Oil and Natural gas

Oil India was incorporated as a private limited company on February 18, 1959 under the name “Oil India Private Limited”, pursuant to a promoters‟ agreement dated January 14, 1958, between the President of India, Burmah Oil Company Limited and Assam Oil Company Limited. At the time of the incorporation, Burmah Oil Company Limited and the President of India held two-thirds and one third of the Equity Share capital, respectively. The Company was incorporated with the main object of exploration and production of crude oil (including natural gas). The Company became a deemed public limited company with effect from March 28, 1961 and the word “private” was deleted from the name of the Company on May 4, 1961.

Consequently, as mentioned earlier, especially crude oil, natural gas and the most of commodities are traded as financial products in recent years. For this reason, decision makers such as politicians in state agencies and managers of private sectors must seriously consider highly volatile market trends, particularly, because they have features of main raw materials. Shocks/innovations originated from oil and natural gas markets must be considered to minimize risks, as well as they should consider their pairwise causality between macroeconomic indicators like economic growth, current account deficit and unemployment. Therefore, they must determine optimal hedge strategies and benefit from derivative products efficiently in line with the midterm program objectives. In addition, for this purpose, regulators can make policies which enable to improve financial deepening. This study can humbly be a pioneer for further or any related studies which can be built on to research for the causes of crude oil and natural gas volatility and pairwise causality between macroeconomic indicators following the collapse of prices from $110 to $46 since June of 2014.

The high activity recently experienced in the crude oil and natural gas markets over the last few years with the arrival of hedge funds and other new players has led researchers and practitioners to focus on these crucial commodities. Our goal in this paper is to give a particular attention to two quantities which play a key role in economics and finance, namely the shape of the forward curve and the spot price volatility.

The government has dedicated that does not plan to take all the revenue that is generated from the gas industry and put them in the Treasury as in the mining sector. Revenue from natural gas will be deposited in a specific fund and it is responsible for Tanzanians to prioritize the use of revenue, a process that will simplify the people’s direct involvement with their natural resources. In order to ensure good and effective management in the natural gas industry, the policy has proposed strengthening power in the financial, legal and regulatory framework. This is what led to the formation of the Oil and Natural gas Revenue Management Act of 2015(URT, 2015a), but also other specific laws that regulated or modified including the natural gas regulations and Income Tax Act (Cap. 332) and the Energy and Water Utilities Authority (EWURA) Act (Cap. 414)(EWURA, 2017).

To see how an investment at this scale could benefit the state of New Mexico, we proceed with the following back-of-the-envelope calculation. According to the well statistics database from the New Mexico Oil Conservation Division 4 , 1283 wells were completed in the New Mexico part of the Permian Basin in 2014. With a direct investment ranging between $2.5 to $4 million per well, this translates to a total new investment in the range of $3.2 to $5.1 billion. Considering that most of the production activities concentrate within two counties (Lea and Eddy), this is a highly intensive direct investment. By 2017, the drilling activities slowed down with 532 wells completed according to the same data source, which translates to a total new direct investment in the range of $1.3 to $2.1 billion. Because of the cumulative effect of investments over time, the revenue impact of the direct investments over time can be considerably large. In the next section, the local employment and income impacts of the oil and natural gas development in the Permian Basin will be analyzed.

Table 1 contains the results from the ADF tests. The top half of the table presents the test statistics that determine whether the series in levels are stationary I(0), and the bottom half of the table presents the findings on whether the first differences of the series are stationary I(1). There are seven columns in the table. The first column refers to the number of lags, p, in each regression. This is followed by two sets of three columns where the first set presents the results for the Henry Hub natural gas price tests and the second has the WTI crude oil price tests. The three columns for each set include the t-statistic for the ADF test that is associated with the α 1 , the t-statistic on the last lagged difference variable in each equation, and the AIC. The null hypothesis in each test is that there is a unit root or the series is I(1); this implies that the coefficient α 1 is zero. Because of the properties of nonstationary series, the distributions of the statistics are different. The critical values are found at the bottom of the table. The t-DY lag and AIC measures are used in evaluating the appropriate number of lags in the testing procedure that remove serial correlation in the residuals.

The demand for natural gas was similar to that for crude oil, with low and nonsignificant short-run price elasticity: –0.01 in 1918-2004, –0.17 in 1918-73, and –0.01 in 1974-2004. Determined by fixed capital, natural gas demand was, therefore, highly price inelastic in the short run. Real GDP was a main driving variable, with significant short-run income elasticities: 0.77 in 1918-2004, 0.70 in 1918-73, and 0.80 in 1974-2004. The rise in real GDP elasticity in 1974-2004 suggests that a structural change increased the importance of natural gas in economic activity. The lower-than-unity income elasticity would explain the lack of demand pressure on natural gas prices in 1918-2004. The natural gas supply function was quite similar to that of the crude oil. Short-run supply price elasticities were low and nonsignificant: 0.09 (1918-2004), –0.32 (1918-73), and 0.05 (1974-2004). These results establish that (i) the short-run price effect was small; namely, natural gas supply was determined by existing production capacity; and (ii) natural gas supply did not react immediately to changes in prices. The small value of the short-run price elasticity in 1974- 2004 may indicate a likely emergence of a producers’ power. It may also stem from the nature of the demand curve: knowing the inelasticity of demand, producers may deliberately restrain output in order to preserve surges in prices. It may be indicative also of a short-run downward supply curve arising from economies of scale in the industry. The crude oil output had a significant effect on the supply of natural gas. The short-run output elasticity was 0.88 in 1918-2004, 1.04 in 1918-73, and 0.35 in 1974-2004, implying interdependence in oil and natural gas production. An expansion in crude supply would likely be accompanied by a significant, although less than proportional, expansion in the supply of natural gas.

The Cost of Imports. Shale development confers an eco- nomic benefit that raises the standard of living in the United States but does not show up as greater GDP. Spe- cifically, increased net exports of natural gas and oil boost the value of the dollar, making imports cheaper and allowing consumers to buy more and businesses to invest more for a given quantity of exports and a given amount of GDP. CBO has not quantified that effect, however. Uncertainty. CBO’s estimates of shale development’s effects on GDP are accompanied by significant uncer- tainty of various kinds. The estimates rest on baseline projections of the prices of shale gas and tight oil, of the quantities of those fuels produced in the United States, and of the profitability of that production—and as is explained earlier (in the section “Uncertainty in the Projections”), all of those projections are uncertain, because of underlying uncertainty about demand for natural gas and oil, demand for other forms of energy, the availability of shale resources, and exploration and production technology.

Summary. The goals of the paper are as follows: i) review some qualitative proper- ties of oil and gas prices in the last 15 years; ii) propose some mathematical elements towards a definition of mean reversion that would not be reduced to the form of the drift in a stochastic differential equation; iii) conduct econometric tests in order to conclude whether mean reversion still exists in the energy commodity price behav- ior. Regarding the third point, a clear “break” in the properties of oil and natural gas prices and volatility can be exhibited in the period 2000-2001.

The application of the desulphurization study had conducted with natural gas in some oil and gas field. This study is still laboratory scale with the feed gas came from separator. During normal operation, the gas pressure on separator is about 220 psi. The natural gas which came out from separator contain very low (nil) water. The component of natural gas (except sulphur content) are showed on Table 1. The content of hydrocarbon compounds are more than 50%, and almost 40% is carbon dioxide.

For many years in the past, natural gas and refined petroleum products viewed as close substitutes, as major users of natural gas substituted one product for the other depending on the price level of each. As a result, a common view held by some (Brown and Yucel, 2007) is that natural gas prices adjust to crude oil prices which in turn determined by world oil market conditions. Such stable relationship between oil prices and natural gas prices led in the past to the use of rules of thumb in energy industry that relate natural gas prices to those for crude oil. The simplest of these rules predict a constant relationship between the two prices 1 . However, as oil prices surged upward in past recent years the association between the two energy prices seemed more complex than can be explained by the simple relationship implied by the rules of thumb. As a result, in recent years the

The EcoShale In-Capsule Technology has been developed by Red Leaf Resources, Inc. to produce high quality liquid fuels from oil shale economically and with a minimal environmental impact. The process comprises heating mined and rubblized oil shale using pipes fired with natural gas burners in a clay-lined, closed-surface capsule. This technology does not require process water, protects ground water by using a liner inside the capsule, and allows for rapid site reclamation by providing an overburden over the capsule [1]. The process schematic is shown in Figure  1.

Natural gas reserves are estimated to last around 30-40 years more than those of oil. Renewable production of bio-methane offers an extension and gradually increasing substitution for fossil natural gas. Bio-methane should preferentially be fed into the general natural gas grid. Hydrogen- methane blends could also offer an additional energy supply channel.

• Production by resource type (conventional, EOR, deepwater, tight, shale, Arctic, any new…) • Cost of supply stacks for remaining resource. • Ability to run sensitivities/construct sce[r]

Beavers, “Assessment of the Effects of Surface Preparation and Coating on the Susceptibility of Line Pipe to Stress Corro- sion Cracking,” Pipeline Research Council International, 1992. [r]

This chart is a simplified model of a potential supply gap between domestic regional supply and demand (it does not predict the timing or extent of supply constraints). In this scenario, additional sources of supply would be required to fill the gap by 2019. There are only two broad choices to fill this gap: (a) import natural gas from foreign sources (as LNG or by pipeline from the US) or (b) find and develop new domestic sources of natural gas. Imported Sources: There are two import avenues. Canaport could serve our region, but at a delivered price that competes with high global LNG prices. Imports from shale gas rich areas in the US are constrained by current pipeline capacity bottlenecks south of Boston. Costly pipeline additions and enhancements on both sides of the border may be required for flow capacity into New Brunswick. If these challenges can be overcome, supply would come at a high delivered cost, due to transmission tolls.

• The ability to account for specific control measures will become more important as Parties strive to meet their emission reduction targets. A Tier-1 approach only captures the impact of any changes in gross activity levels. A Tier-2 or -3 approach must be used in order to show the impact of site-specific vapour and waste- gas control measures. To show changes in emissions from fugitive equipment leaks (a large if not the largest source of organic emissions at many facilities) requires the performance of regular leak detection and repair programmes. Furthermore, conventional technologies used in leak detection and repair programmes (i.e., estimation of leak rates based on leak screening data collected in accordance with US EPA's Method 21) provide only a very crude indication of actual changes in emissions. According to Lott et al. (1996), the typical error from use of such approaches is ±300 percent or more depending on the number of components considered and the actual method used to estimate leak rates from the screening values (i.e., emission factors or leak-rate correlations). Since nearly all the emissions come from the small percentage of components that leak the most, a good approach might be to conduct a simplified screening programme to identify these few leaks and then use direct measurement techniques (e.g., High-Flow sampler [Lott et al., 1996], flow-through flow meters, and bagging techniques) to accurately measure their actual leak rates (also see Section 2.2.3); • While optimizing the quality of the inventory dictates that efforts be focused on the areas of greatest

condensate  fields,  like  the  Margarita  and  Itau  fields operated  by BG. The current liquids  to  gas  ratio  is  very  low  at  3%,  so  there  could  be  substantial  scope  to  expand  output.  It  has  been  suggested  that  Bolivian  gas  plant  liquids  production  could  easily  increase  from  7 kb/d  to  15 kb/d  based  on  current  infrastructure.  Bolivia  has  possibly  as  many  as  7  gas  processing  plants  with a capacity to extract 22 kb/d of NGLs, among  others  a  5‐train  Repsol  operated  plant  in  Santa  Cruz. The biggest plant in terms of NGL output is  probably  the  BG  operated  plant  in  Vertiente.  Bolivia's  government  has  recently  revived  to  expand operational NGL extraction and separation  capacity  in  Rio  Grande  in  the  eastern  region  of  Santa Cruz  and  Chaco  in southeastern Tarija (see  map). 

Once all of the vehicles and equipment are placed in their final resting positions, the berms are set, and the hoses and iron are connected, C&J will ensure that all hoses will b[r]

Oil and Gas SMU Law Review Volume 3 Issue 3 Survey of Texas Law for the Year 1948 Article 2 1949 Oil and Gas Sydney Farr Follow this and additional works at https //scholar smu edu/smulr This Article[.]