01 0.00 0.01 0.00 Adjusted Net Income (loss) per common share - basic $ 0.00$ (0.01 )$ (0.01 )$ 0.00 Net income (loss) per common share - fully diluted (0.01 ) (0.01 ) (0.02 ) $ 0.00 Subtract: Change due to loss on mark-to- market of derivatives, net of tax 0.01 0.00 0.01 0.00 Adjusted Net Income (Loss) per common share - fully diluted $ 0.00$ (0.01 )$ (0.01 )$ 0.00



(a) Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 37%, of $326,000 and $405,000 for the three and six months ended June 30, 2014, respectively.

33 Black Ridge Oil & Gas, Inc. Reconciliation of Adjusted EBITDA (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 Net Income (loss) $ (543,360 )$ (297,300 )$ (924,920 )$ 16,513 Add Back: Interest Expense, net, excluding amortization of warrant based financing costs 1,136,603 520,284 2,065,981 743,056 Income Tax Provision (305,715 ) (92,913 ) (589,738 ) (526,701 ) Depreciation, Depletion, and Amortization 2,139,733 874,474 3,734,590 1,580,010 Accretion of Abandonment Liability 5,148 1,811 9,653 2,963 Share Based Compensation 301,241 223,145 599,003 395,598 Loss on mark-to market of derivatives 881,124 - 1,095,159 - Adjusted EBITDA $ 3,614,774$ 1,229,501$ 5,989,728$ 2,211,439 34



Liquidity and capital resources

The following table summarizes our total current assets, liabilities and working capital at June 30, 2014 and December 31, 2013, respectively.

June 30, December 31, 2014 2013 Current Assets $ 7,427,210$ 4,296,618 Current Liabilities $ 9,547,225$ 8,597,587 Working Capital $ (2,120,015 )$ (4,300,969 )



As of June 30, 2014 we had negative working capital of $2,120,125.

The following table summarizes our cash flows during the three month periods ended June 30, 2014 and 2013, respectively.

Six months Ended June 30, 2014 2013



Net cash provided by operating activities $ 2,012,131$ 1,012,427 Net cash used in investing activities (13,873,281 ) (2,947,282 ) Net cash provided by financing activities 10,795,218 2,089,994

Net change in cash and cash equivalents $ (1,065,932 )$ 155,139

Our net cash flows from operations are primarily affected by production volumes and commodity prices. Net cash provided by operating activities was $2,012,131 and $1,012,427 for the six months ended June 30, 2014 and 2013, respectively, an increase of $999,704. The increase was due to increased gross profit from higher production activity offset by changes in working capital from operating activities. Changes in working capital from operating activities resulted in a decrease in cash of ($2,589,923) in the six months ended June 30, 2014 as compared to a decrease in cash of ($855,610) for the same period in the previous year, primarily driven by increase in accounts receivable in both periods.

Net cash used in investing activities was $13,873,281 and $2,947,282 for the six months ended June 30, 2014 and 2013, respectively, an increase of $10,925,999. The increase was primarily driven by increased expenditures for well development as we paid $10,079,431 for well development and $3,491,089 in advances to operators for future well development during the 2014 period while in the 2013 period we spent $2,259,115 for well development and $615,370 in advances to operators for future well development. Additionally, the increase in cash used in investing activities was attributable to an increase in cash spent for property acquisition as we purchased 200 net leasehold acres of oil and gas properties for $1,652,551 in the six months ended June 30, 2014 as compared to purchasing 800 net leasehold acres of oil and gas properties for $416,283 in the six months ended June 30, 2013. In the six months ended June 30, 2014 we sold 490 net leasehold acres for proceeds of $1,360,920, including proceeds of $20,000 from a swap transaction, while in the comparable 2013 period we sold 105 net leasehold acres for proceeds of $343,486.

Net cash provided from financing was $10,795,218 and $2,089,994 for the six months ended June 30, 2014 and 2013, respectively. We drew $10,850,000, net of repayments, on our credit facilities during the six months ended June 30, 2014 while funding a portion of the operational and investing activity through operating income and working capital. We drew $2,114,994 on our Dougherty revolving credit facility in 2013 while funding additional investing activity through operating cash flows and working capital.

35



Senior Credit Facility and Subordinated Credit Facilities

The Company, as borrower, entered into a Credit Agreement dated August 8, 2013 and amendments thereto (as amended, the "Senior Credit Agreement") with Cadence Bank, N.A. ("Cadence"), as lender (the "Senior Credit Facility"). Under the terms of the Senior Credit Agreement, a senior secured revolving line of credit in the maximum aggregate principal amount of $50 million is available from time to time (i) for direct investment in oil and gas properties, (ii) for general working capital purposes, including the issuance of letters of credit, and (iii) to refinance existing debt under the Company's credit facility with Dougherty Funding LLC.

Availability under the Senior Credit Facility is at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and is subject to periodic redeterminations. The availability has been increased to $20 million as a result of redeterminations. Subject to availability under the borrowing base, the Company may borrow, repay and re-borrow funds in amounts of $250,000 or more. At the Company's election, the unpaid principal balance of any borrowings under the Senior Credit Facility may bear interest at either (i) the Base Rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 1.00% to 1.50% or (ii) the LIBOR rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 3.00% to 3.50%. Interest is payable for Base Rate loans on the last business day of the month and for LIBOR loans on the last LIBOR business day of each LIBOR interest period. The Company is also required to pay a quarterly fee of 0.50% on any unused portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing base.

The Senior Credit Facility will mature on August 8, 2016. The Company may prepay the entire amount of Base Rate loans at any time, and may prepay the entire amount of LIBOR loans upon at least three business days' notice to Cadence. The Senior Credit Facility is secured by first priority interests in mortgages on substantially all of the Company's assets, including but not limited to the Company's mineral interests in North Dakota and Montana.

As of June 30, 2014 the Company had borrowings of $14.05 million outstanding under the Senior Credit Agreement.

The Company, as borrower, entered into a Second Lien Credit Agreement dated August 8, 2013 and amendments thereto (as amended, the "Subordinated Credit Agreement") with Chambers Energy Management, LP, as administrative agent ("Chambers"), and the several other lenders named therein (the "Subordinated Credit Facility"). Under the Subordinated Credit Facility, term loans in the aggregate principal amount of up to $75 million are available from time to time (i) to repay the Previous Credit Facility, (ii) for fees and closing costs in connection with both the Senior Credit Facility and the Subordinated Credit Facility (together, the "Credit Facilities"), and (iii) general corporate purposes.

The Subordinated Credit Agreement provides for initial commitment availability of $25 million, subject to customary conditions, with the remaining commitments subject to the approval of Chambers and other customary conditions. The Company may borrow the available commitments in amounts of $5 million or more and shall not request borrowings of such loans more than once a month, except that the initial draw was required to be at least $15 million. Loans under the Subordinated Credit Facility shall be funded net of a 2% OID. The unpaid principal balance of borrowings under the Subordinated Credit Facility bears interest at the Cash Interest Rate plus the PIK Interest Rate. The Cash Interest Rate is 9.00% per annum plus a rate per annum equal to the greater of (i) 1.00% and (ii) the offered rate for three-month deposits in U.S. dollars that appears on Reuters Screen LIBOR 01 as of 11:00 a.m. (London time) on the second full LIBOR business day preceding the first day of each calendar quarter. The PIK Interest Rate is equal to 4.00% per annum. Interest is payable on the last day of each month. The Company is also required to pay an annual nonrefundable administration fee of $50,000 and a monthly availability fee computed at a rate of 0.50% per annum on the average daily amount of any unused portion of the available amount under the commitment.

36



The Subordinated Credit Facility matures on June 30, 2017. Upon at least three business days' written notice, the Company may prepay the entire amount under the loans, together with accrued interest. Each prepayment made prior to the second anniversary of the funding date, as defined in the Subordinated Credit Facility, shall be accompanied by a make-whole amount, as defined in the Subordinated Credit Agreement. Prepayments made on or after the second anniversary of the funding date shall be accompanied by an applicable premium, as set forth in the Subordinated Credit Agreement. The Subordinated Credit Facility is secured by second priority interests on substantially all of the Company's assets, including but not limited to second priority mortgages on the Company's mineral interests in North Dakota and Montana.

The first funding from the Subordinated Credit Facility occurred on September 9, 2013 at which time we drew $14,700,000, net of a $300,000 original issue discount, from the Subordinated Credit Agreement and used $10,226,057 of those proceeds to repay and terminate the Dougherty revolving credit facility. We have made subsequent draws of an additional $14,700,000, net of $300,000 in original issue discount. Availability under the facility is $35 million as of June 30, 2014.

Cadence and Chambers have entered into an Intercreditor Agreement dated August 8, 2013 (the "Intercreditor Agreement"). The Intercreditor Agreement provides that any liens on the assets of the Company securing indebtedness under the Subordinated Credit Facility are subordinate to liens on the assets securing indebtedness under the Senior Credit Facility and sets forth the respective rights, obligations and remedies of the lenders under the Senior Credit Facility with respect to their first priority liens and the lenders under the Subordinated Credit Facility with respect to their second priority liens.

The Credit Facilities require customary affirmative and negative covenants for credit facilities of the respective types and sizes for companies operating in the oil and gas industry, as well as customary events of default. Furthermore, the Credit Facilities contain financial covenants that require the Company to satisfy certain specified financial ratios. The Senior Credit Agreement requires the Company to maintain (i) as of the last day of each fiscal quarter of the Company, a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, and 0.80 to 1.00 for the quarter ending March 31, 2015 and thereafter, (ii) a ratio of current assets to current liabilities of a minimum of 1.0 to 1.0, (iii) a net debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.75 to 1.00 for the quarter ended March 31, 2014, 4.25 to 1.00 for the quarters ended June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ended December 31, 2014, and 3.50 to 1.00 for the quarter ended March 31, 2015 and thereafter, in each case calculated on a modified trailing four quarter basis, (iv) a maximum senior leverage ratio of not more than 2.5 to 1.0 calculated on a modified trailing four quarter basis, and (v) a minimum interest coverage ratio of not less than 3.0 to 1.0. The Subordinated Credit Agreement requires the Company to maintain (i) as of the last day of each fiscal quarter of the Company, a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, and 0.80 to 1.00 for the quarter ending March 31, 2015 and thereafter, (ii) as of the last day of each fiscal quarter of the Company, a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.75 to 1.00 for the quarter ending March 31, 2014, 4.25 to 1.00 for the quarters ending June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ending December 31, 2014, and 3.50 to 1.00 for the quarter ending March 31, 2015 and thereafter, calculated on a modified trailing four quarter basis, (iii) as of the last day of any fiscal quarter of the Company, a consolidated cash interest coverage ratio (consolidated EBITDA to consolidated cash interest expense) of no less than 2.5 to 1.0, calculated on a modified trailing four quarter basis and (iv) as of the last day of any period of four consecutive fiscal quarters of the Company, a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements prior to funding with regard to no less than 50% and no greater than 75% of its future oil production on currently producing wells. The Company is in compliance with all covenants, as amended, for the period ending June 30, 2014.

37



In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders detachable warrants to purchase up to 5,000,000 shares of the Company's common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018. Proceeds from the loan were allocated between the debt and equity based on the relative fair values at the time of issuance, resulting in a debt discount of $2,473,576 at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. The remaining unamortized balance of the debt discount attributable to the warrants is $1,963,902 as of June 30, 2014.

Dougherty Revolving Credit Facility (former credit facility)

On April 4, 2012, the Company entered into a Secured Revolving Credit Agreement with Dougherty Funding, LLC ("Dougherty") as Lender which was subsequently amended on September 5, 2012 and December 14, 2012 with an Amended and Restated Secured Revolving Credit Agreement (collectively the "Dougherty Credit Facility").

The Dougherty Credit Facility provided for a maximum available amount of $20 million, of which $16.5 million was available prior to termination of the facility, with interest payable on the outstanding balance at a rate of 9.25% per year and a maturity date of August 1, 2015. In connection with the amended financing, the Company issued Dougherty Funding, LLC warrants to purchase 585,000 shares of the Company's common stock at an exercise price of $0.38 per share. The warrants expire on August 31, 2015.

We took our first draw on April 12, 2012 of $2,450,000, and used $2,051,722 of the proceeds to repay and terminate our predecessor PrenAnte5 revolving credit facility, including interest of $51,722.

On September 9, 2013, we repaid the Dougherty Credit Facility with proceeds from the Subordinated Credit Facility.

Although our revenues are expected to grow as our wells are placed into production, our revenues are not expected to exceed our investment developing oil and gas wells and our operating costs throughout the remainder of 2014 and into 2015. However, we believe our availability under our credit facilities provides ample funding for our property acquisition and development plans through those same periods. Our prospects still must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development. Such risks for us include, but are not limited to, potential failure to earn revenues and collect payments that are owed to us; an inability to identify investment and expansion targets; and dissipation of existing assets. To address these risks, we must, among other things, seek growth opportunities through investment and acquisitions in the oil and gas industry, effectively monitor and manage our claims for payments that are owed to us, implement and successfully execute our business strategy, respond to competitive developments, and attract, retain and motivate qualified personnel. We cannot assure that we will be successful in addressing such risks, and the failure to do so could have a material adverse effect on our business prospects, financial condition and results of operations.

Satisfaction of our cash obligations for the next 12 months

As of June 30, 2014, our balance of cash and cash equivalents was $84,415. Our plan for satisfying our cash requirements for the next twelve months, in addition to our revenues from oil and gas sales is through draws on our credit facilities and potential sale or use of shares of our stock.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

38



Critical Accounting Policies and Estimates

Our management's discussion and analysis of financial conditions and results of operations is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP. The preparation of these financial statements required us to make estimates and judgments that affect the reported amounts of assets, liabilities and expenses. On an ongoing basis, we evaluate these estimates and judgments, including those described below. We base our estimates on our historical experience and on various other assumptions that we believe to be reasonable under the circumstances. These estimates and assumptions form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results and experiences may differ materially from these estimates.

While our significant accounting policies are more fully described in notes to our financial statements appearing elsewhere in this Form 10-Q, we believe that the following accounting policies are the most critical to aid you in fully understanding and evaluating our reported financial results and affect the more significant judgments and estimates that we used in the preparation of our financial statements.

Stock-Based Compensation



We have accounted for stock-based compensation under the provisions of FASB Accounting Standards Codification (ASC) 718-10-55 (Prior authoritative literature: FASB Statement 123(R), Share-Based Payment). This statement requires us to record any expense associated with the fair value of stock-based compensation. We used the Black-Scholes option valuation model to calculate stock based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.

Full Cost Method



We follow the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisitions, and exploration activities.

39


For more stories on investments and markets, please see HispanicBusiness' Finance Channel



Source: Edgar Glimpses


Story Tools






HispanicBusiness.com Facebook Linkedin Twitter RSS Feed Email Alerts & Newsletters